Gas-assisted gravity drainage (GAGD) process
GAGD deviates from the current industry practice of horizontal displacement of gas-oil mixture in the reservoir to a vertical one. The current industry practice of Water-Alternating-Gas (WAG) and Continuous Gas Injection (CGI) technologies is an effort to fight with natural forces of gravity while GAGD takes advantage of natural gravity segregation of fluids. This “working-with-nature” concept behind GAGD is what is responsible for yielding consistently high oil recoveries (65%-95%) in various pilot experiments compared to 5%-10% recoveries using conventional (WAG) practice in 59 field projects. The flue gas produced by HydroFlame process can be injected in the vertical wells, which then accumulates at the top of the payzone due to gravity segregation, displacing oil downwards draining to the horizontal producer located at the bottom. The GAGD process has been successfully tested recently in an offshore Vietnamese reservoir. The gravity segregation also helps in eliminating gas breakthrough and hence sequester the injected CO₂/flue-gas thereby eliminating CO₂ emissions. Thus, this unique combination of HF and GAGD technologies, will enable a long-awaited solution to (1) eliminating flares and CO₂ emissions, (2) cost-effective produced water recycling, and (3) improved EOR economics by solving the current problem of low oil recoveries.
The Process
The current commercial practice of gas-based enhanced oil recovery processes involves either Continuous Gas Injection (CGI) or Water-Alternating-Gas (WAG) injection. Over 60 commercial projects in West Texas and other parts of the world have amply demonstrated that these CGI and WAG processes have been technically successful and commercially profitable. However, the oil recoveries from the CGI and WAG processes fall in the range of 5-15% of the remaining oil.
The Gas-Assisted Gravity Drainage (GAGD) process, invented and patented at LSU, has yielded oil recoveries in the range of 65 – 95% in laboratory experiments conducted at realistic reservoir conditions. The GAGD process involves utilizing several vertical wells for injection of CO₂ in addition to drilling long horizontal wells for production. Injected CO₂ accumulates at the top of the payzone due to gravity segregation and displaces oil, which drains to the horizontal producer. This maximizes the volumetric sweep efficiency. The gravity segregation of CO₂ also helps in delaying, or even eliminating, CO₂ breakthrough to the producer as well as preventing the gas phase from competing for flow with oil. Thus GAGD enables sequestering injected CO₂ in addition to yielding much higher recoveries of trapped oil from depleted reservoirs.
Advantages of the GAGD Process
GAGD process yields higher incremental oil recoveries when compared to all the currently used conventional gas injection processes (Water Alternating Gas (WAG) process recovered about 5 – 10% of the original oil in place (OOIP), while conventional Gravity Drainage field applications have yielded upto 40% OOIP and the GAGD is anticipated to do even better.
Comparable ultimate oil recoveries observed during field scaled laboratory GAGD experiments and gravity drainage field projects in both immiscible as well as miscible modes of operation. This would enable low pressure GAGD application, which would save significant gas compression costs.
The horizontal producer of the GAGD process has the capability of producing oil at high flow rates even at a lower drawdown. High flow rates mean quicker payback and higher profits.
In fluvial and marine stratigraphic traps, wherein the reservoir dips are significant and the placement of horizontal wells is difficult, GAGD process offers a tremendous advantage of selective drainage of structurally higher reservoir areas with horizontal wells, and later converting these ‘gassed-out’ horizontal producers into injectors. This helps drain the entire reservoir without requiring costly work-overs, infill drilling and high cost slim (horizontal) holes in the other unswept areas of the reservoir.
The GAGD process is applicable to both secondary as well as tertiary modes of operation in watered out and / or abandoned oil reservoirs. In tertiary mode, the mobile water production can be minimized by placing the horizontal well just above the oil-water contact, which can be inferred from detailed reservoir simulation studies.
Gas requirements for the GAGD process have been calculated to be substantially lower than the conventional WAG processes (2 – 3 MCF/Bbl for GAGD versus 6 – 12 MCF/Bbl). This enables even small operators to use trucked-in CO₂ to produce oil from depleted oil reservoirs instead of abandoning them thereby continuing to yield profits.
The GAGD process is easily scalable from laboratory data to field scale though reservoir simulation. This would enable a-priori prediction of “field-scale” GAGD process performance before any investments are made.
How does GAGD work?
CO₂ injected in the vertical wells accumulates at the top of the payzone due to gravity segregation and displaces oil, which drains to the horizontal producer straddling several injection wells. As injection continues, the CO₂ chamber grows downward and sideways resulting in larger and larger portions of the reservoir being swept by it without any increase in water saturation in the reservoir. This maximizes the volumetric sweep efficiency.
The gravity segregation of CO₂ also helps in delaying, or even eliminating, CO₂ breakthrough to the producer as well as preventing the gas phase from competing for flow with oil. Within the CO₂-filled chamber, the oil displacement efficiency could be maximized by keeping the pressure above the minimum miscibility pressure (MMP). This helps in achieving low interfacial tension between the oil and the injected CO₂, which in turn results in large capillary numbers and low residual oil saturations in the CO₂-swept region. If the formation is water-wet, water is likely to be held back in the rock pores by capillary pressure while oil will be preferentially displaced by CO₂. If the formation is oil-wet, the continuous films of oil will help create drainage paths for the oil to flow to the horizontal producer.
Thus, the proposed GAGD process appears capable of not only eliminating the two main problems (poor sweep and water-shielding) of the conventional WAG processes, but also additional advantages of increased oil saturation and consequently improved oil relative permeability near the producing well-bore, and the lack of competing gas flow. The process makes use of the existing vertical wells in the field for CO 2 injection and calls for drilling a long horizontal well for producing the draining oil. The drilling costs of horizontal wells have been significantly reduced in recent years due to advancements in drilling technology. In summary, the proposed GAGD process offers significant potential for increasing not only ultimate oil recovery but also the rates of recovery compared to that achievable by the conventional WAG process that is being widely applied in the US oil fields.
Self-Contained HydroFlame Process Development Using GAGD
One of the major bottlenecks facing CO₂ EOR projects is the CO₂ supply crunch, with most of these projects requiring pure CO₂ for their operations. CO₂ needed for these projects is mostly tapped from underground resources, defeating the “sequestration” benefit of CO₂ EOR, which is touted as its secondary benefit. Furthermore, 293.2 Billion cubic feet of natural gas was flared/vented from just the Permian shale oil basin last year in 2019 and this number has been steadily trending up over the past 3 years. Due to lack of compression/pipeline infrastructure, this gas is flared rather than being piped to gas hubs for sale. Small to medium operators do not have the economic wherewithal to invest in these capital-intensive infrastructures and are content in selling the oil, which fetches a higher market price, in preference to gas. In the current tight oil production scenario, there is no economic incentive for the operators not to flare the associated gas and that is why we have been seeing the upward trend in flaring/venting over the years. GAGD which doesn’t need pure CO₂ for its operation can help eliminate the flaring/venting by working in tandem with HydroFlame process. Rather than flaring, this natural gas would be diverted to a HydroFlame unit, that would use the energy content of the otherwise flared/vented natural gas for its operations and then use the burnt gases in a downstream GAGD process. This would help mitigate the colossal amount of flaring/venting ongoing in the shale plays. This holistic concept of produced water treatment, recycling and elimination of flaring in a self-contained process is illustrated below.
HydroFlame process would burn flare gas, that is currently being wasted in flares, in order to heat the produced water to knock out the calcium and magnesium carbonates and sulfates whose solubility decreases with increasing temperature. After utilizing their heat content, the exhaust flue gases from the HydroFlame unit will then be compressed and injected into oil bearing formations to produce oil thereby eliminating CO₂ emissions.