Jon H. Pedersen

Lower Paleozoic petroleum from southern Scandinavia: Implications to a Paleozoic petroleum system offshore southern Norway

Petroleum occurring in lower Paleozoic rocks is known to be present in southern Scandinavia, northern Poland, and the Baltic states. Oil has been produced from lower Paleozoic reservoirs in Sweden; northern Poland; and the Baltic countries Lithuania, Latvia, and the Russian exclave area of Kaliningrad. The sources for this petroleum are marine, organic-rich muds deposited in the Cambrian, Ordovician, and Silurian. This article concerns geochemical analysis of oils extracted from sandstones and carbonates from the Norwegian Oslo Graben rift and locations in Sweden and describes, in addition, insoluble bitumens collected from lower Paleozoic rocks in the Oslo Graben, locations in Sweden, and from upper Paleozoic rocks in a Norwegian North Sea well. The oils in this study have several geochemical characteristics shared with oils from the Baltic states and northern Poland, and the maturities of the oils are, in general, low. The occurrences of bitumen and migrated petroleum in the Oslo Graben lead us to believe that petroleum also has been generated and expelled in the related offshore Skagerrak Graben, indicating that a Paleozoic petroleum system operated in the Skagerrak Graben. This potential petroleum system has not suffered the degree of uplift, erosion, and destruction of reservoirs experienced by the onshore Oslo Graben, making preservation of any petroleum accumulations in the Skagerrak Graben more plausible. Although speculative, these considerations should interest anyone involved in petroleum exploration in the Skagerrak and the Norwegian-Danish Basin, not the least because of the proximity of Skagerrak and major energy markets in Europe.

The geochemistry of two unusual oils from the Norwegian North Sea: implications for new source rock and play scenario

Two oils from the Norwegian North Sea and a source-rock extract from the Danish North Sea are seen to have chemical properties deviating from any previously known North Sea oils. An organic geochemical investigation concludes that the two oils are of low to medium maturity, and that these oils represent alternative organic facies of Upper Jurassic age. The organic facies that sourced the investigated oils are believed to be hypersaline and carbonate-type source rocks, which were most likely deposited in locally developed, secluded lagoonal settings with elevated salinity and low clastic influx. The alternative source rocks inferred by the two atypical oils may add new concepts to petroleum exploration on the margins of the Mesozoic Central Graben and Viking Graben in the North Sea.

Maturity and source-rock potential of Palaeozoic sediments in the NW European Northern Permian Basin

The Northern Permian Basin is located in the offshore area SSW of Norway, NNW of Denmark and east of Scotland. This basin is filled mainly by Lower Permian aeolian desert sediments and volcanics, plus Upper Permian evaporitic sediments. The aeolian sandstone is an excellent reservoir rock and is generally capped by thick layers of salt that potentially form a tight cap rock. The highest risk in the petroleum exploration of the Palaeozoic Northern Permian Basin is linked to the presence of source rocks. Palaeozoic source-rock candidates in the Northern Permian Basin area may be present among Lower Palaeozoic marine sediments, within Devonian–Carboniferous lacustrine/deltaic pre- and syn-rift sediments and as Permian marine shales. This study investigates Lower Palaeozoic marine shales, lacustrine Devonian mudstones, Carboniferous mudstones and coals and marine Permian shales in order to assess the thermal maturity, source-rock potential and distribution of Palaeozoic sediments in the Northern Permian Basin region. The majority of the investigated samples were within the oil window in terms of thermal maturity. Lower Palaeozoic marine sediments may have generated both oil and gas, while Upper Palaeozoic coals and mudstones are dominantly gas-prone source rocks. Middle Permian marine shales (Kupferschiefer) are a good oil-prone source rock. Generation and expulsion of hydrocarbons from Lower Palaeozoic source rocks in the eastern parts of the Northern Permian Basin probably began in the Upper Silurian, with peak oil generation in Carboniferous times. Upper Palaeozoic rocks in the same area matured rapidly in Early Triassic times. The likely presence of multiple Palaeozoic source rocks suggests that hydrocarbons were generated in the Northern Permian Basin.

Considerations of SCTP Retransmission Delays for Thin Streams

The popularity of distributed interactive applications has exploded in the last few years. For example, massive multi-player online games have become a fast growing, multi-million industry with a very high user mass supporting hundreds or thousands of concurrent players. Today, such games are usually client-server applications that use TCP for time-dependent communication. Similar multimedia applications also choose TCP frequently. Very thin data streams are sent over each of these TCP connections, which means that they consume very little bandwidth. TCP has several shortcomings with respect to the latency requirements of such thin streams because of its retransmission handling (C. Griwodz and P. Halvorsen, 2006). An alternative to TCP may be SCTP (R. Stewart, 2000) which was developed to answer the requirements for signaling transport. SCTP has subsequently also been considered more appropriate than TCP for congestion controlled streaming of other time-dependent data. Important reasons are its maintenance of packet boundaries and partial reliability. In this paper, we evaluate the performance of the Linux SCTP implementation for thin streams. Like others before, we identify latency challenges. We also propose some enhancements for reducing the latency compared to the original Linux implementation. We argue for separate handling of thin and thick data streams in SCTP

A drilling mud additive influencing the geochemical interpretations of hydrocarbon shows

Oil-based mud additives are used frequently during drilling for various purposes. The chemical compositions of these may interfere/overprint the chemical composition of hydrocarbon shows in the well and thereby complicate geochemical interpretations. This is likely to be an increasing problem as hydrocarbon findings become more subtle. It is important that the geochemist compiles a list of all additives used during drilling and obtains a sample of the pre-drill oil-based mud additives used. In the case of detailed geochemical analyses to be carried out post-drilling, it is then possible to check the influence/contamination of the additives on the hydrocarbons found. The chemical composition of a frequently used oil-based mud additive is demonstrated to have overprinted the hopane signature of an oil-slick sample in well 35/1-1, northern North Sea. This could easily have resulted in erroneous interpretations regarding age and depositional environment of the source rock of the oil. However, the steranes used for interpretation of facies are shown to be unaffected by the mud additive. A study of shows from well 35/1-1 suggested the source of these to be an atypical developed Upper Jurassic source rock, despite the hopane signature suggesting a carbonaceous Permian source. The main argument was that a Permian source would imply higher maturities than observed. The present study reveals that the hopanes in the shows are contaminated completely by the mud additive used during drilling and, hence, a Permian source is ruled out successfully. This paper demonstrates that if one biomarker group from the mud additive overprints that of the indigenous oil show this does not preclude other biomarker groups from truly representing the oil show.

Thermal maturity, hydrocarbon potential and kerogen type of some Triassic–Lower Cretaceous sediments from the SW Barents Sea and Svalbard

Rock-Eval and total organic carbon (TOC) analyses of 144 samples representing Triassic–Lower Cretaceous intervals from the SW Barents Sea (the Svalis Dome, the Nordkapp and Hammerfest basins, and the Bjarmeland Platform) and Svalbard demonstrate lateral variations in source rock properties. Good to excellent source rocks are present in the Lower–Middle Triassic Botneheia and Steinkobbe, and Upper Jurassic Hekkingen formations, 1 – 7 wt% and 6 – 19 wt% TOC, respectively. Hydrogen indices of 298 – 609 mg HC/g TOC in the Botneheia Formation from Svalbard, and 197 – 540 mg HC/g TOC in the Steinkobbe Formation of Svalis Dome suggest Type II (oil-prone) and Type II/III (oil/gas-prone) kerogens, respectively. The Kobbe Formation (Botneheia/Steinkobbe-equivalent) is organic-lean and generally gas-prone (Type III kerogen) on the Bjarmeland Platform and in the Nordkapp Basin, and is a good source rock with Type III/II kerogen in the Hammerfest Basin. In the investigated wells, the Hekkingen Formation is more oil-prone on the Bjarmeland Platform than in the Nordkapp Basin, while Lower Cretaceous samples have poor potential for oil. Upper Triassic samples show potential mainly for gas; however, coal/coaly-shale samples in well 7430/07-U-01 (Bjarmeland Platform) are oil/gas-prone. Most samples analysed are immature to early mature; thus, the variation in petroleum potential and kerogen type is a function of organic facies rather than maturity levels.