The use of carbon dioxide as an agent to assist in fluid recovery from the wellbore is not new. In fact, the practice has been employed in oilfields since the early 1950s.
Yet Alberta’s new carbon pricing approach that will increasingly penalize heavy emitters in the province has some companies turning their attention back to the decades-old tactic – particular with regard to hydraulic fracking and enhanced oil recovery.
Earlier this year, emerging exploration and production company Blackbird Energy announced it had completed production test results on a well located in the Middle Montney formation near Grande Prairie, Alta., which employed an energized carbon dioxide foam frac. The carbon-dioxide-based completion, which reportedly used record-breaking volumes of carbon dioxide, produced 1,768 boe/d, exceeding Blackbird’s gas rate and total boe/d type curve by 109 and 80 per cent, respectively.
The Middle Montney well at Elmworth 2-20-70-7W6 was completed using sliding sleeve frac technology and an energized carbo- dioxide foam fracture with 70 individual stages. A total of 10,531 cubic metres (88,317 bbls) of load fluid and 9,226 cubic metres or tonnes of carbon dioxide distributed an average of 31.75 tonnes of proppant per stage over the 70 stages. Calgary-based Ferus Inc., which provides off-road cryogenic fluids for the energy industry and worked with Blackbird on the test near Grande Prairie, said the latest results represent a precursor of what’s to come as the Alberta government takes a hard stance on carbon dioxide emitters.
As part of a initiative to phase out all pollution created by burning coal and transition to more renewable energy and natural gas generation by 2030, the province is requiring facilities that emit 100,000 tonnes or more of greenhouse gas emissions (GHG) to annually reduce their site-specific emissions intensity by 15 per cent this year, increasing to 20 per cent in 2017, by applying a carbon price across all sectors, starting at $20 per tonne Jan. 1, 2017, and moving to $30 per tonne Jan. 1, 2018.
“When people have to start paying $30 per tonne, there will be more emitting companies interested in carbon dioxide as either a frac fluid or in enhanced oil recovery,” says Murray Reynolds, director of technical services at Ferus. “What I see is an exploration and production company that has a foothills sour gas plant emitting more than 100,000 tonnes a year of carbon dioxide, rather than pay $30 per tonne, allowing a company like Ferus to put a liquefaction plant on their site, capture/recover that carbon dioxide, and use it in their hydraulic fracturing program. If they have a gas plant, they’re probably drilling and completing wells in the area, so this would be the perfect scenario for them.”
How does it work?
Fracturing with carbon dioxide foam fluid is an offshoot of normal hydraulic fracturing. Instead of pumping high rates (more than 60 bpm) of non-viscous fluids into gas-producing reservoirs to generate narrow fractures with low concentrations of proppant (commonly referred to as the slicwater process), carbondioxide foam fracking replaces 70 to 80 per cent of the water that would typically be used with carbon dioxide that is pumped as a liquid.
Once it reaches the reservoir, down-hole conditions cause it to become a super-critical fluid, which results in a significant increase in fluid volume, and further extends the fractures. A portion of the injected carbon dioxide is permanently sequestered, allowing for significant GHG reductions.
“One of the reasons to use carbon dioxide, at least from an environmental standpoint, is we capture all the carbon-dioxide from highemitting man-made sources,” says Reynolds. “If we don’t capture it, it’s just vented into the atmosphere and it’s a greenhouse gas (GHG) that, in a year’s time, someone’s going to be paying $30 per tonne to emit.
In addition, by using nitrogen or carbon dioxide, operators don’t significantly alter lowwater saturation reservoirs that are common in western Alberta. It displaces, rather than uses, large volumes of fresh water that would normally be used in a slicwater treatment. In the case of Ferus’ work with Blackbird, the job was an “80 quality” – or an 80 per cent by volume carbon dioxide. Reynolds says if Blackbird hadn’t used carbon dioxide, all of that would have been water – so another 10,000 cubic metres of fresh water.
More effective
Reynolds adds another reason to use carbon dioxide, particularly in the Montney, is its effectiveness in deep-basin areas when compared to the slicwater process “(It’s effective) in fluid-sensitive formations, which we have a lot of in Western Canada – meaning water in these cases damage the formations, so you don’t get as good productivity,” says Reynolds, noting carbon dioxide and nitrogen are typically the workhorse fluids in deep-basin areas.
Ferus also works with a foamed fluid, which is more viscous when compared to slicwater. Viscosity is measured in centipoise. Water is one centipoise. Foam-fluid systems are in the 200-centipoise range, which allows operators to work more effectively much deeper into the formation.
“More efficient prop and placement and not loading up the formation with water, as well as the more gaseous aspect of carbon dioxide in the reservoir, allows more effective flow-back and more effective cleanup of the fluids you pump in, which ultimately results in a more effective fracturing treatment.”
A 2011 study titled Improved Hydraulic Fracture Performance with Energized Fluids: A Montney Example seemed to confirm that. Lyle Burke of RPS Energy and Grant Nevison of Nevison Consulting Inc. compared 60 wells in the Dawson area of northeastern British Columbia, determining the use of energized fluids was shown to generate significantly improved well performance over those wells fractured with non-energized fluids. On average, each well stimulated with energized fluids was shown to potentially recover up to 2.1 times as much gas as non-energized fracturing treatments.
The study’s authors did note that, however, that foam fracking was more about 55 per cent more expensive than slicwater. That relates to approximately $150,000 to $750,000 of incremental cost to recover 1.27 Bcf of additional reserves. Yet they also concluded that improved recovery far exceeded the additional production costs. Ferus also referred to a study of more than 150 wells in four major Cardium oil-producing areas in central Alberta that showed better long-term production by using nitrogen energized fracture fluids versus non-energized treatments.
In some cases, while initial productivity was similar, major differences in performance were noted within six months, with the energized wells showing a much shallower decline than non-energized wells. Ferus claims the difference in 10-year estimated ultimate recovery between these two well groups averaged 6,100 cubic metres per well.
Reynolds noted Ferus’ work with Blackbird in central Alberta involved the use of more carbon dioxide than the company has ever used previously. A typical Montney frac would include 2,500 to 5,000 tonnes or cubic metres or carbon dioxide. In this case, Ferus injected roughly 10,000 tonnes or cubic metres. “We think it’s a world record. We haven’t come across anything larger anywhere,” says Reynolds. “In recent times, slicwater has gained market share,” says Reynolds. “But as people have more difficulty getting fresh water and there continues to be issues in getting fresh water, people will see the benefits of carbon dioxide. We think it will swing back the other way.”
Carbon dioxide is also being used by some operators during enhanced oil recovery in cyclic solvent injection (CSI), otherwise known as Huff ‘n’ Puff. The process involves injecting carbon dioxide into a producing oil well followed by allowing the carbon dioxide to soak for a period of time before returning the well to production. The process is repeated as often as required. The injected carbon dioxide dissolves in oil present in the reservoir, resulting in solution gas drive.
The relative permeability to oil increases due to decreasing the interfacial tension and oil viscosity. The carbon dioxide also saturates formation water and displaces it from the near wellbore area, resulting in lower water production once the well is brought back on. As the well is produced, the carbon dioxide gas helps to vaporize light crude ends improving production and reducing blockage. Treatment size varies, but is typically 100 to 400 mcf per net foot of pay.
Typical recovery ranges from one to three mcf/STB. Carbon dioxide costs are approximately $18/ mcf, while the average recovery of two mcf/ STB is $36/additional bbl of recovered oil. Huff ‘n’ Puff treatments were originally steam treatments; Ferus says carbon dioxide is more effective for certain reservoirs, and is widely available for treatments in any field, unlike steam. Ferus refers to a case study it recently completed in the Appalachian Basin, where 65 wells in a depleted reservoir were treated. Oil production increased for 15 to 48 months before returning to the original hyperbolic decline curves. Water use was also reduced (up to 1 mcf/STB improved recovery).
The best candidates for Huff ‘n’ Puff treatments are typically depleted reservoirs. Lenticular or severely faulted reservoirs tend to have localized depletion, which results in lower reservoir pressure drive and making them good candidates as well. Ferus says the type of rock tends to have less impact than the quality of rock and localized production.
About the author: Jamie Zachary is the editor of PROCESSWest.
