Flaring from Oil & Gas Production
Per the World Bank, the world currently flares roughly 3.25 tcf of natural gas per year. Some of these flares are visible from satellite pictures, as shown in Figure 1.
The World Bank has solicited support to end this flaring by 2030, and a number of countries and companies have signed on to the initiative. Progress has been made (see Figure 2), however, there is still much work to be done.
Figure 2 - Long-term gas flaring trend (World Bank)
This goal will require multiple solutions to eliminate routine gas flaring and unless these are commercially viable solutions, it is difficult to imagine that this initiative will succeed. Three challenging examples are described below.
Shale oil wells, seen in Figure 3 & Figure 4, typically:
· have a very short life (18 months to three years)
· low production rate per well (<1500 barrels per day)
· are spaced a few miles apart
· are located in remote areas, and
gas rates (< 1 mmscfd) are generally so low that conventional solutions for
recovery are uneconomical .
Figure 3 - Sample Shale Oil Field
It is for this reason that the Texas legislature, for example, exempts collection of or even flaring of gas where the flare rate is less 50,000 scfd from an individual well.
Figure 4 – Fall 2021 Methane Emission in Western
Further, trillions of cubic feet of Natural Gas are stranded in remote harsh environments world-wide where conventional solutions for recovery are currently not viable.
The Oil & Gas industry has made great strides in eliminating routine flaring from large facilities by either collecting the gas from multiple fields and liquifying it into liquified natural gas (“LNG”) or re-injecting back into the reservoir.
But there are a number of challenges that have to be over-come.
· In certain parts of the world, where there is considerable civil unrest, the pipe-line networks are routinely destroyed and the LNG plants become inoperable.
· In other parts, the on-shore gas plant, not operated by the Oil company, may fail due to any number of reasons and be incapable of receiving the gas.
· For certain formations, it is not possible to re-inject or continue to re-inject the gas.
· Gas re-injection can require extremely high-pressure compressors requiring significant power and space which the existing facilities may not be able to accommodate.
Figure 5 - OSO complex operated by ExxonMobil in Nigeria (Business Wire)
In the example shown in Figure 5, the Oil company had to build additional bridge-connected platforms to collect portions (LPG) of the flared gas at significant cost. Even then, the gas had to be sent to shore. While this is practical for certain fields such as Oso, which is located near the Bonny Island LNG plant, it is not viable for all. Thus, often in modern field developments, the gas is re-injected at negative NPV for the overall development from:
· Capital and operating cost for the gas compression, associated processing (gas dehydration), power, utilities and chemicals
· Capital cost for drilling the injection well(s)
· Capital cost for the subsea, risers, umbilicals, and flowlines
As well as lost potential revenue from the injected gas.
Eventually (typically 7 years), the injected gas breaks through the formation and the produced Oil to Gas ration is further reduced (in favor of the gas) making the project less and less commercially attractive.
Thus, at some point in the future, there will be a great number of fields currently in use, where the re-injected gas will become stranded.