Producing Natural Gas from Coal
Natural gas in coal formations is an important resource that is helping address the world’s growing energy
needs. In many areas, market conditions and technological advances have made the exploitation of this
resource a viable option. The unique characteristics of coalbed reservoirs demand novel approaches in well
construction, formation evaluation, completion and stimulation fluids, modeling and reservoir development.
John Anderson
Mike Simpson
Nexen Canada Ltd
Calgary, Alberta, Canada
Paul Basinski
El Paso Production
Houston, Texas, USA
Andrew Beaton
Alberta Geological Survey
Edmonton, Alberta
Charles Boyer
Pittsburgh, Pennsylvania, USA
Daren Bulat
Satyaki Ray
Don Reinheimer
Greg Schlachter
Calgary, Alberta
Leif Colson
Tom Olsen
Denver, Colorado, USA
Zachariah John
Perth, Western Australia, Australia
Riaz Khan
Houston, Texas
Nick Low
Clamart, France
Barry Ryan
British Columbia Ministry of Energy and Mines
Victoria, British Columbia, Canada
David Schoderbek
Burlington Resources
Calgary, Alberta
8
For help in preparation of this article, thanks to Valerie
Biran and Tommy Miller, Abingdon, England; Ian Bryant,
Leo Burdylo, Mo Cordes and Martin Isaacs, Sugar Land,
Texas, USA; Matthew Chadwick, Worland, Wyoming, USA;
Ned Clayton, Sacramento, California, USA; Andrew
Carnegie, Abu Dhabi, United Arab Emirates; Steve Holditch,
College Station, Texas; Lance Fielder, Cambridge, England;
Stephen Lambert and Mike Zuber, Pittsburgh, Pennsylvania,
USA; Harjinder Rai, New Delhi, India; John Seidle, Sproule
Associates Inc., Denver, Colorado, USA; and Dick Zinno,
Houston, Texas. Thanks to Willem Langenberg, Alberta
Geological Survey, and Ken Childress, photographer,
for providing the outcrop and rig photographs,
respectively (above).
AIT (Array Induction Imager Tool), APS (Accelerator
Porosity Sonde), CemNET, ClearFRAC, CoilFRAC, DSI
(Dipole Shear Sonic Imager), ECLIPSE Office, ECS
(Elemental Capture Spectroscopy), ELANPlus, FMI (Fullbore
Formation MicroImager), LiteCRETE, MDT (Modular
Formation Dynamics Tester), OFA (Optical Fluid Analyzer),
Platform Express, RST (Reservoir Saturation Tool), SFL
(Spherically Focused Resistivity), SpectroLith and StimMAP
are marks of Schlumberger.
1. For more on the history of coal exploitation (July 1, 2003):
http://www.bydesign.com/fossilfuels/links/html/coal/coal
_history.html and http://www.pitwork.net/history1.htm
2. Leach WH Jr: “New Technology for CBM Production,”
Opportunities in Coalbed Methane: A Supplement to Oil
and Gas Investor, December 2002, Oil and Gas
Investor/Hart Publications, Houston, Texas, USA.
Schwochow SD: “CBM: Coming to a Basin Near You,”
Opportunities in Coalbed Methane: A Supplement to Oil
and Gas Investor, December 2002, Oil and Gas
Investor/Hart Publications, Houston, Texas, USA.
Oilfield Review
Minds, Mines and Wellbores
Humans have appreciated the energy value of
coal for thousands of years. Early use of coal in
fires, dating back to 200 BC, has been confirmed
in ancient Chinese records. There is even
evidence that Stone-Age inhabitants in Britain
collected coal; archeologists have found flint
axes implanted in coal seams. The earliest coal
finds exploited by humans were used to supplement firewood supplies and were likely found at
the surface, along rock outcrops near stream
banks. The first evidence that humans dug for
coal was found in regions where firewood was
scarce. Mining techniques evolved from the
primitive method of finding an exposed coal
seam along hillsides, then digging into the hill as
Autumn 2003
2000
20,000
1800
18,000
1600
16,000
1400
14,000
1200
12,000
1000
10,000
800
8000
600
6000
400
4000
200
2000
Producing CBM wells
Annual CBM production, Bcf
With global oil production moving from plateau
to decline, worldwide reserves of natural gas take
on added importance. Increasingly, gas is viewed
as a vital alternative energy source because it is
plentiful and burns cleaner than other fossil
fuels (see “A Dynamic Global Gas Market,”
page 4). In mature, high-demand markets, the
industry is looking at nonconventional gas
sources, such as shale gas, low-permeability
sandstones and coalbed methane. These unconventional gas accumulations cannot be exploited
in the same way as conventional reservoirs,
presenting challenges to both operators and
service companies.
Natural gas from coal seams is an important
part of the world’s natural gas resource.
Improved methods of evaluating coals are now
available from new logging measurements
and sampling devices. Lighter cements, with
the effective use of additives, minimize damage
to sensitive coalbed methane reservoirs.
Nondamaging fracture-stimulation fluids and
innovative hydraulic fracturing designs are being
used to improve gas and water flow to the wellbore. Optimized artificial-lift techniques are
achieved through the use of intelligent software
to promote quick and efficient dewatering of
coals. Advanced technologies and industry experience applied worldwide are having a positive
impact on coalbed methane (CBM) development.
This article discusses CBM reservoirs, also
known as coalbed natural gas (CBNG) or coal
seam methane (CSM) reservoirs. First, we review
the history of coal exploitation. Next, we discuss
the geologic processes that led to the formation
of coal, how coals generate and store natural gas,
and what makes CBM reservoirs so different from
traditional clastic and carbonate gas reservoirs.
Finally, case studies from around the world
demonstrate the industry’s use of various technologies to evaluate and develop CBM reservoirs.
0
0
1981
1983
1985
1987
1989
1991
1993
1995
1997
1999
2001
Year
> US coalbed methane (CBM) production (blue) and number of producing wells (red).
far as possible to extract the coal. When the operation became too dangerous, these early coal diggers would move to another location along the
outcrop.1 From excavation sites in Britain, it has
been determined that as early as 50 AD, Romans
mined coal to fuel heating systems and smelting
operations. Eventually, pits were dug to access
the coal.
Modernization of mining methods, including
room and pillar, and longwall mining techniques,
enabled larger and deeper operations, exposing
mine workers to a variety of hazards. One significant hazard in coal mining is methane gas—a
by-product of the coal thermal maturation
process that becomes a serious problem in deeper
mines. Mine operators alleviated dangerous
conditions in the subsurface by using mineventilation techniques. Air pumped into a mine
through mineshafts and ventilation pipes
provided oxygen to workers and dissipated the
poisonous and explosive methane. Mining companies also drill coal-degasification wells into coal
seams to liberate methane gas prior to mining the
coal. Modern ventilation and degasification
techniques paved the way for a safer and more
productive mining industry. Coal mining in many
areas is still not completely safe, so degassing
the mines using wellbores ahead of mining
operations is an extremely important technique
to help reduce the number of mining accidents.
Coal became the energy behind the industrial
revolution in Western Europe and across the
world, and remains an important resource today.
However, there is more to the value of coal
than just burning it for heat and electricity; the
natural gas that once was merely a hazard can
be produced and distributed like conventional
natural gas, providing a clean-burning fuel.
Drilling for Coalbed Natural Gas
Coal degasification in mines was first attempted
in England during the 1800s, and it is reported
that the coal gas was used for lighting the streets
of London. The first CBM well to develop gas as a
resource was drilled in 1931 in West Virginia,
USA. For more than 50 years, CBM drilling activity remained low. In 1978, the US government
passed the Natural Gas Policy Act. This legislation allowed companies to receive higher prices
for natural gas produced from tight gas reservoirs,
gas shales and coal seams. In 1984, the US government offered tax credits for developing and
producing unconventional reservoirs. Originally
set to expire in 1990, the tax credits were
extended two more years because of their positive
impact on drilling activity. After the tax credits
expired in 1992, low gas prices caused concerns
about the economics of CBM development.
Gas price is not the only factor affecting the
viability of CBM production. Accessibility to gastransportation infrastructure and technical issues
related to CBM production, for example low initial
gas-production rates, high water-production rates
and disposal issues, must also be considered. The
positive impact of accessibility to adequate
pipeline capacity can be seen in portions of the
Rocky Mountains, USA, where the expansion of
the Kern River Pipeline in May 2003 has significantly improved gas-production economics.
Today, CBM development is having an impact
on the North American gas market. Annual
production from 11 coal basins in the US now
exceeds 1.5 Tcf [42.9 billion m3], or 10% of the
annual US gas production (above).2 Proven
CBM reserves—17.5 Tcf [501 billion m3]—now
make up 9.5% of US total gas reserves, and the
total US CBM in place is estimated at 749 Tcf
9
[21.4 trillion m3]. About 100 Tcf [2.9 trillion m3]
are thought to be recoverable (below).3
Increased gas prices, the continued expansion of
the natural gas transportation system and recent
advances in oilfield technologies have helped
make CBM wells more profitable. Through the
years, operators and service companies have
gained valuable knowledge from mining
research, and practical experience from drilling
activity induced by the US tax credits.
As operators drilled and produced CBM reservoirs, it became clear that coal reservoirs behave
differently from basin to basin, and even within
basins. This behavior largely guides the application of different technologies within a basin or
field. In many CBM areas, operators have reduced
total exploitation costs while increasing gas recovery by prudent application of new technology.
Canada has just started to produce gas from
CBM reservoirs and estimates its in-place
reserves to be 1287 Tcf [36.8 trillion m3].
Australia started producing CBM in 1998 and
places its total reserves at 300 to 500 Tcf [8.6 to
14.3 trillion m3]. Worldwide, the total CBM
in-place reserves are estimated to be between
3500 and 9500 Tcf [100 and 272 trillion m3].4 By
2001, 35 of the 69 coal-bearing countries had
investigated CBM development but, just as in
North America, the pace of future development
will depend on economics (next page, top).
From Peat to Coal
The formation of coal starts with the deposition of
organic material from plants, creating peat. Peat
is formed by continued subaqueous deposition of
plant-derived organic material in environments
where the interstitial waters are oxygen-poor.
Distinct environments allow the accumulation,
burial and preservation of peat, including swamps
and overbank areas that may or may not be
marine influenced (next page, bottom). In the
geologic past, most peat is thought to have formed
in deltaic or marginal marine environments.
Coalification, or the conversion of peat into
coal, occurs at different rates in different environments. Biochemical degradation initiates the
coalification process, but with burial, increasing
overburden pressures and subsurface temperatures cause physicochemical processes that
continue coalification. As water, carbon dioxide
and methane are released, the coal increases
in rank, which is a measure of maturity.
Coals are divided into rank stages and include,
in order of increasing rank: sub-bituminous,
high-volatile bituminous, medium-volatile bituminous, low-volatile bituminous, semi-anthracite,
and anthracite coals. Although coals contain
some inorganic minerals, they are composed
largely of macerals, or vegetal compounds,
ranging from woody plants to resins.
The three general categories of macerals are
vitrinite, liptinite and inertinite. Vitrinite refers
to woody plant material, like trunks, roots,
branches and stems. Liptinite macerals correspond to the more resistant parts of the plant,
such as spores, pollen, waxes and resins.
Inertinite macerals represent altered plant
material and are less structured. These macerals
have a greater carbon content from oxidation
processes that occurred during deposition, for
example the burning of wood or peat in fires.
Maceral data reflect the basic makeup of coals
and therefore help geologists determine CBM
reservoir potential.
An Unconventional Reservoir
From the time of deposition, coal is different
from other kinds of reservoir rock. It is composed
of altered vegetative material—macerals—that
function as both hydrocarbon source and
reservoir. It is inherently fractured from the
Western
Washington
Coal Region
Northern
Appalachian
North Central
Coal Region
Bighorn
Wind River
Greater
Green River
Powder
River
Uinta
Hanna
Carbon
Piceance
Central
Appalachian
Forest City
Illinois
Richmond
Kaiparowits
Plateau
Denver
Raton
Cherokee
Arkoma
San Juan
Tertiary
Tertiary-Cretaceous
Cretaceous
Jurassic
Triassic
0
0
200
400
600
800 km
100 200 300 400 500 miles
Gulf Coast
Black
Warrior
Cahaba/Coose
Pennsylvanian and Permian
Mississippian
> US basins containing coalbed methane reserves. Major coal basins are shown with the associated periods of coal deposition.
10
Oilfield Review
> Worldwide coalbed methane activity. By 2001, 35 (red dots) of the 69 coal-bearing countries had investigated CBM development.
coalification process, which forms vertical
fractures, or cleats. Coal cleats are classified geometrically with the primary, more continuous
cleats called face cleats and the secondary, less
continuous cleats called butt cleats.
Genetic classification of coal fractures is also
common. Endogenetic fractures, or classic cleats,
are created under tension as the coal matrix
shrinks due to dewatering and devolatilization during coal maturation. These cleat sets are orthogonal and nearly always perpendicular to bedding. In
contrast, exogenetic fractures form due to tectonism and therefore regional stress fields dictate
their orientation. Shear fractures, oriented 45º to
the bedding planes, also are observed.
In virtually all coalbed reservoirs, cleats are
the primary permeability mechanism. Like conventional reservoirs, coals can also be naturally
fractured. In deeper coal seams, higher overburden stresses can crush the coal structure and
close the cleats. In such locations, subsequent
natural fracturing tends to be the main permeability driver. Understanding the cleating and
3. Nuccio V: “Coal-Bed Methane: Potential and Concerns,”
U.S. Geological Survey, USGS Fact Sheet FS–123–00,
October 2000. http://pubs.usgs.gov/fs/fs123-00/fs12300.pdf
4. Olsen TN, Brenize G and Frenzel T: “Improvement
Processes for Coalbed Natural Gas Completion and
Stimulation,” paper SPE 84122, presented at the SPE
Annual Technical Conference and Exhibition, Denver,
Colorado, USA, October 5–8, 2003.
Autumn 2003
> Peat-forming environments. Peat is formed by continual subaqueous deposition of organic matter in
environments where waters are poorly oxygenated. The accumulation, burial and preservation of peat
occur in a range of environments that include swamps and overbank areas. These may or may not be
marine influenced. (These photographs of the Loxahatchee River, Florida, USA, are from the South
Florida Water Management District Web site: www.sfwmd.gov/org/oee/vcd/photos/hires/hilist.html)
11
natural-fracture systems in coals is critical
during all facets of CBM reservoir development.
Methane generation is a function of maceral
type and the thermal maturation process.
As temperature and pressure increase, the rank
of the coal changes along with its ability to
generate and store methane (left).5 Also, each
maceral type stores, or adsorbs, different volumes of methane. In addition, coal can store
more gas as its rank increases.
Conventional sandstone and carbonate reservoirs store compressed gas in porosity systems.
Methane is stored in coal by adsorption, a process by which the individual gas molecules are
bound by weak electrical forces to the solid
organic molecules that make up the coal. To
assess how CBM wells might produce over time,
the sorptive capacity of crushed coal samples are
tested and desorption isotherms are constructed
(below). Desorption isotherms describe the relationship between pressure and adsorbed gas
content in the coal at static temperature and
moisture conditions. Coal’s ability to store
methane largely reduces the need for conventional reservoir-trapping mechanisms, making its
gas content—which is related to coal rank—and
the degree of cleating or natural fracturing the
overriding considerations when assessing an
area for CBM production potential.
Increasing gas volume
Gas Generation as a Function of Coal Rank
Thermally-derived
methane
Volatile matter
driven off
Biogenic methane
Nitrogen
Carbon dioxide
Lignite
Sub-bituminous
Bituminous
Anthracite
Graphite
Increasing coal rank
> Gas generation in coal. As temperature and pressure increase, coal rank
changes along with its ability to generate and store methane. Through time,
dewatering and devolatization occur, causing shrinkage of the coal matrix
and creation of endogenetic cleats.
Stage l
Stage ll
Stage lll
Producing rate, Mscf/D or STB/D
Well “dewatered”
Gas
Water
Production time
> Coalbed production characteristics. During Stage I, production is dominated by water. Gas production increases during Stage II, as water in the
coal is produced and the relative permeability to gas increases. During
Stage III, both water and gas production decline.
600
1000
500
Coal versus Sandstone–Gas Content versus Pressure
Coal
Gas content, scf/ton (coal equivalent)
Absorbed gas content, scf/ton (dry, ash-free)
Methane Sorptive Capacity versus Coal Rank
1200
800
600
400
Anthracite
Medium-volatile bituminous
High-volatile bituminous A
High-volatile bituminous B
200
400
Coal isotherm
8% porosity to gas
6% porosity to gas
4% porosity to gas
300
200
Sandstones
100
0
0
0
200
400
Pressure, psia
600
800
1000
0
500
1000
1500
2000
2500
3000
3500
4000
4500
Pore pressure, psia
> Sorptive capacity of coal. As coal maturity increases from bituminous to anthracite, the sorptive capacity of coal increases. Tests conducted on coal
samples to relate adsorbed gas to pressure—under isothermal conditions—assess how CBM wells might produce over time. The plot shows
typical responses in bituminous and anthracite coals (left). The gas storage capacity of coal can be significantly greater than that of sandstones (right).
12
Oilfield Review
Autumn 2003
Production from 23 CBM Wells
175,000
150,000
Cumulative gas production, Mscf
This storing ability gives coals unique earlytime production behavior that is related to desorption, not pressure depletion. Coals may
contain water or gas, or both, in the cleat and
natural fracture systems, and gas sorbed onto the
internal surface of the coal matrix. Any water
present in the cleat system must be produced to
reduce the reservoir pressure in the cleat system
before significant volumes of gas can be produced. Dewatering increases the permeability to
gas within the cleats and fractures, and causes
the gas in the matrix to desorb, diffuse through
the matrix and move into the cleat system, resulting in CBM production profiles that are quite
unique (previous page, middle).
Initial production is dominated by water. As
the water moves out of the cleats and fractures,
gas saturation and production increase and water
production falls. When permeability to gas eventually stabilizes, the coal is considered dewatered
and gas production peaks. From this point, both
water and gas production slowly decline, with gas
being the dominant produced fluid. The speed at
which the reservoir dewaters depends on several
factors, including original gas and water saturations, cleat porosity, relative and absolute permeability of the coal, and well spacing.
Some CBM wells produce dry gas from the
start. For example, some wells in Alberta and
British Columbia, Canada, and the underpressured portion of the San Juan basin are comparable to conventional reservoirs and produce
water-free at irreducible water saturation. Dry
gas coalbed production typically declines from
the start, exhibiting Stage III behavior.
As with all gas reservoirs, the permeability
controls production and largely dictates the
amount of gas reserves in coal seams. Local variations in cleat and natural-fracture conductivity
and density—how closely cleats or fractures are
spaced—lead to wide variations in well performance within some areas of development (above
right). For example, 23 wells in a field in the
Black Warrior basin, USA, with similar coal thicknesses and original gas contents, were drilled and
completed identically, at equal well spacings, but
show diversity in production performance
because of the local variations in cleat conductivity—permeability. Also, in this basin, cleat and
natural-fracture conductivity are greatly affected
by the stress on the reservoir. Field-test data confirm the inverse relationship between closure
stress and coal permeability; increasing closure
stress from 1000 to 5000 psi [6.9 to 34.4 MPa]
decreased permeability from 10 to 1 mD.
125,000
100,000
75,000
50,000
25,000
0
0
10
20
30
40
50
60
70
80
Time, months
> Local well-performance variations in a group of 23 similar wells in a field in the Black Warrior basin,
USA. In this area, the differences are attributed to local changes in cleat and natural-fracture permeabilities. The plot shows cumulative gas production through time for each of the 23 wells.
The unconventional properties and production performance of coalbed reservoirs, including
high initial water production and low initial gas
production, are largely responsible for the relatively slow uptake in CBM reservoir development
around the world. However, the collective
knowledge and experiences of the industry in
exploiting this resource are showing results in
increased CBM production.
Investigating a New Resource in India
After reviewing the major coal-bearing basins in
India, the Oil and Natural Gas Corporation
(ONGC) concluded that the Jharia basin, 250 km
[155 miles] northwest of Calcutta, had the best
potential for coalbed natural gas production.
Three pilot wells were drilled through the
Permian-age Barakar formation, which contains
up to 18 clearly identifiable coal beds, each from
1 to 20 m [3 to 66 ft] thick. The second pilot hole
was cored and logged with high vertical resolution lithodensity, neutron and resistivity measurements from the Platform Express integrated
wireline logging tool, FMI Fullbore Formation
MicroImager, DSI Dipole Shear Sonic Imager and
ECS Elemental Capture Spectroscopy tools.
Fullbore cores were obtained in many of the
coals and were sent for proximate analysis, rank
determination and adsorbed gas content.6 The
logs were analyzed for these same parameters
and for cleat porosity.
The first step was proximate analysis from the
lithodensity, neutron and gamma ray logs. These
log measurements have widely different
responses to the various coal components and
can resolve them well. The main uncertainty lies
in the response parameters of ash, since it may
contain varying amounts of quartz, clay, calcite,
pyrite and other minerals.7 The parameters of
volatile matter—mainly organics, wax, carbon
dioxide [CO2] and sulfur dioxide [SO2]—and
fixed carbon are reasonably similar for the bituminous and anthracite coals of interest. In the
Jharia well, results of the log analysis were in
5. Zuber M and Boyer C: “Evaluation of Coalbed Methane
Reservoirs,” prepared for the University of Oviedo, Spain.
Holditch-Reservoir Technologies Consulting Services,
Pittsburgh, Pennsylvania, USA, May 24–25, 2001.
6. Proximate analysis is the term used for the identification
of the major fractions of the coal, taken as moisture,
volatiles, fixed carbon and ash. These fractions have
usually been determined by progressively heating and
then burning crushed samples and observing the volume
of the different fractions removed at each stage until
nothing is left but ash. Proximate analysis is distinct from
ultimate analysis, in which the weight percent of different elements is determined.
7. Ash is the inorganic constituent, derived from mineral
matter, that remains after proximate analysis.
13
Moisture
Caliper > Bit Size
Hole Size
Depth, m
6
in.
16
Gamma Ray
Ash
Clay
Fixed Carbon
Quartz
Volatile Matter
Water
Core Coal Rank
Log Coal Rank
ELAN volumes
50
Low-volume
bituminous
Sub-bituminous
1 10
High-volume
bituminous
vol/vol
Medium-volume
bituminous
150 0
API
Semi-anthracite
0
X060
X070
17
24
36
40
% Volatile matter
Volatiles + fixed carbon
High Resolution
Photoelectric Effect
Capture Cross Section
Gamma
Ray
Density
Neutron
g/cm3
vol/vol
Ash
2.75
0.05
12
400
Fixed Carbon
1.35
0.45
0.2
20
Volatile Matter
0.90
1.00
0.5
0
Moisture
1.00
1.00
0.5
0
barn/cm3
API
> An example of proximate analysis and coal rank determination from logs in India. In Track 1, the
caliper indicates that the hole is moderately washed out but still smooth. Track 2 shows good agreement
between the log-derived proximate analysis, using the parameters given in the table, and core-derived
analyses. Track 3 compares coal rank from logs, after applying a vertical average, with coal rank from
core. Coal rank is determined by the proportion of volatile material in the dry, ash-free coal, using the
cutoffs shown (bottom).
good agreement with core data (above). The ECS
data added detailed information on the composition of the ash and improved the estimate of total
ash in washed-out coals, where the density and
other logs were more affected by the borehole
14
(see “The Elements of Coal Analysis,” page 16).
The next step was to estimate the volume of
adsorbed gas in each seam. Ideally, this would be
derived directly from logs. However, the effect of
adsorbed gas on the response parameters of coal
is small and there are not enough independent
measurements to solve reliably for gas.
Traditional coal-industry techniques determine
gas content from cores, and in their absence, by
estimating the rank of the coal from proximate
analysis and the gas content from rank, pressure,
temperature and a suitable adsorption isotherm.
The American Society of Testing and Materials
(ASTM) ranks coals by the percentage of volatile
material after normalizing to dry, ash-free coal.
Slightly different ranking criteria were used in
Jharia and were applied to both core and log data.
With logs providing information on intervals
where core data were missing, ONGC was able to
study the quality of the different coal seams. The
average coal rank increased with depth, but with
a probable change in trend half-way down the
section (next page, top). The change in trend is
most likely related to a major fault seen on the
FMI data at this depth. Coal rank and proximate
analysis can also be entered into a suitable sorptive capacity transform to determine the gas in
place within each coal seam.8
Cleat porosity was estimated by four different
methods: from the porosity seen by microresistivity measurements, by the separation of deep and
shallow laterolog curves, by the quantity and type
of mineralization seen by the ECS tool, and from
the shear-wave anisotropy measured by DSI data.
When the borehole is in gauge, the microresistivity measurement gives the most accurate results,
and is used to calibrate the ECS and DSI data. In
washed-out coals, the ECS log is least affected by
hole rugosity, while the DSI and microresistivity
logs can be affected more severely. The estimate
of cleat porosity adds information on flow capacity to that already obtained on gas volume. These
data helped ONGC decide which seams to test,
whether to develop this resource and how best to
accomplish this.
Huge Reserves and Progress in Canada
Canada’s estimated 1287 Tcf of probable in-place
CBM reserves lie primarily in the provinces of
British Columbia and Alberta, and can be divided
into three main areas, the Alberta foothills, the
Alberta plains and the British Columbia foothills.
Coals from these areas vary in rank, gas content
and accessibility. Canadian coal experts maintain that coal permeability is the main driver of
CBM reservoir potential. For this reason, much of
the focus when assessing CBM reservoirs in
Canada is on understanding cleats and natural
fractures, both in outcrop and in wellbores.
Alberta contains vast amounts of coal distributed throughout the southern plains, foothills
and mountains. Originally deposited in relatively
Oilfield Review
Orientation North
Depth, m
0 120 240 360
0
deg
90
X50
50
Fault
45
Volatile matter, wt % (dry, ash-free)
Bedding
True Dip
FMI Static Image
Res.
Cond.
40
35
X55
30
Fault location
25
20
15
10
100 m
Increasing log depth, m
> Percent of volatile material—dry and ash free—and coal rank versus depth for the Jharia well. Logderived data (red curves) and core-derived data (blue dots) are shown only in the coal seams. The
core-derived data, in particular, suggest a change in trend (blue line) probably associated with a fault
observed on the FMI image (inset) and in other data at that depth.
Coal Zones with
CBM Potential
Alberta
Distribution of Coal by Rank
Low- and mediumvolatile bituminous coals
High-volatile
bituminous coals
Mannville Group
Horseshoe Canyon
Group
Belly River Group
Sub-bituminous coal
Scollard Formation
Kootenay Group
0
Luscar Group
0
Lignite
200
100
400 km
200
300 miles
flat-lying peat swamps, organic matter was
buried by sediments derived from the west and
gradually coalified with increasing heat and pressure after burial. Coals were subsequently folded,
faulted, uplifted and partially eroded, resulting
in the present distribution of coal across the
plains. Coal-bearing strata gently dip westward
towards the mountains, where the coals are
folded and abruptly turn towards the surface to
be reexposed in the foothills.
Coal seams occur within distinctive horizons
of the upper Cretaceous Scollard, Horseshoe
Canyon and Belly River formations, and within
the lower Cretaceous Mannville group strata in
the Alberta plains. Coal is also found within the
Paleocene Coalspur formation and the Mist
Mountain formation of the Jurassic-Cretaceous
Luscar/Kootenay groups in the Alberta foothills
(below left). Individual coal seams vary in thickness from less than 1 meter [3 ft] to more than
6 meters [20 ft]. Groups of coal seams are separated by 10 to 50 m [30 to 160 ft] of rock. Most
coals at shallow depths—less than 1000 m
[3300 ft]—in the plains are sub-bituminous to
high-volatile bituminous rank. Coals in the
Alberta foothills generally are more mature, with
ranks from high-volatile to low-volatile bituminous. Alberta plains coals have more predictable
cleat characteristics than foothills coals in
Alberta and British Columbia because of their
limited deformation.
Permeability, formation pressure and reservoir fluid saturation are critical in identifying
areas suitable for CBM development. Common
methods used to measure permeability in coals,
such as injection and falloff testing, often yield
inconsistent results because the cleat permeability can be a function of injection pressure. Test
intervals may be disturbed by drilling fluids and
can be damaged by cementing, breakdown and
stimulation fluids, causing adverse effects on
test results. Ambiguities occur for a variety of
reasons, including inflation of coal cleats and
fractures, two-phase permeability and wellborestorage effects.
(continued on page 20)
Edmonton
Calgary
Edmonton
Calgary
8. The theory of Langmuir relates the gas volume adsorbed
on ash-free coal to pressure at a given temperature and
to two factors that depend on temperature and coal
rank. Various researchers have correlated these factors
with the results of proximate analysis, so that the
adsorbed gas volume can be estimated from logs. See
Hawkins JM, Schraufnagel RA and Olszewski AJ:
“Estimating Coalbed Gas Content and Sorption Isotherm
Using Well Log Data,” paper SPE 24905, presented at the
SPE Annual Technical Conference and Exhibition,
Washington, DC, USA, October 4–7, 1992.
> Alberta coals. Maps show the distribution of major coal seams (left) and coal rank (right) in Alberta.
Autumn 2003
15
The Elements of Coal Analysis
In the simplest technique of proximate analysis from logs, the bulk density is interpreted
for ash content, which is then correlated with
the other proximates for each rank of coal.
Addition of the neutron, gamma ray and photoelectric logs makes the analysis more general
and less dependent on local correlations.
Unfortunately, some coals tend to wash out
while drilling, leading to oversize boreholes
and large borehole effects on the logs. In addition, the composition of the components, in
particular ash, can vary, creating some uncertainty in the parameters to be used
in interpretation.
An alternative technique is based on elemental analysis from neutron-induced gamma ray
spectroscopy. Both the ECS Elemental Capture
Spectroscopy sonde and the RST Reservoir
Saturation Tool device estimate the quantity of
minerals in the coal. The advantage of neutron-induced gamma ray spectroscopy is that
the majority of the signals of interest arise
from elements in the formation and are therefore unaffected by the borehole. In addition,
the components of the ash can be more precisely defined from the mineralogy.
Neutron-induced gamma ray spectroscopy
tools emit high-energy neutrons that are then
slowed down and captured by elements in the
borehole and the formation. During capture, a
gamma ray is emitted with an energy that is
characteristic of the element. A detector measures the gamma ray spectrum, or the number
of gamma rays received at the detector at each
energy level. This energy may be degraded by
scattering in the formation, but there is sufficient character in the final spectrum to recognize the peaks caused by different elements.
The first processing step is to calculate the
proportion, or relative yield, of gamma rays
from each element by comparing the measured
spectrum with the theoretical spectrum of
each individual element (next page). A mathematical inversion provides the percentage of
the principal contributors, such as silicon,
calcium, iron, sulfur and hydrogen.
The yields are only relative measures
because the total signal depends on the environment, which may vary throughout the
logged interval. To obtain the absolute elemental concentrations, additional information
is needed. The principle of oxide closure
states that a dry rock consists of a set of
oxides, the sum of whose concentrations must
be unity.1 Measuring the relative yield of all
the oxides allows the calculation of the total
yield and the factor needed to convert the
total to unity. This normalization factor will
India
80
80
70
70
60
Proximate component, wet weight %
Proximate component, wet weight %
San Juan Basin, USA
y = -0.834x + 75.471
R2 = 0.997
50
Fixed carbon
Volatiles
Moisture
40
30
y = -0.171x + 24.034
R2 = 0.944
20
then convert each relative yield to a dry
weight elemental concentration.
Finally, the SpectroLith lithology processing
technique transforms elemental concentrations into mineral concentrations using a set of
correlations based on the study of more than
400 core samples from different clastic environments.2 The results are expressed as the
dry weight percentage of clay, coal, accessory
minerals such as pyrite and siderite, and the
aggregate of quartz, feldspars and micas. While
there may be local variations in these correlations, the major advantage of this technique is
that it is automatic, with no user intervention.
This contrasts with standard methods for clay
determination that depend heavily on userselected parameters.
Coals are easily identified by their high
hydrogen concentration. Quantifying the
amount of fixed carbon, volatile material and
moisture in coal is more difficult and requires
two assumptions. First, there are other sources
of hydrogen that must be considered, including
water in the cleats, clay water and moisture in
the formation, and in the borehole, unless the
well was drilled with air. Since these form a
consistent background, they can be subtracted
to give the hydrogen concentration in coal.
Second, different types of coal have different
10
60
y = -0.7762x + 75.575
R2 = 0.8662
50
Fixed carbon
Volatiles
Moisture
40
30
y = -0.2245x + 24.286
R2 = 0.3507
20
10
y = 0.005x + 0.495
0
0
10
20
30
40
Ash, wet weight %
y = -0.0014x + 0.1816
0
50
60
70
0
10
20
30
40
50
60
Ash, wet weight %
> Proximate analysis based on ash content. Excellent correlations have been found with data from three wells in the Fruitland coal interval in the
San Juan basin (left). The correlations from the Jharia well in India are satisfactory for fixed carbon but poor for volatile matter (right).
16
Oilfield Review
Induced Gamma Ray Spectra
Counts
Gd
H
Inversion (Spectral Stripping)
Fe
Si
Si
Cl
Ca
Fe
S
Ti
Gd
Cl
H
Inelastic
X00
Energy
X50
X00
Oxide Closure
Coal
Si
Ca
S
Fe
Ti
Gd
m
X50
SpectroLith Model
Pyrite (wt %)
Carbonate (wt %)
Sand (wt %)
Coal (wt %)
Clay (wt %)
> The interpretation steps for obtaining mineralogy from gamma rays. The
detector receives a spectrum of gamma rays that is compared with standards
for each element to obtain their relative yields. The yields are converted into
elemental concentrations by applying a normalization factor computed from
the oxide-closure model. Finally, the SpectroLith model estimates mineral
percentages from elements.
hydrogen contents. However, in a given area or
formation, this can be sufficiently consistent to
allow a conversion from hydrogen concentration to coal percentage.
Data from the ECS tool allow a quick and
automatic proximate analysis at the wellsite.
The total ash content is simply obtained from
its components, namely quartz, clay, carbonates
and pyrite, while the amount of fixed carbon
and volatile material can be estimated from
correlations with ash content (previous page).
Autumn 2003
1. In practice, the process is not so straightforward.
First, we measure elements, not oxides, but nature is
helpful since the most abundant elements exist in only
one common oxide, for example quartz [SiO2] for silicon [Si]. Thus for most elements there is an exact
association factor that converts the concentration of
the element to the concentration of the oxide. Second,
although the ECS tool measures a majority of the most
common elements, there are exceptions, the most
important being those of potassium and aluminum.
Luckily, the concentration of these elements is
strongly correlated to that of iron, so that they can be
included in the oxide association factor for iron.
2. Herron S and Herron M: “Quantitative Lithology: An
Application for Open and Cased Hole Spectroscopy,”
Transactions of the SPWLA 37th Annual Symposium,
New Orleans, Louisiana, USA, June 16–19, 1996, paper E.
17
Bed Gas Content Range
Gas Content Range
Moisture
Gas Content (Hawkins Study)
Mineral Ash
0
scf/ton
500
Well Cleated
Min. Gas Content
Fixed Carbon
Volatiles
0
0
Core Moisture
Mineral Ash
0
wt %
0.4 0
Core Mineral Ash
0
wt %
wt %
wt %
scf/ton
Poorly Cleated
500
MMcf/acre
RST Cleat Porosity
ft3/ft3
50 0
Max. Bed Gas
1 0
Core Fixed Carbon
0.4 0
Partly Cleated
500
Min. Bed Gas
1 0
Core Fixed Carbon
Mineral Ash
0
wt %
scf/ton
Max. Gas Content
1 0
MMcf/acre
0.1
Openhole Resistivity
ft3/ft3
50 0
Core Desorbed Gas Content
SFL Resistivity
scf/ton
ohm-m
500 0.2
0.1
2000
> A typical coal evaluation using neutron-induced gamma ray spectroscopy from the RST Reservoir
Saturation Tool. Tracks 1 and 2 show proximate analyses from logs and core. Track 3 shows gas
content and cumulative gas content from core and from logs using two different transforms. One is
the Langmuir Rank equation developed by Hawkins et al, reference 8, main text. The other is a local
equation based on ash content, temperature and pressure. Track 4 indicates the cleat intensity.
Many such correlations have already been
established from core data for specific areas
or formations.3 Alternatively, the ECS mineralogy can be combined with other log data in
an ELANPlus computation. The resulting
proximate analysis is enhanced by the
detailed ash description from the ECS sonde,
and by the ability of lithodensity and neutron
data to distinguish between fixed carbon and
volatile matter.
The more detailed ECS mineralogy also
helps identify the degree of cleating. The
18
presence of calcite and pyrite indicates a welldeveloped cleat system in which the flow of
water has caused secondary mineralization.
However, large quantities of calcite and pyrite
suggest that the cleats have been filled or that
the coal is of low grade. Quartz and clay have
also been observed in cleats, but large volumes of these minerals and a large total ash
volume indicate a lower-ranked coal. Such
coals will have lost less water and volatile
matter during coalification and will therefore
have fewer cleats.4 These observations can be
used to identify well-cleated coal by, for example, calcite percentages between 2 and 7%, and
pyrite percentages between 0.5 and 5%. Poorly
cleated coals have total ash percentages above
45%, clay percentages above 25% and quartz
percentages above 10%. Mineral percentages
that fall between those of well-cleated coals
and poorly cleated coals indicate partly cleated
coals.5 The rules and cutoffs can vary by area
and should be established locally from production data.
Oilfield Review
Coal Indication from Openhole Density
Openhole Formation Density
g/cm3
1
Depth, ft
Gamma Ray
0
API
200 0
10
Caliper
6
3
Photoelectric Factor
Density Derived from Carbon/Oxygen Ratio
in.
g/cm3
16 1
3
Openhole bulk density
X450
2.0
1.8
R2 = 0.9025
1.6
1.4
1.2
1.8
2.0
2.2
2.4
2.6
2.8
Carbon/oxygen ratio
X500
> Comparison of density from an openhole log (red) and that derived from the RST carbon/oxygen ratio
(black), after making the best-fit correlation shown in the plot (inset). The openhole density suggests a
coal at X447, but the carbon/oxygen data show this to be incorrect and to be caused instead by the
washout seen on the caliper.
The coal rank and gas content can be estimated based on proximate analysis. Cleat
intensity indicates permeability and hence
productivity. Thus, neutron-induced gamma
ray spectroscopy, in combination with other
logs, provides a continuous record of the
major factors needed to evaluate a coal seam
and any surrounding sands shortly after the
well has been drilled (previous page).
Elemental analysis has an additional role in
cased holes, where the RST carbon/oxygen
ratio is the most accurate logging method for
Autumn 2003
identifying coals. This technique is particularly
useful in wells drilled for deeper targets that
have been cased over the coal-bearing zones
without recording an openhole density log. The
carbon/oxygen ratio is calibrated to coal density, using data from other wells in the area
(above). The other elemental yields can be
interpreted as already described after allowing
for the effects of casing and cement on the
silicon and calcium concentrations.
3. Hawkins et al, reference 8, main text.
4. Law BE: “The Relationship Between Coal Rank and
Spacing; The Implications for the Prediction of
Permeability in Coal,” Proceedings of the International
Coalbed Methane Symposium, Vol. 2, Birmingham,
Alabama, USA, (May 17–21, 1993): 435–442.
5. Ahmed U, Johnston D and Colson L: “An Advanced
and Integrated Approach to Coal Formation
Evaluation,” paper SPE 22736, presented at the 66th
SPE Annual Technical Conference and Exhibition,
Dallas, Texas, USA, October 6–9, 1991.
19
Density
125 mm
375
0
375
Gamma Ray
0
API
2650
Orientation North
Bit Size
125 mm
kg/m3
1000
120
240
360
FMI Static Image
Resistive
Conductive
Depth, m
Caliper
Orientation North
0
120
240
360
Bedding
True Dip
FMI Dynamic Image
Resistive
Conductive
150
0
deg
90
X49.6
Coal unresolved by the
density log
X49.8
5-cm coal layer
X50.0
X50.2
Probable subvertical cleats
X50.4
X50.6
X50.8
X51.0
Pyrite inclusions affect
the density measurement
X51.2
> High-resolution measurements in thin-bedded coals. Many coals are thin-bedded and may not be
identified with standard measurements. The FMI Fullbore Formation MicroImager tool has a vertical
resolution of 0.2 in. [0.5 cm], which allows analysts to image thin coals. Track 1 contains gamma ray,
caliper and borehole orientation data. A comparison between the density log and the FMI static image
is displayed in Track 2. The FMI tool clearly identifies the thin coal at X50.0 m, where the density log
does not. Pyrite inclusions that dramatically affect the density at X51.0 m appear as dark spots on the
FMI image. Track 3 contains the FMI dynamic image, and Track 4 displays dip information.
Nexen Canada Ltd. has run successful tests on
shallow plains coal seams using the MDT Modular
Formation Dynamics Tester device (next page).
After pumping out drilling fluid, the MDT packer
module can withdraw reservoir fluid from isolated
coal seams at near-virgin conditions. The tool
provides accurate flow rate and pressure information, and measures the properties of the recovered
fluids in real time. Pressure-transient analysis can
be applied to the pressure response to determine
coal permeability. Bottomhole shut-in pressure
reduces the problem of wellbore storage that can
mask the formation response in pressuretransient analysis. Nexen Canada has found that
20
the MDT device is cost-effective and minimizes
uncertainties inherent in other coal-permeability
testing methods.
Some of the Mannville coals of the Alberta
plains are thin-bedded, as seen in a Burlington
Resources Canada well FMI image (above). Here,
the bulk density log seems to respond to heavy
minerals like pyrite in the coal matrix. These are
seen as conductive specks on FMI images, giving
anomalously high density peaks that cause some
potential errors in net-coal estimates. The higher
resolution of the FMI tool allows more reliable
net-coal thickness measurement.9
Abundant folds and thrust faults related to
Laramide deformation characterize the complex
structural geology of the British Columbia and
Alberta foothills. The present minimum horizontal
stress direction runs northwest-southeast
throughout much of the foothills area, roughly
parallel to the outcrops, although local stress
variations are indicated in borehole-breakout
studies. In the Alberta plains, recent studies by
(continued on page 23)
9. Schoderbek D and Ray S: “Applications of Formation
MicroImage Interpretation to Canadian Coalbed
Methane Exploration,” presented at the CSPG–CSEG
Annual Convention, Calgary, Alberta, Canada,
June 2–6, 2003.
Oilfield Review
Hydrostatic
Pressure Pressure
Hydrostatic
kPa
kPa
1500
Gamma Ray
Gamma Ray
0
0
API
API
150
Caliper Caliper
125
125
mm
mm
375
Bit Size Bit Size
125
125
mm
mm
375
Hydrostatic
Hydrostatic
gradient gradient
SphericalSpherical
Permeability
Permeability
15000.2
0.2
True vertical depth, m
1000
True vertical depth, m
1000
1500.2
3750.2
3750.2
XX15
mD
mD
FormationFormation
Pressure Pressure
2000 500 2000 500
AIT Resistivity
AIT Resistivity
10-in. 10-in.
0.2
ohm-m
ohm-m
AIT Resistivity
AIT Resistivity
30-in. 30-in.
0.2
ohm-m
ohm-m
0.2
ohm-m
ohm-m
kPa
1000
1000
Neutron Porosity
Neutron Porosity
2000 0.6 2000 0.6
m3/m3
m3/m3
0
0
0.15
0.15
Density Porosity
Density Porosity
2000 0.752000 0.75
AIT Resistivity
AIT Resistivity
90-in. 90-in.
kPa
m3/m3
m3/m3
Photoelectric
Photoelectric
Effect Effect
10
2000 0 2000 0
10
XX15
Test
Test
position #2position #2
Test
Test
position #1position #1
XX25
925
XX25
Test Position #2
Specialized Analysis PlotSpherical Flow Buildup
915
905
15157
15017
14877
14737
895
Pressure, kPa
Test Position
#2
k sph = 1.289 mD
p int = 916.9 kPa
885
14597
14457
875
14317
865
14177
855
14037
13897
845
13757
835
13617
825
0
0.05
0.10
0.15
0.20
0.25
Delta P & derivative groups, kPa
1e+03
13477
13337
Spherical time function
13197
Test Position #2
Flow Regime Identification PlotCBM Buildup
13057
12917
12777
1e+02
Pressure
Derivative
12637
12497
12357
1e+01
12217
12077
11937
1e+00
11797
11657
Time, s
1e- 01
1e- 01
1e + 00
1e + 01
Delta T, s
1e + 02
1e +03
Pressure/Temperature/Resistivity
E 500
Pressure (kPa) - PASG
v
Temperature (°C) - PAQT
e 13.00
n 0.00
Resistivity (ohm-m) t
Pump Out Volume (C3) - POPV
s 0
1500
15.00
0.00
80,000
E
v
e
n
t
s
Gas
Detection
Fluid
Fraction
High
Water
Medium
Oil
Low
Mud
OFA Fluid Density
Fluid Color
> Pressure and permeability from the MDT Modular Formation Dynamics Tester device. Nexen Canada Ltd. ran the MDT tool on
a well to test coal seams in the Alberta plains. The MDT test position 2 can be located on the log (top). Hydrostatic pressures are
plotted in Track 1, along with the gamma ray and caliper data. Results from the spherical flow buildup permeability analysis (middle
left) are plotted in Track 2, along with the resistivity data. Buildup data were also used to identify a spherical flow regime (bottom
left). Formation pressure determined from the buildup analysis is plotted in Track 3, along with porosity and lithology information.
The OFA Optical Fluid Analyzer plot (right) shows pressure, temperature and pumpout volume during sampling, and fluid recovery changes during the test. Drilling mud was recovered initially (brown), then water (blue) with some possible small shows of
gas (white).
Autumn 2003
21
Bed Boundary
True Dip
0
mm
0
375
mm
deg
90
Drilling-Induced Fracture
True Dip
Caliper 1
125
90
Cross Bedding
True Dip
Bit Size
125
deg
375
0
deg
90
Caliper 2
125
mm
Partial Open Fracture
True Dip
375
Density
Gamma Ray
Measured depth, m
0
API
150
1000
deg
Gamma Ray
45 to 75 API
Gamma Ray
< 45 API
0
20
1
m3/m3
AIT Resistivity 90-in.
2650
Neutron Porosity
Borehole Drift
0
kg/m3
0.2
ohm-m
Resistive Fracture
True Dip
0.2
ohm-m
0
Orientation North
0
Photoelectric Factor
120
240
360
10
Coal
Fracture Aperture
2e-05
cm
After-Frac Survey
Resistive
0.2
deg
90
Unconformable
Bed Boundary
True Dip
2000
FMI Dynamic Image
0
90
2000
AIT Resistivity 10-in.
0
deg
Background
Background
Scandium
Coal
Coal
Scandium
Antimony
Antimony
Iridium
Iridium
Conductive
0
deg
90
Perfs
XX70
XX75
Fault drag
XX80
XX85
Fractures in coal
Perfs
> Analysis of Alberta plains coal seams. A fault was identified during the FMI image interpretation of this Burlington well at a depth of XX79.5 m
(Track 4). Faults and associated fracturing have a direct impact on the permeability of coal seams. Gamma ray and caliper data are displayed in
Track 1 with borehole orientation. Track 2 contains porosity and lithology information. Fracture apertures exceeding 0.01 cm [0.004 in.] were calculated from FMI data and are displayed with resistivity data in Track 3. Track 4 contains the dynamic FMI image from which bedding and fractures
planes were picked. Track 5 shows the dip plots from the interpretation of Track 4. An after-frac survey is included on the right to demonstrate the
vertical growth of hydraulic fractures from the perforated coals. The presence of radioactive tracers below the perforations indicates downward
fracture growth.
22
Oilfield Review
Autumn 2003
Alberta Plains Coal
British Columbia Foothills Coal
Caliper
Face Cleat
125 mm 375
Orientation North
Bit Size
125 mm 375 0
Gamma
Ray
0 API 150
120
240
360 0
deg
90
Bedding True Dip
FMI Dynamic Image
Resistive
Conductive
0
deg
Measured depth, m
Caliper
Measured depth, m
the Alberta Energy and Utilities Board (AEUB)
using regional geological data, and drilling and
completion records indicate stress variation
between upper Cretaceous-Tertiary and lower
Cretaceous rock sequences.10 In addition, image
data from the FMI tool have shown faults in these
areas (previous page). After-fracture surveys were
run to evaluate how hydraulic fractures propagate
through the coals and surrounding rock.
In the foothills of northeast British Columbia,
the Cretaceous Gates and Gething formations
contain the thickest coal resources. Coals in
these formations are exposed in the Peace River
coal field, along northwest-trending outcrops,
where they are mined. In the southeast corner of
British Columbia, coal is contained in the
Jurassic-Cretaceous Mist Mountain formation,
which outcrops in the front range of the Rocky
Mountains in the Elk Valley, Crowsnest and
Flathead coal fields.
The Gething formation contains over 20 m
[65 ft] of cumulative coal in the Pine River area.
The formation thins regionally southeastward
but maintains cumulative coal thicknesses of
about 6 m. A 1980 report of coal exploration in
the northern part of the Gething trend provides
information on gas contents from drill holes. The
data indicate high gas contents—up to
19.5 m3/tonne [620 scf/ton] at a depth of 459 m
[1506 ft] in at least one hole. Gething coal rank
generally decreases to the east and spans the
bituminous range.11 Face cleats within the
Gething coals in the north trend northwestsoutheast and, under the current stress regime,
may be closed.12
The Gates formation thins to the northwest
and its coal reserves are not as widespread as
those in the Gething formation. Where coal is
present in the Gates formation, it normally
contains four coal seams with an average total
thickness of 15 to 20 m [49 to 66 ft]. In 1996,
Phillips Petroleum drilled four wells to test the
Gates formation coals at a depth of 1300 to
1500 m [4270 to 4920 ft]. Gas contents measured
in these wells were promising and ranged from
6.3 to 29.2 m3/tonne [202 to 935 scf/ton],
although measured permeability was low. Face
cleats in Gates coal trend northeast-southwest
and may be perpendicular to the present
minimum stress direction. It is therefore reasonable to surmise that the face cleats in the Gates
formation may be open.
The outcrop exposures in the Peace River
coal field have given geologists insights
into the interrelationships between deformation, cleat development and present stress fields,
and their relationship to coal permeability. The
90
XX59
125 mm 375
Face Cleat
Bit Size
Orientation North
125 mm 375 0
Gamma
Ray
120
240
360 0
FMI Dynamic Image
Resistive
Conductive
0 API 150
deg
90
Bedding True Dip
0
deg
90
XX20
Shear
fractures
Face cleat
XX21
XX60
Butt cleat
Face cleat
XX22
Plains Coal
Foothills Coal
Face cleat
Butt cleat
Shear fracture
Bedding
> Comparison of FMI images from the Alberta plains coal and British Columbia foothills coal. The
image of a plains coal shows clear face- and butt-cleat development (top left). The images of the
foothills coal help geologists identify significant shear fracturing (top right). Outcrop exposures of
Alberta plains and British Columbia foothills coals show bedding planes, face and butt cleats, and
shear fractures. Features are marked on the outcrop photographs. The foothills coal (bottom right)
shows extensive shear fractures, while the plains coal does not (bottom left). Shear fracturing
degrades coal permeability.
combination of depth and deformation may have
significantly reduced the permeability in coal
seams in the Gething and Gates formations.
Intraseam shearing of these coals is thought to
have diminished coal permeability.
Coal outcrops provide extensive information
on stresses and coal-fracture systems. In the subsurface, many operators rely on borehole imaging
to determine the degree of cleating and natural
fracturing within the coals; in some wells, shear
fractures can be observed using borehole images
(above). Burlington Resources Canada and their
10. Bell JS and Bachu S: “In Situ Stress Magnitude and
Orientation Estimates for Cretaceous Coal Bearing
Strata Beneath the Plains Area of Central and Southern
Alberta,” Bulletin of Canadian Petroleum Geology 51, no.
1 (2003): 1–28.
11. Marchioni D and Kalkreuth WD: “Vitrinite Reflectance
and Thermal Maturity in Cretaceous Strata of the Peace
River Arch Region, West-Central Alberta and Adjacent
British Columbia,” Geological Survey of Canada, Open
File Report 2576, 1992.
12. Bachu S: “In Situ Stress Regime in the Coal-Bearing
Strata of the Northeastern Plains Area of British
Columbia,” Sigma H. Consultants Ltd. Invarmere BC,
Report for the Ministry of Energy and Mines, British
Columbia, 2002.
23
Depth, m
Orientation North
0
120
240
360
FMI Dynamic Image
Resistive
Conductive
Bedding
True Dip
0
Maximum horizontal
stress direction
Minimum horizontal
stress direction
Borehole
breakout
deg
90
Drilling-induced
fractures S45E
Induced
fracture
Borehole
breakout N45E
XX92
XX93
> In-situ stress determination from borehole images. During drilling operations, stress release around
the borehole causes induced fractures and borehole breakout (left). These phenomena indicate the
direction of in-situ stresses. The orientations of these features, interpreted from FMI data (right), are
used in hydraulic fracture treatment and deviated well designs.
Bed Boundary
True Dip
Bit Size
125
mm
375
0
Caliper 1
125
mm
Density
Caliper 2
Measured depth, m
125
mm
375 1000
API
Gamma Ray
45 to 75 API
Gamma Ray
< 45 API
2650
Neutron Porosity
Gamma Ray
0
kg/m3
150
1
m3/m3
0
Coal
ohm-m
2000
Orientation North
AIT Resistivity 10-in.
0.2
10
0
AIT Resistivity 90-in.
0.2
Photoelectric Factor
0
deg
90
Conductive Fracture
True Dip
375
ohm-m
2000
Fracture Aperture
2e-05
cm
0.2
0
120
240
deg
90
Drilling-Induced Fracture
True Dip
360 0
deg
90
Resistive Fracture
FMI Dynamic Image
True Dip
Resistive
Conductive
0
deg
90
XX16
XX18
Missing Core
XX20
XX22
XX24
> Montage of British Columbia foothills coal interval. The high degree of fracturing in the foothills
coals can make fullbore core recovery difficult. The interval shown was cored, but a short but crucial
section of core was lost from XX19 m to XX20 m. The FMI image, acquired across the interval, showed
that the missing core interval was heavily fractured. Gamma ray and caliper data are displayed in
Track 1 with borehole orientation. Track 2 contains porosity and lithology information. Fracture apertures calculated from FMI data are generally lower than in the plains coals and are displayed with
resistivity data in Track 3. Track 4 contains the dynamic FMI image from which bedding and fracture
planes were picked. Track 5 shows the dip plots from the interpretation of Track 4.
24
partners have acquired FMI data to determine
cleat and fracture directions, as well as presentday stress orientation. This information is used in
well planning and aids in the evaluation of
hydraulic fracture stimulation behavior and
effectiveness (left). Drilling-induced fractures
and borehole breakouts indicate orientation of
in-situ stresses. High-quality borehole images of
natural fractures facilitate interpretation of
paleostress orientations and fracture apertures.
Deviated wells are drilled perpendicular to the
dominant fracture set using FMI information
from nearby wellbores or uphole log data.
Borehole images also are used to orient and
depth-match cored intervals, particularly in
zones of poor core recovery (below left).
In addition to borehole imaging, shear and
compressional acoustic-velocity data have long
been used with other petrophysical measurements like bulk density, porosity and shale volume to derive rock elastic properties and to
determine closure-stress profiles for input to
hydraulic fracture designs.13 Although these
methods have been routinely used in western
Canada for several years, their application in
coals is a recent phenomenon.
Multiarray induction logs can provide
invasion profiles and qualitative comparisons
of cleating in coals. In Canada, geologists
and petrophysicists with Burlington and
Schlumberger are investigating a method to
assess coal permeability by examining drillingfluid invasion using AIT Array Induction Imager
Tool data. The AIT device provides resistivity
measurements at five depths of investigation,
ranging from 10 inches to 90 inches, and with
vertical resolutions of 1, 2 and 4 feet. The invasion profile is calculated using a model with a
fully flushed zone of diameter Di, followed by a
zone of transition to the uninvaded formation at
diameter Do. The model has been used to compute the invasion profile in two contrasting wells,
a low-permeability foothills CBM test well and a
higher permeability plains CBM well. Both wells
were drilled with fresh mud systems, providing a
good resistivity contrast between mud filtrate
and formation-water resistivity.
In the plains coals, the AIT analysis indicated
greater invasion where the FMI tool displayed
tensional fracturing (next page). The 1-ft [0.3-m]
resolution measurement was able to resolve the
effects of invasion in the vicinity of a fault seen on
13. Ali AHA, Brown T, Delgado R, Lee D, Plumb D, Smirnov
N, Marsden R, Prado-Velarde E, Ramsey L, Spooner D,
Stone T and Stouffer T: “Watching Rocks Change—
Mechanical Earth Modeling,” Oilfield Review 15, no. 2
(Summer 2003): 22–39.
Oilfield Review
Moved Water
AIT Resistivity 20-in.
0.2
Moved Hydrocarbon
ohm-m 2000
AIT Resistivity 60-in.
Density
Bit Size
125
mm
375
Measured depth, m
mm
375
Gamma Ray
0
API
Gamma Ray
45 to 75 API
Gamma Ray
< 45 API
150
Water
ohm-m 2000
Gas
1000 kg/m3 2650 AIT Resistivity 30-in.
Neutron Porosity
Caliper
125
0.2
0.2
0 AIT Resistivity 10-in.
Photoelectric Factor 0.2 ohm-m 2000
1
Quartz
m3/m3
0
Flushed Zone
Resistivity
20
Density Correction 0.2
900
Calcite
ohm-m 2000
kg/m3
Coal
ohm-m 2000
-100 AIT Resistivity 90-in.
0.2
Coal
Outer Invasion
Diameter
Inner Invasion
Diameter
ohm-m 2000 6000
mm
0
Static Young’s
Modulus
0
GPa
100
Poisson’s Ratio
6000 0
0.5 1
Bound Water
Illite
Volumetric
Analysis
vol/vol
0
XX70
XX75
XX80
XX85
> Invasion analysis in the Alberta plains coals. Using a ramp-style invasion model and AIT Array
Induction Imager Tool data, the plains coals show invasion up to 3.5 m [11.5 ft] in Track 4. Increased
invasion is associated with intervals showing tensional fracturing on the FMI images. The 1-ft resolution AIT measurement was able to resolve the effects of invasion near a fault seen on FMI images at
XX79.5 m. Log analysts use this information to gauge the amount of invasion, which may be related to
reservoir permeability. Track 1 displays gamma ray and caliper data. Track 2 contains porosity and
lithology information, and Track 3 contains resistivity data. Track 4 shows the invasion calculation, and
Track 5 contains mechanical properties data, which show a higher Poisson’s ratio and lower Young’s
modulus in the coals. Track 6 displays ELANPlus Elemental Log Analysis lithology results.
Autumn 2003
25
Moved Water
AIT Resistivity 20-in.
0.2
Moved Hydrocarbon
ohm-m 2000
AIT Resistivity 60-in.
Density
Bit Size
125
mm
375
Measured depth, m
mm
375
Gamma Ray
0
API
Gamma Ray
45 to 75 API
Gamma Ray
< 45 API
150
Water
ohm-m 2000
Gas
1000 kg/m3 2650 AIT Resistivity 30-in.
Neutron Porosity
Caliper
125
0.2
0.2
0 AIT Resistivity 10-in.
Photoelectric Factor 0.2 ohm-m 2000
1
Quartz
m3/m3
0
Flushed Zone
Resistivity
20
Density Correction 0.2
900
Calcite
ohm-m 2000
kg/m3
Coal
ohm-m 2000
-100 AIT Resistivity 90-in.
0.2
Coal
Outer Invasion
Diameter
Inner Invasion
Diameter
ohm-m 2000 6000
mm
0
Static Young’s
Modulus
0
GPa
100
Poisson’s Ratio
6000 0
0.5 1
Bound Water
Illite
Volumetric
Analysis
vol/vol
0
XX00
XX05
> Invasion analysis in British Columbia foothills coals. The foothills coals show relatively low invasion,
between 1 and 2 m [3 and 6 ft]. Shallow invasion profiles are observed in zones where the FMI image
showed a high degree of shear fractures. Track 1 displays gamma ray and caliper data. Track 2
contains porosity and lithology information and Track 3 contains resistivity data. Track 4 shows the
invasion calculation, and Track 5 contains mechanical properties data, which show a higher Poisson’s
ratio and lower Young’s modulus in the coals. Track 6 displays ELANPlus lithology results.
the FMI image at XX79.5 m. Further investigation
is needed to establish correlations to producibility. In contrast, the shear fractures observed on
the FMI images in the foothills coals were associated with zones showing less invasion on the AIT
invasion analysis (above). The log analysts
believe this analysis provides a dependable way to
gauge the degree of invasion, which may correlate
to reservoir-scale permeability.
Information from logs, core and outcrop can
be used in well construction. Proper cementing
of Canadian CBM wells is a major challenge
because of the fractured state of coals.
Frequently, primary cementing jobs fail to obtain
or maintain cement returns to the surface,
resulting in low cement tops and greater risk of
gas migration. Historically, operators have relied
on increasing the amount of excess cement
26
pumped to combat low cement tops, but a novel
solution known as CemNET advanced fiber
cement has yielded excellent results.
The CemNET slurry contains silica fibers that
bridge and plug lost-circulation areas, allowing
the slurry to return up the annulus. Operators
are benefiting from this unique technology by
pumping less cement, significantly reducing
cement-disposal costs and potential damage to
the coals. The long-term benefit is better
cemented wells without remedial cementing
costs. In extremely problematic lost-circulation
areas, CemNET fibers, coupled with the
LiteCRETE slurry system, have proved successful
in CBM areas in Canada and in Wyoming, USA.14
The combination of these technologies in
LiteCRETE CBM cement minimizes lost circulation problems, providing better cement coverage
that has helped reduce screenouts during
fracture-stimulation treatments in some Rocky
Mountain areas. Additionally, operators can
cement a well with a single production-quality
cement back to surface, which no longer poses
any constraints on the completion strategy.
Properly cemented wells prepare the way for
subsequent completion challenges. In CBM production areas worldwide, typically coal seams
first need to be dewatered to achieve maximum
gas production. This is also true in Canada,
although many dry coal seams have been found.
When stimulating coals that have minimal water
in their cleat systems, or low-pressure coals, a
compatible fracturing fluid system minimizes
damage to the permeability network. In Canada,
fracturing fluid selections have included pure
nitrogen only, guar-based systems or the
polymer-free ClearFRAC fracturing fluid.15 These
fluids have been foamed using either nitrogen or
carbon dioxide. The move to polymer-free
systems and foaming helps ensure improved
fluid flow to the wellbore without damaging
coal permeability.
Another common characteristic of Canadian
CBM targets is that they consist of multiple thin
coal seams; it is not unusual to have more than
20 seams present. Schlumberger CoilFRAC stimulation through coiled tubing technology has
allowed operators to economically perforate and
fracture all of these zones individually in a oneday operation.16 In some areas, Schlumberger is
fracturing more than 30 zones per well and can
stimulate two wells per day in certain circumstances. Operators benefit from reduced setup
costs, reduced gas flaring and significantly
reduced time from completion to gas sales.
CoilFRAC operations are suitable for environmentally sensitive areas since the equipment has
a smaller footprint than a service rig and most of
the equipment travels to the lease only once.
Efforts to exploit Canada’s vast CBM resources
have just begun. Armed with the historical knowledge of the coal mining industry, Canada’s CBM
operators continue to seek out optimal methods
for drilling, evaluating, completing and producing
coalbed reservoirs.
Development in the Raton Basin
The Raton basin is located in the southern Rocky
Mountains, along the boundary between New
Mexico and Colorado, USA. It was formed during
the late Cretaceous period and the early Tertiary
period. The Laramide uplift led to the erosion of
the ancestral Rocky Mountains and the creation
of an eastward prograding wedge of fluviodeltaic
sedimentation, including the deposition of
numerous coal beds. The basin contains two
Oilfield Review
Walsenburg
Ap
Basin axis
is
h
Ar
Colorado
New Mexico
Arc
Sa
h
ngr
e d
e
Las
C ri s t
A
Arc nimas
h
o Mou
ntains
ch
Autumn 2003
Holocene and
Alluvium, slopewash and
Quaternary
landslide material
Basalt flows
Huerfano formation
Middle Tertiary intrusives
Tertiary
Cuchara formation
Poison Canyon formation
Raton formation
Vermejo formation
Trinidad sandstone and
Cretaceous
Pierre shale undivided
Pierre shale/Niobrara undivided
Precambrian rock undivided
Raton basin boundary
a
14. LiteCRETE cement is a unique system based on the principle of trimodal particle sizes. At low cement densities,
it exhibits compressive strength similar to normal density
cements and maintains significantly lower permeabilities. For more on LiteCRETE slurry:
Low N, Daccord G and Bedel J-P: “Designing Fibered
Cement Slurries for Lost Circulation Applications: Case
Histories,” paper SPE 84617, presented at the SPE
Annual Technical Conference and Exhibition, Denver,
Colorado, USA, October 5–8, 2003.
Junaidi E, Junaidi H, Abbas R and Malik BZ: “Fibers In
Cement Form Network to Cure Lost Circulation,” World
Oil (June 2003): 48–50.
Walton D, Ward E, Frenzel T and Dearing H: “Drilling
Fluid and Cementing Improvements Reduced Per-Ft
Drilling Costs by 10%,” World Oil (April 2003): 39–47.
Raton
basin
ap
rra
Gra
nde
Raton
Sie
coal reservoir systems: the primary production
target, the Vermejo formation coals, at an
average depth of approximately 2000 ft [610 m],
and the overlying Raton formation coals, the
secondary coal target.
The Vermejo coals are moderately continuous
because they were deposited in swamps and in
floodplains within a fluvial-dominated delta
plain. Vermejo coals reach a combined thickness
of up to 40 ft [12 m] and average 20 ft [6 m] in
combined thickness, with an average individual
seam thickness of 2.6 ft [0.8 m], over a 275-ft
[84-m] gross interval. By contrast, the Raton
coals are thinner and less continuous because
their deposition was typically overbank into the
backswamp environments associated with meandering river systems. Raton coals can exceed
75 ft [23 m] in gross thickness, but individual
seams average 1.5 ft [0.5 m] in thickness.
During the Miocene epoch, an igneous
complex called the Spanish Peaks intruded into
the basin.17 Igneous activity formed a complex
network of dikes, sills and fractures that have
influenced the reservoir characteristics of both
coals and sandstones (right).18 The mid-Tertiary
burial and the late-Tertiary uplift and erosion in
the southern part of the basin, coupled with the
late-Tertiary intrusions and associated heating,
caused the overall fluid pressure in the basin to
drop.19 This complicated geologic history has
made the Raton basin difficult to understand
and develop.
With CBM operations in several US basins
and over 1.9 Tcf [54.4 billion m3] in CBM
reserves, El Paso Production Corporation has
studied the Raton basin extensively since 1989.
El Paso has drilled more than 350 wells and has
recovered more than 42,000 ft [12,800 m] of fullbore core in the basin, making these coals some of
the most studied CBM reservoirs in the industry.
Vast amounts of lithologic, gas-content and
isotherm data from cores taken across El Paso’s
acreage have been examined and used to model
the CBM reservoirs. These data have also been
instrumental in the calibration of log interpretation techniques, including ELANPlus Elemental
0
0
20 km
15 miles
> Surface geology of the Raton basin. The 2200-square mile [5700-km2] basin contains two coal reservoir systems: the primary production target, the Vermejo formation coals (pale yellow), at an average
depth of 2000 ft [610 m], and the overlying Raton formation coals (light brown), which is a secondary
coal target. Tertiary igneous sills and dikes of the Spanish Peaks intrusion (magenta) have altered
coals locally. (Adapted from Flores and Bader, reference 18.).
Log Analysis computations. Since 2001, El Paso
has acquired Platform Express and ECS data on
290 wells, and DSI and FMI data on strategically
located wells across the Vermejo Park Ranch.
Borehole images have been used along with outcrop and core data in a comprehensive effort to
model the basin’s fracture systems.20
Al-Suwaidi A, Hun C, Bustillos J, Guillot D, Rondeau J,
Vigneaux P, Helou H, Martínez Ramírez JA and Reséndiz
Robles JL: “Light as a Feather, Hard as a Rock,” Oilfield
Review 13, no. 2 (Summer 2001): 2–15.
15. Chase B, Chmilowski W, Marcinew R, Mitchell C, Dang Y,
Krauss K, Nelson E, Lantz T, Parham C and Plummer J:
“Clear Fracturing Fluids for Increased Well Productivity,”
Oilfield Review 9, no. 3 (Autumn 1997): 20–33.
16. Degenhardt KF, Stevenson J, Gale B, Gonzalez D, Hall S,
Marsh J and Zemlak W: “Isolate and Stimulate Individual
Pay Zones,” Oilfield Review 13, no. 3 (Autumn 2001):
60–77.
17. Rose PR, Everett JR and Merin IS: “Potential BasinCentered Gas Accumulation in Cretaceous Trinidad
Sandstone, Raton Basin, Colorado,” in Geology of Tight
Gas Reservoirs, AAPG Special Publication. Tulsa,
Oklahoma, USA: AAPG (1986): 111–128.
18. Flores RM and Bader LR: “A Summary of Tertiary Coal
Resources of the Raton Basin, Colorado and New
Mexico,” in 1999 Resource Assessment of Selected
Tertiary Coal Beds and Zones in the Northern Rocky
Mountains and Great Plains Region, U.S. Geological
Survey Professional Paper 1625-A.
19. Stevens SH, Lombardi TE, Kelso BS and Coats JM: “A
Geologic Assessment of Natural Gas from Coal Seams in
the Raton and Vermejo Formations, Raton Basin,” Gas
Research Institute Topical Report, GRI 92/0345, Contract
No. 5091-214-2316, 1992.
20. Rautman CA, Cooper SP, Arnold BW, Basinski PM,
Mroz TH and Lorenz JC: “Advantages and Limitations of
Different Methods for Assessing Natural Fractures in the
Raton Basin of Colorado and New Mexico,” in Assessing
Natural Fractures in the Raton Basin, June 2002.
27
Ash
Fixed Carbon
Moved Water
Crossover
ohm-m
Density Porosity
2
2000
AIT Resistivity 20-in.
Depth, ft
2
2
Caliper > Bit Size
16
2
0
Gamma Ray < 75
API
1
ohm-m
2000
2
ohm-m
Epithermal Neutron
Porosity
Calcite
g/cm3
Quartz
1.7
Density 1-in.
ohm-m
g/cm3
2000 1
Pyrite
0.05
AIT Resistivity 90-in.
200 2
Carbonate
Dolomite
Density 2-in.
2000 1
Water
Effective Porosity
ft3/ft3
Hydrocarbon
Water
Gas
8
0.3
Flushed Zone Resistivity
Gamma Ray
0
0.05
Photoelectric Factor
2000
Formation Water
Resistivity
ECS Capture Hydrogen
1
ft3/ft3
Moisture
Irreducible Water
AIT Resistivity 60-in.
Caliper
in.
ohm-m
0.3
2000
AIT Resistivity 30-in.
Gas
6
ohm-m
Volatiles
Moved Hydrocarbon
AIT Resistivity 10-in.
Coal
Bound Water
1.7
Illite
Intrinsic Permeability
Water Saturation
ft3/ft3
1
0
Volume Water
0.25
ft3/ft3
0
Effective Porosity
0.25
ft3/ft3
0
Irreducible Water
Flushed Zone
0.25
ft3/ft3
Poorly
Cleated
XX00
10
mD
10
Permeablility to Gas
0.01
Well
Cleated
mD
Permeablility to Water
0.01
Partially
Cleated
mD
10
Hydrocarbon
Water
0
Irreducible Water
Water
Saturation
ft3/ft3
XX50
0.35
0.14
0.94
0.35
0.06
0.44
0.35
0.13
0.08
1.00
0.35
0.35
0.07
0.06
0.41
0.64
0.35
0.35
0.10
0.65
0.11
0.57
0.35
0.11
0.35
0.12
0.48
0.44
0.35
0.01
Integrated Coal
Footage
Estimated Gas
0
Mcf/day 300
Estimated Gas
Mcf/day
33.50
161.07
27.50
143.49
1.00
> Characterizing coal and noncoal resources. With ECS Elemental Capture Spectroscopy and Platform Express data, an
ELANPlus analysis is computed. Lithology is presented in Track 4. Proximate (Track 5) and cleat analysis (Track 6) provide
information on coal quality. Computed permeabilities are in Track 7 and estimated gas production is displayed in Track 8. El
Paso also uses the ELANPlus processing to calculate the reserves in the surrounding sandstones and siltstones.
Even with this extensive database, the Raton
basin remains a challenging area in which to
operate because of numerous complicating
factors. First, gas-content values in the Vermejo
and Raton formation coals vary across the basin,
ranging from 50 to more than 400 scf/ton [1.56 to
12.48 m3/tonne], on an in-situ basis. The deeper
Vermejo coals are typically gas-saturated and
lend themselves to log-based interpretation techniques. However, selected shallower Vermejo and
many Raton formation coals are undersaturated
to varying degrees because they have been
affected by the basin’s complex burial, thermal,
pressure and hydrological history. As a result,
variations in gas saturation relative to the
isotherm complicate efforts to model the coals’
productive potential and make log-based
estimation of gas content and saturation profiles
more difficult.
28
Another complicating factor is that the hot
intrusions locally altered the rank and the cleat
and fracture permeability of the coals. The alteration of coal to a higher rank directly affects its
productive potential. The intrusive bodies have
changed bituminous coal into higher rank coal,
so the impact on gas content is inconsistent and
not yet predictable.
El Paso’s understanding of the reservoirs and
the basin as a whole has allowed the company to
improve its models and adopt strategies in
drilling, completion, stimulation and production
that maximize environmentally sound exploitation. For example, El Paso drills Raton basin
CBM wells using air as the drilling fluid, thereby
minimizing the damage to the coal’s cleat and
natural-fracturing systems. Wireline logging is
accomplished with air in the borehole by acquiring epithermal neutron data in combination with
the Platform Express tool.21
The Platform Express tool is designed to
minimize the adverse borehole-rugosity effects
on the density measurement commonly observed
in coals and in air-filled boreholes. Detailed
lithology of both the coals and the surrounding
low-permeability gas sandstone is computed
using the ECS tool, and SpectroLith and
ELANPlus processing. Log-based proximate
analysis is also performed in the coals to determine the percentages of volatile matter, fixed
carbon, moisture and ash, based on benchmarking to voluminous core data. From these percentages, coal rank and adsorbed gas volume can be
estimated (above). In addition, the logs provide a
qualitative estimate of the degree of cleating.
The DSI tool also provides El Paso with valuable information on fractures and in-situ stress
fields by measuring shear wave anisotropy.
Anisotropy causes shear waves to split into two
components, one polarized along the direction of
Oilfield Review
Autumn 2003
Fast Shear Slowness
µs/ ft
950
50
Slow Shear Slowness
0
API
in.
20
Minimum 5
Cross
Tool
Azimuth
Energy
0
100
deg
50
Anisotropy–Slowness
150
Energy
Difference Hole Diameter Quality
0
µs/ ft
950
Gamma Ray
0
100
Anisotropy – Time
Fast Shear Azimuth
100
0
Anisotropy
360
Azimuth Uncertainty
Hole Azimuth
Maximum
Cross 0
deg
360
Fast Shear Azimuth
Energy
Gamma Ray
<
75 API
-90
deg
90 Slowness
0
100
>16
8-16
4- 8
2- 4
0- 2
< Understanding the
stress fields. Anisotropy
data from the DSI tool
are used to compute
the fast shear direction
that corresponds with
the maximum horizontal in-situ stress direction. Here, the fast
shear direction is oriented NNE to NNW
(Track 2). The abrupt
shift in fast shear
azimuth in the coal at a
depth of X060 ft is not
fully understood.
Time
NW 8
Depth, ft
maximum velocity, and the other along the direction of minimum velocity. With two transmitters
and two sets of receivers oriented perpendicular
to one another, the DSI tool can measure both
the in-line waveforms from receivers oriented in
the same azimuth as the transmitter, and
crossline waveforms from receivers oriented 90°
from the transmitter.22
During the DSI measurement, there is no way
to know how the signals are oriented with
respect to anisotropy. However, with both in-line
and crossline waveforms, it is possible to perform
a mathematical rotation to find the azimuth of
the fast shear wave, and to determine the velocities of both fast and slow shear waves. This rotation relies on the fact that the crossline
waveforms should vanish when the measurement
axis is aligned with the anisotropy axis. The processing also computes the energy in the crossline
waveforms as a percentage of the total waveform
energy. When the two axes are aligned, the result
is known as the minimum energy and is zero if
the rotation model is correct. The maximum
energy is the energy at 90°. The difference
between minimum and maximum is known as
energy anisotropy and is the principal measure of
anisotropy from DSI data.
The polytectonic history of the Raton basin has
introduced other complications. For example,
late-Tertiary changes in the regional stresses from
compression to tension, thought to be caused by
Rio Grande rifting to the west, have major implications for field development, especially in terms
of well placement and stimulation practices. Prior
to acquisition of key log data by El Paso, the Raton
basin’s maximum principal stress direction was
believed to be east-west, consistent with a
compressional basin model. FMI images and DSI
anisotropy data have shown that the maximum
principal stress direction is actually north-south
(above right). This change has significant implications for planning field development and well
stimulations (see “Refracturing Works,” page 38).
Fracture stimulation will tend to propagate in this
north-south direction and, given an east-west
Laramide-age open natural-fracture system,
optimal drainage aspect ratios are anticipated. As
a result, where possible, development wells are
not positioned due north-south or east-west of one
another; this maximizes ultimate drainage areas
and gas recovery.
Currently, El Paso is assessing two different
hydraulic fracture stimulation treatments in the
Raton basin. The first is a low-polymer borate
fracturing fluid and higher concentrations of
proppant, delivered using coiled tubing and
NW 2
NW 5
NW 6
NW 7
X050
NW 41
NW 61
NE 15
NE 4
NE 11
NE 13
NE 0
NW 17
NE 18
NE 11
X100
NE 23
NE 21
NE 20
NE 11
NE 32
straddle packers. This technique has been beneficial in wells where six to eight different coalbed
layers have been identified for stimulation. These
polymer-base fluids have been more successful in
areas that initially produce large amounts of
water, and where cleat- and fracture-system
damage is of less concern. However, in areas
where the coals initially produce low volumes of
water, degrading the permeability to gas within
the cleats and fractures is likely with polymer
liquids. In these areas, El Paso is evaluating a
second technique of pumping foamed nitrogen
down casing to hydraulically fracture the coals
and place smaller proppant concentrations.
The complexity and variability in the Raton
basin make it extremely difficult to gauge the
success of fracture stimulation treatments in
well-performance terms. The search for the ideal
treatment continues, but it is generally agreed
that more information is needed on hydraulic
fracture propagation in and around coals.
Coalbed Completion Strategies
Coals often are adjacent to productive sands that
have dramatically different mechanical properties. Coal has a higher Poisson’s ratio and a lower
Young’s modulus than sand, so coals tend to
transfer overburden stress laterally and maintain
higher fracture gradients. Cleating and natural
fracturing in coals create complex hydraulic
fracturing scenarios that are extremely difficult
to model.23
21. The epithermal neutron measurement is based on the
slowing down of neutrons between a source and one or
more detectors that measure neutrons at the epithermal
level, where their energy is above that of the surrounding matter. In air-filled boreholes, the lack of hydrogen
dramatically changes the thermal neutron population
near the detectors, invalidating the response of a standard thermal neutron log. The epithermal measurement
is less affected by the borehole and by using an array of
back-shielded detectors, as in the APS Accelerator
Porosity Sonde device, can be calibrated to give porosity. Also, by measuring neutrons at the epithermal level,
the effects of thermal neutron absorbers are avoided.
22. Armstrong P, Ireson D, Chmela B, Dodds K, Esmersoy C,
Miller D, Hornby B, Sayers C, Schoenberg M, Leaney S
and Lynn H: “The Promise of Elastic Anisotropy,” Oilfield
Review 6, no. 4 (October 1994): 36–47.
23. Olsen et al, reference 4.
29
Flushed Zone
Resistivity
2
ohm-m
Pore Pressure
Gradient
2000
psi/ft
AIT Resistivity 90-in.
2
Caliper
6
in.
Depth, ft
mV
16 2
API
ohm-m
2000
AIT Resistivity 20-in.
20 2
Gamma Ray
0
2000
Water
ohm-m
2000
Sand
Coal
106 psi
ohm-m
2000
psi/ft
10
0
106 psi
0
Poisson’s Ratio
Static
Fracture Pressure
Young’s Modulus
Dynamic
Poisson’s Ratio
Dynamic
psi
Closure Stress
10
Bound Water Young’s Modulus
AIT Resistivity 10-in.
Static
Shale
106 psi
200 2
Fracture Gradient
Young’s Modulus
Dynamic
AIT Resistivity 60-in. Hydrocarbon 0
Spontaneous
Potential
-80
ohm-m
980
10 980
psi
2380
Closure Stress Averaged
psi
0
0.5
Poisson’s Ratio
Static
2380 0
0.5
X350
Stress in coal
is higher than in
surrounding layers
X400
> Stress contrast. Coals are typically more stressed than surrounding rocks (blue arrows). This
contrast inhibits fracture growth within the coals and promotes fracture growth in surrounding sands
and siltstones. Multiple fractures of limited length can also be created in the coals, causing damage to
coal permeability, slower dewatering and reduced gas production. Where adjacent sandstones have
productive potential, a technique called indirect vertical fracturing (IVF) initiates the fracture in the
less-stressed sands above or below the coal. This creates fractures of greater half-length, which
contact and drain the coal more effectively. Gamma ray and caliper data are shown in Track 1 and
resistivity data are displayed in Track 2. Lithology and volumetric information is shown in Track 3.
Track 4 contains Young’s modulus and pore pressure gradient data and Track 5 displays closure stress
and fracture pressure data zoned for input into hydraulic fracture design programs. Poisson’s ratio
data are presented in Track 6.
24. Almaguer J, Manrique J, Wickramasuriya S, Habbtar A,
López-de-Cárdenas J, May D, McNally AC and
Sulbarán A: “Orienting Perforations in the Right Direction,”
Oilfield Review 14, no. 1 (Spring 2002): 16–31.
Manrique JF, Poe BD Jr and England K: Production
Optimization and Practical Reservoir Management of
Coal Bed Methane Reservoirs,” paper SPE 67315, presented at the SPE Production Operations Symposium,
Oklahoma City, Oklahoma, USA, March 26–29, 2001.
25. Palmer ID, Puri R and King GE: “Damage to Coal
Permeability During Hydraulic Fracturing,” paper SPE
21813, presented at the SPE Rocky Mountain Regional
Meeting and Low-Permeability Reservoirs Symposium,
Denver, Colorado, USA, April 15–17, 1991.
26. Olsen et al, reference 4.
27. Gas lock is a condition sometimes encountered in a
pumping well when dissolved gas, released from solution
during the upstroke of the plunger, appears as free gas
between the valves. On the downstroke, pressure inside
30
a barrel completely filled with gas may never reach the
pressure needed to open the traveling valve. In the
upstroke, the pressure inside the barrel never decreases
enough for the standing valve to open and allow liquid to
enter the pump. Thus no fluid enters or leaves the pump,
and the pump is locked. It does not cause equipment
failure, but with a nonfunctional pump, the pumping
system is useless. A decrease in pumping rate is accompanied by an increase of bottomhole pressure (or fluid
level in the annulus). In many cases of gas lock, this
increase in bottomhole pressure can exceed the pressure
in the barrel and liquid can enter through the standing
valve. After a few strokes, enough liquid enters the pump
to break the gas lock, and the pump functions normally.
28. Schwochow, reference 2.
29. Albright J, Cassell B, Dangerfield J, Deflandre J-P,
Johnstad S and Withers R: “Seismic Surveillance for
Monitoring Reservoir Changes,” Oilfield Review 6, no. 1
(January 1994): 4–14.
Devices such as the DSI tool help determine
accurate in-situ stress magnitudes and directions
to improve hydraulic fracturing designs. In addition, borehole images allow determination of the
preferred fracture plane, which reflects the
current stress conditions at the wellbore. This
information is used to devise perforation
strategies that maximize the efficiency of
hydraulic fracturing operations by reducing nearwellbore tortuosity effects that lead to early
screenout.24 The relationship between coal cleats
and horizontal stresses is equally important and
can help explain CBM production variations
between wells and between production areas.
The effectiveness of hydraulically fracturing
individual coals has been debated because of
these inherent complexities. Proppant volumes
used in coal stimulations can be as high as
12,000 lbm/ft [17,700 kg/m] of coal, but the
effective hydraulic fracture half-lengths are disappointingly low—rarely documented over 200 ft
[60 m]. Hydraulic fractures can grow out of zone
or develop into complex fracture networks within
the coal, often damaging coal permeability when
polymer-base fracturing fluids are used.25
Some experts believe that CBM reserves
would triple if fracturing coals were as effective
as fracturing sandstones. Mechanical properties
from DSI data show the stress contrast between
coals and surrounding layers, enabling engineers to predict fracture height and improve
stimulation treatments (left). In areas where
adjacent sandstones have productive potential,
operators are reexamining their perforating and
stimulation strategies in coals and sandstones. A
technique called indirect vertical fracturing
(IVF) initiates the fracture in the less-stressed
sandstones above or below the coal to ensure
adequate fracture propagation.26 In coals, this
technique succeeds because the vertical
permeability of coal is frequently greater than its
horizontal permeability, reducing the need for a
hydraulic fracture to completely pass through
the coal to effectively drain it. Another reason for
the success of this technique in coals is due to
the contrast in fracture gradient between the
surrounding clastic rocks and the coal. This
difference helps ensure fracture connection with
the coal seam along the length of the hydraulic
fracture. This technique was first demonstrated
in the Fruitland coal and Picture Cliff sands
of the San Juan basin in New Mexico and is
currently being employed successfully in the
central Rocky Mountains.
Oilfield Review
Dewatering Methods
In a majority of CBM wells, water production is
crucial to the gas-production process. Successful
dewatering requires uninterrupted pumping
operations to decrease the bottomhole pressure
so gas will desorb from the matrix and diffuse
into the cleat systems as quickly as possible.
Pumping methods vary according to area lift
requirements and economics. Pumps must
handle large volumes of water and be resistant to
coal fines, proppant damage and gas lock.27 These
requirements have made progressing cavity
pump deployment one of the more attractive lift
methods for CBM applications. The selection and
design of an appropriate lift method often are not
straightforward and should focus on capacity,
efficiency and dependability.
Schlumberger engineers and scientists at the
Abingdon Technology Center and Cambridge
Research Center in England are developing software to aid in artificial-lift selection specific to
gas-well dewatering. The Gas Well Dewatering
Selection Tool (GDST) brings consistency to
this critical selection process by utilizing the
available well information to select the most
appropriate lift method. This software helps
Schlumberger field engineers, interacting with
the clients, use a selection process based on
sound engineering practice. The tool provides a
case-based reasoning engine and sensitivity
analysis to obtain recommendations with
defined confidence levels.
The economic drivers for CBM wells differ
from conventional gas wells in that most wells
will not require indefinite or increased dewatering through time. The GDST program enables
the engineer to make several iterations to determine the best lift method. The program does not
provide for comparative economics of lift methods, although economic limitations of the proposed lift methods are considered in the
selection process. The tool is designed to aid in
the selection of lift methods, including those that
may not have been considered previously. (above
right). An optimal dewatering strategy, coupled
with nondamaging cementing and stimulation
techniques, helps expedite water movement out
of the coal’s fracture permeability network,
thereby increasing well productivity.
Gas for the Future
The exploitation of CBM resources is progressing
steadily. In the USA, natural gas prices have
made many areas—for example the Green River
region, Piceance basin, Arkoma basin and
Cherokee basin—more attractive for CBM
drilling, although some are not yet producing
Autumn 2003
Reservoir Information
270 psi
Bottom Hole Flowing Pressure
Bottom Hole Static Pressure
1,000 psi
Reservoir Temperature
Liquid Composition
275 F
Plunger Lift
>30% Condensates
Wellhead Compression
Production Information
250 bbl/D
Current Liquid Rate
Current Gas Rate (MMscfd)
>600
Production Tubing Size (OD in inches)
Up to 2-7/8”
SandProduction
No
Velocity Strings
Siphon Strings
Foaming
Continuous Gas Lift
Well Head Pressure
150 psi
Intermittent GL Plunger
Sales Line Pressure
140 psi
Intermittent Chamber Lift
Well Depth
2,500 ft
Casing Size (OD in inches)
>4-1/2”
Well Deviation
High
Requires Packer
Yes
Rod Pump
Hydraulic Jet Pump
ESP
PCP
Site Information
Electricity Available
No
Injection/compressed Gas Available
No
Comments
Sufficient Information entered
Confidence
> The Gas Well Dewatering Selection Tool (GDST) software. The GDST helps
Schlumberger field engineers and clients select the most appropriate lift
method, using a consistent selection process. Length of dark blue bars on the
right indicates preferred dewatering methods.
significant volumes of natural gas. Tremendous
CBM reserves in the US Gulf Coast region have
yet to be tapped, but CBM activity has started in
the Cook Inlet, Alaska, USA.28 Worldwide, many
countries have just started investigating their
CBM resources. Local activity will grow out of
necessity and out of the knowledge of how these
reservoirs behave.
Formation-evaluation methods, together with
fullbore core data, are helping the industry
understand coal reservoirs. Log processing techniques yield detailed lithology, and proximate
and permeability data. Cleat and fracture
systems are studied along with important
local stress information through the use of borehole imaging techniques to more thoroughly
appreciate coal-seam permeability.
Coal-seam permeability, controlled by events
that occurred during deposition, maturation and
tectonism, has surfaced as the most important
factor in CBM production. Coal fracture systems
must be connected successfully to the wellbore
through nondamaging stimulation methods.
However, complex stress profiles and coal
fracture systems make hydraulic fracture propagation in and around coals difficult to simulate.
New fracture-monitoring technology promises
real-time images of hydraulic fracture creation.
Early passive-seismic technologies performed
primitive hydraulic fracture monitoring, but
processing these data was tedious and timeconsuming, and did not provide real-time
information during fracturing operations.29 The
StimMAP hydraulic fracture stimulation diagnostics software allows real-time, onsite imaging of
hydraulic fracture seismic events, resulting in
improved job placement, enhanced well productivity and a better understanding of fracture
geometry for future field-development decisions.
Although the industry’s knowledge of coal is
vast and growing, modeling CBM reservoir behavior has been a challenging task. Schlumberger
has improved coal reservoir modeling capabilities in ECLIPSE Office integrated simulation
manager and case builder software. This new
software incorporates isotherm data and handles
uncertainties, and will have the capability to
manage multiple gas types.
The nature of CBM development demands
careful economic consideration. Low-cost solutions can help, but technological advances in
drilling, formation evaluation, completion, stimulation, production and reservoir modeling will
have a far greater impact. With immense worldwide reserves and a growing infrastructure to
exploit them economically, coal ranks high on
the short list of unconventional fuels awaiting
future development.
—MG, JS
31