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North Dakota is now the nation’s second leading oil producer, but another energy resource in western North  Dakota is also in the news—natural gas.

When crude oil is extracted from geologic reservoirs, associated gas is also typically produced. As of August 2012, North Dakota daily oil production had increased to over 700,000 bbl a day (up from 500,000 at the end of 2011); likewise, daily natural gas production had increased to over 760,000 Mcf/day. Associated gas, once separated from crude oil at the wellsite, is typically captured and transported via a low-pressure pipeline to large gas-processing facilities. These gas-processing plants separate the various components of associated gas for subsequent sale. At this time, there is enough gas-gathering infrastructure in North Dakota to gather, process, and transport 65%–70% of all associated gas produced.

Where gas-gathering pipeline does not exist, associated gas is sometimes burned in gas flares until gathering infrastructure can be built. EERC researchers recently completed a study assessing the technical and economic viability of technologies and processes that could lead to increased utilization of associated gas in the Williston Basin and decreased flaring.

“The flaring of associated gas is a by-product of the rapid growth of oil production in North Dakota,” said EERC Senior Research Manager Chad Wocken, the project manager on the EERC study. “Gas flaring continues primarily because of a shortage of gathering infrastructure to bring gas from the wellhead to gas-processing plants, but that infrastructure and new technologies are rapidly coming into place. We have enough gas-processing plants for the gas currently being produced and enough planned expansion to address expected growth. The major bottleneck has been the small gathering lines and compressor stations needed to get this highly distributed gas resource to the processing plants.”

In the interim, until processing can catch up, flaring is a safer and better option for the environment than simply venting the associated gas into the atmosphere: the gas is volatile and is about 60% methane, which has far greater heat-trapping potential than carbon dioxide. Further, associated gas contains valuable hydrocarbons with established markets for energy production or chemical manufacturing.

“Over the past couple of years, most of the drilling has been focused on securing leases by getting a single producing well on each ‘spacing unit.’ A shift in drilling activities has begun, away from single-well sites to in-fill drilling on already-producing locations,” Wocken added. “This shift is likely to allow gas-gathering infrastructure to catch up and have a noticeable impact on the fraction of gas that is flared.”

It is doubtful that flaring will cease completely, however. Because many North Dakota oil fields are in remote locations and wells are some distance apart, it may never be economically or geographically feasible to build the infrastructure to harvest all of the gas. At those sites, it is important to extract the most value from that gas, Wocken said. Flared gas is a transient resource. It changes in quantity and location as oil wells begin and end production and as infrastructure gets constructed. These conditions create a challenge to pairing an end-use technology to the resource.

Associated gas that is captured is transported to large gas-processing facilities where the mixture of C1–C6 hydrocarbons—methane (60%), ethane, propane, butane, pentane, and hexane—is separated into marketable products such as pipeline gas, liquid petroleum gas, and petrochemical feedstocks. The EERC study mentioned earlier looked at ways to use more associated gas upstream of these gas-processing facilities, reducing the burden of gas capture and processing, especially for locations geographically isolated from infrastructure. The objective was to define technical and economic conditions that would allow greater gas use at the wellhead or intermediate gathering locations upstream of the gas-processing plant. Technologies evaluated included 1) natural gas liquid (NGL) recovery, 2) compressed natural gas (CNG) for vehicle fuel, 3) electrical power generation, and 4) chemical production.

Bakken associated gas is typically low in sulfur and high in NGLs, creating both challenges to utilization and economic opportunity since NGLs, the larger hydrocarbon molecules, are currently more valuable than methane. The study concluded that deploying small-scale NGL recovery systems as an interim practice while gathering lines are built allows the highest value and most easily transported hydrocarbons to be marketed. The leaner gas generated from these systems can be more easily utilized for power or transportation fuel or transported as a compressed gas, but technology mobility is critical to enable relocation to new wells as gas-gathering infrastructure is constructed.

Bakken associated gas is too rich with NGLs and too variable in composition to be used “as is” in NG vehicles. It must be purified to a strict specification and compressed before being dispensed to a vehicle. Vehicle fleets utilizing the CNG fuel would need to be adaptable and flexible to take advantage of this stranded and transient gas resource. In spite of these drawbacks, U.S. Energy Information Administration data indicate that CNG prices have been consistently lower over the past decade when compared to gasoline and diesel fuels, and the price gap is expected to continue through 2015 with the increased availability of low-cost gas.

The demand for power in the Williston Basin has grown rapidly. The electric load in oil-producing areas of western North Dakota and eastern Montana is expected to triple. Based on an initial review of the characteristics of distributed power generation, three technologies were evaluated: reciprocating engine, gas turbine, and microturbine. A wide variety of power generation technologies exists that can, without much difficulty, utilize rich gas of varying quality to produce electricity and are scaled to wellhead flow rates.

The petrochemical industry is dominated by large processing plants where economy of scale and access to large gas fields, generally on the Gulf Coast, maximize profitability. Pipeline and rail export of North Dakota gas and NGLs to existing petrochemical infrastructure is likely to continue to be the predominant market for these resources. Still, for products like fertilizer, where regional demand is strong, smaller-scale production that can convert low-cost gas to higher-value chemicals or fuels may be economical. Furthermore, small-scale NGL recovery, although less efficient than at large centralized facilities, may be an enabling technology, allowing value to be extracted from associated gas while improving economic utilization of leaner gas for fuel. Chemicals production would be the most challenging to deploy at small scale in the Williston Basin, but some chemicals (specifically nitrogen-based fertilizers) may hold some promise.

“Although none of the approaches studied was highly compelling from a purely economic perspective, power production with NGL recovery provides a technically feasible option, as commercially available power-generating engines and turbines match the scale and temporal nature of the associated gas resource,” said EERC Associate Director for Research John Harju.

The EERC conducted the study in partnership with the North Dakota Industrial Commission (NDIC) Oil and Gas Research Council and the U.S. DOE National Energy Technology Laboratory.