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Another Bakken Opportunity: Harnessing the power of associated gas

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.

EERC Wins ARPA-E: Project to reduce largest use of water in the United States

One of the most pressing issues of this century is water sustainability. More freshwater is now used for thermoelectric power production (41%) than for agricultural irrigation (37%) in the United States according to the U.S. Geological Survey (Circular 1344, 2005), so power plant cooling is a critical area of innovative research. The Energy & Environmental Research Center’s (EERC’s) novel dry cooling project, which has the potential to reduce the largest use of water in the United States, was recently awarded one of just 66 cutting-edge research project awards given by the U.S. Department of Energy (DOE) Advanced Research Projects Agency – Energy (ARPA-E) “Open 2012” Program.

Most thermoelectric power is generated through the steam-driven heat engine process known as the Rankine cycle. Heat is generated from the combustion of conventional and renewable fuels, solar and geothermal energy, or nuclear fission and is used to boil water to make high-pressure steam that is expanded through a turbine to generate power. Water is then used to condense the exhausted steam and dissipate heat to the environment. Water-based cooling is cost-effective and efficient, but lack of water availability in many areas may limit opportunities for utilities to meet the needs of the industry.

The most prevalent cooling option for power generation is once-through (or open-loop) cooling because it requires the lowest capital costs. Large amounts of water are withdrawn from a body of water for cooling. Although most is returned to the water source, it is at a higher temperature, altering aquatic ecosystems. This has led to regulatory pressure from the U.S. Environmental Protection Agency to switch to technologies with less environmental impact. Closed-loop systems recycle the cooling water and, therefore, withdraw less, but virtually all of the water withdrawn is consumed because of evaporative losses. Conventional dry cooling systems don’t work as efficiently as a wet cooling system; they also don’t produce as much electricity during hot weather and cost three to four times as much.

Instead of using water for cooling, the EERC’s novel dry cooling technology uses a liquid drying agent, which  is nonvolatile and does not evaporate. There is no net water consumption, and the original working fluid is expected to last for the life of the system. The novel dry cooling technology is intended to address the key shortcomings of conventional dry cooling technologies: high capital cost and degraded cooling performance during daytime temperature peaks. If the EERC’s novel dry cooling system proves to be cost-competitive, it could be a tremendous breakthrough in cooling, particularly for water-starved areas of the western United States.

“By eliminating the largest user of water at power plants, the EERC’s novel dry cooling technology has the potential to advance the nation’s long-term sustainable energy and economic development,” said EERC Director Gerry Groenewold.

ARPA-E awarded the EERC $472,586 to develop heat-exchange surfaces for use with the system. The objective of the ARPA-E project is to determine if the EERC’s novel dry cooling technology can be turned into a marketable technology. Although drying agents are widely used in air-conditioning systems and for humidity control applications, using drying agents for cooling appears to be a unique idea, according to Chris Martin, EERC Research Engineer and project manager for the EERC’s novel dry cooling project.

“Based on the testing performed under previous projects, the underlying concept for using a nonvolatile liquid  drying agent to dissipate heat to the atmosphere appears valid,” said Martin.

“ARPA-E funds concepts that have a clear market application but pursue a fundamentally different technology path, one that holds the promise of significant benefits over conventional approaches,” said Martin. “As our proposal to ARPA-E stated, ‘the purpose of this project is to transform this dry cooling technology from a novel concept into a revolutionary technology with significant cost and performance benefits compared to existing dry cooling technology.’”

The ARPA-E Program, which began in 2009, now has a total portfolio of some 285 projects for an award total of $770 million. It has already resulted in funded projects that have made significant progress: the world’s first 400-Wh/kg lithium-ion battery, which is poised to revolutionize the electric vehicle industry; a wind turbine, inspired by the design of jet engines, that could deliver 300% more power than existing turbines of the same size and cost; and a high-power laser drilling system that can penetrate hard rock formations over long distances and is ten times more economical than conventional drilling technologies.

Competition for the ARPA-E awards is steep, and the EERC’s project is the program’s first award in North Dakota. The EERC’s application began as a concept paper that described the merits of the proposed technology and was developed further after the EERC was encouraged to submit a full proposal. Typically, only one-third to one-half of the concept papers submitted are encouraged to submit full applications, and few of these are funded. For example, in its first year, ARPA-E received 3700 concept papers and eventually elected to fund 37 merit-based projects worth a total of $151 million.

As an awardee, the EERC was recently invited to participate in the Technology Showcase at the 4th Annual Energy Innovation Summit in Washington, D.C.

“Our project was the only one there dealing directly with the issue of improved power plant cooling,” according to Martin. “A number of attendees stopped by to reinforce the need for what we are working on.”

Biomass and Biopower: What's the Outlook?


Now that the Obama Administration has another 4-year window and the hotly debated fiscal cliff has been avoided, scuttlebutt around office bubblers (a midwestern term for water fountain) surrounds the outlook for biomass and biopower. In one of my columns last year, I was cautiously optimistic on biopower projects. So what’s my outlook today? I remain cautiously optimistic. It appears that projects related to biomass and biopower have a chance to make a contribution to the U.S. energy mix, and my reasons for this follow.



First of all, the Obama Administration’s drive for renewable energy production and research will continue, as was vividly pointed out in the passing of fiscal cliff legislation. The bill extended the production tax credit by 1 year, which is valid not only for wind power projects, but also for biomass and waste-to-energy projects. Several other tax credit extensions for various biofuels and new eligible feedstocks, such as algae, telegraph the probiomass intent of the Obama Administration. This will definitely keep some biomass projects on the table.

The Administration’s intent with respect to certain biopower competitors, like low-cost natural gas, is less obvious. Natural gas prices have been on a downward skid since January 2012, and at this writing, they hover a little over $3/MMBtu. This is a challenge for biomass, especially since the Administration’s most effective carbon reduction method has been the replacement of coal power generation with natural gas generation. The fact remains that the United States has built only a handful of new power plants over the past several years, and now that some sectors of the economy are recovering, there is a strong possibility that new generation will be needed. Significant biopower supply is still relegated either to large coal-fired utilities cofiring small fractions of regional biomass feedstocks, small industrial plants burning large amounts or 100% regional biomass feedstocks, or new 100% biomass industrial boiler installations.

So the concurrent  innovation of American oil and gas explorers and the Administration has indirectly made new natural gas power generation the winner. This inadvertently hurts biopower, since the cost of biomass-derived power simply cannot beat out that derived from natural gas produced and sold for less than $5–$6/MMBtu.

A good case in point is a project in California. About 15 years ago, the Energy & Environmental Research Center (EERC) was working with several California entities to utilize biomass in new and existing power-generating systems. California was slowly weaning itself from coal-fired generation. Most of these in-state biopower efforts ultimately died off because of a lack of sustainable biomass supply, high biomass costs, onerous permitting and environmental processes, and loss of state incentives for biopower. Contrast that scenario with today, where the electricity demand is still high in California and the baseload power choices are down to natural gas or biomass, as coal is out because of state laws aimed at prohibiting greenhouse gas, SOx, NOx, and trace metal emissions.

Biomass is out for some of those same emission reasons, with attendant environmental reasons involving agriculture, and the lack of a low-cost sustainable supply. Natural gas is in because of the plentiful supply, lower emissions, competitive capital cost for generating platforms, and projected hope for sustainable fuel prices. So, in late 2012, the new 255-MW Lodi Energy Center natural gas power plant was commissioned at a cost of $452 million.

But the federal government is not exclusively driving the bus on making natural gas a winner over biomass and other renewable energy forms. Industry and economics are playing a role. At a recent energy conference, I was caught off guard slightly when several energy executives representing utility, power plant equipment and services, and energy regulatory entities all believed that abundant North American natural gas resources would most likely hover between $4–$6/MMBtu for decades. For these folks, that makes natural gas very competitive, with ample room for coal to remain a major player. Biomass remains a player only when state or regional incentives come into play or when feedstocks are fairly cheap.

Whether these trends continue remains to be seen. I am still cautiously optimistic for biomass and biopower.  

By Chris J. Zygarlicke, Deputy Associate Director for Research, Energy & Environmental Research Center (EERC)