Autonomous Inflow Control Device 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.

Technology Focus: Completions (April 2024)

To start a text for high-level readers with a cliché is always a risk, but I will take it: “Data is the new oil.” When British mathematician Clive Humby coined this clever sentence in 2006, the thought-provoking idea behind it was that both oil and data need to be refined and processed to have value. Time and repetition eventually shaped the new, more common-sense meaning that data is as valuable as oil. And when the data refers to oil exploration and production, Humby’s statement becomes resounding, especially in its original meaning. The oil and gas industry, notably the completion activity, with its distributed sensors, optical fibers, permanent downhole gauges, sealed-wellbore pressure monitoring (SWPM), and microseismic, has generated a fantastic amount of data, which has increasingly been properly refined and processed, producing more information—and more oil. A quick search of OnePetro shows the number of papers that deal with the use of artificial intelligence with massive amounts of data that are being made available in the cloud to solve everything from the most prosaic completion decisions to the automatic design of stimulations in naturally fractured reservoirs. A good example of the use of data is shown in paper SPE 212922, which provides an in-depth analysis of interventions in the UK sector of the North Sea. Most of the conclusions, although mostly based on the UK Stewardship Survey, can be easily extrapolated to other regions of the world. And one of them puts its finger on the wound: the fear of asset managers of conducting interventions, even though they appear to be highly effective and economically viable. Paper SPE 212367 discusses the automation of SWPM data analysis for automatic volume-to-first-response matching, a great evolution in the design of refractures in the legendary Eagle Ford shales. And, if the evolution of completing unconventionals led the US to its historic production record in 2023, with more than 16 million BOE/D, in Argentina, shale gas has been a driver of development. The evolution of completions in the most famous unconventional prospect, Vaca Muerta, can be followed in paper SPE 212574. All of these great readings prove the cliché that “data is the new oil.” To complement the reading, a paper that will bring a discreet smile to a generation that breathlessly watched spaceships and even planets being destroyed by lasers, paper SPE 215016, details the industrial use of lasers in perforation. The future has finally arrived. To close the selections, two papers present current and important topics: completion options for carbon capture, use, and storage (SPE 216187) and innovations in autonomous inflow control devices, with the ingenious activation of the apparatus with chemical devices (SPE 216041). Recommended additional reading at OnePetro: www.onepetro.org. SPE 215016 First Industrial High-Power Laser Perforation Deployment by Sameeh I. Batarseh, Saudi Aramco, et al. SPE 216187 Improving Injection Efficiency in CCUS Wells: A Comparative Analysis of Different Completion Designs by Prakasa Bona, Halliburton, et al. SPE 216041Configurable Adaptive Chemical Inflow Control Device Eliminates Intervention by P. Asthana, Saudi Aramco, et al.

Применение внутритрубного электроцентробежного насоса для повышения нефтедобычи на месторождении имени Ю. Корчагина

Offshore field development projects are significantly different from onshore projects. Offshore operations include many difficulties, such as the specific technology for the operation and construction of wells, and the high cost of technical means. One of the most popular offshore field development projects is the Yu. Korchagin field. Various types of non-stationary flooding are actively and effectively used in this project, which are equipped with inflow control devices, among which passive and autonomous inflow control devices are distinguished. In the early 2010s, during the first drilling of the Neokomsko-Volzhskaya deposit, slit filters were used on wells, and later they began to use counter-pressure filters with the installation of sliding couplings. In multi-barrel wells, multi-position couplings are used to regulate the operation of each barrel. The introduction of some technologies in the conditions of extended horizontal boreholes of the Yu. Korchagin field had limited possibilities for launching equipment due to the complex trajectory of the well. The most urgent problems of modern oil and gas production are the completeness and efficiency of fluid extraction, achieving a uniform inflow profile, limiting and isolating gas and water breakthroughs. Inflow control systems, including and "intelligent" ones allow to minimize the flooding of wells, and the descent into the pumping and compressor pipes of the in-line electric centrifugal pump in case of failure of the standard pump will avoid the suspension of drilling operations. The purpose of the work is to analyze the application of the latest technological solutions at the Yu. Korchagin field in the waters of the Northern Caspian Sea.

Retrofitted Autonomous Inflow Control Devices Optimize Completions Design

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31301, “Optimized Completions Design Using Retrofit Autonomous Inflow Control Devices,” by Ezinne A. Nnebocha, Schlumberger; Akinola Akinbola, NPDC; and Omagbemi G. Kayakor, First Hydrocarbon Nigeria, et al. The paper has not been peer reviewed. Copyright 2021 Offshore Technology Conference. Reproduced by permission. _ Discovered in 1964, the Beta Field in the Niger Delta sedimentary basin consists of 25 stacked hydrocarbon-bearing reservoirs between 5,500 and 12,000 ft true vertical depth subsea (TVDSS). Oil production peaked at 8,900 STB/D shortly after field startup and has been on the decline. Two horizontal wells, Beta 7 and Beta 8, were planned in the field, but a production forecast of the planned wells showed potential early water breakthrough and high water cut. Autonomous inflow control devices (AICDs) were deployed successfully in the Beta Field for the purpose of minimizing water production and maximizing oil recovery. Introduction After history matching, the two new horizontal wells were simulated to target the sweet spots in the reservoir using constraints of oil saturation, porosity and permeability limits, and distance to the oil/water contact (OWC). The history-matched model was then used in forecasting the production profile for the new wells using a target liquid production rate of 2,000 STB/D. The production forecast without inflow control showed water breakthrough in the new wells within the first month of production, reaching to 45% within 3 months of production. Cyclonic AICD completions then were simulated for Beta-7 and Beta-8 horizontal wells, which showed improved oil production and delayed water production. AICD Retrofit Design Cyclonic AICDs were selected for application in the Beta Field to improve production performance. However, the short lead time required for the job execution and border closures caused by the COVID-19 pandemic created restrictions in mobilizing personnel and equipment from outside the country. It did not appear that the equipment could arrive in time for the job. The conventional nozzle-based passive ICD joints were available in country. Therefore, leveraging engineering skills and operational knowledge, a solution to retrofit AICD nozzles in existing ICD screen joints was conceived. The engineering team developed a design of machined components that could be quickly manufactured at the facility of the original equipment manufacturer (OEM) and shipped to the location. Failure-mode and effects-analysis assessment, and subsequent risk-management procedures, became useful to manage the process locally with the help of the remote OEM team. A step-by-step procedure on the retrofit was devised. Fig. 1 shows a flow chart used to guide the retrofitting process and the retrofitted AICD joints after modification. Upon completion of the screen retrofit, the joints were quality-checked and inspected to verify their preparedness for well completion.

Technology Focus: Sand Management (October 2023)

As drilling and completion activity resumes post-pandemic, the sand-control market faces several logistical challenges. Inflation and supply-chain interruption concerns are expected to continue into 2024 because of high volatility in raw material pricing amplified by geopolitical tensions in Europe and the South China Sea. As oil price strengthens, consumer preferences shift and more operators investigate newer technology and focus more on performance than price. Despite these factors, the fundamentals of sand control and sand management remain the same. As more-challenging reservoirs are being developed and new difficulties arise, however, more engineers are questioning the conventional sand-control aperture-sizing wisdom. Any sand-control effort aims to manage solids production while creating the fewest restrictions to fluid flow. To assure that sand-control efforts meet these goals throughout the life cycle of the wells, engineers must design them in a way that can withstand the forces of nature, doesn’t erode with high and localized flow, doesn’t corrode with the harshness of produced fluid, and doesn’t mechanically deform during installation and life-cycle loads. If you are interested in diving into these design processes, paper IPTC 21158 provides insight. With the higher adaptation of flow-control devices in recent years to improve flow segmentation and reduce the premature failure of sand control because of highly localized flow, flow-control-device implementation is becoming an integral part of sand-management strategy. More papers every year discuss the design process and field implementation of various kinds of flow-control devices along with sand controls. Paper SPE 210299 provides good insight into some of the field challenges and results of implementing flow-control devices with sand control. As always, monitoring for sand and solid production is key in any sand-management effort to assure the integrity of the system and maintain the containment of the fluids. In the past year, several papers focused on monitoring, including discussions of new technologies and presentations of field case studies. Paper IPTC 22989 is among the interesting papers in this subject. Recommended additional reading at OnePetro: www.onepetro.org. IPTC 21223 Lesson Learned From First Application of Openhole Standalone Screen With Autonomous Inflow Control Devices in Oil Field Offshore East Malaysia by Catherine Ye Tang, Petronas, et al. SPE 210128 Erosion-Resistant Sand Screen: Development and Deployment by Antonio Lazo, Chevron, et al. SPE 208162 Prediction of Threshold Sand Rates From Acoustic Monitors Using Artificial Intelligence by Ronald E. Vieira, University of Tulsa, et al.

Technology Focus: Offshore Drilling and Completion (October 2023)

Optimizing and continually increasing efficiencies at every stage of the drilling and completion process are central themes in the papers showcased in this feature. Innovating our way through difficult times is what the oil and gas industry excels at, especially during challenging periods. During the COVID-19 pandemic, the offshore energy industry faced immense struggles with high upfront capital investment and long lead times in uncertain circumstances with extremely low oil prices. The challenges brought about by the pandemic served as a backdrop to many of these innovations. Companies were compelled to discover creative solutions to maintain efficiency, reduce costs, and ensure safety during an era of unprecedented disruption. Innovation in advanced analytics and machine-learning algorithms is used to optimize drilling-center locations, leading to cost reduction. This development became even more critical during the pandemic as companies aimed to maximize efficiency and minimize expenses. The execution of large-scale projects such as the Johan Sverdrup development highlights innovation in project management, enabling timely and cost-effective operations in a challenging environment. The emphasis on digital solutions and fiber-optic technology in Guyana’s offshore operations illustrates the industry’s adaptation to the pandemic by enabling remote operations and real-time data collection while maintaining efficiency in a new discovery. Innovations in riserless light well intervention systems are particularly relevant during the pandemic. These systems improved efficiency and safety for offshore interventions, enabling the industry to operate with minimal personnel onboard. The focus on well-planning strategies to overcome challenges in deep depleted reservoirs includes approaches that optimize drilling in complex conditions, which is crucial when efficiency is paramount. Retrofitting autonomous inflow control devices proved an effective approach in implementing state-of-the-art technology to improve reservoir sweep and productivity. Moving forward, this innovative spirit in our industry as seen in these papers is a testament to our resilience during challenging times. In the coming years, this ability to sustainably increase recovery efficiencies to ensure energy security is crucial to shaping the future of energy production. Recommended additional reading at OnePetro: www.onepetro.org. SPE 212499 4D Radar Imaging of Wellbore Geometry While Drilling by Lars Øy, Well ID, et al. OTC 30979 Guyana Operations and First Oil by Mike F. Ryan, ExxonMobil, et al. SPE 212915 Enhancing Riserless Light Well Intervention Operability From Operator Perspective by Michael Long Ge, BP, et al. SPE 214057 Challenges of Drilling Deep Wells in a Complex Overburden With Severe Depletion and Experiences From Caspian Sea by Anwar Juma Al Saadi, Dragon Oil, et al.

Analysis and experimental study on resistance-increasing behavior of composite high efficiency autonomous inflow control device

Bottom water coning is the main reason to reduce the recovery of horizontal bottom water reservoir. By water coning, we mean the oil-water interface changes from a horizontal state to a mound-shaped cone and breaks through to the wellbore. Autonomous inflow control device (AICD) is an important instrument maintain normal production after bottom water coning, however, the resistance increasing ability of the swirl type AICD is insufficient at present, which seriously affects the water control effect. Aiming this problem, this paper designs a multi-stage resistance-increasing and composite type AICD. The separation mechanism of oil-water two phases in this structure, the resistance form of oil-water single phase and the resistance-increasing principle of water phase are analyzed. Establishing the dual-phase multi-stage separation and resistance-increasing model, and verified by measuring the throttling pressure drop and oil-water volume fraction of the AICD, it is found that the composite type AICD has the effect of ICD and AICD at the same time, which can balance the production rate of each well section at the initial stage of production, delay the occurrence of bottom water coning. In the middle and later stages of production, water-blocking can be effectively increased to achieve water control and stable production. After structural sensitivity analysis, the influence law of various structural parameters on the water control performance of composite AICD was obtained. The simulation calculation results show that, compared with the existing swirl type AICD, composite AICD has higher sensitivity to moisture content, the water phase throttling pressure drop is increased by 4.5 times on average. The composite AICD is suitable for the entire stage of horizontal well production.

Autonomous Inflow Control Valve for Medium-Light Oil and Its Effective Performance

Summary Many horizontal oil wells will after a time start producing unwanted fluids. Autonomous inflow control valves may help to choke these unwanted fluids and consequently improve carbon efficiency. This paper publishes new experimental data describing how an autonomous inflow control valve manages medium-light oil (6 cp), water, and gas at reservoir conditions. A further objective is to evaluate how this valve might impact well performance under various conditions. To verify the single- and multiphase flow behavior of the valve, extensive flow loop experiments were performed. Initial testing was done in a model fluid laboratory, while a more extensive test was performed at reservoir conditions (i.e., with formation water, reservoir oil, and hydrocarbon gas at the given reservoir temperature and pressure). To explore and understand the impact of this valve for various reservoir scenarios, a simple conceptual reservoir model with realistic boundary conditions was used. At various differential pressures, the single-phase oil, water, and gas rates were measured. Performance at varying water and gas fractions was measured to get an improved understanding and knowledge of multiphase flow occurring in a well. The results show clearly that the valve will choke gas and water effectively, both at single-phase and multiphase flow conditions. The reservoir and model fluid evaluations show consistent results. The valve shows roughly a monotonic decreasing total rate with decreasing oil fraction, implying that the valve will always prioritize sections with the largest oil fraction. A mathematical model match of the valve performance is possible via the 10-parameter extended autonomous inflow control device (AICD) equation that enables practical evaluation of the valve in industry-standard reservoir simulators. Various scenarios are explored with a conceptual reservoir model, and the autonomous inflow control valve shows its capacity to reduce water production and enable a more gradual and controlled increase in gas/oil ratio for most scenarios. The autonomous inflow control valve shows its largest potential to reduce unwanted fluids and increase oil recovery when used in segmented reservoirs. In cases with uncertain aquifer and/or gas cap strength, or large variation in effective permeability, the valve will make an infill well more robust as it autonomously adapts to reality, chokes unwanted fluids, and consequently enables more carbon-efficient reservoir management.

Technology Focus: Completions (April 2023)

_ A few years ago, exaggerating a figure of speech, I coined the expression, “We work in a water industry; oil is just a supporting actor.” In fact, producing water is the final destination of every oil field, but obviously the objective was to highlight the importance of water management in the hydrocarbon-production process. Since the beginning, well completion and stimulation strategies have always sought to optimize water management and, extending the concept, management of all fluids produced. Selective completions in vertical and multilateral wells (combined with sand control or not) and segmentation of horizontal wells are good examples of this effort. These technologies, combined with intelligent completion, have brought very positive results. Intelligent completion in open hole, currently used in the Brazilian presalt, has allowed the reduction of the carbon footprint, so necessary nowadays. The optimal application of intelligent completion is the subject of paper SPE 209965, an excellent compendium of best practices on the topic. In recent years, driven by technological advances, good results, and the need to increase operational efficiency, we have experienced a major increase in the use of devices for flow equalization and selective fluid production [e.g., inflow control devices, autonomous inflow control devices (AICDs), and autonomous inflow control valves]. A significant reduction in water and gas production has been reported in several technical papers. In fact, this is the most published completion topic in the past 3 years, and many good articles are available. Apart from new and exciting trends, conventional solutions continue to play their important role. Basic themes long discussed continue to evolve and bring new insights. This is the case with paper SPE 204185, which deals with perforating for fracturing. Finally, paper SPE 210417 discusses the use of AICD technology in the Singue Field in Ecuador, which resulted in an increase in cumulative oil rate and a decrease in cumulative water. Recommended additional reading SPE 210205 Successful Autonomous Inflow-Control Device Application To Reduce Water Production in a Heavy Oil Greenfield by Carlos A. Pedroso, Enauta, et al. SPE 206213 Automated Well Production and Gas Lift System Diagnostics and Optimization Using an Augmented Artificial Intelligence Approach in a Complex Offshore Field by Mahmoud Elwan, Dragon Oil, et al. OTC 31483 Case Study: How the Newest Generation of Autonomous Inflow Control Devices Helps To Control Excessive Well-Water Production Within a Major Sultanate of Oman Oilfield by Salim Buwauqi, Petroleum Development Oman, et al.

Autonomous ICDs Optimize Production in Singue Field, Ecuador

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 210417, “Autonomous ICD Introduction in Singue Field, Ecuador: Completion Methodology and Production Evaluation,” by Alejandro Chacon, SPE, Georgina Corona, and Juan Pico, Halliburton, et al. The paper has not been peer reviewed. _ Autonomous-inflow-control-device (AICD) technology, design methodology, and production-performance evaluation for AICD completions were applied for the first time in multiple horizontal wells of the Singue oilfield development in Ecuador. The analysis described in the complete paper covered the complete cycle, from reservoir modeling, completion design, post-drilling match, calibration, and production-performance analysis. Background and Field Information Singue is a field in a tropical rainforest in the Sucumbios province of Ecuador. The first well in the Singue field was drilled in February 1991. Lower U was the target reservoir in this first well. The well was drilled on the basis of seismic 2D data acquired from 1979 to 1989. Field cumulative oil production between 1991 and 1997 was 447,000 bbl. The field then was shut in until 2012, when Gente Oil Company was assigned as the operator of Block 53. Despite heavy field-development investment, a cumulative oil production of 8 million bbl was generated until 2018. Alternate completion techniques were considered to increase oil production by drilling horizontal wells. Water breakthrough was the challenge in these wells. The field has strong support from a water aquifer. An additional challenge in this area was the environmental sensitivity of the Amazon region to produced-water disposal. A horizontal completion with inflow-control technology to restrict water was considered as a mitigation measure. The first horizontal well, AH1, was drilled in 2019; it included swell packers and AICDs to balance the oil and control and restrict water at breakthrough. The second well, BH2, was drilled in 2020; the third and fourth wells were drilled in 2021 with similar completion technology. These wells were drilled in the Lower U reservoir, which has an average oil API gravity of 22.8. This reservoir is considered a consolidated sandstone with no sand production. Fluidic-Diode AICD Technology AICDs have a similar performance to traditional ICDs during the initial oil-production phase of the well before the onset of unwanted fluids (water/gas). During oil production, AICDs induce a low-pressure differential that allows balancing the flow across the completion. Therefore, they also provide the benefit of delaying the onset of water or gas. However, this technology offers additional benefits. In contrast to ICDs, AICDs induce a higher restriction for water or gas by creating a greater pressure differential across the devices for these fluids, which reduces the flow rate when compared with traditional ICDs.

Research on Production Performance Prediction Model of Horizontal Wells Completed with AICDs in Bottom Water Reservoirs

With the advancement of completion technology for horizontal wells in bottom water reservoirs, Autonomous Inflow Control Devices (AICDs), which have achieved good results in recent years, have been widely used in the oil fields of the eastern South China Sea. Although some mathematical methods can be used to predict the production performance of horizontal wells, there is no dynamic prediction method for the production performance of horizontal wells completed with AICDs. In this work, a mathematical model of porous flow in the reservoir, nozzle flow in the AICD, and pipe flow in the horizontal well is established, and then a new model is presented for predicting the dynamic performance of horizontal wells completed with AICDs in bottom water reservoirs. The new coupling model is compared with two horizontal wells completed with AICDs in the bottom water reservoirs of the eastern South China Sea, and the results indicate that the accuracy of the new model is sufficiently high to provide theoretical support for the further prediction of horizontal wells in the eastern South China Sea.

Modeling and Simulation of Autonomous Inflow Control Devices for Gas Exploitation.

Horizontal well technology is an efficient method of oil and gas exploitation. The goal of increasing oil production and improving productivity can be achieved by increasing the contact area between the reservoir and the wellbore. The presence of bottom water cresting reduces the efficiency of oil and gas production significantly. Autonomous inflow control devices (AICDs) are widely used to delay the influx of water into the wellbore. Two kinds of AICDs are proposed to restrain the bottom water breakthrough during natural gas production. The fluid flows in the AICDs are simulated numerically. The pressure difference between the inlet and outlet is calculated to evaluate the ability of blocking the flow. A dual-inlet design can increase the flow rate of AICDs, thus enhancing the water blocking effect. Numerical simulations show that the devices can block water flowing into the wellbore effectively.

Study of the Dynamic Behavior of an Autonomous Inflow-Control Device Using a Digital Twin

Solutions that aim to reduce water production in heavy oil wells have led to the design of devices known as rate-controlled production (RCP) autonomous inflow-control device (AICD) valves, which are placed in well completions and autonomously open with the oil inflow and close with water by choking the flow. These devices, which are based on Bernoulli’s principle, use a levitating disk that chokes the flow of the phase with the lowest flow resistance. This study proposes a numerical model based on computational fluid dynamics (CFD) technology to understand these devices’ operations and propose better designs without experimentation. The numerical model was based on dynamic fluid–body interaction (DFBI) and volume of fluid (VOF) models. The model was found to respond as expected depending on the physical properties of the fluids involved in heavy oil production. Finally, some limitations were found in the numerical study that can be improved in future studies.

Case Study: Oil Production Optimized With Autonomous Inflow Control Devices Offshore Malaysia

_ Advanced well completions have proven to be an effective method of moderating gas breakthrough while producing a thin oil rim when placed in a heterogenous, carbonate reservoir. In addition, several studies have proven that the application of autonomous inflow control devices (AICDs) acts as a type of insurance policy against geological and dynamic reservoir uncertainties to reduce the risk and variation in the expected oil production profiles. During 2019 and 2020, Sarawak Shell Berhad conducted development campaigns in the central Luconia province in a thin oil rim carbonate reservoir offshore Sarawak, Malaysia. The horizontal, approximately 6,000-ft development wells were expected to intersect with different geological layers with varying rock properties, resulting in an uneven reservoir influx toward the wellbore. Oil production from these wells was expected to suffer severely from early gas and water breakthrough. To produce the oil rim without the risk of early gas production, global production optimization specialist, Tendeka, incorporated FloSure AICDs in the lower completion design at the reservoir interface along the horizontal section of the wells. As an active flow control device, the technology delivers a variable flow restriction in response to the properties of the fluid entering the wellbore and the rate of flow passing through it to help manage gas coning/cusping risks. The fluid is then lifted to surface with natural in-situ gas lift built into the upper completion. A three-phase development was planned for the field, and to date, two phases have been completed. New-Generation ICD The first AICD completion was installed in Norway in 2008 and widely implemented in the Troll field in 2013 with very encouraging results (SPE 159634). However, its use is relatively new to both the Asia Pacific region and this type of application. Similar to a standard ICD which balances the influx of reservoir fluids, the FloSure AICD will delay the production of unwanted effluents prior to their breakthrough (proactive solution). However, once a breakthrough occurs, the device restricts the production of unwanted effluents with lower viscosity, such as gas (in light oil applications) and both gas and water in viscous oil production (reactive solution) (OTC 30403, OTC 30363, SPE 193718). The device delivers a variable flow restriction in response to the properties of the fluid and the rate of flow passing through it. Flow enters the device through the nozzle in the top plate of the body. This impacts the disk and spreads radially through the gap between the disk and the top plate, then turns around the top plate and is discharged through several outlet ports in the body (Fig. 1). The overall geometry of the device is critical to its ability to balance these forces effectively and create the desired fluid-dependent pressure drop. Field A employed 7.5-mm AICD valves to match the performance of the devices to the potential well flow rate. The oil, water, and gas viscosities are 0.40 cP, 0.27 cP, and 0.018 cP, respectively, at downhole flow conditions.

Evaluating the performance of advanced wells in heavy oil reservoirs under uncertainty in permeability parameters

Advanced wells play a crucial role in maximizing the efficiency of oil production. To achieve a successful design for advanced wells, several parameters must be considered and evaluated. Uncertainty in these parameters can have a significant impact on the performance assessment of the well in its lifetime. Absolute permeability, relative permeability, and permeability anisotropy are the parameters that determine reservoir permeability and are among the most important design parameters to be considered. This paper aims to assess the performance of advanced wells completed with passive and reactive downhole Flow Control Devices (FCDs) under uncertainty in the reservoir permeability parameters. The assessment is conducted through a case study on a synthetic heavy oil reservoir with a strong water drive. The EclipseSM reservoir simulator is used as a simulation tool and the Latin Hypercube Sampling (LHS) approach is applied as a sampling tool for uncertainty analysis in this study. According to the obtained results, under the presence of uncertainty, advanced wells with Autonomous Inflow Control Device (AICD) and Autonomous Inflow Control Valve (AICV) completions are able to mitigate the risk of water production by 53.20% and 71.12% respectively compared to conventional wells. However, Inflow Control Device (ICD) completion can only reduce the risk by 0.87%.

Matrix Injectivity Achieved in Deepwater Gas-Injector Wells

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 208809, “Deepwater Gas-Injector Wells: Overcoming the Challenge of Achieving Matrix Injectivity,” by Cedric Manzoleloua, Chau Nguyen, SPE, and Albert Okhrimenko, SPE, Schlumberger, et al. The paper has not been peer reviewed. After a successful exploration phase, an opportunity to develop the Guyana Suriname Basin came to fruition. The drilling and completion campaign scope included planned gas-injector wells that required a breaker application for matrix injection. A reversible nonaqueous reservoir drill-in fluid (RDIF) system using a calcium bromide brine as the internal phase and formulated at a 50/50 oil/water ratio (OWR) was selected. The complete paper discusses the results of extensive laboratory tests for the selection, customization of both the RDIF and the delayed breaker, and the field performance of the two fluids. Introduction All wells in the field were completed either as openhole gravel-pack or stand-alone screen configurations using inflow control devices (ICDs) or autonomous ICDs (AICDs). The gas-injector wells were completed as standalone completions with ICDs. The primary objective of the gas-injector wells was to put the wells on direct injection with no opportunity to flow back or fracture the formation.

Using Smart Completion Technology to Control Water Coning Problems and Increase Oil Recovery in a Southern Iraqi Oilfield

This research describes the using of a new well completion technology system that enhance the homogeneous and heterogeneous reservoir deliverability and the production performance gained through a completion technique using Autonomous Inflow Control Valve (AICD) by self-decreasing/delaying water and gas progress and promoting increasing in oil production, therefore, equalizing the drawdown (∆P=Pi-Pwf) along the well and provide a dynamic water shut-off operation and significantly increasing the economic life of a well and therefore, reducing capital and operational expenditures for the field development.
 The research presents a production performance simulation results for a conventional and smart well completion technology in a horizontal well in a southern Iraqi oilfield for two stages during well life; early stage (till 2018) and late stage (till 2033). For early stage of well life, there was no significant difference in results when comparing between the conventional completion design and the smart completion design. In the contrast, the simulation results for the late life of the well showed that the well can produce for approximately 1056.7 barrel per day crude oil with a water-cut of 82 % at the year of 2033. The also revealed that the results showed that the cumulative oil production from the year of 2018 till 2050 will be 23 million barrel of crude oil and 44 million barrel of water when the well is completed with conventional completion design. When the completion design has been changed and equipped with autonomous inflow control devices (AICDs) technology and simulated the production performance by NETool Software. The simulation results showed that the oil production has been increased by 891 barrel per day (1947.3 barrel per day) and the water cut has reduced significantly in comparison with the conventional production completion by 17 % (65.4 %) at the year of 2033. The results revealed that the cumulative oil production from the year of 2018 till 2050 will be 31 million barrel of crude oil and 33 million barrel of water.
 It has been concluded, from the reservoir and production simulation, that the application of the technology is successful and showed a clear advantage of using Autonomous Inflow Control Device (AICD) that provides better water influx control profile.

Technology Focus: Heavy Oil (April 2022)

Heavy oils are characterized by high density, high viscosity, and high-heavy-fraction components. Because of high viscosity and lower API gravity than conventional crude oil, primary recovery of some of these crude oil types requires thermal stimulation of the reservoirs. Most of the technologies that deal with heavy oil need to address the mobility ratio or viscous forces before any flooding. In general, poor recovery is caused by physical reasons or geological reasons. Physical reasons can be categorized as capillary forces (existence of the interfacial tension between oil and water, wettability) or viscous forces (high mobility ratio between water and oil). Geological reasons are heterogeneities in reservoir rock and exist in all petroleum oil systems. In heavy oil reservoirs, enhanced oil recovery (EOR) intends to reduce the capillary forces and interfacial tension to improve microscopic displacement efficiency or improve the sweep efficiency (macroscopic) by reducing the mobility ratio between injected fluid and displaced fluid. Improving the mobility ratio is achieved by increasing the viscosity of water using polymers or by reducing the oil viscosity using heat. In general, all technologies need to address the capillary and viscous forces to improve oil recovery. Paper SPE 207361 discusses improving of the efficiency of the flood by near-wellbore conformance and improving the vertical sweep efficiency. The use of fiber-optic sensors, as addressed in paper SPE 199023, is intended to gather better data and avoid misinterpretation during falloff tests and injectivity tests. Traditionally, for heavy oil EOR simulation, because of the addition of chemical species or heat to the flow equations as well as the need for a finer grid resolution, the use of the full-field model in most cases was limited and the use of sector models and local grid refinement to obtain a reasonable accuracy has been applied in the industry. Sector modeling conditions must be satisfied to establish the reliability and the trade-off between accuracy (sector models) and computational expediency (full-field model). Recent development of hardware and software [graphics-processing-unit (GPU) -based simulators] has provided the industry with the tools to achieve a full-field model simulation in most fields by taking advantage of GPU solvers and using a fine-grid model to predict full-field performance. Recommended additional reading at OnePetro: www.onepetro.org. SPE 200279 - Field Application of the Autonomous Inflow Control Device for Optimized Heavy Oil Production in South Sultanate of Oman by Ali Al-Jumah, Petroleum Development Oman, et al. SPE 203012 - More Oil and Less Water: Autonomous Inflow Control Devices in New and Old Producers in Heavy Oil Fields From South of Oman by Ameera Al Harrasi, Petroleum Development Oman, et al. SPE 207684 - Game Changer in Dealing With Hard Scale Using a Slickline Torque Action Debris Breaker by Mahmoud Mohamed Koriesh, Dragon Oil, et al.

Extended-Reach Wells Help Optimize Production in Marginal Offshore Prospects

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202896, “Optimizing Production From Marginal and Challenging Prospects To Unlock Field Potential: Success Cases in the Jasmine Field, Gulf of Thailand,” by Mukminin Yusuf, SPE, Pattarapong Prasongtham, SPE, and Theeranun Limniyakul, SPE, Mubadala Petroleum, et al. The paper has not been peer reviewed. The development of marginal volumes in the Jasmine field is part of the operator’s strategy to extend the field’s life, involving the exploitation of increasingly challenging prospects. The complete paper highlights two case studies to illustrate how the operator has developed marginal prospects to unlock the Jasmine field’s remaining potential successfully. The use of autonomous inflow control devices (AICD) has played a significant role in optimizing production in reservoirs with small oil rims and thick gas caps. Jasmine Field The designation “Jasmine field” is commonly used to refer to both the Jasmine field and the neighboring Ban Yen field, which are essentially one integrated field from an operational perspective. The fields are in the Gulf of Thailand, approximately 300 km southeast of Bangkok in depths of 190 to 200 ft (Fig. 1).

Technology Focus: Mature Fields and Well Revitalization (January 2022)

The highlight of this year’s feature on mature fields and well revitalization has been the increasing use of artificial intelligence (AI) and machine learning (ML) for analysis of mature assets. Many paper proposals studied using AI/ML techniques cover a wide range of topics including optimization of production operations, faster reservoir characterization of mature fields, and improvement of ongoing waterfloods. In fact, increased use of AI/ML has been a recurring theme in many of the areas covered in the Technology Focus sections of 2021’s JPT issues. There has also been a focus on implementing novel technologies such as the use of autonomous inflow-control devices in horizontal wells to suppress ingress of unwanted fluids in thin-oil-rim reservoirs, using integrated-asset models for debottlenecking, and the use of cased-hole logging in old wells to look for missed opportunities. After serving for 5 years, my time for writing this column is coming to an end. It has been a highly rewarding exercise going through the paper proposals, experiencing the hard work put in by industry professionals to arrest inevitably declining production from mature assets by putting together ideas in diverse fields such as reservoir management, production optimization, drilling, and formation evaluation to produce the extra barrel from mature brownfields. Out of the 314 paper proposals studied in these 5 years, 137 (44%) dealt with waterflood improvement, reservoir characterization, and simulation, and approximately 78 papers (25%) dealt with well revitalization involving workover drilling, completion, and stimulation. Sustaining production from mature brownfields challenges the best from each discipline, and significant success stories have come from a genuine collaboration of ideas across disciplines from subsurface to engineering. Recommended additional reading at OnePetro: www.onepetro.org. SPE 206195 - Data-Driven Optimization of Intermittent Gas Production in Mature Fields Assisted by Deep Learning and a Population-Based Global Optimizer by Javier Fatou Gómez, TNO, et al. SPE 205546 - Role of Geomechanics in Identification of Possible Mechanisms for Nonproductive Time and Improving Drilling Operations in a Mature Field in Offshore Sarawak, Malaysia by Avirup Chatterjee, Baker Hughes, et al. SPE 206303 - Combining Capacitance Resistance Model With Geological Data for Large Reservoirs by Davud Davudov, Resermine, et al.