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Regional overview of deepsedimentary thermal gradientsof the geopressured zoneof the Texas–Louisianacontinental shelf
AAPG Bulletin, v. 92, no. 1 (January 2008), pp. 1–14

A new technology for thecharacterization ofmicrofractured reservoirs(test case: Unayzah reservoir,Wudayhi field, Saudi Arabia)
AAPG Bulletin, v. 92, no. 1 (January 2008), pp. 31–52

Coal reservoir saturation:Impact of temperatureand pressure 
AAPG Bulletin, v. 92, no. 1 (January 2008), pp. 77–86

Characterizing the shalegas resource potential ofDevonian–Mississippianstrata in the WesternCanada sedimentary basin:Application of an integratedformation evaluation
AAPG Bulletin, v. 92, no. 1 (January 2008), pp. 87–125

History of the Newark Eastfield and the Barnett Shaleas a gas reservoir
AAPG Bulletin, v. 91, no. 4 (April 2007), pp. 399–403

Geologic framework of theMississippian BarnettShale, Barnett-Paleozoic totalpetroleum system, Bendarch–FortWorth Basin, Texas
AAPG Bulletin, v. 91, no. 4 (April 2007), pp. 405–436
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Regional overview of deepsedimentary thermal gradientsof the geopressured zoneof the Texas–Louisianacontinental shelf

Seiichi Nagihara and Michael A. Smith

ABSTRACT
Nearly 600 bottom-hole temperature data from the northern continental
shelf of the Gulf of Mexico, each corrected for drilling
disturbance, yielded a regional map of geothermal gradient down to
approximately 6 km (3.7 mi) sub–sea floor. Two geographic trends
can be seen on the map. First, from east to west, the geothermal
gradient changes from values between 0.025 and 0.03 K/m (0.014
and 0.016jF/ft) off the Alabama–Mississippi shore to lower values
of 0.015–0.025 K/m (0.008–0.014jF/ft) off eastern Louisiana
and to higher values of 0.03–0.06 K/m (0.016–0.033jF/ft) off
western Louisiana through Texas. Second, thermal gradients tend to
be lower toward the outer continental shelf (less than 0.02 K/m
[0.0112jF/ft]). We believe that the observed variations are primarily
attributable to the thermal effect of rapid and regionally
variable sediment accumulation during the Cenozoic era, which
resulted in the occurrence of the geopressured zone in the Texas–
Louisiana shelf. In the eastern Louisiana shelf, where accumulation
was fastest, sediments down to about 6 km (3.7 mi) are relatively
young (about <15 Ma) and have not had enough time to fully
equilibrate with deeper, hotter sediments. That resulted in the low
thermal gradient. As the depocenter migrated farther offshore,
younger sediments accumulatedmore in the outer shelf and resulted
in an even lower thermal gradient there. However, this mechanism
alone cannot explain the fact that geothermal gradients in the
Texas shelf are higher than those in the Alabama shelf, where Cenozoic
sedimentation has been much slower. It may be suggested

A new technology for thecharacterization ofmicrofractured reservoirs(test case: Unayzah reservoir,Wudayhi field, Saudi Arabia)

Mohammed S. Ameen and Ernest A. Hailwood

ABSTRACT
This article presents a test case of a new technology using artificially
enhanced anisotropy of magnetic susceptibility (referred to here as
EAMS) for the characterization of microfractured reservoirs. These
are reservoirs in which microfractures are essential to porosity and/or
permeability. A conventional geological characterization is costly,
time consuming, and difficult to quantify in terms of assessing fracture
impact on porosity and permeability. Therefore, an efficient and
effective method is required to characterize these microfractures and
to determine their contribution to porosity and permeability. The
EAMS technology, which we developed and tested, allows rapid
analysis that bridges reservoir geology and engineering. Using petrography,
the margin of error to detect microfractures that impact porosity
and/or permeability is 43%; however, it requires three times
the sampling rate of the new EAMS technology.
The lower part of the Unayzah reservoir (Unayzah-B/C) in the
Wudayhi field, Saudi Arabia, where fractures were studied and microfractures
are known to impact reservoir performance, is used
to develop and verify the EAMS technology. The results show that
EAMS-derived microfracture fabric strikes east-northeast–westsouthwest,
consistent with that obtained by geological means. The
effective-porosity profile obtained from EAMS tests is similar to
that of the conventionally acquired porosity. Open microfractures
in tested samples increase mean values of reservoir effective porosity
by 36–50% in Unayzah-B/C. The occurrence of connected microfractures
is estimated to cause an increase in average permeability of
75% in Unayzah-B/C. This is in agreement with the fact that wells

Coal reservoir saturation:Impact of temperatureand pressure

Amanda M. M. Bustin and R. Marc Bustin

ABSTRACT
Methane adsorption isotherms measured for a series of coals with
varying rank at a wide range of temperatures and pressures allows
the prediction of the change in sorption capacity as a function of
tectonic history. Changes in sorption capacity in response to declining
pressure and temperature associated with uplift may increase or
decrease the capacity of the coal and, if the coal is initially saturated,
result in excess gas or a deficiency of gas (undersaturation). Assuming
reasonable geothermal and pressure gradients, our data indicate
that the sorption capacity will generally decrease with uplift and associated
exhumation, suggesting that an initially gas-saturated coal
will desorb gas during uplift of the reservoir. The desorbed gas would
be available for migration and/or, potentially, resaturation of an undersaturated
coal. Our results argue against the generally accepted
theory that undersaturation of coal reservoirs results froman increase
in the sorption capacity with uplift except for coals at such high pressures
that the isotherms are essentially flat or for very high pressure
and geothermal gradients.

Characterizing the shalegas resource potential ofDevonian–Mississippianstrata in the WesternCanada sedimentary basin:Application of an integratedformation evaluation

Daniel J. K. Ross and R. Marc Bustin

ABSTRACT
Devonian–Mississippian strata in the northwestern region of the
Western Canada sedimentary basin (WCSB) were investigated for
shale gas potential. In the subsurface, thermally mature strata of the
Besa River, Horn River, Muskwa, and Fort Simpson formations attain
thicknesses of more than 1 km (0.6 mi), encompassing an area
of approximately 125,000 km2 (48,300 mi2) and represent an enormous
potential gas resource. Total gas capacity estimates range between
60 and 600 bcf/section. Of particular exploration interest
are shales and mudrocks of the Horn River Formation (including
the laterally equivalent lower Besa River mudrocks), Muskwa Formation,
and upper Besa River Formation, which yield total organic
carbon (TOC) contents of up to 5.7 wt.%. Fort Simpson shales seldom
have TOC contents above 1 wt.%. Horn River and Muskwa
formations have excellent shale gas potential in a region between
longitudes 122jW and 123jW and latitudes 59jN and 60jN (National
Topographic System [NTS] 94O08 to 94O15). In this area,
which covers an areal extent of 6250 km2 (2404mi2), average TOC
contents are higher (>3 wt.% as determined by wire-line-log calibrations),
and have a stratal thickness of more than 200 m (656 ft).
Gas capacities are estimated to be between 100 and 240 bcf/section
and possibly greater than 400 tcf gas in place. A substantial percentage
of the gas capacity is free gas caused by high reservoir temperatures
and pressures.Muskwa shales have adsorbed gas capacities
ranging between 0.3 and 0.5 cm3/g (9.6–16 scf/t) at reservoir

History of the Newark Eastfield and the Barnett Shaleas a gas reservoir

David F. Martineau

INTRODUCTION
In 2006, the Newark East field was the largest producing gas field
in Texas, and according to the Energy Information Administration
(EIA) latest reserves estimate (EIA, 2006, tables B2 and B4), Newark
East field ranks third in the nation and second in the nation in
terms of production. The Newark East field has generated considerable
attention because the gas is produced from the Barnett Shale
as opposed to conventional sandstone, conglomerate, or carbonate
reservoirs. The field was discovered in 1981 byMitchell Energy Corporation
(MEC) in Wise County, Texas, located in the Fort Worth
Basin in north central Texas. George Mitchell, founder and chief
executive officer of MEC, had the vision and leadership behind
MEC’s continued exploration and research for the correct technology
to extract gas from this unconventional gas reservoir. Dan
Steward was the chief geologist for MEC during the critical exploration
development of the Barnett Shale and was honored by AAPG
with the 2007 Outstanding Explorer Award. The development of
the field started slowly, and only 100 wells were completed between
1981 and 1990. In 1998, a major breakthrough in completion technique
occurred when water fracturing replaced gel fracturing. From
1997 to 2006, more than 5829 wells were put on production, and
hundreds of additional wells were drilled, completed, or waiting on
a pipeline. The field has been divided into two areas: (1) the original
core area, where the Barnett sits on top of the Viola Limestone, and
(2) the expansion area, where the Barnett sits on top of the Ellenburger
Group. Vertical wells were the primary drilling method until
2002. Devon Energy, who subsequently bought Mitchell Energy,
drilled seven experimental horizontal wells in both the core and
expansion areas. The excellent success of these wells prompted
many operators to move their drilling mode from vertical to horizontal
and to move into the expansion area. The U.S. Geological
Survey in 2004 reported the potential of both core and expansion
areas of the field to be 26.2 tcf (U.S. Geological Survey, 2004). This

Geologic framework of theMississippian BarnettShale, Barnett-Paleozoic totalpetroleum system, Bendarch–FortWorth Basin, Texas

Richard M. Pollastro, Daniel M. Jarvie, Ronald J. Hill,
and Craig W. Adams

ABSTRACT
This article describes the primary geologic characteristics and criteria
of the Barnett Shale and Barnett-Paleozoic total petroleum
system (TPS) of the Fort Worth Basin used to define two geographic
areas of the Barnett Shale for petroleum resource assessment. From
these two areas, referred to as ‘‘assessment units,’’ the U.S. Geological
Survey estimated a mean volume of about 26 tcf of undiscovered,
technically recoverable hydrocarbon gas in the Barnett Shale.
The Mississippian Barnett Shale is the primary source rock for
oil and gas produced fromPaleozoic reservoir rocks in the Bend arch–
Fort Worth Basin area and is also one of the most significant gasproducing
formations in Texas. Subsurface mapping from well logs
and commercial databases and petroleum geochemistry demonstrate
that the Barnett Shale is organic rich and thermally mature for hydrocarbon
generation over most of the Bend arch–FortWorth Basin
area. In the northeastern and structurally deepest part of the Fort
Worth Basin adjacent to the Muenster arch, the formation is more
than 1000 ft (305 m) thick and interbedded with thick limestone
units; westward, it thins rapidly over the Mississippian Chappel shelf
to only a few tens of feet.
The Barnett-Paleozoic TPS is identified where thermally mature
Barnett Shale has generated large volumes of hydrocarbons
and is (1) containedwithin the Barnett Shale unconventional continuous
accumulation and (2) expelled and distributed among numerous
conventional clastic- and carbonate-rock reservoirs of Paleozoic
age. Vitrinite reflectance (Ro)measurements show little correlation
with present-day burial depth.Contours of equal Ro values measured
from Barnett Shale and typing of produced hydrocarbons indicate

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非常感谢提供AAPG文章，写得很详细，透彻，这点上比SPE上的文章好