This paper describes the deployment of Autonomous Inflow Control Valve (AICV) technology in an oil producing well affected by gas breakthrough, to reduce gas production and increase conformance. Based on the fluid properties, AICV differentiates the fluid flowing through it and can autonomously choke / shut off gas inflow from the high gas saturated zones, while allowing oil production from healthy oil-saturated zones. The subject oil producing well has open hole section of over 3200ft. A multidisciplinary data integration of well logs, production history, and subsurface geological description is considered for modelling and designing optimum AICV completion. The main objective is to restrict the gas breakthrough to a smaller compartment, allowing other compartments to produce at higher oil production. The AICV completion was run with a remote actuated shoe to enable fluid circulation from the end of downhole completion string while run-in-hole. AICV technology allows pro-active reservoir management. It shuts-off the gas at subsurface level autonomously, without any intervention. Due to the chocking effect, AICV allows sustain the well production within the reservoir management guidelines, with improved well availability and reducing the operating expenditures. This has an additional positive impact on the environment due to reduction of gas flaring as AICV is expected to reduce the gas production/GOR by 81% This paper discuss in detail how the AICV completion offered a technically attractive and cost-effective gas management and production optimization opportunity. Futures implementation of this solution will improve Miscible Water Alternating Gas (MWAG) injection efficiency and gas recycling in addition to reducing the carbon footprint per barrel of produced while sustaining production.
Maximum Reservoir Contact (MRC) drains have been introduced and implemented as an attractive solution in reservoir developments to accelerate production/injection while optimizing the development costs. The main objective of this paper is to provide a workflow to assess the optimum well length (Lopt) and MRC wells evaluation. In addition, it aims to highlight the factors affecting actual Effective well length (Leff) based on a study performed on a giant oil field and the planned execution plans to mitigate wells with poor effective well length. A new approach is proposed to predict the optimum well length based on the proportionality of flux rates and productivity index (PI). The approach uses steady-state well modelling packages built using the static well data such as trajectories, reservoir/fluid properties, vertical and lower completion tuned with dynamic data such as surface well test data and downhole P& T measurements. Output results are oil influx rates along the trajectory, PI and production profiles. For the sensitivities, an automated well model base calculation was implemented through an Excel-Macro to facilitate performing different realizations of wellbore design, permeability ranges, and tubing sizes. Next, the evaluation of horizontal wells was assessed utilizing surveillance tools with the integration of the several factors affecting the effective well length. Prior to implementing MRC drilling, the asset team must assess the optimum well length (Lopt) for their reservoir settings where a certain limit for horizontal section indicates an increase in frictional losses and increment (Q, PI) is no longer favorable. Theoretical models indicate productivity and rates proportionality with horizontal length. While field case evidence of wells surveillance show effective length is rarely 100%. The findings proved the tool's efficiency to predict Lopt with the capability to reduce simulation runs/efforts for multiple scenarios. For the studied reservoirs, the Lopt was inferred to be in the range of 9000 up to 16,000 ft depending on the permeability, fluid properties, completion size and surface back pressure. Tubing diameter size was found to have a major influence on the flux rate, while wellbore diameter had a negligible impact. The workflow assessment on field studies with average conventional wells and MRC wells length of 1800 ft-10,000 ft inferred significant factors affecting actual well effective length to be: Well placement (Porous/dense), Heel-toe effects, Damage while drilling, production/Injection rate, Barefoot vs. completion, acid Stimulation after drilling, Well accessibility due to hole condition and production rate limits (Spinner threshold). The tool will help in the preliminary assessment to decide the optimum well length for the MRC, considering the reservoir settings and multiple completion options. In addition, the application can be extended to integrate with dynamic simulation as a robust tool to optimize completion design to be fit for future conditions. Furthermore, the field case set a generic workflow for confirming factors that may impact the Leff and evaluate MRC performance.
An onshore gas field contains several gas wells which have low–intermittent production rates. The poor production has been attributed to liquid loading issue in the wellbore. This study will investigate the impact of optimizing the tubing and liner completion design to improve the gas production rates from the wells. Numerous sensitivity runs are carried out with varying tubing and liner dimensions, to identity optimal downhole completions design. The study begins by identifying weak wells having severe gas production problems. Once the weak wells have been identified, wellbore schematics for those wells are studied. Simulation runs are performed with the current downhole completion design and this will be used as the base case. Several completion designs are considered to minimize the effect of liquid loading in the wells; these include reducing the tubing diameter but keeping the existing liner diameter the same, keeping the original tubing diameter the same but only reducing the liner diameter, extending the tubing to the Total Depth (TD) while keeping the original tubing diameter, and extending a reduced diameter tubing string to the TD. The primary cause of the liquid loading seems to be the reduced velocity of the incoming gas from the reservoir as it flows through the wellbore. A simulation study was performed using the various completion designs to optimize the well completion and achieve higher gas velocities in the weak wells. The results of the study showed significant improvement in gas production rates when the tubing diameter and liner diameter were reduced, providing further evidence that increased velocity of the incoming fluids due to restricted flow led to less liquid loading. The paper demonstrates the impact of downhole completion design on the productivity of the gas wells. The study shows that revisiting the existing completion designs and optimizing them using commercial simulators can lead to significant improvement in well production rates. It is also noted that restricting the flow near the sand face increases the velocity of the incoming fluid and reduces liquid loading in the wells.
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