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- Volume 33, Issue 12, 2015
First Break - Volume 33, Issue 12, 2015
Volume 33, Issue 12, 2015
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Delineating thin sand connectivity in a complex fluvial system in Mangala field, India, using high resolution seismic data
Authors Sreedurga Somasundaram, Amlan Das and Sanjay KumarThe Mangala field is located in the northern part of the onshore Barmer Basin in India. The primary reservoir in the field is the Fatehgarh Formation, deposited during the rifting phase that created the Barmer Basin during the Late Cretaceous to Early Paleocene period. The majority of reservoired oil is con¬tained within the Upper FM1 member of the Fatehgarh Formation, composed of single storey and multi-storey stacked, meandering channel sands. The average gross thickness of FM1 is 80 m, and individual sands vary in thickness from 3 to 7 m, with net-to-gross ratio ranging from 18% to 78% due to inherent heterogeneity within FM1 as evident from core data. For such a heterogeneous fluvial system, correlation of fluvial channel sands and flood plain shales poses a major challenge for reservoir characterization when based on well data alone. Detecting or mapping the lateral continuity of these thin fluvial channel sands is difficult because they are below seismic resolution in conventional seismic data. We applied sparse-layer reflectivity inversion (Zhang and Castagna, 2011) to the 3D stack PSTM data, which resulted in a data¬set with improved detectability and resolution. The 7-50 Hz bandwidth of the input seismic data increased to 7-100 Hz through the inversion process. Results were validated using well log and production data. The new data contributed to greater understanding of the lateral connectivity of the FM1 fluvial channel sands, and enabled geobody extraction for reservoir static modelling.
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New reserves in an old field, the Niobrara/ Codell resource plays in the Wattenberg Field, Denver Basin, Colorado
More LessThe Niobrara Formation and Codell Sandstone are one of nine horizons that are productive in the giant Wattenberg Field area (GWA) of Colorado. GWA covers approximately 3200 square miles. The field was discovered in 1970 (J Sandstone) and the first significant Codell production from vertical wells was established in 1981 followed by Niobrara production in 1986. Horizontal Niobrara/Codell drilling began in the field in 2009. Wattenberg straddles the Denver Basin synclinal axis and is regarded as a basin-centre petroleum accumulation. The Niobrara/Codell is overpressured and drilling depths are 6200 to 8200 ft. The Wattenberg area is a ‘hot spot’ or positive temperature anomaly. Temperature gradients range from 16 to 18oF/1000 ft on the edges of the field to about 28 to 29oF/1000ft in high GOR areas. The Niobrara consists of four limestone (chalk) units and three intervening marl intervals. The lower limestone is named the Fort Hays and the overlying units are grouped together as the Smoky Hill member. The chalk units are referred to in descending order as the A, B, C, and Fort Hays. Erosional unconformities exist at the top and base of the Niobrara. The upper unconformity removes the upper chalk bed in some areas of the Wattenberg Field. The B and C chalks are the main focus of horizontal drilling by operators in the field. The underlying Codell Sandstone/Fort Hays is also targeted with horizontal wells. Recent horizontal completions in the Niobrara have initial production of approximately 100 to 700 BOPD with a GOR of 500 to 10,000 cu ft per barrel. Estimated ultimate recovery per well is greater than 300,000 BOE.
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Reservoir quality and stratigraphy of the Mowry and Muddy interval of the Powder River Basin, Wyoming, USA
Interest in the Powder River Basin (PRB) of Wyoming, Northwest USA, has been increasing in recent years, as it is a mature basin with a number of prolific stacked plays, coupled with the promise and opportunity of a few key emerging plays. The Mowry Shale is one of the emerging unconventional plays and has historically been characterized as a key source rock for the underlying Muddy Sandstone and other shallower reservoirs. Both the Mowry Shale and the Muddy Sandstone are considered underex¬plored and to have potentially significant potential. Looking at these two plays in concert, the contrasts between the conventional and unconventional opportunities are clear. Despite its name suggesting otherwise, in its truest form, the Muddy Member is a fluvial estuarine sandstone and, when found, is most often clean and well sorted. The Mowry, on the other hand, is a shallow marine shale, ubiqui¬tous however quite heterogeneous in the basis. Drilling activ¬ity suggests that the industry is struggling to understand the stratigraphic and spatial controls on exploiting the Mowry as an unconventional target. In discussing prospectivity in the Mowry and Muddy interval, a common theme is: ‘We know where the Mowry is but we don’t know where it’s good; we know the Muddy is good but we don’t know where it is.’
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Evidence of early halokinesis in the Zechstein Group suggests the formation of Permian-Triassic carbonates build-ups offshore UK (Quad. 20-21)
Authors Paolo Esestime, Peter Browning-Stamp and Ashleigh HewittThe Upper Permian Zechstein Group comprises sequences of carbonate and evaporites, which extend over most of the onshore areas in North- West Europe, from Britain to Poland, and across the central and southern North Sea, bringing important economic value to hydrocarbon exploration. The nature and distribution of the evaporitic facies are key factors influencing the deposition, thermal evolution and the trap¬ping mechanism in the overburden section, as well as the sealing of the Early Permian-Carboniferous units under¬neath. The Zechstein Group includes source rocks from anoxic shale and microbialites, reservoirs from shallow water carbonate and several levels of seals from anhydrites and halite (Karnin et al., 1992; Cooke-Yarborough 1994; Slowakiewicz et al., 2013). The early salt movements have been tracked back to the Triassic and Jurassic (Glennie and Higham, 2003 and references therein), under different tectonic regimes between the Jurassic-Cretaceous rifting, to the Paleogene inversion, active in the remote foreland of the Alpine Orogeny. The lateral facies distribution has been largely described as a result of different subsidence rates and climatic fluctuation in the Zechstein Basin (Figure 1). Well data confirms the complex architecture of this basin at different scales (Geluk, 2000).
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From Basalt to Skeletons – the 200 million-year history of the Namibian margin uncovered by new seismic data
Authors Ken McDermott, Elisabeth Gillbard and Nicola ClarkeSouth of the prolific Angolan oil provinces and conjugate to the Southern Brasil margin, offshore Namibia could be the area focus for future exploration discoveries. The margin is adjacent to existing markets in South Africa such that hydrocarbon discoveries of significant quantity should prove to be commercial. Exploration offshore Namibia has yet to produce results as the expected potential remains elusive. Campaigns from the 1970s to 2000s have tested variety of plays from near shore shelfal carbonates to deep-water clastics. All exploration phases have approached the margin through the lens of the technologies and trends of the time, but only hydrocarbon discovery is the Kudu gas field discovered in 1973. More recent wells have successfully proven the constituent parts of a working petroleum system; mature source, reservoir, seal and trap; unfortunately the right combination to produce a large discovery and unlock a new petroleum province remains elusive. In order to understand the context of this margin it is important to see how the overall architecture of the Namibian offshore is fundamentally different from the provinces to the north and farther west in Brazil. On the West African margin the Walvis ridge is a significant boundary between the Cretaceous salt basins farther north and the more magmatic and clastic dominated systems further south. Thus, a different set of play concepts are required and are best understood within the regional setting of the margin. In 2014, ION acquired NamibiaSPAN, a 10,400 km survey of deep, long-offset, regional BasinSPAN seismic reflection lines covering the entire offshore Namibian margin from the shallow coastal waters to the abyssal plains (Figure 1). These data were acquired to intersect important wells and cross numerous basins, crustal domains and tectonic fabric. The objective of the survey was to image the full sedimentary and crustal section down to below the Moho. Several BasinSPAN surveys have been acquired across many of the world’s margins and prolific hydrocarbon provinces. This paper presents the PSTM data from the NamibiaSPAN survey. The PSDM data will be avail¬able in November 2015.
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Prospectivity of the Nigeria-São Tomé & Príncipe Joint Development Zone – an integrated geoscience approach
Authors Matthew Tyrrell, Muhammad Tammanai and Sam HosseinzadehThe area of the Joint Development Zone (JDZ), between Nigeria and São Tomé & Príncipe, lies on the southern front of the Niger Delta. The delta is a prolific hydrocarbon-producing region with numer¬ous commercial discoveries of oil, condensate and gas. The JDZ is divided into 11 hydrocarbon exploration blocks that have undergone competitive bid licence rounds; notably in 2004 when nine blocks were offered and a year later when five blocks were offered. To date, eight wells have been drilled within the waters of the JDZ by major international oil companies and all are believed to have encountered hydrocarbons. Obo-1, Obo-2 and Enitimi-1 wells encountered oil and gas whilst Lemba- 1X, Malanza-1X, Oki East-1X, Bomu-1 and Kina-1XR found gas. These eight wells have only targeted structural traps – six of these wells have been drilled on hanging walls of the toe-thrusts, while only two (Obo-1 and -2) have targeted reservoirs within a footwall, encountering oil. In 2002, PGS acquired a 3000 km2 multi-client 3D seismic dataset over the northern part of the JDZ waters; this dataset was then reprocessed in 2007 through a Pre-Stack Time Migration sequence. The seismic survey covers Blocks 1 to 4 (and partially Blocks 5 and 6) covering the eight exploration wells and is situated in water depths of between 1500 and 2300 m.
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Experiments showed no reactions coupled to methane leaked into shallow aquifers
Authors Márton Berta, Anne Becker, Frank Dethlefsen, Markus Ebert, Saskia Koch and Andreas DahmkeThe need for subsurface energy stor¬age to balance the fluctuations in power production using renewable sources already exists, and based on the current deployment rate of wind and solar power stations, scenarios with a renewable share of up to 80% of the German energy production were developed for the next decades (UBA, 2010). Owing to the fluctuat¬ing character of renewable energy production, storage of gases, including compressed air, methane, and hydro¬gen may play a deciding role in the geological energy storage mix (Bauer et al., 2013). In case of a methane storage concept, the gas is generated from surplus renewable electricity via the Sabatier process, stored under¬ground in deep porous reservoirs or salt caverns, and retrieved and used in the existing energy system when needed. Any geological gas storage may result in leakages of the stored gas into shallow geological compart¬ments due to various reasons such as well failure (Evans, 2009). Evaluating hydrogeochemical reactions following such a potential accidental methane leakage into shallow aquifers are of particular importance for ensuring good groundwater quality, especially if the overlying shallow aquifers are used for drinking water production.
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The application of data conditioning, frequency decomposition and RGB colour blending in the Gohta discovery (Barents Sea, Norway)
Authors Syed Fakhar Gilani and Luis Gómez-MartínezGeological Expression workflows, involving data conditioning and frequency decomposition can be used to detect subtle changes within the seismic signal, increase the confidence on the seismic interpretation and de-risk exploration and appraisal wells. This paper looks at the application of these workflows to the Permian carbonates in the Gohta discovery (Barents Sea, Norway) and how the results can help to increase the confidence on the proposed appraisal programme. As a preparation for the rest of the workflow, the data was conditioned using post imaging techniques. The first step involved noise cancellation of the seismic data using structurally oriented and edge-preserving algorithms. An area of poor quality data due to shallow gas clouds was identified to the south of the Gohta structure. In this area, a stronger noise attenuation workflow followed by an amplitude normalisation was applied to increase the reflector continuity. Both noise cancellations were then combined and this noise cancelled dataset was used as an input for the spectral enhancement. Two different spectral enhancements were tested using different methods; one involved the enhancement of the low frequencies using a low-pass high-cut filter, and the other one involved an enhancement of both the low and the high frequencies, aiming for a white spectrum. Frequency decomposition and RGB blending were applied on both enhanced datasets, using two different methods: one involving a short window-based Fast Fourier Transform, and the other one involving an adaptive matching pursuit algorithm. The bright colours observed in the blends were interpreted as an indicator of the presence of oil and gas, while colour changes were interpreted as changes in reservoir thickness, lithology or fluid content. The results of this work supported the presence hydrocarbons on the proposed location of the Gohta appraisal well (7120/1- 4 S), which was drilled in 2014 and encountered gas but the testing in the oil zone was inconclusive because of the technical problem of isolating gas flow from the oil zone, proving the validity of this technique as a DHI.
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Volumes & issues
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Volume 42 (2024)
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Volume 41 (2023)
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Volume 40 (2022)
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Volume 39 (2021)
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Volume 38 (2020)
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Volume 37 (2019)
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Volume 36 (2018)
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Volume 35 (2017)
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Volume 34 (2016)
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Volume 33 (2015)
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Volume 32 (2014)
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Volume 31 (2013)
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Volume 30 (2012)
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Volume 29 (2011)
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Volume 28 (2010)
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Volume 27 (2009)
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Volume 26 (2008)
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Volume 25 (2007)
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Volume 24 (2006)
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Volume 23 (2005)
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Volume 22 (2004)
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Volume 21 (2003)
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Volume 20 (2002)
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Volume 19 (2001)
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Volume 18 (2000)
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Volume 17 (1999)
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Volume 16 (1998)
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Volume 15 (1997)
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Volume 14 (1996)
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Volume 13 (1995)
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Volume 12 (1994)
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Volume 11 (1993)
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Volume 10 (1992)
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Volume 9 (1991)
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Volume 8 (1990)
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Volume 7 (1989)
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Volume 6 (1988)
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Volume 5 (1987)
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Volume 4 (1986)
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Volume 3 (1985)
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Volume 2 (1984)
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Volume 1 (1983)