Inflow Control Devices Research Articles

Technology Focus: Heavy Oil (March 2018)

Technology Focus Despite the recent downturn, a significant number of pilot- or demonstration-scale applications of existing technologies to develop new heavy-oil fields or new technologies to develop existing fields have been reported over the past year. I have selected two of them (SPE 184974 and SPE 184154) in this issue. While they might be projects that started a few years ago when oil prices were at a peak level, they are interesting and still relevant because the projects have continued and valuable results and observations have been shared. Reported cases of cost-effective applications such as well stimulation using chemicals and solvents have also been prominent over the past few years. Well-based applications such as stimulation or production optimization (SPE 184094) are quite useful to improve the productivity in smaller fields. On the other hand, efforts on cost reduction in large-scale thermal projects were obvious. Yet, in laboratory-scale experimental investigations, observations on the use of nanoparticles (SPE 184117) and new- generation chemicals to improve the efficiency of large-scale thermal and non-thermal (mainly chemical flooding) applications are very promising. I also would like to mention high-tech imaging applications to map the heat distribution in field-scale applications (SPE 184971). The areas listed seem to be the trend of new research studies and field applications along with optimization attempts on the basis of data-driven modeling. The focus will also be on new technology attempts toward the reduction of the cost of heavy-oil production, including lower-cost (solar panels) and in-situ steam generation (SPE 184118), minimizing steam needs by use of chemical additives and solvents (solvent-aided thermal—steam or electromagnetic—processes), and nonthermal applications (well stimulation by chemicals and solvents). I hope to read more papers in the coming years on the philosophical approaches to describing the problems and limitations of existing solutions because complex heavy-oil applications still need more effort on model development and experimental data generation. I included SPE 185633 in this issue as a good example of this kind of attempt. Recommended additional reading at OnePetro: www.onepetro.org. SPE 184118 In-Situ Steam Generation: A New Technology Application for Heavy-Oil Production by Ayman R. Al-Nakhli, Saudi Aramco, et al. SPE 184117 Experimental Study for Enhancing Heavy-Oil Recovery by Nanofluid Followed by Steam Flooding NFSF by Osamah Alomair, Kuwait University, et al. SPE 184094 Fluidic-Diode Autonomous Inflow-Control Device for Heavy-Oil Application by Georgina Corona, Halliburton, et al. SPE 184971 Satellite Monitoring of Cyclic Steam Stimulation Without Corner Reflectors by Michael D. Henschel, MDA, et al.

Применение устройств контроля притока в боковых горизонтальных стволах скважин пласта АВ4-5 Самотлорского месторождения

Применение устройств контроля притока в боковых горизонтальных стволах скважин пласта АВ4-5 Самотлорского месторождения

English

Production and injection in long reach horizontal wells pose several challenges in production optimization, flow assurance and reservoir management. Horizontal wells are known to be superior to vertical wells in terms of productivity, however, they are also susceptible to early water and/or gas cut production due to the heel-toe effect and/or permeability contrasts. Uniform distribution of water injection into all zones can also be a challenge in case of high-permeability streaks and fractures. To negate some of the adverse reservoir properties and to control the flow profile of production and injection fluids, downhole flow control devices are increasingly in use and beneficial in regulating flow, improved overall reservoir sweep, improved productivity from the tail section of the well and reduced water coning or gas cusping. Wellbore hydraulics for a long reach well completed with downhole valves have great influence on the reservoir performance and recovery in the long run. This paper presents a discussion aimed at better understanding of the critical challenges that long reach horizontal wells are prone to in terms of completion, as well as the developments so-far that have been applied to capture the physics across the long horizontal section. Three case studies are also discussed with some details emphasizing practical experiences of such wells.   Key words: Downhole flow controllers, horizontal wells, inflow control devices (ICD), internal control valves (ICV), production enhancement.

Design and Performance of a Novel Autonomous Inflow Control Device

Due to geological complexity and the heel–toe effect, the production profiles of long horizontal wells are usually imbalanced, and as a result, premature water breakthrough is usually encountered. Once water breakthrough occurs, this phenomenon will reduce oil production. To maximize oil recovery, inflow-control devices (ICDs) are widely used to create a uniform inflow profile. To date, known ICDs cannot meet all the ideal requirements throughout the well’s life. In this study, based on the combination of a successive restriction mechanism and water swelling rubber, a novel autonomous inflow control device is proposed. Then, the rules of oil–water two-phase flow through the novel design are studied by a numerical simulation based on optimized structural parameters, and the fluid property sensitivities are analyzed. Upon integration of the novel design into the test apparatus, flow tests are conducted. The influences of water content, inflow rate, and injection rate on the pressure drop are further analyze...

Technology Focus: Production and Facilities (December 2017)

Technology Focus The overarching theme of work published during the past year relating to production and facilities is performance and productivity improvement—doing more with less at a lower cost. This applies to the character of work that was performed and the topics that were investigated. The publications clearly illustrate how the low-price environment stimulated creativity in the improvement of existing operations and technologies as well as in the development of new technologies. Nearly one-third of the papers reviewed for this feature involved the use of digital models and simulations. Models were used to verify the study results or were improved on the basis of study results. Where adequate models were unavailable, new ones were developed (paper SPE 182450). Computational-fluid-dynamics (CFD) simulations played an important role in a number of published studies. One study (paper OTC 27762) validates simulations by actual physical testing and includes an evaluation of multiphase CFD flow-modeling techniques. Overall, this year’s publications confirm the pervasive dependence of technological advancements on the use of valid and (hopefully) reliable digital modeling. “Big data” played a role in several investigations, with objectives that ranged from optimizing field production (paper SPE 182450) to improving maintenance and lowering the cost for it (paper OTC 27788). Big data was also incorporated into project management by forward-using available information to systematically “Eliminate Decision Bias in Facilities Planning” (paper SPE 187283). Compressors and compression are components of facilities that often show higher capital and maintenance costs, so it is not surprising that several papers described means to reduce these costs. Three papers addressed compressor failure/reliability issues (papers SPE 183322, SPE 183528, and SPE 183253), while two papers described means to improve production economics by the purposeful application of compressor technology, including the use of a multiphase compressor to improve recoveries on a marginal wellhead platform (paper IPTC 18692). Inflow-control devices (ICDs) were addressed by several authors, with some focusing on the application of ICDs to steam-injection wells (paper SPE 183842). Others reported on the development of new types of devices that operate on electrical resistance (paper SPE 185682) or are viscosity independent (paper SPE 183930). Finally, the use of 3D printing for oil-field applications was described in two papers (papers OTC 27540 and OTC 27766). A review of existing and emerging nanotechnology applications in the oil patch was also provided (paper SPE 183301). Recommended additional reading at OnePetro: www.onepetro.org. OTC 27762 Modeling of a Full-Scale Horizontal Liquid/Liquid Separator Under Conditions of Varying Flow Rate, Water Cut, and Viscosity With Experimental Validation by A.B. McCleney, Southwest Research Institute, et al. SPE 183842 Developing a Robust Inflow-Control Device Suitable for High-Rate Injection by Joshua Snitkoff, Baker Hughes, a GE Company, et al. SPE 183840 A Robust Framework for ICD Design in a Giant Field Using 4D Dynamic Modeling by O.A. Ogunsanwo, Schlumberger, et al.

Integrated Cemented Inflow-Control-Device System Design

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 183383, “Integrated Off-Bottom Cemented Inflow-Control-Device System Design Toward Well-Delivery Optimization,” by Mohammed A. Al Madan and Mazen Bu Khamseen, Saudi Aramco, and Hedy Suherdiana and Ahmad Al Abdulmohsen, Baker Hughes, a GE company, prepared for the 2016 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 7–10 November. The paper has not been peer reviewed. Off-bottom-cementing (OBC) operations are unique to Saudi Arabia and represent a very challenging approach to drilling and workover operations when deployed in combination with inflow-control devices (ICDs) across horizontal sections. The multitasking-valve (MTV) feature in upgraded ICDs offers safe, simple, and cost-effective deployment operations. This paper discusses the first deployment of an ICD system combined with an OBC system for a workover operation in a mature producer well in the Kingdom of Saudi Arabia. Introduction In wells where an OBC liner is required to cover nontargeted formations above the production zone, two methods of deployment can be used: the one-trip system and the two-trip system. These refer, respectively, to whether the OBC components are deployed in a single trip along with the ICD or in a second trip with string in the previously deployed ICD completion. The one-trip OBC ICD completion does not allow an inner-string application. Therefore, circulation while running in hole was ineffective in this producer, which caused deployment problems. The two-trip OBC ICD completion was then considered. The idea was to split the completion into a lower ICD completion, which is dropped off inside the openhole horizontal section with a setting sleeve. The earlier two-trip OBC ICD completion used an inner string, a circulating system, and an openhole-packer-setting tool. This allowed 100% circulation from the shoe during deployment of the lower ICD completion, although circulation rate is limited because of pumping through the small internal diameter (ID). The upgraded ICD with an MTV allows the lower completion to be deployed without an inner string while achieving 100% circulation at the shoe, which smooths operations and saves up to 24 hours of rig time. The MTV temporarily blocks the communication between string and annulus while running in hole. Once reaching the setting depth, MTVs are actuated by hydraulic pressure. All hydraulically set equipment can also be set at this point. Ultimately, in the case outlined in the complete paper, it was decided to combine once again the separated deployment into a single system by use of the MTV feature, which provides important functions for the one-trip OBC ICD completion—the ability to perform 100% circulation from the shoe and to set all hydraulic downhole tools with one setting ball.

Characterization and Erosion Modeling of a Nozzle-Based Inflow-Control Device

Summary In the petroleum industry, water-and-gas breakthrough in hydrocarbon reservoirs is a common issue that eventually leads to uneconomic production. To extend the economic production lifetime, inflow-control devices (ICDs) are designed to delay the water-and-gas breakthrough. Because the lifetime of a hydrocarbon reservoir commonly exceeds 20 years and it is a harsh environment, the reliability of the ICDs is vital. With computational fluid dynamics (CFD), an inclined nozzle-based ICD is characterized in terms of the Reynolds number, discharge coefficient, and geometric variations. The analysis shows that especially the nozzle edges affect the ICD flow characteristics. To apply the results, an equation for the discharge coefficient is proposed. The Lagrangian particle approach is used to further investigate the ICD. This allows for erosion modeling by injecting sand particles into the system. By altering the geometry and modeling several scenarios while analyzing the erosion in the nozzles and at the nozzle edges, an optimized design for incompressible media is found. With a filleted design and an erosion-resistant material, the mean erosion rate in the nozzles may be reduced by a factor of more than 2,500.

Performance of Horizontal Wells with Inflow Control Devices in Homogeneous Reservoirs with Bottom Water Drive

Horizontal well techniques play an important role in the development of unconventional oil and gas plays. A key challenge in horizontal well completions is that water cut will rise rapidly once water breakthrough without inflow control. Inflow control devices restrict flow by creating an additional drop in pressure to equal the drop in wellbore pressure in order to reduce water or gas coning. Once a control device is installed in the wellbore, it is almost impossible to adjust. As a result, it is extremely important to understand the oil–water pressure profile and the long-term behavior of well completions with ICDs. We use the theory of dynamic simulation-coupled well-reservoir flow to analyze the performance of horizontal well completions with and without ICDs using the multi-segment well model. This study proposes a new single-flow wellbore model and develops the model of oil–water flow in horizontal wellbore with influx. The performance of horizontal well completions with ICDs in reservoir with water drive is analyzed on the basis of the new coupled reservoir–wellbore model. Simulation results show that water breakthrough first occurs near the heel of the horizontal well due to the drop in pressure in the wellbore by the end of water-free production period in the homogeneous reservoirs. We also point out that completion with ICDs can optimize production in horizontal wells with long production sections, low drawdown pressure and high production rates. In these situations, the effects of a drop in oil–water two-phase pressure are significant.

A Mathematical Model and Inflow Control Effect Analysis of Inflow Control Devices Completed Horizontal Well

The main purpose of this paper is to analyze and compare the influence of nozzle size, uneven gravel packing, packer leakage, and dynamic production process on the inflow control effect. First, a new mathematical model of Inflow control devices (ICDs) completed horizontal well is proposed which has two new features. One feature is that the annulus between the sand control screen and the formation is considered. Therefore, the influence of uneven gravel packing can be simulated by adjusting the permeability distribution along the annulus. The other feature is that it accounts for packer leakage by introducing a new parameter named “leakage factor” into the model. Then, the inflow control efficiency is defined and used to quantitatively characterize the inflow control effect, and the influences of nozzle size, uneven gravel packing, packer leakage, and dynamic production process on inflow control efficiency are analyzed. The results show that the nozzle size and packer leakage have the biggest influence on the inflow control efficiency, and the influence of gravel packing is negligible unless the permeability of the packed gravel along the wellbore is extremely heterogeneous.

A 5-Year Journey of Advanced Completions

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 175330, “Five Years’ Journey of Advanced Completions for the Kuwait Oil Company,” by Mohammed A. Siddiqui, SPE, Ahmad K. Al-Jasmi, SPE, Menwer M. Al-Rasheedi, and Hashem F. Al-Abdullah, Kuwait Oil Company, prepared for the 2015 SPE Kuwait Oil and Gas Show and Conference, Mishref, Kuwait, 11–14 October. The paper has not been peer reviewed. With the objective of increasing its production to 4.0 million BOPD, the Kuwait Oil Company (KOC) is developing its fields with optimum technology solutions. One of these promising technologies is that of advanced completions—specifically, inflow-control devices (ICDs) and interval-control valves (ICVs). Application of this technology led to multifold increases in sustained production in horizontal wells in all reservoirs and a simultaneous reduction in water cut. Introduction The main reservoir objectives for applying advanced completions include decreasing the influence of heel-to-toe effects, controlling influx from high-permeability zones, delaying water/gas fronting, depleting the reservoir uniformly, and improving well cleanup and sweep efficiency. Advanced completions are applicable in both sandstone and carbonate reservoirs. The ICVs also provide the advantage of controlling production from multiple laterals in multilateral wells and controlling influx in layered reservoirs. KOC operates several prolific oil reservoirs with significant differences in geological and fluid characteristics (these are described in detail in the complete paper). ICDs (conventional or advanced) are passive flow-velocity restrictors and offer excellent regulation of flow through the constricted openings (Fig. 1). An optimal pressure drop can be achieved through this equipment in a comprehensive downhole completion design that includes ICD type, placement methodology, and well-thought-out and optimally planned reservoir segmentation with use of geological and petrophysical data. The compartmentalization of the lateral section can be achieved through swellable or mechanical packers. ICVs are intelligent well-equipment systems whose functions, in principle, are similar to those of the ICD in terms of reservoir management. Additionally, they allow operators to control flow into or out of a segmented reservoir interval wherever selective control over production or injection is required.

Technology Update: New Intelligent Completion System Enables Compartment-Level Control in Multilateral Wells

Technology Update Although early inflow control devices and intelligent completions (ICs) were introduced almost 20 years ago, completion technology has not kept pace with advancements in drilling technology. Today, wells completed in multilayered reservoirs, multilaterals with compartments of varying pressure, and extended-reach drilling (ERD) with wellbores as long as 12 km are becoming common. In complex, hard-to-reach reservoirs and tighter formations, operators need to maximize reservoir contact in every well to optimize reservoir drainage and minimize costs. Yet the evolution of ICs has lagged, creating a technology gap with significant ramifications. IC reliability has been steadily increasing over the years, reaching more than 97% for the life of the well in many applications. Most permanent downhole monitoring and control solutions still consist of a separate “kit” of products rather than an integrated system. Traditional IC systems lack sufficient real-time measurements in individual producing zones to facilitate “cause and effect” decision making. Without detailed compartmental information and control in case of water or gas breakthrough, operators are forced to restrict production, intervene, and in some instances work over the entire well. Until recently, there has been no way to maintain production from other unaffected zones during the long diagnostic process of production logging, well testing, interpretation, and execution of an appropriate well intervention. The typical optimization cycle substantially raises operating costs while delaying vital production for weeks or months. Consider Saudi Aramco’s experience with ICs in remote oil fields, where tight formations and a shortage of suitable surface locations drove the need to dramatically increase reservoir contact per wellhead. Before 2007, the company had successfully drilled and completed a number of multilateral ERD wells, achieving more than 5 km (16,400 ft) of reservoir contact per well. These maximum reservoir contact (MRC) wells were completed with then state-of-the-art IC technology. Completions consisted of permanent downhole gauges (PDGs) and downhole flow-control valves (FCVs), which could be partially or fully opened or closed by hydraulic control lines from the surface. Monitoring and control stations were installed in the motherbore above the junction to each side lateral.

Mechanism and sensitivity analysis of an inflow control devices (ICDs) for reducing water production in heterogeneous oil reservoir with bottom water

The improved oil recovery (IOR) mechanism of ICDs is usually contributed to equalizing pressure drop to achieve an evenly distributed inflow profile along the horizontal section. Substantially, in heterogeneous oil reservoirs with bottom water, the intrinsic mechanism is changing the pressure distribution in formation to effectively utilize the energy of bottom water. In this work, a reservoir-ICD-wellbore coupled model was established and the corresponding simulator was developed. In the rest of the paper, this model was used to discover the mechanisms of ICDs in heterogeneous reservoir with bottom water. Finally, the sensitivity of many factors on oil recovery factor and IOR of ICDs were demonstrated. The results show that ICDs can improve the recovery and delay the water coning. The intrinsic mechanisms of ICDs contains both equalizing pressure drop around the wellbore and changing the direction of lateral flow to increase the sweep volume of bottom water, but ICDs is essentially a shallow profile control technique. The IOR of ICDs is significant in strong heterogeneous oil reservoirs; the IOR increases as the well production rate and oil viscosity increase; as Kv/Kh (the ratio of vertical to horizontal permeability) and HD (dimensionless water avoidance height) increase, the IOR first increases and then decreases, the optimal values are related to the permeability heterogeneity.

Application of multi-segment well approach: Dynamic modeling of hydraulic fractures

Hydraulic fracturing is a stimulation treatment routinely performed to create fracture network on low permeability reservoirs to enhance the productivity. Such induced fracture network has much higher conductivity and generally is treated through either local grid refinement (LGR) to capture the transient phenomenon or embedded discrete fracture model (EDFM). Both approaches require complex gridding meshes, leading to heavy computational time. LGR also requires the orthogonal orientation of hydraulic fracture with horizontal wellbore trajectory. Another challenge for LGR and EDFM comes from the dynamic meshing over the time. Infill drilling and re-fracturing are common due to the nature of the fast production decline in those hydraulically fractured wells. In the case of infill drilling or re-fracturing, the grids for the well or completion stages have to be generated from the beginning of the simulation, causing computational inefficiency. Also, sensitivity evaluation of well landing point, spacing, and completion optimization needs easy preprocessing of model input and short simulation time.In this paper, we overcome the above challenges through representing hydraulic fracture network with multisegment well (MSW) concept. Multisegment wells (MSW) offer an improved description of the wellbore physics over conventionally modeled wells and can be used in different situations like, horizontal or multilateral wells, wells with inflow control devices (ICDs), and significantly varying flow conditions along the wellbore. On the other hand, the conventional well model (CWM) represents a well as a single pipe (single fluid) a MSW discretizes the well trajectory into several segments. Each segment has its fluid conditions and solution variables, hence allowing for detailed modeling of changing conditions along the wellbore.Since MSW node system is independent of reservoir grid system, fracture orientation can be at any angle freely with wellbore trajectory, which avoids the complex LGR or EDFM and reduces the number of grids. Meanwhile, MSW provides a flexibility of fracture geometry representation, enabling easy addition and alteration of fractures at any simulation time.Our MSW approach has been validated by comparing with the LGR through several benchmarking studies of a tight reservoir. A field case was demonstrated for infill drilling among existing vertical wells and re-fracturing operations. While it is difficult to model infill drilling of a well with hydraulic fractures through another modeling approach, the MSW option makes it easy by just opening the wellbore with fractures at certain simulation time. The re-fracturing operation is modeled as the opening of the completion. These settings can be done for each well. Our approach also has potential to dynamically couple with stimulation design tools.

Degradation profiles of poly(methylene oxide) and poly(glycolic acid) for inflow control devices in oil wells

ABSTRACTThe viability of the application of hydrolysable polymers, such as poly(methylene oxide) (PMO) and poly(glycolic acid) (PGA), in formation treatments in oil wells, was studied; we examined their addition to inflow control devices (ICDs), which are instruments used to control the oil‐flow profile along production intervals. Thereby, the structural and morphological changes of PMO and PGA samples exposed to common chemicals, such as hydrochloric acid (HCl) and sodium chloride (NaCl) solutions and xylene, used in the procedure were evaluated under conditions similar to those observed in southeastern Brazilian offshore oil fields (temperature range = 50–130 °C, 41.4 MPa). The aim of this study was to verify whether the polymers hydrolyzed and could be further removed from the ICDs. Techniques including high‐pressure liquid chromatography, ion chromatography, 13C‐NMR, differential scanning calorimetry, scanning electron microscopy, and optical microscopy were applied in this study. Xylene did not produce expressive effects in the samples. PMO was significantly affected by 15% HCl at 75 °C but was not completely dissolved after 24 h of exposure; this counter indicates its use. The PGA hydrolysis profile in NaCl brine was suitable for application around 75 °C. © 2016 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2016, 133, 43786.

Flow-Control Optimization Maximizes Accuracy of Multiphase-Flow Rate Allocation

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 173873, “Flow-Control Optimization To Maximize the Accuracy of Multiphase-Flow Rate Allocation,” by Reza Malakooti, Khafiz Muradov, and David Davies, Heriot-Watt University, and Alexander Kuznetsov, Weatherford, prepared for the 2015 SPE Bergen One Day Seminar, Bergen, Norway, 22 April. The paper has not been peer reviewed. The value added by intelligent wells (I-wells) derives from real-time reservoir and production-performance monitoring together with zonal downhole flow control. Unfortunately, downhole sensors that directly measure the flow rates and phase cuts required for optimal control of the well’s producing zones are not typically installed. This paper describes an “active” monitoring technique that uses a direct search method to optimize the sequence of interval-control-valve (ICV) positions during a routine multirate test in an I-well. Introduction I-well completions include both downhole flow-control tools and monitoring sensors. Reservoir inflow is controlled by means of passive devices [inflow- control devices (ICDs)], active valves (ICVs), and self-adjusting devices ( autonomous ICDs and autonomous ICVs). Reservoir and well-performance properties should be monitored regularly to support flow- control decisions efficiently. Various physical quantities, including temperature, pressure, flow rate, acoustics, strain, and seismic, are currently measured by electronic, radioactive, and fiber-optic sensors to assist the multiphase-flow rate allocation in I-wells. Producing from only a single well or zone during a test is a common practice. This delivers a single flow-rate value measured at a particular time. However, this approach is inefficient, resulting in lost production and possible difficulties when trying to restart the closed-in wells or zones. A costly production-logging well intervention is a possible alternative; it does provide an inflow rate and a phase-cut profile, but only at a specific time without the possibility of delivering the current phase cut and production rate continuously. The alternative is to use (continuous) passive indirect measurements. Such soft-sensing techniques are used widely in (surface) facilities and process plants where extensive, complex networks of sensors can be implemented relatively easily. They are now being introduced for reservoir and well applications. A multiphase soft sensor consists of (1) an estimation technique, (2) a multiphase-flow model, and (3) the measurements. The multiphase-flow model relates the measurements to the parameters required for the estimation of downhole flow rates. The estimation technique is used to compute these parameters by minimization of the mismatch between measured information and predicted values. Published soft sensors have used both stochastically and deterministically based optimization methods as the estimation technique. The complete paper provides a review of recent research and developments in this field. Soft-sensing techniques are subjected to multiphase-flow-model errors and measurement uncertainties. The latter refers to variance of the values attributed to a measured quantity. For this reason, a new approach is required to overcome the limitation of the passive soft- sensing techniques used to allocate downhole flow rates. To accomplish this goal, an active multiphase-flow-rate soft-sensing method has been developed to design an optimum series of flow tests. The soft sensor obtains the most accurate estimate of the zonal properties by use of the deformed-configuration (DC) method to optimize the flow-test conditions (the ICV flow area in multizone I-wells or the wellhead-choke position for multiple conventional wells). To the authors’ knowledge, this work is the first publication to demonstrate the applicability of the DC optimization method in well soft-sensing problems.

The theory of the automatic phase selection controller and its performance analysis

Bottom water coning, to a large extent, will shorten the reservoir anhydrous production time and seriously affects horizontal well performance. As a result, the comprehensive benefit of the exploitation is damaged, which is the restriction of horizontal efficient key during the development of bottom water reservoir. At present most of the oil fields in China are facing high water-cut and low oil production traditional ICD (Inflow Control Device) is only suitable for the well before water breakthrough, and affects little after water breakthrough. Therefore, a new water control tool, automatic phase selection controller (PSC), has been developed based on the current technical difficulties and practical problems in the exploitation of oil field by horizontal wells in China. Automatic phase selection controller based only on the fluid properties and flow path to distinguish fluid and limit the output of the water without the use of any moving parts. The flow field analysis, sensitivity analysis, erosion analysis, water control ability and comparison analysis of ICD pressure drop are carried out by using CFD software. Simulation results indicate that: (i) the pressure drop generated by the water flow in the PSC is higher than the oil flow in it, and the main reason is the water rotating at a high speed in the tool to produce higher pressure drop and oil will not rotation; (ii) the pressure drop of the fluid flow through the valve is mainly determined by the viscosity and flow rate of the fluid, and the density of the fluid is very low; (iii) the sand carrying liquid can cause the erosion damage to the PSC, but the erosion rate is very small and at affordable range; (iv)the higher the water content is, the greater the pressure drop across the valve is; (v) as soon as water breaks through into the well PSC would be able to provide more flow resistance than nozzle type ICD. The experimental results show that the PSC can be applied to restrict water production after water breakthrough in the well and the CFD software can be used in the design and performance analysis of the PSC. Engineering application has been used to verify indoor simulation and the results show that PSC has potential practical application in increasing oil recovery.

Optimization of Upper Burgan Reservoir Multilateral Well With Inflow-Control Device

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 175227, “Optimize Development Strategy of Upper Burgan Reservoir Through Multilateral Well With Inflow-Control Device in Raudhatain Field, North Kuwait,” by Sankar Chowdhuri, Peter Cameron, Tarek A. Gawwad, Mohammad R. Madar, Siddhartha Sankar Sharma, Moute’a Dughaim AlMutairi, Vijay Shankar Rajagopalan, Suresh Chellappan, and Moudi Fahad Al-Ajmi, Kuwait Oil Company, prepared for the 2015 SPE Kuwait Oil & Gas Show and Conference, Mishref, Kuwait, 11–14 October. The paper has not been peer reviewed. In coning situations, such as in the production of oil reservoirs with a bottom aquifer, multilateral wells reduce the coning effect and, hence, prove to be more cost-effective. This paper discusses the first multilateral well with a Level-4 junction combined with an inflow-control device (ICD) planned, designed, and drilled in the Upper Burgan reservoir of Raudhatain field, north Kuwait. The paper covers the main challenges of well placement during geosteering to ensure the best quality of reservoir rock in structurally and depositionally complex settings with smart-completion design. Introduction The Raudhatain oilfield structure is one of several developed along a prominent anticlinal ridge that plunges gently north of Kuwait. These individual highs, in which the principal oil accumulations of the area are localized, tend to be of large areal extent and substantial structural relief. The Raudhatain structure exhibits a quasiradial pattern of small normal faults of limited throw. This geometry suggests a primary origin by uplift. The Raudhatain structure is a faulted anticlinal dome with 65 to 90 ft of topographical relief. The 3D seismic has defined the major faulting in the northern part of Raudhatain as northwest trending, whereas in the southwestern part of the field the faults trend northwest. Fault throws are highly variable and range from less than 30 ft to as much as 150 ft. Stratigraphy of Upper Burgan Reservoir The Burgan formation is a major reservoir unit. It unconformably overlies the carbonate Shuaiba formation and underlies the Mauddud carbonates with locally unconformable contact. The thickness of Burgan is approximately 950 ft of soft, clean, porous, well-sorted quartz sandstones of littoral to possibly deltaic aspect, interbedded with siltstones and dark shales. The Burgan formation at Raudhatain has been divided informally into three members, termed the Upper Sand, Middle Shale, and Lower Sand.

RESERVOIR AND WELL COUPLING SIMULATION WITH DISTRIBUTED ALGORITHM

A major goal when using a horizontal well is to increase the productivity rate when compared to the vertical layout, due to a larger area of the reservoir exposed to the well. The coupled solution into the reservoir and through the well requires finding the answer to the Darcy equation in the reservoir and the Navier-Stokes equations in the well. Additionally, several types of completion, which introduce new flow resistances, such as completions with inflow control device (ICD), stinger completion, packed off, gravel pack, and slotted liner are considered. All these details are not available with the current reservoir simulators, since the level of local detail would require a very large computational time and a complex model. In this work, the coupling between the reservoir and the well is accomplished through a distributed system, where the flow, at various types of completion, is handled through correlations obtained analytically or provided by completion equipment manufacturers. The proposed procedure consists of a fast tool, accurate and easy to use for a petroleum engineer. The results of this work show that the distributed system allows a detailed view of the flow into the well and its completion, quantifying the flow rate and pressure over the annular and liner for different types of completion, adding more physics into these simulations.

The application of risk-based methods to multilateral well design

Horizontal and multilateral oil and gas wells are used to maximise hydrocarbon recovery while reducing the required well count and associated costs. Presently, lateral lengths are designed using semi-quantitative methods. Guided by a desire to minimise the risk of poor well deliverability, the tendency is to design producing lengths longer than required, with the rationale that the well connects with sufficient hydrocarbon bearing reservoir to provide good deliverability. Drilling long producing lengths, however, is expensive and generates a higher risk of drilling and lifecycle (intervention and workover) problems. Furthermore, attempting to increase deliverability by extending the producing length encounters the law of diminishing returns as the flow becomes constrained by tubing friction loss. This paper seeks to quantify the optimal length for a horizontal well for a given range of reservoir conditions through multiphase fluid modelling and stochastic analysis. A discretised horizontal well model was created, which shows how changing the well length transforms the probability density function of the production rate for the well. A parametric case study was conducted, which demonstrates the evolution of the optimal well length and production rate with parameters including well diameter, fluid viscosity and well flowing bottomhole pressure. A simplified economic analysis illustrates the incremental change in discounted cash flow and quantified risk from drilling a longer well. The model also considered the influence of inflow control devices (ICDs) to adjust the inflow to match permeability and even-out inflows along the producing length, thus reducing the risk of gas and water coning, and improving hydrocarbon recovery.

Optimized Design of Autonomous Inflow-Control Devices for Gas and Water Coning

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 173203, “Optimized Design of Autonomous Inflow-Control Devices for Gas and Water Coning,” by Terry W. Stone, Terje Moen, David A. Edwards, Alexander Shadchnev, and Kashif Rashid, Schlumberger, and Geir Frode Kvilaas and Kjell Christoffersen, Det Norske Oljeselskap, prepared for the 2015 SPE Reservoir Simulation Symposium, Houston, 23–25 February. The paper has not been peer reviewed. Several designs for autonomous inflow-control devices (AICDs) are available. One forces inflowing fluids to enter gates, depending on inertial and viscous forces of the various fluids. Another is an autonomous valve in the shape of a free-floating disk that restricts the flow rate of low-viscosity fluids and is primarily used to choke gas and water inflow. Recently, a device with water-swellable rubber inside the nozzle has been proposed, but it is not yet commercially available. The comparative properties and abilities of these designs are the focus of this paper. Well Model, Reservoir Simulator, and Optimizer The well model used in this work is part of a next-generation parallel commercial reservoir simulator and features a flexible multisegmented well topology, enhanced robustness for difficult problems, and extensive well-model options. It forms part of a scalable parallel commercial reservoir simulator. Optimizations carried out in this work used an optimizer developed to alleviate the computational cost in an optimization study where simulation-based objective functions are expensive to evaluate. When compared with several other commonly used optimizers, it was demonstrated that this optimizer outperformed others significantly. Modeling Inflow-Control Devices (ICDs) Various ICD designs include those with nozzle orifices, tubes, and helices. Unlike ICDs, AICDs may or may not have moving parts but they can change or modify their state in response to inflow. Design of the AICD determines the particular unwanted fluids that are delayed. There are a number of types available commercially, including a floating flapper, an oil- selector valve, an autonomous inflow-control valve, the rate-controlled-production (RCP) valve, and a fluidic diode valve. Another design recently proposed is based on inclusion of water-swellable rubber within the nozzle, but this is not yet commercially available. Both ICDs and AICDs are often deployed in a compartment whose edges are sealed with a packer, and are placed in the tubing wall between an annulus and main production stream.