Modelling and Optimizing Inflow Control Devices

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.

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.

Summary An inflow-control device (ICD) is completion hardware that is deployed as part of well completions aimed at distributing the inflow evenly. Even though the detailed structures vary from one design to another, the principle for different ICDs is the same—restrict flow by creating additional pressure drop and therefore adjusting wellbore pressure distribution to achieve an evenly distributed flow profile along a horizontal well. With a more evenly distributed flow profile, one can reduce water or gas coning, prevent sand production, and solve other drawdown-related production problems. In general, ICDs are not adjustable; once installed in the well, the location of the device and the relationship between rate and pressure drop are fixed. This makes the design of a well completion and ICDs extremely critical for production. ICDs can be either beneficial or detrimental to production, depending on the reservoir condition, well structure, and completion design. Realizing that reservoir conditions will change during the life of a well, the impact of an ICD is a function of time. Reservoir heterogeneity and uncertainty can complicate the situation easily. The ICDs sometimes can be overlooked if the design is based only on reservoir flow simulations at initial conditions. In this paper, we will investigate how and when an ICD should be used. An integrated analysis method of inflow (reservoir) and outflow (wellbore) is used to generate the flow profile of a horizontal well, and additional frictional pressure drop created by ICDs will be considered. Two conditions that result in production problems, wellbore pressure drop and reservoir heterogeneity, will be addressed. The focus will be on when and how an ICD can optimize production. Examples will be used to illustrate that it is critical to understand the reservoir conditions and wellbore dynamics together when designing a well completion with ICDs. The observations from this study show that overdesigned ICDs will not just increase the cost of well completion, but also will impact the well performance negatively. ICDs are not a universal solution of production problems. The application requires a thorough understanding of long-term reservoir behavior and upfront reservoir characterization for implementation.

Horizontal wells drilled in heterogeneous reservoirs present several challenges for reservoir management. Issues like early water breakthrough and inefficient drainage around the well in a reservoir with high contrast in permeability are very common in horizontal wells. An effective approach to address the challenges of horizontal wells and to increase the oil recovery is to complete the wells with inflow control device (ICD) technology. Most ICD technologies available in the market are passive inflow control devices that do not have the ability to change properties when unwanted fluids break through. The new ICD not only incorporates the benefits of passive ICD technology, it also incorporates sliding sleeves in the module that can be closed whenever the ICD starts producing water. This helps maximize the oil production from the well and reduces the problems related to handling of water at the surface facilities. This paper will demonstrate the effectiveness of the new hybrid ICD design. It is novel viscosity insensitive and may provide higher restriction to water over oil, and the successful operation of the sliding sleeve feature through a field case of a well drilled in a carbonate field in Middle East. Bottomhole pressure and weight indication observed through specialized fiber optic-installed coiled tubing confirmed the operability of technology by proper opening and closing of sliding sleeve. A fluid flow profile recorded by a production logging tool (PLT) on the same CT proved that the completion effectively equalized flow along the wellbore and will delay eventual water breakthrough while still producing at the desired production rates. PLT proved that the custom-designed completion with its appropriate number of compartments, number of ICD joints and flow resistance rating, achieved an optimized ICD completion.

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.

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.

The Midale field, located in Saskatchewan, Canada, is one of the largest water-alternate-gas (WAG) injection operations in the world for enhanced oil recovery (EOR). Wells are normally completed across the three main oil horizons of the Marly formation (M1, M2, and M3), with production from all three zones being commingled. Horizontal producers and injectors are openhole wells, whereas vertical wells are usually casedhole. After years of operation, the WAG injected fluids started to communicate from injectors toward producers, resulting in high water and CO2 cuts and making oil production optimization and recovery more challenging. A new completion was envisioned to improve the oil producers’ rates and overall EOR performance. A casedhole vertical well was selected for upgrading into a new adaptable multiport completion, designed to give independent control of each zone. This new completion was designed considering the challenges of the produced fluids, as well as the interaction between each port, the nozzle size of each inflow control devices (ICD), and the financial impact of producing higher rates under the current (2015–2016) market, which is challenged by low oil prices. The engineering analyses used a steady-state hydraulic well model and a compositional fluid model to consider the impact of the CO2 operating in near critical conditions. Production well tests and laboratory analysis were used to tune the hydraulic well model and the fluid model, respectively. The optimization workflow used the ICD nozzle sizes as decision variables for each port of the new completion, and the financial function, which used reference prices for oil and handling costs for gas and water as coefficients, was maximized by a numerical mixed integer nonlinear programming (MINLP) solver for each case of study. The ICD nozzle sizes were selected for each port of the new completion, based on the hydraulic performance of a series of possible production scenarios, the optimization of the financial function, and the available settings of the ports. This paper presents the results of an integration of production test separator data, production logging test (PLT) surveys, fluid pressure/volume/temperature (PVT) data, equation of state (EOS) fluid models, hydraulic models, and optimization solvers. These data and models enabled engineers to analyze several possible ICD designs to maximize financial gain.

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.

A near-uniform well (production) inflow or (injection) outflow profile delays early water breakthrough and further decreases water cut which results in higher oil recovery. Field experience has shown that wells producing from, or injecting into, multiple layers and/or reservoirs benefit from an Inflow Control Device (ICD) completion's ability to reduce the in/out-flow imbalance along its length. The standard ICD completion design workflow involves selection of the “strength” of the ICD's restriction based on the incomplete knowledge of the reservoir that is available prior to drilling the well with several commercial softwares available for this. However, more complete reservoir data becomes available once the drilled completion zone has been logged and the data analysed. There follows a short period of time during which the engineer must judge whether the planned ICD completion design is “fit-for-purpose” or needs further consideration. The availability of a rapid ICD completion design methodology that does not require access to computationally demanding commercial software would be highly beneficial at this time. This paper presents a workflow which meets the above requirements. It extends our previous analytical approach to ICD sizing to directly relate the uniform-strength ICD completion design to the predicted heterogeneity of the open-hole inflow profile together with the consequent loss in well productivity from the ICD's flow restriction. The workflow combines a series of dimensionless, universal type curves and analytical solutions in a relatively simple and fast process to find the desired ICD design. A new completion design can be made immediately after drilling has been completed to provide the desired level of inflow variation from the latest predicted level of reservoir and fluid inflow heterogeneity determined by a “quick-look” evaluation of the well's log data. The same design procedure can be used to select ICD completion designs that are a compromise between two competing objectives: increasing the uniformity of the inflow profile and minimising the reduction of the well's productivity index that results from the extra pressure losses imposed by the ICDs. Two typical examples of the workflow's application are provided. The first one examines whether it is necessary to change the ICD completion design when drilling problems result in a reduction of the well's completion length. The second example evaluates the impact of the actual reservoir permeability profile being more heterogeneous than originally expected. The workflow's design philosophy was confirmed by commercial numerical simulators recommending the same ICD completion design in both cases. This work extends our earlier analytical approach to ICD sizing. This new ICD completion design workflow can be used by completion design engineers to rapidly analyse uniform-strength ICD completion design options and their consequences on well inflow performance without expensive computational resources. The underlying principles, assumptions and application area of the analytical model are fully discussed in the paper.

Objectives/Scope The Laverda Field is an offshore waterflooded field developed with two long horizontal producers targeting two stacked high quality sandstone units. The oil producer LAV02ST2 is completed with sand screens and Inflow Control Devices (ICDs). Elevated Gas Oil Ratios (GORs) were experienced during start-up, which indicated free gas production downhole, raising concerns over ICD erosion and sand production. While the ICDs have defined operating limits in the presence of single-phase flow, the safe operating range in multi-phase flow conditions was highly uncertain. Given the significant risk of well failure due to erosion, additional bean up was halted pending studies to understand and quantify the erosion risk. Erosion risk was influenced by: the distribution of gas along the well (concentrated vs dispersed inflow), the presence of an open annulus and associated erosion risk due to solids production, and tolerance of the ICDs to higher velocities under three-phase flow. Methods, Procedures, Process Collaboration between subsurface and completions disciplines was required to understand the source of the gas and assess the risk to completions. Initially, production trends were analysed in conjunction with a review of geological data and numerical simulation insights to identify likely sources of gas and which areas within the well were more susceptible to gas exposure. Near-wellbore modelling using NETool® and GAP was undertaken to understand the range of feasible gas inflow scenarios and eliminate scenarios inconsistent with observed production data. The most likely scenario was then used to establish the relationship between total well rate and peak velocities in the ICDs, for a worse-case erosion outcome. To understand the risk of ICD erosion under multi-phase flow and potential for loss of well integrity, Computational Fluid Dynamics (CFD) modelling was conducted on a range of expected production scenarios to establish safe operating limits. Both, ICD slot erosion and housing erosion behaviour was investigated, as a function of peak ICD gas rate/velocity, well liquid rate and well GOR. Results, Observations, Conclusions The CFD study helped to establish a relationship between erosion rate and total downhole rate at reservoir conditions for various production scenarios, thus allowing calculation of erosion over the course of field life. A revised safe operating envelope was recommended for the oil producer in multi-phase conditions that allowed the production rate to be doubled without compromising well integrity. Novel/Additive Information Traditionally, industry physical erosion testing of the ICDs by the vendor is restricted to single-phase, liquid conditions only. Successfully benchmarking the CFD model to the single-phase physical tests allowed quantification of erosion rates in multi-phase flow and establishment of a safe operating envelope over the life of the well.

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.

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

To increase the production and recovery of marginal, mature, and challenging oil reservoirs, developing new inflow control technologies is of great importance. In cases where production of surrounding reservoir fluids such as gas and water can cause negative effects on both the total oil recovery and the amounts of energy required to drain the reservoir, the multiphase flow performances of these technologies are of particular significance. In typical cases, a Long Horizontal Well (LHW) will eventually start producing increasing amounts of these fluids. This will cause the Water Cut (WC) and/or Gas Oil Ratio (GOR) to rise, ultimately forcing the well to be shut down even though there still are considerable amounts of oil left in the reservoir. In earlier cases, Inflow Control Devices (ICD) and Autonomous Inflow Control Devices (AICD) have proven to limit these challenges and increase the total recovery by balancing the influx along the well and delaying the breakthrough of gas and/or water. The Autonomous Inflow Control Valve (AICV) builds on these same principles, and in addition has the ability to autonomously close when breakthrough of unwanted gas and/or water occurs. This will even out the total drawdown in the well, allowing it to continue producing without the WC and/or GOR reaching inacceptable limits. As part of the qualification program of the light-oil AICV, extensive flow performance tests have been carried out in a multiphase flow loop test rig. The tests have been performed under realistic reservoir conditions with respect to variables such as pressure and temperature, with model oil, water, and gas at different WC's and GOR's. Conducting these multiphase experiments has been valuable in the process of establishing the AICV's multiphase flow behavior, and the results are presented and discussed in this paper. Single phase performance and a comparison with a conventional ICD are also presented. The results display that the AICV shows significantly better performance than the ICD, both for single and multiphase flow. A static reservoir modelling method have been used to evaluate the AICV performance in a light-oil reservoir. When compared to a screen-only completion and an ICD completion, the simulation shows that a completion with AICV's will outperform the above-mentioned completions with respect to WC and GOR behavior. A discussion on how this novel AICV can be utilized in marginal, mature, and other challenging reservoirs will be provided in the paper.

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.

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.