Dana Petroleum plc is an oil and gas exploration and production company based in Aberdeen, United Kingdom. Its activities are focused on the North Sea, Africa and The Middle East. It is a subsidiary of the Korea National Oil Corporation and is a former constituent of the FTSE 250 Index. Wikipedia.
News Article | July 7, 2017
ABERDEEN, 07-Jul-2017 — /EuropaWire/ — On 1 July 2016, EnQuest announced a discovery in respect of the recently drilled Eagle exploration well in the Central North Sea. EnQuest asserted that it had drilled the well on a 100% working interest basis. Prior to EnQuest proceeding to drill the Eagle exploration well, Dana had asserted to EnQuest that EnQuest did not have authority to do so. It remains Dana’s position that it has a 50% ownership interest in the Eagle well discovery and it has reserved its rights under the relevant licence, under the Joint Operating Agreement and at law. The company looks forward to the further evaluation of the Eagle results in due course. Dana Petroleum Limited is a wholly owned subsidiary of the Korea National Oil Corporation (KNOC). We are an international oil and gas business with operations in the UK, Egypt, the Netherlands and Africa, producing an average of 50,000 barrels of oil a day. Dana holds 25 operated and 19 non-operated licences in the UK.
Ceraldi T.S.,BP Sunbury |
Hodgkinson R.,Dana Petroleum |
Backe G.,BP Oman
Geological Society Special Publication | Year: 2017
The continental margin of West Africa formed as result of the south-to-north rifting of Gondwana and the progressive separation of the South American and African continents. This margin has enjoyed a rich and varied exploration history and, in the 70 years or so since the first significant exploration began in the onshore area, the margin has emerged as a significant hydrocarbon-producing region. The amalgamation of hydrocarbon exploration approaches and imaginative ideas, leveraged with modern technologies, is yielding significant scientific and economic successes. The main objective of this Special Publication is to provide an overview of the advances in our understanding of the crustal structure, tectonic evolution and Mesozoic to Cenozoic stratigraphy of the West Africa margin both onshore and offshore, with a particular focus on the petroleum geology. The papers contained in this Special Publication represent a selection from the 37 abstracts presented at the original conference in March 2014, which covered the entirety of the margin from South Africa to Morocco as well as stratigraphy from the crystalline basement to the most recent strata. The original abstracts from the conference are available through the Geological Society of London website at: http://www.geolsoc.org.uk/pgresources. © 2017 The Author(s).
Martin-Monge A.,Repsol |
Baudino R.,Repsol |
Gairifo-Ferreira L.M.,Repsol |
Tocco R.,Repsol |
And 13 more authors.
Geological Society Special Publication | Year: 2017
The Taoudeni Basin is the largest sedimentary basin in Africa. This intracratonic basin, which forms the sedimentary cover of the West African Craton, records episodic sedimentation since the Proterozoic. It is a largely unexplored basin, with only eight exploration wells drilled to date, although its petroleum prospectivity was established in 1974 when gas and liquids were tested in the Abolag-1 well. This paper focuses on the identification and assessment of potential source rocks and reservoirs in the Taoudeni Basin in Mauritania and aims to establish a geochemical genetic link between the occurrence of petroleum and potential sources. Various disciplines and techniques were integrated to reach a better understanding of the petroleum systems potentially existing in this basin. We also define and describe the elements and processes of the Atar-Atar (!) petroleum system. This study is an example of the exploration of an unusual and high-risk play in some of the oldest sedimentary rocks on Earth, with a long, polyphase structural evolution, a complex thermal history (where burial might not be the only controlling factor), a massively diagenetized carbonate reservoir, and large uncertainties on the timing of generation, trap formation and preservation. © 2017 The Author(s). Published by The Geological Society of London.
Mohamed A.Y.,University of Aberdeen |
Whiteman A.J.,University of Aberdeen |
Archer S.G.,University of Aberdeen |
Archer S.G.,Dana Petroleum |
Bowden S.A.,University of Aberdeen
Marine and Petroleum Geology | Year: 2016
The thermal history of the Melut rift Basin was studied in a number of wells and along a northeast-southwest cross sectionacross the basin using 1-D and 2-D basin models. Modelling was conducted using PetroMod software to test subsidence, thermal history and their implications for hydrocarbon generation, migration and accumulations. Geotherms were found ranging between 24 and 44 °C/km and average 32 °C/km and present day heat flow was found to vary between 53 and 65 averaging 59 mW/m2. A geologicaly realistic paleoheat flow model with higher heat flow peaks of 75, 70 and 65 mW/m2 during the first, second and third rifting phases respectively, calibrated against vitrinite reflectance data was employed. The model was found sensitive to Cenozoic erosions and a 600 m of exhumation did support the vitrinite data in providing a reasonable fit in most locations. Using the Easy %Ro vitrinite kinetic model for maturity the average present day oil window was found between 1565 and 4050 m in the wells studied and between 1705 and 4200 m along the cross section. Using type-II kerogen for the Aptian-Albian source rocks, the hydrocarbon generation and expulsion were modelled and revealed that the generation started as early as 95 Ma in some areas but significant generation rates were during the second rifting phase and expulsion started at around 85 Ma. Calculations of the probable expelled amounts of hydrocarbon from the northern sub basin are high and up to 2.2 × 1011 bbls of oil and 2.3 × 1014 ft3of gas. Migration of oils from Cretaceous source rocks kitchen to the Cenozoic traps was probably through faults, porous carrier beds and breaching of traps cap rocks. The filling of these traps might be periodic during the rifting episodes and hydrocarbons remigrated from deeper traps to shallow ones. It is possible that thinner and siltier cap rocks along the hydrocarbon migration path, may have allowed gas to scape but holded the oil back. It is most probable that part of the hydrocarbons might have been generated from shallower source rocks areas and a 2-D hybrid Darcy-Flow path model have demonstrated this and predicted a number of accumulations which are similar to the known large discoveries such as Palogue-Fal and Adar-Yale oil fields. © 2016 Elsevier Ltd
Evenstar L.A.,University of Aberdeen |
Hartley A.J.,University of Aberdeen |
Archer S.G.,Dana Petroleum |
Neilson J.E.,University of Aberdeen
Basin Research | Year: 2015
The Salar de Atacama forms one of a series of forearc basins developed along the western flank of the Central Andes. Exposed along the northwest margin of the basin, a salt-cored range, the Cordillera de la Sal, records the Mid-Miocene to recent sedimentological and structural development of this basin. Sediments of the Mid-Miocene Vilama Formation record the complex interaction between regional/local climate change, halokinesis and compressional deformation. This study reveals how these factors have controlled the facies development and distribution within the Salar de Atacama. Detailed sedimentary logging, cross-sections and present day geomorphology through the northern Cordillera de la Sal have been used to establish a lithostratigraphy, chronostratigraphy and the regional distribution of the Vilama Formation. The Vilama Formation documents an increase in aridity with a hiatus in sedimentation from Mid-Miocene to 9 Ma with initial uplift of the Cordillera de la Sal. From 9 Ma to 8.5 Ma deposition of a meandering fluvial system is recorded followed by a rapid decrease in sedimentation till 6 Ma. From 6 to 2 Ma, the deposition of extensive palustrine carbonates and distal alluvial-mudflat-lacustrine demonstrates the existence of an extensive lake within the Salar de Atacama. Post 2 Ma, the lake decreased in size and braided alluvial gravels associated with alluvial fans were widespread through the region suggesting a final shift to hyperarid conditions. By comparing the Vilama Formation with similar age facies throughout northern Chile and southern Peru, several shifts in climate are recognized. Climate signatures within northern Chile appear to be largely diachronous with the last regional event in the Mid-Miocene. Since that time, humid events have been restricted to either Precordillerian basins or the Central Atacama. Within the Central Atacama, the final switch to hyperarid conditions was not till the earliest Pleistocene, much later than previously estimated within the region. © 2015 John Wiley & Sons Ltd, European Association of Geoscientists & Engineers and International Association of Sedimentologists.
Smyth H.R.,HRS GeoLogic Ltd |
Morton A.,CASP |
Morton A.,HM Research Associates |
Richardson N.,Dana Petroleum |
Geological Society Special Publication | Year: 2015
Sediment provenance studies concern the origin, composition, transportation and deposition of detritus, and are therefore an important part of understanding the links between basinal sedimentation, and hinterland tectonics and unroofing. Such studies can add value at many stages of hydrocarbon exploitation, from identifying regional-scale crustal affinities and sediment-dispersal patterns during the earliest stages of exploration to detailed correlation in producing reservoirs and understanding the impact of mineralogy on reservoir diagenesis. This Special Publication records 20 of the papers given at the conference titled 'Sediment Provenance Studies in Hydrocarbon Exploration and Production' organized by the Petroleum Group of the Geological Society of London, and held in London from 5 to 7 December 2011. The observations drawn in this introductory section reflect the volume editors' experience, presentations at the conference and papers within this volume. © The Geological Society of London 2014.
Kneller B.,University of Aberdeen |
Dykstra M.,Colorado School of Mines |
Dykstra M.,Statoil |
Fairweather L.,Dana Petroleum |
Milana J.P.,National University of San Juan
AAPG Bulletin | Year: 2016
Mass-transport events are virtually ubiquitous on the modern continental slope and are also frequent in the stratigraphic record, but the potential they create for stratigraphic trapping within the sea-floor topography is not generally appreciated. Given the abundance of mass-transport deposits (MTDs), we should expect that many turbidite systems are so affected. The MTDs may be very large (volumes > 103 km3 [~250 mi3], areas > 10 km2 [~625O mi2], thicknesses > 102 m [~330 ft]), and they extensively remold sea-floor topography on the continental slope and rise. Turbidity currents are highly sensitive to topography; thus, turbidite reservoir distribution and geometry on the slope and rise are often significantly affected by subjacent MTDs or their slide scars. Tur-bidites may be captured within slide scars and on the trailing edges, margins, and rugose upper surfaces of MTDs; developed in accommodation when the mass movement comes to rest; or subsequently resulting from compaction or creep. The filling of such accommodation depends on the properties of the turbidity currents, their depositional gradient, and how they interact with basin floor topography. The scale of accommodation on top of MTDs is determined largely by the dynamics of the initial mass flow and internal structure of the final deposit, and it typically has a limited range of length scales. We present interpretations of a range of previously published and original case studies to illustrate the range of accommodation styles associated with MTD-related topography within the evacuated space of the slide scar, around and on top of the deposits themselves. In fact, several well-known deep-water outcrops probably represent examples of sedimentation influenced by MTDs. Hydrocarbon reservoirs in many slope settings may be controlled by the accommodation related to MTD topography. At the exploration scale, entire shelf margin and slope depositional systems may be contained within the scars evacuated on the upper slope by mass failure, whereas at the production scale, the rugosity on the top of MTDs creates widespread potential for stratigraphic trapping. The location, geometry, and property distribution of such reservoirs are closely controlled by the interaction of turbidity currents with the topography; thus, an understanding of these processes and their impact on slope stratigraphy is vital to reservoir prediction. © Copyright 2016. The American Association of Petroleum Geologists. All rights reserved.
Contreras A.,Woodside Energy |
Torres-Verdin C.,University of Texas at Austin |
Fasnacht T.,Anadarko Petroleum Co. |
Chesters W.,JPMorgan |
Kvien K.,Dana Petroleum
Leading Edge | Year: 2014
A new algorithm for joint stochastic inversion of well logs and multiple-angle stacks of migrated 3D prestack seismic data is based on a Bayesian statistical search criterion implemented with fast Markov-chain Monte Carlo updates. It enforces a priori measures of spatial correlation as well as geometric structural and stratigraphic embedding. Results consist of spatial distributions of elastic properties with a vertical resolution intermediate between that of seismic-amplitude data and well logs. In addition, the algorithm provides quantitative estimates of nonuniqueness based on statistical distribution of multiple spatial realizations derived from random initial models. It is also possible to estimate lithology and petrophysical properties such as porosity by enforcing multidimensional statistical correlations between elastic and petrophysical properties sampled from well logs. Results are described from the successful application of the inversion algorithm to the high-resolution characterization of hydrocarbon-producing units of a deepwater reservoir in the central Gulf of Mexico. Sensitivity analyses of resolution and non-uniqueness at blind-well locations corroborate the reliable estimation of elastic and petrophysical properties. Estimated distributions of lithology and elastic properties are influenced only marginally by the choice of inversion parameters and the assumed measures of spatial correlation. © 2014 by The Society of Exploration Geophysicists.
Smit R.C.A.,Dana Petroleum |
Salimi H.,Technical University of Delft |
Wolf K.H.A.A.,Technical University of Delft
76th European Association of Geoscientists and Engineers Conference and Exhibition 2014: Experience the Energy - Incorporating SPE EUROPEC 2014 | Year: 2014
Currently, geothermal-energy production is marginally economical. Through optimization of the well positions, the profitability of a project can be improved. This paper studies optimization of the well positions such that the net present value of a project is maximized in a 2D geothermal reservoir for the selected heterogeneity structures. For this purpose, an automated gradient-based optimization method is used. The reservoir simulations are performed using the Finite-Element Method in the program COMSOL Multiphysics. The major features of the simulation results are discussed in detail. It is shown that the effect of heterogeneities on the thermal-retardation factor is small. Furthermore, from an economical standpoint, it makes little sense to assume a doublet lifetime of more than 30 years. A higher heat-recovery factor does not necessarily mean that a doublet is more profitable. There exists an optimum well spacing for doublets such that additional gain of later breakthrough (when placing the production well further away from the injector) is negated by the loss in pressure support of the injection well. Heat production from aquifers can be optimized through the usage of different doublet layouts. It is found that a checkers-board well arrangement is more effective than a tram-rail well arrangement.
Van Der Most M.,Dana Petroleum |
McKellar D.,Dana Petroleum |
Castelein S.,Dana Petroleum
Offshore Engineer | Year: 2012
The article explains how drilling and completing the Dutch North Sea's first intelligent auto-gas lift tri-lateral subsea oil and gas well helped transform the highly marginal Van Ghent discovery into an economically robust development. The Van Ghent exploration well discovered an oil and gas field 4.5km southeast of the existing De Ruyter platform, situated in the southern North Sea on the Dutch continental shelf about 60km west of The Hague in 2008. Medway is being developed using two subsea wells tied back via dedicated flowlines to the existing De Ruyter platform. The Van Ghent and Van Nes discoveries lie 4.5km and 8km respectively from the De Ruyter platform. The development concept comprises two subsea templates tied back via a wye structure to the De Ruyter facilities, which allows for future expansion through possible additional discoveries. Using the full core coverage of the Van Brakel field, the Volpriehausen reservoir was modeled statically and dynamically.