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- Volume 28, Issue 2, 2022
Petroleum Geoscience - Volume 28, Issue 2, 2022
Volume 28, Issue 2, 2022
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Overview of the exploration potential of offshore Argentina – insight from new seismic interpretations
Authors Steve DeVito and Hannah KearnsArgentina's offshore sedimentary basins cover a vast area on one of the widest continental margins on the planet, yet they remain underexplored today. Previous exploration drilling has failed to encounter commercial volumes of hydrocarbons, in part due to the poor seismic imaging of legacy 1960s–1990s 2D seismic data, and to the majority of wells being drilled on structural highs outside of the source rock kitchens. In this study, we reviewed 52 000 km of recently acquired (2017–2018) regional 2D long-offset seismic data with broadband pre-stack time (PSTM) and depth migration (PSDM) processing. We identified five major structural domains with hydrocarbon prospectivity on the Northern Margin of Argentina and four on the Southern Margin, and the presence of previously unseen structural and stratigraphic traps involving sequences assigned to proven regional source rocks and reservoirs in Permian, Jurassic and Cretaceous rocks. The source and reservoir rocks, petroleum systems, and play types present in the deepwater of the undrilled Argentina Basin represent a true frontier for hydrocarbon exploration. Pseudo relief attribute seismic displays and amplitude v. angle (AVA) analysis are demonstrated to be valuable tools in predicting the stratigraphy of the basins. A new framework for understanding the oil and gas prospectivity of the study area is presented.
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The principles of helium exploration
Commercial helium systems have been found to date as a serendipitous by-product of petroleum exploration. There are nevertheless significant differences in the source and migration properties of helium compared with petroleum. An understanding of these differences enables prospects for helium gas accumulations to be identified in regions where petroleum exploration would not be tenable. Here we show how the basic petroleum exploration playbook (source, primary migration from the source rock, secondary longer distance migration, trapping) can be modified to identify helium plays. Plays are the areas occupied by a prospective reservoir and overlying seal associated with a mature helium source. This is the first step in identifying the detail of helium prospects (discrete pools of trapped helium). We show how these principles, adapted for helium, can be applied using the Rukwa Basin in the Tanzanian section of the East African Rift as a case study. A thermal hiatus caused by rifting of the continental basement has resulted in a surface expression of deep crustal gas release in the form of high-nitrogen gas seeps containing up to 10% 4He. We calculate the total likely regional source-rock helium generative capacity, identify the role of the Rungwe volcanic province in releasing the accumulated crustal helium and show the spatial control of helium concentration dilution by the associated volcanic CO2. Nitrogen, both dissolved and as a free-gas phase, plays a key role in the primary and secondary migration of crustal helium and its accumulation into what might become a commercially viable gas pool. This too is examined. We identify and discuss evidence that structures and seals suitable for trapping hydrocarbon and CO2 gases will likely also be efficient for helium accumulation on the timescale of the Rukwa Basin activity. The Rukwa Basin prospective recoverable P50 resources of helium have been independently estimated to be about 138 BSCF (billion standard cubic ft: 2.78 × 109 m3 at STP). If this volume is confirmed it would represent about 25% of the current global helium reserve. Two exploration wells, Tai 1 and Tai 2, completed by August 2021 have proved the presence of seal and reservoir horizons with the reservoirs containing significant helium shows.
This article is part of the Energy Geoscience Series available at https://www.lyellcollection.org/cc/energy-geoscience-series
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Clumped isotope constraints on the origins of reservoir methane from the Barents Sea
The Barents Sea basin is an oil and gas province containing more than 760 million tons of oil equivalents. The reservoir geology of the Barents Sea is complex due to multiple episodes of subsidence, uplift and erosion, which opened a network of extensional and wrench related faults allowing for fluid migration. The multifaceted geological history complicates efforts to describe the source and characteristics of natural gas in the subsurface Barents Sea. Here we apply stable isotopes, including methane clumped isotope measurements, to thirteen natural gases from five (Skrugard Appraisal, Havis, Alta, Filicudi, and Svanefjell) reservoirs in the Loppa High area in the southwestern Barents Sea to estimate the origins of methane. We compare estimates of methane formation temperature based on clumped isotopes to thermal evolution models for the region. We find that the methane has diverse origins including microbial and thermogenic sources forming and equilibrating at temperatures ranging from 34–238°C. Our clumped isotope temperature estimates are consistent with thermal evolution models for the area. These temperatures can be explained by gas generation and expulsion in the oil and gas window followed by isotopic re-equilibration in some reservoirs due to microbial methanogenesis and/or anaerobic oxidation of methane. Gases from the Skrugard Appraisal, Havis and Alta have methane equilibration temperatures consistent with maximum burial temperatures, while gases from Svanefjell have methane equilibration temperatures consistent with current reservoir temperature, suggesting isotope re-equilibration in the shallow reservoir. Gases from Filicudi on the other hand are consistent with generation over multiple points over its thermal history.
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Naturally occurring underpressure – a global review
Authors T. Birchall, K. Senger and Richard SwarbrickSeveral mechanisms have been suggested as drivers of naturally occurring underpressure. However, the phenomenon is largely underrepresented in literature. Previous studies have focused on individual cases in North America, where challenges due to topography and defining hydrostatic gradients exist. More recent publications from underpressured basins have emerged from other parts of the world, where settings are arguably more favourable to studying the phenomenon. Based on a total of 29 underpressured locations, it is apparent that the magnitudes and depths of underpressure are similar throughout the world.
Pressures of up to 60 bar blow hydrostatic are common in sedimentary basins of North America, China, Russia, and Europe and typically occur at shallow depths (<2500 m). All occurrences of underpressure occur in areas that have been geologically recently uplifted and is predominantly confined to low permeability rocks. Although rarely tested, it appears that mudstone intervals are susceptible to developing underpressure. Given the shallowness, low permeability, and recent uplift of the cases, it seems that underpressure is typically a geologically short-lived phenomenon.
Thematic collection: This article is part of the Geopressure collection available at: https://www.lyellcollection.org/cc/geopressure
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Investigating the role of differential biotic production on carbonate geometries through stratigraphic forward modelling and sensitivity analysis: the Llucmajor example
Authors Timothy O. Tella, Gerd Winterleitner and Maria MuttiThe geometry of carbonate platforms reflects the interaction of several factors. However, the impact of carbonate-producing organisms has been poorly investigated so far. This study applies stratigraphic forward modelling (SFM) and sensitivity analysis to examine, referenced to the Miocene Llucmajor Platform, the effect of changes of dominant biotic production in the oligophotic and euphotic zones on platform geometry. Our results show that the complex interplay of carbonate production rates, bathymetry and variations in accommodation space control the platform geometry. The main driver of progradation is the oligophotic production of rhodalgal sediments during the lowstands. This study demonstrates that platform geometry and internal architecture varies significantly according to the interaction of the predominant carbonate-producing biotas. The input parameters for this study are based on well-understood Miocene carbonate biotas with characteristic euphotic, oligophotic and photo-independent carbonate production in which it is crucial that each carbonate-producing class is modelled explicitly within the simulation run and not averaged with a single carbonate production–depth profile. This is important in subsurface exploration studies based on stratigraphic forward models where the overall platform geometry may be approximated through calibration runs, and constrained by seismic surveys and wellbores. However, the internal architecture is likely to be oversimplified without an in-depth understanding of the target carbonate system and a transfer to forward modelling parameters.
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The impact of clay fraction on the strength and stress ratio (K 0) in Gulf of Mexico mudrocks and quartz silt mixtures: implications for borehole stability and fracture gradient
Authors Mark Zablocki, John T. Germaine, Richard Plumb and Peter B. FlemingsMudrock strength parameters are required to improve the prediction of fracture gradient during drilling in poorly consolidated formations. Understanding the influence that mineral composition and consolidation stress have on the mechanical properties of mudrocks aids safe well design. Small changes in the mudrock clay content are shown to have significant effects on two important engineering parameters: the lateral stress ratio at rest, K 0, and the critical state effective friction angle, ′cs. A laboratory-testing programme using quartz silt and a Gulf of Mexico clay mixture investigates the effects of mudrock clay content on K 0 and ′cs at two stress levels: 1 and 10 MPa. Values of K 0 and ′cs were obtained by subjecting composition-controlled clay–silt specimens to a drained uniaxial vertical strain (K 0 consolidation) phase, followed by an undrained compression triaxial shear phase. Triaxial tests illustrate consistent and systematic increases in K 0 and decreases in ′cs, with increases in clay content at both stress levels. Stress dependence is observed through increases in K 0 and decreases in ′cs with increases in stress level. Stress-dependent behaviour is shown to be more pronounced in mudrocks of high clay content. A predictive model is presented for K 0 in normally consolidated mudrocks, as a function of clay content and effective stress. The model is used to calculate the fracture gradient (least horizontal stress) profile at the International Ocean Drilling Program (IODP) Expedition 308 Site 1324. The estimated fracture gradient illustrates the effects of clay content and consolidation stress on safe mud weight design.
Thematic collection: This article is part of the Geopressure collection available at: https://www.lyellcollection.org/cc/geopressure
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3D seismic interpretation and fault slip potential analysis from hydraulic fracturing in the Bowland Shale, UK
Authors Sirawitch Nantanoi, Germán Rodríguez-Pradilla and James VerdonThe Bowland Shale Formation is one of the most promising targets for unconventional exploration in the United Kingdom, with estimated resources large enough to supply the country's entire natural gas consumption for 50 years. However, development of the Bowland Shale has stalled due to concerns over hydraulic-fracturing-induced seismicity. Only three wells have been drilled and hydraulic-fractured to date in the Bowland Shale, and all three have produced levels of seismicity of sufficient magnitude to be felt at the surface. Susceptibility to induced seismicity will be determined by the presence of critically stressed faults. However, such faults can go undetected in conventional interpretation of 2D or 3D seismic surveys if they are shorter than the resolution retrievable from a seismic survey, or if they have low (and in some cases even zero) vertical displacement. In such cases, the faults that cause induced seismicity may only be visible via microseismic observations once they are reactivated. To better identify fault planes from 3D seismic images, and their reactivation potential due to hydraulic fracturing, a high-resolution fault-detection attribute was tested in a 3D seismic survey that was acquired over the Preston New Road site, where two shale-gas wells were hydraulic-fractured in the Bowland Shale in 2018 and 2019, obtaining fault planes with lengths between 400 and 1500 m. Fault slip potential was then estimated by integrating the obtained faults with the formation's stress and pore pressure conditions (with the Bowland shale also being significantly overpressured), and several critically stressed faults were identified near the previously hydraulic fractured wells. However, the faults that induced the largest seismic events in the Preston New Road site, of c. 200 m in length for seismic events of magnitudes below 3.0 (as imaged with a multicomponent, downhole microseismic monitoring array deployed during the hydraulic-fracturing stimulations), could not be identified in the 3D seismic survey, which only mapped fault planes larger than 400 m in length.
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Interaction between volcanic and non-volcanic systems and its implication for prospectivity in the Faroe–Shetland Basin, NE Atlantic continental margin
Authors Heri Ziska, Uni Árting and Morten S. RiishuusExploration in the Faroe–Shetland Basin on the Faroese Continental Shelf has revealed thick and complex volcanic successions and discovery of inter-volcanic oil-bearing siliciclastic sandstone fan deposits in the central parts of the basin. The possibility for such play types at the fringe of the North Atlantic Igneous Province requires a better understanding of the interaction between competing sedimentary and volcanic depositional transport systems. We have re-examined volcanic units in cuttings from exploration wells in the greater Judd Sub-basin area for evaluation of facies and geochemical affinity. This allows for chemostratigraphical correlation of wells to the absolute radiometrically age-constrained Faroe Islands Basalt Group. The collective well data were subsequently tied to a regional interpretation of 2D seismic data which facilitated a detailed interpretation of temporal development of the volcanic successions in the Judd Sub-basin area in terms of geometry, volcanic facies, depositional environment, and interdigitation with non-volcanic sedimentary units.
The Judd Sub-basin was influenced by major volcanic phases during pre-breakup and syn-breakup. The influence was both direct, in the form of volcanic deposits, and indirect, in the form of obstructing established sedimentary transport systems and creating new provenance areas. The volcanic transport systems reached different areas of the Judd Sub-basin at different times during pre-breakup volcanism. The earliest incursion in the west was during late Mid Paleocene (T-sequence T31/T32). With at least three stratigraphically discrete incursions of volcanic material into the Judd Sub-basin, possibilities arise for sub- and inter-volcanic stratigraphic and structural traps for each incursion.
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The role of pore pressure and its prediction in deep geothermal energy drilling – examples from the North Alpine Foreland Basin, SE Germany
Pore pressure prediction is a well-developed key discipline for well planning in the hydrocarbon industry, suggesting a similar importance for deep geothermal wells, especially, since drilling cost is often the largest investment in deep geothermal energy projects. To address the role of pore pressure prediction in deep geothermal energy, we investigated pore pressure-related drilling problems in the overpressured North Alpine Foreland Basin in SE Germany – one of Europe's most extensively explored deep geothermal energy plays. In the past, pore pressure was mainly predicted via maximum drilling mud weights of offset hydrocarbon wells, but recently more data became available, which led to a re-evaluation of the pore pressure distribution in this area. To compare the impact of pore pressure and its prediction, 70% of all deep geothermal wells drilled have been investigated for pore pressure-related drilling problems and two deep geothermal projects are given as more detailed examples. Thereby, pore pressure-related drilling problems were encountered in one third of all wells drilled, resulting in several side-tracks and an estimated drilling rate decrease of up to 40%, highlighting the importance of accurate pore pressure prediction to significantly reduce the cost of deep geothermal drilling in overpressured environments.
Thematic collection: This article is part of the Geopressure collection available at: https://www.lyellcollection.org/cc/geopressure
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Kicks and their significance in pore pressure prediction
Authors Jack Lee, Richard Swarbrick and Stephen O'ConnorKnowledge of subsurface formation pressures is critical for the calibration of predictions and models needed for safe drilling of deep wells, historically for oil and gas wells. The same details apply to the sequestration of CO2, ephemeral storage of gases such as hydrogen and for geothermal power. An estimated 10–14% of wells globally experience an unexpected influx of formation fluid, indicative of the controlling mud in the borehole at that time having a lower pressure than the surrounding formation. The drilling events, known as kicks and wellbore breathing, lead to, at best, downtime on the drilling rig which might affect the economic viability of the well, or in the extreme its safety with possible loss of life such as in the case of an uncontrolled blowout. Not all kicks are of equivalent value: dynamic and static kicks can be classified with a high degree of confidence and may become values for true formation pressure. Other types of fluid influx during drilling, including swab kicks and wellbore breathing, need to be identified and will not be accepted in a kick database. These types of influx may be eliminated as potential formation pressure values but, along with mud weights, can be valuable data to constrain the range of possible formation pressures, of significant where no other data exist. A new, rigorous evaluation procedure for determining formation pressure is presented, and compared with direct pore pressure measurements (e.g. RFT, MDT, RCI values). The comparison shows that the proposed methodology illustrates typical uncertainty of about 10 bar (145 psi) pressure over the full range of pressures for which data are available in this study.
Thematic collection: This article is part of the Geopressure collection available at: https://www.lyellcollection.org/cc/geopressure
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Pressure variations in the northern part of the Danish Central Graben, North Sea
More LessThe overpressure variation in the Cenozoic–Jurassic succession in the northern part of the Danish Central Graben may broadly be divided into three major compartments. An upper hydrostatically pressured unit comprises the post-mid Miocene–recent succession down to c. 1200 m depth in the northern and c. 700 m in the southern parts of the Danish Central Graben. The second compartment comprises the mid-Miocene smectite-rich clays down to and including the upper Cretaceous chalk. There the Paleogene–Lower Miocene succession provides the seal. The third compartment constitutes the Jurassic succession with pressure above hydrostatic that may exceed twice that seen at the upper Chalk level. Pressure levels can be estimated using the Eaton approach for the second compartment that are in agreement with pressure data. Modelling of the transient pressure development in the Cretaceous–mid-Miocene succession broadly complies with the Eaton estimates and shows that the main overpressure build-up has occurred within the last 10 myr. The overpressure in this succession may be mapped using methods that exploit correlations between fluid pressure and the degree of consolidation, while that in the Jurassic cannot. However, the lateral variation in the Upper Jurassic overpressure correlates broadly with the maturity of the Upper Jurassic source rock, allowing the pressure variation to be mapped.
Thematic collection: This article is part of the Geopressure collection available at: https://www.lyellcollection.org/cc/geopressure
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Volumes & issues
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Volume 30 (2024)
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Volume 29 (2023)
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Volume 28 (2022)
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Volume 27 (2021)
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Volume 26 (2020)
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Volume 25 (2019)
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Volume 24 (2018)
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Volume 23 (2017)
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Volume 22 (2016)
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Volume 21 (2015)
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Volume 20 (2014)
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Volume 19 (2013)
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Volume 18 (2012)
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Volume 17 (2011)
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Volume 16 (2010)
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Volume 15 (2009)
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Volume 14 (2008)
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Volume 13 (2007)
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Volume 12 (2006)
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Volume 11 (2005)
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Volume 10 (2004)
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Volume 9 (2003)
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Volume 8 (2002)
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Volume 7 (2001)
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Volume 6 (2000)
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Volume 5 (1999)
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Volume 4 (1998)
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Volume 3 (1997)
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Volume 2 (1996)
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Volume 1 (1995)