Passive Inflow Control Devices Research Articles

Completion Performance Evaluation in Multilateral Wells Incorporating Single and Multiple Types of Flow Control Devices Using Grey Wolf Optimizer

There has been a tendency in oil and gas industry towards the adoption of multilateral wells (MLWs) with completions that incorporate multiple types of flow control devices (FCDs). In this completion technique, passive inflow control devices (ICDs) or autonomous inflow control devices (AICDs) are positioned within the laterals, while interval control valves (ICVs) are installed at lateral junctions to regulate the overall flow from each lateral. While the outcomes observed in real field applications appear promising, the efficacy of this specific downhole completion combination has yet to undergo comparative testing against alternative completion methods that employ a singular flow control device type. Additionally, the design and current evaluations of such completions are predominantly based on analytical tools that overlook dynamic reservoir behavior, long-term production impacts, and the correlation effects among different devices. In this study, we explore the potential of integrating various types of flow control devices within multilateral wells, employing dynamic optimization process using numerical reservoir simulator while the Grey Wolf Optimizer (GWO) is used as optimization algorithm. The Egg benchmark reservoir model is utilized and developed with two dual-lateral wells. These wells serve as the foundation for implementing and testing 22 distinct completion cases considering single-type and multiple types of flow control devices under reactive and proactive management strategies. This comprehensive investigation aims to shed light on the advantages and limitations of these innovative completion methods in optimizing well and reservoir performance. Our findings revealed that the incorporation of multiple types of FCDs in multilateral well completions significantly enhance well performance and can surpass single-type completions including ICDs or AICDs. However, this enhancement depends on the type of the device implemented inside the lateral and the control strategy that is used to control the ICVs at the lateral junctions. The best performance of multiple-type FCD-based completion was achieved through combining AICDs with reactive ICVs which achieved around 75 million USD profit. This represents 42% and 22% increase in the objective function compared to single-type ICDs and AICDs installations, respectively. The optimal settings for ICD and AICD in individual applications may significantly differ from the optimal settings when combined with ICVs. This highlights a strong correlation between the different devices (control variables), proving that using either a common, simplified analytical, or a standard sequential optimization approach that do not explore this inter-dependence between devices would result in sub-optimal solutions in such completion cases. Notably, the ICV-based completion, where only ICVs are installed with lateral completion, demonstrated superior performance, particularly when ICVs are reactively controlled, resulting in an impressive 80 million USD NPV which represents 53% and 30% increase in the objective function compared to single-type ICDs and AICDs installations, respectively.

The Impact of Autonomous Inflow Control Valve on Improved Oil Recovery in a Thin-Oil-Rim Reservoir

Summary Oil production from thin-oil-rim fields can be challenging as such fields are prone to gas coning. Excessive gas production from these fields results in poor production and recovery. Hence, these resources require advanced recovery methods to improve the oil recovery. One of the recovery methods that is widely used today is advanced inflow control technology such as autonomous inflow control valve (AICV). AICV restricts the inflow of gas in the zones where breakthrough occurs and may consequently improve the recovery from thin-oil-rim fields. This paper presents a performance analysis of AICVs, passive inflow control devices (ICDs), and sand screens based on the results from experiments and simulations. Single- and multiphase-flow experiments are performed with light oil, gas, and water at typical Troll field reservoir conditions (RCs). The obtained data from the experiments are the differential pressure across the device vs. the volume flow rate for the different phases. The results from the experiments confirm the significantly better ability of the AICV to restrict the production of gas, especially at higher gas volume fractions (GVFs). Near-well oil production from a thin-oil-rim field considering sand screens, AICV, and ICD completion is modeled. In this study, the simulation model is developed using the CMG simulator/STARS module. Completion of the well with AICVs reduces the cumulative gas production by 22.5% and 26.7% compared with ICDs and sand screens, respectively. The results also show that AICVs increase the cumulative oil production by 48.7% compared with using ICDs and sand screens. The simulation results confirm that the well completed with AICVs produces at a beneficial gas/oil ratio (GOR) for a longer time compared with the cases with ICDs and sand screens. The novelty of this work is the multiphase experiments of a new AICV and the implementation of the data in the simulator. A workflow for the simulation of AICV/ICD is proposed. The simulated results, which are based on the proposed workflow, agree with the experimental AICV performance results. As it is demonstrated in this work, deploying AICV in the most challenging light oil reservoirs with high GOR can be beneficial with respect to increased production and recovery.

СИСТЕМА УПРАВЛЕНИЯ УСТРОЙСТВОМ КОНТРОЛЯ ПРИТОКА ФЛЮИДА В СКВАЖИНЕ

Актуальность исследования состоит в том, что решением преждевременного прорыва воды или газа в горизонтальной скважине из-за неоднородности профилей притока вдоль оси горизонтального ствола, является изменение пластового давления на различных участках, а также при разработке контактных месторождений, особенно по мере истощения залежи, могут служить устройства контроля притока флюида. Различают активные Interval Control Valve (ICV) или пассивные Inflow Control Device (ICD) устройства. Устройства ICD способны выровнять приток вдоль горизонтальной скважины за счет создания дополнительного сопротивления потоку жидкости, зависящего от величины притока на данном горизонтальном участке. Недостаток современных ICD в том, что они не имеют возможности регулирования и приведения пассивных устройств в действие после установки в стволе скважины. В связи с тем, что имеются риски связанные с неопределенностью в описании свойств пласта, которые присутствуют на всех стадиях разработки месторождения недостаток ICD оказывается существенным. Системы ICV приводятся в действие дистанционно с поверхности скважины, но не способны определять характер поступающего флюида (нефть, газ, вода) в скважину и принимать решение в автоматическом режиме. Цель: разработка новой конструктивной схемы устройства контроля притоком с возможностью непрерывного мониторинга характера поступающей жидкости, и программного обеспечения для управления клапаном с устья скважины. Объекты: горизонтальная скважина и устройство контроля притоком флюида. Методы: имитационное моделирование Simulink, нейронные сети, матричные методы, методы линеаризации нелинейных уравнений. Результаты. Предложена новая конструктивная схема устройства контроля притока в горизонтальной скважине, позволяющая непрерывно оценивать характер поступающего флюида. Данная конструкция позволяет в автоматическом режиме регулировать положение исполнительного механизма по данным измерительных приборов. Дано математическое описание работы клапана. Разработана модель клапана в среде моделирования Simulink, с использованием матричного подхода и нейронных сетей, для построения качественной зависимости положения клапана от значения создаваемого перепада давления. Приведены результаты работы блока нейронной сети и конечный результат моделирования.

Combining Passive and Autonomous Inflow-Control Devices in a Trilateral Horizontal Well in the Alvheim Field

Summary In this paper we describe the analysis, test, and design work to deliver an optimal lower completion for a trilateral well by integrating passive and autonomous inflow-control devices (ICDs) (AICDs) at the Alvheim Field offshore Norway. In 2015, both passive ICDs and AICDs were tested in the laboratory with Alvheim fluids at reservoir conditions. The experimental flow testing demonstrated that the AICD chokes gas more efficiently than the passive ICD. The experimental results enabled correct modeling of AICDs in both the reservoir-simulation model and the simpler steady-state inflow model. The following lower-completion strategy was established for the new well: Where the well was close to the overlying gas cap, AICDs should be used, whereas passive ICDs with variable strength were to be used elsewhere to optimize the inflow. During the drilling phase, the steady-state model was updated with the as-drilled information; the lower-completion design for each branch focused on obtaining what was estimated to be an optimal inflow depending on the oil volume per drainage area. A key uncertainty in the design work was whether shaly zones along the wellbore would creep/collapse with time and act effectively as packers. The lower completion covered 7 km of reservoir penetration in the three branches, and 15 unique oil tracers were installed to evaluate the cleanup and the inflow profile along the well. The well started producing in May 2016 and a successful cleanup was confirmed by oil-tracer responses. In August 2016, a restart-tracer-sampling campaign was performed after a 12-day shut-in, and this formed the basis for a “chemical production log.” The tracer-based inflow interpretation was compared quantitatively with the model-predicted inflow and qualitatively to the tracer responses seen during the cleanup. The comparison confirmed that the lower completion works as initially planned. The interpretation further indicated that the upper zone has a lower degree of pressure support than the lower zone, and that the larger shaly sections have creeped/collapsed and act as packers. The well has exceeded predrill production expectations, with an average oil rate of 3375 std m3/d (21,240 STB/D) during the first production year. A large part of exceeding the predrill expectations is attributed to the lower-completion design, where the focus has been to optimize such that the whole well contributes, from the heel to all toes.

Passive Inflow-Control Device Maximizes Productivity Through Every Phase of a Well's Life

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 13863, ’The First Passive Inflow-Control Device That Maximizes Productivity During Every Phase of a Well's Life,’ by Luis A. Garcia, SPE, Martin P. Coronado, SPE, Ronnie D. Russell, Gonzalo A. Garcia, SPE, and Elmer R. Peterson, SPE, Baker Hughes, prepared for the 2009 International Petroleum Technology Conference, Doha, Qatar, 7-9 December. The paper has not been peer reviewed. In long horizontal wells, production rate typically is higher at the heel than it is at the toe. This imbalanced production profile may cause early water or gas breakthrough into the wellbore. To eliminate this imbalance, inflow-control devices (ICDs) are placed in each screen joint to balance the production-influx profile across the entire lateral length to compensate for permeability variations. Passive ICDs (PICDs) could control the influx without the need for intervention. Introduction The primary purpose of ICDs is balancing well production throughout the operational life of the completion to optimize hydrocarbon recovery. Because a typical well with ICDs can produce for 5 to 20 years or longer, the long-term reliability of such a device is crucial to the well’s overall success. If an ICD cannot maintain a uniform flux rate, increased localized production rates will occur and the well will become unbalanced. Thereby, the ICD becomes ineffective, leading to premature water and/or gas breakthrough and possible loss of sand control. Water can reach the wellbore in certain sections because of formation heterogeneities and/or vertical fractures. Ideally, once breakthrough occurs, flow contribution from these water-producing zones should be less than that of the oil-producing sections. The ICD device should increase the flow restriction at the onset of water production, thus allowing other oil-producing zones to continue flowing effectively. In wells with oil viscosity >10 cp, ICD-type selection becomes more critical because of the large difference in viscosity between the oil and produced water. To maintain an even flow profile across the entire wellbore lateral, the pressure-reduction mechanism in the ICD situation must have the lowest sensitivity to viscosity. A restrictive-type ICD can provide desirable results in this regard with its lower sensitivity to viscosity. However, this type of ICD requires a very small flow area to generate the pressure drop (restriction) required in ICD applications. This small flow area has a greater potential for erosion and a low plugging resistance. Another solution is to enable lower viscosity sensitivity in the restrictive device with the low erosion and high plugging-resistance level of the frictional design. The restrictive-pressure-loss mechanism can be used while limiting the fluid velocity through the device below the critical level, which will minimize erosion potential.

Combining Distributed-Temperature Sensing With Inflow-Control Devices for Improved Injection Profile

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 127772, ’Combining Distributed-Temperature Sensing With Inflow-Control Devices Provides Improved Injection Profile With Real-Time Measurement in Power-Water Injector Wells,’ by Drew Hembling, and Garo Berberian, SPE, Saudi Aramco, and Mark Watson, Sam Simonian, and Garth Naldrett, SPE, Tendeka, prepared for the 2010 SPE Intelligent Energy Conference, Utrecht, The Netherlands, 23-25 March. Passive inflow-control devices (ICDs) are used to enhance the performance of horizontal producing wells in unfavorable environments such as nonuniform permeability and/or pressure variations along horizontal sections. ICDs were combined with a fiber-optic distributed-temperature-sensing (DTS) system to manage the water-injection profile across a reservoir horizon. This field trial demonstrated the effectiveness of the ICD system when used for injection-well profiling and for fluid diversion during acid stimulation. Introduction To understand the injection profile and well performance, a DTS system was deployed with ICDs and swellable packers as a field trial in a planned injection well. The objectives were to provide real-time information on multirate testing, determine real-time compartmental-injection profiling, and eliminate the need for horizontal flowmeter logging and well intervention. Recent designs use ICD-completion technology with a DTS umbilical deployed in the openhole producing section below a liner for real-time monitoring and controlling of inflow from each compartment, thereby extending well life and increasing recovery. This case involved the use of DTS and ICD technology to control injection profiles in an openhole near-horizontal well. Compartments were created by use of water-swellable packers with feedthrough capabilities for the DTS umbilical. Completion Design The reservoir section was separated into six compartments. On the basis of openhole-log analysis, the reservoir has a uniform porosity along the length of the well, with a few dolomite intervals present. The spacing of the ICDs and packers was planned in such a way as to isolate these dolomite sections while distributing the desired injection rate along the well. To mitigate the risk of getting stuck while running the lower completion to total depth, it was decided to limit the number of openhole packers to six, thereby reducing the number of allowable compartments. DTS System and Installation The DTS and a permanent downhole-monitoring system were installed in April 2009. The fiber-optic DTS cable was attached and secured to the production-tubing string and provides multipoint temperature profiles across the length of the well. The real-time data from the DTS system can be used for injection optimization and reservoir management by monitoring injection rates between and within the ICD compartments and by identifying crossflow conditions.

Advanced Wells: A Comprehensive Approach to the Selection Between Passive and Active Inflow-Control Completions

Summary Well architecture advances from conventional wells to horizontal. Then multilateral wells, which have maximized reservoir contact, have been paralleled by advances in completion-equipment development. Passive inflow-control devices (ICDs) and active intervalcontrol valves (ICVs) provide a range of fluid-flow control options that can enhance the reservoir sweep efficiency and increase reserves. ICVs were used originally for controlled, commingled production from multiple reservoirs, while ICDs were developed to counteract the horizontal well's heel/toe effect. The variety of their applications has proliferated since these beginnings. Their application areas now overlap, resulting in it becoming a complex, time-consuming process to select between ICVs or ICDs for a particular well's completion. This publication summarizes the results of a comprehensive, comparative study of the functionality and applicability of the two technologies. It maps out a workflow of the selection process on the basis of the thorough analysis of the ICD and ICV advantages in major reservoir, production, operation, and economic areas. It provides detailed analysis of Reservoir-engineering aspects, such as uncertainty management, formation heterogeneity, and the level of flexibility required by the developmentProduction and completion characteristics, such as tubing size, the number of separately controllable zones, the completion of multiple laterals, and the value of real-time informationOperational and economical aspects, such as proper modeling, gas-and oilfield applications, equipment costs and installation risks, long-term reliability, and technical performance. The results of this work's systematic approach form the basis of a screening tool to identify the most appropriate control technology for a wide range of situations. This selection framework can be applied by both production technologists and reservoir engineers when choosing between passive or active flow control in advanced wells. The value of these guidelines is illustrated by their application to synthetic- and real-field case studies.

New Technology Applications for Improved Attic-Oil Recovery: Slim Smart Completions

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 12365, "New Technology Applications for Improved Attic-Oil Recovery: The World's First Slim Smart Completions," by Stig Lyngra, SPE, Abdulkareem M. Al-Sofi, SPE, Uthman F. Al-Otaibi, SPE, Mohammed J. Alshakhs, SPE, and Ahmad A. Al-Alawi, SPE, Saudi Aramco, prepared for the 2008 International Petroleum Technology Conference, Kuala Lumpur, 3-5 December. The paper has not been peer reviewed. Smart completions, passive inflow-control devices (ICDs), and maximum-reservoir-contact (MRC) wells are some recent technologies used to enhance recovery and extend the life of mature oil fields. In a Saudi Aramco field, one challenge was to maximize production from the inadequately swept attic-oil zone. Since 1995, new technology has improved oil recovery from this thin attic-oil zone. Technology deployments included recompletion with short-radius-horizontal (SRH) sidetracks, single-lateral re-entry sidetracks equipped with passive ICDs, and multilateral MRC wells equipped with intelligent completions. A slim smart completion (SSC) was run in a multilateral sidetrack enabling production optimization and control of individual laterals. Introduction This field in Saudi Arabia was discovered in the early 1940s. A pressure-support program was started after 8 years of primary depletion. During a 24-year period, the produced solution gas was reinjected as part of the reservoir-pressure-support program. Gas injection was into the primary reservoir at the crest of a high-relief dome feature. A flank water-injection program was started in the mid-1950s, and it became the main field pressure-support mechanism. After more than 60 years of production, approximately 57% of the oil initially in place in the primary reservoir has been produced. Still, the field water cut has remained less than 35%. The absence of vertical barriers, relatively long distance from injector to first-row producers, and managed production offtake have allowed gravity to play the primary role in the recovery process. The main-reservoir permeability distribution (higher permeability toward the top, excluding the top 25 ft) allowed oil production from the top section while gravity drainage occurred in the lower, poorer reservoir section. As a result, water production has been very limited. The normal production practice during the first 34 years was to shut in any producing well with crude samples containing salt. Attic-Oil Target Zone The attic-oil section is approximately 25 ft thick. Saturation logs run in 2007 in wells very close to flank injectors indicated that this interval is at original oil saturations. Fig. 1 is a schematic showing the main layering of the attic-oil interval.