Navigant Research Blog

Natural Gas Flaring: Time to Turn a $30 Billion Waste Stream into Profit, Part 2

— May 22, 2017

Part 1 of this blog series covered the state of natural gas flaring; this post examines specific developments allowing stakeholders to put the gas to use.

Flaring, the intentional burning of excess natural gas, contributes a great to deal to climate change. Therefore, this practice is regulated across the globe in the hopes of meeting climate goals. But is regulation necessary? Ideally, this wasted gas would be put to profitable, efficient use, limiting the need for specific flare gas regulations. In fact, several developments are pointing toward the profitable use of associated gas, including improved gas-to-liquids (GTL) technologies, improved onsite combustion technologies, and access to electricity offtakers through microgrids. Consider the following:

  • GTL technologies are improving rapidly. Notably, small-scale GTL players like Velocys, CompactGTL, and many others have commercially available products that convert natural gas into a variety of liquid products, including diesel and methanol, among others. These products have generally higher local value than natural gas and can be transported easily. This points to more opportunities in the developing world—much of which relies on liquid fuels, but has limited access to pipelines. GTL technologies have been held back by low oil prices, but become quite economical in many cases when oil costs over $50 per barrel—a scenario playing out with more regularity.
  • Improved combustion technologies, including natural gas reciprocating engines and microturbines, are opening new opportunities. Manufacturers like Caterpillar and Cummins offer dual fuel generator sets (gensets) that can mix natural gas into oilfield diesel generators. Meanwhile, microturbine vendors like Capstone Turbine offer units as small as 30 kW that can run on a wide range of fuels. GE’s Jenbacher gensets, well suited to handle the variable composition and impurities in associated gas, account for more than 450 MW of installed associated gas generation worldwide.
  • Access to new electricity offtakers through microgrids has the potential to put flare gas to use. Improvements in solar, storage, and microgrid controls technologies make microgrids a popular phenomenon—though such microgrids often call for a consistent baseload fossil fuel source to optimize generation. This is a good match for wellhead gas, which is produced with a relatively consistent output. Various companies are developing microgrids tied to oil & gas production, from Horizon Power in Australia to Mesa Natural Gas Solutions in the United States.

Global Opportunities

As a measure of global opportunities, consider developments in two key markets: Nigeria and Indonesia. Both major oil-producing nations, these countries rank No. 7 and No. 12, respectively, on The World Bank’s flare gas ranking list, accounting for a collective $2 billion in wasted gas (based on the $5.61 per million Btu measure previously outlined).

Nigeria has an aggressive strategy of 75% electrification by 2020 and recently released minigrid regulations that encourage decentralized generation. This, combined with continued oil & gas growth, points to opportunities for the $1.5 billion of wasted flare gas.

Indonesia, meanwhile, recently released new rules that incentivize wellhead power developments—provided that they are close to gas fields and to existing transmission lines and consumers. With more than $500 million in gas flared there, this regulation will open opportunities for microgrid developers, generator vendors, and other stakeholders in distributed power. With billions of dollars of gas going up in smoke and technologies and regulations pushing for efficient generation, opportunity looms large in flare gas alternatives.

 

Natural Gas Demand Response – Not Just for Electricity Any More: Part 2

— May 17, 2017

Coauthored by Brett Feldman

What Is Holding Back Natural Gas Demand Response?

As we discussed in our earlier blog, demand response (DR) in the electricity sector has been a common practice for decades for utilities and grid operators. Historically, DR has been less prevalent in the natural gas industry, but changing market factors have increased interest in the practice.

In this blog, we discuss the opportunities for DR in the natural gas sector and describe some of the major challenges. A key area of opportunity for natural gas DR lies in alleviating pipeline capacity constraints during periods of peak usage, which are typical spikes in demand driven by extreme weather or logistical issues.

Natural gas DR is alluring because it is theoretically less expensive than expanding existing infrastructure or constructing new pipeline and it incentivizes consumers of natural gas to defer or forego demand during periods of peak usage in exchange for compensation. Before we can determine the price of deferred natural gas consumption, however, we must establish its value.

What Is the Value of Natural Gas DR?

One of the reasons electric DR has been successful is that it reduces electric demand. Perhaps most importantly, it also has a clear, established value: the wholesale, retail capacity, and energy price that an electric DR provider typically receives for each negawatt of reduced demand that other market participants—like generators—are paid for each megawatt of delivered power.

There is no equivalent price for a nega-molecule of methane in natural gas markets. The price value of gas DR would have to be a negotiation due to an absent market structure. To provide an incentive for natural gas DR, the price would need to be equal to or less than the price paid for consuming the gas. A key challenge to determining the value of DR is that although natural gas prices can demonstrate significant volatility during periods of increased demand, many consumers of natural gas do not pay these high prices—at least not directly.

How Do We Develop a Price Signal?

Residential consumers, for example, purchase their natural gas supply and transportation through their local distribution company (LDC). The LDCs, in turn, typically rely on a variety of gas transportation and commodity supply plans with varying terms and prices. As part of their obligation to serve, the LDCs are required to build gas supply plans that mitigate the exposure of customers to volatility in prices. During a period of extreme increases in demand, the LDC may need to procure additional supply during certain days throughout the year, but these purchases are typically a small fraction of the overall daily demand. Most LDCs charge customers monthly, which causes the extreme price increases to become a small component of the overall bill.

Many commercial and industrial (C&I) customers, including power generators, purchase natural gas supply from a LDC. Larger C&I customers arrange transportation through an interstate or intrastate pipeline company to obtain their commodity via a marketer. Although the physical delivery arrangements are different compared to the residential sector, the economics are similar and the barriers to the development of a price signal for deferred consumption remain the same.

The absence of a clear price signal is a significant impediment to the adoption of natural gas DR despite the promise of providing a potentially less expensive means of alleviating pipeline constraints. Regardless of these challenges, natural gas DR offers a viable method to shift gas consumption during periods of peak demand.

Part 3 of our blog series will explore what utilities have tried for natural gas DR in the past and what new concepts could develop in the future.

 

Natural Gas Flaring: Time to Turn a $30 Billion Waste Stream into Profit, Part 1

— May 15, 2017

In 2015, an energy source equivalent to twice the total global solar production literally went up in smoke. That year, 147 billion cubic meters of associated natural gas was burned at the wellhead, releasing more than 300 million tons of CO2 into the atmosphere. Associated gas is a byproduct associated with petroleum wells, as opposed to wells built for natural gas production only.

What Is Flaring?

Globally, most associated gas is captured and put to use; however, flaring occurs due to a variety of technical, regulatory, and economic constraints. The light from these flares makes up a large part of the Earth-produced light that is visible from space. Indeed, the quantity and value of the gas is substantial. Amounting to 5.2 quadrillion Btu (known as quads), the flared gas would be worth about $30 billion annually if sold on major global markets (assuming a global value of $5.61 per million Btu, which is an average of the costs in the major markets of the United States, Canada, Germany, United Kingdom, and Japan in 2015).

There are a variety of reasons for flaring. In many cases, the amount of associated gas from oil operations is too small to justify the infrastructure needed to economically capture, compress, and transport it. Where it might be burned for electricity, there are often insufficient offtakers within 1- to 10-mile distances, over which electricity infrastructure is often worth building. Some countries, and even some oil companies, avoid pumping from locations that will require flaring, but flaring remains common practice in many cases.

Flaring Regulations and Economics

Flaring regulations take a variety of forms. In most of the world, flaring is regulated at the national level—a practice that has had mixed results. For example, Norway produces one-fifth the amount of oil as Russia, but burns less than one-fiftieth as much flare gas, due in part to stricter regulations. On the other hand, perverse incentives (with unintended consequences) also exist: the coffers in some countries (like Kazakhstan) count on the significant revenue generated by penalties for flaring, making crackdowns less likely there. Another perverse regulation exists in North America, where unlike most of the world, emissions are regulated at the state—or even regional levels—through air quality management districts or other entities. This has the advantage of tailoring regulations to local needs, but can also lead to administrative burdens and a lack of consistency across countries.

The economic choices related to flaring associated gas are complex, and the equations are changing as technologies and policies shift the energy landscape. However, the emissions associated with flare gas are substantial enough to merit scrutiny if countries are to meet their emissions targets for 2020, 2030, and beyond.

Part 2 of this blog series will look at some of the specific developments that will turn associated gas from waste into profits—for technology vendors, energy developers, and oil & gas companies. These developments include improved gas-to-liquids technologies, improved onsite combustion technologies, and access to electricity offtakers through microgrids.

 

Natural Gas Demand Response – Not Just for Electricity Any More: Part 1

— March 31, 2017

Coauthored by Jay Paidipati

Demand response (DR) in the electricity sector has been a common practice for decades for utilities and grid operators. When there are emergency situations or high prices, some residential customers and commercial and industrial (C&I) businesses are willing to reduce their electrical load or turn on distributed generation in return for financial compensation or the knowledge they are helping to maintain the grid. Historically, DR is less prevalent in the natural gas industry, but changing market factors have increased interest in the practice.

Similar to the electric side, some utilities offer large C&I natural gas users interruptible rates (IR). IR is an optional program between customers and the utility company that gives the utility company the right to shut off gas service to facilities in return for a reduced rate. It is a blunt instrument compared to customers shutting down parts of their operations to reduce gas usage. Some customers maintain backup gas storage onsite so they can switch to in case of interruption.

A more fine-tuned type of natural gas DR starts by putting communication devices at a customer’s site, then dispatching the device during critical times. The current implementation uses smart thermostats to control residential furnaces and slightly reduce temperature settings during peak heating times.

Why Natural Gas DR Now?

There is an indirect need for natural gas DR because of how it affects the electricity grid. In the past 5 years, natural gas has become the predominant fuel source for generation in many areas of the United States, often replacing coal and nuclear plants as they retire. However, the gas pipeline system was mainly designed to accommodate gas usage for end uses like cooking, heating, and cooling. The pipeline capacity did not anticipate large volumes flowing to power plants—especially in the winter when heating demand is highest.

The limited pipeline capacity was most evident during the polar vortex in January 2014, when pipelines were full but some gas generators could not get fuel, leading to electricity supply concerns and high energy prices. Since the polar vortex, other natural gas constraints and storage leaks have led to other fuel shortages. Some utilities and grid operators have instituted winter electric DR programs to address this concern, but curtailing natural gas usage is another.

The investigation into natural gas DR continues. Part 2 of this blog series will explore barriers to natural gas DR and which companies have successfully implemented it. Part 3 will explore what new concepts could develop in the future.

 

Blog Articles

Most Recent

By Date

Tags

Clean Transportation, Digital Utility Strategies, Electric Vehicles, Energy Technologies, Policy & Regulation, Renewable Energy, Smart Energy Practice, Smart Energy Program, Transportation Efficiencies, Utility Transformations

By Author


{"userID":"","pageName":"Natural Gas","path":"\/tag\/natural-gas","date":"5\/29\/2017"}