Integrated Cemented Inflow-Control-Device System Design

Off-bottom cementing (OBC) operations are unique to Saudi Arabia and also represents one of the most challenging types of drilling and workover operations, when deployed in combination with inflow control devices (ICDs) across horizontal sections. In a conventional ICD system, an inner string with packer setting tools is required for setting open hole packers, and to have 100% circulation at the bottom of the completion, to wash down any tight spots. As a consequence, this introduces additional issues such as health, safety and environment, logistics and additional rig time. The inner string also increases the ICD completion string weight, while deploying the system in the horizontal section, creating more drag and increasing the risk of getting stuck. The multitasking valve (MTV) feature in the upgraded ICDs offers safe, simple and cost-effective deployment operations. The MTV allows the system to be deployed without the need for an inner string. This will positively impact the deployment by simplifying the complexity in the rig operation while achieving 100% circulation at the shoe. Besides, all the hydraulically activated equipment, such as the liner hanger packer, open hole mechanical packers, etc., can be pressurized and set simultaneously. Furthermore, the ICD completion will weigh less in the horizontal section, resulting in less friction and drag to reach total depth (TD). The MTV feature provides an opportunity to deploy the ICD system and the OBC liner system together in one trip. This paper will discuss the first deployment of a combined ICD system with an OBC system for a workover operation, in a historical oil well producer in the Kingdom of Saudi Arabia. The merged system was successfully deployed to depth, then cemented off-bottom, saving approximately 40 hours of rig operation time.

The most challenging aspect of reservoir management in a highly fractured carbonate reservoir is determining a completion that has the ability to control the production flux and prevent early unwanted fluid breakthrough while maintaining the production. Throughout the years, Saudi Aramco has made much advancement in the field of reservoir optimized completions, by continuously implementing new technology and techniques that enhance the design and deployment of these completions. When designing an ICD completion, it is critical to design a completion that is best able to provide production flux control while meeting production requirements, as well as considering key operational factors such as, safety, cost and the time required completing the design. On a recent well in Saudi Arabia an ICD completion was designed to achieve an optimum lower completion as well as reducing the safety risk, the overall cost of the completion and achieving a faster deployment time by deploying for the first time in the Middle East a new generation of Inflow Control Devices (ICD) in a work-over well. The new ICD contains several unique features, such as the new third generation ICD flow mechanism, the multi-tasking valve (MTV) and a built-in sliding sleeve. The new third generation ICD flow mechanism is a labyrinth flow path design that is strongly dependent on the fluid density (the lower the density, the lower the pressure drop across the ICD), therefore making the ICD viscosity insensitive to fluids; the ICD is virtually insensitive to viscosities up to 300 cp. Another advantage of the new ICD design is the adjustability of the flow resistance rating (FRR) feature that provides reservoir engineers further option in designing the lower completion. The new ICD design also features the MTV valves, which simplify the deployment of the completion therefore making the deployment operation safer and more cost-effective.

Horizontal well completions are often equipped with Inflow Control Devices (ICDs) to optimize flow rates across the completion for the whole length of the interval and to increase the oil recovery. The ICD technology has become useful method of optimizing production from horizontal wells in a wide range of applications. It has proved to be beneficial in horizontal water injectors and steam assisted gravity drainage wells. Traditionally the challenges related to early gas or water breakthrough were dealt with complex and costly workover/intervention operations. ICD manipulation used to be done with down-hole tractor conveyed using an electric line (e-line) cable or by utilization of a conventional coiled tubing (CT) string. Wellbore profile, high doglegs, tubular ID, drag and buoyancy forces added limitations to the e-line interventions even with the use of tractor. Utilization of conventional CT string supplement the uncertainties during shifting operations by not having the assurance of accurate depth and forces applied downhole. A field in Saudi Arabia is completed with open-hole packer with ICD completion system. The excessive production from the wells resulted in increase of water cut, hence ICD's shifting was required. As operations become more complex due to fact that there was no mean to assure that ICD is shifted as needed, it was imperative to find ways to maximize both assurance and quality performance. In this particular case, several ICD manipulating jobs were conducted in the horizontal wells. A 2-7/8-in intelligent coiled tubing (ICT) system was used to optimize the well intervention performance by providing downhole real-time feedback. The indication for the correct ICD shifting was confirmed by Casing Collar Locator (CCL) and Tension & Compression signatures. This paper will present the ICT system consists of a customized bottom-hole assembly (BHA) that transmits Tension, compression, differential pressure, temperature and casing collar locator data instantaneously to the surface via a nonintrusive tube wire installed inside the coiled tubing. The main advantages of the ICT system in this operation were: monitoring the downhole force on the shifting tool while performing ICD manipulation, differential pressure, and accurately determining depth from the casing collar locator. Based on the known estimated optimum working ranges for ICD shifting and having access to real-time downhole data, the operator could decide that required force was transmitted to BHA. This bring about saving job time while finding sleeves, efficient open and close of ICD via applying required Weight on Bit (WOB) and even providing a mean to identify ICD that had debris accumulation. The experience acquired using this method in the successful operation in Saudi Arabia yielded recommendations for future similar operations.

This paper includes a discussion of a progressive approach and recent practices to stimulate wells in one of Saudi offshore fields. A chemical treatment pilot aimed for production enhancement was recently conducted and proven successful in an offshore environment while recognizing merits associated, including fluid placement optimization in terms of logistics and time beside treatment effectiveness. Implementation of such practices has increased chemical treatment success rate, enhanced well production performance, reduced cost and improved operational HSE practices. The recent chemical treatment applications and practices were the outcome of five years of dedicated search and collaboration with service companies to find the most effective chemical recipes and their deployment method. The campaign was initially piloted in three different wells completed with inflow control devices wrapped with premium screens, using three different chemical applications while utilizing a distributed temperature sensing (DTS) technology for the first time in an offshore field to evaluate treatment effictiveness. Initially, three wells were completed in high permeable and contrasted sandstone layers. Those wells are completed with sandstone screen completions coupled with inflow control devices to control sand production while providing a degree of production management across the producing lateral. The completion practice prior to the pilot did not allow an efficient cleanup due to HSE and operational considerations. Extensive technical, operational and economical evaluations were conducted to ascertain the best chemical recipe, fluid placement technique, equipment and applications used to ensure the proper treatment exposure to the damaged zone for better production output results. Horizontal completion practices have changed; hence new challenges have arisen to consider for instance the best contemporary placement technique used for treating fluids in different type of horizontal completions. Long horizontal sandstone producing laterals in the past, which used to be completed as cased and perforated are being completed as open hole laterals with inflow control devices coupled with screens where the fluid placement technique must vary to account for best and uniform treatment coverage. This paper will include the pilot results and recognized merits. Offshore production engineering insights will be also shared in this paper. Introduction The first chemical treatment experience in offshore sandstone fields in Saudi was in 2005 with a limited success especially in "S" oil producing field. Search for better recipe resulted in identifying three chemicals; M1, M2 and M3. The chemicals were tested extensively by a specialized formation damage laboratory. Moreover, a further search for excellence with Inflow control devices manufacturers revealed that bullheading of such chemicals at high rates in wells with screens will have a better chemical distribution along the producing compartments. To complement this unique approach, effective logging while bullheading was achieved by a distributed temperature sensing coiled tubing (DTS-CT string) string to show the zonal chemical placement and identify any thief zone. This cutting edge technology, which was used previously in Saudi Arabia has led to a significant chemical consumption optimization that is being recognized as an international record with outstanding results. From the three treated wells in the "S" field, the bullheading technique was confirmed by the DTS-CT as superior to pumping through conventional coiled tubing in wells completed with inflow control devices.

A new generation of sophisticated wells are to be drilled in a giant offshore field in Abu Dhabi. These extended reach wells will reach and produce remote areas of the field from artificially built islands. The first maximum reservoir contact (MRC) pilot well was drilled successfully with 20,000 ft total depth and a 10,000 ft producing interval completed with inflow control devices (ICDs). The well started producing dry oil at reasonably high flow rate and uniform contribution from each ICD compartment. After a relatively short period of dry oil production water break-through occurred and started causing unexpected downhole flow assurance concerns, especially at the locations of the ICDs. Production logging along with caliper data showed severe corrosion around water producing ICD nozzles and high gamma ray readings in the water producing intervals, suggesting that scale had precipitated behind pipe either in the near wellbore rock (believed to be unlikely based on the history of scale precipitation in the field) or on the outside of the completion (thought to be more likely). An investigation was launched to determine the cause of the corrosion around the ICD nozzles and improve understanding of the influence of ICD flow dynamics on scale deposition and material corrosion, with the objective of developing a suitable mitigation method for scale and corrosion in future MRC/ICD wells. The study results showed that high wall shear stress developed in and around the water producing ICD nozzle area are at the origin of the corrosion in the pilot well, and that low-to-moderate wall shear stresses on and around the wire-wrapped screen sections of the ICDs could be the cause of the scale deposition. Consequently, the completion design for future wells with ICD completions has been revised to mitigate the risks of flow induced corrosion. This paper will present results of the laboratory study into the influence of ICD flow dynamics on corrosion rates and mineral scale precipitation and discuss strategies for mitigating both concerns via the design of the ICD.

Advances in drilling and well construction technologies have enabled extended-reach horizontal and multilateral wells to increase reservoir contact and improve recovery. Completion systems with passive inflow control devices (ICD) or intelligent wells are used to optimize and control inflow from the compartments or laterals. ICD completions are passive systems with torturous paths or orifices designed to choke back inflow from dominant zones and equalize influx along the wellbore. ICDs combined with openhole packers provide very fine compartmentalization of the open hole and it is common to have completions with 40 inflow compartments in some extended-reach wells. ICD completions require well intervention to close zones with high water or gas. Intelligent completions, on the other hand, have downhole valves that can be remotely operated from surface. The requirement for downhole control lines and penetrations at the wellhead and packers has limited the number of downhole valves to a maximum of six in a well. This limitation excludes a significant number of applications where greater compartmentalization can yield superior well performance. The industry has recently developed innovative completion systems that increase the number of surface-controlled downhole valves while minimizing the number of downhole lines. These technologies improve completion design while overcoming limitations like the number of control lines, feedthrough ports on packers and wellhead. Saudi Aramco has recently installed an all-electric intelligent completion with 8 downhole active flow-control devices (AFCD) controlled via a single downhole control line. This installation is currently the world record for the highest number of inflow control valves installed for an intelligent completion. This paper presents details of technology development, evaluation, completion design, installation and in-well testing of the all-electric intelligent completion system in a multilateral well. The paper presents the novel completion design with redundancies, system components, advantages of the chosen technologies and the completion method. The section about the planning phase of installation highlights steps taken to ensure successful execution of the job while minimizing operational risks associated with the deployment of the new technology. Finally, the execution phase of the installation is presented with special emphasis on procedures and actions during installation to improve operational efficiency and minimize health and safety (HSE) risks. Thorough design, planning and execution of the job yielded the successful installation of an advanced and complex intelligent completion system in an efficient and safe manner. All-electric intelligent completion systems capable of controlling multiple downhole valves are anticipated to increase well life and recovery through improved downhole monitoring and control. This system can control as many as 27 AFCDs on a single electric control line.

Openhole horizontal completions in consolidated formations have been commonplace for a number of years. This type of completion has been very successful due to the relative simplicity of the completion design and ability to segment the horizontal production interval by using openhole hydrostatic-set packers. Using inflow control devices (ICDs) in this completion design allows a uniform inflow across the entire horizontal wellbore, which mitigates early water or gas coning into the wellbore. A newly designed ICD has been developed and field-trialed successfully that mitigates the need for an inner string during installation, allowing circulation through the liner while running in the hole as well as hydraulic setting of the openhole packers before pulling out of the hole with the workstring. This also provides an improved well control condition. A temporary valve system has been incorporated into the ICD design that provides pressure integrity in the liner until after the upper completion has been installed. Once the upper completion is in place, the valves are triggered hydraulically with applied pressure in the production tubing and opened once the differential pressure is removed, allowing the ICD to be reconfigured into the production mode. Once the valves have been opened the ICD performs normally for the operational life of the well. This completion technology also provides the added benefit of isolating the upper wellbore from the reservoir until after the upper completion is installed. This potentially prevents unwanted and costly fluid losses into the formation before the well is put on production. This paper will describe the new ICD design technology developed for the application and review initial case history well installations in Saudi Arabia.

As part of the Islands Project which involves the use of 4 artificial islands to drill & complete over 300 ERD wells in a giant offshore oilfield, several completion designs have been piloted to test & monitor their suitability for the brownfield development. One well design incorporated the use of Inflow Control Devices (ICDs) & swell packers which was ZADCO's first use of such technology in a production well. The technology was installed in the pilot well to test in-flow control along a 10,000ft lateral & to manage future water production. The Paper will cover: The design of the well detailing the ICD configurations & swell packer arrangements providing 15 compartments along the reservoir section, The inflow performance recorded annually along the lateral showing differing results, The outcome of an extensive intervention program in 2013 utilising different logging tools to record internal & external data, live camera to view condition in low water cut well & venturi tool to recover downhole samples that concluded the mechanical failure of ICDs in the heel, The extensive post-failure investigation undertaken such as extensive review of installed ICD design, flow assurance, computational fluid dynamic (CFD) simulations, laboratory testing for different conditions & materials, comparison of modelled with actual data to determine failure mode & The way forward for future ICD installations with initial short term solution & plans for future long term design solutions to give a required 30 year life.

The long-term development plan for a giant oil field offshore Abu Dhabi calls for new extended reach wells drilled from artificial islands. The existing wells in this field have historically suffered from inorganic sulfate-based scale deposition in the production tubing which is mitigated by periodic scale inhibition squeeze treatments. The new extended reach wells will have more sophisticated lower completions, including limited-entry liners (LELs) and inflow control devices (ICDs) with external debris barriers. It is currently planned to mitigate inorganic scale in these wells with periodic coiled tubing or bullhead scale inhibition squeeze treatments, which are anticipated to be more challenging and costly due to the extended reach. It is unknown as to whether these types of completion equipment are susceptible to scale deposition or how much scale deposition can be tolerated before well productivity is impacted.Knowledge of the rate of scale buildup on ICDs and LELs versus the volume of water produced through the devices is an important factor for choosing the optimum frequency for scale inhibition squeeze treatments to mitigate scale in these completions while keeping operational costs down. A two-phase laboratory study is currently underway to assess the susceptibility of ICDs to scale deposition. The first phase of the study will focus on the potential for strontium sulfate scale deposition on the debris barrier upstream of the ICD.This paper reports the experimental design and results of laboratory scale deposition experiments on a series of debris barrier test coupons with the goal of estimating the rate of scale buildup on the full-size ICD debris barriers, and the volume of scaling brine that can be produced through the ICD debris barrier (in the absence of any scale inhibitor chemical) without risking significant plugging.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 180065, “Thermal Effects on Subsea Wellhead Fatigue During Workover Operations,” by L. Cantinelli Sevillano, J. De Andrade, S. Sangesland, and M. Stanko, Norwegian University of Science and Technology, prepared for the 2016 SPE Bergen One Day Seminar, Bergen, Norway, 20 April. The paper has not been peer reviewed. Intervention and workover operations can significantly affect the structural integrity of subsea-wellhead systems with regard to their fatigue life. The increasing frequency of these operations has called for a renewed focus on the fatigue capacity of subsea wells, which has greatly improved the overall methodology used for wellhead-fatigue analysis. However, thermal effects along the well have yet to be incorporated. This paper analyzes wellhead-fatigue damage during a workover operation considering the thermal effects. Methodology The goal of the present study is to investigate the effects of the temperature variation along the well on wellhead-fatigue- damage rates by incorporating the temperature profiles of casing strings and cement into the fatigue-damage assessment of a particular wellhead system during a workover operation. In this study, a decoupled approach is proposed. The temperatures of riser, wellhead, and well components are calculated for different instants during the workover operation using a finite-difference method. Then, the temperature profiles for a given moment during the operation are incorporated into a 3D finite-element model (FEM) of the wellhead system. A structural analysis with focus on stresses at the fatigue hot spots is performed. Subsequently, a dynamic analysis of the riser provides the loading time history to which the wellhead is subjected; finally, combining the results of the structural analysis and the riser-response analysis enables the fatigue damage during the simulated operation to be estimated. The well adopted in this study follows a conventional subsea-completion program on the Norwegian continental shelf, with four casing strings and a production liner. Temperature Calculations. It is assumed that enough time has passed—between the shutting down of production and the moment that the workover riser is connected to the wellhead and the workover operation begins—for the temperature in the well to reach the undisturbed geothermal temperature profile. The workover operation simulated for temperature calculations consisted of injecting and circulating a heavy fluid until the hydrocarbons in the well were displaced. After that, circulation was stopped. The temperature profiles were calculated with a finite-difference method. During the simulated cold-fluid injection into the well, the deepest sections of the well are subjected to the largest temperature drop, given that the fluid is at lower temperature than the surrounding formation and well fluid, while the uppermost sections experience the effects of a circulating fluid at a higher temperature. Circulation was deemed to last approximately 3 hours.

This paper provides the learnings from a successful application of a smart completion in a complex heterogeneous carbonate reservoir. It details the study, planning, coordination, and implementation process of two pilot wells by a multidisciplinary team, and pilot production performance results, illustrating the success. First, to select an optimum completion design for the field, multi-segment well option and local grid refinement option were applied to the reservoir simulation model including calibration of faults/fractures. Second, based on the modified model, sensitivity analysis was conducted; 1) by selecting different types of completion including Open-hole, blank pipes (BP), compartmentalized slotted liners (SL), inflow control device (ICD) and hydraulic flow control valve (FCV); 2) by optimizing the number of compartments (packer and blank pipe placements for all cases), and ICD / FCV numbers and nozzle sizes. Using the data from the modeled cases, economic analysis was conducted, which indicated that the ICD in conjunction with sliding sleeves (SSD) was the best option. Two candidate wells were selected to cover the variation of reservoir characteristics: one well representing the heterogeneous part of the reservoir with high-density of faults, fractures and kurst, and another one representing the relatively homogenous part of the reservoir suffering from heel to toe effect. A multidisciplinary implementation team was set up to align all stakeholders on subsurface requirements, following up the completion design, coordinating material procurement and logistics for mobilizations, daily drilling operations follow-up, real-time logging data interpretations and completion design adjustment. Evaluation of the two pilots’ results based on predefined KPIs during the study, exceeded overall expectations.

Increased water production is often the cause of reduced well performance, decreased hydrocarbon production, and/or killing the well. Water entry must be pinpointed before the remedial work to shutoff the water and to increase well productivity. A standard practice for shutting off the water is by running an integrated multiphase production logging tool, which is challenging in horizontal wells due to the high deviation, wellbore conditions, and multiple flow regimes. The diagnosis of this type of well becomes complicated when the horizontal well is dead. In this paper, three field examples are presented on data acquisition (logging) in dead horizontal wells, with subsequent interpretation to pinpoint the water entry interval(s). The first well was completed with an inflow control device (ICD). An integrated production logging run during shut-in identified a leak with crossflow from the blank pipe to the open hole. The water source was determined to be a zone above the completed intervals. The second example is an open hole completion. The well flowed after nitrogen (N2) gas kickoff and the water entry was pinpointed from the toe section along with the oil profile. The third example is also a horizontal open hole completion. This well did not flow naturally, despite N2 lifting for 8 hours. Logging was conducted while injecting N2. Repeated passes yielded consistent results in pinpointing the water entry interval, and the water entry was identified also from the toe section. These field examples demonstrated that integrated job planning and integrated interpretation are essential to opening new opportunities for diagnosing dead wells and providing solutions. Guidelines and recommendations for logging dead wells are now available for these types of logging conditions. Introduction The objectives of running integrated horizontal multiphase production logging (MPL) tools are mainly to obtain fluid-flow profiles, determine the relative contribution of the reservoir intervals, and identify water/gas breakthrough intervals to provide data for water/gas shutoff operations. Integrated horizontal MPLs are also used to evaluate the performance of open hole horizontal producers (Al-Muthana, et al. 2008), the effectiveness of a well completion (such as smart completions) or workover operations (such as water/gas shutoffs). Multiphase production logging is challenging in horizontal wells due to high deviation, wellbore conditions, and/or multiple flow regimes. In addition, there are many different scenarios that could lead to high-water production sources such as:· Tubing, casing, or packer leak· Flow behind the casing and problems in or near the wellbore such as poor cement· Water coning· Rapid breakthrough of water through fissures

The objective of this case study is to show the value of the NMR real-time log data, acquired while drilling, for reservoir characterization as a lithology independent porosity logging solution and most important for permeability computation. The applied methods are being discussed with much focus on the added value of the transverse relaxation time T2 spectrum analysis in a highly heterogeneous, upper Jurassic carbonate reservoir, to characterize the pore size distribution while geosteering the wellbore to track the better quality pore systems and generate a real-time permeability profile, supporting the later advanced completion run for the first time, in this offshore field. The current field development plans are based on drilling multi-lateral horizontal and highly deviated wellbores along the layers of Reservoir-D to enhance the injection and production efficiency. Running radioactive-based porosity logging tools with such complicated well trajectories poses a high operational risks and collide with environmental regulations, this paper presents a case where nuclear magnetic resonance (NMR) as a source-less porosity logging device, run with the conventional resistivity-gamma ray logging while drilling combination achieved effective real-time formation evaluation and supported efficient well placement to maximize the reservoir contact. The NMR formation evaluation supported the design of the following Inflow Control Device (ICD) well completion operation for water injection, in a timely effective process, later validated with production logging data. The application is focused on maximizing the value of the real-time LWD (NMR) data for the time-critical (ICD) design and deployment in the highly deviated/ horizontal drains drilled, offshore Abu Dhabi.

High resolution micro-resistivity imaging has been available in the logging while drilling (LWD) industry for the last 15 years in water-based mud (WBM) systems. However, the recent introduction of LWD ultrasonic technologies means that high-resolution images and associated analysis are now available for both WBM and oil-based mud (OBM) applications. This paper details the deployment of a 4¾-in. LWD ultrasonic imaging service in a mature offshore carbonate field, in Abu Dhabi, and the assessment of images in WBM with micro-resistivity image comparisons. The 4¾-in. ultrasonic service combines borehole size and shape measurements with high-resolution radius and reflection amplitude images. The LWD tool takes advantage of drill string rotation to make a 360-degree scan of the borehole with each transducer. The ultrasonic sensor uses four transducers that operate in a pulse-echo mode. By firing simultaneously, the transducers provide a total of 2,000 traveltime and reflection amplitude measurements each second, enabling the creation of high-resolution images, even at high-logging speeds. The images were used to evaluate the suitability of the LWD ultrasonic measurements to enhance reservoir understanding, along with azimuthal high-resolution resistivity image measurements in WBM applications. The ultrasonic tool was run in tandem with the resistivity imaging tool on a recent well where an inflow control device (ICD) had to be installed. The ultrasonic images showed excellent agreement with the high-resolution resistivity measurements, illustrating bedding, natural fractures, and sedimentological features. The resolution of the reflection amplitude images enables identification of drilling-induced features on the surface of the borehole, highlighting the measurement's value in understanding the impact of bottom hole assembly (BHA) design on the quality of the wellbore in fine detail. The travel-time measurements provide detailed evaluation of the borehole size and shape, with a three-dimensional (3D) visualization of the wellbore illustrating the ability of the tool to identify borehole enlargement and breakout. These findings demonstrate the suitability of the ultrasonic imager to address wellbore stability issues, identify principal stress orientations, and aid completion design in real time by confirming swell packer positions. Comparisons between ultrasonic images and established LWD technologies highlight the suitability of the radius and reflection amplitude images to provide enhanced reservoir characterization in both WBM and OBM applications. Log examples show that high-resolution images can identify bedding features, confirm natural fracture types and provide assessment of borehole size and shape for wellbore stability assessment for better ICD completion design.

Some of the wells in the southern part of a remote field in Saudi Aramco are either producing intermittently or ceasing to flow against the high trunk line pressure. Saudi Aramco had considered various options along with horizontal thrust boring direct drilling under the sand dunes to reduce this high back pressure. A helico-axial multiphase pumping (MPP) technology was selected for the trial test in this field since in 2005 the horizontal thrust boring technology was limited to distance up to 2 km. In addition, the multiphase pump provides the flexibility such as reducing the back pressure and particularly, the helico-axial technology has a wider operating envelope as some wells will be weaker in the long run. Saudi Aramco has successfully re-commissioned the MPP in January 2011, and it was trial tested for a nine month period at the remote area with three dead wells and two marginal flowing wells. A total of 7,000 to 8,000 barrel oil per day incremental production was realized by lowering the back pressure on these wells using the MPP. This paper describes the testing, field operational experience and recommended improvement of a rotodynamic (helico-axial) MPP system at a remote, hilly terrain onshore oil field in Saudi Arabia. This paper is a sequent to SPE-117462 paper, Deployment of Rotodynamic Multiphase Pump in a Remote Hilly-Terrain Oil Field in Saudi Arabia," presented at the 2008 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE.