Importance of low-permeability natural gas reservoirs
Introduction
Production from low-permeability reservoirs, including shale gas and tight
gas, has become a major source of domestic natural gas supply. In 2008,
low-permeability reservoirs accounted for about 40 percent of natural gas
production and about 35 percent of natural gas consumption in the United
States. Permeability is a measure of the rate at which liquids and gases
can move through rock. Low-permeability natural gas reservoirs encompass
the shale, sandstone, and carbonate formations whose natural permeability
is roughly 0.1 millidarcies or below. (Permeability is measured in “darcies.”)
The use of hydraulic fracturing in conjunction with horizontal drilling
in shale gas formations and the use of hydraulic fracturing in tight gas
formations has opened up natural gas resources that would not be commercially
viable without these technologies. As shale gas production has expanded
into more basins and recovery technology has improved, the size of the
shale gas resource base in the AEO has increased markedly. Because the
exploitation of shale gas resources is still in its initial stages, and
because many shale beds have not yet been tested, there is a great deal
of uncertainty over the size of the recoverable shale gas resource base.
Low-permeability gas wells typically produce at high initial flow rates,
which decline rapidly and then stabilize at relatively low levels for the
remaining life of the wells.
To illustrate the importance of low-permeability natural gas reservoirs
for future U.S. natural gas supply, consumption, and prices, three alternative
cases were developed for AEO2010: a No Shale Gas Drilling case, a No Low-Permeability
Gas Drilling case, and a High Shale Gas Resource case. The No Shale Gas
Drilling and No Low-Permeability Gas Drilling cases examine the implications
of no new drilling in low-permeability formations. The High Shale Resource
case examines the possibility that shale gas resources could be considerably
greater than those represented in the Reference case. The three alternative
cases are not intended to represent any expected future reality. Rather,
they are intended to illustrate the importance of low-permeability formations
for EIA’s projections of future U.S. natural gas supply and are likely
to be extremes. All the cases assume no change from the Reference case
assumptions about the size of, and access to, Canadian and other international
natural gas resources. Specific assumptions in the three cases are as follows.
No Shale Gas Drilling case. Starting in 2010, in this case no new onshore
lower 48 shale gas production wells are drilled. Natural gas production
from shale gas wells drilled before 2010 declines continuously through
2035.
No Low-Permeability Gas Drilling case. Starting in 2010, in this case no
new onshore lower 48 low-permeability natural gas production wells are drilled,
including shale gas wells and “tight” sandstone and carbonate gas wells.
Natural gas production from low-permeability wells drilled before 2010
declines continuously through 2035.
High Shale Gas Resource case. In this case, the unexploited portion of
each shale formation supports twice as many new wells as in the Reference
case. The lower 48 shale gas resource base increases by 88 percent, from
347 trillion cubic feet in the Reference case to 652 trillion cubic feet
in the High Shale Gas Resource case. The estimated recovery per well in
each formation is the same as in the Reference case.
Natural gas supply, consumption, and prices
Low-permeability natural gas resources are more abundant and less expensive
than other domestic natural gas supply alternatives that could replace
them, and they are expected to play a significant role in future domestic
natural gas markets. Consequently, their future absence or presence is
expected to have a significant impact on the average cost of natural gas
production and prices, which in turn would affect natural gas imports and
consumption. In the No Shale Gas Drilling and No Low-Permeability Gas Drilling
cases, lower 48 onshore natural gas productive capacity is less than in
the Reference case, and as a result average U.S. natural gas prices are
higher, more natural gas is imported, and natural gas consumption is reduced
(Table 7). Conversely, in the High Shale Gas Resource case, natural gas
productive capacity is higher, natural gas prices and imports are lower,
and consumption is higher than projected in the Reference case.
No Shale Gas Drilling and No Low-Permeability Gas Drilling cases
In the No Shale Gas Drilling and No Low-Permeability Gas Drilling cases,
total domestic natural gas production in 2035 is 18 percent and 25 percent
lower, respectively, and onshore lower 48 production is 27 percent and
39 percent lower, respectively, than in the Reference case. The loss of
onshore lower 48 productive capacity leads to higher natural gas prices
and lower consumption levels. In the No Shale Gas Drilling and No Low-Permeability
Gas Drilling cases, the Henry Hub spot price for natural gas in 2035 is
$1.49 and $2.00 per million Btu higher, respectively, than the Reference
case price of $8.88 per million Btu. The significantly higher natural gas
prices are a result of the removal of considerable low-cost natural gas
resources, leaving a smaller natural gas resource base that is more expensive
to produce.
Because higher domestic natural gas prices make other supply sources more
competitive, both offshore Gulf of Mexico production and net natural gas
imports increase in the No Shale Gas Drilling and No Low-Permeability Gas
Drilling cases. Offshore natural gas production levels in 2035 are 7 percent
and 18 percent (0.3 trillion cubic feet and 0.8 trillion cubic feet) higher,
respectively, than in the Reference case, and net imports are 154 percent
and 207 percent higher (2.2 trillion cubic feet and 3.0 trillion cubic
feet). In 2035, net imports make up 6 percent of total U.S. natural gas
supply in the Reference case, 16 percent in the No Shale Gas Drilling case,
and 20 percent in the No Low-Permeability Gas Drilling case. The higher
levels of net imports in the two alternative cases are the result of increases
in LNG imports and imports from Canada, as well as a reduction in exports
to Mexico.
In 2035, net LNG imports in the No Shale Gas Drilling and No Low-Permeability
Gas Drilling cases are more than double those in the Reference case (1.8, 2.4,
and 0.8 trillion cubic feet, respectively), and net natural gas imports
from Canada are 52 percent and 59 percent greater, respectively, in the
two alternative cases than in the Reference case. Because the assumptions
in these cases are not applied to the Canadian natural gas resource base,
higher U.S.prices lead to more natural gas production in Canada (including Canadian
shale gas). In addition, Canada’s Mackenzie Delta natural gas pipeline
begins operating before 2035 in the two alternative cases, which does not
occur in the Reference case. Net natural gas exports to Mexico in 2035
are 35 percent and 47 percent lower in the No Shale Gas Drilling and No
Low-Permeability Gas Drilling cases, respectively, than in the Reference
case.
The impact on natural gas consumption of restricted drilling in low-permeability
reservoirs is less pronounced than the impact on domestic supply, for two
reasons. First, the increase in net imports partially offsets the reduction
in domestic natural gas productive capacity. Second, long-lived natural
gas consumption equipment responds more slowly to changes in natural gas
prices than does natural gas supply—although the electric power sector,
where natural gas consumption responds relatively quickly to changes in
natural gas prices, is an exception. In 2035, natural gas consumption in
the electric power sector is 1.3 trillion cubic feet (17 percent) lower
in the No Shale Gas Drilling case and 1.9 trillion cubic feet (26 percent)
lower in the No Low-Permeability Gas Drilling case than the Reference case
level of 7.4 trillion cubic feet.
High Shale Gas Resource case
Relative to the Reference case, both natural gas production costs and prices
are reduced in the High Shale Gas Resource case. Consequently, domestic
natural gas production is more competitive, and U.S. natural gas consumption
is higher. In 2035, onshore lower 48 and total natural gas production are
17 percent and 11 percent higher, respectively, in the High Shale Gas Resource
case than in the Reference case, and Henry Hub spot prices are $1.26 per
million Btu lower than in the Reference case. Increased domestic production
and lower natural gas prices reduce net imports in 2035 by 44 percent from
their level in the Reference case, to 0.8 trillion cubic feet, and offshore
natural gas production in 2035 is reduced by 7 percent, to 4.0 trillion
cubic feet. The decline in net imports results from a 19-percent reduction
in net imports from Canada, an 8-percent reduction in net LNG imports,
and a 25-percent increase in net exports to Mexico in the High Shale Gas
Resource case, relative to the Reference case.
Because of the lower natural gas prices in the High Shale Gas Resource
case, U.S. natural gas use in 2035 is 2.0 trillion cubic feet (8 percent)
higher than in the Reference case. The majority of the increase is in the
electric power sector, which accounts for 1.3 trillion cubic feet (18 percent)
of the total increase. |