GEOGRAPHICAL REVIEW, Issue 4 2007
Daanish Mustafa
ABSTRACT. The article identifies important themes and future research directions for analyzing water and conflict dynamics at the subnational scale in the Indus Basin. A historical overview of water development in the Indus Basin suggests that the water-security nexus was always a salient theme in the minds of water developers, even in the nineteenth century. Conflicts over contemporary large-scale water-development projects in the Indian and Pakistani parts of the Indus Basin are reviewed. Engineers' single-minded focus on megaprojects, to the neglect of the wider set of values that societies attach to water resources in the eastern and western Indus Basin are largely to blame for continuing low-grade conflict in the basin. A review of local-level conflicts over water supply and sanitation in Karachi and the distribution of irrigation water in Pakistani Punjab illustrates the critical role of governance and differential social power relations in accentuating conflict. The article argues against neo-Malthusian assumptions about the inevitability of conflict over water because of its future absolute scarcity. Instead, the article seeks to demonstrate that, despite evidence suggesting that international armed conflict over water does not exist, the potential for political instability over domestic water distribution and development issues is real. The question of whether conflict at the subnational scale will culminate in violence will depend on how water-resources institutions in the basin behave. [source]

THE A.D. 1300 EVENT IN THE PACIFIC BASIN,

GEOGRAPHICAL REVIEW, Issue 1 2007
Patrick D. Nunn
ABSTRACT. Around a.d. 1300 the entire Pacific Basin (continental Pacific Rim and oceanic Pacific Islands) was affected by comparatively rapid cooling and sea-level fall, and possibly increased storminess, that caused massive and enduring changes to Pacific environments and societies. For most Pacific societies, adapted to the warmer, drier, and more stable climates of the preceding Medieval Climate Anomaly (a.d. 750,1250), the effects of this A.D. 1300 Event were profoundly disruptive, largely because of the reduction in food resources available in coastal zones attributable to the 70,80-centimeter sea-level fall. This disruption was manifested by the outbreak of persistent conflict, shifts in settlements from coasts to refugia inland or on unoccupied offshore islands, changes in subsistence strategies, and an abrupt end to long-distance cross-ocean interaction during the ensuing Little Ice Age (a.d. 1350,1800). The A.D. 1300 Event provides a good example of the disruptive potential for human societies of abrupt, short-lived climate changes. [source]

NILE BASIN: States Sign Agreement

AFRICA RESEARCH BULLETIN: ECONOMIC, FINANCIAL AND TECHNICAL SERIES, Issue 4 2010
Article first published online: 4 JUN 2010
No abstract is available for this article. [source]

NILE BASIN: Traditional Quotas Retained

AFRICA RESEARCH BULLETIN: ECONOMIC, FINANCIAL AND TECHNICAL SERIES, Issue 7 2009
Article first published online: 27 AUG 200
No abstract is available for this article. [source]

HYDROCARBON POTENTIAL OF THE LATE CRETACEOUS GONGILA AND FIKA FORMATIONS, BORNU (CHAD) BASIN, NE NIGERIA

JOURNAL OF PETROLEUM GEOLOGY, Issue 4 2010
B. Alalade
The hydrocarbon potential of possible shale source rocks from the Late Cretaceous Gongila and Fika Formations of the Chad Basin of NE Nigeria is evaluated using an integration of organic geochemistry and palynofacies observations. Total organic carbon (TOC) values for about 170 cutting samples range between 0.5% and 1.5% and Rock-Eval hydrogen indices (HI) are below 100 mgHC/gTOC, suggesting that the shales are organically lean and contain Type III/IV kerogen. Amorphous organic matter (AOM) dominates the kerogen assemblage (typically >80%) although its fluorescence does not show a significant correlation with measured HI. Atomic H/C ratios of a subset of the samples indicate higher quality oil- to gas-prone organic matter (Type II-III kerogens) and exhibit a significant correlation with the fluorescence of AOM (r2= 0.86). Rock-Eval Tmax calibrated against AOM fluorescence, biomarker and aromatic hydrocarbon maturity data suggests a transition from immature (<435°C) to mature (>435°C) in the Fika Formation and mature to post-mature (>470°C) in the Gongila Formation. The low TOC values in most of the shales samples limit their overall source rock potential. The immature to early mature upper part of the Fika Formation, in which about 10% of the samples have TOC values greater than 2.0%, has the best oil generating potential. Oil would have been generated if such intervals had become thermally mature. On the basis of the samples studied here, the basin has potential for mostly gaseous rather than liquid hydrocarbons. [source]

PETROPHYSICAL CHARACTERISTICS OF SOURCE AND RESERVOIR ROCKS IN THE HISTRIA BASIN, WESTERN BLACK SEA

JOURNAL OF PETROLEUM GEOLOGY, Issue 4 2009
C. Cranganu
The petroleum system in the Histria Basin, Western Black Sea, includes Oligocene source rocks and Upper Cretaceous , Eocene reservoir rocks. Here we report on the petrophysical characteristics of these source and reservoir rocks using mercury intrusion porosimetry data from 14 core samples collected from five wells drilled on the East Lebada, West Lebada and Pescarus structures. Samples were in general dominated by carbonate lithologies with minor shales. Petrophysical parameters analyzed were: median pore-throat radius, average pore-throat radius, apparent porosity, pore-throat size distribution, pore-throat type, pore-throat sorting, maximum threshold entry radius, pore-throat radius at 35% mercury saturation (R35), and air permeability. Reservoir rock quality was estimated using a permeability / porosity / pore-throat type plot. The Oligocene samples showed little petrophysical variation. Samples were relatively homogenous and had the same pore-throat type (nano), were well sorted, had unimodal pore-throat distribution (suggesting the existence of a single fluid phase), had similar values for median and average pore-throat radius, and similar values for R35 and maximum threshold entry radius. Upper Cretaceous , Eocene samples were more heterogeneous in terms of petrophysical properties, and reservoir quality was in general higher than in the Oligocene interval. Average porosity and calculated air-permeability values were 18.4% and 0.37 mD, respectively for Upper Cretaceous samples; and 11.8% and 27.11 mD, respectively for Eocene samples. A case study of Oligocene and Cretaceous , Eocene samples from well West Lebada 817 is presented. This paper represents the first petrophysical study of source and reservoir rocks in the Histria Basin, Western Black Sea. The results will help to establish the links between petrophysical characteristics, age and depositional environment for source and reservoir rocks in other basins bordering the Black Sea. [source]

AN INTEGRATED STUDY OF DIAGENESIS AND DEPOSITIONAL FACIES IN TIDAL SANDSTONES: HAWAZ FORMATION (MIDDLE ORDOVICIAN), MURZUQ BASIN, LIBYA

JOURNAL OF PETROLEUM GEOLOGY, Issue 1 2009
A. Abouessa
Studies of the impact of diagenesis on reservoir quality in tidal sandstones can be of great importance in successful hydrocarbon exploration. The study reported here shows that diagenetic alterations and bioturbation have induced considerable deterioration and heterogeneity in the reservoir quality of the sand-dominated tidal deposits of the Middle Ordovician Hawaz Formation in the Muruq Basin, Libya. Comparison is made between the diagenetic evolution of samples from the subsurface (present-day depth 1500 m) and from surface outcrops in order to study the impact of burial and uplift on the spatial and temporal distribution of reservoir quality in the Hawaz Formation sandstones. Eogenetic alterations, which were mediated by meteoric water circulation, included kaolinitization and dissolution of framework silicates and mechanical compaction. Mesogenetic alterations (T > 70°C; depth > 2 km) included pressure dissolution of quartz grains and concomitant quartz cementation, conversion of kaolinite into dickite, illitization of kaolinite and of grain-coating clays, and the precipitation of Mg-rich siderite cement. Reduction of intergranular porosity was due more to compaction than to cementation, yet quartz overgrowths are up to 16% in some of the sandstones. Bioturbation has resulted in a greater reduction in sandstone permeability in the lower part of the formation than the upper part. A higher ratio of dickite to kaolinite in subsurface samples than in outcrop samples is attributed to the longer residence time of the former sandstones under mesogenetic conditions. Telodiagenesis has not resulted in enhancement of reservoir quality of the Hawaz Formation Sandstones but in pseudomorphic calcitization of siderite and oxidation of pyrite to goethite. This study shows that the reservoir-quality evolution of tidal sandstones can best be elucidated when linked to depositional facies and distribution of diagenetic alterations. [source]

PETROLEUM PROSPECTIVITY OF CRETACEOUS FORMATIONS IN THE GONGOLA BASIN, UPPER BENUE TROUGH, NIGERIA: AN ORGANIC GEOCHEMICAL PERSPECTIVE ON A MIGRATED OIL CONTROVERSY

JOURNAL OF PETROLEUM GEOLOGY, Issue 4 2008
M. B. Abubakar
Organic geochemical studies of Cretaceous formations in the Gongola Basin, northern Nigeria, show TOC values that are generally higher than the minimum (0.5 wt %) required for hydrocarbon generation. Data from Rock-Eval pyrolysis and biomarker studies indicate the presence of both terrestrial and marine derived Types II and III organic matter, which is immature in the Gombe Formation and of marginal maturity in the Yolde Formation. Immature Type III to IV OM is present in the Pindiga Formation; and Type III OM, with a maturity that corresponds to the conventional onset (or perhaps peak) of oil generation occurs in the Bima Formation. However, Bima Formation samples from the 4710 , 4770 ft (1435.6 , 1453.9 m) depth interval within well Nasara-1 indicate Type I OM of perhaps lacustrine origin (H31R/H30 ratio generally ,0.25). Although the Nasara-1 well was reported to be dry, geochemical parameters (high TOCs, S1, S2 and Hls, low Tmax compared to adjacent samples, a bimodal S2 peak on the Rock-Eval pyrogram, a dominance of fluorinite macerals), together with generally low H3IR/H30 biomarker ratios within the 4710,4770 ft (1435.6,1453.9 m) interval, suggest the presence of migrated oil, perhaps sourced by lacustrine shales in the Albian Bima Formation located at as-yet unpenetrated depths. The presence of the migrated oil in the Bima Formation and its possible lacustrine origin suggest that the petroleum system in the Gongola Basin is similar to that of the Termit, Doba and Doseo Basins of the Chad Republic, where economic oil reserves have been encountered. [source]

KINETICS OF HYDROCARBON GAS GENERATION FROM MARINE KEROGEN AND OIL: IMPLICATIONS FOR THE ORIGIN OF NATURAL GASES IN THE HETIANHE GASFIELD, TARIM BASIN, NW CHINA

JOURNAL OF PETROLEUM GEOLOGY, Issue 4 2007
Yunpeng Wang
In this paper we derive kinetic parameters for the generation of gaseous hydrocarbons (C1-5) and methane (C1) from closed-system laboratory pyrolysis of selected samples of marine kerogen and oil from the SW Tarim Basin. The activation energy distributions for the generation of both C1-5 (Ea = 59-72kcal, A = 1.0×1014 s,1) and C1 (Ea = 61-78kcal, A = 6.06×1014 s,1) hydrocarbons from the marine oil are narrower than those for the generation of these hydrocarbons from marine kerogen (Ea = 50-74kcal, A = 1.0×1014 s,1 for C1-5; and Ea = 48-72kcal, A=3.9×1013 s,1 for C1, respectively). Using these kinetic parameters, both the yields and timings of C1-5 and C1 hydrocarbons generated from Cambrian source rocks and from in-reservoir cracking of oil in Ordovician strata were predicted for selected wells along a north-south profile in the SW of the basin. Thermodynamic conditions for the cracking of oil and kerogen were modelled within the context of the geological framework. It is suggested that marine kerogen began to crack at temperatures of around 120°C (or 0.8 %Ro) and entered the gas window at 138°C (or 1.05 %Ro); whereas the marine oil began to crack at about 140 °C (or 1.1 %Ro) and entered the gas window at 158 °C (or 1.6%Ro). The main geological controls identified for gas accumulations in the Bachu Arch (Southwest Depression, SW Tarim Basin) include the remaining gas potential following Caledonian uplift; oil trapping and preservation in basal Ordovician strata; the extent of breaching of Ordovician reservoirs; and whether reservoir burial depths are sufficiently deep for oil cracking to have occurred. In the Maigaiti Slope and Southwest Depression, the timing of gas generation was later than that in the Bachu Arch, with much higher yields and generation rates, and hence better prospects for gas exploration. It appears from the gas generation kinetics that the primary source for the gases in the Hetianhe gasfield was the Southwest Depression. [source]

IMPACT OF MAGMATISM ON PETROLEUM SYSTEMS IN THE SVERDRUP BASIN, CANADIAN ARCTIC ISLANDS, NUNAVUT: A NUMERICAL MODELLING STUDY

JOURNAL OF PETROLEUM GEOLOGY, Issue 3 2007
S.F. Jones
Numerical modelling is used to investigate for the first time the interactions between a petroleum system and sill intrusion in the NE Sverdrup Basin, Canadian Arctic Archipelago. Although hydrocarbonexploration has been successful in the western Sverdrup Basin, the results in the NE part of thebasin have been disappointing, despite the presence of suitable Mesozoic source rocks, migrationpaths and structural/stratigraphic traps, many involving evaporites. This was explained by (i) theformation of structural traps during basin inversion in the Eocene, after the main phase ofhydrocarbon generation, and/or (ii) the presence of evaporite diapirs locally modifying the geothermalgradient, leading to thermal overmaturity of hydrocarbons. This study is the first attempt at modellingthe intrusion of Cretaceous sills in the east-central Sverdrup Basin, and to investigate how theymay have affected the petroleum system. A one-dimensional numerical model, constructed using PetroMod9.0®, investigates the effectsof rifting and magmatic events on the thermal history and on petroleum generation at the DepotPoint L-24 well, eastern Axel Heiberg Island (79°23,40,N, 85°44,22,W). The thermal history isconstrained by vitrinite reflectance and fission-track data, and by the tectonic history. The simulationidentifies the time intervals during which hydrocarbons were generated, and illustrates the interplaybetween hydrocarbon production and igneous activity at the time of sill intrusion during the EarlyCretaceous. The comparison of the petroleum and magmatic systems in the context of previouslyproposed models of basin evolution and renewed tectonism was an essential step in the interpretationof the results from the Depot Point L-24 well. The model results show that an episode of minor renewed rifting and widespread sill intrusionin the Early Cretaceous occurred after hydrocarbon generation ceased at about 220 Ma in theHare Fiord and Van Hauen Formations. We conclude that the generation potential of these deeperformations in the eastern Sverdrup Basin was not likely to have been affected by the intrusion ofmafic sills during the Early Cretaceous. However, the model suggests that in shallower sourcerocks such as the Blaa Mountain Formation, rapid generation of natural gas occurred at 125 Ma, contemporaneous with tectonic rejuvenation and sill intrusion in the east-central Sverdrup Basin. A sensitivity study shows that the emplacement of sills increased the hydrocarbon generation ratesin the Blaa Mountain Formation, and facilitated the production of gas rather than oil. [source]

HYDROTHERMALLY FLUORITIZED ORDOVICIAN CARBONATES AS RESERVOIR ROCKS IN THE TAZHONG AREA, CENTRALTARIM BASIN, NW CHINA

JOURNAL OF PETROLEUM GEOLOGY, Issue 1 2006
Zhijun Jin
Reservoir rocks at the Tazhong 45 oil pool, central Tarim Basin, consist of fluoritized carbonate strata of Middle - Late Ordovician age. Petrological observations indicate that the fluorite replaces calcite. Several other hydrothermal minerals including pyrite, quartz, sphalerite and chlorite accompany the fluorite. Two generations of fluid inclusions are present in the fluorite. Homogenization temperatures (Th) for primary inclusions are mostly between 260°C and 310°C and represent the temperature of the hydrothermal fluid responsible for fluorite precipitation. Th for secondary inclusions range from 100°C to 130°C, and represent the hydrocarbon charging temperature as shown by the presence of hydrocarbons trapped in some secondary inclusions. The mineral assemblage and the homogenization temperatures of the primary fluid inclusions indicate that the precipitation of fluorite is related to hydrothermal activity in the Tazhong area. Strontium isotope analyses imply that the hydrothermal fluids responsible for fluorite precipitation are related to late-stage magmatic activity, and felsic magmas were generated by mixing of mafic magma and crustal materials during the Permian. Theoretical calculations show that the molecular volume of a carbonate rock decreases by 33.5% when calcite is replaced by fluorite, and the volume shrinkage can greatly enhance reservoir porosity by the formation of abundant intercrystalline pores. Fluoritization has thus greatly enhanced the reservoir quality of Ordovician carbonates in the Tazhong 45 area, so that the fluorite and limestone host rocks have become an efficient hydrocarbon reservoir. According to the modelled burial and thermal history of the Tazhong 45 well, and the homogenization temperatures of secondary fluid inclusions in the fluorite, hydrocarbon charging at the Tazhong 45 reservoir took place in the Tertiary. [source]

THE LACUSTRINE LIANGJIALOU FAN IN THE DONGYING DEPRESSION, EASTERN CHINA: DEEP-WATER RESERVOIR SANDSTONES IN A NON-MARINE RIFT BASIN

JOURNAL OF PETROLEUM GEOLOGY, Issue 4 2005
Jin Qiang
A lacustrine fan covering an area of about 175sq. km has been identified in the Liangjialou area in the SW of the Dongying Depression, a Tertiary non-marine rift basin in eastern China. Fluvial and deltaic sandstones are established reservoir rocks in the basin, and the deep-water sandstones of the fan succession, which are assigned to Member 3 of the lower Tertiary Shahejie Formation, are also thought to have important reservoir potential. Available data for this study included some 800m of core from 16 wells, well-log data from 426 wells, and 220 sq.km of 3D surveys together with well-test and other production data. From geomorphological reconstructions of the fan, we distinguish first-order (major) fan channels from second-order branched and more distal tip channels. Crevasse splays and overbank shales occur between channels, and sandstone lobes were deposited at channel mouths. Conglomeratic sandstones deposited in major channels are probably the most promising reservoir facies (average porosity c. 20%; average permeability > 1D). Fan construction took place during a single complete cycle of lake level variation which was composed of several sub-cycles. During initial highstand conditions, the fan was dominated by small-scale branched and tip channels and intervening sandy lobes. Fan size increased rapidly during the following lowstand, and then decreased during the ensuing highstand. [source]

HYDROCARBON SEEPAGE AND CARBONATE MOUND FORMATION: A BASIN MODELLING STUDY FROM THE PORCUPINE BASIN (OFFSHORE IRELAND)

JOURNAL OF PETROLEUM GEOLOGY, Issue 2 2005
J. Naeth
This study assesses whether the growth of deep water carbonate mounds on the continental slope of the north Atlantic may be associated with active hydrocarbon leakage. The carbonate mounds studied occur in two distinct areas of the Porcupine Basin, 200 km offshore Ireland, known as the Hovland-Magellan and the Belgica areas. To evaluate the possible link between hydrocarbon leakage and mound growth, we used two dimensional cross-section and map-based basin modelling. Geological information was derived from interpretation of five seismic lines across the province as well as the Connemara oilfield. Calibration data was available from the northern part of the study area and included vitrinite reflectance, temperature and apatite fission track data. Modelling results indicate that the main Jurassic source rocks are mature to overmature for hydrocarbon generation throughout the basin. Hydrocarbon generation and migration started in the Late Cretaceous. Based on our stratigraphic and lithologic model definitions, hydrocarbon migration is modelled to be mainly vertical, with only Aptian and Tertiary deltaic strata directing hydrocarbon flow laterally out of the basin. Gas chimneys observed in the Connemara field were reproduced using flow modelling and are related to leakage at the apices of rotated Jurassic fault blocks. The model predicts significant focussing of gas migration towards the Belgica mounds, where Cretaceous and Tertiary carrier layers pinch out. In the Hovland-Magellan area, no obvious focus of hydrocarbon flow was modelled from the 2D section, but drainage area analysis of Tertiary maps indicates a link between mound position and shallow Tertiary closures which may focus hydrocarbon flow towards the mounds. [source]

DISTRIBUTION OF SOURCE ROCKS AND MATURITY MODELLING IN THE NORTHERN CENOZOIC SONG HONG BASIN (GULF OF TONKIN), VIETNAM

JOURNAL OF PETROLEUM GEOLOGY, Issue 2 2005
C. Andersen
The northern offshore part of the Cenozoic Song Hong Basin in the Gulf of Tonkin (East Vietnam Sea) is at an early stage of exploration with only a few wells drilled. Oil to source rock correlation indicates that coals are responsible for the sub-commercial oil and gas accumulations in sandstones in two of the four wells which have been drilled on faulted anticlines and flower structures. The wells are located in a narrow, structurally inverted zone with a thick predominantly deltaic Miocene succession between the Song Chay and Vinh Ninh/Song Lo fault zones. These faults are splays belonging to the offshore extension of the Red River Fault Zone. Access to a database of 3,500 km of 2D seismic data has allowed a detailed and consistent break-down of the geological record of the northern part of the basin into chronostratigraphic events which were used as inputs to model the hydrocarbon generation history. In addition, seismic facies mapping, using the internal reflection characteristics of selected seismic sequences, has been applied to predict the lateral distribution of source rock intervals. The results based on Yükler ID basin modelling are presented as profiles and maturity maps. The robustness of the results are analysed by testing different heat flow scenarios and by transfer of the model concept to IES Petromod software to obtain a more acceptable temperature history reconstruction using the Easy%R0 algorithm. Miocene coals in the wells located in the inverted zone between the fault splays are present in separate intervals. Seismic facies analysis suggests that the upper interval is of limited areal extent. The lower interval, of more widespread occurrence, is presently in the oil and condensate generating zones in deep synclines between inversion ridges. The Yükler modelling indicates, however, that the coaly source rock interval entered the main window prior to formation of traps as a result of Late Miocene inversion. Lacustrine mudstones, similar to the highly oil-prone Oligocene mudstones and coals which are exposed in the Dong Ho area at the northern margin of the Song Hong Basin and on Bach Long Vi Island in Gulf of Tonkin, are interpreted to be preserved in a system of undrilled NW,SE Paleogene half-grabens NE of the Song Lo Fault Zone. This is based on the presence of intervals with distinct, continuous, high reflection seismic amplitudes. Considerable overlap exists between the shale-prone seismic facies and the modelled extent of the present-day oil and condensate generating zones, suggesting that active source kitchens also exist in this part of the basin. Recently reported oil in a well located onshore (BIO-STB-IX) at the margin of the basin, which is sourced mainly from "Dong Ho type" lacustrine mudstones supports the presence of an additional Paleogene sourced petroleum system. [source]

SOURCE ROCK PROPERTIES OF LACUSTRINE MUDSTONES AND COALS (OLIGOCENE DONG HO FORMATION), ONSHORE SONG HONG BASIN, NORTHERN VIETNAM

JOURNAL OF PETROLEUM GEOLOGY, Issue 1 2005
H. I. Petersen
Oligocene lacustrine mudstones and coals of the Dong Ho Formation outcropping around Dong Ho, at the northern margin of the mainly offshore Cenozoic Song Hong Basin (northern Vietnam), include highly oil-prone potential source rocks. Mudstone and coal samples were collected and analysed for their content of total organic carbon and total sulphur, and source rock screening data were obtained by Rock-Eval pyrolysis. The organic matter composition in a number of samples was analysed by reflected light microscopy. In addition, two coal samples were subjected to progressive hydrous pyrolysis in order to study their oil generation characteristics, including the compositional evolution in the extracts from the pyrolysed samples. The organic material in the mudstones is mainly composed of fluorescing amorphous organic matter, liptodetrinite and alginite with Botryococcus-morphology (corresponding to Type I kerogen). The mudstones contain up to 19.6 wt.% TOC and Hydrogen Index values range from 436,572 mg HC/g TOC. From a pyrolysis S2 versus TOC plot it is estimated that about 55% of the mudstones'TOC can be pyrolised into hydrocarbons; the plot also suggests that a minimum content of only 0.5 wt.% TOC is required to saturate the source rock to the expulsion threshold. Humic coals and coaly mudstones have Hydrogen Index values of 318,409 mg HC/g TOC. They are dominated by huminite (Type III kerogen) and generally contain a significant proportion of terrestrial-derived liptodetrinite. Upon artificial maturation by hydrous pyrolysis, the coals generate significant quantities of saturated hydrocarbons, which are probably expelled at or before a maturity corresponding to a vitrinite reflectance of 0.97%R0. This is earlier than previously indicated from Dong Ho Formation coals with a lower source potential. The composition of a newly discovered oil (well B10-STB-1x) at the NE margin of the Song Hong Basin is consistent with contributions from both source rocks, and is encouraging for the prospectivity of offshore half-grabens in the Song Hong Basin. [source]

TURBIDITE, SLUMP AND DEBRIS FLOW DEPOSITS AT THE KALCHINSKOE AND ZIMNEE OILFIELDS, WEST SIBERIAN BASIN

JOURNAL OF PETROLEUM GEOLOGY, Issue 1 2005
S. F. Khafizov
This paper discusses specific facies associated with Cretaceous deep-water slumps and sandstone intrusions in the West Siberian Basin. The slumps were formed during sea-level falls when storms caused sediment masses to be discharged into deep-water areas where they imposed a significant load on the underlying semi-consolidated black shales, deforming and partially destroying them. Multiple slump / avalanche events are observed at the boundary between the Lower Cretaceous (Neocomian) and Upper Jurassic (Tithonian) sequences and form potential targets for oil exploration. High-resolution sequence stratigraphic analyses show that both slump and distal fans are genetically related to lower slope/basin floor sediments and were deposited during regressions and subsequent lowstands. Two key depositional environments are recognized: the proximal parts of fans, where the most prospective potential reservoirs are found; and the more distal parts of slumps, which are principally composed of deformed shale clasts in a silt-mudstone matrix. A third facies ("slump head") is only observed on seismic profiles and is probably related to horizontally displaced "shingled" semi-consolidated black shales. [source]

TEMPESTITE DEPOSITS ON A STORM-INFLUENCED CARBONATE RAMP: AN EXAMPLE FROM THE PABDEH FORMATION (PALEOGENE), ZAGROS BASIN, SW IRAN

JOURNAL OF PETROLEUM GEOLOGY, Issue 2 2004
H. Mohseni
The Pabdeh Formation is part of a thick carbonate-siliciclastic succession in the Zagros Basin of SW Iran which includes carbonate reservoirs of Cretaceous and Cenozoic ages. From field observations and petrographic and facies analysis of exposures in the type section of the Pabdeh Formation, four lithofacies were recognized. These are from oldest to youngest: (i) a mottled, bioturbated bioclastic wackestone/mudstone facies; (ii) a wackestone/packstone facies with horizontal burrows on bedding planes; (iii) a thin-bedded bioclastic wackestone/mudstone facies alternating with thin bioclastic-oolitic-intraclastic intervals; and (iv) a bioclastic foraminiferal / algal / peloidal packstone facies. These observations indicate that facies evolved upwards from deep outer-ramp deposits to inner-ramp deposits within a shoal complex, suggesting progradation of the ramp depositional system. Storm events significantly influenced the ramp system. Storm-generated surges transported sediments from nearshore to the deeper outer-ramp environment where they were deposited as shell-lags, composed mostly of bioclastic packstones, rich in pelagic microfauna with sharp, undulatory erosional basal contacts. The packstones rest on outer ramp mudstones deposited below storm base level. Sedimentary structures in the Pabdeh Formation are those typical of storm deposits, such as hummocky cross-stratification, ripple cross-lamination, ripple marks, escape burrows on the tops of the beds, couplets of fine- and coarse-grained laminae and mixed fauna, as well as intraclasts derived from underlying facies. These distinctive sequences are interpreted to have been generated by waning storm-generated currents. The dominance of fine-grained sediments (medium to fine sand); the lack of large- scale hummocky cross-stratification; the minor amounts of intraclasts derived from underlying facies; the paucity of amalgamated tempestite beds; and the finely-laminated (mm to cm scale) couplets of coarse and fine lamina all suggest a distal tempestite facies. Palaeogeographic reconstruction of the Zagros Basin during the Eocene indicates that the study area was situated in tropical, storm-dominated palaeolatitudes. [source]

POTENTIAL STRUCTURAL TRAPS ASSOCIATED WITH LOWER CARBONIFEROUS SALT IN THE NORTHERN TARIM BASIN, NW CHINA

JOURNAL OF PETROLEUM GEOLOGY, Issue 1 2004
Jiangyu Zhou
In the Aixieke-Santamu area of the northern Tarim Basin (NW China), 45 relatively low amplitude structures related to the plastic flow of Lower Carboniferous salt have been discovered in the Lower Carboniferous Kalashayi Formation and the Middle-Upper Triassic Akekule and Halahatan Formations. Three small hydrocarbon accumulations have so far been located at the margins of a Lower Carboniferous salt body (measuring about 55km x 75km and 115,225m thick, controlled by wells and 2D and 3D seismic sections). In this paper, we consider the development of this salt body and discuss possible reasons why vertical diapirs are absent from the study area. We attempt to develop a model of salt flow and we investigate the relationship between salt flow and the occurrence of oil and gas traps. Using recently-acquired high-resolution 2D and 3D seismic profiles, we show that the Lower Carboniferous salt has undergone three separate phases of plastic flow. At the end of the Early Permian, the salt flowed southwards by 2.0,2.8 km; then, during the Late Triassic,Early Jurassic, it flowed in the same direction by 1.0,1.8 km; and finally at the end of the Tertiary, it flowed northwards by 0.6,1.5 km. These movements resulted in the formation of various types of structural trap in the Kalashayi, Akekule and Halahatan Formations including salt ridge anticlines, domes and marginal troughs. Salt ridge and salt edge low-amplitude anticlines are probably the most important targets for future hydrocarbon exploration. [source]

UPPER TRIASSIC-MIDDLE JURASSIC STRATIGRAPHY AND SEDIMENTOLOGY IN THE NE QAIDAM BASIN, NW CHINA: PETROLEUM GEOLOGICAL SIGNIFICANCE OF NEW OUTCROP AND SUBSURFACE DATA

JOURNAL OF PETROLEUM GEOLOGY, Issue 4 2003
Yang Yongtai
Although Mesozoic source and reservoir rocks are known to occur at oilfields in the northern Qaidam Basin (NW China), the precise identification and distribution of Mesozoic rocks in the subsurface are outstanding problems. The Dameigou locality has in the past been considered as the type section for Lower-Middle Jurassic strata in northern Qaidam. Previous studies have concluded that the onset of non-marine sedimentation here took place in the Early Jurassic; and that Mesozoic strata penetrated by wells in the Lenghu structural zone are Middle Jurassic. In this paper, we present new data from the Lengke-1 well, drilled in the Lenghu structural zone in 1997. This data indicates the existence of a more extensive pre-Middle Jurassic stratigraphy than has previously been recognized. Biostratigraphic data together with regional seismic mapping suggest that the pre-Middle Jurassic succession at Lengke-1 includes both Late Triassic and Early Jurassic deposits. The Late Triassic sedimentary rocks appear to have been deposited in local half graben, some of which were later inverted during Jurassic, Cretaceous and Cenozoic tectonism. Lower and Middle Jurassic strata (lacustrine and fluvial deposits) are present in the SW and NE parts of the Lenghu structural zone, respectively. Extensive organic-rich intervals are present in both successions. Lower Jurassic lacustrine mudstones may represent a previously under-appreciated, and potentially large, source rock sequence. [source]

HYDROCARBON POTENTIAL OF JURASSIC SOURCE ROCKS IN THE JUNGGAR BASIN, NW CHINA

JOURNAL OF PETROLEUM GEOLOGY, Issue 3 2003
A. N. Ding
Jurassic source rocks in the Junggar Basin (NW China) include coal swamp and freshwater lacustrine deposits. Hydrocarbon-generating macerals in the coal swamp deposits are dominated by desmocollinite and exinite of higher-plant origin. In lacustrine facies, macerals consists of bacterially-altered amorphinite, algal- amorphinite, alginite, exinite and vitrinite. Coals and coaly mudstones in the Lower Jurassic Badaowan Formation generate oil at the Qigu oilfield on the southern margin of the basin. Lacustrine source rocks generate oil at the Cainan oilfield in the centre of the basin. The vitrinite reflectance (Ro) of coal swamp deposits ranges from 0.5% to 0.9%, and that of lacustrine source rocks from 0.4% to 1.2%. Biomarker compositions likewise indicate that thermal maturities are variable. These variations cause those with lighter compositions to have matured earlier. Our data indicate that oil and gas generation has occurred at different stages of source-rock maturation, an "early" stage and a "mature" stage. Ro values are 0.4%,0.7% in the former and 0.8%,1.2% in the latter. [source]

DEPOSITIONAL ENVIRONMENT AND DIAGENESIS OF THE EOCENE JDEIR FORMATION, GABES-TRIPOLI BASIN, WESTERN OFFSHORE, LIBYA

JOURNAL OF PETROLEUM GEOLOGY, Issue 4 2000
J. M. Anketell
The late Ypresian (early Eocene) Jdeir Formation was deposited in the Mesozoic-Cenozoic Gabes-Tripoli Basin, offshore Libya. The basin developed on the northern passive margin of the African Plate and was relatively unstable being affected by syn-sedimentary tectonic movements. Deposition was coeval with a relative rise of sea-level and the subsequent highstand. A lower, thinly-developed nummulitic bank facies with restricted distribution records the transgressive event and is succeeded by more micritic sediments that record the time of maximum flooding. The succeeding sea-level highstand is represented by a thick, and widely developed, progradational-aggradational nummulitic sequence that displays lateral changes across WE-ESE trending facies belts. Three major lithofacies are recognized in the Jdeir Formation: Nummulites packstone-grainstone, Alveolina-Orbitoliteswackestone-packtone, andFragmental-Discocyclina-Assilina wackestone-packstone, depositedin bank, back-bank, and fore-bank environments, respectively. The formation passes to the NNE into the pelagic lithofacies of the Hallab Formation; landward, to the south, it passes into shoreline evaporitic facies of the Taljah Formation. The lithofacies were structurally controlled by contemporaneous and/or syndepositional tectonic movements, with nummulitic facies tending to develop on uplifted areas. Petrographic and petrophysical studies indicate that porosity in the Jdeir Formation is controlled by depositional environment, tectonic setting and diagenesis. The combined effects of salt tectonics, a major unconformity at the top of the formation and meteoric diagenesis have produced excellent-quality reservoir facies at the Bouri oilfield and in other areas. Porosity is highest in the nummulitic bank facies and lowest in the Alveolina-Orbitolites micrite facies. Good to excellent reservoir quality occurs in the upper part of the nummulitic packstone-grainstone facies, especially where these sediments overlie structurally high areas. High rates of dissolution found at the crests of domes and anticlines suggest that early diagenetic processes and features are, in part, structurally controlled. Future exploration success will depend on investigation of similar structures within the Gabes-Tripoli Basin. Both porosity initiation and preservation are related to early depositional and diagenetic processes. The wide time-gap between hydrocarbon generation and reservoir formation points to the role of the seal in porosity preservation and rules out the assumption that early emplacement of oil had preserved the porosity. [source]

DOLOMITIZATION OF THE EARLY EOCENE JIRANI DOLOMITE FORMATION, GABES-TRIPOLI BASIN, WESTERN OFFSHORE, LIBYA

JOURNAL OF PETROLEUM GEOLOGY, Issue 4 2000
I. Y. Mriheel
Dolomitization in the early Eocene Jirani Formation in the Gabes-Tripoli Basin (offshore western Libya) occurred in two stages. Stage I dolomites are composed of two types, one associated with anhydrite (Type I) the other anhydrite free (Type II,). The stratigraphic and sedimentological settings together with petrographic and geochemical criteria suggest that dolomitization was effected by refluxed evaporative seawater. Stable isotope and trace element analyses suggest dolomitization of both Types from a fluid of near-surface seawater composition under oxidising conditions modified by evaporation. Non-luminescence and lack ofzonation of all the dolomite indicate that the dolomitizing fluids maintained a relatively constant composition. The geologic setting during the early Eocene, interpreted as hypersaline lagoon, supports an evaporative reflux origin for the anhydritic dolomite Type I. Type II developed under less saline conditions in the transition zone between lagoon and open marine shelf. Stage II dolomitization is recorded by negative isotope values in both Types I and II indicating their dissolution and recrystallization (neomorphism) by dilute solutions. A period of exposure of the overlying Jdeir Formation following a relative sea-level fall allowed ingress of meteoric waters into both the Jdeir and the underlying Jirani Formations. Flushing by meteoric waters also resulted in development of excellent secondaly porosity and caused major dissolution of anhydrite to form the anhydritic-free dolomite facies typical of Type II. Following, and possibly during, both Stages I and II, low temperature dolomites (Type IIIa) precipitated in pore spaces from residual jluids at shallow burial depths, partially occluding porosity. In the late stage of basin evolution, medium clystalline, pore-filling saddle dolomite precipitated, causing some filling of mouldic and vuggy porosity (Type IIIb). Very light oxygen isotopic signatures confirm that it developed from high temperature fluids during deep burial diagenesis. Calculation of temperatures and timings of the dolomitization and cement phases show that the main dolomitization phases and Type IIIa cements occurred in the early Eocene, and that the saddle dolomite precipitated in the Miocene; these results are consistent with age relationships established from stratigraphic, petrographic and geochemical signatures. The most common porosity includes intercrystal, vuggy and mouldic types. Porosity is both pre-dolomitization and syn-dolomitization in origin, but the latter is the most dominant. Hence, reservoir quality is largely controlled by fluid dynamics. [source]

POST-DRILLING ANALYSIS OF THE NORTH FALKLAND BASIN, PART 1: TECTONO-STRATIGRAPHIC FRAMEWORK

JOURNAL OF PETROLEUM GEOLOGY, Issue 3 2000
P. C. Richards
Six wells were drilled in the extensional North Falkland Basin in 1998. The wells encountered a Devonian to Cenozoic stratigraphy dominated by thick Mesozoic syn- and post-rift successions. Although most previously published models predicted that the succession would most likely be of marine origin, it is in fact predominantly terrestrial; marine conditions did not become established in the basin until the Late Cretaceous. The oldest rocks recorded are Devonian and these were penetrated in only one well. The overlying succession comprises: a fluvio-lacustrine, early syn-rft interval of ?mid-Jurassic to Tithonian age; a late syn-rift fluvio-lacustrine interval of Tithonian to Berriasian age; a rift-sag transitional unit of Berriasian to Valanginian age; an early post-rift lacustrine unit of Valanginian to early Aptian age; a middle post-rift, transgressive unit of Aptian to Albian age; a late post-rift, terrestrial to marine unit of Albian to early Palaeocene age; and a post-up lift thermal subsidence unit of Palaeocene to Recent age. Much of the sediment appears to have been derived from volcanic and/or metamorphic terranes, probably located to the north or NW of the basin. As well as the volcanic material which occurs in the ground mass and as lithoclasts in many of the units, some volcaniclastic rocks and minor amounts of ashfall tufls are observed, particularly within the late syn-rift succession. [source]

THE GEOLOGY AND HYDROCARBON HABITAT OF THE SARIR SANDSTONE, SE SIRT BASIN, LIBYA

JOURNAL OF PETROLEUM GEOLOGY, Issue 2 2000
G. Ambrose
The Jurassic , Lower Cretaceous Sarir Sandstone Cformerly known as the Nubian Sandstone) in the SE Sirt Basin is composed of four members which can be correlated regionally using a lithostratigraphic framework. These synrift sandstones unconformably overlie a little known pre-rift succession, and are in turn unconformably overlain by post-rift marine shales of Late Cretaceous age. Within the Sarir Sandstone are two sandstone-dominated members, each reflecting a rapid drop in base level, which are important oil reservoirs in the study area. Between these sandstones are thick shales of continental origin which define the architecture of the reservoir units. This four-fold lithostratigraphic subdivision of the Sarir Sandstone contrasts with previous schemes which generally only recognised three members. The sandstones below the top-Sarir unconformity host in excess of 20 billion barrels of oil in-place. The dominant traps are structural (e.g. Sarir C field), stratigraphic (e.g. Messla field), hanging-wall fault plays (e.g. UU1,65 field) and horst-block plays (e.g. Calanscio field). Three Sarir petroleum systems are recognised in the SE Sirt Basin. The most significant relies on post-rift (Upper Cretaceous) shales, which act as both source and seal. The Variegated Shale Member of the Sarir Sandstone may also provide source and seal; while a third, conceptual petroleum system requires generation of non-marine oils from pre-rift (?Triassic) source rocks in the axis of the Sarir Trough. The intrabasinal Messla High forms a relatively rigid block at the intersection of two rift trends, around which stress vectors were deflected during deposition of the syn-rift Sarir Sandstone. Adjacent troughs accommodated thick, post-rift shale successions which comprise excellent source rocks. Palaeogene subsidence facilitated oil generation, and the Messla High was a focus for oil migration. Wrenching on master faults with associated shale smear has facilitated fault seal and the retention of hydrocarbons. In the Calanscio area, transpressional faulting has resulted in structural inversion with oil entrapment in "pop-up" horst blocks. Elsewhere, transtensional faulting has resulted in numerous fault-dependent traps which, in combination with stratigraphic and truncation plays, will provide the focus for future exploration. [source]

THE NATURE AND ORIGIN OF PETROLEUM IN THE CHAIWOPU SUB-BASIN (JUNGGAR BASIN), NW CHINA

JOURNAL OF PETROLEUM GEOLOGY, Issue 2 2000
H. P. Huang
The Chaiwopu Sub-basin is a minor extension of the Junggar Basin, hW China, and covers an area of about 2,500 sq. km. It is bounded to the east and north by the Bogda Shan and to the south by the Tian Shan ("Shan" meaning "mountains" in Chinese). Four wells have been drilled in the sub-basin; condensate and gas have been produced in noncommercial quantities at one of the wells (Well C), but the other three wells were dry. In this paper, I investigate the nature and origin of the petroleum at Well C. Three of the four wells in the Chaiwopu Sub-basin penetrated the Upper Permian Lucaogou Formation. Previous studies in the Junggar Basin have established that laminated lacustrine mudstones assigned to this formation comprise a very thick high quality source rock. However, the analysis of cores from wells in the sub-basin shows that the Lucaogou Formation is composed here of shallow lacustrine, fluvial and alluvial deposits which have very low petroleum generation potential. Overlying sediments (Upper Permian, Triassic and younger strata) likewise have little source potential. Around 1,000 m of Upper Permian laminated oil shales crop out at Dalongkou and Tianchi on the northern side of the Bogda Shan. On the southern side of the Bogda Shan, however, only 30 m of Upper Permian oil shales occur at Guodikong. Shales and oil seeps from these locations were analysed using standard organic-geochemical techniques. The physical properties of the petroleum present at Well C, and its carbon isotope and biomarker characteristics, suggest that it has migrated over long distances from its source rock, although an alternative explanation for its origin is not precluded. Burial history modelling indicates that hydrocarbon generation and migration may have occurred before the uplift of the Bogda Shan in the Late Jurassic,Early Cretaceous, the orogenic episode which resulted in the diflerentiation of the Chaiwopu Sub-basinfrom the Junggar Basin. [source]

BURIAL AND MATURATION HISTORY OF THE HEGLIG FIELD AREA, MUGLAD BASIN, SUDAN

JOURNAL OF PETROLEUM GEOLOGY, Issue 1 2000
A. Y. Mohamed
The NW-SE trending Muglad Basin (SW Sudan) is one of a number of Mesozoic basins which together make up the Central African Rift System. Three phases of rifting occurred during the Cretaceous and Tertiary, resulting in the deposition of at least 13 km of sediments in this basin. Commercial hydrocarbons are sourced from the Barremian-Neocomian Sharaf Formation and the Aptian-Albian Abu Gabra Formation. The Heglig field is located on a NW-SE oriented structural high in the SE of the Muglad Basin, and is the second-largest commercial oil discovery in Sudan. The high is characterised by the presence of rotated fault blocks, and is surrounded by sub-basinal structural lows. We modelled the geohistories of three wells on different fault blocks in the Heglig field (Heglig-2, Barki-1 and Kanga-1) and one well in the Kaikang Trough (May25,1). The models were calibrated to measured porosity-depth data, temperature and vitrinite reflectance measurements. Predicted present-day heat flow over this part of the Muglad Basin is about 55 mW/m2. However, a constant heat-flow model with this value did not result in a good fit between calculated vitrinite Ro and measured Ro at the wells studied. Therefore a variable heat-flow model was used; heat flow peaks of 75, 70 and 70 mW/m2 were modelled, these maxima corresponding to the three synrift phases. This model resulted in a better fit between calculated and measured Ro. The source rock section in the Sharaf and Abu Gabra Formations was modelled for hydrocarbon generation in the four wells. Model results indicate that the present-day oil generation window in the Hegligfield area lies at depths of between 2 and 4 km, and that oil and gas generation from the basal unit of the Abu Gabra Formation occurred between about 90 and 55 Ma and from the Sharaf Formation between 120 and 50 Ma. The results suggest that the oils discovered in the Heglig area have been generated from a deep, mature as-yet unpenetrated source-rock section, and/or from source rocks in nearby sub- basinal areas. [source]

GLOBAL SYSTEMATIC AND PHYLOGENETIC ANALYSIS OF SARGASSUM IN THE GULF OF MEXICO, CARIBBEAN AND PACIFIC BASIN

JOURNAL OF PHYCOLOGY, Issue 2000
N. Phillips
Sargassum is one of the most species-rich genera in the brown algae with over 400 described species worldwide. The bulk of these species occurs in Pacific-Indian ocean waters with only a small portion found on the Atlantic side of the Isthmus of Panama. Sargassum also has one of the most subdivided and complex taxonomic systems used within the algae. Systematic distinctions within the genus are further complicated by high rates of phenotypic variability in several key morphological characters. Molecular analyses in such systems should allow testing of systematic concepts while providing insights into speciation and evolutionary patterns. Global molecular phylogenetic analyses using both conserved and variable regions of the Rubisco operon (rbcL and rbcL-IGS-rbcS) were performed with species from the Gulf of Mexico, Caribbean, and Pacific basin. Results confirm earlier analyses based on rbcL-IGS- rbcS from Pacific species at the subgeneric and sectional level while providing additional insights into the systematics and phylogenetics on a global scale. For example, species east of the Isthmus of Panama form a distinct well-resolved clade within the tropical subgenus. This result in sharp contrast to traditional systematic treatments but provides a window into the evolutionary history of this genus in the Pacific and Atlantic Ocean basins and a possible means to time speciation events. [source]

Water Resources Modeling of the Ganges-Brahmaputra-Meghna River Basins Using Satellite Remote Sensing Data,

JOURNAL OF THE AMERICAN WATER RESOURCES ASSOCIATION, Issue 6 2009
Bushra Nishat
Nishat, Bushra and S.M. Mahbubur Rahman, 2009. Water Resources Modeling of the Ganges-Brahmaputra-Meghna River Basins Using Satellite Remote Sensing Data. Journal of the American Water Resources Association (JAWRA) 45(6):1313-1327. Abstract:, Large-scale water resources modeling can provide useful insights on future water availability scenarios for downstream nations in anticipation of proposed upstream water resources projects in large international river basins (IRBs). However, model set up can be challenging due to the large amounts of data requirement on both static states (soils, vegetation, topography, drainage network, etc.) and dynamic variables (rainfall, streamflow, soil moisture, evapotranspiration, etc.) over the basin from multiple nations and data collection agencies. Under such circumstances, satellite remote sensing provides a more pragmatic and convenient alternative because of the vantage of space and easy availability from a single data platform. In this paper, we demonstrate a modeling effort to set up a water resources management model, MIKE BASIN, over the Ganges, Brahmaputra, and Meghna (GBM) river basins. The model is set up with the objective of providing Bangladesh, the lowermost riparian nation in the GBM basins, a framework for assessing proposed water diversion scenarios in the upstream transboundary regions of India and deriving quantitative impacts on water availability. Using an array of satellite remote sensing data on topography, vegetation, and rainfall from the transboundary regions, we demonstrate that it is possible to calibrate MIKE BASIN to a satisfactory level and predict streamflow in the Ganges and Brahmaputra rivers at the entry points of Bangladesh at relevant scales of water resources management. Simulated runoff for the Ganges and Brahmaputra rivers follow the trends in the rated discharge for the calibration period. However, monthly flow volume differs from the actual rated flow by (,) 8% to (+) 20% in the Ganges basin, by (,) 15 to (+) 12% in the Brahmaputra basin, and by (,) 15 to (+) 19% in the Meghna basin. Our large-scale modeling initiative is generic enough for other downstream nations in IRBs to adopt for their own modeling needs. [source]

PACIFIC NORTHWEST REGIONAL ASSESSMIENT: THE IMPACTS OF CLIMATE VARIABILITY AND CLIMATE CHANGE ON THE WATER RESOURCES OF TEE COLUMBIA RWER BASIN,

JOURNAL OF THE AMERICAN WATER RESOURCES ASSOCIATION, Issue 2 2000
Edward L. Miles
ABSTRACT: The Pacific Northwest (PNW) regional assessment is an integrated examination of the consequences of natural climate variability and projected future climate change for the natural and human systems of the region. The assessment currently focuses on four sectors: hydrology/water resources, forests and forestry, aquatic ecosystems, and coastal activities. The assessment begins by identifying and elucidating the natural patterns of climate vanability in the PNW on interannual to decadal timescales. The pathways through which these climate variations are manifested and the resultant impacts on the natural and human systems of the region are investigated. Knowledge of these pathways allows an analysis of the potential impacts of future climate change, as defined by IPCC climate change scenarios. In this paper, we examine the sensitivity, adaptability and vulnerability of hydrology and water resources to climate variability and change. We focus on the Columbia River Basin, which covers approximately 75 percent of the PNW and is the basis for the dominant water resources system of the PNW. The water resources system of the Columbia River is sensitive to climate variability, especially with respect to drought. Management inertia and the lack of a centralized authority coordinating all uses of the resource impede adaptability to drought and optimization of water distribution. Climate change projections suggest exacerbated conditions of conflict between users as a result of low summertime streamfiow conditions. An understanding of the patterns and consequences of regional climate variability is crucial to developing an adequate response to future changes in climate. [source]

SIZE-AND AGE-CLASS SEGREGATION OF BOWHEAD WHALES SUMMERING IN NORTHERN FOXE BASIN: A PHOTOGRAMMETRIC ANALYSIS

MARINE MAMMAL SCIENCE, Issue 2 2003
Susan E. Cosens
Abstract To determine whether Hudson Bay-Foxe Basin bowhead whales segregate on the basis of age, whales summering in northern Foxe Basin, were aerially photographed in August of 1996, 1997, and 1998. Image lengths on either the negatives or contact prints were measured and total body lengths were estimated. In all three years the majority of whales photographed were ,13.5 m long. Calves and juveniles made up 89.3%, 96.6%, and 79.3% of the total number of measured whales in 1996 (n = 28), 1997 (n = 30) and 1998 (n = 29) respectively. The number of bowheads >13.5 m, the approximate size at which females reach sexual maturity, that were photographed was directly proportional to the number of calves photographed. Our results indicate that northern Foxe Basin bowheads are part of a more widely distributed stock. Adult males and resting adult females apparently summer in another part of the range, probably northwestern Hudson Bay. Northern Foxe Basin appears to be used as a summer feeding area by cows with young-of-the-year calves and by juveniles. [source]