An Innovative Inflow Control Device Technology with Sliding Sleeve Functionality Maximizes Recovery in Horizontal Wells

Rubiales and Quifa are the Colombia's major heavy oilfields (oil gravity ranges from 11.3 to 14.4° API) with a current oil production of more than 260 MSTB with an oil viscosity ranges from 370 to 730 centipoises. Horizontal well technology is used to drill through unconsolidated sandstones with an active and strong aquifer, under primary depletion. Since 2006, 604 horizontal producer wells have been drilled and completed using slotted liner in open hole. The high water production rate from the beginning of the operation in the horizontal wells is the main problem to be controlled in the Rubiales and Quifa fields, due to the high cost of produced water treatment and other factors. Water production is inevitably associated with the oil production; however one of the biggest challenges is to delay the water production as much longer as possible. Rubiales and Quifa actually have a large number of closed wells that have reached its economic limits, mainly by high water production. This production imbalance is being addressed in the new horizontal wells, using inflow control devices (ICDs). The ICDs is placed in each screen joint to balance the production influx profile across the entire lateral length and compensate the permeability variation and therefore the productivity of each zone. In 2012, a pilot test has been designed and implemented in Rubiales field with three horizontal wells using passive ICDs completion. The performance of the ICD's is found to reach the highest cumulative oil production compared to neighboring wells. The main purpose of this paper is to detail the selection process design and results evaluation for the use of the passive ICDs in horizontal wells at Rubiales and Quifa Fields, heavy oil reservoirs.

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

The field-A1 is an offshore gas field located about 56 km from the coast of East Africa with the water depth of 1153 m. The permeability distribution varies across different layers with an overall permeability of 680 m and porosity distribution for the reservoir field-A1 varies 0.21-023. The reservoir thickness also varies up to 50 m thick. This research work identifies parameters that will contribute to the impact of water coning. Simulation sensitivities are run to observe the effect of water coning/cresting in horizontal gas wells and predicting the performance of these wells using Petrel simulator. Results have shown that put horizontal well in East-west will have early water breakthrough and not recommended due to the impact of edge aquifer due to less recovery compared to north-south and original wells orientation (northwest-southeast). The varying height of perforation and standoff as identified is at the standoff between 30-40 m in the field-A2 will delay water coning high recovery with more extended plateau length period. The gas recovery may happen to be low, due to the distribution of permeability layer for the horizontal wells and low productivity index that is the performance of the well. Rate-dependent skin and mechanical skin evolution in time show that increasing non-Darcy /turbulence factor reduces the performance of the well and decreases gas recovery the high drawdown tendency is observed before water breakthrough time however there is early water breakthrough, thus use of deep penetration. Horizontal gas wells have a constant horizontal length for all cases of 300 m increasing tubing head pressure from 40-100 bars result to decrease plateau length period of the gas production, low water production rate, and low gas recovery. Varying the kv/kh ratio from 0.1, 0.6 to 1 shows early water breakthrough by 6 months earlier from the base case with 0.1 hence will not delay water coning. The gas recovery is reduced by 5%. Gas recovery is increased with an increase in gas rates constrain, and early water breakthrough is observed when producing at high rates. Producing at low rates may delay water coning. However, it is not economical since there is less gas recovery and may take a more extended period for production to reach to its total maximum gas production of which is less compared when producing at high gas rates. There is a stronger of the aquifer from the west side, which is predictable to cause water coning than on the east side. This aquifer impacts the gas recovery reduction by 19%, with water coning radial extension of 1.7 km and peak water production rate for 16 years. The aquifer influx rate is seen to be increased by 69% when the aquifer volume is double. Therefore, from the results producing at a high rate that has high recovery before the impact of aquifer or water has occurred to the wells, known as outrunning of the aquifer. To avoid water coning, using advance completion technique such as inflow control devices (ICD), installing a down hole gauge. Also, it is essential not to perforate if well is near to gas water contact the horizontal wells should be located at maximum distance from gas water contact to maximize gas recovery. Not only that but also use of fully open choke allows much water production rate increase, which leads to water coning.

To address the need for better understanding of multiphase fluid flow behavior through passive inflow control devices (PICDs), two-phase (oil-water) full-scale flow loop testing on helical and a new ICD design, "Hybrid" has been completed. The primary testing objective was to generate a comprehensive two-phase (oil-water) data set of flow performance curves for the helical ICD and the hybrid ICD. The test included a broad range of flow tests with varying viscosities, water cuts and pressures. The results are presented in an innovative manner using isobaric plots (isobars lines with trend lines for each viscosity value) and Reynolds number vs. Flow Coefficient plots, which can be used to easily compare different ICD performances. Test results confirm that for oil-water flow, a viscosity break point for the helical ICD occurs at 2 centipoise (cP) of medium oil. Below this break point the helical ICD does not promote water production in two-phase flow. Above this viscosity break point, the helical ICD exhibits a physical phenomenon where, at water cuts above 30%, the total flow increases at any given pressure drop promoting water flow. With regards to two-phase oil-water fluid flow, the hybrid ICD performs independently of viscosity for the range tested (up to 200 cP - maximum flow viscosity tested at the lab).The hybrid ICD consistently creates more resistance to water flow than to oil flow, causing total flow to gradually decrease at constant pressure as water cut increases. This effect was more apparent at higher pressure regimes. The functional break point of the hybrid ICD is determined to be above 200 cP. Introduction A comprehensive two-phase (oil-water) data set of flow performance curves for the helix inflow control devices (ICDs) and hybrid ICDs was conducted through extensive laboratory testing to identify the threshold viscosity, and to quantify single and multiphase model validity. These test results confirm that the threshold viscosity is 2 centipoise (cP). At viscosities greater than 2 cP, the test results confirm previously published findings that the helix design exhibits preferential production of water for a given pressure drop in a two-phase flow. Additionally, results verify that the helix ICD behavior exhibits correlation to the single phase model but requires a correction due to non-constant flow coefficient, and does not exhibit correlation when the fluids are multiphase, especially at higher viscosities.

Horizontal wells are well-recognized as one of the most effective innovations in exposing the wellbore to maximum reservoir contact and drainage area to improve recovery economics. It creates lower pressure drop to achieve better productivity compared to vertical/deviated wells. In order to enhance sweep efficiency, horizontal wells can be completed with Inflow Control Devices (ICD). ICD completion creates a more uniform inflow distribution along the production interval of the horizontal well. It aims to delay water breakthrough at high permeability zones and to provide better well clean up at initial production. In general, the performance evaluation shows that horizontal wells with ICD's have better sustained productivity than horizontal wells completed open hole or with screens. ICD completion design was previously done based on near-wellbore data only. A new methodology has been applied by tailoring the ICD completion design with fine-grid dynamic 3D simulation that is fast enough to be used for real-time model optimisation while drilling. 3D simulation enables the optimisation for the number and placement of nozzles and packers by maximising the utilisation of reservoir information. The improvement on delivering ICD completion design also includes torque and drag analysis on every horizontal well candidate. The new ICD completion design workflow has been applied since 2015. The real-time single-well dynamic 3D simulation-based design results in a better understanding of the completion options and their performance predictions. Various ICD completion scenarios, from constant nozzle sizes to varying nozzle sizes, and different packer numbers and placements are simulated. The new 3D simulation tool is able to provide time-lapse effects of cumulative fluid (oil and water) production for different flow rates. Additional pressure drop across the completion is modelled for different nozzle configurations. Based on these simulation results better informed decisions can be made regarding the nozzle sizes and numbers. In addition, the proposed ICD completion run-in-hole tally is evaluated in the torque and drag simulator to ensure the proposed ICD completions can be run to total depth (TD). The results of these two simulation steps are combined to optimize the final ICD completion design.

One of the largest oil fields in the GCC was developed in the 1960's. The field was initially produced under natural depletion supplemented by gas injection. The high offtake rates led to a rapid displacement of the gas/oil contact; thus, the field has now been suffering from early gas/water breakthrough and uneven fluid influx along with the horizontal wells. The reservoir has been on production for more than 50 years. Water/gas breakthrough from fractures being the major challenge which negatively affects wells oil production rates. Applying technology which can manage water/gas breakthrough in a cost-effective manner whilst allowing increased oil production was a key goal from operators in this field. Passive Inflow Control Devices (ICD) were introduced to the global oil and gas market in mid/late-1990's, and the first generation of Autonomous ICD (AICD) that can help reduce more unwanted gas or water was first installed in 2007. ICD's successfully demonstrated that they could delay the gas and/or water breakthrough within horizontal wells, but they could not choke gas when the coning/gas-breakthrough occurred and along with limited abilities to stop unwanted water production. To help solve this problem, the Autonomous Inflow Control Devices (AICD-RCP) with a movable disc was introduced to the market and demonstrated reduction of gas production by 20-30% with similar gains in oil production[1]. In this paper, the newest generation of Autonomous Inflow Control Valve (AICV) technology is presented. The AICV technology has a movable piston that can close and reduce the unwanted gas and water production by up to 95%[2]. The application of AICVs discussed herein were deployed within several wells which had extremely high Gas Oil Ratio (GOR) and low oil production. The novel AICV technology can differentiate between fluid types based on viscosity and density. When undesired fluid (gas and/or water) starts to be produced, the AICV chokes the valve flow area gradually until completely shutting off, all without well intervention[3]. Well production performances are documenting the benefits of installing AICV completions. The results demonstrate the AICVs closing the zones with high gas production and favoring oil-rich zones. Majority of evaluated wells demonstrated clearly that the extremely high GOR was reduced; some wells have returned to solution GOR for more than two years, and at the same time, the daily oil production is increased.

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

A finite-difference, lumped-parameter based, reservoir-wellbore coupled model was developed to characterize the economic benefit of inflow control devices on horizontal well completions. Baker Oil Tools' inflow control device (ICD), the Equalizer™, has been tested and analyzed as a standalone entity. Several correlations have been developed to quantify the pressure drop characteristics of this ICD. To show the positive effects an ICD has on an asset, one must quantify, not only the flow performance of the ICD, but the time dependent depletion scenarios of the reservoir in question.In this paper, the benefits of a unique inflow control device will be shown by analyzing reservoir depletion scenarios with and without inflow control. Without inflow control, a horizontal completion is at risk of early water breakthrough. With early water breakthrough, the water cut tends to escalate due to its lower viscosity compared to that of oil. As the water cut escalates, oil production drops significantly, often leading to shutdown of the well and reserves being left in the ground. This paper will show the benefits of using an ICD by describing the model development of a hypothetical, yet typical, field and the subsequent analysis that drives the completion design of the horizontal well.The model includes the reservoir, water oil contact, near-wellbore characteristics, wellbore, sand control screen, ICDs, basepipe, and production tubing, capital expenditure input, and real time calculations of net present value of the reservoir. The use of inflow control devices increases the capital expenditure, but the increased cost is more than compensated for by the increased production efficiency.The technology presented can be extrapolated and applied to the analysis of well completions consisting of different types of hardware. Future developments of this type of analysis will be described.This work provides three additions to the technical knowledge base of the petroleum industry; 1) use of a lumped-parameter finite-difference based model to couple the wellbore completion to the reservoir, 2) proof of the positive effects of inflow control devices on producing hydrocarbons, and 3) further information on using the "economics of reservoir depletion" to drive horizontal completion designs.

The objective of this paper is to present learnings from designing inflow control devices (ICD) of numerous wells at reservoirs with gas cap with various settings. Key aspects and an efficient ICD design workflow will be presented. The evaluation is based on the application of nozzle ICD for single lateral horizontal well. A synthetic simulation model is utilized to demonstrate example cases. A horizontal well installed with ICD completions improves well performance by equalizing production along the horizontal section to delay water/ gas breakthrough for an oil reservoir with gas cap and aquifer. We utilized an in-house reservoir simulator with advanced complex well options. The first step is to develop an ICD completion design workflow, which includes understanding reservoir permeability heterogeneity, its magnitude and well flow behavior under open-hole completion. At well level, this step is to estimate future major gas and water contribution. Optimum well rate is sensitized for the ICD design. The next step is to focus on ICD design optimization which includes numbers of ICD requirements and compartments, ICD choking. The performance of horizontal well placed under a gas cap was analyzed. An early gas production easily occurs especially for well with high production rate. Controlling gas and water production showed an improvement on oil recovery. We developed the workflow of an ICD completion design optimization for the evaluation. Simulation model with different reservoir properties vertically were created for ICD design case. The ICD design optimization cases with combination of these two factors are evaluated to identify conditions for ICD installation that provide best benefits. Results showed that installation of ICD provides good performance improvement and more even gas oil contact and water oil contact movement toward the wellbore. The ICD design workflow provides a guideline to do the ICD design systematically utilizing reservoir simulation model for an oil rim reservoir. Learnings obtained from the results provide an understanding on the optimal conditions for ICD installation with the goal to ultimately deliver long-life wells while controlling water and gas production in different levels of reservoir heterogeneity and well lengths.

The goals of reducing excess water production appear challenging. An inflow control device (ICD) is completion hardware that is included as a part of a downhole completion across the reservoir section and that helps in distributing the inflow evenly. Production logging after the installation of ICDs can be performed to determine the flow profile and understand the downhole productivity to help with future development, and calibration of reservoir model. However, evaluating fluid flow through these complex completions with the presence of emulsion could include uncertainties. Two investigations were conducted in two emulsified horizontal wells that were ICD-completion oil producers. The presence of downhole emulsion during the operations was limiting the identification of the downhole flow rates of both oil and water. In the first example, three horizontal production logs (HPLs) were acquired before and after the ICD installation. The initial two acquisitions were to monitor and support the ICD completion design, respectively. Challenges encountered in the third horizontal production logging tool (HPLT), deployed by tractor, required evaluating the adaptive ICD performance and closing the ports that are producing water. To minimize chances of emulsion, flowing data were acquired at high, medium, and low choke settings. This was observed by electric-probe water detection and the separation of minispinners with well deviation at lower choke sizes. The other logging operation was an attempt to acquire an inflow profile along the length of 3,000 ft in the horizontal well. Due to the presence of emulsion, three-phase holdup and water-flow logs from the pulsed neutron logging tool (PNLT) were integrated with the production log to appraise the ICD performance and identify the water entry zones. Each of the investigation actions were interpreted independently before combining the data to conclude the results. The presented production logging techniques solved challenges in horizontal wells. The solution focused on reducing the requirements for evaluating complex emulsified boreholes completed with ICDs, with the goals of restoring and maximizing production, saving the operator time and money for complex interventions, and getting the maximum return on investment.

The first horizontal oil well was drilled through an anticline structure in the Block-7E of East Flank, S-field, penetrating three production sands Sand I, Sand II and Sand III. Based on a comprehensive pre-drill study through steady-state and 3D dynamic time lapse simulation, Inflow Control Device (ICD) with integral sleeve (on/off function) attached to the ICD's joint is the optimum development of the fault block that maximizes zonal control for contrasting water encroachments. Due to the unconsolidated nature of the target reservoir, this well is designed for Open-Hole Gravel Pack (OHGP) with specialty 3D filtration screen to manage sanding issue. This paper highlights 2-in-1 application of ICD with enabled zonal shut-off sleeves and the OHGP completions with external screen. A pre-drilled ICD dynamic modeling is constructed to evaluate the well performance with ICD configuration. The design criteria for an optimum ICD design configuration is based on number of compartments and size, packer placement, ICD nozzle sizes and numbers. This dynamic single well model was used to justify the technology value which resulted in production improvement (maximizing oil and minimizing/delaying water). However, during the drilling of this well, the pre-drilled model is then updated in real time with the input of actual petrophysical data from Logging While Drilling (LWD) measurements along the OH section. Actual well trajectory and structure adjustment encountered while drilling were also co-utilized to determine the final optimum ICD design for the field run-in-hole (RIH) completion. Target fault block in S-Field East Flank requires optimum development strategy for its economic viability (Kumaran, P. N et al. 2017). Only one open-sea discovery well proved the oil bearing sands to-date, but a lot of uncertainties remains: geological structure, fluid contacts, fluid characterization, existence and nature of an aquifer, etc. Hence, all these uncertainties are incorporated in the ICD optimization through sensitivity analysis and uncertainty range estimation. Oil production improvement with water reduction while delaying water encroachment are key in the optimization of the ICD design, which is achieved by evaluating the impact of ICD's influx balancing throughout the horizontal section. Study shows that water encroachment is effectively controlled with 9 compartmentalization zones along the horizontal section, each one separated using oil swellable packer. After 7 months of stable flow, well test is showing zero-water and zero-sanding to surface with well controlled production rate that can produce more if required. This is the testimonial of the deployment success from its initial conceptual design to its ultimate completion.

This paper describes the use of advanced completions employing passive inflow control devices (ICD) and autonomous inflow control devices (AICD) in multi-zone horizontal wells to improve the distribution of gas injection and to restrict premature production of gas in gas injection soak EOR process for unconventional oil wells. The recovery efficiency of unconventional oil reserves is very low due to the micro-permeability of these reservoirs and rapid depletion of pore pressure proximal to the fractures and wellbore. Several enhanced oil recovery schemes have been proposed to stimulate production and increase recovery efficiency in these reservoirs by injecting gas or carbon dioxide in fracture stimulated, long horizontal wells, and either producing oil from adjacent wells (gas injection flooding drive mechanism), or by back-producing the injectant and reservoir fluids in the same wellbore after a suitable "soak" period (huff and puff). The effective distribution of the injected gas in these wells and the ability to keep the gas in the reservoir to maintain energy can greatly affect the recovery efficiency that can be achieved. Advanced completions utilizing appropriately designed ICDs and AICDs can enhance the performance of these EOR schemes. ICDs can be used to balance the distribution of gas injection along the length of the wellbore, while AICDs can help control the early back-production of gas. The Autonomous Inflow Control Device (AICD) is an active flow control device that delivers a variable flow restriction in response to the properties (viscosity) of the fluid flowing through it. Water or gas flowing through the device is restricted more than oil. When used in a horizontal well, segmented into multiple compartments, this design prevents excessive production of gas after breakthrough occurs in one or more compartments. The implementation of advanced completions in EOR applications has been studied by reservoir and well performance simulation. This proper use of ICDs and AICDs in these applications can significantly improve recovery efficiency without further well intervention. To evaluate the performance of the AICD, a comprehensive multi-phase flow model of the autonomous performance has been developed and workflow created for simulation of performance within the reservoir. This paper will describe the experience with the technology and modelling prediction for EOR projects.

High water production is a major issue in horizontal oil wells, especially in longer laterals, because of the high drawdown from the heel to toe. In addition, the presence of heterogeneity along the lateral section can lead to uneven sweep of hydrocarbons which can result in poor recovery. To control the water production and achieve better sweep efficiency, ICDs have been introduced which balance fluid flux along the producing horizontal well. This paper discusses the feasibility and results of using integrated technologies such as ICDs along with rotary steerable drilling systems (RSS) and azimuthal logging while drilling well placement technology to achieve higher reservoir sweep efficiency. This case study is focused on a Gulf of Mexico (GoM) shelf horizontal well which was completed with prepacked screens. The well was sanded in and plugged after five years of high water production. A saturation log was run in the offset well which granted the viability to revisit this reservoir. Consequently, a new offset horizontal well was proposed and drilled next to the existing well to sweep out remaining reserves. For the new offset well, full field dynamic simulations were performed to evaluate attic placement methodology and optimization of Inflow Control Devices (ICDs) into the integrated design. The results illustrate that attic horizontal well placement is feasible using integrated drilling with ICD technology to maximize the sweep efficiency.

Raudhatain field located in North Kuwait produces hydrocarbons from over 230 wells into Gathering Center X with varying complex geometries, completions and downhole equipment. NK asset team is executing a project of modeling the entire NK production system starting with wells in Raudhatain field producing to GC-X, involving building models for the wells and the gathering surface network of flow lines. There are numerous challenges that the NK asset team is facing in meeting production targets, including controlling water/gas breakthrough in horizontal wells. Mitigation measures include installation of inflow control devices (ICDs). Since inception a decade ago this proven technology has long been used in many oilfields around the world and is increasingly being installed in horizontal wells in Kuwait. To date there are several horizontal wells in Raudhatain field completed with ICDs. Reservoir modeling and simulation approach is frequently used in the industry capturing the behavior of existing ICD wells. This approach uses conventional modeling tools that are typically more intricate and require expert skills in capturing the dynamic behavior of the wellbore and the reservoir which is less appealing to the operations and practicing engineers. Limited with time and resources in this project, the NK team took a relatively simpler and fast approach in modeling existing ICD wells in Raudhatain field with the aim of enabling the engineers to capture the behaviour of the wells using existing production engineering tools at their disposal. The approach can be summarized as follows: ➢Establishing the well performance➢Modeling the individual ICD sections in accordance to the approximate flow distribution/geometry along the horizontal well➢Matching the well with well test data Key benefits of this approach are: ➢Enabling the engineers to quickly model the ICD wells.➢Facilitated the use of existing tools to deliver engineering models fit for use in the production system.➢Serves the purpose of high level modeling of complex ICD wells and in the future this exercise will certainly be undertaken to capture wellbore hydraulic effects.➢ICD well models are timely added into the gathering network which would otherwise have been delayed using a conventional method.

Heavy oil reservoirs cover up 2/3 of the world's hydrocarbon reservoirs.When heavy oil is produced through horizontal wells with water drive, a water breakthrough is expected.Conventional inflow control devices (ICDs) can only delay a water breakthrough.The disadvantage of ICDs is the inability to control the water inflow, after the water breakthrough.Autonomous inflow control valve (AICV) is designed to choke or stop the inflow as soon as the water breakthrough occurs.To evaluate the performance of AICVs OLGA-Rocx simulations were conducted.Simulations show that the AICVs have a superior potential in limiting the water inflow to the base pipe (86% reduction in water accumulation compared to normal ICDs).AICVs are more effective in heterogeneous and fractured reservoirs as it can restrict the early water breakthrough.In homogeneous reservoirs, AICVs' function reduces oil production rate compared to the ICD system, however, the lifetime of the well is increased.