Unconventional Gas

Unconventional gas refers to gas produced from coal-seams (‘coal-seam or coal-bed methane’), shale (‘shale gas’) rocks and rocks with low permeability (‘tight gas’). Once gas is produced from these reservoirs, it has the same properties of gas produced from ‘conventional’ (ie: sedimentary reservoirs with high porosity and permeability) sources. Unconventional gas may have high levels of Natural Gas Liquids (an exception is coal-seam gas which tends to be very ‘dry’ with high proportion of methane vs NGLs), may have low or high levels of carbon dioxide and high and low levels of sulfur (ie: ‘sweet or sour’). Because unconventional reservoirs have low permeability, artificial methods to increase gas flows, such as mechanical or chemical ‘fracking’, is often required before the wells are able to produce commercial quantities of gas.The growth of gas produced from unconventional sources is truly remarkable, especially in North America and Australia. According to the US Energy Information Agency (EIA), US shale gas production was 5% of total US dry gas production in 2004, was 10% in 2007, and is now over 56%.2 The growth of shale gas, in particular, has dramatically disrupted the global gas markets. The United States was expected to become a large importer of LNG because of increasing demand and declining conventional gas production; however, because of the large and relatively cheap shale gas fields that have been developed over the past decade, the United States (and Canada) is now poised to export LNG and has forced other exporters, especially in the Atlantic basin, to alter their marketing efforts. It is now likely that long-term US natural gas prices will stay at levels of $3.50/MMBtu or below for the foreseeable future because of the enormous volumes of shale gas that can be produced at or below this price level.

Coal Bed Methane
Similar to the process of conversion of organic matter to natural gas, the natural conversion of organic materials to coal also generates large amounts of methane. Methane is stored within the coal beds in much larger quantities per volume of rock than conventional gas reservoirs. 

Much of coal, and thus much of the methane contained within the seams, occurs close to the surface. This allows cheaper exploration and production from less-expensive, but less-productive (because of lower reservoir pressure), shallow wells. Methane produced from coal seams is called coal bed methane (CBM), coal seam methane, or coal seam natural gas. Other than usually having a lower heat value because of the lack of heavier gas compounds, it is similar to gas produced from conventional gas reservoirs. Once it is produced, it is transported and marketed like conventional natural gas.

In conventional hydrocarbon reservoirs, gas overlies oil, both of which overlie adjacent water aquifers. Perforations are selectively placed to maximize production of hydrocarbons and reduce production of water. In contrast, water permeates coal seams, and water pressure traps any CBM present. Producing CBM requires first removing water to decrease pressure on the coal matrix, allowing free gas to flow into the wellbore (fig. 1–29). The water is usually saline, and disposing of it can add considerably to the cost of CBM production. Water production is especially a problem in the early stages of production, when large amounts of water are produced to decrease trapping pressure on the methane. A general rule of thumb is that conventional gas is relatively difficult to find but easy to produce, whereas unconventional gas, such as CBM, is easy to find but relatively difficult to produce—and may require constant water removal to maintain production levels.

Conventional gas is produced from relatively homogeneous reservoirs with predictable drainage and flow rates. By contrast, coal seams are variable in terms of their thickness, gas saturation, and depositional environment. Consequently, the production profile of CBM is very different from that of conventional gas production (fig. 1–30). Conventional gas field development requires large initial capital investments and relatively low operating expenses. Consequently, as reservoir pressure declines, the gas field exhibits a steep production volume decrease. CBM fields require ongoing well drilling and water disposal investments; however, this results in a longer “plateau” production profile and longer field life.

According to EIA, the United States has estimated proved CBM reserves of 15.7 tcf as of 2014. Estimated production of coal-bed natural gas was 1.40 tcf in 2014, equating to around 5% of natural gas production in the United States.3 Large CBM reserves are found in Canada, China, and Australia. Many regions, such as in the United States, have offered tax incentives to encourage production of CBM resources. Other nations, such as Indonesia, have large CBM potential, but fiscal terms and legal complexity have limited production to date. As expected, interest in CBM increases with high gas prices and where associated infrastructure, such as gas pipelines, is already present.

Australia is home to the only LNG projects based on CBM reserves. In other countries, CBM gas is typically injected into the natural gas network or is used to generate power close to fields. Supplying the three Eastern Australian CBM-to-LNG projects with current total capacity of 24 million metric tonnes annually (MTA) requires hundreds of CBM wells to be drilled every year for the life of the LNG project. Even though the wells are generally less deep and simpler to produce than conventional wells, the scale of this effort raises significant project risks. Because CBM reservoirs are not homogeneous, well designs have to be tailored to each location, and future well costs are not easy to estimate. For example, the 8-MTA GLNG project in Australia requires gas from more than 500 wells, plus a further 800 wells, drilled over 20 years to produce 5 tcf of feed gas. By contrast, a conventional LNG project of similar size, such as Pluto LNG in Western Australia, is expected to receive all its feed gas from only five or six wells, with one or two additional wells every 5–10 years. 

Because of the ongoing well drilling and completion expense, CBM-to-LNG projects are more exposed to volatile LNG prices than conventional gas-based LNG projects, whose major expenses occur only in the early years of plant operation. In addition, CBM drilling results and volumes of waste water produced are not as consistent and predictable as project sponsors claim. Thus, the level and expense of the ongoing well drilling requirement is a “wildcard” that has to be absorbed in the project economics. Importantly, a large portion of the profits of most LNG projects comes from NGL (LPG and condensates) production. CBM-to-LNG projects do not get this benefit because CBM feed gas is dry.


Shale Gas
Shale gas refers to natural gas reservoir contained within layers of fine-grain clay and siltstone rocks commonly referred to as ‘shale’. Shale is the earth’s most common sedimentary rock, rich in organic carbon but characterized by ultra-low permeability. Permeability refers to the ability of the rock to allow gas to flow. Gas can either flow via natural fractures within the rock, or fractures must be artificially created.

Shale has always been regarded as the source of gas which eventually migrates to sandstones and carbonates and is produced as ‘conventional’ gas. However, not all the gas produced in the shale migrates to these higher permeability rocks. Over the past few decades, technological advances, especially horizontal drilling and artificially increasing the permeability of the shale (via mechanical or chemical ‘fracking’ stimulation to create artificial fractures) have facilitated the economic production of shale gas. Improvement in well completion and drilling efficiency are also key factors in unlocking this large resource.

Shale gas formations are often found at depths similar to or even deeper than conventional reservoirs, often 1,500–4,000 meters below the surface. Horizontal drilling begins by drilling a simple vertical well down to a predetermined point, commonly referred as the kickoff point, and from here onward the well makes a 90° turn and could extend up to several kilometers horizontally. Thus, the well may actually drain a reservoir many kilometers from its surface location.

For prevention of groundwater contamination, several layers of steel casing are cemented into the wellbore to prevent gas contamination with water tables. Fracturing is only done after the cement bore has been checked. This technique has been safely used in millions of wells worldwide but continues to attract controversy—often as a result of a distortion of facts by antigas activists who have fixated on fracking as a new and ultimately evil process. Numerous studies have shown many of the arguments against fracking to be baseless and impacts on groundwater minimal when regulations are followed and enforced. 


Shale gas discoveries have added a substantial amount of US gas reserves. Outside of the more developed Barnett shale play in Texas, the DOE estimates four major shale plays (Haynesville, Fayetteville, Marcellus, and Woodford) may account for 550 tcf of gas, or ~30% of the ~1,750 tcf (2013 numbers) of technically recoverable reserves in the US. Shale gas is becoming increasingly important to annual US gas production as well. Major shale gas reservoirs accounted for about 40% of new onshore gas production in 2009.

 Shale gas success factors

  • Limited gas reserves driving increased prices. From the 1970s until the 1990s, the U.S. faced declining reserves, demand growth and escalation in natural gas prices. There was growing dependence on imports from Canada and construction of plans for significant LNG import capacity. This created the impetus for alternative exploration methods resulted in dramatic growth in shale gas development that began in the late 1990s.
  • Technological advances in horizontal drilling and fracturing techniques
    These advances include as longer laterals, expanded numbers of frac stages per well, pad drilling, and simultaneous operations. The technology, coupled with lean, factory-like practices, has shortened drilling and completion times, reduced costs, and raised initial production levels, making these plays cost effective. One Marcellus shale operator reported bringing drilling and completion costs per frac stage down by 50% between 2008 and 2009 by applying technical and efficiency improvements
  • Nimble independent exploration and production companies, working with service providers to advance conventional technologies into unconventional gas Major energy company were completely absent from early shale gas activities. Independents have decentralized corporate structure that enables quick, in-the-field decision making in crucial areas, such as asset/land acquisitions and key operational decisions during the drilling and completion processes.
  • Availability of capital. The US has a very developed financial system allowing small companies access to capital and equity. Smaller independents formed JVs with larger companies and National Oil Companies allowing the larger partners to fund operations
  • Relatively easy access to land, fueled by the private ownership of surface and mineral rights and industry-friendly regulations.
  • Mineral rights ownerships allow profit sharing with land owners, which provide strong financial incentives to cooperate with industry developing shale resources.
  • U.S. government’s stance to date has been relatively positive towards the oil and gas industry.

Other countries that are hoping to replicate the US shale growth experience include Canada, China, Australia, Poland, Argentina, Brazil, Indonesia and India. However, their success will be dependent on the elements listed above.