SPE-176801-MS

Milestones, Lessons Learned and Best Practices in the Designing,Deployment and Installation of ICDs in Saudi Arabia

Mohammed A Madan, Saudi Aramco; Kousha Gohari, Baker Hughes RDS; Roberto Vicario, Baker Hughes;

Heikki A Jutila, Baker Hughes RDS; Hesham A Mohammed, Baker Hughes

Copyright 2015, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Middle East Intelligent Oil & Gas Conference & Exhibition held in Abu Dhabi, UAE, 1516 September 2015.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contentsof the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflectany position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the writtenconsent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations maynot be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract

Horizontal wells have provided operators a way to maximize reservoir contact, improve sweep efficiencyand well productivity. Conventionally completed horizontal wells present a high risk of gas cusping andwater coning that can significantly affect the wells effectiveness. Preventing early unwanted fluidbreakthrough is key to the wells success, hence it is critical that an even production influx profile alongthe entire wellbore is achieved.

The production profile along the wellbore is affected by various parameters, including: heterogeneitywith respect to the permeability and reservoir pressure along the wellbore, the presence of fractures, andfrictional effects. Inflow control devices (ICDs) were developed to delay gas/water breakthrough,maximize sweep, and reduce even potentially eliminate future well intervention.

ICDs have become a mainstream completion tool in Saudi Arabia. With each ICD completiondeployment, a better understanding is gained with respect to deployment and installation of the lowercompletion, as well as a greater insight to how to achieve optimum reservoir management. Analysisgained from the previous wells has helped capture a substantial amount of best practices and lessonslearned.

This paper intends to capture the lessons learned after more than 10 years of deployment of inflowcontrol completions in Saudi Arabia. The main topics that are to be discussed are:

ICD types, the optimum operating envelope, and new technological advancements Optimum ICD design approach Open hole packers Deployment systems Best operational practices and their potential impact

This paper provides a guideline for designing a well with ICD completions, and explains how theadvancement in technology impacts cost, time and reservoir management.

IntroductionHorizontal and deviated wells have become an excellent method of developing fields to maximizeeconomics, increase productivity and improve recovery efficiency. Furthermore, horizontal wells providethe optimum mechanism for reservoir management especially in thin reservoirs where coning/caspingmake conventional well types less efficient for oil recovery. The effectiveness of a horizontal well islimited once premature unwanted fluid (gas, water) breakthrough occurs, potentially leaving significantamount of potentially recoverable reserves behind. Therefore, for horizontal wells to achieve optimumrecovery it is critical that the production influx along the wellbore is uniform or produces in a manner thatdelays unwanted fluid breakthrough. Some of the phenomena that impact the production influx along theproducing wellbore section are:

Heel-to-toe effect due to the frictional effect along the wellbore (Figure 1)

Permeability heterogeneity (Figure 1) Pressure differential along the wellbore Different mobility ratios of oil, gas and water

In a homogeneous reservoir the heel-to-toe effect due to the friction is a function of the reservoirpermeability, reservoir pressure, fluid properties, well length, flow area and production rate. In reservoirwith low permeability (requiring higher draw-down to achieve target rate) the heel-to-toe effect is less. Asimple study to demonstrate the effects of permeability on the effect is presented in Figure 2. The studywas conducted with light oil of 30 API, for a well length 3,000 ft across the reservoir section at a TVD

Figure 1Inflow along the open hole interval

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of 6,000 ft. The wellbore trajectory has no tortuosity in the horizontal section as the intention of the studyis to demonstrate the effects of permeability.

It can be observed that a reservoir with homogeneous permeability of 10 mD (indicated by the blueline) has an even production influx along the entire reservoir section. As the reservoir permeabilityincreases it can be observed that the heel-to-toe effect becomes more pronounced.

The impact of pressure differential across the production interval can have a significant impact onproduction influx along the wellbore. Using the same basic approach as the previous example (1 Darcycase), a pressure differential of 25 psi from heel to toe was placed to demonstrate (Figure 3) the effectsof pressure differential.

Figure 2Oil influx along the reservoir section for cases with varying permeability

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As shown in Figure 3, there is a significant volume of oil that is reinjected into the toe of the well. Thecross-flow can impact the reservoir flow capability of the section affected by the cross-flow; hence oncethe pressure profile evens out the production contribution may never be as expected.

To control production influx along the horizontal interval inflow control systems have been developed.Inflow control systems are designed to regulate the production influx along the wellbore ensuring that thelife of the well is extended with higher recovery efficiency.

Brief History of ICDs in Saudi ArabiaICDs were deployed for the first time in Saudi Arabia in 2002 (Qudaihy, et al. 2003), to obtain uniformproduction influx along open hole horizontal section and to delay water breakthrough, maximizing therecovery from a long radius horizontal sandstone production well. In 2005 the technology had evolved tobe better suited for consolidated formation. In 2006, ICD systems have been expanded to include shortradius reentry producers across the Arab-D carbonate reservoir in Ghawar field. Since 2009 various newtechnologies with respect to inflow control have been deployed such as:

Ultra slim ICDs (Al-Mumen, et al. 2009) (Lyngra, et al. 2007) ICDs with Multi-Tasking Valve (MTV) SYSTEM (Infra, et al. 2010) ICDs with sliding sleeve (retrofit in 2010 and part of kit in 2012) (Madan, et al. 2013)

In 2012 ICD applications included water injectors in highly fractured reservoirs (Al-Abdulmohsin, etal. 2013). Since 2012 Aramco has moved toward using autonomous type passive inflow control devices(Madan, et al. 2013), (Al-Kadem, et al. June 4, 2015).

All the technological advancement have been developed to help achieve optimum recovery from thewell while easing the deployment operation as well as reduce the risks with respect to HS&E and successof the operations. Saudi Aramco has continually pushed the boundary for achieving the optimum fieldmanagement while reducing the risks associated with the deployment and installation of the completion.In 2013 this paradigm was achieved with the deployment of an ICD lower completion deployed with an

Figure 3Oil influx along the reservoir section for cases with a pressure differential from heel to toe

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off-bottom cemented kit in a carbonate reservoir (Madan, et al. 2013). This feat was finally achieved in2015 for sandstone reservoirs, when the first ICDs with MTV was deployed for the first time.

Passive Inflow Control DevicesInflow control systems can be broken down into two categories; active and passive inflow control. Activeinflow control allows for changing of settings as required throughout the production life of the well.Passive inflow control systems are configured prior to deploying the system, based on known reservoirdescription and understanding. Once the system is installed the settings cannot be modified. This paperdiscusses mainly passive inflow control systems.

A passive inflow control device (PICD) is a choking devise that balances inflow along the wellbore byadding additional rate dependent pressure drop. There are several PICD types in the market currently suchas, friction type, restriction type and hybrid (autonomous) type.

The friction type ICD such as the Helix (Figure 4) uses surface friction of the helical channel togenerate pressure drop. This type of ICD is designed to produce a distributed pressure drop over arelatively large area; hence this ICD type is less prone to erosion and plugging concerns due to the largeflow area. The pressure drop of the friction based ICD is described with Poiseulles law shown in Equation1.

Equation 1: Poiseulles Law used to describe the pressure drop through a friction-based ICD

As can be seen from Equation 1, since the pressure drop is due to friction this type of ICD is viscositysensitive hence it is not applicable for reservoirs with higher viscosities.

Another disadvantage of the friction type ICDs is not having the ability to adjust the resistance settingat the rig-site. In Saudi Arabia some friction-based ICDs used in sandstone reservoirs were modified toprovide adjustability at the rig site. The modification only provided two settings for each device.

The restriction type ICD such as the nozzle/orifice (Figure 5) use restriction to generate the desiredpressure drop. The restriction type ICDs are more prone to erosion and plugging due to the small flow areaof the nozzle/orifice.

Figure 4Friction-based ICD

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The pressure drop for the restriction-based ICD can be characterized by Bernoullis equation (Equation2) (Jones, et al. January 1, 2009). From Equation 2 it can be deduced that the restriction-based ICDs areless sensitive to viscosity. They do have an operating envelope for applicability before viscosity has asignificant impact on the performance.

Equation 2: Bernoullis equation used to describe the pressure drop through a friction-based ICD

Based on flow loop tests conducted on various ICD (Lauritzen and Martiniussen 2011), the dischargecoefficient (CD) of an office is a function of the Reynolds number. This can be observed in Figure 6, takenfrom SPE-146347.

Both friction and restriction type ICDs have a limited operating envelope depending on reservoir fluidproperties, environment and inflow control strategy. One of the major limitations of the friction andrestriction type ICDs is that neither ICD type is truly viscosity insensitive; neither type works in anautonomous manner. Therefore, prior to selecting a device it is critical to take into account not just howthe reservoir behaves during the oil phase but also how the ICDs behave upon water breakthrough. The

Figure 5Restriction-based ICD

Figure 6Discharge coefficient (CD) of an office vs Reynolds number (Re) (Lauritzen and Martiniussen 2011)

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desired performance of an ICD is for the device to increase its resistance upon water breakthrough; thisprincipal is depicted in Figure 7.

For reservoirs with higher viscosity oil the necessity of the ICD to behave in an autonomous mannerbecomes of paramount importance to achieve the optimum recovery from the well. Therefore a third typeof ICD has been designed. There are several autonomous type ICDs in the market such as the one inFigure 8, which uses a labyrinth channel that incorporates restriction and friction as well as momentumto create a pressure drop by allowing the fluid to flow through a torturous pathway.

The new autonomous type ICD has the advantage of having large cross-sectional area is that itgenerates lower fluid velocity making them resistant to erosion and plugging during mud flow backoperation. The flow behavior through the torturous pathway for 1 cP water (Figure 9) and 189cP oil(Figure 10) illustrates the autonomous behavior of the device. The 1cP water takes a less direct path

Figure 7Behavior of autonomous and non-autonomous ICD upon water breakthrough

Figure 8Autonomous ICD

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compared to the 189cP oil, which has a more direct path from one stage to the next. The device is moredependent on the density of the fluid.

The characterization of the AICD, such as the one in Figure 8, was described by Coronado, et al.(Coronado, et al. 2009). Coronado, et al. suggested that Equation 3, which is used to characterize thepressure drop of liquid flow through the pipeline with valves, elbows, etc., used to characterize thepressure drop of the new autonomous type ICD.

Equation 3

Coronado, et al. observed the relationship of the pressure loss coefficient (K) and Reynolds number(Figure 11). Hence the data suggested that the pressure loss coefficient (K) relationship to Reynoldsnumber trend to be used to accurately characterize the AICD. A seven parameter logistic regression isused to fit the test data and describe the pressure loss coefficient for the ICD.

Figure 9Velocity of 1cP water through AICD

Figure 10Velocity of 189cP oil through AICD

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Equation 4: Pressure loss coefficient (K) equation (Coronado, et al. 2009)

The approach used by Coronado, et al. is the good method for characterizing the performance of theICD. Getting the flow performance of an ICD characterized accurately is of paramount importance whendesigning an ICD completion. If the performance is not characterized accurately the inflow completioncould potentially have adverse impact on recovery efficiency. When using dynamic simulator formodeling ICD completions the use of VFP tables may be the best option.

Figure 12, describes the performance behavior of the various types of ICD in terms of pressure dropfor oil relative to water at flow rate of 188 STB/day. As shown the viscosity of the oil (x-axis) increasesall the way up to 200cP. The y-axis is the relative pressure drop of oil to water. Hence, 0 on the y-axisindicates that the pressure drop of 188 STB/day of oil is the same as 188 STB/day of water; therefore theICD will not differentiate between oil and water. The optimum behavior is for the ICD to provide lesspressure drop to the oil phase than to the water phase. While for lower oil viscosities both restriction andfriction-based ICDs provide an equal or lower pressure drop for the oil phase than to the water phase; forrelatively higher viscosities the opposite is true where oil phase is choked back more than the water phase(Lee, et al. March 26, 2013, Lauritzen and Martiniussen 2011). Hence, for oil viscosities higher than 20cPa friction or restriction-based ICDs would not be applicable. The autonomous type ICD (purple curve inFigure 12), will provide less resistance to the oil phase (up to viscosity of 500cP for the devise in Figure8) than to water, hence the ICD chokes back the water phase more than the oil phase.

Figure 11Pressure loss coefficient (K) relationship to Reynolds number for different ICD types (Coronado, et al. 2009)

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Open hole PackersThe work published by Gavioli et al. (Gavioli and Vicario 2012) offers a comprehensive description ofopen hole packers. For this paper the basic guidelines and description have been provided as perexperiences of inflow control in Saudi Arabia.

There are several types of open hole packers available in the industry. Each packer type is unique andhas a niche application. It is critical that the open hole packers chosen are appropriate for the specificapplication. There are several factors that need to be considered when choosing open hole packer, suchas:

Required pressure differential rating across the packer Expected hole diameter, wash-outs or is the open hole gauge Deployment & Installation complexity Max OD during the deployment Deployment time Well trajectory and well data (mud weight, open hole, inclination, dog leg, etc.) Immediate seal required Formation type (shale, sand, carbonate, etc.)

External Casing Packers (ECP), Figure 13, are inflatable packers, in which the elements can be mudor cement inflated. Typically the most common ECPs have an inflatable element with non-continuousrib-type reinforcing at each end of the element. The ribs are steel strips that overlap each other and forma steel shell at each end of the element when it is expanded. The element length can vary from a few ftto 40 ft. In some cases it may include multiple layers of composite and non-composite ribs-typereinforcement at each end of the ECP to distribute stresses evenly, increase element strength, enhanceproper deployment in irregular wellbores and increase elongation of elastomer at high temperatures.

Figure 12ICD performance with respect to viscosity

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ECPs generally are flexible in the application. They do however, have some glaring limitations and willonly provide a permeant seal when they are cement inflated. This adds complexity when the packer isutilized as an isolation packer to create compartments. Furthermore, ECPs have a complex inflatingprocess and are more susceptible to suffering sealing element damage during deployment.

ECPs are generally used in Saudi Arabia for off-bottom cementing applications, where sections abovethe productive open hole section will need to be isolated with cement. In 2012 special ECPs (Extreme)were used as isolation packers to create compartments for the ICD completion due to large washouts.

Mechanical Noninflatable Open Hole Packers, Figure 14, use a noninflatable packing element toprovide a seal. This type of packer usually has an elastomeric element with composite structure which isset mechanically by allowing wellbore hydrostatic pressure or applied hydraulic pressure to flood anatmospheric chamber and to apply setting force to the noninflatable element. The element is thenmechanically locked in place via a body lock ring. Additional setting force can be attained by applyingadditional pressure by selective means or by applying pressure to the entire casing string if applicable.

A mechanical packer is normally run in the liner string between screens, slotted liners, or gravel packedsections as a means to isolate production intervals. It can also be used in annular cementing operations toisolate the open hole/liner annulus in open hole completions in conjunction with stage cementingequipment. This packer can be run as a single or stacked in multiples to provide for increased seal length.

Typically there are two potential setting mechanisms to allow downhole pressure access to the settingpiston. The available setting trigger mechanisms are mechanical and applied pressure. This packer is alsoavailable with a feed-through option for intelligent well or remote control option.

In Saudi Arabia this type of packer is widely used as isolation packers to create compartments; itperforms well in wells with open hole diameters larger than gauge. The packer has proved to be reliableand tough although setting the packers with applied pressure with ICDs that allow communication to theformation will require each packer to be set individually. A newer version of the packer has beendeveloped to incorporate an electronic trigger that activates the packer without the need for anyintervention or applied pressure.

Swelling Elastomer Packers, Figure 15, are commonly used in open hole. The element is designed toswell once it is in contact with oil- or water-based fluids. This packer in the first few years of its

Figure 13External Casing Packer (ECP)

Figure 14Mechanical Noninflatable Open hole Packers, run-in and set position

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introduction in the market became very popular, mainly due to its lower cost compared to other types ofpackers and simple deployment. Today it is probably the most commonly run wellbore isolation device.

This packer is designed to work in either oil or water to provide an annular seal in oil producers andwater injectors. Elastomers reacting with oil-based fluids can initiate the swell reaction in concentrationsas little as 3% oil, ensuring the element will set when deployed. As for the water-swelling compound, therate of reaction or swelling is a function of temperature and concentration of salts. The polymer will notreact in a pure oil-based fluid but, will begin swelling in low water-cut. There are a few things that areimportant to know about the water-swelling elastomer and the salt type present. Monovalent salts such asNaCl, KCl and Formates are reasonably good at providing enough free water for the element to function(up to about 20% by wt.). Divalent salts such as CaCl2, CaBr2 and ZnBr2 will inhibit the swelling of theelement in relatively low concentrations (5% by wt.). When a scenario involves high salt concentrationsand/or divalent salts, it is recommended to displace the packer area with fresh water based fluid or watercut hydrocarbon production. Swell packers have been tested at least up to 10,000 psi differential (this canbe increased further with a longer element) and are HCl, HF, H2S and CO2 resistant.

In Saudi Arabia this type of packer is widely used as isolation packer to create compartments. Its lowcost and simple installation makes this packer attractive to use. Its limitation is to the maximum O.D. thepacker can seal and maintain the required pressure differential limits. The packer will also not be able toprovide an instantaneous seal and this may not be suitable for some applications.

There are also smaller versions of the swell packers that can be installed directly onto the completionor liner pipes. The two main categories are clamp-on (Figure 16) and slide-on type packers. These packersare also usually called barriers, instead of packers, since the differential pressure across the set packer ismuch lower than for a standard packer, so they are used mainly as mean of annular barrier inmultisegmented completions.

Figure 15Swelling Elastomer Packer

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A typical clamp-on swelling packer is built with a rigid steel cage surrounded with either oil-swellingor water-swelling compound. The tool can be installed onto existing pipe and is secured to the base pipeusing a hardened steel pin.

The type of packer used for an ICD completion depends on several factors. All open hole packersessentially serve the same purpose of isolating and creation of compartments. The differences between thepackers are the activation mechanism, the limitation due to open hole condition, and time required for theseal to occur. In a sandstone formation where the open hole is gauge and has a lower chance of incurringloss circulation zones, swell packers are preferred due to simplicity and cost, since an immediate seal isnot necessary. One should also recognize the risk associated with swell packers, such as the swelling time.In the event that the deployment takes longer to deploy or gets stuck in the open hole for too long the riskof the swell packers swelling will increase. This situation makes the stimulation treatment or the fishingoperation more difficult.

Deployment System RequirementsSeveral deployment systems are used in Saudi Arabia, depending on the isolation requirements (Figure18).

Figure 16Clamp-on swell packer and its internal metal cage

Figure 17Slide-on swell packers

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In new wells where cemented casing is designed to cover non-targeted formation, there is norequirement for cement isolation above the interval of interest and a non-cemented option is utilized.There are two main non-cemented options, the most predominantly used system is the use of liner hanger-liner top packer or a packer that is sufficient to hang the completion off. This system has the sealingmechanism (Liner Top Packer) to prevent the flow bypass ICD through annulus. Also, the seal willprevent any unwanted flow from the casing shoe due to poor cement job or damage in the formation. Apacker can also be utilized inside the casing close to the shoe if there is potential leakage in formationbehind the casing. The liner top packer of the deployment system is set a minimum of 150 ft above thelast casing shoe to avoid setting the packer in damaged casing. The deployment system utilization ismainly dependent on the formation type. For a sandstone formation where oil-based mud is commonlyused, it essential to stimulate the target formation, to reduce skin created by the mud filter cake that couldaffect the production and increase the potential for screen plugging. This will require setting the liner toppacker after circulating the treatment. This operation is critical because the removal of the mud cake willlead to losses. Thus it is recommended to run the fluid loss valve, which will help in deploying the uppercompletion and also avoid losing drilling fluids into the formation. The deployment system should workin the following process:

1. Run in hole with the deployment assembly to the planned depth.2. Set the liner hanger and regain circulation if required.3. Pump the treatment.4. Set the liner top packer to let the treatment exposed to the targeted formation.5. Activate the fluid loss valve.

For a multilateral well, there are two approaches; the first is when the lateral is side tracked with a longradius lateral above the desired formation from the main bore casing, Figure 19. This will require a Level4 multilateral junction to isolate the drilled window rat hole with cement. Smaller bit will be utilized todrill the horizontal targeted formation; hence a smaller ICD completion with a non-cemented liner hangerand top packer deployment will be utilized, as shown in Figure 20.

Figure 18Deployment system tree

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The second is when the lateral is drilled in the same desired formation as fish bone lateral or shortradius lateral. This will require Level 2 Multilateral Junction (Whipstock) without cement requirementFigure 23. In this option uses a polish seal-bore drop off system to deploy the ICD Figure 24.

Figure 21Level 4 Multilateral with ICD Screen Systems

Figure 22Multilateral Well Plan 1

Figure 23Multilateral Well Plan 2

Figure 24Level 2 Multilateral with ICD Screen Systems

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This method uses a polish seal-bore drop-off, which in most cases will accompany a swell packer toprovide an annular seal. The system is utilized mainly in multilateral wells (Figure 25) and dropped offin the open hole section in the lateral a few feet from the mother bore. Usually in the sandstone formationthis option is avoided, as it would be challenging to stimulate the formation with the drop-off system.

If the formation above the zone of interest is deemed to require a cemented isolation than an off bottomcemented system is used. This will eliminates the need to drill a hole to the reservoir top, run a liner andcement it, then proceed to drill a smaller open hole across the reservoir.

There are two methods of off-bottom cemented systems used in Saudi Arabia one-trip deploymentand two-trip deployment. The trip refers to if the cement system components are deployed in a singletrip with the ICD completion or on a second trip, with the cement system stung into the previouslyinstalled ICD completion (Figure 26).

The off-bottom cemented kit consists of a seal assembly (if a two trip system is used), a float collar,a landing collar, two external casing packers (ECP), a hydraulic stage cementing valve (PAC Valve),blank pipe, a hydraulic liner hanger and mechanically set liner top packer. Mechanical set packer can berun below the ECP to offer redundancy and provide a better indication of the packer setting. For the twotrip system the seal assembly has been designed to give a positive indication that the seals had indeedlocated and sealed in the polish seal bore in the ICD completion assembly. Once the seals are placed inthe seal bore and the ball was circulated to the landing collar, the liner hanger was hydraulically set andthe ECPs were inflated. Once the ECPs were inflated and the ICD completion below the ECPs wasisolated, the cementing operation ensued, with the opening of the PAC valve. Once the cementing

Figure 25Short radius lateral non-cemented system

Figure 26Long radius two trip off-bottom cemented system

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operation was completed and the PAC valve was closed, the liner top packer was set mechanically. Theoperational concept of the one trip system is similar. Figure 27 is a typical two trip off-bottom cementedlower completion. The design of the off bottom system number of trips is depended on the horizontalsection length and the hole condition. If the hole is not stable or has washouts, it will be challenging tosting the seals into the polish bore. Thus, it is recommended to run the one trip system. The one trip systemhas a limitation in terms of operation parameters and deployment, such as not being able to have an innerstring with the assembly. Therefore an extra trip is required to set the mechanical set packers and pumpthe filter cake removal treatment.

The deployment systems in horizontal wells are highly recommended to be able to attain 100 percentcirculation through the toe of the completion. In Saudi Arabia the use of a circulation system to 100percent circulation through the toe of the completion is standard practice. The circulation system providesthe benefits associated with the normal run-in-hole, but also helps achieve a more efficient way of spottingstimulation fluids and provides more options if the deployment gets stuck while running in open hole. Theconcern with running inner string is the extra weight that increases the potential of differential sticking.Also the operation complexity increases the like hood of NPT and injury risks. Also the circulation systemcan get hydraulic lock between the fluid loss valve and the circulation system, which results in fishing theinner string.

As the ICD deployment is usually utilized in extended reach wells, there are some limitations in termsof stiffness and number of packers used. From reservoir point of view, the higher the number ofcompartments that are used in the completion the more control the completion has over the inflow. It ismore challenging to deploy the completion to TD, due to the increase in drag forces and stiffness of theassembly with an increase in packers. Therefore torque and drag analysis should be conducted to ensurethat the completion is able to be deployed to TD. In Saudi Arabia, the general rule used is that the

Figure 27Two trip off-bottom completion (Madan, et al. 2013)

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completion will be limited to no more than 56 long packers. If more compartments are required, thenthey will be created by the barrier type packers that are clamp on pipe or slide on pipe type.

Another important consideration is the importance of a smooth transition from vertical to horizontalwhile drilling and avoid having a dogleg of more than 35 Deg/100ft in the hole. In terms of rotation andreaming to bottom while deploying the assembly, it is not recommended as it may damage the screens andthe packers.

Completion Design MethodologyFirst step in obtaining the optimum completion design is to select the lower completion components thatare fit-for-purpose. Therefore it is critical that ICD type chosen has the flow characteristics that are bestsuited for the reservoir, and has the functionality that is required to design the optimum lower completion.The open hole packers should also be chosen to ensure that the packer will provide the required pressurerating across the sealing element.

To obtain equalization along the open hole section, the average pressure drop across the ICDcompletion (PICD) has to be equal to or higher than the pressure drop at the sand face (Psandface). Thisgeneral design concept (Figure 28) is applicable for carbonates and sandstone; if the PICD is less thanPsandface, the reservoir parameters will dominate the production influx along the wellbore.

While it is beneficial that the general ICD design concept is applied, it is not critical that the completiondesign rigorously maintain a PICDequal or higher than thePsandfacefor all the compartments. Thepressure drop distribution can be different for various compartments depending on the requirement; lowPICD could be placed in compartments that have relatively lower flow parameters (i.e., permeability) andthere is little concern of unwanted fluid breakout from occurring, while a higher PICDshould be placedin compartment with higher uncertainty or higher chance of unwanted fluid breakout occurring. Figure 29is a typical example of the pressure distribution for an ICD completion design.

Figure 28General ICD design concept

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To achieve the required PICDneeded to obtain equalization the number of ICD joints and the FlowResistance Ratings (FRR) are key design parameters. For a constant liquid rate, the number of ICD jointsand the FRR directly affects the pressure drop created across the ICD. Hence it is important to determinethe target production rate and the maximum drawdown, to determine the optimum number of ICD jointsand the FRR required, to achieve the optimum recovery from the well.

To achieve the equalization goals for wells in consolidated formations, the number of joints can bevaried depending on the target production rate and the maximum drawdown. Hence, the number of jointswill be dependent on the reservoir parameters, production requirement and reservoir managementstrategy. The number of ICD joints can be determined once the pressure drop across the ICD completionis defined. The performance curve (Figure 30) of the ICD is used to determine the liquid rate per ICD jointfor the allowable pressure drop through the completion. Dividing the expected production target rate bythe liquid rate per ICD joint will determine the number of ICD joints and/or flow resistance rating for thecandidate well.

For unconsolidated sandstone reservoirs, the number of joints are fixed to ensure that screens are placedacross the sands; this is done to reduce the possibility of sand production, due to high fluid velocities fromthe sandface, especially in a highly unconsolidated formation in case high pressure drop situation is

Figure 29Example of typical pressure distribution

Figure 30ICD 1.6 FRR performance curve

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created, and to ensure that there is enough screen coverage across the sands in the event that some screensplug. Hence ICD used in unconsolidated sandstone reservoirs will need to have sufficient FRR settingsto achieve the required level of control over the production influx along the production interval. Generally,for wells in unconsolidated sandstone, a higher number of ICD joints will be utilized compared to wellsin consolidated formations.

Another key design guideline is to create effective compartmentalization of the wellbore. The processof compartmentalization is to prevent annular flow that can affect the performance of the completion.When the annulus is open to flow, the path of least resistance for the fluid after entering the wellbore fromthe reservoir will be along the annular area. This phenomenon is due to the completion creating aresistance to fluid (pressure drop) that, even if its minimum is still enough to divert the flow in alldirections in the annulus before entering the completion. If severe heterogeneities are present, thereservoir-to-wellbore flow will be dominated by those heterogeneities, minimizing the benefits of an ICDcompletion.

Therefore, ICDs alone without the use of packers will provide limited impact to reservoir managementaspect, unless the well is in an unconsolidated sandstone formation where a gravel pack completion willbe implemented. The gravel pack will essentially eliminate annular flow from occurring. From a reservoirmanagement view a gravel pack will be an optimum completion. The number of compartments, placementof packers, number of ICD and the associated FRR are determined based on reservoir parameters, suchas permeability, quality of fractures, differential pressure (heel-to-toe), water saturation, proximity tooil-water contact or injector well.

Generally the higher the number of compartments the more control the completion would have on theproduction influx along the wellbore (Gavioli and Vicario 2012). Gavioli et al. reviewed the water-cut ofwells in a carbonate field in Saudi Arabia to determine the optimum number of compartment. The wellsthat were studied were experiencing water production after a minimum of a years production; all the wellswere located in the same area. Gavioli et al. proceeded to plot the water-cut for each well against thenumber of compartments (Figure 31). Based on the results of the study one can drive the optimum numberof compartments. It can also be noted that while the water-cut was not consistent, the higher the numberof compartments, the more the water production is controlled. It should also be noted that morecompartmentalization is need to control gas compared to water.

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Various scenarios of different number and location of compartments, number of ICDs in eachcompartment, FRR of each ICD, and potential water breakthrough cases should be modelled andevaluated using near wellbore simulator when determining the well design. There are general guidelinesto help determine the starting point to obtain the most effective design for the well.

When designing an ICD completion, it is generally accepted that the greater the heterogeneity in thereservoir the more compartments and the higher the pressure drop (reduction of ICD joints and/or higherFRR) through the completion is required (Figure 32).

Similar considerations exists when taking into account the mobility of the fluid and the number ofpossible or suspected entry points for undesired fluid (Figure 33). The more entry points and the smaller

Figure 31Effect of compartmentalization in water control (Gavioli and Vicario 2012)

Figure 32Empirical relationship between number of compartments, FRR and reservoir heterogeneity (Gavioli and Vicario 2012)

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(or discrete) are those entry points of undesired fluid, the more compartments and the higher the FRR isrequired.

Furthermore, another criteria used for selection of the number of compartments, number of joints andFRR is the level of uncertainty (Figure 34). The more uncertainty and lack of data exists the morecompartments and the higher the FRR that is needed.

Best Operational Practices and Potential ImpactGood clean-up practices and efficient filter cake removal is critical to the performance of the wells. Thisis especially true in Sandstone reservoirs. It should be noted that in the industry it is generally accepted

Figure 33Empirical relationship between number of compartments, FRR and undesired fluid mobility and number of breakthroughpoints (Gavioli and Vicario 2012)

Figure 34Empirical relationship between number of compartments, FRR and uncertainty (Gavioli and Vicario 2012)

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that for Stand-Alone-Screen (SAS) completions, screen plugging is associated with poor clean-uppractices and filter cake damage, hence extreme care should be taken to address these key designparameters during the planning phase of a well. The work done by Furgier et al. (Furgier, et al. 2013)further confirms that when SAS completions are designed with care, they can perform well.

Work done by Shahri et al. (Shahri, et al. 2009) looked at the actual versus expected production trendsin a Sandstone reservoir offshore Saudi Arabia. The work indicated that the test rate generally underper-formed what was expected.

The underperformance of the wells was attributed to insufficient clean-up and formation damageduring drilling. Proper design of the drilling fluids, better clean-up prior to deployment of the lowercompletion, spotting a filter cake removal treatment and sufficient cleanup techniques once the well hasbeen completed can significantly improve productivity of the well. The work of Shahri et al. (Shahri, etal. 2009) Further validates the importance of treatment fluids (Figure 36). The wells with the proper filtercake removal treatment preformed as per expectations if not better.

Figure 35Production trend (actual vs expected) for well completed with ICD screens without treatment (Shahri, et al. 2009)

SPE-176801-MS 23

To achieve an efficient placement of the treatment fluid it is essential for the deployment system to beable to have 100 percent circulation through the toe of the completion. Generally this is achieved with theuse of an inner string. Running an inner string is time consuming and adds additional work that can beassociated to unnecessary risks that should be avoided if possible. A recent feature in the market has beenthe Multi-Tasking Valves (MTV) (Figure 37); this device essentially prevents communication betweenupstream and downstream of the ICD, basically making the ICD behave like blank pipe during deploy-ment.

The MTV consists of a pins that prevent pressure communication when the seals on the pins are sealingin the housing, two ball bearings that prevent the pins from ejecting, a spring that will eject the pins oncethe well is ready to be put on production, a shear pin that prevent the pins from getting activatedprematurely and magnets that will attract the steel ball bearings once the shear pin has been sheared. Thevalve is placed between the ICD module and the ports into the tubing Figure 38.

Figure 36PI actual vs. expected comparing a flow back without treatment to the ones with treatment (Shahri, et al. 2009)

Figure 37MTV

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The MTV feature reduces cost and time while reducing the risks to safety associated with the lowercompletion installation operations. Besides the circulating through the toe of the completion, the MTVvalves provides additional benefits such as setting of mechanically activated open hole packers withoutan inner string and could be setup to behave as a fluid loss control valve (FLCV).

The MTV system work in the following process (Figure 39):

1. During run-in-hole stage the MTV valves remain in closed position. Once the completion is ondepth all treatment fluid can be circulated.

2. Once the treatment has been concluded a low specific gravity is floated to the shoe of thecompletion essentially isolating the completion from the reservoir. During this stage all hydrau-lically set equipment (such as the mechanical packers and liner hanger packer, etc.) are set. Thepins can now be activated if need be; if the pins are activated they will remain in place as long asthe 200 psi overbalance is maintained. The shear pins can be designed to allow the MTV to behaveas an FLCV, and even allow for the upper completion to be set against it.

3. When the pins have been activated and the hydrostatic is lightened to below 200 psi overbalancethe pins are ejected and the valve is open to flow.

Along with all the benefits that have been stated, the operational time saved by the device has had aquantifiable impact. Based on a pervious study, conducted by Maden, et al., on two wells in the samecarbonate formation, the ICDs with MTV feature proved to save a little more than one day of rig timeoperations (Figure 40).

Figure 38View of ICD in conjunction with MTV

Figure 39MTV positions

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Recently the first ICDs with MTV have been deployed in Saudi Arabia and the time analysis based onan analogue well indicated that 1.75 days has been saved by using the MTV feature (Figure 41). Theimpact associated to the time saving can easily be quantified financially. One should also take into accountthe risks from an HS&E and potential time dependent problems avoided by reducing this time.

Figure 40Rig time comparison: Standard ICD liner vs. ICD system with MTV for a carbonate reservoir (Madan, et al. 2013)

Figure 41Rig time comparison: Standard ICD liner vs. ICD system with MTV for a unconsolidated sandstone reservoir

26 SPE-176801-MS

Another critical parameter in the design process is to ensure that the production rate does not exceedthe erosional velocity of the device. Slight erosion of the flow area of the device can significantly affectthe performance of the ICD. The ICD types that have relatively higher velocity are more prone to erosionand it should be a key consideration parameter when selecting an ICD.

Stopping annular flow in SAS applications is important for the longevity of the completion. While ICDcompletions significantly reduce the annular velocity that could essentially lead to hot spotting, the useof compartmentalization of the ICD completion can further reduce annular velocity. A simple study wasconducted to demonstrate the effects of compartmentalization on annular flow velocities. The studyfurther illustrated the impact of ICD and compartmentalization can significantly reduce the annularvelocity (Figure 42). The study has been conducted on light oil of 30 API, for a well length 3,000 ft acrossthe reservoir section at TVD of 6,000 ft. The wellbore trajectory has no tortuosity in the horizontal section,as the intention of the study is to demonstrate the effects of ICD and compartmentalization. The work doneby Regulacion, et al. (Regulacion and Shahreyar 2011), further confirms the effect of compartmentaliza-tion with ICD completions.

Figure 42Annular Velocity

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The FRR will also have an impact on an annular velocity. Looking at an ICD completion that is notcompartmentalized by increasing the 0.8 FRR to 6.4 FRR the annular velocity is significantly reduced(Figure 43).

The high FRR will also impact the production influx along the wellbore, hence leading to moreefficient oil recovery from the well. The equalization of the production influx should delay waterbreakthrough and reduce cumulative water production. Coupling the ICD strategy with Improved OilRecovery (IOR) and Enhanced Oil Recovery (EOR), the sweep efficiency should increase, leading tohigher oil recoveries. To illustrate the effect of the FRR a simple model is used with a light oil of 30 API,for a well length 3,000 ft across the reservoir section at TVD of 6,000 ft. The permeability of each 500ft compartment ranges from 50 mD to 1 Darcy (Figure 44).

Figure 43Annular velocity comparing 0.8 FRR vs 6.4 FRR

Figure 44Permeability distribution

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The intention is to capture the production influx from the reservoir into the well, along the horizontalunconsolidated sandstone section. The model was set to a liquid constraint of 10,000 STB/day. The resultsseen in Figure 45, show that the production influx along the wellbore is more even for the higher FRR6.4 (red) than the 0.8 FRR (purple). Furthermore, looking at the pressure profile the pressure drop throughthe sandface, remains higher in most compartments then the pressure drop through the ICD for the 0.8FRR. The results indicate that while the ICD is providing some benefit compared to SAS (not shown) thecompartment in the heel of the well would experience an earlier unwanted fluid breakthrough. The 6.4FRR provides a more equalized production profile. The designs could be further optimized but the intentis to demonstrate the importance of having a sufficient FRR. Note that the 6.4 FRR completions consumemore energy than the 0.8 FRR and when designing the ICD completion, it is important to develop aninflow control strategy that meets the economic needs of the well.

General best practices suggest that ICD completions should have a compartment size of 300500 ft.As previously stated, compartmentalization is critical to achieve optimum recovery from a well. Thecompartmentalization should take into consideration permeability, pressure and saturation profile along

Figure 45Pressure and production influx along the wellbore

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the wellbore as well as consider the stand-off and relative position of other wells (injector and producers).Furthermore the ICD and compartmentalization strategy should take uncertainty analysis into account. Toillustrate the impact of increasing compartmentalization a simple model is used with light oil of 30 API,for a well length 3,000 ft across the reservoir section at TVD of 6,000 ft. The permeability used for thematrix is 250 mD and two fractures are placed at heel and middle of the well (Figure 46). The model isused as an analogue to a typical carbonate in Saudi Arabia. The model was set to a liquid constraint of10,000 STB/day.

The simulation done is to demonstrate the impact of increasing compartmentalization, therefore thewater saturation in the fracture is increased (Figure 47); this is to simulate the fractures in the process ofbecoming watered out.

Figure 46Permeability profile

Figure 47Saturation profile

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Two scenarios were run, the first with six compartments of roughly 500 ft, the second 19 compartments1 compartment per ICD and two blank pipe joints. The simulation resulted in decreasing the water-cut by42.78 percent (Figure 48).

It is important to note that this analysis only considers that the water saturation is the same in both casesand is only evaluating the near wellbore effects; hence comparing like for like. The reality is that the waterbreakthrough would be furthered delayed and hence the water saturation would be lower for the designwith a larger number of compartments. During the design process a dynamic reservoir simulator wouldbe able to compare the value added by the additional compartmentalization.

It should be noted that the intent of the analysis is to simply illustrate the value of compartmental-ization. For carbonate and highly fractured reservoirs, a good reservoir characterization and a goodunderstanding of the fracture-matrix interaction should be used to determine an inflow control strategywith respect to how to complete the fracture segments. In the case shown, blanking the fracture sectionscould have provided a better completion strategy and result in a better oil recovery from the well. Adynamic reservoir simulator should be used to quantify the differences between the various ICD designs.

ICD Completion Workflow OverviewThe authors of this paper would like to summarize a typical ICD workflow. It starts from the point thatthe ICD completion was deemed the optimum completion for the reservoir and is to be implemented foran upcoming well.

The process should begin with obtaining reservoir and analogue well data. Often lessons learned fromother wells can help avoid encountering problems with the current well. The data should be used to

Figure 48Production water influx along the wellbore

Table 1Water-cut results

SPE-176801-MS 31

determine the requirement for the ICD, such as, the optimum type, the number of ICD joints, and the FRRand compartmentalization requirements. Simple analytical methods can be used to obtain the ICDrequirements.

For isolation requirements the engineer will need to have a good understanding if potential washoutsare likely. If there is an expectation of significant washout occurring swell packers may not be ideal anda mechanical packer should be considered. If the washouts are significant an ECP should be consideredif no other packer type is able to provide the required pressure differential across the seal; in this eventthe engineer should consider the fluid used to inflate the packer-based on perceived operational risk andtemperature of the reservoir and fluid. A caliper log should always be used to confirm the placement ofpacker in the open hole section to ensure the packer is able to provide the required seal.

The completion engineer should also ensure that the reservoir drilling fluid design is compatible withthe formation, formation fluid and completion. Furthermore the completion engineer should considerutilizing a filter cake removal treatment. This is an additional cost but the risk of not utilizing a properfilter cake removal treatment could impair productivity significantly. The deployment system used for theICD completion should take into account all operation requirements. The deployment system should bechosen to simplify the operation and ensure that the completion installation is efficient and effective. MTVtype systems provide value and should be considered.

To obtain the optimum completion design modeling is required. There are several ways of modelingand designing ICD. For the designing and analysis a dynamic reservoir simulator and analyticalsteady-state wellbore simulator are typically used. It is critical to understand the capability of eachsimulator. A steady-state wellbore simulator will allow an engineer to understand the physics occurringin the near wellbore in relatively easy and short time; hence steady-state wellbore simulator can be usedto determine the resistance strength (FRR), number of ICD joints and compartmentalization requirementswith relative ease. The effective use of a steady-state wellbore simulator will improve understanding ofthe phenomena that is occurring near the wellbore and be able to come up with a design that provides therequired inflow control along the wellbore. A dynamic reservoir simulator will provide a better understandof the dynamics occurring within the reservoir and validate the ICD completion design.

The authors of this paper recommend using both a dynamic reservoir simulator and steady-statewellbore simulator to design the completion. A typical approach when designing ICD completion isshown in Figure 49.

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Another important point to remember is to implement an ICD completion that is effective. It is criticalthat a good understanding of the reservoir is obtained. Therefore it is important for reservoir engineersdesigning the ICD completion to track the drilling operation and take note of drilling parameters, such as,where losses occur, rate of penetration, tight points, etc.

Future DevelopmentThe authors of this paper believe that the boundaries should be continually pushed to achieve higher andmore efficient oil recoveries. While the industry has made great advancement in the realm of inflowcontrol, further progress is needed. ICDs provide a system that can optimize recoveries in a lot ofapplications and in some cases makes it economical to develop fields that without the advent of ICDswould not be economical. The industry is currently working on developing passive devices that are moreautonomous and self-regulating, with some success being observed.

In more challenging environments, a passive system like ICDs may not be the optimum tool and anactive inflow control should be investigated. Until recently the flaw with active inflow control systemswas the limitation of the number of compartments possible. Systems like the MultiNode (Figure 50),recently deployed in Saudi Arabia, seems to be a more attractive development tool for long reach wellsthat are in complex reservoirs with a high level of uncertainty.

Figure 49Typical ICD modeling approach

SPE-176801-MS 33

ConclusionThis paper has outlined the learnings attained in Saudi Arabia after 10 years of the deployment of ICDs.The main objective of this paper was to describe the best practices when designing, deploying andinstalling the PICD, such as:

Using the ICD type that is best suited for the reservoir Using components that simplify and provides cost savings such as the MTV Using good clean-up practices will significantly improve well productivity Using a good filter cake treatment is well worth the money and should be used for all wells The impact of compartments and optimum packer The importance of the FRR

Nomenclature

AICD Autonomous Inflow Control DeviceCD Discharge CoefficientcP CentipoiseECP External Casing PackerEOR Enhanced Oil RecoveryFLCV Fluid Loss Control ValveFRR Flow Resistance RatingCD Inflow Control DeviceIOR Improved Oil RecoveryK Pressure Loss CoefficientmD Milli-DarcyMD Measured DepthMTV Multi-Tasking ValveM/U Make UpOH Open HoleP PressurePAC Pressure Actuated Cement valvePI Productivity IndexPICD Passive Inflow Control DevicePOOH Pull Out Of HoleQg Gas Production InfluxQo Oil Production InfluxQw Water Production InfluxRe Reynolds Number

Figure 50MultiNode electrically operated valve

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RIH Run In HoleSAS Stand Alone ScreenSTB/Day Standard Barrel per DayTD Total DepthV velocityWC Water-Cut Fluid Density ViscosityPICD Pressure drop through Inflow Control DevicePsandface Pressure drop through sandface

AcknowledgementsThe authors would like to thank management of Saudi Aramco & Baker Hughes for their support andpermission to publish this paper.

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Milestones, Lessons Learned and Best Practices in the Designing, Deployment and Installation of ...IntroductionBrief History of ICDs in Saudi ArabiaPassive Inflow Control DevicesOpen hole PackersDeployment System RequirementsCompletion Design MethodologyBest Operational Practices and Potential ImpactICD Completion Workflow OverviewFuture DevelopmentConclusion

AcknowledgementsReferences