GERI named Energy Excellence Awards Champion for its new steam generation technology

The second annual Energy Excellence Awards (EEAs) program, presented by the Daily Oil Bulletin, uniquely recognizes energy excellence and focuses on the advancement of collaboration within Canada’s energy industry.

For 2020, the DOB received close to 90 nominations in four broad awards categories — Project Execution Excellence; Innovation & Technology Excellence; Environmental Excellence; and Exporting Excellence — recognizing work completed last year. The nominees were further broken down into 12 subcategories across the four groupings, before being judged by a committee of industry leaders.

In the following days we will present the champions in each subcategory. Today, we feature the champion in Innovation & Technology Excellence in the subcategory of Production.

The Champions stories are compiled here, and access all the Finalists stories here.




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Leading the discussion is Wendy Ell, director of strategic partnerships and industry development for Glacier Resource Innovation Group, which publishes the DOB. Joining her is Mark Guirguis, account manager with Spartan Controls, which is the Silver Sponsor of the Energy Excellence Awards, as well as Douglas Freel, managing director of oilfield service for ARC Financial Corporation.

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Heavy oil production in Alberta and Saskatchewan has notoriously poor recovery rates, often leaving as much as 90 per cent of the resource behind. It also tends to be emissions- and capital-intensive, meaning smaller deposits are not economically feasible to develop.

A Calgary-based startup has developed a technology that could entirely change that equation. General Energy Recovery Inc.(GERI) is advancing direct contact steam generator (DCSG) technology that promises to be both cheaper and cleaner than currently used steam generation technologies.

The company’s high-pressure portable DCSG technology, which provides steam and flue gases for enhanced heavy oil production, earned it top marks for Innovation and Technology Excellence in the subcategory of Production.

GERI’s DCSG is capital efficient at less than 10 per cent of the cost of once through steam generation (OTSG) commonly used today, and does not require central processing facilities or steam pipelines that come with OTSG use. Its DCSG is designed to be compact and mobile so that it can be easily installed on existing wellsites with no additional land disturbance, then quickly demobilized once steaming is completed.

Because heavy oil production typically requires significant up-front capital investment in large, permanent central facilities, it often entails a five- to 10-year planning horizon in order to optimize the steam plant and production, not to mention the time and effort to secure regulatory approvals that include land disturbance and water supply, notes GERI.

Additionally, OTSG operators face large energy losses from the central steam plant, along the pipeline transmission to the well and in the wellbore. This requires larger central facilities and a robust thermal well design with stronger casing, joints and cementing — increasing both capital and operating expense. As a result, projects usually require a significant oil pool size of greater than 50 million bbls to meet the economic hurdle rate to proceed, GERI said.

Novel approach

Conventional boilers generate steam by heating water that flows through a collection of tubes inside the boiler. They require flue gas treatment as well as a relatively clean water supply to avoid contaminant buildup and plugging of the boiler tubes, both of which increase energy use and greenhouse gas emissions, reducing the system’s overall efficiency.

DCSG presents a novel approach to generating steam by injecting the water directly into the combustion chamber and injecting the high-pressure steam and CO2-rich flue gas mixture into the production wells. The method greatly reduces the water cleaning requirements since boiler tubes are no longer used, resulting in greater efficiency and less GHGs, according to Natural Resources Canada (NRCan), which has funded research into the technology.

Up to 80 per cent of the CO2 in the flue gas that is injected into the production wells remains underground when the condensed steam and oil is pumped back to the surface, while the recovered water can be recycled with minimal treatment since DCSG can operate with lower water quality requirements, according to NRCan.

Canada’s Oil Sands Innovation Alliance (COSIA) has also backed research into DCSG, testing the technology with SAGD produced water. The system recycles 90 per cent of the water it uses, requiring just 10 per cent of additional water to replenish the system, according to COSIA. If taken from existing oilsands tailings water, tailings pond water could be consumed using this technology, it said.

Field trials

The current DCSG design developed by GERI has the capability of steam, CO2, N2 and heat output equivalent up to 75 cubic metres per day at 80 per cent steam quality.

In field trials conducted in Saskatchewan on its own and in a nearby well with Canadian Natural Resources Limited (CNRL), GERI’s DCSG completed the largest steam/flue gas volume ever injected into a non-thermal well, said the company, which has an operations base in Lloydminster on the Alberta-Saskatchewan border.

The field-testing was able to demonstrate a steam-oil ratio of only 0.58. To date more than 18,000 bbls of incremental oil production has been realized. CNRL also noticed an increase in production from surrounding offset wells, according to GERI.

In addition, GERI was able to confirm at least 70 per cent of the CO2 was sequestered, and its DCSG produces 50 per cent less emissions and uses less water as 92 per cent of the steam/effluent energy is directed into the reservoir.

GERI also collaborated with the Saskatchewan Research Council’s (SRC) Post-CHOPs Well Test Centre to help validate DCSG performance. SRC’s multi-well CHOPS (cold heavy oil production with sand) model integrated with Computer Modelling Group Ltd.’s STARS simulator was used to forecast expected reservoir response by history matching the oil, water and sand production data for the selected test well and several surrounding wells.

SRC’s field unit provided onsite gas analysis to confirm the volume of flue gas injected and sequestered in the reservoir. SRC’s direct involvement in the field trial also provided important independent validation of the results.

“The overall field trial provided the opportunity and results to determine performance, both technically and economically, including reservoir response of the GERI DCSG on post-CHOPS wells and its applicability for further application,” said GERI.

“Completing this field testing and demonstrating to industry, with the third-party validation of SRC, gave GERI the credibility for other producers to work with GERI to evaluate the potential for their operations, providing a new low-cost alternative to increase production with existing assets that meets their low emissions goals.”

Additional applications

GERI said it believes it can extend the application of its DCSG to steam non-thermally cased and cemented wellbores using its patented annular cooling loop technology. It is currently examining the potential for SAGD as well as tight, light oil applications in partnership with interested producers.

It has two projects underway to further prove and expand the applications of its DCSG technology. One project is with a large heavy oil operator in the Lloydminster area as a second application to improve oil recovery in late stage heavy oil reservoirs.

A second project is with a medium size producer in southeast Saskatchewan to assess the effectiveness of enhancing light oil recovery in tight or low permeability reservoirs. It is currently in the reservoir model stage with SRC.

“Working collaboratively with oil and gas producers and SRC to develop and refine our DCSG technology has ensured we have a technology that meets all the requirements of lower cost, much less emissions, and high safety standards,” said Brian Kay, GERI chief technology officer.



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