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- Volume 11, Issue 1, 2005
Petroleum Geoscience - Volume 11, Issue 1, 2005
Volume 11, Issue 1, 2005
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Reservoir challenges of heterolithic tidal sandstone reservoirs in the Halten Terrace, mid-Norway
Authors A. W. Martinius, P. S. Ringrose, C. Brostrøm, C. Elfenbein, A. Næss and J. E. RingåsProduction from the Halten Terrace hydrocarbon province (Mid-Norwegian shelf) is mainly from heterolithic siliciclastic successions as well as diagenetically altered sandstones. Eight hydrocarbon fields are currently in production, which produce c. 840 000 BBL oil equivalent per day, with several new fields expected to come on stream in the next decade. This paper is an introduction to a thematic set on the characterization and modelling of heterolithic reservoirs and focuses on the three main types of heterogeneity: (1) heterolithic facies, (2) faulting and (3) diagenesis. Challenges vary according to field setting: shallow (1–3 km burial depth), deep (3–5 km) or very deep (currently up to 5.6 km). Water depths vary from 200 m to 500 m. Heterolithic sedimentary packages are composed of shale or siltstone layers intercalated with clean, but often thin, sandstone layers of varying lateral extent. These were deposited in Lower Jurassic tide-influenced or tide-dominated deltaic and estuarine environments along the margin of a shallow seaway. Hydrocarbon traps are formed by faulted and rotated fault blocks created during rifting. Faulting of these heterolithic facies is a critical parameter for fluid flow, with fault transmissibility and fault position often difficult to determine. Complex patterns of diagenetic cementation are an additional aspect of heterogeneity in the deeply buried reservoirs, such as the Smørbukk and Kristin fields. However, grain coatings of chlorite, illite/chlorite and illite have prevented or hindered the development of quartz overgrowths and allowed the preservation of anomalously high porosity and permeability. Modelling and assessing the impact of these reservoir uncertainties has included development of novel tools and methods, leading to a much-improved level of understanding, better prediction of recoverable reserves and significantly increased recovery factors.
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Petrophysical characterization of a heterolithic tidal reservoir interval using a process-based modelling tool
Authors Kjetil Nordahl, Philip S. Ringrose and Renjun WenHeterolithic lithofacies in the Jurassic Tilje Formation, offshore mid-Norway, consist of three components – sand, silt and mud intercalated at the centimetre scale – and are generally difficult to characterize petrophysically with core and wireline data. A near-wellbore model of the lower part of the Tilje Formation in the Heidrun Field is constructed to illustrate the application of these results to formation evaluation studies. The sedimentological model is developed by detailed parameterization of a cored well interval and the petrophysical properties are based on core plug data, taking into account sampling bias and length scale. The variation in petrophysical properties as a function of sample volume is examined by calculating the representative elementary volume. The sensitivity of the representative permeability values to the contrast between the three components is studied and gives a better understanding of the flow behaviour of this system. These results are used to rescale the core plug data to a representative value and thereby quantify the uncertainty associated with the wireline-based estimates of porosity and horizontal permeability and to give an improved estimate of the k v/k h ratio.
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Vertical permeability estimation in heterolithic tidal deltaic sandstones
Authors Philip Ringrose, Kjetil Nordahl and Renjun WenA method for estimation of vertical permeability in heterolithic tidal deltaic sandstones is proposed. Three-dimensional, stochastic, process-based models of sedimentary bedding are used to give estimates for the effective permeability of heterolithic tidal sandstone units where heterogeneities in the sandstone and mudstone components are evaluated explicitly.
Subsurface core (probe permeameter) data from two contrasting reservoir intervals in the Tilje Formation, offshore mid-Norway, have been used to derive representative petrophysical properties for the models. These data illustrate the nature of petrophysical variability in heterolithic sandstones and provide estimates of the mean and standard deviation of sandstone permeability at the lamina scale. The coefficient of variation, C v, for permeability within sandstone beds is found to be around 0.5 while the C v for heterolithic units is in the range of 1.0 to 4.0 (i.e. very heterogeneous). Measurement of mudstone permeability is a challenge; however, a limited set of mudstone (pulse-decay) measurements gives values in the range of 10−6 mD to 10−2 mD.
Effective vertical permeability is mainly a function of mudstone fraction with different characteristics above and below the percolation threshold. Vertical permeability functions have been integrated with conventional well logs and compared with available subsurface estimates for vertical permeability.
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Reservoir modelling and simulation of Lajas Formation outcrops (Argentina) to constrain tidal reservoirs of the Halten Terrace (Norway)
Authors Inge Brandsæter, Duncan McIlroy, Oddvar Lia, Philip Ringrose and Arve NæssThree-dimensional geological modelling and reservoir simulations of an outcrop analogue to reservoirs of the Halten Terrace, offshore mid-Norway, are presented. The model of the outcrop incorporates (a) a detailed sedimentological understanding, (b) a set of stochastic realizations highly-constrained to the geological models and (c) streamline waterflood flow simulations assuming typical subsurface petrophysical properties from the Halten Terrace. Statistical analysis of simulation results has been used to show the importance of both the facies architecture and the spatial petrophysical model. The outcrop model has significantly improved the estimation of facies dimensions and architecture and gives a valuable insight into understanding petroleum reservoirs of the Halten Terrace.
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Characterization of deeply buried heterolithic tidal reservoirs in the Smørbukk Field using inverted post-stack seismic acoustic impedance
Authors L. Klefstad, S. Kvarsvik, J. E. Ringås, J. J. Stene and O. SundsbyDeeply buried reservoirs in Smørbukk Field play an important role in oil production from the Halten Terrace hydrocarbon province (Mid-Norwegian shelf). These heterolithic reservoir sandstones are sedimentary systems for which estimation of reservoir properties is challenging. The main problem is to derive realistic models of the lateral changes of porosities and permeabilities in the inter-well space. There is a very significant upside potential in producible reserves if infill production wells can be placed and completed in an optimal position with respect to reservoir quality.
In this paper reservoir characterization work, based on good quality seismic data, has been performed in order to predict porosity, net: gross ratio and permeability both qualitatively and quantitatively supported by reliable geological models. Essentially, Acoustic Impedance (AI) is correlated to porosity and inverted seismic data have been used to predict reservoir properties. Two different porosity modelling methods in the Tilje Formation are used: (1) by means of simple regression; (2) using geostatistical methods.
Lateral changes in porosity follow a pattern that is sedimentologically plausible. A geostatistical workflow resulted in porosity maps that take into account both lack of vertical resolution in seismic data and poor lateral resolution in well data. This is considered to be the most optimal method for predicting geologically acceptable reservoir properties, because uncertainties in porosity modelling are measured. Porosity maps were used to update the reservoir simulation model and adjust targets for infill wells in the Smørbukk Field. Results were tested in two wells drilled after utilizing the seismic AI and showed an excellent match.
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A 3D stochastic model integrating depth, fault and property uncertainty for planning robust wells, Njord Field, offshore Norway
Authors Jan C. Rivenæs, Cecilie Otterlei, Eli Zachariassen, Chris Dart and Jorunn SjøholmThe Njord Field, situated in the Haltenbanken area, is one of the most challenging reservoirs on the Norwegian shelf. The structural complexity is high, with numerous intersecting faults compartmentalizing the reservoir. The reservoir is dominated by alternating shale and sand intervals of tidal, estuarine and deltaic depositional origin.
One of the main segments on Njord – the Central Area – was the target for a one-year improved oil recovery study. The Central Area reservoir is produced by depletion, with a current recovery factor of only 6%, as most faults appear to seal during production. The previous drilling experience revealed quite large uncertainty with respect to both depth and missing faults due to poor seismic data quality.
In order to plan further wells in this area a model that comprises the full uncertainty with respect to both structural components (depth uncertainty and faults) and property components (facies, permeability, porosity) was made. The model was built by combining commercial modelling software (IRAP RMS and STORM:HORIZON) with an R&D tool (HAVANA) in a manner that has not been attempted previously, and 200 stochastic realizations were run. Each realization has a different structural 3D grid (depth and fault pattern) and different petrophysical properties. A streamline simulator in IRAP RMS was applied to rank the realizations and ten realizations were chosen for further well screening in the flow simulator (ECLIPSE). The model was applied to propose two new well targets that were robust economically (given all uncertainty). In addition, the model was applied in testing various unconventional well types, for example so-called ‘connector-wells’, which are open holes in the reservoir (but not connected to the surface), in order to connect fault blocks bounded by sealing faults.
Drilling and subsequent seismic interpretation after the model had been built revealed that the structural uncertainty was even greater than predicted. It is crucial to capture the full interpretation uncertainty and, in particular, to address the problem of jump-correlation across fault blocks. Despite this, however, the observed cumulative production from the new oil producer compares well with the prognosis from the model.
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Mathematical models of the distribution of geotracers during oil migration and accumulation
Authors Yunlai Yang, Andrew C. Aplin and Steve R. LarterCompounds which partition into water and which are adsorbed by solid phases (‘geotracers’) are lost from petroleum along migration pathways, giving important clues about the nature and length of the route from source to reservoir. Many factors influence the distribution of petroleum geotracers, including migration distance, the inherent properties of the migration systems, the chemical properties of the tracers, the volume of reservoired oil and the filling sequence. This paper constructs the mathematical models that are required to describe adequately the occurrence of geotracers in migrated and reservoired oils. The models show that for commonly used geotracers (phenol and carbazole compounds): (1) adsorption to oil-wet mineral sites is a major process removing geotracers from oil; (2) adsorption onto mineral surfaces can be treated as an equilibrium process on a geological time-scale; (3) diffusion of tracers from a migrating oil slug to the surrounding sediments can be neglected; and (4) the tracer concentration in a reservoired oil is not related uniquely to migration distance but is negatively correlated to the ratio of relative migration distance divided by the volume of reservoired oil having travelled the migration pathway. The potential applications of the models in petroleum exploration include: assessment of the route and relative distance of oil migration (with implications for the identification of undrilled prospects); estimation of the volume of lost oil by spill from a reservoir; and differentiation of migration through fractures and capillary migration through fine-grained rocks.
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Quantification of exhumation in the Eromanga Basin and its implications for hydrocarbon exploration
Authors Angelos Mavromatidis and Richard HillisExhumation in the Eromanga Basin of South Australia and Queensland has been quantified using compaction methodology. All methods of estimating exhumation utilize rock properties that are affected by, and retain a memory of, burial in excess of that presently observed. The tool used for estimating the exhumation in this study is analysis of the degree of overcompaction of rock units. Since porosity describes compaction state, the sonic log, controlled strongly by the amount of porosity, is an appropriate indicator of compaction and, hence, is used for quantifying exhumation from compaction. The standard method of estimating exhumation based on the degree of overcompaction of a single shale unit has been modified, and seven units, predominantly shales ranging in age from the Cretaceous to the Jurassic, have been analysed. All units yield similar results. Burial at depth greater than currently observed is the most likely cause of overcompaction since it is unlikely that sedimentological and/or diagenetic processes are responsible for similar amounts of overcompaction in different lithologies. The results of the compaction analysis reveal that Late Cretaceous–Tertiary exhumation increases eastwards from the Patchawarra Trough, through the Gidgealpa–Merrimelia–Innamincka Trend and Nappamerri Trough into the Queensland sector of the basins. This study has major implications for hydrocarbon exploration. Predicted maturation of source rocks will be greater for any given geothermal history if exhumation is incorporated in maturation modelling. The exhumation study helps to quantify velocity anomalies associated with overcompaction. Exhumation values can also be used to improve porosity predictions of reservoir units in undrilled targets.
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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)