China Science » Earth and Space Science

Leaves in turbidite sands:The main source of oil and gas in the deep-water Kutei Basin,Indonesia:Reply

admin — Sat, 14 Jun 2008 15:03:35 +0000

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.

ur 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

Leaves in turbidite sands: The main source of oil and gas in the deep-water Kutei Basin,Indonesia:Discussion

admin — Sat, 14 Jun 2008 15:02:18 +0000

Sailer et al. (2006) have concluded that leaves in the upper Miocene turbidite sands were the main source of oil and gas in the deep-water Kutei Basin, East Kalimantan (Borneo), Indonesia. They have reported that oils from the Kutei Basin have high (4-7) pristane/phytane ratios, suggesting a coaly organic source. This is consistent with other observations made on oils from the Gippsland Basin in Australia, showing high pristane/ phytane ratios (5-6) that were attributed to coniferous rain forests and related land-plant organic matter (Shanmugam, 1985).

G. Shanmugam
Department of Earth and Environmental Sciences, University of Texas at Arlington, P.O. Box 19049, Arlington, Texas 76019-0049

Characterizing the shale gas resource potential of Devonian-Mississippian strata in the Western Canada sedimentary basin:Application of an integrated formation evaluation

admin — Sat, 14 Jun 2008 15:01:20 +0000

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

Coal reservoir saturation:Impact of temperature and pressure

admin — Sat, 14 Jun 2008 15:00:08 +0000

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 un-dersaturated coal. Our results argue against the generally accepted theory that undersaturation of coal reservoirs results from an 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.

Amanda M. M. Bustin　R. Marc Bustin
Department of Earth and Ocean Sciences, University of British Columbia, 6359 Stores Road Vancouver, British Columbia, Canada. V6T 1Z4

Petroleum generation and migration in the Ghadames Basin, north Africa:A two-dimensional basin-modeling study

admin — Sat, 14 Jun 2008 14:58:35 +0000

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

A new technology for the characterization of microfractured reservoirs

admin — Sat, 14 Jun 2008 14:57:10 +0000

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.in microfractured Unayzah-B/C have 4.5-14 times the productivity of wells as nonfractured sections of this reservoir. A maximum permeability trend of northeast-southwest permeability anisotropy is detected. The implementation of the EAMS technology in other fields with microfractured reservoirs will directly impact operational and simulation effort.

Mohammed S. Ameen　Ernest A. Hailwood
Geological Technical Senices Division. Saudi Aramco P.O. Box 2817. Dhahran 31311, Saudi Arabic; Core Magnetics, The Green, Sedbergh LAW 5JS, United Kingdom

Electronic Submission Guidelines For AAPG Bulletin

admin — Sat, 14 Jun 2008 14:55:23 +0000

Authors are asked to submit new manuscripts online through Rapid Review (www.rapidreview.com), where they can track their manuscripts from submission through acceptance. Preparing computer files in one of the preferred computer applications increases the likelihood that graphics will be rendered correctly. Success in translation depends upon the complexity of the document. If submitting by mail, please also provide high-quality laser prints for scanning in case translation problems occur. Do not provide graphics in word processing programs.

Impacts of volumetric strain on CO2 sequestration in coals and enhanced CH4 recovery

admin — Sat, 14 Jun 2008 14:53:41 +0000

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

Regional overview of deep sedimentary thermal gradients of the geopressured zone of the Texas-Louisiana continental shelf

admin — Sat, 14 Jun 2008 14:51:33 +0000

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