Autonomous inflow control devices (AICDs) have recently been introduced in the petroleum industry to restrict the production of unwanted fluids, namely water and gas, much more effectively than conventional inflow control devices (ICDs). As with ICDs, AICDs are installed downhole along the completion string to first delay water/gas coning and then restrict their influx, without well intervention, if/when coning such occurs. Unlike ICDs, AICDs selectively choke back water and gas significantly more so than oil. A novel cyclonic AICD was recently developed using computational fluid dynamics (CFD) driven design optimization. The cyclonic AICD's unique internal geometry increases the flow resistance to unwanted fluids based on how their viscosities and densities differ from oil, as initially predicted using CFD and subsequently validated by extensive, carefully controlled single- and two-phase flow tests. The resulting excellent match obtained between CFD and such laboratory tests yielded accurate mathematical models for predicting flow performance over a broad range of flow rates and oil, water and gas properties. The flow performance models were then incorporated into a state-of-the-art dynamic reservoir simulator with multi-segmented wellbore capability to compare the production performance over time for the same well but completed with no ICDs, conventional ICDs, and cyclonic AICDs. A synthetic but realistic three- dimensional (3-D) reservoir model has used that allowed oil, gas and water production. Multiple sensitivity runs were initially performed to optimize the number of compartments using packers for annular isolation, and the number of ICDs per compartment. Once these parameters were optimized, only the ICD type was varied for performance comparison. The results of this systematic, multi-step process, as presented herein, demonstrate that the cyclonic AICD adds significant value to the improvement of oil production by controlling unwanted fluids, such as water and gas, and by preserving the reservoir energy.
Extended Reach Drilling (ERD) wells can be extremely long and technically challenging from drilling through completions, clean up, stimulation and production optimization. This paper will focus on the key challenges associated with ERD well completion, real-time clean up, production monitoring and optimization and will present an advanced intelligent solution enabled by new technologies to handle these complex challenges. As the fields become more mature, there is an increasing requirement for real time flow profile understanding and interventions to correct unwanted flow profile anomalies such as water production, gas breakthrough, etc. to have better production and reservoir management. By combining real-time data monitoring and active control with optimal zonal isolation along the wellbore has been proven to be one of the most efficient and effective completion strategies in the industry for the abovementioned requirements. The operator can proactively manage production, eliminate or reduce interventions and associated production downtime, well costs and risks. However, getting the invention less permanent intelligent completions to the Total Depth (TD) of ERD wells is one of the major challenges and hence very long horizontal ERD wells are typically completed partially leaving out stretches of reservoir section unmonitored and uncontrolled. Also, conventional intelligent completions have clear limitations on number of flow control valves and sensors that can be deployed in a well, mainly limited by the maximum number of control lines, which can be deployed with the completion. The limitation comes from the feedthrough port limitation of critical completion tools such as tubing hanger, production packer etc. and also from the completion deployment challenges faced with increasing number of control lines. This limits the ability to have an optimal segmentation along the wellbore in many cases. Another important challenge that our industry faces is in effectively using real-time monitoring data to make informed decisions and take required actions efficiently. Traditionally the whole process of data gathering from down hole tools to decision making and taking reasonable action is long ranging from months to years and requires multi-disciplinary expertise. As a result the well controllability, reservoir management and hence production optimization are compromised due to technology solutions limitation. New all electrical solution with reliable downhole wet connects and integrated answer product software for data management and analysis of real-time data presented here is a key intelligent end to end solution. This paper gives details of this new generation technology solution that enables above mentioned challenges.
A study was conducted to determine the optimum re-completion for an offshore Abu Dhabi well. The candidate well was completed as open hole in a complex carbonate reservoir with faults and fractures and suffering from rapid increases in water cut. To quantify the value of re-completing the well with ICDs completions, a dynamic simulation modeling and optimization workflow was applied. To evaluate the best completion design, the dynamic model was refined and history matched in the sector area of the well using multi-segmented well technique. The number of downhole compartments (sections between packers), location of packers and ICDs flow area were simultaneously optimized to determine the best completion options for the candidate well using an objective function that included both; the value of oil and the cost of water. The ICD flow area per compartment was reverse engineered into an appropriate number of ICD joints and set of nozzles as part of the completion design process. The workflow provided a quantitative method for choosing the most appropriate horizontal well completion and demonstrated significant value for installing downhole flow control devices. The presentation of the results in terms of oil gain and water reduction for the different objective functions provided a clear indication about the best completion options, depending on the cost or aversion for water production versus the value of oil.
The paper presents successful installation of Permanent Downhole Gauges (PDGs) and Distributed Temperature Sensing (DTS) technologies for the first 13 wells, data transmission method of gauges data via mobile network and application used to receive and store the data with visualization software in an Abu Dhabi giant offshore field. As a part of the plans to increase production and reserves recovered from the field, extended reach wells are planned to be drilled off four artificial islands. The project includes a series of oil producer wells along with water injectors. Gas lift will help to sustain the production level after the initial period of natural flow. During the planning phase, it was identified that efficient management of gas lift operations can be achieved through DTS. In addition, 2 single-point pressure and temperature data points from PDGs were to be acquired to assist in reservoir management efforts and calibration of the DTS. The solution provided for each well was to deploy tandem high resolution tubing pressure and temperature gauges run on a hybrid permanent downhole cable containing tubing encapsulated conductor (TEC) plus fiber optics for DTS. The hybrid cable serves as a power and communication line to the gauges installed above the production packer at measured depths varying from 10,000ft to 20,000ft as well as providing distributed temperature measurements across the upper completion through a multi-mode fiber. The temperature data will be used for gas lift operations surveillance and optimization. An additional fiber is installed for distributed acoustic sensing for future well integrity surveillance purposes. As of August 2015, the first 13 wells have been installed successfully in the field with PDGs and Fiber Optic monitoring. The gauge data (pressure and temperature) is planned to be delivered through a GSM network transmission system into the onshore office node at the operator headquarter (HQ). The focus has been on integration of different components of surface system like Data Acquisition Unit, Remote Terminal Unit (RTU), GSM Modem, Virtual Machine (server located in the onshore office) and fully customized Human Machine Interface (HMI) software. The new approach allows for continuous real time monitoring of data at the HQ and taking necessary actions in a timely and efficient manner. Initial stage of project implementation has shown successful results with all PDGs and Fiber Optics operational in all wells and improved execution efficiency of field installation. Well completion designs are planned to continue with the same gauge and fiber optic design for the duration of the field development.
The durability of sand screen completions is essential to longer well life, especially for high rate wells with sand screen erosion concerns. An excessive fluid flow enters the conventional screens near the heel or high permeability/fracture zones, causing premature sand control loss. The high rate screens with a simulation-driven approach address this concern by achieving the annulus-to-tubing flow equalization and reducing the influx spike near the heel or high permeability/fracture zone. The study presents a comprehensive modeling approach including a single-well model workflow for initial production screening along the wellbore with different reservoir conditions, which provides input to the novel multiscale 3D-2D-3D computational fluid dynamics (CFD) modeling technique to design or validate high-rate completions for the specific operating conditions. The principle of operation is based on equalizing the production influx along the screen by achieving the distributed inflow control devices (ICD) effect on the basepipe. The modeling approach was used to compute maximum local velocities in the vicinity of the screen near the heel under 39,000 RB/D of ultra-light oil production in one case and 200 MMscf/D of gas production in another. The design methodology is validated through erosion and sand retention tests performed to verify the screens’ correct slot/gauge size. The high-rate completion case history consists of seven deepwater wells with chemical tracers. The novel design and the modeling methodology are validated by physical erosion tests and verified through field installations.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
customersupport@researchsolutions.com
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.