Gas production
~10e3
m³/day restored
Combined stabilized gas production across two wells after installation.
How Vermilion Energy restored production from mature liquid-loaded gas wells using Fluidstream multiphase compression.
Vermilion Energy restored two mature Alberta, Canada wells without adding separation-first infrastructure.
Vermilion Energy used a 200 HP gas-driven Fluidstream MC2270 MultiphaseCommander™ to reduce backpressure, manage real multiphase flow, and return two nearly dead wells to stable gas and condensate production.
Performance snapshot
Production recovery, reliability, and simpler field operation.
This was a real Vermilion Energy field deployment, not a controlled test environment. It was deployed at an unmanned Alberta, Canada location with no electrical power, severe liquid loading, rising pipeline pressure, plunger-lift cycling, winter operation, and highly variable gas-liquid flow. The average production recovery was important, but the more difficult engineering requirement was the transient operating envelope: the system had to handle peak instantaneous gas flow near 95e3 m³/day during plunger-lift events and then continue operating as flow tapered toward low-flow or no-flow conditions.
Variable flow
~95e3
m³/day peak gas flow
Peak instantaneous gas flow during plunger-lift events, showing the technology can handle wide variable-flow operating conditions.
Revenue uplift
C$1.5M+
per year
Estimated incremental annual revenue based on field economics and commodity pricing assumptions available at the time of analysis.
Reliability
0
seal leakage
No gland-seal leakage reported and no maintenance reported on the Fluidstream compression system to date.
Root cause engineering
The wells did not run out of hydrocarbons. The flow system could no longer clear liquids.
As reservoir pressure declined, gas velocity fell below the critical transport velocity required to continuously lift water and condensate to surface. Liquids accumulated in the tubing, added hydrostatic head, increased flowing bottomhole pressure, and reduced effective drawdown against the reservoir. The lower gas rate then made liquid fallback worse, creating a self-reinforcing liquid-loading cycle. The wells did not become uneconomic because hydrocarbons disappeared; they became uneconomic because the flow system could no longer unload liquids against the available pressure differential.
Pipeline pressure could rise to about 1200 kPa while Vermilion Energy wanted the wells exposed to approximately 250 kPa to produce effectively. Plunger lift remained useful, but the wells had moved beyond the operating window where cyclic unloading could maintain sustained production. The operating profile created repeated flow transients: pressure buildup, high-rate unloading, liquid and gas surge, tapering flow, and then fallback. Fluidstream’s advantage was the ability to reduce surface pressure while tolerating that unstable multiphase duty.
01
Declining reservoir energy
Lower reservoir pressure reduced gas velocity below the rate needed for continuous water and condensate transport.
02
Liquid fallback and loading
Produced water and condensate accumulated in the tubing, increasing hydrostatic head and flowing bottomhole pressure.
03
Rising line pressure
Pipeline pressure reduced available drawdown, narrowing the pressure window needed for sustained unloading.
04
Production collapse
The wells needed continuous pressure reduction, transient-flow tolerance, and multiphase handling, not another gas-only assumption.
Why conventional systems struggled
Gas-only equipment pushes cost and complexity upstream.
Traditional compression can reduce pressure, but it usually depends on a conditioned inlet stream. In this operating window, liquid slugs, water, condensate, variable gas rates, high instantaneous flow, low-flow tail conditions, and no-flow periods were normal operating conditions, not exceptions. That is why a conventional gas-only design basis would have pushed more equipment upstream before compression.
01
Liquids create mechanical risk.
Conventional reciprocating and screw compressors are vulnerable when liquids enter the machine. Free liquids are effectively incompressible; repeated slugging or hydraulic lock can damage valves, rods, bearings, lubrication systems, seals, and wear components. Even before catastrophic failure, wet gas can destabilize operation and increase maintenance exposure.
02
Separation adds facility burden.
The typical workaround is to install scrubbers, separators, tanks, pumps, heaters, controls, drains, and trucking logistics before compression. That shifts the complexity upstream and can turn a targeted production optimization project into a larger facility build with more footprint, maintenance, permitting, and operating burden.
03
Interventions destroy uptime economics.
If the system stopped long enough for the wells to load again, the operator expected a swabbing rig could be required at about C$15,000 per event. Reliability was therefore central to project viability.
Fluidstream deployment
MC2270 • 200 HP gas drive • Alberta, Canada
The Vermilion Energy location had no electrical power, the wells were deeper than 2400 m, and the producer wanted to avoid new separation equipment. Fluidstream installed a gas-driven MultiphaseCommander™ package that used produced gas as fuel and operated directly on the mixed gas-liquid stream. The package was selected for practical field operation: compact surface installation, no separation-first infrastructure, and autonomous operation in a wet, variable-flow environment.
The wells required more than simple steady-state compression. Peak instantaneous gas flow could reach roughly 95e3 m³/day during plunger-lift events and then taper toward very low flow. Fluidstream technology can handle variable flow rates because the system is designed around changing chamber conditions, liquid-influenced compression behavior, and autonomous response rather than a narrow steady-state gas-only operating point. The equipment had to tolerate peak flow, low-flow tail conditions, slugs, liquid variability, no-flow periods, and winter operation.
Field outcome
Lower backpressure without separation-first infrastructure.
Fluidstream’s multiphase approach addressed the actual field bottleneck: reducing wellhead pressure while allowing gas, condensate, water, and transient slugs to move through the system together.
Instead of designing the site around the limitations of a conventional gas-only compressor, Vermilion Energy used a purpose-built multiphase compression system that supported a simpler pad configuration and lower intervention exposure.
Technology advantage
Patented multiphase compression built for real field instability.
Fluidstream technology is positioned around direct liquid handling, sealed containment, piston-location awareness, and autonomous upset response. In this case, those features mattered because the machine was exposed to liquid slugs, rapid flow-rate changes, pressure variation, and harsh winter conditions. The result is supported by a system architecture designed for wet, unstable, liquid-influenced field operation.
01
Liquid handling inside compression.
Fluidstream’s patented liquid-aware compression logic is designed to manage incompressible liquids and changing chamber conditions in the compression process rather than treating liquid presence as a failure condition that must always be removed upstream.
02
Sealed gland protection and wear visibility.
The gland-seal arrangement separates power fluid from the produced multiphase stream and is paired with electronic wear detection. This supports containment, reliability, maintenance planning, and reduced field burden where leakage or disposal issues would undermine operator confidence.
03
Autonomous upset-condition response.
Piston-location awareness and autonomous controls help the system respond to slugs, solids buildup, ice risk, no-flow periods, temperature changes, changing gas-drive conditions, and rapid swings in production rate with less operator intervention.
Fluidstream’s patent portfolio, including CA2843321C, CA2883283C, US10221664B2, and US11098709B2, supports the engineering behind multiphase compression, liquid-influenced compression response, and field-ready control logic. US11098709B2 is especially relevant to liquid-aware compression response. In this application, the practical value was clear: the patented operating approach helped restore production without a conventional separation-first facility while tolerating the variable-rate behavior created by plunger-lift cycling.
Customer benefits
A production solution, not just another compressor package.
The value came from multiple field benefits working together: recovered production, avoided infrastructure, lower intervention exposure, gas-drive compatibility, autonomous operation, cold-weather suitability, and containment performance.
Reduced dependence on intervention.
The wells moved away from a reactive mode where production recovery depended on intermittent unloading and toward a more stable continuous-production strategy.
No separation-heavy buildout.
Vermilion Energy avoided adding the full suite of extra wellsite equipment normally required to protect conventional gas-only compression from wet, unstable flow.
Gas-drive deployment fit.
Because there was no electrical power on site, the ability to run on fuel gas was a deployment enabler, not just an option.
Variable plunger-lift flow tolerance.
The package tolerated broad swings in gas and liquid rates, including peak instantaneous gas flow near 95e3 m³/day followed by low-flow and no-flow periods.
Winter field viability.
The system operated through harsh Alberta, Canada winter conditions without requiring insulation or heat tracing on the compressor.
Containment and HSE advantage.
The fully contained gland arrangement avoided ongoing leakage and disposal burden, improving field cleanliness and operational confidence.
Technical fit summary
Why MultiphaseCommander™ fit this operating window.
Liquid-loaded wells, rising pipeline pressure, plunger-lift instability, and limited power availability create a difficult operating window. Fluidstream is best suited for applications where the produced stream is mixed, variable, and difficult to condition economically.
Plunger lift
Useful in the right window, but intermittent and pressure-dependent. In this case, liquid
fallback and
line pressure prevented sustained production recovery.
Swabbing
Can unload wells, but it is reactive, costly, and incompatible with a low-touch operating model
when
repeated events are required.
Conventional compression
Can reduce pressure, but generally requires a dry, conditioned inlet stream and supporting
equipment that
adds cost, footprint, and maintenance exposure.
Fluidstream
Provides continuous, autonomous, multiphase-tolerant pressure reduction with no
separation-first
requirement, strong reliability, and scalable field economics.
Next step
Evaluate whether MultiphaseCommander™ can restore value in your field.
Fluidstream can review line pressure, wellhead conditions, stabilized and peak gas rates, liquid rates, plunger-lift behavior, slug frequency, expected low-flow/no-flow periods, power availability, H₂S exposure, sand risk, winterization requirements, and uptime requirements to determine whether MultiphaseCommander™ fits the application.