China Science

We are glad that Shanmugan has taken time to read and think about our recent article in the AAPG Bulletin. However, the discussion that he has written seems more oriented toward presenting his own sedimentologic ideas than debating whether leaves in deep-water sands can produce viable source rocks, which was the purpose of our article. Nevertheless, we will address some of his questions below.

Arthur Sailer?John Dunham?Rui Lin
Chevron ETC, 1500 Louisiana, Houston, Texas 77002; Chevron Thailand Exploration and Production, Tower III, SCB Park Plaza, 19 Ratchadapisek Road, Chatuchak, Bangkok 10900, Thailand

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 km (48,300 mi ) 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 122 degreeW and 123 degreeW and latitudes 59degreeN and 60 degreeN (National Topographic System [NTS] 94O08 to 94015). In this area, which covers an areal extent of 6250 km~2 (2404 mi~2 ), 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 cm~3/g (9.6-16 scf/t) at reservoir temperatures of 60-80degreeC (140-176 degree F), whereas Besa River mudrocks and shales have low adsorbed gas capacities of less than 0.01 cm13/g [0.32 scf/t; Liard Basin region) because reservoir temperatures exceed 130 degreeC (266degreeF). Potential free gas capacities range from 1.2 to 9.5 cm~3/g (38.4 to 304 scf/t) when total pore volumes (0.4-6.9%) are saturated with gas. The mineralogy has a major influence on total gas capacity. Carbonate-rich samples, indicative of adjacent carbonate platform and embayment successions, commonly have lower organic carbon content and porosity and corresponding lower gas capacity (< 1 % TOC and <1% porosity). Seaward of the carbonate Slave Point edge, Muskwa and lower Besa River mudrocks can be both silica and TOC rich (up to 92% quartz and 5 wt.% TOC) and most favorable for shale gas reservoir exploration because of possible fracture enhancement of the brittle organic- and siliceous-rich facies. However, an inverse relation between silica and porosity in some re- gions implies that zones with the best propensity for fracture completion may not provide optimal gas capacity, and a balance between favorable reservoir characteristics needs to be sought.

Daniel J. K. Ross?R. Marc Bustin
Department of Earth and Ocean Sciences, University of British Columbia, 6339 Stores Road. Vancouver. British Columbia. Canada V6T 1Z4; Department of Geological Sciences, University of British Columbia, 6339 Stores Road. Vancouver, British Columbia Canada. V6T 1Z4

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Sequestration of CO2 into deep, unminable coal seams is an attractive option to reduce atmospheric emissions. However, coal seams commonly have low initial permeability, and CO2 adsorption causes the coal matrix to swell, which further reduces the permeability and may result in inefficient injection. We investigate numerically the impacts of coal swelling on coal permeability and, thus, CO2 injection efficiency with constraints determined by experimental adsorption-associated volumetric strain measurements on three western Canadian coals. Our results show that injecting pure CO2 markedly reduces permeability through time to the extent that it is not a feasible sequestration technology for almost all coals. However, injection of a gas mixture of N2 and CO2 (flue gas) markedly improved CO2 injection efficiency while mildly reducing CO2 sequestration capacity. The study also suggests that different geological settings and mechanical properties of specific coal seams strongly control coal seam permeability during gas injection and, thus, viability of CO2 sequestration.

R. Marc Bustin?Xiaojun Cui?Laxmi Chikatamarla
Department of Earth and Ocean Sciences, University of British Columbia, 6339 Stores Road, Vancouver, British Columbia, Canada V6T 1Z4

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 0.016 degreeF/ft) off the Alabama-Mississippi shore to lower values of 0.015-0.025 K/m (0.008-0.014 degreeF/ft) off eastern Louisiana and to higher values of 0.03-0.06 K/m (0.016-0.033degreeF/ft) off western Louisiana through Texas. Second, thermal gradients tend to be lower toward the outer continental shelf (less than 0.02 K/m [0.0112 degree F/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 accumulated more 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 that the contrasting sedimentation history between the Texas and Alabama shelves has resulted in some difference in overall thermal conductivity of sediment, and that the geothermal gradients reflect such difference. However, it is more plausible if additional mechanisms enhance heat flow through sediment in the Texas shelf, such as (1) upward migration of pore fluid expelled from deep, overpressured sands and/or (2) a greater amount of heat released from the igneous basement. Deep sedimentary temperatures in the high-thermal-gradient areas suggest higher risks of hydrogen sulfide occurrence and reservoir quality degradation because of quartz cementation.

Seiichi Nagihara?Michael A. Smith
Department of Geosciences, Texas Tech University, Lubbock, Texas 79409; Minerals Management Service, New Orleans, Louisiana 70123

In the Tremp Basin area(south Pyrenean foreland,Spain),the Campanian-Maastrichtian Orcau-Vell and Santa Engracia deposi-tional sequences onlap the western termination of the Sant Corneli anticline.The precise mapping of the different systems tracts belonging to these depositional sequences,their spatial arrangement,and the structural control of the anticline on the sedimentation still remained unclear.To accurately interpret the geometry of the depositional sequences and to determine the factors influencing the sedimentation,we have developed a method that aims to build a three-dimensional[3-D]geological picture of this area.The originality of our approach is that the 3-D map,which consists of the volume and shape of all the systems tracts,has been produced mainly from the interpretation and combination of surface data,including a mosaic of aerial photographs at 50-cm(20-in.)pixel size and a digital elevation model at 10-m(33-ft)resolution.We have additionally constrained the model by integrating bedding dip and strike data and balanced cross sections.The three-dimensional visualization and field observations reveal the structural control at different scales of the lateral propagation of a fault-propagation fold(Sant Corneli anticline)on the stratigraphic architecture.The Orcau-Vell depositional sequence was controlled by the rise of the base level and was characterized by differences in the sedimentation rates.The emplacement of a north-south-trending gravitational normal fault,located at the western tip of the Sant Corneli anticline,was coeval with the emplacement of the Santa Engracia depositional sequence.This fault resulted from the westward propagation of the Sant Corneli anticline,generating a local slope and a depression that channeled the turbidites and the Gilbert-type delta deposits of the Santa Engracia depositional sequence.Uplift of the Sant Corneli anticline may have subsequently stopped,and the area subsided,inducing a rapid rise of the base level.

Benjamin Cuillaume?Damien Dhont?Stephane Brusset

Previous pressure-volume calculations during oil cracking to gas,based on the conventional model that presupposes oil cracking to be completed by approximately 150°C,underestimate the potential for gas accumulation in petroleum reservoirs.In this article,a compositional kinetic model of gas generation from oil cracking is suggested based on pyrolysis data using sealed gold tubes,and the pressure-volume changes are recalculated based on the new kinetic model under various geological conditions.The kinetic modeling of oil cracking confirms that crude oil begins cracking at about 160°C for a heating rate of 2°C/m.y.,and that the oil-cracking process has two distinct stages with significant differences in gas composition.The first stage is characterized by dominant C_(2-5)wet gases,whereas the second is characterized by the recracking of C_(2-5)wet gases to methane and pyrobitumen,leading to a progressive increasing dryness of the gas.The pressure-volume-temperature simulations of oil cracking to gas show that initial oil saturation,temperature-pressure gradients,and openness of reservoirs are important geological factors that control gas accumulation in original petroleum reservoirs.For a reservoir that is geologically open and saturated with 100% oil,gas spills out of the trap at 196°C.The gas loss at 240°C is almost 50% of the total gas,far lower than the 75% based on the conventional model of oil destruction.With lower oil saturation,the gas loss decreases because the gas-water contact can shift downward,and the gas loss occurs mainly by solution.For effectively isolated reservoirs,oil cracking readily exceeds lithostatic pressure,leading to reservoir fracturing,which becomes more obvious when oil saturation-decreases.The calculated fracturing temperatures for 100 and 50 vol.% oil saturations correspond to oil destructions of 95% and 86.4%,greatly exceeding the value of 1% as suggested by previous studies.A conceptual model of gas accumulation and loss in isolated and open geological conditions for a reservoir with 50% oil saturation is suggested.On the basis of this model,the Triassic carbonate gas pool in northeastern Sichuan Basin was discussed as a typical example for in-situ accumulation of gas cracked from reservoired oils.The present model infers that the reservoired oils were completely cracked into gas at 87.6 Ma,and that 75-85% of the gas has been preserved in the original reservoir rocks to form the in-situ gas pools with a huge amount of gas resources.We believe that gas accumulation from oil cracking in original petroleum reservoirs is much more prospective than previously thought,and that gas cracked from oil has great potential in other areas of the Sichuan Basin and the eastern Tarim Basin.

Hui Tian?Xianming Xiao?Ronald W.T.Wilkins

The Ghadames Basin contains important oil- and gas-producing reservoirs distributed across Algeria, Tunisia, and Libya. Regional two-dimensional (2-D) modeling, using data from more than 30 wells, has been undertaken to assess the timing and distribution of hydrocarbon generation in the basin. Four potential petroleum systems have been identified: (1) a Middle-Upper Devonian (Frasnian) and Triassic (Triassic Argilo Greseux Inferieur [TAG-I]) system in the central-western basin; (2) a Lower Silurian (Tannezuft) and Triassic (TAG-I) system to the far west; (3) a Lower Silurian (Tannezuft) and Upper Silurian (Acacus) system in the eastern and northeastern margins; and (4) a Lower Silurian (Tanezzuft) and Middle-Upper Devonian (Frasnian) system to the east-southeast. The Lower Silurian Tanezzuft source rock underwent two main phases of hydrocarbon generation. The first phase occurred during the Carboniferous, and the second started during the Cretaceous, generating most hydrocarbons in the eastern (Libyan) basin. The Frasnian shales underwent an initial, minor generative phase in the central depression during the Carboniferous. However, the main generation occurred during the Late Jurassic-Cenozoic in the western and central depression. The Frasnian shales are currently only marginally mature in the eastern part of the basin. Modeling indicates that the Alpine (Eocene) exhumation of the eastern (Libyan) basin margin had a significant control on the timing of hydrocarbon generation from the Lower Silurian source rock. The preferred burial-history model calibrates source rock maturity data by incorporating late exhumation and reduced subsidence prior to the Hercynian (Carboniferous) orogeny. As a result, the Tannezuft shales preserve their generative potential into the Mesozoic-Cenozoic, with renewed hydrocarbon generation during subsequent reburial, which can migrate to post-Hercynian (Carboniferous] traps, hence favoring the preservation of hydrocarbon accumulations.

Ruth Underdown?Jonathan Redfern
North Africa Research Group, School of Earth, Atmospheric and environmentalSciences, University of Manchester, Oxford Road, Manchester M13 9PL, United kingdom