Inflow control devices (ICD) completion is a downhole flow control solution that is designed to balance influx contributions across wellbore horizontal section, to delay water breakthrough or coning hot-spots and to increase ultimate cumulative oil recovery. This paper illustrates a novel and successful systematic workflow to implement this technology in order to effectively manage the marginal green reservoir uncertainties while achieving field development requirements. In general, this production-upsides justification and design process started from an early stage full field ICD completion feasibility study; followed by single well pre-drill ICD design through dynamic simulation as preparation for real time drilling operation support. Subsequently, ICD nozzle-configuration optimization and packer placement design fine-tuning were performed before run in hole during real time operation. The final optimized design for ICD and tracer tally can then be proposed for on-site execution. The key enabler of this process is a novel and time-efficient single well dynamic simulation method, which is compiling the dynamic time-lapse production responds with various ICD nozzle and packer design optimisation workflow. The sensitivities of various design scenarios were applied as a working range to guide on-site ICD installation. This paper highlight the design and optimization workflow from the perspective of dynamic modeling against the conventional nodal-based or single time-step production scenario simulation carried out. In illustrating the more ‘down-to-earth’ production upside results when time-lapse impact are considered, single well dynamic modeling can provide a more realistic real-time design especially in marginal oilfield application and critical decision-making during real-time. Against the typical over-optimistic production upsides analysis result portrayed by conventional single time-step production scenario simulation, some actual design cases as conservatively predicted by dynamic modeling single well will be demonstrated to influence decision-making when ICD's upsides is marginal . This crucial differentiation in due dilligence upside analysis will guide towards most optimal ICD's configuration RIH or reciprocally applying standalone screen (SAS) instead against the ICD's RIH minimal production benefits against its cost value. The results showed that the uncertainties and production repercussion that are affecting the decision of either running ICD's or SAS during real-time ICD's modeling updates are handled more inclusively and objectively with time-lapse based dynamic prediction.

This work is put in perspective by mentioning some of the applications of butterfly throttle valves and explaining how the next tests are complementary to other work (1). The present tests examine the flow characteristics of a butterfly throttle valve in relation to valve opening, pressure ratio and circumferential and axial location of the pressure tappings. The paper gives results of a comprehensive series of steady flow tests and, also, results of a limited number of unsteady flow tests. In the latter, the butterfly throttle valve was located in the intake system of a single cylinder diesel engine. The paper highlights the importance of the position of pressure tappings when pressure measurements are used to estimate flow rates. The results of the present study show that when suitable precautions are taken the quasi-steady flow method may be used to predict the flow rates under pulsating conditions.

The "M" field is located offshore East Malaysia, with a major lateral fault separating the field into North and South. The south area main reservoirs are I, K and L with strong water drive and highly unconsolidated formations. These reservoirs contain approximately 200 MMSTB STOIIP with a current recovery factor of 24%. The major challenges in this field are (1) high well deviation, (2) sand production and (3) early water break-through. In order to dynamically mitigate these challenges, a pilot well with intelligent well technology was considered for one of the new highly deviated infill wells which targeted 3 producing zones. A combination of cased-hole gravel-packing and open- hole stand-alone screens (SAS) was installed at the reservoir sections. This Intelligent Completion IC system is equipped with innovative multi-drop hydraulic modules. The first IC system, successfully installed 2 years ago in 2 wells of an offset field pilot, has had a significant impact on production to date. These systems used the conventional control line configuration of an N+1 system, where N = the number of zones to be completed. However, the newly installed IC system provides an engineering solution to reduce the required number of control lines from 4 to only 2 to control 3 zones, i.e. an N-1 control line configuration. This innovative solution was essential to the project to avoid modifications to the wellhead due to the short lead-time before the installation. This solution also reduced the installation time compared to the first edition of the IC system. This paper highlights the screening process for candidate selection and the successful installation of IC system in multi stack reservoirs with gravel pack assembly and also the lessons learned from the full collaboration between the project team and service provider.

Well B-2 is a dual-string producers with Distributed Temperature Sensing (DTS) fiber installed along the long string (i.e. Well B-2L) across the reservoir sections. Each zone comprises of sub-layers. This system enabled the operator to continuously monitor the wellbore temperature across all the producing intervals including gas-lift monitoring, well integrity identification, zonal inflow profiling and stimulation job evaluation. This paper mainly discusses the post matrix acid stimulation job with interpreted DTS and zonal Permanent Downhole Gauge (PDG) data. Well B-2L has been selected for matrix acidizing treatment to improve the productivity due to potential formation damage, proven by the declining production over the years. Prior to the execution of the acidizing job, several conformance jobs such as injectivity test, tubing pickling were performed. This is followed by the main acid treatment and flow back. DTS & zonal PDG data were acquired throughout the operation. A transient simulator model was built incorporating all the reservoir properties including well trajectory and completion schematic to analyze the DTS profile and understand the zonal inflow profiling for each zone post treatment. A baseline temperature was acquired for the geothermal evaluation. The DTS data has been studied according to actual event schedules. Some significant findings are; i) completion accessories effect (feedthru packers) creates temperature anomalies, ii) leak points detected at top producing zone signifies cooling effect due to injected fluid. The main treatment was intended at zone 2 and 3 using nitrified acid. However, leak points at top zone caused bypassed injection into Zone 1 and 2 instead. Fiber optic DTS warmback profiles post main-treatment was analyzed to quantify the fluid intake from sub-layer in each zone. Qualitatively from the DTS-interpreted zonal profiling, the data clearly shows most of treatment fluid is being injected into Zone 1 and 2 with no intakes at Zone 3. Furthermore, warmback analysis confirmed the high intake zones from sub-layers within the main zone based on the permeability contrast. This paper will further discuss the zonal injectivity understanding for improvement from the zonal-inflow profiling evaluation by incorporating DTS, PDG and surface production data.

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.