Calgary鈥� Millennium Stimulation is now launching is new form of hydraulic fracturing, one with the promise to dramatically reduce if not eliminate the use of fresh water.
Fresh water usage is one of the most contentious issues around hydraulic fracturing.
Grant Nevison, vice-president of the liquefied natural gas division of Millennium Stimulation, came up with the process and patents. He spoke to Pipeline News on Sept. 14, providing the details of this new process.
Nevison had founded Enfrac, a company which was acquired by Millennium in 2014.
鈥淚 developed the process and put the intellectual property from that process into Enfrac. Initial development took about a year,鈥� he said. Work began in the concept in early 2011.
They were making the fundamental steps towards commercialization. Prior to Millennium鈥檚 involvement, Enfrac had worked with two other partners for two years, but that ended up being more of a hindrance than a help, according to Nevison. 鈥淚t was very, very slow moving forward with these guys. Lots of delays, lots of bureaucracy.鈥�
Now, Millennium is bringing the idea to market. The Millennium team, he noted, has 鈥渂een great.鈥�
鈥淭hey certainly brought a sense of urgency to getting the commercialization finalized, the equipment out and ready to pump this process.鈥�
Enfrac was absorbed by Millennium in August 2014 after two months of negotiations.
Something different
Hydraulic fracturing has become something of a commodity service, he agreed.
鈥淎s you鈥檙e aware, there are a lot of perceived issues around hydraulic fracturing. Having a technology that effectively addresses those is a great differentiator.鈥�
What was the impetus to use liquefied natural gas over other fluids like propane, butane or water?
鈥淚t was taking a look at the industry and understanding the issues the industry was having with water use and greenhouse gas emissions, as a result of hydraulic fracturing. With understanding the issues, you start to ask yourself what are the possible solutions?鈥� Nevison replied.
鈥淔or hydraulic fracturing, there鈥檚 two points. One, whatever you鈥檙e going to use as your hydraulic fracturing fluid, it needs to be very available, so logistics don鈥檛 become an issue. With availability, it becomes cost effective. With the same point, it needs to address the issues you need to target, primarily that鈥檚 around water use and emissions.
鈥淲ith that, natural gas became a very good fluid to choose for both those reasons, and the challenge became how do we incorporate that effectively into the fracturing process?鈥�
With water off the table, it came down to a hydrocarbon that they had the most of that was inexpensive.
鈥淭he volumes used in hydraulic fracturing are massive. If you don鈥檛 have a commodity-type product you can deploy for your fracturing fluid, then the economics and logistics are going to be terrible. Natural gas is pretty available everywhere there鈥檚 oil and gas.鈥�
鈥淵ou can draw natural gas from any pipeline, field sales line, or even from a nearby well,鈥� Nevison said.
That is contingent on the use of a mobile liquefied natural gas plant, which supercools the natural gas to a cryogenic liquid that is handled and stored at atmospheric pressure.
鈥淭he process of handling LNG is quite similar to handling liquid nitrogen, which is commonly used in the oil and gas industry. What we鈥檙e doing is employing cryogenic to create a gas phase within the fracturing fluid which is done every day in the industry using nitrogen or carbon dioxide.鈥�
To be cryogenic, LNG is -160 C. In contrast nitrogen is actually colder, at -196 C. Liquefied natural gas is stored in closed vessels which are essentially excellent Thermos bottles, he noted. It can be stored up to three weeks without any gas venting off.
While natural gas is readily available, facilities to liquefy it are not. Nevison said, 鈥淲hat we鈥檙e looking at right now is a skid-based LNG plant. Essentially all an LNG plant does is expand natural gas which creates a cooling effect. You use that natural gas as a refrigerant to cool a concurrent stream of natural gas down to the point where it actually liquefies.鈥�
Thus natural gas is used both as the refrigerant and as the product being processed.
sed. Depending on what volume you need, additional trains can be added. For example, if you need 300,000 gallons per day, and each train can produce 100,000 gallons per day, then you would use three trains.
鈥淭he bottom end is about 5,000 gallons per day,鈥� he said.
The physical footprint of such a plant would be five truckloads, as a middle range example, for a 100,000 gallon per day plant.
For large pad jobs, it would be possible to have it on site, nearby, or in the region. But movement of the LNG from the plant to the well will generally be done by truck, going into into large tanker trucks known as a 鈥渒ing鈥� for storage until it is used in the actual frac.
鈥淚t鈥檚 difficult to pipeline cryogenics,鈥� he noted.
LNG is about half the weight of water or liquid nitrogen, according to Nevison, so you can transport more volume in a single truck than either nitrogen or water, allowing for better logistical efficiency.
A Montney basin frac might need 12 kings on site. As the frac is pumped, they are refilled in a logical manner to maintain fracturing rates.
The process
鈥淲e trademarked it as ENG, so people don鈥檛 confuse it with NGLs as natural gas liquids or LPGs and liquefied petroleum gas.鈥�
That stands for energized natural gas. 鈥淚t means you take a fracturing liquid, which can be water or oil, that contains your viscosifiers and proppant, and mix into that stream a gaseous natural gas stream 鈥� not liquid natural gas, but gaseous natural gas. The combination of your liquid slurry and natural gas form your volume that is used to hydraulically fracture the well.
The natural gas, which has been liquid up to this point above ground, is converted to a gaseous state just before it goes underground.
鈥淲e take the liquefied natural gas, in liquid form, and used a cryogenic pump to bring it up to the fracturing pressure. That鈥檚 still at -160 C temperature, but we鈥檝e pressured it up to, say, 50 MPa (megapascals).
鈥淚t鈥檚 really cold, it will destroy normal seals like nitrogen does, or it will freeze whatever it contacts, so we need to heat it up. Generally we鈥檒l heat it up to 10 to 20 C, just through a heat exchanger.鈥�
The difference is an increase of 170 to 180 degrees Celsius. The volume remains by the same because there is next to no pressure change. Hydrostatic pressure change is close to the friction pressure change. When it gets to the bottom of the tubing, the pressure will actually increase slightly.
At the wellhead, the ENG combines with the conventional fracturing fluid slurry and travels down the wellbore to the reservoir and serves to hydraulically fracture the formation.
鈥淚t stays at fracturing pressure through the whole fracturing process. As you add more fracturing fluids at surface, you increase the volume downhole which causes the fracture to propagate. This is conventional fracturing. Any liquid or gas will cause that. Once you鈥檝e got a big enough crack and you fill it with proppant, you stop pumping. At that point the fracturing pressure starts to dissipate by nature of the fracturing fluid moving through the reservoir matrix,鈥� Nevison said.
鈥淔or each single volume of liquefied natural gas at surface, you get at least one-an-a-half volume of fluid in reservoir,鈥� Nevison said. 鈥淔or example, if I need 1,500 cubic metres of volume downhole in a frac, I only need 1,000 cubic metres of LNG on the surface. That鈥檇 due to expansion from liquid to a gas.
Thus the volume requirements are a third less, and pumping requirements are correspondingly reduced.
One other difference from a water frac is that the process doesn鈥檛 put proppant into the system until the wellhead. As a result, there鈥檚 less maintenance. On a conventional water frac, proppant goes through the frac pumps.
Gas used must be cleaned prior to entry in the cryogenic process, either by using sales quality gas or processing it before it enters the process. 鈥淭he gas has to be prepared,鈥� Nevison said.
On the fluid side, Nevison said you can use water with the natural gas, and since you have a two-phase mixture, you can create things like foams. The foams create viscosity and carry proppant very well. Such foams would be 50 to 95 per cent ENG, meaning a very large portion of water that would otherwise be used has been replaced by natural gas.
鈥淭hat allows you to create the same frac volume of a conventional frac, using five to 50 per cent of the water that you would otherwise use on a conventional frac treatment.
Another method is to use an oil-based frac, which could be a distillate, diesel, crude oil (usually treated) and fracturing oils. Fracturing oils are similar to diesel and can be obtained from refineries, but it can be a logistic issue depending on how near the source is.
鈥淎ny pumpable, hydrocarbon liquid can be used,鈥� he said. In some formations, there鈥檚 better production if an oil-based frac is used.
He noted in the Montney, one company uses exclusively fracturing oils, while another uses exclusively water-based fracs.
Asked about Saskatchewan, Nevison said, 鈥淚 think there鈥檚 good potential for ENG fracturing in all reservoirs.鈥�
Reservoir damage averted
Nevison said, 鈥淭he perfect frac would be you frac the rock and have a proppant in there without a frac fluid to be seen or found. Unfortunately we need some sort of liquid or fluid to create the crack and carry proppant into those cracks. If you use water, generally what you see is less than 30 per cent of the water recovered when you clean out the frac. The water that remains behind tends to get trapped in pores and fissures by nature of capillary pressure.
That hinders the movement of oil and gas from the reservoir to the fracture and along the fracture to the wellbore to be produced.鈥�
鈥淏y using natural gas as part of your fracturing fluid, you reduce the volume of liquid placed in the reservoir, so there鈥檚 less liquid to block.
鈥淎s a gas phase in the reservoir, the gas phase will expand and help drive the water out of the pours, overcoming the capillary pressure holding it there so you get better removal of that liquid when recovering the frac, and you get better production.鈥�
Recovery
Since there is a gas phase present, the hydrostatic pressure in the wellbore is very much reduced. That allows for less pressure in the wellbore to provide a greater pressure differential, helping gas and liquids to move out of the well. With enough pressure, this can be put into a pipeline for removal.
Unlike water, natural gas used at a frac fluid is soluable with the hydrocarbons, oil or natural gas, you want to produce. The natural gas used in the frac is then saleable product upon the completion of the frac, unlike water, the flowback of which has to be captured, processed and disposed of. Instead of a sunk cost like water, nitrogen or carbon dioxide, it鈥檚 recoverable with existing infrastructure and you can sell it.
A conventional water frac might have a 10-day flowback period, whereas an ENG-based frac allows gas to be immediately recovered to pipeline (instead of flared), and for a two-to-three day period, a separator pulls liquids from the returning gas stream. Then the well can be flowed and put on production.
鈥淭here鈥檚 zero venting and flaring. Everything we put in the well is pipeline compatible. We鈥檝e designed the fracturing treatment so that, on flowback, we have enough pressure at the wellhead that we can put the natural gas in the pipeline,鈥� Nevison said.聽
Nitrogen is a comparable product. But when a nitrogen frac is done, the nitrogen has zero value later. Even worse, it contaminates any reservoir gases it comes into contact with. 鈥淣ot only do you end up venting the nitrogen, you end up contaminating the reservoir gases as well. During the cleanup process, with nitrogen, you will have two to three days recovering water, and then 10 days of venting and flaring to get rid of the contaminated gas.鈥�
The first month of production of a well is also its most productive, and thus a portion of that production is lost with a water or nitrogen frac.
