Memorandum submitted by the Department
of Energy and Climate Change (SG 01)|
UK ONSHORE OIL
& GAS ACTIVITY
1. The onshore oil and gas industry has been operating
in the UK for well over 60 years and production, although currently
only 1.5% of overall UK oil & gas total, nevertheless contributes
usefully to UK security of supply and to the UK economy.
2. Close cooperation between the industry and the
planning authorities has allowed the industry to develop with
minimal environmental impact. Alongside DECC licences and consents,
all exploration and development activities also need to be authorised
by the Health & Safety Executive .
3. Recent years have seen continued interest in
onshore oil and gas activity as the response to the 13th Round
in 2008 proved. That Round saw a good outcome with 97 licences
awarded in total confirming the continuing commercial attractiveness
of onshore oil and gas exploration opportunities in the UK, and
there was renewed interest in coal bed methane.
4. Current estimates suggest that overall onshore
potential proven and probable reserves equate to around 1.5%-2%
of the UK's overall reserves. Government wants to ensure that
operators get the opportunity to explore and develop onshore -
and licensing is the first part of this process.
5. There are currently some 28 UK onshore oil fields
and 10 onshore gas fields in production. Overall UK onshore oil
production is around 24,000 barrels per day (2009). BP's Wytch
Farm field (Dorset) is the largest onshore oil field in Europe,
and, although production peaked over a decade ago, the field still
produces around 20,000 barrels a day (around 83% of UK onshore
6. In the UK, as elsewhere, gas (and oil) is predominantly
produced from permeable rock formations such as sandstones.
But there have been many attempts over the years to develop other
kinds of petroleum resources. The commercial development of
"unconventional" gas resources has been limited until
the last decade, when new production techniques have enabled a
rapid development of shale gas.
7. Natural gas can also be extracted from coal deposits
by drilling ("coal bed methane" or CBM - also known
as "coal seam gas"). The energy of coal can also be
exploited by gasifying the coal in the ground ("underground
coal gasification" or UCG), though the gas produced is not
"natural gas" (ie, predominantly methane), but a mixture
of combustible gases.
Conventional versus unconventional shale gas,
tight gas and coal bed methane (CBM)
UK POTENTIAL &
8. Although there may be significant resources of
unconventional gas in the UK, this has not so far been demonstrated.
It should not be assumed that the commercial success of shale
gas and CBM in the US will be transferable to the different geological
and other conditions of the UK. We are however encouraging exploration
and appraisal actively for both shale gas and coal bed methane.
The Coal Authority is similarly encouraging exploration and appraisal
for underground coal gasification actively.
9. DECC aims to launch a new (14th) onshore
round this year, and expects a fair amount of interest from the
industry, for both conventional and unconventional prospects.
10. The map below shows the location of CBM wells
drilled, the three approved CBM developments, the Underground
Coal Gasification licences awarded by the Coal Authority, the
current onshore licences and the area under consultation which
may be offered in the 14th licence round.
Map showing onshore licences, coal bed methane
activity, and potential 14th Round licence acreage.
11. The Technology - Shale gas is natural
gas produced from shale. Shale has low permeability, so gas production
in commercial quantities requires fractures to provide permeability.
Although a small amount of shale gas has been produced for years
from shales with natural fractures, the shale gas boom in recent
years has been due to modern technology in hydraulic fracturing
where fluid is pumped into the ground to create fractures to make
the reservoir more permeable, then the fractures are propped open
by small particles, and can enable the released gas to flow at
commercial rates. Horizontal drilling is often used with shale
gas wells, with lateral lengths up to 10,000 feet within the shale,
to create maximum borehole surface area in contact with the shale.
The US experience suggests that successful production techniques
are quite specific to particular formations.
Ranges of Total Organic Carbon in typical tight
gas sand, shale gas, and coal bed methane prospects
12. As the diagram above shows, there is a continuum
of unconventional gas prospectivity from tight gas sands, gas
shales to coal bed methane (CBM).
13. Some conventional sandstone wells that failed
to flow gas are being re-examined in light of American tight gas
successes and 56 billion cubic metres (bcm) of tight gas potential
reserves have been identified in the sandstone reservoirs of the
Southern North Sea.
14. Gas can be found in the pores and fractures
of rocks but also bound to the matrix, by a process known as adsorption,
where the gas molecules adhere to the surfaces within a shale
or a coal.
15. UK Potential - While there is growing
interest in European potential for shale gas, the UK potential
is as yet untested. The UK shale gas industry is in its infancy,
and ahead of drilling with fracture stimulation and testing, there
are no reliable indicators of potential productivity. There is
variable data available on the geology, depending on whether oil
and gas exploration has been undertaken and the extent of existing
seismic data available.
16. A DECC commissioned British Geological Survey
(BGS) study has recently concluded that, with the present state
of knowledge about relevant UK geology, the only means of estimating
the resource is by analogy with similar shales which have been
successfully exploited in America. The study has been placed
on DECC's Oil and Gas website and can be found via the following
It is also attached to this report for ease of reference.
17. If the prospective shale area of UK shale gas
potential did prove to be as prolific as the analogous basins
in the US, it could be of the order of 150 bcm of gas (900 million
barrels of oil equivalent). To put this in context, this compares
with the UK's overall remaining conventional oil and gas reserves
of some 20 billion barrels (including offshore).
18. However it is not yet clear whether there is
any economic shale gas resource in the UK, as testing of our shales
may show them to be less productive that those in the US. In
addition, bearing in mind planning and environmental issues, it
would be unrealistic to assume that the drilling density achieved
in the US (thousands of wells) could be replicated in the UK.
So this figure may be more representative of the theoretical
top end reserves, rather than what it might be ultimately recoverable
through practical development.
19. The Technology - In addition to exploiting
methane from abandoned and existing coal mining operations, the
opportunity also exists to exploit methane which is still locked
into the reserves of coal and coal measures strata that remain
unworked. This concept is referred to as Coal Bed Methane
since it involves directly drilling into unworked coal and coal
measures strata to release methane held (or adsorbed) within the
coal. CBM offers a method of extracting methane without detrimentally
affecting the physical properties of the coal.
20. UK Potential - In the last 5 years over
40 CBM exploration and appraisal wells and 12 pilot production
development wells have been drilled. IGAS and Nexen are generating
electricity from CBM production, a first for the UK, at their
Doe Green development, near Warrington and are currently flow
testing in Staffordshire at Keele Park as part of the Potteries
CBM development. In Scotland, Composite Energy drilled 18 multi-lateral
wells in their Airth CBM development, which is currently suspended,
but produced water and gas in 2008 and 2009.
21. The theoretical CBM resource in the UK is estimated
to be 2900 billion cubic metres (bcm) using only coals with the
right depth, thickness, gas content, and separation from underground
mine workings. Given that the 2009 annual UK natural gas consumption
was approximately 86 bcm this corresponds to about 33 years consumption.
However, the part of this CBM resource that is economically
viable to produce is likely to be very much smaller, possibly
around 10% or less. This is largely due to perceived widespread
low seam permeability, low gas content, resource density and planning
constraints. More drilling and testing is necessary to refine
the estimate. At the moment only modest amounts of CBM gas has
been shown to be economic and realistic estimates of the size
of the resource are not possible until drilling and production
demonstrates more generally the economics of production in UK
conditions. A BGS study on UK CBM potential is available on DECC's
Oil & Gas website at: https://www.og.decc.gov.uk/upstream/licensing/cbm.pdf
22. The Technology: UCG is the partial in-situ
combustion of a deep underground coal seam to produce a gas for
use as an energy source. It is achieved by drilling two boreholes
from the surface, one to supply oxygen and water/steam, the other
to bring the product gas to the surface. This combustible
gas can be used for industrial heating, power generation or the
manufacture of hydrogen, synthetic natural gas or other chemicals.
The technique has not yet been demonstrated to be commercial anywhere
in the world, though there is one long-running project in Uzbekistan.
23. UK Potential: Although trials were conducted
in the UK as long ago as the 50s, the technical and economic viability
of underground coal gasification (UCG) has not to date been demonstrated.
It is too early to judge, therefore, what contribution this fledgling
technology might make to future UK energy needs. Notwithstanding,
there is active interest in the sector's potential. The licensing
body, the Coal Authority, has over the last year or so granted
14 Conditional Licences for UCG (all in relation to undersea reserves).
DECC is monitoring progress with interest and continues to work
with other parties (the Coal Authority, Environment Agency) to
help ensure clarity around the regulatory aspects of the process.
What are the prospects for shale gas in the UK
and what are the risks of rapid depletion of shale gas resources?
24. The Namurian Bowland Shales in the Lancashire
basin (which are the source rock for the Irish Sea fields) are
the most prospective, but also the Jurassic Kimmeridge and Lias
shales (source rocks for the North Sea and English Channel fields)
are being considered in the Weald basin in southern England. Indications
of gas have often been encountered while drilling through these
shales for conventional exploration of sandstone and limestone.
25. The first UK exploration well designed to
evaluate shale gas potential, using state-of-the-art fracture
stimulation and testing procedures, is currently drilling west
of Blackpool (Cuadrilla's Preese Hall 1 well), shown on the far
right (North end) of the diagram below.
Cross section from England's south coast to the
Lancashire basin near Blackpool
26. Reserves can be estimated for conventional oil
and gas prospects by applying a recovery factor to the hydrocarbons
in place, but for shale gas, the reserves are dependent upon the
number of wells drilled, the success of the fracture stimulation,
and the use of horizontal drilling to increasing the area that
can be drained around each borehole.
27. Shale gas success can only be measured after
a number of wells are drilled and tested. The initial production
rates and ultimate recovery of gas for each well then are averaged
to estimate the reserves in the various parts of a large shale
28. An estimate of UK potential can only be made
by analogy to productive areas. On an area basis, comparing the
size of the prospective UK Namurian Carboniferous (Upper Bowland
Shale) shale to the Barnett Shale play in Texas, the Lancashire
basin could potentially yield up to 133 bcm of shale gas. If the
onshore UK Jurassic shale gas play is analogous to the Antrim
Shale in Michigan, the Weald/Wessex basin could potentially yield
6 bcm recoverable shale gas. There is higher risk potential in
older shales, and some offshore potential too.
29. However, as noted above, it is difficult to
imagine that a US model for shale gas development, with thousands
of wells in each trend, can be replicated in the UK. Planning
and environmental considerations are likely to limit the number
of surface locations from which wells can be drilled, but there
is hope that a smaller scale development with numerous horizontal
wells from central sites could be economically viable. But it
is too early in UK shale gas exploration to know if commercial
development can be established.
30. Unlike some other countries where landowners
own the oil and gas under their land, in the UK the Crown controls
the right to produce hydrocarbons. DECC licenses these rights
to exploit oil and gas resources; and, together with the environmental
control through the planning system (by Local Authority supported
by the Environmental Agency and other consultees), and safety
regulation (by the Health and Safety Executive), this should result
in a well ordered development of the resource. This has already
been achieved with the UK's long experience of development of
its more conventional onshore oil and gas resources.
Risks of Rapid Depletion of Shale Gas Resources?
31. While there has been debate in the industry
regarding the forecasting of future shale gas production profiles,
it is too early to know what decline rates we might experience.
We don't yet have UK data to estimate the initial production
rate, the initial rate of production decline, and the degree to
which that initial decline rate flattens out over time. We have
significant potential reserves - but no proved prospectivity for
shale gas, and only pilot production data for CBM.
What are the implications of large discoveries
of shale gas around the world for UK energy and climate change
Prospects for further production in the US
32. Production of unconventional gas in the US is
expected to increase with the growth in unconventional gas production
being driven largely by shale gas production rising from 14% of
total consumption (around 3 trillion cubic feet) in 2009 to 45%
(around 12 tcf) in 2035, according to the EIA (US Energy Information
Administration) chart below.
U.S. DRY GAS PRODUCTION (TRILLION CUBIC
FEET A YEAR) BY SOURCE: 1990 - 2035.
Source: US Energy Information Administration
33. This growth is expected to help put downward
pressure on the US's demand for imports. The US's net imports
peaked in 2007 at around 3.5 trillion cubic feet of gas, most
of which was imported from Canada. The US's net imports are projected
to fall from 2.6 tcf in 2009 to 1.3 tcf in 2025 and 0.3 tcf in
2035. The EIA are expecting imports of gas from Canada and from
LNG to fall over the next two decades.
34. The EIA has continued to revise up its expectations
for shale gas production and the impacts this will have on the
US market. For example in contrast to the Annual Energy Outlook
2010 reference case, the EIA now:
doubled the technically recoverable unproved reserves of shale
- Projects higher shale gas production;
- Projects lower US prices;
- Projects lower total U.S. net imports of LNG
(due in part to less world liquefaction capacity and greater
world regasification capacity, as well as increased use of LNG
in markets outside North America); and
- Assumes the Alaska pipeline will not be constructed
as projected due to both the projected lower US prices and higher
capital costs which makes this unattractive.
It should be noted that such projections are sensitive
to a number of assumptions, relating for example to the pace of
technological innovation and economic growth.
35. The impact of further growth in gas production
in the US on global markets will depend on a number of factors:
- The extent to which the increase in production
is offset by increases in US demand for gas;
- The extent to which it exceeds, or falls below,
market expectations and therefore helps push the global market
into over- or under-capacity; and
- Whether the US will be able, and the extent to
which it will be able to export natural gas in other markets.
Prospects for unconventional gas production in the
rest of the world
GLOBAL UNCONVENTIONAL NATURAL GAS RESOURCES
IN PLACE (trillion cubic metres)
|Middle East and North Africa||23
|Former Soviet Union||25
|Central Asia and China||10
|Central and Eastern Europe||2
Source: Rogner (1996), Kawata and Fujita (2001), Holditch (2006).
Taken from World
Energy Outlook 2009 table 11.3, International Energy Agency.
36. While North American production is expected to continue to
increase, there are significant uncertainties over the extent,
the timing and the location of production elsewhere in the world.
This is due to a number of factors including:
- the limited understanding of reserves: The table above
shows estimates for the unconventional gas reserves thought to
be in place in various regions across the world. On these estimates,
the resource could be very large. For comparison, global consumption
of gas is around 3 tcm per annum.
However, comprehensive assessments are few and far between.
And there is a lack of production experience outside the US, which
leaves substantial uncertainty about how much of the resource
might ultimately be producible. Nonetheless, the current IEA
estimate is that around 380 tcm could be recoverable based on
current data. This compares to an estimated 404 tcm of recoverable
conventional reserves and 184 tcm of proven gas reserves;
- prices: the price required to incentivise investment will
depend on a number of factors, such as the productivity and
cost of the well, access to transport infrastructure etc. The
IEA has estimated recoverable unconventional resources can be
produced at prices between $2.7/MBtu
and $9/MBtu in the US;
- environmental controls and population density: unconventional
production is more land intensive than traditional methods. Either
factor could restrict development, particularly in Europe which
has high population density and a well developed regulatory framework;
- land ownership: US legislation differs from most, including
that in Europe, in that it grants landowners rights over hydrocarbon
resources rather than conferring ownership on the state. This
has provided a huge incentive for landowners to agree to invasive
drilling on their property. The lack of such an incentive could
be particularly significant in parts of Europe with strict planning
- availability of infrastructure: the US and Canada have
highly developed gas grids, something that is lacking in China,
India and some other potential sources of unconventional gas;
- access to technology and expertise: the technology
required to exploit unconventional resources is highly specialised
and has been largely, though not entirely, confined to the US.
37. Notwithstanding the uncertainty it is clear that there is
potential for additional gas to be brought to market in large
volumes. Should this be the case, there could be significant
impacts on global energy markets and climate change.
38. Price implicationsThe unexpected growth in
unconventional gas production in the US has already, in conjunction
with other factors, helped to depress UK and global spot wholesale
gas prices over the course of 2009 by reducing the US need for
LNG imports, although recently UK wholesale prices have rebounded
strongly. Over the medium and long-term, the impact of new sources
of unconventional gas on prices is uncertain. Increased supply
of gas via increased production of unconventional is likely to
reduce gas prices going forward. However, instead there might
be upwards pressure on gas prices if expectations of unconventional
gas being brought to market leads to under-investment in conventional
gas or other energy sources. The EIA expects unconventional gas
to exert downward pressure on natural gas price. Natural gas
wellhead prices in AEO2011 (in 2009 dollars) only reach $6.53
per thousand cubic feet in 2035, compared with $8.06 in AEO2010
due in part to increased estimates on recoverable shale gas resources.
39. Security of supplythere is potential for security
of supply to be improved due to the opportunities for consuming
countries to diversity across a wider range of sources of supply.
40. Climate implicationsincreased unconventional
production would result in lower emissions if it displaces fuels
such as coal that are associated with higher emissions. However,
the potential downside from reduced emissions in the short- to
medium-term is that this reduces the incentive to invest in developing
and deploying the low-carbon alternatives required to meet longer-term
emission goals. If gas was to play a major longer-term role, this
would suggest a greater need for effective CCS technology for
gas plants. Tighter national emission targets and policies to
support innovation and deployment of low-carbon technologies could
be used to reduce these risks. With such measures, the increased
use of gas could be an effective bridge to help deliver greater
41. To reduce the uncertainty posed by these issues, the Department
intends to closely monitor developments and will consider the
need for additional research to improve our understanding of the
implications for policy. In the meantime, DECC is continuing
to liaise with the energy industry and academia as knowledge and
What are the risks and hazards associated with drilling for
42. The safety risks and hazards associated with drilling for
shale gas should be no more onerous than those associated with
drilling for any other hydrocarbons by a borehole (for instance,
the worse case being a blow out leading to the release and possible
ignition of gas).
43. The process of extending the borehole to the shale formations
of interest, will follow those used for conventional drilling
of oil and gas wells, with a number of casings of reducing diameter
being run and cemented to form a conduit to surface. The principle
of dual barriers to any potential flow of fluid will be maintained
and equivalent safety features for the production phase of shale
gas will be in place i.e. sub surface safety valves.
44. The risks to people from drilling a borehole for hydrocarbons
under a production, or exploration and appraisal, license
will be regulated by the Health and Safety Executive (HSE).
45. UK legislation requires the operator to assess not only the
risks and hazards above ground but also those associated with
the sub surface aspects of the operations. The operator must notify HSE
of any proposed drilling operations which will allow a dialogue
to start on the management of the risks that have been identified.
46. More generally environmental risks of shale gas development
have received some media attention in the US and have even resulted
in a hydrofrac drilling ban in the state of New York which flanks
the successful Marcellus shale trend. It is claimed that
some incompetent operators have allowed gas to contaminate shallow
aquifers, which should not be possible with proper well casing
47. The use of large quantities of water for fracture stimulation
in areas with limited water supply and the safe disposal of the
recovered fluids have also been reported as contentious in the
US. Public health concerns there have resulted in a demand for
greater transparency regarding the chemical composition of the
fracture stimulation fluid and the US Environmental Protection
Agency have recently changed their requirements. In the US, where
the landowner owns the mineral rights, directly benefiting from
drilling, consent to dense drilling has been allowed with reported
possible negative effects on local communities.
How does the carbon footprint of Shale Gas compare to other
48. The carbon intensity of natural gas from shale formations
varies between various shales and depends on the extraction process
and emission management. Both the greater number of bore holes
required to be drilled for shale gas in relation to field gas
and the process of hydraulic fracturing of the rock add to the
energy and carbon footprint of the extraction process. This carbon
footprint can be increased further by fugitive emissions of methane
released directly to the atmosphere as a result of the fracturing
49. Little investigation has been undertaken into the size and
variability of greenhouse gas emissions from the extraction process
and even less has been conducted on the potential impact of fugitive
methane emissions. Estimates of the carbon intensity of shale
gas should therefore be treated with caution until peer-reviewed
work is available. However, providing that fugitive emissions
of methane can be managed adequately, shale gas can be expected
to have a carbon intensity greater than that of natural gas from
conventional fields, but significantly lower than that of coal.
NB: 1 tcf is equal to around 28.3 bcm. Back
WEO 2010, Table 5.1, Primary natural gas demand by region and
scenario (bcm), page 181. Back
Millions of British thermal units. Back