bluuebunny/crossref_metadata_2025_split huggingface dataset:
A road map for the identification and recovery of by-passed pay
Authors: Worthington P. F. 
Published: May 2011

Abstract

By-passed pay can occur at or between wells. Either way, it constitutes a lower risk prospect than hydrocarbon accumulations in unappraised areas. Beyond this, there are three contemporary drivers for its exploitation. First, new technology in the form of sharper reservoir imaging allows insights that were not achievable previously. Second, an evolving understanding of how reservoirs work has led to improved procedures for maximizing the exploitation of even the most problematic accumulations. Third, market forces amid global post-peak production fears are giving the incremental development of by-passed pay an even greater commercial impetus today. An examination of case histories that illustrate the role of these drivers has led to a six-fold type classification of by-passed pay. Type 1 can be produced using an existing identified well. Type 2 requires a side track or a new well in order to capture the reserves. Each type is further subdivided into three classes. The classification scheme has provided the context for an emerging
modus operandi
to maximize commercially recoverable hydrocarbons in developed assets. Thus, the approach takes the form of a road map for practical application. By corollary, the type classification demonstrably accommodates a wide range of reported exploitations of by-passed pay from diverse reservoirs. Therefore, this classification constitutes a potential foundation for further systemic refinements to the identification and recovery of by-passed pay.
A holostratigraphic approach to the chalk of the North Sea Eldfisk Field, Norway
Authors: Hampton M. J. , Bailey H. W. , Jones A. D. 
Published: May 2011

Abstract

A biostratigraphic review, conducted on 34 wells from the chalk of the Eldfisk Field, Norwegian Central Graben, has been integrated with petrophysical, geophysical and sedimentological information resulting in a revised lithostratigraphic framework for the chalk on this structure. Chalk of Danian to Turonian age is divided into five formations: the established Ekofisk Formation of Danian age and Tor Formation of Maastrichtian age, together with a new three-fold division of the Hod Formation, namely the Magne Formation of Campanian age, the Thud Formation of Santonian age and Narve Formation of Coniacian to Turonian age. This work demonstrates the application of this three-fold division of the Hod Formation. Internal field specific subdivisions of all formations are also presented for the Eldfisk Field. This lithostratigraphic framework is applied across the Eldfisk Field, together with the recognition of erosional features, unconformities, areas of non‐deposition, reworking and lateral changes in biofacies. The results have also allowed recognition of the following regionally synchronous tectonic phases for the first time on a Norwegian chalk structure: Stille's Ilsede phase (Late Turonian–Coniacian) and Wernigerode phase (Late Santonian–‘earliest’ Campanian), Mittel–Santon phase (Middle Santonian) of Niebuhr
et al.
and Reidel's Peine phase (‘latest’ Early Campanian), together with un-named phases of ‘latest’ Campanian, intra Mid Maastrichtian and (previously unrecognized?) intra Danian age. Evidence for these tectonic phases is compared with work from Denmark, Germany and the Anglo-Paris Basin. An innovative approach to mapping lateral biofacies (principally water depth) variations has been applied using the microfaunal database. This enhances understanding of the timing of structural phases when integrated with time lines generated by nanoplankton data. Biofacies proxies for silica content in the sediment may also correlate with changes in reservoir quality. Biofacies interpretations have also facilitated the identification and mapping of allochthonous bioclastic rich debris flow deposits. The fully calibrated biostratigraphic, lithostratigraphic and tectonostratigraphic frameworks presented can be applied to chalk structures regionally.
Assessment of undiscovered petroleum resources of the north and east margins of the Siberian craton north of the Arctic Circle
Authors: Klett T. R. , Wandrey C. J. , Pitman J. K. 
Published: May 2011

Abstract
The Siberian craton consists of crystalline rocks and superimposed Precambrian sedimentary rocks deposited in rift basins. Palaeozoic rocks, mainly carbonates, were deposited along the margins of the craton to form an outwardly younger concentric pattern that underlies an outward-thickening Mesozoic sedimentary section. The north and east margins of the Siberian craton subsequently became foreland basins created by compressional deformation during collision with other tectonic plates. The Tunguska Basin developed as a Palaeozoic rift/sag basin over Proterozoic rifts.

The geological provinces along the north and east margins of the Siberian craton are immature with respect to exploration, so exploration-history analysis alone cannot be used for assessing undiscovered petroleum resources. Therefore, other areas from around the world having greater petroleum exploration maturity and similar geological characteristics, and which have been previously assessed, were used as analogues to aid in this assessment. The analogues included those of foreland basins and rift/sag basins that were later subjected to compression. The US Geological Survey estimated the mean undiscovered, technically recoverable conventional petroleum resources to be
c.
28 billion barrels of oil equivalent, including
c.
8 billion barrels of crude oil, 103 trillion cubic feet of natural gas, and 3 billion barrels of natural gas liquids.
From Neoproterozoic to Early Cenozoic: exploring the potential of older and deeper hydrocarbon plays across North Africa and the Middle East
Authors: Craig J. , Grigo D. , Rebora A. , Serafini G. , Tebaldi E. 
Published: May 2011

Abstract
As the traditional exploration plays in the main productive basins of North Africa and the Middle East become more ‘mature’, attention is increasingly focusing on more challenging, older and deeper plays in the main producing basins and on high-risk, but more conventional, plays in under-explored frontier areas. This shift brings with it a range of technical and commercial challenges that must be addressed, if exploration in the region is to remain an attractive proposition. Exploration in North Africa and the Middle East has traditionally focused on the prolific Mesozoic- and Cenozoic-sourced petroleum systems of the Nile Delta, the Sirte Basin, the Pelagian Shelf, and the Arabian Plate and on the Palaeozoic-sourced petroleum systems of the Berkine, Ghadames, Illizi, Ahnet and Murzuq basins, the Central Arabian Basin, the Qatar Arch and the Rub Al Khali Basin. Together these form one of the most prolific petroleum provinces in the world and, as a consequence, there has been little commercial incentive to invest in exploring more challenging and riskier plays in these areas. However, as the need to find new reserves becomes imperative, attempts are increasingly being made to test new play concepts and to extend already proven plays into new areas. Key recent developments in this regard include the recognition of the hydrocarbon potential of the Neoproterozoic to Early Cambrian (‘Infracambrian’) sedimentary section lying below the traditionally explored Palaeozoic succession in many basins in North Africa. In some areas, particularly the Berkine Basin in Algeria, the Nile Delta in Egypt and the Rub Al Khali Basin in Saudi Arabia, attention is also increasingly being focused on developing deeper gas plays, both in new areas and beneath existing producing fields. The technical challenges associated with these deeper gas plays are immense and include difficult seismic imaging of deep prospects, low porosity and permeability, high temperature and pressure and a critical need to identify ‘sweet spots’ where either locally preserved primary reservoir characteristics or secondary enhancement of reservoir quality through palaeo-weathering and/or fracturing allow commercial rates of gas production to be achieved. Despite these challenges, it is clear that the future for exploration in many of the more mature basins of North Africa and the Middle East will increasingly lie in evaluating such older and more deeply-buried plays.
Palaeohighs: their influence on the North African Palaeozoic petroleum systems
Authors: Eschard R. , Braik F. , Bekkouche D. , Rahuma M. Ben , Desaubliaux G. , Deschamps R. , Proust J. N. 
Published: May 2011

Abstract
We present new insights for the characterization of the petroleum system evolution in North Africa based on a review of the stratigraphic architecture description of some selected North African Palaeozoic basins. During Palaeozoic time, the Gondwana platform was divided into sub-basins bounded by structural highs. Most of the highs were inherited from north–south and SW–NE Pan-African crustal faults which were reactivated during the Palaeozoic and later, in the Austrian and Alpine tectonic phases. We studied the stratigraphic architecture of the Palaeozoic succession around four main highs showing a clear tectonic activity during the Palaeozoic sedimentation. The Gargaff Arch, in Libya, is a major SW–NE broad anticline which slowly grew up during the Cambrian and Ordovician and stopped rising during the Silurian. The activity resumed during Late Silurian and early Devonian and during the Late Devonian. The Tihemboka High is a north–south anticline in between Libya and Algeria. The uplift started during the Cambro-Ordovician then stopped during most of the Silurian. The activity resumed during the Late Silurian and continued until the Lower Carboniferous. The Ahara High, separating the Illizi and Berkine basins in Algeria, has continuously grown during the Cambro-Ordovician, stopped rising during the Silurian, and grew again continuously during the Devonian. The Bled El-Mass High is a part of the Azzel-Matti Ridge separating the Ahnet and Reggane basins in Algeria. The high mostly rose during the Cambro-Ordovician then subsided relatively less quickly than the surrounding basins during the Silurian and Devonian. The uplift timing and chronology of each palaeohigh partly controlled the petroleum systems of the surrounding basins. Topographic lows favoured the occurrence of anoxic conditions and the preservation of Lower Silurian and Frasnian source rocks. Complex progressive unconformities developed around the palaeohighs form potential complex tectonostratigraphic traps. Finally, hydrocarbons could have been trapped around the highs during pre-Hercynian times, preserving reservoir porosity from early silicification. Mixed stratigraphic–structural plays could then be present today around the highs.
Stratigraphic trapping potential in the Carboniferous of North Africa: developing new play concepts based on integrated outcrop sedimentology and regional sequence stratigraphy (Morocco, Algeria, Libya)
Authors: Lubeseder S. , Redfern J. , Petitpierre L. , Fröhlich S. 
Published: May 2011

Abstract
The lower Carboniferous (Tournaisian to Visean) of North Africa is characterized by cycle-stacks of predominantly shelfal to marginal marine sandstones and limestones, thick shelfal mudstones and less common but important interbedded fluvio-deltaic sandstones. The cyclic sedimentation pattern continues into the Mid Carboniferous (Serpukhovian to Bashkirian), when mixed siliciclastic–carbonate sequences give way to tropical carbonates, before an abrupt return to continental deposits in the upper Carboniferous (Bashkirian to Gzhelian). The alternation of widespread shallow marine and more discrete fluvial reservoirs with interbedded offshore mudstone seals is interpreted to result from high-frequency, high-amplitude Carboniferous glacio-eustatic sea-level changes. The large base-level changes during that time, combined with climatic conditions that produced high amounts of terrigenous mud, provided favourable conditions for the development of stratigraphic traps in the clastic-prone lower Carboniferous, while the advent of tropical carbonates produced reefal buildups in the Mid Carboniferous. Four stratigraphic trapping types are recognized: (1) truncation traps in which reservoir units were eroded on subaerially exposed proximal palaeohighs and thick underlying transgressive and highstand systems tract (TST and HST) mudstones form the bottom-seal and the rapid transgression of the offshore facies forms the top-seal; (2) pinchout traps of lowstand wedges on the flanks of distal palaeohighs, which were only affected by subaqueous reworking of previous TST–HST mudstones and were buried during the subsequent transgression; (3) incised valleys of the lowstand systems tract (LST), filled with thick fluvial and tidal sandstones, cutting either into TST–HST mudstones in the lower Carboniferous, or into exposed carbonate platforms in the Mid Carboniferous; (4) Waulsortian-type reefal buildups of the Mid Carboniferous. The four trapping types are discussed using selected outcrop examples, and are placed into regional sequence stratigraphic context of the Carboniferous depositional systems and sequence development of North Africa. These concepts can be readily applied to the subsurface and offer significant potential for new plays across North Africa.
Biostratigraphy, chemostratigraphy and thermal maturity of the A1-NC198 exploration well in the Kufra Basin, SE Libya
Authors: Lüning S. , Miles N. , Pearce T. , Brooker E. , Barnard P. , Johannson G. , Schäfer S. 
Published: May 2011

Abstract

The A1-NC198 exploration well was drilled in the Kufra Basin in 2007 by RWE Dea and represented only the third well in a large, 400 000 km
2
frontier basin. Despite being dry and lacking any hydrocarbon shows, the well provides important data to improve the understanding of the regional petroleum play. In the 1980s and 1990s the basin's prospectivity was questioned largely because of supposed (1) lack of structuration, (2) lack of source rock and (3) thermal immaturity at Silurian level. Following a series of academic and industry studies over the past 10 years, these assertions can no longer be upheld. The analysis of available seismic has proven the existence of Murzuq-style fault blocks as well as late Ordovician glacial erosional relict buried hills, potentially forming suitable structural and stratigraphic traps. The presence of hot shale in the Kufra Basin is evidenced by typical seismic onlaps of strong amplitude reflectors at base Silurian levels, shallow drilling results and outcrop spectral gamma-ray evidence. A spore colouration study of A1-NC198 cuttings indicates a deep oil window maturity for the Silurian, implying potential oil generation in the basin if suitable Silurian source rocks exist. The stratigraphy of the A1-NC198 succession was analysed by means of biostratigraphy and chemostratigraphy, which form the basis for improved well correlations within the basin.
Exploring subtle exploration plays in the Gulf of Suez
Authors: Dancer P. N. , Collins J. , Beckly A. , Johnson K. , Campbell G. , Mumaw G. , Hepworth B. 
Published: May 2011

Abstract
The Gulf of Suez Basin is a classic extensional rift basin of Miocene age, with a number of syn- and pre-rift hydrocarbon plays. Exploration started in 1886, targeting areas around documented oil seeps, and was highly successful. During the boom in offshore exploration in the 1950s and 1960s, a combination of diligent geology and serendipity resulted in the discovery of a number of giant fields whose reserves form a major part of some 10 billion barrels discovered to date. However, the pursuit of smaller fields, both structural and stratigraphic, has been hampered by the poor quality seismic data characteristic of the basin. The poor quality of the seismic data is due to the interbedded shales and evaporites of shallow post-rift Zeit and South Gharib formations that create massive reverberation and severe attenuation of the seismic signal. Incremental progress in imaging the deeper horizons, including the key pre-rift Nubia Sandstone reservoir, has been achieved through low frequency enhancement and 3D seismic data acquisition. However it is still common for exploration and development wells to miss the Nubia objective due to the poor imaging and consequent misinterpretation of the seismic data. Exploration is now directed towards the smaller targets and subtle plays of the Gulf of Suez. To improve seismic imaging the focus has been on improved acquisition, with 3D ocean-bottom cable seismic data. This has the advantages of reduced multiple energy, higher fold and a broader bandwidth over streamer 3D data. Combined with detailed models of the tectonically controlled sedimentation that characterizes the syn-rift section, this has allowed the development of a re-invigorated exploration programme.
Appraisal and development of the Taq Taq field, Kurdistan region, Iraq
Authors: Garland C. R. , Abalioglu I. , Akca L. , Cassidy A. , Chiffoleau Y. , Godail L. , Grace M. A. S. , Kader H. J. , Khalek F. , Legarre H. , Nazhat H. B. , Sallier B. 
Published: May 2011

Abstract
The Taq Taq Field is located within an anticline in the gently folded zone of the Zagros mountains, northeastern Iraq, approximately 50 km ESE of Erbil. The main reservoirs are fractured limestones and dolomites of Late Cretaceous age, with an oil column exceeding 500 m in thickness. Eocene limestones and dolomites at shallow depth form a subsidiary reservoir. The structure is a gentle thrust-related fold which has also been affected by dextral transpression. A pervasive fracture system is present within the reservoirs, giving good connectivity and deliverability. Initial discovery and appraisal was made in 1978 when three wells were drilled. The recent appraisal programme started in 2005 and by the end of 2008 two seismic surveys had been acquired and eight additional wells had been drilled. Mapping has incorporated a seismic principal component analysis for horizon and lithology identification. Modelling of the fractures has utilized a comprehensive data set derived from core and image logs. Special core analysis has been directed towards the understanding of the pore system and its interaction with the fractures. Synthesis of all these elements is performed in a dual-media dynamic model which is currently in use for development planning.
Sedimentology, geochemistry and hydrocarbon potential of the Late Cretaceous Shiranish Formation in the Euphrates Graben (Syria)
Authors: Ismail S. , Schulz H.-M. , Wilkes H. , Horsfield B. , di Primo R. , Dransfield M. , Nederlof P. , Tomeh R. 
Published: May 2011

Abstract

The Shiranish Formation consists of mudstones and wackestones in the central Euphrates Graben which are rich in organic carbon. Here the Shiranish Formation is more than 700 m thick with a minor increase in organic maturity with depth. The Shiranish Formation sediments are characterized by a continuously increasing hydrogen index to the top whereas the oxygen index is markedly lower in the Upper Shiranish Formation (USF). The Lower Shiranish Formation (LSF) is characterized by lower hydrogen indices and higher oxygen indices relative to the USF. These organic geochemical characteristics enable a rough subdivision into a lower and an upper part of the Shiranish Formation. Furthermore, mineralogical results enable a subdivision of the USF into two parts (USF-1, lower part; USF-2, upper part) each with individual mineralogical signatures due to a modified depositional environment and differing diagenetic history. The LSF resembles mineralogically the USF-2. Ankerite, together with higher pyrite contents in the LSF and USF-2, reflect similar diagenetic pathways which were controlled by higher clay contents. During early diagenesis, a traceable conversion of metabolizable organic matter led to mineral assemblages due to significant methanogenesis. Intervals in the USF with total organic carbon (TOC) contents up to around 4% and hydrogen indexes up to 500 mg HC/g TOC indicate the presence of very good potential source rock intervals for oil generation. Additionally, intervals of the LSF also contain gas-prone organic material. Bulk kinetic investigations show a broad activation energy of the LSF and a narrow activation energy pattern for the USF for hydrocarbon generation. Furthermore, the predicted petroleum formation temperatures are 136°C for the USF and 144°C for the LSF, respectively. This corresponds to
c
. 630 m difference in burial depth for petroleum formation. These differences in activation energies and corresponding depth to reach oil window maturity are controlled by facies, and less by maturity.
Passive margins: overview
Authors: Levell B. , Argent J. , Doré A. G. , Fraser S. 
Published: May 2011

Abstract
Passive margins have been the reliable, accessible mainstay of exploration success worldwide for the last 25 years, and have hosted the spectacularly fast exploitation of deepwater resources (Angola, Nigeria, Brazil, Trinidad, USA Gulf of Mexico, Egypt, Australia and India). Despite, or perhaps because of this, there is still much to learn about the variety of hydrocarbon habitats they present.
For example: (1) deep seismic observations and deep sea drilling have revealed more of the diversity of passive margins geodynamics. This liberates explorationists from simple geodynamic models, with consequences not only for new views of thermal history but also for the whole tectonic and stratigraphic evolution. For example, the time significance assigned to the geometries traditionally labelled ‘pre-rift, syn-rift and sag’ may be misleading. This has implications for correlations, the significance assigned to unconformities and sequence boundaries, heat flow and structural history. (2) New deep imaging of the sedimentary sections has revealed mistaken assumptions about the importance of ‘mobile substrate’ in major deltas and allowed the detailed unravelling of salt and shale movement and its implications for reservoir and trap. (3) Depositional models for deepwater reservoirs have increased in predictive capability and modern seismic imaging supports new models for shallow water sequences. (4) Discoveries of very large amounts of dry bacterial methane in stratigraphic traps have challenged old assumptions about prospectivity based on thermally matured source rocks. (5) New engineering and development technologies are opening up the commercialization of remote frontiers. As a consequence there is legitimate scope to re-visit old ‘dogmas’ and to propose that each passive margin segment is best regarded as unique, with analysis and interpretation rooted in observation rather than models (at least while the newly proposed models evolve to stability). Many of these themes were visited in the Passive Margins session of the Seventh Petroleum Geology Conference, held in London in 2009. This paper outlines some of these ideas, and considers how exploration along passive margins in the next decade can use new geoscience thinking.