Segmented Well Completion for Non-Condensable Gas Management
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Solution Overview
Problem
Conventional hydrocarbon production methods face challenges in maintaining reservoir pressure and controlling gas production during ramp-down and blowdown phases, leading to inefficient operations and potential pressure imbalances between adjacent reservoir areas.
Innovation Solution
The method involves configuring production wells with spaced fluid-inlet components to segment drainage fluids into semi-localized zones, prioritizing hydraulic communication with low gas-content zones and modulating pump speed to manage gas and liquid phase ratios, thereby retaining non-condensable gas within the reservoir and maintaining oil production rates.
Engineering Contradictions & Design Principles
Engineering Contradiction Analysis
1Stress or pressure
If non-condensable gas is injected into the reservoir during ramp-down and blowdown phases, then reservoir pressure is maintained and residual hydrocarbons are recovered, but unwanted gas incursion increases and control over gas phase:liquid phase ratios is lost
Solution Approach 1:
The production well completion is segmented into multiple independently controllable zones using inflow control devices (ICDs) positioned at different depths. Each zone can be individually activated or deactivated, allowing selective production from zones with favorable gas:liquid ratios while isolating zones experiencing unwanted gas incursion. This segmentation enables precise control over which reservoir regions contribute to production during ramp-down and blowdown phases.
Solution Approach 2:
Different zones of the production well are assigned different operational characteristics based on local reservoir conditions. Zones experiencing high gas incursion are restricted or shut in, while zones with favorable liquid production are prioritized. This local differentiation allows the system to maintain overall pressure support from gas injection while locally managing gas:liquid phase ratios to prevent harmful gas dominance in the produced fluid.
2Device complexity
If conventional production-well completions are used during ramp-down and blowdown, then simple well configuration is maintained, but control over gas phase:liquid phase ratios is lost and high gas-content fluids cannot be managed
Solution Approach 1:
The well completion system incorporates dynamically adjustable inflow control devices that can be remotely operated to change their flow characteristics in response to real-time production conditions. This dynamic capability allows operators to adapt the well's gas:liquid phase ratio control to changing reservoir conditions during ramp-down and blowdown, transforming a static completion into an actively managed system that responds to operational needs.
Solution Approach 2:
The system employs monitoring of produced fluid composition and reservoir pressure to provide feedback on actual gas:liquid phase ratios. This information feeds back to operational decisions regarding ICD positioning and pump rate adjustments, creating a closed-loop control system that continuously optimizes phase ratio management based on actual performance rather than relying on fixed, pre-determined well completion configurations.
3Productivity
If pump speed is increased to maintain oil production rates, then production-flow rate is maintained, but gas production increases and liquid phase:gas phase ratio deteriorates
Solution Approach 1:
By segmenting the production well into multiple zones with independent flow control, the system can selectively produce from zones that are currently providing favorable liquid:gas ratios. When pump rate increases cause gas incursion in certain zones, those specific zones can be restricted via ICDs while maintaining production from other zones, thus maintaining overall oil production rates without proportionally increasing gas production.
Solution Approach 2:
The system changes operational parameters dynamically - specifically adjusting the effective permeability to gas versus liquid in different zones through ICD positioning, and adjusting pump rate based on real-time phase ratio monitoring. These parameter changes allow the system to maintain productive oil flow rates while shifting the balance toward liquid phase production by restricting gas-prone zones and optimizing pump operation within the constrained phase ratio envelope.
Applied Scientific Principles
This section explains which scientific principles are used to turn an abstract innovation direction into a practical engineering solution.
Function Achieved in This Case
This approach allows for greater control over non-condensable gas production, maintaining or improving oil production rates while maintaining favorable liquid to gas ratios, thus enhancing recovery metrics and avoiding pressure imbalances between reservoir areas.
Implementation Method 1
producing a production fluid at a production-flow rate via a pump
Data Source
AI summary
Methods for producing hydrocarbons from subterranean reservoirs utilize a production well having a plurality of individually-actuatable fluid-inlet components that are spaced apart to define a plurality of production-well fluid-inlet zones. An injection fluid including a non-condensable gas (NCG) is injected into the reservoir, such that a drainage fluid including at least a portion of the NCG occupies the production-well fluid-inlet zones. The gas phase:liquid phase ratio of a production fluid is modulated by identifying at least one of the production-well fluid-inlet zones as having a gas content above a threshold and thus being a higher-gas zone, and actuating variations in pump speed and the flow states of the plurality of fluid-inlet components adjacent and corresponding to the higher-gas zone to prioritize hydraulic communication with a subset of the plurality of production-well fluid-inlet zones spaced apart from the higher-gas zone.