What is Tight Gas?

Since its production is tied to technological developments, well cost, and fraccing gas prices, tight gas is an economic issue
This article appeared in Vol. 9, No. 3 - 2012


Numbers of rigs allocated to oil and gas drilling in the US and the relationship to the ratio of the oil spot price to the gas spot price. Source: US wellhead gas prices since 1989. Source: US dry natural gas production since 1990: tight gas now accounts for nearly 30% of production. Source: EIA, Annual Energy Outlook 2011 A practical definition of a tight gas field at present is one that can be made economic with a combination of horizontal wells and fracture stimulation. Production and permeability guidelines are relative to technology development, well cost, frac cost and current gas price. As technology has developed the permeability guideline, at least onshore, has changed from <0.1mD in the 1970s to <0.01mD today and arguably to <0.001mD in the US.

Comparing USA and Europe

Rotliegendes Basin and active tight gas areas. Source: Dr Andy Sims, Merlin Energy Resources Outcrops of the Rotliegendes sandstone, such as this one near Cullercoats, north-east England, typically show significant small scale faulting with cementation and offsets – all indicating flow barriers likely to impact on recovery from subsurface gas reservoirs. Source: Dr. Tim Wright, Merlin Energy Resources A comparison between the US and Europe is instructive. The US was the largest volume producer in the world from the 1870s through to the 1960s. It had developed a large and competitive service industry, with over 2,000 active rigs and a countrywide natural gas pipeline grid by the time gas demand began to exceed supply in the 1970s. The shortages were addressed by deregulation of the gas price and by US government-funded R&D and tax incentives to create the technology required for tight gas development. It was in the 1970s that the United States government defined a tight gas reservoir as one in which the permeability to gas flow was less than 0.1 mD. This definition is now defunct but was used to allocate federal and state tax credits for producing gas from tight reservoirs. In addition, the National Energy Technology Laboratory (NETL), part of the US Department of Energy (DOE), invested significant funds in developing the essential science to characterise and produce tight gas and the Gas Research Institute and industry cooperated to launch the early technology demonstrations.

The results have been remarkable. Not only has tight gas grown from almost non-existent production levels in the early 1970s to account for close to 30% of current US production, but the technology was further developed to produce coal bed methane and then shale gas. In combination, these are now responsible for some 50% of US production and are all forecast to continue to grow. Gas price played a role. It stayed close to $2/Mcf through to the end of 1999 but then rose to peak above $10/Mcf in mid-2008. Inevitably, independents were encouraged to develop formerly marginal assets such as tight gas in Jonah, Pinedale and Bossier and coal bed methane in Powder River and San Juan. The real breakthrough came after 2002 when it was demonstrated in the Barnett and Fayetville gas shales that high rates of gas production could be achieved by using intensively stimulated horizontal wells. Natural gas production from shallow, fractured shale formations in the Appalachian and Michigan basins of the US had existed for decades; the ‘game changer’ was the recognition that intensively stimulated horizontal wells could create a reservoir. Typical Barnett completions developed from 500m to 1,000m and the number of fracs from 5 to 12.

Gas development was so successful that by the end of 2008 there was an oversupply of about 5 Bcfpd, prices fell to circa $4/Mcf and the total rig count halved. By mid-2009, however, the rig count was again on the increase because higher relative crude prices encouraged operators to drill for crude oil and natural gas liquids. This shift can be clearly seen in the redistribution of the US rig fleet since mid-2009. Futures prices 3 years forward are now $25/barrel less than the market price, indicating that the current success with oil development is expected to continue.

Lessons to be Learned

Thin section showing dolomite growth (hence permeability reduction) around quartz grains. Source: Dr. Neil Meadows Redrock International The lessons to be learned are that the US gas market is very flexible and driven by price, technology, an efficient service industry and a lack of ‘easy’ import possibilities. The gas plays had been known for 50 years, but it took the combination of technology development, shortage of supply and the increase in gas price to make them commercial, and when oversupply made further development unattractive operators switched rapidly to oil and gas liquids. It is also significant that it was the small independents that developed the tight and shale gas plays, growing significantly as a result.

In Europe it is very different. A large scale gas market developed after the discovery of Rotliegendes gas in 1959. It has been sustained by the development of Groningen (Netherlands), Salzwedel (Germany) and very large North Sea fields, principally by state companies and majors, and the ready availability of gas from the FSU and North Africa. As a result, tight gas has not received the attention it has in the US. Recent interest has been sparked by the US shale gas boom and Poland in particular has seen an increase in shale activity.

Cost is a barrier to successful tight gas development in Europe. Most European rig contractors have fewer than 10 rigs, are effectively unchallenged in their own geographical area because of language and other barriers to competition and rely on overseas work to keep going. There are currently about 30 land rigs working in Europe; 50 working is a peak, compared with close to 2,000 in the USA. At present 10 frac crews are available but not fully employed in Europe, while in the US more than 500 frac crews are busy. As a result of the limited capacity in Europe, costs for single wells are high but conversely the potential exists for large reductions for long term contracts. As an example, a ‘factory’ well drilled to 3,500m tvd (total vertical depth) and 1,200m horizontal with 14 frac stages can cost €6million in the US but as a single well project could cost €18million in Europe. Offshore, the same well could cost €58 million. Given a long drilling programme with repetition of the well design and a reduction in data requirements – pilot holes, cores, wireline logs – it is likely that Europe could get close to US costs onshore. Although US drilling is remarkably cost-effective, the efficiency and cost reduction in an extended field development comes from reducing data collection and cutting out inefficiencies. There is no reason why Europe cannot replicate the US experience if large scale development takes place.

Rotliegendes Tight Gas

So what is a typical tight gas reservoir? Most are sandstones where the original pore space has been reduced by lithifaction and diagenesis. A small percentage of production comes from fractured limestones, and natural fractures can play a role in production from tight sandstone reservoirs. A tight gas reservoir can be deep or shallow; high pressure or low pressure; high temperature or low temperature; blanket or lenticular; homogeneous or naturally fractured; and contain a single or multiple layers.

The major gas source in Europe is the Rotliegendes sandstones, a portion of which can be characterised as tight gas. Deposition occurred in a range of arid, terrestrial environments, wadi systems, aeolian deposits, desert-lake environments, and adjacent sabkhas. Compaction, pressure solution, and precipitation of diagenetic minerals all negatively impact the porosity and permeability of Rotliegendes reservoirs, but precipitation of fibrous illite is the most damaging diagenetic effect. Sandstones with the cleanest, best porosity at the time of deposition, and those sandstones deposited away from the water table tend to retain porosity and permeability. Fluviatile sandstones are commonly severely altered by diagenetic processes and tend to be those classified as tight. Small scale faulting with cementation and offsets are common in Rotliegendes outcrops and similar features are likely to act as subsurface flow barriers and further impact on recovery from gas reservoirs.

Development of Rotliegendes gas started in 1959 when Groningen was discovered onshore Holland (see GEO Expro Vol. 6, No. 4). In 1965 the discovery of West Sole proved that similar Rotliegendes sediments extended across the southern North Sea. Some 300 gas fields and 75 Tcf of recoverable natural gas have been discovered in the southern North Sea, and onshore in the Netherlands, Germany and Poland about 260 gas fields and 150 Tcf have been found. Unfortunately there is no equivalent of the EIA to record tight gas developments. A review of the technical literature, however, indicates that about 50 fields are described as tight, with over 300 slant and 100 horizontal wells drilled, amounting to reserves of around 7 Tcf. The potential is much greater; a joint industry/university study identified potential of 10 to 18 Tcf in tight Rotliegendes in the North German Basin alone.1

Fracture stimulation of individual tight Rotliegendes wells commenced in the 1970s and the first field development that relied on fracture stimulation was North West Leman in 1987. Fracture stimulation of slant wells proved generally successful but problems were encountered with fluid incompatibility, proppant back production and early water breakthrough due to fracturing into the water leg. During the early 1990s the emphasis moved to horizontal drilling2, which proved particularly effective in the UK sector, where a number of fields had productive natural fracture systems or wells encountered sweet spots. The use of multiple propped fractures in horizontal wells followed. Underbalanced drilling was introduced in the late 1990s but faded when it became clear that the increase in productivity did not compensate for the additional cost.3 The use of horizontal wells stimulated with multiple propped fractures is now the technology of choice for the development of tight gas.

Technology Transfer?

SEM Rotliegendes core – fibrous illite with wisps and strands bridging the pore throats. Source: Dr Neil Meadows In conclusion, tight gas development is a large-scale day-to-day business in the US and the technology and resources (trained manpower, equipment, business environment) allowed the development of shale gas. Tight gas has barely been tried in the rest of the world. Europe and Poland in particular has now jumped directly to shale gas appraisal and development without the benefit of the infrastructure and business environment built on the back of a tight gas industry. Success requires the technology to be transferred from the US – but how easily that can happen while trying to build critical mass is an interesting question.


1. Gaupp, R. et al., 2005. Adding Value through Integrated Research to Unlock the Tight Gas Potential in the Rotliegendes Formation of North-Germany, SPE 94354.

2. Tehrani, A.D.H., 1992. An Overview of Horizontal Well Targets Recently Drilled in Europe, SPE 22390-MS.

3. Veeken, C.A.M. et al. Underbalanced Drilling and Completion of Sand-Prone Tight Gas Reservoirs in Southern North Sea, SPE 107673.

About the Author

Roy Hartley graduated as a petroleum engineer from Imperial College in 1969. He witnessed his first frac in the Rotliegendes in the same year. He is currently Chief Operating Officer for Aurelian Oil and Gas.


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