Subsea Membrane Gas Separator for CO2 Reinjection
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Solution Overview
Problem
Conventional methods for removing sour gases like CO2 and H2S from natural gas in offshore oil fields are inefficient and require significant equipment, leading to high energy consumption and emissions, and are not designed to handle the high concentrations of CO2 that result from CO2 flooding operations, which limits the commercial use of CO2 injection for enhanced oil recovery (EOR) in offshore environments.
Innovation Solution
A subsea fluid processing system that includes a pressure control device, a gas-liquid separator, a membrane separator, a compressor, and a discharge cooler, which separates and compresses the gas stream, then cools it to a higher density for reinjection into the reservoir, avoiding the need for extensive topside equipment and reducing the risk of hydrate formation.
Engineering Contradictions & Design Principles
Engineering Contradiction Analysis
1Manufacturing precision
If conventional amine absorption separation is used to remove sour gases, then the product gas meets requirements for CO2 content and heating value, but the equipment dimensions become very large (contactor columns up to 5 meters diameter and 30 meters height, stripper columns of similar size) and energy consumption for solvent recovery becomes high
Solution Approach 1:
The patent uses thin film membranes with selective polymer coatings to separate CO2 from natural gas. These membranes are orders of magnitude thinner than conventional absorber columns, reducing equipment volume dramatically while maintaining separation effectiveness. The selective polymer layer allows CO2 to permeate through while retaining methane, achieving the required product gas composition without large-scale equipment.
Solution Approach 2:
The invention changes the separation mechanism from chemical absorption requiring large contactor columns to physical permeation through thin films. By operating at different pressure conditions (high pressure on feed side, low pressure on permeate side) and utilizing the selective permeability parameter of the membrane material, the system achieves efficient CO2 removal with compact equipment dimensions.
2Manufacturing precision
If conventional amine absorption separation is used to remove sour gases, then the product gas meets requirements for CO2 content and heating value, but the energy consumption for solvent recovery becomes high
Solution Approach 1:
The patent replaces the thermal-mechanical solvent recovery process (heating and flashing in stripper columns) with a purely mechanical pressure-driven permeation process. The membrane separator uses pressure differential to drive CO2 through the selective film, eliminating the need for energy-intensive thermal regeneration of solvents while maintaining product gas quality specifications.
Solution Approach 2:
The invention changes the separation mechanism from thermal-driven chemical absorption to pressure-driven physical permeation. By operating the membrane system at appropriate pressure differentials without requiring thermal energy input for solvent regeneration, the system achieves significant energy consumption reduction while meeting product gas composition requirements.
3Productivity
If CO2 is injected into offshore oil reservoirs for enhanced oil recovery, then oil recovery is improved, but the high concentrations of CO2 from flooding operations cannot be handled by conventional gas processing equipment designed for onshore facilities
Solution Approach 1:
The patent employs thin film membrane separators that are inherently adaptable to varying gas compositions including high CO2 concentrations. These flexible membrane systems can be configured in modular arrangements to handle the specific high CO2 load from flooding operations, unlike rigid conventional equipment designed for lower CO2 concentrations typical of onshore facilities.
Solution Approach 2:
The invention segments the gas processing function into modular membrane separation units that can be scaled and configured to handle high CO2 concentrations. Rather than requiring a single large conventional processing facility with limited adaptability, multiple membrane modules can be arranged in series or parallel to accommodate the specific CO2 loading from offshore flooding operations.
4Quantity of substance
If gas is compressed and cooled for reinjection into subsurface reservoirs, then the density of the gas increases for efficient injection, but hydrate formation risk increases in subsea environments
Solution Approach 1:
The patent performs preliminary CO2 separation and compression at subsea pressure conditions before the gas enters the cooler. By pre-compressing the CO2-rich stream to high pressure (matching reservoir conditions) before cooling, the system achieves high density for efficient injection while controlling the cooling process to avoid temperature ranges that would promote hydrate formation in the presence of water.
Solution Approach 2:
The invention carefully controls the pressure-temperature parameters during compression and cooling to navigate around the hydrate formation region. By maintaining the gas temperature above the hydrate formation point at each pressure stage, or by using inhibition strategies, the system achieves the required high density for efficient reservoir injection while preventing harmful hydrate formation in the subsea environment.
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 system enables efficient separation and reinjection of CO2 into offshore oil reservoirs, reducing the need for external CO2 supply, allowing for widespread use of CO2 EOR, and achieving over 95% CO2 removal from well streams, while preventing hydrate formation and maintaining flow stability.
Implementation Method 1
a membrane separator adapted to receive the gas stream and provide a retentate stream and a permeate stream
Implementation Method 2
a compressor adapted to receive the permeate stream and provide a compressed permeate stream
Implementation Method 3
a discharge cooler adapted to receive the compressed permeate stream and provide a cooled permeate stream for injection into a subsurface reservoir
Data Source
AI summary
A subsea fluid processing system which receives a wellstream flow. The subsea fluid processing system includes a pressure control device which regulates a pressure of the wellstream flow, a gas-liquid separator unit which receives the wellstream flow downstream of the pressure control device and which provides a liquid stream and a gas stream, a first membrane separator which receives the gas stream and which provides a retentate stream and a permeate stream, a compressor which receives the permeate stream and which provides a compressed permeate stream, and a discharge cooler which receives the compressed permeate stream and which provides a cooled compressed permeate stream for injection into a subsurface reservoir. A density of the cooled compressed permeate stream is higher than a density of the compressed permeate stream.