Sandy Fielden, RBN Energy LLC
In June 2012 Bakken oil production reached 660 Mb/d with 0.7 Bcf/d of associated natural gas. A third of that associated gas (32% or 0.22 Bcf/d) was flared at the wellhead. There are sound environmental and economic reasons why flaring occurs. In other States like Texas the percentage of flaring is tiny (0.5%). The answer to flaring is better infrastructure but huge investments in North Dakota could still not be enough to eliminate flaring. Today we shed new light on the issue.
What is flaring? Flaring occurs when the natural gas produced from an oil and/or gas well is captured and burned (we will get to why it’s burned next). There are a couple of broad categories of flaring. The first category is a limited activity carried out by producers during well completion. In this case, the producer captures gas that bubbles up the well casing that would otherwise escape into the atmosphere and then flares that gas separately. The second, more significant category consists of a continuous flaring process to burn the associated gas that comes to the surface with the oil once a well is producing. We are going to concentrate on the second category.
Why does flaring occur? There are two reasons that flaring occurs. The first is environmental. In any situation where gas would otherwise escape into the atmosphere (known as venting) it is better for the environment to flare that gas. Flaring is safer than venting because natural gas (methane) is 20 times more environmentally damaging (e.g. to ozone) if vented into the atmosphere than if it is flared first. The byproduct of flaring is CO2 – not tremendously good for the environment but a heck of a lot better than methane. So if you are going to get rid of methane, flaring is better than venting.
The second reason for flaring is economic. If you drill a well for oil and start production, you can capture the oil in tanks and transport it to market in trucks long before pipeline infrastructure is available. Oil is much easier to store and transport than gas. Any associated gas produced from the well is not feasible to capture and transport to market until a gathering pipeline infrastructure is in place. The companies that invest in gas gathering pipelines and the gas processing infrastructure necessary to treat the natural gas before transporting it to market will only make such an investment once they know how much associated gas is being produced. The answer to that question is not easy to predict until oil production gets underway. So if you ban flaring (assuming that venting is verboten) then you would be banning oil production and you would never know if the associated gas could be recovered because you would not be drilling the well in the first place.
Flaring is therefore allowed (usually through a permit application to the State), in order to burn associated gas that has no route to market. This allows oil production to start, revenue to flow, taxes and fees to be paid, and gas volumes to be assessed by infrastructure companies.
How much flaring goes on? Almost all existing oil and gas wells will have required some flaring during completion as mentioned above in our first flaring category. New Environmental Protection Agency (EPA) rules introduced in April 2012 require new wells (starting in January 2015) to be completed using “green” techniques that capture any gas and store it for practical use instead of flaring it. These new rules do not deal with associated gas production but they do address flaring during well completion.
Flaring of associated gas produced from oil shale wells is a particular issue in the Bakken. North Dakota Industry Commission (NDIC) data indicate that about 32% of current natural gas production (out of the total production of 0.7 Bcf/d in June 2012) was flared (see North Dakota Chamber of Commerce presentation chart below). That percentage is not as high as it has been (36% in September 2011), but it is still huge compared to Texas, where the Texas Railroad Commission’s last published natural gas production numbers for May 2012 put gas flaring at 0.49%. The extent and necessity of flaring depends on the basin characteristics (how much gas is produced) and also on the infrastructure in place. In the Bakken it’s mostly related to infrastructure, or lack thereof.
Drilling in the Bakken has concentrated on oil, with natural gas and natural gas liquids (NGLs) playing second fiddle. The more than 50 active operators in the Bakken have so far had to put up with significant transport constraints just to get their crude to market (see “The Bakken Buck Starts Here – Bakken Crude Pricing Part I, Part II and Part III”). Dealing with infrastructure for associated gas has been a secondary priority. In other plays such as the Eagle Ford and Permian basins in Texas, existing infrastructure was already somewhat in place to gather natural gas.
Bakken flaring occurs during the time lag between when an oil well starts producing and when gas gathering system infrastructure is installed. North Dakota State regulations allow flaring to occur during the first 12 months of production without penalty. After that, producers need to get an exemption for flaring that requires them to justify the “economic feasibility” of flaring based on the cost of connecting to the nearest gas pipeline being greater than the return they would get by selling the gas. If the exemption is not granted, then the producer has to pay royalties and taxes on the flared production.
When we previously covered Bakken gas production takeaway in “Border Wars – Will Bakken Producers Muscle Out Canadian Gas?” we learned that there is considerable natural gas takeaway capacity in North Dakota via the Northern Border and Alliance (wet gas) interstate pipelines and WBI Energy Transmission. These pipelines provide delivery access to Midwest markets such as Chicago. The issue with associated gas in the Bakken is therefore not pipeline takeaway capacity but rather with the gathering pipeline infrastructure and gas processing capacity required to get wellhead gas processed ready for shipping on the interstates.
To this end, natural gas and natural gas liquids midstream companies are investing heavily. According to the NDIC Pipeline Authority – to the tune of $4 billion (see graphic by North Dakota Pipeline Authority below). By the end of 2012 gas-processing capacity is expected to reach 0.9 Bcf/d and that should be greater than production (current production 0.7 Bcf/d). By the end of 2014 processing capacity will reach 1.3 Bcf/d. Gas plant capacity does not stop flaring on its own. The gathering infrastructure to deliver wellhead gas to the plants also needs to be in place. Challenges to building out gathering infrastructure in the Bakken include the large size of the production areas, freezing winter and spring working conditions, and workforce availability. However, Bakken natural gas is rich in NGLs, making it attractive to midstream companies because the liquids fetch a higher return than dry gas.
As the new gas-processing plants come on stream they should reduce the need for flaring. The recent BENTEK study for the North Dakota Pipeline Authority (you can get a copy here) reported that the gas to oil ratio of Bakken wells increases during the life of the wells, meaning that associated gas production will increase faster than oil. This is already happening and it means more gas is on the way. The BENTEK study concluded that once the currently planned new gas plant infrastructure is in place by the end of 2014, gas production will quickly outpace capacity again – meaning more new infrastructure is required or more flaring.
Once you accept the economic argument to invest in oil shale drilling, then some flaring is inevitable. At 32 percent of production, Bakken flaring levels leave the industry open to accusations of environmental damage or wasting resources. In the same way that concerns with hydraulic fracturing seem to refuse to go away, the issue of flaring is likely to remain on environmental agendas for as long as it happens on this scale. At this point in the development of Bakken oil production, the need for new gas infrastructure should be easier to predict than it was earlier on. Producers would be wise to plan ahead and find a home for expected associated gas. Otherwise, if Bakken gas flaring does not fade away, producers may be required by regulators to adopt solutions they find uneconomic to implement.
Not Fade Away was first recorded by Buddy Holly and The Crickets in May 1957 and subsequently covered by The Rolling Stones in 1964
This article first appeared in an RBN Energy LLC blog on September 6, 2012.
About the author
Sandy Fielden serves as Director Energy Analytics for RBN Energy LLC and is an internationally accomplished professional with 25 years of management and communication experience in the European and North American energy industry, including ten years as a vice president at industry leading firms. He is a widely recognized expert at analyzing, processing, and communicating the value of a wide range of information in the energy industry.
Why will Bakken flaring not fade away?
Sandy Fielden, RBN Energy LLC