Heavy Oil

01

Heavy Oil Challenges​

Often only 2% to 10% of the original oil in place (OOIP) in heavy oil fields is recovered through primary production, with most reservoirs then being abandoned without enhanced oil recovery (EOR) being applied.

Problem 1: LOW OIL MOBILITY

The biggest challenge in enhanced heavy oil recovery is getting the oil to move in the reservoir because of its high viscosity. Increasing the oil temperature to decrease its viscosity is the near-universal means of enhancing heavy-oil production.

Problem 2: DEPLETED DRIVE MECHANISM

Primary oil production results mostly from the utilization of existing pressure. As fluids are produced (particularly in reservoirs where the dominant drive mechanisms are dissolved/solution gas and/or free-gas drive), reservoir pressure declines, resulting in a direct reduction of oil production. Pressure maintenance is usually the most effective approach to increasing oil production and ultimate recovery from depleted oil reservoirs.
Darcy's Law Relationship
02

The DCSG Solution​

GERI’s Direct Contact Steam Generation (DCSG) technology adds both HEAT and PRESSURE, two critical parameters of enhanced heavy-oil recovery, by co-injecting steam and flue gas.
Co-injecting steam and flue gas also provides additional benefits:
  • Flue gases move further from the injection zone (vs steam alone) contacting larger oil volumes (Siddique et al., 1993; Wan et al., 2020), leading to incremental oil recovery
  • CO₂ dissolves in oil, further reducing its viscosity and causing swelling (more so at colder temperatures)
  • Flue gas can form foamy oil (Wang et al., 2017) and direct emulsions
  • Free gas acts as an insulation blanket at the top of the reservoir resulting in less heat loss to the overburden (= improved thermal efficiency vs steam only)
  • Improving sweep efficiency with simultaneous gas override and water underride sweep (not applicable in steam assisted gravity drainage (SAGD))

03

Heavy Oil Applications​

GERI’s portable DCSG Co-Injector can be deployed in a variety of different applications. The ideal application for a heavy oil field depends on reservoir properties, existing infrastructure, and customer needs.
GERI’s equipment located on a multi-lateral horizontal well pad

Cyclic Stimulation/Huff-n-Puff

(Steam + Flue Gas or Hot Water + Flue Gas)

GERI’s Co-Injector performs an enhanced version of Cyclic Steam Stimulation (CSS), adding heat while also rapidly re-pressurizing the reservoir
by co-injecting flue gases. Steam (or hot water) and flue gas are injected into a well for weeks to months, followed by a brief soaking period, and
then the same well is re-equipped and put into production. CSS with flue gas is an ideal solution for depleted heavy-oil wells with nearly any
wellbore design (multilateral, horizontal, vertical) placed comfortably above a formation water leg. Benefits include:
  • Maximum focused heat and pressure support
  • Short duration and quick results (within weeks after stimulation)
  • Broad applicability
Phase 1: Injection
Phase 2: Soak
Phase 3: Production

Flooding

(Steam + Flue Gas or Hot Water + Flue Gas)

Steam (or hot water) and flue gas flooding offers another solution for enhancing depleted heavy-oil fields. Heat and flue gas are injected into a well, and oil is produced from offsetting wells. Optimal sweep efficiency is achieved by the vapour phase scouring top-oil, and the liquid phase sweeping the lower part of the reservoir, similar to a water-alternating-gas (WAG) flood. Benefits include:
  • Long-term heat and pressure delivery
  • Flue gas insulates the overburden
  • Improved sweep efficiency
  • Fewer well conversions (vs. cyclic projects)
Steam Flooding with Flue Gases diagram
STEAM + FLUE GAS FLOOD
04

Frequently Asked Questions​

Hot Water vs. Steam

Hot produced water generation has a major advantage over steam generation as it eliminates fresh-water usage and reduces cost. Additionally, injecting at lower-temperatures can eliminate the need for thermal wellbores and equipment.  Injecting hot produced water is also a viable means of adding heat to reservoirs with certain clays that are detrimentally affected by the injection of non-saline water and/or steam, but not by produced water.  GERI Direct Contact Steam Generation (DCSG) has successfully generated hot water (and flue gas) using produced water with a total dissolved solids (TDS) of 30,000 ppm, without any problematic scaling issues.

Reservoir Applications

Yes. DCSG stimulations are applicable to reservoirs as thin as three metres.
GERI has a list of candidate selection criteria that can be shared with the customer; however, each reservoir and application is different and requires its own consideration.  The ideal reservoir will benefit from lowering the viscosity of oil (by adding heat), and pressurizing the reservoir (by injecting non-condensible gases).  Obvious candidates are pressure-depleted, heavy-oil wells, but there is a wide range of oil-field applications for DCSG technology.
Because GERI’s DCSG is portable, stimulations can be either cyclic or continuous (flooding). 
GERI’s reservoir engineer is available to lead or assist customers as needed. Depending on the project requirements, GERI can assist and guide third-party reservoir modeling.

Steam Assisted Gravity Drainage (SAGD)

01

SAGD Challenges​

Non-condensable gas (NCG) injection in SAGD has rapidly increased in the last 10 years with over 250 MMcf/d of natural gas currently being injected as NCG in SAGD projects in Canada.

However, the industry purchases large amounts of natural gas for NCG injection, which is costly and emits substantial amounts of flue gas from steam generation, which is a significant greenhouse gas (GHG) emissions challenge. Why not, then, inject flue gas as an NCG instead of methane?

Non-condensable gas (NCG) injection in CANADIAN SAGD
02

The DSCG Solution​

GERI’s portable Direct-Contact Steam Generation (DCSG) technology offers a lower-cost, less-carbon-intensive solution for steam and non-condensable gas (NCG) co-injection into steam assisted gravity drainage (SAGD) reservoirs, readily integrating with existing operations.

GERI’s DCSG Reduces Costs and Natural Gas Supply Requirements

The flue gas injected by GERI’s DCSG is a more effective alternative to injecting natural gas as an NCG. Depending on the source of electrical power, it converts 1 unit of NCG (natural gas) into 10 units of NCG (flue gas), substantially lowering the amount of natural gas that must be supplied and purchased. Additionally, co-injecting flue gas and steam with DCSG stores CO2 in the reservoir, cuts carbon intensity and can improve oil recovery compared to conventional co-injection by blending natural gas with steam.

GERI’s DCSG Brings Rapidly Deployable, Incremental Steam Capacity

GERI’s modular DCSG is portable and rapidly deployable to complement existing SAGD operations with minimal disruption (this process has been refined over five field pilots). The latest GERI unit fits within most existing well leases, takes approximately a week to set up and only a few days to rig out, depending on site-specific factors.
GERI’s equipment DEPLOYED ON AN SAGD well pad
03

Benefits

Adds steam and NCG capacity

  • GERI’s DCSG co-injector frees-up steam that can be re-deployed to newer wells.

Improves oil recovery

  • Flue gas works as a non-condensable gas (NCG) and may perform better than CH₄.
  • We provide:
    • Injection of (up to) 90 tonnes of steam per day (80% quality)
    • Injection of (up to) 54 e³m³/d NCGs (approx. 88% N2, 12% CO₂)
  • This can result in $12K/day incremental oil revenue (assuming steam re-deployed at steam-to-oil ratio (SOR) = 2, and oil price of $55/bbl).

Reduces operating cost

  • GERI’s DCSG co-injector can achieve up to 1/3 reduction in daily operating cost (for equivalent volumes of steam and NCGs injected).
  • Significantly reduces natural gas requirements for co-injection by converting 1 unit of methane NCG intup up to 10 units of flue gas NCG.

Reduces carbon intensity

  • Uses pre-existing infrastructure for low-cost carbon storage. A typical SAGD well pair can store roughly 1,500 tonnes CO₂ (in the form of flue gas).A,B
  • DCSG is up to 25% less carbon intensive than Once-Through Steam Generation (OTSG):C
    • No wasted heat in vented flue gas from steam generation
    • CO₂ from steam generation is stored underground
    • No steam pipeline heat losses when deployed
      at a pad
    • Electrically driven compression

Reduces water requirements

  • Water created from combustion is injected downhole resulting in 11% less boiler feedwater requirement vs. OTSG for the same steam output.

A Based on GERI’s third-party SAGD CGS model simulation in a 70 m wide x 1000 m long x 30 m high wellpair block.

BConforms closely with extrapolation of Law, David H.-S. “Disposal of Carbon Dioxide, a Greenhouse Gas, for Pressure Maintenance in a Steam-Based Thermal Process for Recovery of Heavy Oil and Bitumen.“, March 2004.

CGERI estimate which varies depending on the project and application. Internal study and simulation currently underway with expected results Q1 2025.

Slots into existing operations with minimal disruption

  • GERI’s modular DCSG co-injector is modular, portable, and rapidly deployable to complement existing SAGD operations with minimal disruption.

De-centralized steam generation that is easily moved around

  • GERI’s mobile DCSG fits within a standard pad/lease size, which eliminates steam pipeline heat loss.
04

Scenarios Where DCSG Can Help​

  • Late-stage or wind-down SAGD co-injection
  • Top-gas, thief zone or depleted gas-over-bitumen pressurization
  • On well pads with natural gas supply constraints, GERI’s technology can turn 1 unit of NCG (natural gas) into 10 units of NCG (flue gas)
  • Anywhere immediate or temporary steam is needed (steam and pressure maintenance during turnarounds, production well stimulation)
  • Voidage replacement in top-water dewatering schemes
  • Deployment at pads located far or inaccessible from the central processing facility (CPF)
Theoretical expansion of application boundaries with geri’s portable dcsg technology
Theoretical expansion of
application boundaries with
geri’s portable dcsg technology
05

Frequently Asked Questions​

Yes, and several studies point to it potentially working better than methane.

  • Steam assisted gravity drainage (SAGD) flue gas co-injection was first field piloted in Alberta in 2001, long before the current GHG landscape. Chi-Tak Yee, A. Stroich, “Flue Gas Injection into a Mature SAGD Steam Chamber at the Dover Project (formerly UTF)”
    .
  • It also involves relatively well understood reservoir dynamics, with many studies and simulations.

     

    “Addition of CH4 will impair SAGD process because CH4 overrides faster than steam and hinders the development of a steam chamber. N2 can accelerate the oil recovery rate but has no effect on improving recovery factor. On the contrary, the viscosity reduction effect of CH4 and N2 is much less than CO2. With the results of this paper, the recovery factor of SAGD process can be improved by 8% and steam-to-oil ratio (SOR) can be improved by 14.7% when CO2 was co-injected with steam.” Erpeng Gao, et. al., “Study On Thermal-GAS EOR Method in In-Depth Extra-Heavy Oil Reservoir in China.” March 2016.
  • S. Ashoori, I. Gates, “Intensity of in-situ oil sands operations with direct contact steam generation lower than that of once-through steam generation”, 2022.
  • Yongrong Gao, et. al., “Research on the Selection of NCG in Improving SAGD Recovery for Super-Heavy Oil Reservoir with Top-Water”, October 2017.
  • Nasr, T.N.,et. al., “The Use Of Flue Gas With Steam In Bitumen Recovery From Oil Sands”, 1987.
Some of the injected CO₂ and N₂ will be produced back to the surface. In steam assisted gravity drainage (SAGD), the produced gas (containing non-burnable CO₂ and N₂) can be either re-injected at the pad level (with or without a nitrogen rejection unit), or produced to the central processing facility (CPF) and blended with a large volume of pipeline gas. The large volume of pipeline gas used at a CPF provides a significant buffer to blend the non-burnable gases produced. Evaluation of a hypothetical, large-scale GERI project at several SAGD facilities showed that under worst-case recycle ratio scenarios, non-burnable gas content in the blended gas reaches only a few per cent. Reducing the heat content of gas burned at the CPF must be evaluated by the operator, but these levels fit within the practical range of most industrial gas-fired equipment.
Electricity for GERI’s process is normally supplied with GERI’s own portable generators. A large portion of the DCSG power requirement is for electrically driven air and fuel compression, a design consideration which allows us to connect to grid power if available. Using grid power reduces natural gas requirements by about half, and if the grid power source is low-carbon, GERI’s technology can recover oil at a carbon intensity of up to 90% less than conventional thermal.
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