Fluidstream turned two liquid-loaded wells from near-zero output into revenue-generating assets.

Field problem, solved at the real bottleneck

This case study documents how Fluidstream’s MultiphaseCommander™ restored production on two mature wells in Alberta, Canada that had become effectively uneconomic because rising pipeline backpressure and severe liquid loading had choked off flow. The producer operates internationally, but this specific installation and performance history occurred in Alberta. The operator needed a field-ready solution that could reduce wellhead pressure, tolerate real multiphase flow, avoid costly separation infrastructure, and run at an unmanned location with no electrical power. Fluidstream installed a 200 HP gas-driven MC2270 unit and converted two nearly dead wells into stable, revenue-producing assets. Combined production was restored to approximately 10e3 m3/day of gas and 5 m3/day of condensate, creating more than C$1.5 million per year of incremental revenue while also reducing intervention risk, avoiding repeated swabbing events, and demonstrating a scalable pathway for broader pad and field deployment.

Root cause engineering

The wells were not “empty” - they were liquid loaded.

The production problem was not simply 'older wells underperforming.' It was a textbook liquid-loading failure amplified by surface constraints. As mature gas wells decline, reservoir pressure falls and gas velocity drops below the threshold required to continuously carry produced water and condensate to surface. Once that critical transport velocity is lost, liquids begin to accumulate in the tubing. This adds hydrostatic head, which increases the effective backpressure on the formation and further suppresses gas flow. The lower the gas rate becomes, the more difficult it is to lift liquids. The result is a self-reinforcing cycle: lower rate leads to more liquid fallback, which creates more pressure burden, which leads to still lower rate. Eventually the well does not die because hydrocarbons are gone; it dies because the flow system can no longer clear liquids.

Plunger lift helped, but not enough in this operating window.

The operator was already using plunger lift on the two wells. Plunger lift can be a useful deliquification method because it uses well energy to periodically lift a liquid slug, but it is inherently cyclic rather than continuous. In this Alberta application, the problem had moved beyond the range where a cyclic unloading method could reliably maintain production. Pipeline pressure could rise to about 1200 kPa, while the operator wanted the wells seeing something closer to 250 kPa to produce effectively. Under those conditions, the available pressure differential was not sufficient to consistently unload the wells. The wells would build pressure, produce intermittently, unload partially, then fall back again. That meant high instantaneous swings, unstable operating conditions, liquid fallback between cycles, and insufficient average drawdown to keep the wells alive on a sustained basis.

Surface constraints narrowed the solution set.

Several practical issues made the problem harder. The wells were deeper than 2400 m, which made a downhole pumping approach less attractive. The operator did not want to add extra surface liquid separation because the additional facilities, tanks, handling systems, and associated field logistics would have raised project cost and complexity. There was also no electricity available on location. The solution therefore had to be compact, autonomous, able to run on fuel gas, and capable of operating directly in the presence of multiphase flow rather than depending on a perfectly conditioned inlet stream.

Why conventional systems fail here

Liquid ingestion destroys conventional compressor economics.

Traditional gas compressors are designed for gas service, not for the repeated ingestion of multiphase slugs. When liquids enter a conventional reciprocating or screw machine, they can cause liquid slugging or hydraulic lock because liquids are not compressible. That creates a direct path to broken valves, bent rods, bearing damage, lubrication breakdown, corrosion, and rapid wear. Even before a major mechanical event, liquid carryover can reduce efficiency, destabilize the machine, and increase maintenance burden.

Conventional compression usually requires extra facility buildout.

Because traditional compressors do not tolerate wet, unstable inlet conditions, the normal workaround is to install separation ahead of compression. That may mean scrubbers, separators, tanks, heaters, pumps, controls, drains, trucking logistics, and a larger facility footprint. For the operator in this case, that was exactly what it wanted to avoid. The wells were worth saving, but not if the only path forward required turning a simple optimization project into a facility buildout.

Swabbing works - but it is not a stable operating model.

If the compression system were to stop long enough for the wells to fully load up again, the operator indicated that a swabbing rig would be required to unload the wells, at an estimated cost of about $15,000 per event. Swabbing can restore flow by removing enough liquid column to reduce hydrostatic pressure, but it is an intervention, not a continuous operating strategy. It introduces downtime, mobilization cost, and uncertainty. From an economics perspective, poor reliability would quickly destroy value. That is why uptime and autonomous performance were not secondary issues in this case; they were central to project viability.

Fluidstream technical differentiation

Direct multiphase compression

Fluidstream’s core differentiator is that it is purpose-built to compress real production streams containing gas, liquids, and solids, instead of requiring the stream to be cleaned up before compression. That changes the design philosophy completely. Rather than avoiding liquids, Fluidstream uses a liquid-handling methodology designed to safely and efficiently manage incompressible fluids inside the machine. This allows the operator to eliminate separation-first infrastructure and address the actual field problem at the wellsite.

Contained gland-seal architecture

A major operational concern in multiphase service is how to keep the power-fluid side and the produced multiphase stream properly isolated without creating a disposal or leakage problem. Fluidstream’s fully contained gland-seal arrangement separates the power fluid from the multiphase process fluid and is paired with electronic seal wear detection. The result is a design that improves reliability while also giving operators visibility into seal condition. In this Alberta application, no gland seal leakage was reported to date, and the operator did not face an ongoing disposal burden from seal leakage. That is a significant credibility point because sealing and containment are often where complex multiphase systems lose trust in the field.

Autonomous control under unstable flow

Multiphase service is not just about surviving liquids; it is about surviving instability. These wells remained on plunger lift cycles, which meant the compression system had to tolerate very broad flow swings. Peak gas flow could reach roughly 95e3 m3/day at certain moments and then taper down to nearly no flow. Liquid rates also fluctuated. Fluidstream’s autonomous control system and mechanical design were able to accommodate variable flow, no-flow periods, transient surges, and liquid slugs without requiring continuous operator involvement. That operating range is part of what made the system valuable here. It did not just compress a steady-state stream; it managed a highly dynamic field reality.

Fit for abrasive and winter service

Fluidstream’s configuration is also designed for abrasive service and adverse field conditions. Its piston and gland-seal systems are configured to support performance in sand-bearing applications, and the controls help protect the system in upset conditions involving solids, temperature swings, and other disturbances. In this case, the MC2270 did not require insulation or heat tracing to operate effectively through extreme winter conditions, despite the presence of water in the produced fluid. That is commercially important because it reduces installation complexity and helps validate the technology for harsh Canadian operating environments.

Alberta deployment reality

The operator in this case is an oil and gas producer with international assets, but the specific project described here was deployed in Alberta, Canada. Newer wells tied into the system had increased line pressure, and the legacy wells on this pad no longer had enough reservoir energy to overcome that backpressure. The two target wells had previously produced gas, condensate, and water, but over time had become effectively non-producing. The operator wanted to avoid a separation-heavy surface solution, did not want to rely on downhole pumping in wells deeper than 2400 m, and had no electrical power on site. Fluidstream installed a gas-driven MC2270 multiphase compressor package using produced gas as fuel. The selected model was well suited because the wells were not characterized by simple steady average flow; they exhibited periodic, high instantaneous gas and liquid rates associated with plunger-lift cycling, followed by sharp tapering. That meant equipment selection had to account for both the peak rates and the low-flow tail, not just the daily average.

Results

The production outcome was material. One well recovered to about 7e3 m3/day of gas and 3 m3/day of condensate. The second recovered to about 3e3 m3/day of gas and 2 m3/day of condensate. Combined, the two wells returned to roughly 10e3 m3/day of gas and 5 m3/day of condensate.

At April 2026 commodity pricing referenced in the source materials, the resulting increase in revenue exceeded C$1.5 million per year. The significance of that number is not merely the size of the uplift. The more important point is that the wells moved from generating virtually no meaningful revenue to producing a solid annual cash contribution without requiring a major new facility build.

Reliability was equally important to the operator. Aside from maintenance, service, and optimization work associated with the gas drive itself, there was no maintenance reported on the Fluidstream compression system. There was no gland seal leakage to date, and the autonomous control system handled slugging, variable flow, and upset conditions without creating operational headaches. For a producer concerned that 24-plus hours of downtime could force a $15,000 swabbing intervention, that runtime performance had direct economic value.