Kristian Backer-Owe

Processes controlling water and hydrocarbon composition in seeps from the Salton Sea geothermal system, California, USA

Water-, mud-, gas-, and petroleum-bearing seeps are part of the Salton Sea geothermal system (SSGS) in Southern California. Seeps in the Davis-Schrimpf seep fi eld (~14,000 m 2 ) show considerable variations in water temperature, pH, density, and solute content. Water-rich springs have low densities ( 98 vol%). Halogen geochemistry of the waters indicates that mixing of deep and shallow waters occurs and that near-surface dissolution of halite may overprint the original fl uid compositions. Carbon isotopic analyses suggest that hydrocarbon seep gases have a thermogenic origin. This hypothesis is supported by the presence of petroleum in a water-dominated spring, composed of 53% saturated compounds, 35% aromatics, and 12% polar compounds. The abundance of polyaromatic hydrocarbons and immature biomarkers suggests a hydrothermal formation of the petroleum, making the SSGS a relevant analogue to less accessible hydrothermal seep systems, e.g., the Guaymas Basin in the Gulf of California.

Petroleum migration, faults and overpressure. Part II. Case history: The Haltenbanken Petroleum Province, offshore Norway

Abstract Petroleum inclusion and geochemical data from core extracts were applied to deduce a model for oil migration, overpressure development and palaeo-leakage of oil from currently dry structures in the Haltenbanken Vest area. The existence of fluorescent oil type inclusions in quartz in the Smørbukk (Åsgard-2) field suggest that oil migrated into this structure 70–50 million years before present (Ma bp). This is also the case for the dry structures 6506/12-4, 6506/11-3 and 6506/11-1, west of the main Smørbukk Fault Zone. Black oil inclusions with medium gas/oil ratio (GOR) occur in these fields together with condensate-type petroleum inclusions. This suggests that the dry structures transformed from containing oil to condensate before leakage. Petroleum extracted from inclusions in these structures and in nearby fields have identical marine type II kerogen signatures. Source rocks at the Spekk Formation level in the current drainage area of Smørbukk and these dry structures, were immature 70–50 Ma bp and the Smørbukk Sør (Åsgard-3) field did not fill at this early time. Thus, oil must initially have entered into Smørbukk from areas to the W-SW, through the currently pressure sealing Smørbukk Fault Zone which today marks the westward limit of the Smørbukk field. Diagenesis in this fault zone caused the much later overpressure development and petroleum was lost from the 6506/12-4, 6506/11-3 and 6506/11-1 structures as overpressure built up regionally. Petroleum loss from these structures with their often thick seals must have occurred via self-propagating open-fracture-induced mechanisms. Lack of petroleum in the Cretaceous strata above these structures suggests that leakage occurred to even shallower strata. This could imply that the Cretaceous strata in Halten Vest were overpressured at the time of leakage. In contrast, the oil in the Cretaceous Lysing and Lange Formation (above the Jurassic reservoirs in Smørbukk and Smørbukk Sør) most likely originated (based on geochemistry and GORs) from the Jurassic reservoirs below and not from Cretaceous strata. This migration event would have been facilitated if it occurred before these sands became overpressured as they are today. Modelling suggests that the Spekk Formation became mature in the Smørbukk Sør region <10 Ma bp and microthermometry of oil inclusions from Smørbukk Sør supports filling during the past 10 Ma. This implies that caprock failure in the Halten Vest structures 6506/12-4, 6506/11-1 and 6506/11-3 most likely occurred after filling of the Smørbukk Sør and 6406/3-1 structures. Rapid regional burial during the past 10 Ma caused local migration of oil into Smørbukk Sør, Smørbukk and 6406/3-1 structures, and generation of high GOR oils in the deeper Halten Vest region. High GOR petroleum inclusions in the Halten Vest structures signify this event and suggests that caprock fracturing occurred after a gas-condensate had replaced oil in these traps. Rapid burial during the past 3 Ma is likely to have caused the current overpressure and associated leakage in Halten Vest. The fact that these traps did not later refill in this progressively subsiding and maturing basin must be related to trap pressures remaining too close to the actual fracture pressures.

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.

Petroleum geochemistry of the Frøy field and Rind discovery, Norwegian Continental Shelf. Implications for reservoir characterization, compartmentalization and basin scale hydrocarbon migration patterns in the region

Abstract Petroleum geochemistry provides an excellent tool for understanding reservoir characteristics with respect to oil flow and tracing out elements of basin scale migrational patterns and reservoir compartmentalization. Organic geochemical characterization has been carried out on 580 core extracts and 9 oils from 11 wells of the Froy field and Rind discovery in the South Viking Graben. Two different drainage areas and source rock systems have been identified for the hydrocarbons in the Froy field and the Rind discovery on the basis of differences in maturity and gas to oil ratio in addition to facies differences like % C 28 -αα-sterane content and the ratio of bisnorhopane to bisnorhopane plus norhopane. Results show that the Rind discovery contains oil of higher maturity compared to the oil from Froy field. The petroleum in the Rind discovery has a more terrestrial character and is interpreted to have been derived from source rocks other than the Draupne Formation in its typical anoxic distal development. A likely candidate is the Heather Formation. In addition, a small contribution of immature oil has been identified in a separate small sub-compartment in the Froy field. The petroleum in this sub-compartment shows a high pristane to phytane ratio and a very prominent odd-to-even predominance. Well 25-14, drilled northeast of the Froy field, penetrates a water-bearing, hydrostatic structure. The detailed geochemical characterization including petroleum inclusion studies have shown that this structure never received oil or gas, nor did it have any communication with the Froy field. Hence it is inferred that this structure never communicated with the hydrocarbon producing basin. One of the two compartments in the Rind discovery is hydrostatic and contains petroleum of a comparatively large maturity span whilst residual core bitumen in a high-pressured neighboring compartment has a very small maturity span and contains presently only water as producible phase. The ratios of the 20S to 20S + 20R isomers of C 29 -αα-steranes, the ratio of C 20 to C 20 + C 28 triaromatic steroids and the C 28 triaromatic steroid to C 28 triaromatic steroid + C 29 monoaromatic steroid ratio in the latter compartment have almost uniform values indicating a single oil pulse, i.e. a short filling history, whereas in the other compartment, these ratios vary over a large range indicating a longer filling history. As both compartments contain petroleum with the same source rock facies signatures, it is suggested that these at some time were part of the same migration system. Communication between these compartments is inferred to have been disrupted before seal failure occurred in the structure which was penetrated by well 25-15R2. The analyses carried out indicate a high degree of chemical homogeneity in the petroleum of the Froy field reservoir which, in comparison with the Rind discovery, is more similar to extracts from typical anoxic developed distal shales of the Upper Jurassic source rock in the Viking Graben, i.e. the Kimmeridge equivalent Draupne Formation. However, the upper reservoir units in the northern well 25/5-A7 contain extracts with lower maturity and more terrestrial characteristics compared with the extracts in the deeper reservoir sections. In addition, well 25/5-1, which penetrates the highest point of the Froy structure, contains petroleum of slightly higher maturity than found elsewhere in the Froy field. The results further suggest that the faults in the Froy field including the main E-W trending fault separating the northern and the southern parts of the of the Froy field did not adversely affect lateral communication during filling. To conclude, there is no petroleum geochemical evidence to suggest that intra-reservoir faults have caused significant compartmentalization of the Froy field except for the N-S trending fault which separates a small block to the west from the Froy field main reservoir. Thus with respect to petroleum production, it is concluded that primary sedimentological features are more important in terms of exerting a first order control for determining the vertical and lateral flow of hydrocarbons in this reservoir than faults.

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.

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.

Regional petroleum alteration trends in Barents Sea oils and condensates as a clue to migration regimes and processes

To date, most condensates and gases found in the Hammerfest Basin exist in distal, central basin settings, in traps with tight cap rocks of class 1 traps, whereas low-gas–oil-ratio (GOR) oils occur systematically in proximal basin settings, where cap rocks of class 3 traps prevail. Multiple fill-spill events resulted in the redistribution of oils toward structurally higher basin margins. In a systematic evaluation of light hydrocarbon parameters from condensates and oils, it was found that oils in general exhibit more traceable alteration effects than do condensates. Whereas 75% of condensate and 13.3% of oil samples are fractionated, 6.25% and 10%, respectively, show signs of biodegradation. Long-distance migration is indicated for 12.5% of condensate and 50% of oil samples. In addition, clear evidence is shown for the mixing of recently migrated high-GOR petroleum phases with older, low-GOR paleo oils. In general, variation in source-specific parameters is surprisingly less pronounced. Decreasing thermal maturity of entrapped petroleum from the eastern part of the Tromso Basin toward the Masoy-Nysleppen Fault Complex is observed, whereas high maturities are shown for the Nordkapp Basin and the Finnmark Platform in the eastern part of the study area. Low-to-medium maturities are recorded for oils from the basin margins of the Hammerfest Basin. Alterations in the composition of the petroleums by physiochemical processes and distribution patterns of the petroleums are closely associated with uplift and erosion.

Depositional environment and age determination of oils and condensates from the Barents Sea

The Barents Sea hosts multiple source rocks from Palaeozoic to Cretaceous age. Attempts in the past to link individual oil and condensates directly to one type of source rock have often been complicated due to ‘blended-oil’ signatures. As a result of uplift, remigration, alteration and mixing of petroleums, deconvolution of primary petroleum signatures in terms of maturity, age and depositional environment is generally complicated. In this paper, we use δ13C isotopes, and age- and source-related biomarkers to line out the main basin-scale trends concerning the depositional environments and source-rock ages, as well as the type of organic matter input that constitutes the inferred source-rock kerogen. Multivariate statistical analysis was applied as an auxillary tool to suggest petroleum families. Results classify the petroleums into four families: (1) Permian–Triassic-sourced petroleums; (2) Carboniferous-sourced petroleums; (3) Jurassic-sourced petroleums; and (4) phase-fractionated condensates charged from late mature Triassic–Jurassic source rocks. The inferred palaeo-environments for the petroleums cover marine, transitional and terrestrial depositional environments, and display geological variations that prevailed during Permian–Jurassic times. Isotope signatures and age-specific parameters suggest that many oils in the region should be considered as blends or mixtures derived from more than one source rock.

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.

Petroleum occurrences in the carbonate lithologies of the Gohta and Alta discoveries in the Barents Sea, Arctic Norway

Investigation of petroleum inclusions in carbonate samples from the Senilix well in the Barents Sea reveals petroleum entrapment in Paleozoic carbonates at reservoir temperatures from as low as 87.3°C to more than 130°C. Using corrected bottom hole temperatures, this corresponds to depths of 2800–4100 m, compared to the present-day depth of these samples of only 1965.9–2020.5 m. The oil in the Gohta and Alta discoveries is concluded to be of either Lower Triassic or Paleozoic origin based on the isomer distribution of triaromatic dimethylcholesteroids (TA-DMC). A potential source-rock candidate is the Ørret Formation, which is the time-equivalent to the Ravnefjeld Formation in Greenland. These oils are of a different origin compared to oils in the nearby Skrugard (renamed to Johan Castberg) discovery which contain oil sourced from the Upper Jurassic Hekkingen Formation. Evidence is presented to suggest that the Gohta and Alta oils represent blends of petroleum expelled at maturities ranging from about 1.0% calculated vitrinite reflectance (Rc) to more than 1.3%Rc, and this corroborates the inferences made from the petroleum inclusions. This emerging play is significant to exploration in the karst developed on the Barents Shelf and the Bjarmeland Platform during the Permo-Carboniferous. Karst reservoirs have been linked to eustatic sea-level changes, and analogous karst reservoirs may be present elsewhere in the Circum-Arctic: for example, in the Sverdrup Basin.