bluuebunny/crossref_metadata_2025 huggingface dataset:
Sonic velocity and grain contact properties in reservoir sandstones
Authors: Storvoll Vidar , Bjørlykke Knut
Published: October 2008

The purpose of this study was to examine the effect of grain contacts and quartz cementation with regard to acoustic wave propagation in sandstones. Grain contacts have been considered essential when relating acoustic velocities to physical rock properties, and a parameter numerically representing the contact area between individual grains (contact length) has been measured. The method used involves digital petrographic microscopy pictures analysed by image analysis software. Other parameters, such as grain size, number of grain-to-grain contacts, cracks, clay content and porosity, have also been closely examined. The results showed that the contact area between sand grains may be useful for explaining velocity variations during the initial stages of quartz cementation and grain framework stiffening. Continued increase in grain-contact area by chemical compaction will have less influence on the sonic velocity compared to variations in porosity. The Garn Fm. from the Norne Field (2.6–2.7 km burial depth), which is in the early phase of initial grain framework stiffening by quartz cementation, and the Garn Fm. from the Kristin Field (4.6–4.7 km burial depth), which is thoroughly quartz cemented, were chosen as sample materials. Log-derived velocities, in addition to some laboratory ultrasonic velocity measurements, were used in this study.
Seismic evidence for gas hydrates in the North Makassar Basin, Indonesia
Authors: Jackson B. A.
Published: October 2008

This paper describes the distribution, seismic characteristics and potential volume of gas hydrates in the eastern part of the North Makassar Basin, Indonesia. Identification of the gas hydrates depends entirely on the presence of extensive bottom simulating reflectors (BSR) which are distributed primarily within the offshore extension of the West Sulawesi Fold Belt. Turbidite deposition within the fold belt mini-basins provides a reservoir and a source of organic material for the production of biogenic methane gas. Several seismic examples are shown, including a suspected palaeo-BSR on the crest of an eroded anticline, a submarine mud volcano and an occurrence of rotated slump blocks and debris flows that glide along the hydrate/free gas interface.

Geothermal gradients derived from the BSR database averaged 4.7°C/100 m, whilst derived heat flow values varied from 20 mW m
−2
to 60 mW m
−2
, comparing favourably with regional heat flow data. Gas-in-place estimations for the most contiguous accumulation of gas hydrates (
c
. 8000 km
2
) yielded an estimated 1.89×10
12
 m
3
(67×10
12
 SCF) of methane gas. Free gas in place below the hydrate zone within the same area was estimated to be 379×10
9
 m
3
(13×10
12
 SCF).
Vertical permeability estimation in heterolithic tidal deltaic sandstones
Authors: Ringrose Philip , Nordahl Kjetil , Wen Renjun
Published: October 2008

A 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.
Mapping and characterization of thin chalk reservoirs using data integration: the Kraka Field, Danish North Sea
Authors: Klinkby Lone , Kristensen Lars , Nielsen Erik B. , Zinck-Jørgensen Kim , Stemmerik Lars
Published: October 2008

The integration of 3D seismic data, well logs and synthetic seismic data has been used to identify an additional Intra Danian seismic horizon in the chalk reservoir of the Kraka Field, Danish North Sea. Mapping of this seismic horizon has allowed production of a separate thickness map for the main reservoir unit, the Danian Porous, in the greater Kraka area. The unit is less than 25 m thick in most areas and, to produce reliable reservoir maps, it has been necessary to use well data to guide the seismic interpretation. It is impossible, however, to resolve the reservoir stratigraphy properly in areas where the Danian Porous is thinner than
c.
15 m due to tuning effects.

The lateral porosity distribution has been mapped using a combination of well log data and seismic data inverted for acoustic impedance. The Danian Porous unit is characterized by average porosities over 28% and shows no evidence of depth-related porosity reduction. Rather, the impedance data indicate the presence of positive porosity anomalies both over the crest and downflank towards the southeast. Comparison of impedance-derived porosities with those derived from well data indicates that the seismic-based data reflect the variations in porosity but underestimate the highest porosity by 3–4%.

Faults and fractures are important for production of the Kraka Field. Detailed mapping of seismic horizons, supplemented with seismic attribute mapping, has proved useful for outlining areas with high fault intensity in the northwestern part of the field but has been unsuccessful in identifying individual faults as recognized from log data.
Geothermal regime and hydrocarbon generation in the Albanides
Authors: Frashëri Alfred
Published: October 2008

Following a summary of the geological structure of the Albanides and of the oil and gas reservoirs in Albania, the parameters controlling the distribution of the present-day geothermal field are analysed in detail: temperature, geothermal gradient and heat flow density in the centre of the Albanian Sedimentary Basin. The paper analyses the palaeothermal regime of the External Albanides for the Upper Triassic–Eocene carbonates and the Middle–Upper Miocene and Pliocene molasse. It looks in detail at the burial and thermal history of the External Albanides and discusses the implications for hydrocarbon generation.
Hydrocarbon potential of the Karapinaryaylasi Formation (Paleocene–Eocene) source rock in the Tuz Gölü Basin, central Anatolia, Turkey
Authors: Ayyıldız Turhan
Published: October 2008

In the Tuz Gölü Basin (central Anatolia), the Karapinaryaylasi Formation (Paleocene–Eocene) is represented by shale and sandstone alternation, conglomerates and lensoid limestones. The total organic carbon (TOC) results from most outcrops and the Karapinar-2A well samples show less than 0.50 wt%, and the hydrogen index (HI) and genetic potential values are very low. In the Aktas-1A, Aksaray-1 and Sultanhani-1 wells, the TOC content is generally lower than 0.5 wt% but can reach up to 1.50 wt%. Rock-Eval pyrolysis indicates that some intervals within the Karapinaryaylasi Formation possess good gas potential, with a total yield of up to 4268 ppm. The Paleocene–Eocene rocks are thermally immature to marginally mature with respect to
T
max
, ranging from 420°C to 458°C, while vitrinite reflectance and spore colour index values range from 0.50% R
o
to 0.88% R
o
and 4 to 8(?), respectively. Microscopic investigations and the HI vs. oxygen index (OI) and HI vs.
T
max
diagrams show that the samples contain Type III and Type II kerogen, which is often oxidized, together with reworked material. Gas chromatography and gas chromatography–mass spectrometry analysis results support these conclusions. Consideration of all the data indicates that the Karapinaryaylasi Formation (Paleocene–Eocene) could be the source rock for gas production in the Tuz Gölü Basin.
Effects of hydrocarbon generation, basal heat flow and sediment compaction on overpressure development: a numerical study
Authors: Hansom Jennifer , Lee Ming-Kuo
Published: October 2008

This study outlines numerical experiments to investigate the effects of hydrocarbon generation, basal heat flow and sediment compaction on overpressure development in evolving sedimentary basins. The model integrates predicted groundwater flow and temperature and pressure distribution with thermal maturation simulations. The programme uses the Arrhenius kinetic model to simulate the kerogen–oil or oil–gas conversion processes. Such conversion processes result in an increase in fluid volume and overpressure development since oil and gas generated are less dense than their precursors. The model integrates an equation of state to calculate gas densities for the CH
4
–CO
2
–H
2
O system over a wide temperature–pressure (T–P) range expected in sedimentary basins; this approach allows for prediction of the rate of pore volume increases and fluid pressure changes due to gas generation. Sample calculations of compaction of kerogen-rich shales in the Delaware Basin shed light on the magnitudes of overpressures created by hydrocarbon generation from the Late Pennsylvanian to Middle Permian. Oil generation can cause excess pore pressure (
c
. 425 atm) up to
c
. 40% of that generated by compaction only (
c
. 300 atm). Oil and CH
4
gas generation together yield the maximum excess pressure (
c
. 750 atm) up to about 150% of that generated by compaction only. There is much greater pore pressure build-up from oil to CH
4
conversion (
c
. 325 atm) than oil to CO
2
conversion (
c
. 75 atm) because density of CH
4
gas is less than that of CO
2
under the same P and T conditions. Sensitivity analyses also show that lower activation energy and higher pre-exponential factor lead to faster thermal cracking that allows oil or gas to reach peak generation earlier. Moreover, a basin experiencing a high heat flow throughout the burial history reaches hydrocarbon generation and overpressure development earlier. Calculation results also show that the oil and gas windows become deeper as the sedimentation rate increases. Thus, a basin experiencing high sedimentation rates would exhibit higher levels of thermal maturity and excess pore pressure over the deeper section. This also implies that greater overpressure may be expected at shallower depths in a basin with relatively low sedimentation rates. The modelling results demonstrate that kinetic parameters, basal heat flow and sedimentation rates all influence the timing, duration and depth of oil and gas generation, which in turn, profoundly affects the spatial and temporal distribution of overpressure.
Rock physics modelling of shale diagenesis
Authors: Dræge Anders , Jakobsen Morten , Johansen Tor Arne
Published: October 2008

A model for estimating the effective anisotropic properties of cemented shales is presented. The model is based on two mathematical methods for estimation of effective properties of a composite medium; a self-consistent approximation and a differential effective medium model. In combination these theories allow approximation of a shale with connected clay minerals and cement, and disconnected pores and quartz grains, which can be compared with the conditions in a real cemented shale. A strategy is also presented for estimation of stiffnesses in the transition zone from mechanical compaction to chemical compaction dominated diagenesis. Combining these theories with a shale compaction theory, enables modelling of the effective elastic stiffnesses for shales from deposition and mechanical compaction to deep burial and chemical compaction/cementing. Results from the model were compared with velocity data from three wells, showing good fit for velocity predictions, following the main velocity trends with increased temperature and depth.
Maturity and source-rock potential of Palaeozoic sediments in the NW European Northern Permian Basin
Authors: Pedersen Jon H. , Karlsen Dag A. , Lie Jan E. , Brunstad Harald , di Primio Rolando
Published: October 2008

The Northern Permian Basin is located in the offshore area SSW of Norway, NNW of Denmark and east of Scotland. This basin is filled mainly by Lower Permian aeolian desert sediments and volcanics, plus Upper Permian evaporitic sediments. The aeolian sandstone is an excellent reservoir rock and is generally capped by thick layers of salt that potentially form a tight cap rock. The highest risk in the petroleum exploration of the Palaeozoic Northern Permian Basin is linked to the presence of source rocks. Palaeozoic source-rock candidates in the Northern Permian Basin area may be present among Lower Palaeozoic marine sediments, within Devonian–Carboniferous lacustrine/deltaic pre- and syn-rift sediments and as Permian marine shales. This study investigates Lower Palaeozoic marine shales, lacustrine Devonian mudstones, Carboniferous mudstones and coals and marine Permian shales in order to assess the thermal maturity, source-rock potential and distribution of Palaeozoic sediments in the Northern Permian Basin region. The majority of the investigated samples were within the oil window in terms of thermal maturity. Lower Palaeozoic marine sediments may have generated both oil and gas, while Upper Palaeozoic coals and mudstones are dominantly gas-prone source rocks. Middle Permian marine shales (Kupferschiefer) are a good oil-prone source rock. Generation and expulsion of hydrocarbons from Lower Palaeozoic source rocks in the eastern parts of the Northern Permian Basin probably began in the Upper Silurian, with peak oil generation in Carboniferous times. Upper Palaeozoic rocks in the same area matured rapidly in Early Triassic times. The likely presence of multiple Palaeozoic source rocks suggests that hydrocarbons were generated in the Northern Permian Basin.
Sequence stratigraphically controlled diagenesis governs reservoir quality in the carbonate Dehluran Field, southwest Iran
Authors: Taghavi Ali Asghar , Mørk Atle , Emadi Mohammad Ali
Published: October 2008

The Sarvak Formation (late Albian–early Turonian) is one of the major oil and gas reservoir units in southwestern Iran and was deposited in a wide carbonate ramp marine setting. Three major transgressive–regressive sequences are interpreted in the upper part of the Sarvak Formation in the Dehluran Field. Sequence boundaries are recognized from facies shifts and diagenetic effects related to sea-level fall, whereas maximum flooding episodes are indicated by deep-water facies characterized by abundant bioturbation and high gamma-ray log responses.

Diagenesis is the main controlling factor on reservoir quality and plays both a constructive and a destructive role. Permeability is decreased by cementation, which fills primary porosity and disconnects pore throats, while compaction decreases porosity by establishing tighter intergrain contacts. Conversely, the dissolution of unstable minerals (mainly aragonite) is the major process that improves porosity and then permeability by enlarging pores and pore throats. Dolomitization, when associated with dissolution, creates the best reservoir intervals in the Sarvak Formation, although this is not a widespread phenomenon.

These diagenetic processes are controlled by sea-level fluctuations, and thus the sequence stratigraphic development. Dissolution, early cementation and exposure-related dolomitization took place during falling sea-levels, mainly in the uppermost, regressive parts of the major sequences. Dolomitization is recognized in the transgressive and in the regressive systems tracts. Stylolitization and fracturing are independent of sea-level fluctuations and are most likely to have formed through a combination of compaction and tectonic events.
The Aquitaine Basin
Authors: Biteau Jean-Jacques , Le Marrec Alain , Le Vot Michel , Masset Jean-Marie
Published: October 2008

The Aquitaine Basin is located in the southwest of France, between the Gironde Arch in the north and the Pyrenean Mountain Chain in the south. It is a triangular-shaped domain, extending over 35 000 km
2
. From north to south, six main geological provinces can be identified: (1) the Medoc Platform located south of the Gironde Arch; (2) the Parentis sub-basin; (3) the Landes Saddle; (4) the North Aquitaine Platform; (5) the foreland of the Pyrenees (also known as the Adour, Arzacq and Comminges sub-basins); and (6) the Pyrenean fold-and-thrust belt. Only the Parentis sub-basin, the foreland of the Pyrenean Chain and a minor part of the fold-and-thrust belt itself are proven hydrocarbon provinces.

The Aquitaine Basin, in turn, is subdivided into four sub-basins – the Parentis, Adour–Arzacq, Tarbes and Comminges areas. The lozenge shape of these depocentres is related to the Hercynian tectonic framework of the Palaeozoic basement, reactivated during Early Cretaceous rifting. This rift phase aborted at the end of the Albian (prior to the development of an oceanic crust) in response to the beginning of the subduction of the Iberian plate under the European plate. During the Upper Cretaceous, continued subduction led to the creation of northwards-migrating flexural basins. In the Eocene, a paroxysmal phase of compression was responsible for the uplift of the Pyrenean Mountain Chain and for the thin-skinned deformation of the foreland basin. The resulting structuration is limited to the south by the internal core of the chain and to the north by the leading edge of the fold-and-thrust belt, where the Lacq and Meillon gas fields are located.

Four main petroleum provinces have been exploited since the Second World War: (1) the oil-prone Parentis sub-basin and (2) salt ridges surrounding the Arzacq and Tarbes sub-basins; and (3) the gas-prone southern Arzacq sub-basin (including the external Pyrenean fold-and-thrust belt and the proximal foreland sub-basin) and (4) Comminges sub-basin. Two major distinct vertically drained petroleum systems (PS) can be identified: the Upper Kimmeridgian–Barremian is the main PS, based on Type II shaly-carbonate source rocks; and the Lias PS based on Type II–III source rocks. The latter is restricted to the Comminges and Tarbes sub-basins. Reservoirs consist of fractured and diagenetically modified carbonates, and clastics. Shaly-marly deposits of regional extent associated with transgressive systems provide the main seals.

Formation of petroleum traps results from a complex polyphase geodynamic evolution. They are developed mainly along Palaeozoic inherited palaeostructures. Oil and gas migration took place from Albian times up to the present, depending on the respective structural position and histories of the traps. These petroleum provinces of the Aquitaine Basin have been exploited since 1939 and a total of 11.5×10
12
SCF of gas and 470×10
6
BBL oil recoverable reserves have been proven to date (the total amount is in the order of 2.5×10
9
BOE).
Modelling the effects of stratigraphical uncertainty on fault seal and trap-fill in faulted structures
Authors: Clarke S. M. , Littler M. , Burley S. D. , Williams G. D. , Hughes D. , Coogan S.
Published: October 2008

A three-dimensional approach to migration modelling through faulted structures is described that allows the effects of stratigraphical uncertainty on potential hydrocarbon accumulations to be assessed. Deterministic, three-dimensional fault seal analysis typically produces results that are extremely sensitive to input parameters such as structural architecture and stratigraphical variation. These parameters can be amongst the most poorly defined of modelling inputs because subsurface structural detail and stratigraphical variation are often below the limit of seismic resolution and are not sampled by well data.

The new technique is fully integrated with three-dimensional fault seal analysis and hydrocarbon flow pathway modelling to give a workflow that predicts the likelihood of fault-controlled hydrocarbon accumulations, given these uncertainties. Multiple deterministic realizations of the model are used to highlight specific uncertainties in stratigraphy to which predicted hydrocarbon accumulations are sensitive. The results of these realizations are incorporated into, and used to condition, a stochastic model to risk predicted accumulations based on their likelihood of occurrence and volume.

This technique has many advantages over either purely deterministic or purely stochastic approaches. A single deterministic realization places over-optimistic faith in the accuracy of the geological model because of the high sensitivity of fault seal analysis to input parameters. Multiple realizations allow specific input parameter uncertainties to be investigated, and the resulting common traps can be considered low risk, but accumulations exclusive to individual realizations cannot be risked. Moreover, a purely stochastic simulation based on all uncertainties will, at best, reduce efficiency by modelling uncertainties to which the result is insensitive or, at worst, may bias results with geologically implausible, stochastically-generated trials.
Stratigraphy, structure and petroleum potential of the Lady Franklin and Maniitsoq Basins, offshore southern West Greenland
Authors: Sørensen Aage Bach
Published: October 2008

The Lady Franklin Basin, which contains a thick succession of Cretaceous and Cenozoic sediments, constitutes the western part of the southern West Greenland offshore area. In the Davis Strait and Labrador Sea region rifting was initiated in the earliest Cretaceous and a number of basins formed. In time these basins deepened, although subsidence was interrupted by two main phases of uplift and erosion that took place in middle and late Cretaceous time, resulting in two hiatuses in the succession. Sediments with source or reservoir potential were deposited in the basins. Source rocks are known to occur in the marine Cretaceous successions of onshore northern Canada and central West Greenland and also offshore eastern Canada, and can therefore be expected to occur in the Lady Franklin and Maniitsoq basins.

In the Lady Franklin area Paleocene volcanism associated with further tectonism caused the eruption of flood basalts and hyaloclastites on top of the Cretaceous mudstone and sandstone succession. A Lower Palaeogene sediment succession, which may contain both source and reservoir rocks, was then deposited on top of the basalts, as seen in the nearby Canadian Hekja O-71 well. Around the Ypresian to Lutetian transition a regression took place. The regression gave rise to an unconformity and a hiatus spanning a few million years throughout the entire West Greenland shelf. New deposition followed and, after a long period, major compression set in and a regression occurred across the whole shelf in Late Oligocene time. Erosion set in and was deep on the southern shelf, resulting in a hiatus spanning about 39 Ma. To the north the hiatus is only about 19 Ma.

In early Middle Miocene time the tectonic regime in the Davis Strait area changed. Subsidence and deposition resumed offshore West Greenland. These events may have created conditions for generation of hydrocarbons in the potential source-rock sequences in the Cretaceous succession. Therefore, although hydrocarbon exploration has been limited in this region and had little success, it is thought that conditions are favourable for the discovery of significant oil and gas accumulations.
Contribution of research borehole data to modelling fine-grained turbidite reservoir analogues, Permian Tanqua–Karoo basin-floor fans (South Africa)
Authors: Luthi Stefan M. , Hodgson David M. , Geel Cees R. , Flint Stephen S. , Goedbloed Jan Willem , Drinkwater Nicholas J. , Johannessen Erik P.
Published: October 2008

Outcrop analogue studies can be augmented and constrained by drilling research wells through the same stratigraphic interval. Close-to-outcrop wells help to validate outcrop observations with well log and core data and thus improve the use of such data in actual field developments. Research wells located further away from the outcrops increase the spatial data coverage and can give important insight into regional facies distributions and net:gross changes.

In the Tanqua–Karoo Basin (South Africa), seven wells were drilled into fine-grained sand-rich basin-floor fans and interfan mudstones to supplement outcrop data. Three close-to-outcrop wells proved useful in establishing characteristic log responses of the main architectural elements identified from the nearby outcrops. Lithofacies were correctly identified in more than 80% of cases using an artificial neural network. Borehole images provided detailed information on sedimentary structures, including a wealth of palaeocurrent data from climbing ripples that significantly enhanced the interpretations based only on outcrops. Wells sited away from the outcrops supplied information on lateral thickness and facies trends and intrafan stacking patterns, which helped to define the stratigraphic evolution of the fans. The combined data indicate that deposition was controlled in part by subtle basin-floor topography, and that intrafan lobe switching took place, leading to internal subdivisions that potentially caused effective compartmentalization of the basin-floor fan.
Wettability of chalk: impact of silica, clay content and mechanical properties
Authors: Strand S. , Hjuler M. L. , Torsvik R. , Pedersen J. I. , Madland M. V. , Austad T.
Published: October 2008

The success of improved oil recovery from natural fractured chalk fields by injection of water depends largely on the wetting conditions of the reservoir rock and also, to some extent, on the compaction due to water weakening of the formation. Samples from outcrops are often used to mimic the reservoir properties in laboratory work. The present study illustrates that care must be taken when selecting outcrop material; in particular, the content of silica will affect these important properties. Chalk samples from Aalborg, which contained significant amounts of silica and minor amounts of clay (6.3 wt% Si), were studied by SEM and the mineral properties of the silica characterized. The surface chemistry of the porous medium was different from chalk containing smaller amounts of silica and clay (1.4–2.8 wt%). In the presence of a crude oil with high acid number and initial formation water, the water-wet fraction of Aalborg chalk remained close to 1.0 after aging for four weeks at 90°C in the crude oil. The Amott–Harvey wetting index showed, however, the wetting condition to be close to neutral, and only small amounts of water and oil imbibed spontaneously at the residual saturations. The difference in wetting conditions due to different content of silica and clay is also reflected in differences in the mechanical properties. It appeared that the mechanical strength, as studied by a large number of tests, became weaker as the water wetness decreased. The effect of wettability on the water weakening of chalk is discussed in terms of chalk dissolution and the chemistry associated with thin water films. As an overall conclusion and recommendation, a careful comparison should be made of the Si-content in the reservoir rock and outcrop chalk when picking material for laboratory experiments.
Using geological information to optimize fracture stimulation practices in the Cooper Basin, Australia
Authors: Nelson Emma J. , Chipperfield Simon T. , Hillis Richard R. , Gilbert John , McGowen Jim
Published: October 2008

Fracture stimulation treatments of tight formations in the Cooper Basin can be associated with hydraulic fracture complexity that results in abnormally high treating pressures, low proppant placement and poor economic success. Pre-completion (image log and rock testing data) and post-completion data (fracture stimulation pressure decline plots) were reviewed in 13 treatment zones from the Cooper Basin. Rock strength, image log and stimulation data were available for seven of those zones.

From this analysis, a distinct relationship between rock properties (shear and tensile rock strength), geological weaknesses (natural fractures and other fabrics) and fracture stimulation complexity (net pressure, near-wellbore pressure loss and pressure-dependent leak-off) was observed. It is proposed that high
in situ
stress (
S
hmin
≧0.8 psi ft
−1
; 18.1 MPa km
−1
), a large contrast in tensile strength between intact rock (
T
>1015 psi (7 MPa)) and pre-existing weaknesses in the reservoir (
T
∼0) promote the propagation of fracturing fluid along multiple fracture pathways, and thus abnormally high treating pressures, low proppant placement and poor economic success during fracture stimulation treatments in the Cooper Basin.

The methodology used to predict
in situ
stress and hydraulic fracture complexity herein presents a potential generic approach that can be used in similar basins where hydraulic fracture complexity is a problem or where conventional stimulation practices are unsuccessful.
A new technique for evaluating coarse grids based on flow thresholding
Authors: Zhang Pinggang , Pickup Gillian E. , Christie Michael A.
Published: October 2008

Current upgridding techniques usually require the scale-up factor to be known
a priori
and, in practice, the scale-up factor is selected rather subjectively. The main consideration is that the scale-up factor should be large enough for practical use and not so large that the results are likely to be very inaccurate. A more objective approach to selecting the scale-up factor is desirable. This paper proposes a novel approach to determine a more appropriate scale-up factor for a coarse model. The new approach is based on an analysis of the flows in the fine-scale model. The regions that make a significant contribution to the flow are identified using a thresholding technique. A range of scale-up factors is tested and high flow regions are identified in each case. The percentage overlap (denoted by
R
o
) of the high flow regions in the coarse and fine grids is then calculated. The value of
R
o
can be used as a predictor of the accuracy of upscaling and the appropriate coarse grid size can thus be evaluated. When the upscaling is performed using a global method, there is little extra computational cost. This method is suitable for use in multi-phase flow simulations of 3D heterogeneous reservoir models. The technique is demonstrated using a simulation of a waterflood in a highly heterogeneous 2D model.
Petroleum generation and migration in the ‘Tight Gas’ area of the German Rotliegend natural gas play: a basin modelling study
Authors: Schwarzer D. , Littke R.
Published: October 2008

The Northwest German Basin is an important hydrocarbon province with considerable reserves of natural gas accumulated at its centre. To unravel the thermal and maturation history of the Carboniferous source rocks, particularly gas generation and migration, a combined petrological–geochemical and numerical basin modelling study was performed. Generally two main phases of maturation can be assigned to the Triassic–Late Jurassic and latest Cretaceous–Present intervals. Maturity data reflect the latter event and are consistent with a variable heat flow of 60–63 mW m
−2
during Cretaceous–Tertiary burial which accounts for considerable late gas generation. Vitrinite reflectance data and maturity modelling show the Top pre-Permian strata in the northern part of the basin to be in the gas window at present, with a rather uniform maturity of VR
r
 = 1.5% to 2.0% (at 4600–5100 m). However, the important top coal marker is at different depth levels and reveals a more complex coalification pattern, suggesting a strong structural control on maturation of source rocks. This effect is influenced locally by the high thermal conductivity of large salt bodies in the overburden. A significant delay in gas generation from source rocks at elevated horst blocks can be observed. The generation and migration of pre-Westphalian gas started during Late Carboniferous times, when much of the gas was lost from the basin due to ineffective seals. With ongoing burial, gas migration from Westphalian source rocks started in Early Triassic times within Permian graben areas, but was actually delayed until the Late Cretaceous at highly elevated horst blocks. The gas from early migration phases was replaced almost entirely by successively younger Westphalian gas.
Architecture of Lower Oligocene source rocks in the Alpine Foreland Basin: a model for syn- and post-depositional source-rock features in the Paratethyan realm
Authors: Sachsenhofer R. F. , Schulz H.-M.
Published: October 2008

Oligocene rocks are one of the most important sources of hydrocarbons within the Paratethyan realm. In the Alpine Foreland Basin (Central Paratethys) the main Oligocene source rock is the Schöneck Formation, but organic-rich rocks occur in the entire Lower Oligocene succession. Based on well-log calibration by core data, the spatial distribution and thickness variations of different Lower Oligocene source-rock facies are investigated. The deeper-water sediments are characterized by lateral continuity, but exhibit vertical variability. The latter reflects major palaeoceanographic changes in the Central Paratethys, such as the closure of seaways, basin-wide changes in salinity and in redox conditions. The upper shaly part of the Schöneck Formation has the highest source potential (>5% TOC, initial HI: 500–600 mgHC g
−1
TOC) and reaches its maximum thickness (
c
. 5 m) in a narrow belt parallel to the palaeo-shoreline.

The present-day distribution of Lower Oligocene rocks is controlled by submarine erosion which affected the northern passive slope of the foreland basin. Erosion climaxed during the late Early Oligocene. The eroded material was re-deposited along the lower basin slope (Oberhofen facies). The source-rock potential of the re-deposited sediments is relatively low. The oil kitchen (4–7 km burial depth) is located beneath the Alpine nappes where the Lower Oligocene succession was removed locally by the advancing nappes. Both submarine erosion at the northern basin slope and tectonic erosion beneath the Alps have to be considered in the evaluation of the prospectivity of the basin.

Because deposition of the Lower Oligocene succession in the Alpine Foreland Basin is controlled by basin-wide processes, it may serve as a model for source- rock deposition in foreland basins of the Paratethyan realm (e.g. Carpathians, Terek–Caspian Foredeep).
Faults in conventional flow simulation models: a consideration of representational assumptions and geological uncertainties
Authors: Manzocchi T. , Heath A. E. , Palananthakumar B. , Childs C. , Walsh J. J.
Published: October 2008

Even when geologically based methods are used to determine fault rock permeabilities and thicknesses for input into flow simulators, a wide range of simplifying assumptions regarding fault structure and content are still present. Many of these assumptions are addressed by defining quantitative and flexible methods for realistic parameterization of fault-related uncertainties, and by defining automated methods for including these effects routinely in full-field flow simulation modelling. The fault effects considered include: the two-phase properties of fault rocks; the spatial distributions of naturally variable or uncertain single-phase fault rock properties and fault throws; and the frequencies and properties of sub-resolution fault system or fault zone complexities, including sub-seismic faults, normal drag and damage zones, paired slip surfaces and fault relay zones. Innovative two-phase or geometrical upscaling approaches implemented in a reservoir simulator pre-processor provide transmissibility solutions incorporating the effect, but represented within the geometrical framework of the full-field flow simulation model. The solutions and flexible workflows are applied and discussed within the context of a sensitivity study carried out on two faulted versions of the same full-field flow simulation model. Significant influence of some of these generally neglected fault-related assumptions and uncertainties is revealed.
A drilling mud additive influencing the geochemical interpretations of hydrocarbon shows
Authors: Ohm S. E. , Karlsen D. A. , Backer-Owe K. , Pedersen J. H. , Beeley H. S.
Published: October 2008

Oil-based mud additives are used frequently during drilling for various purposes. The chemical compositions of these may interfere/overprint the chemical composition of hydrocarbon shows in the well and thereby complicate geochemical interpretations. This is likely to be an increasing problem as hydrocarbon findings become more subtle. It is important that the geochemist compiles a list of all additives used during drilling and obtains a sample of the pre-drill oil-based mud additives used. In the case of detailed geochemical analyses to be carried out post-drilling, it is then possible to check the influence/contamination of the additives on the hydrocarbons found.

The chemical composition of a frequently used oil-based mud additive is demonstrated to have overprinted the hopane signature of an oil-slick sample in well 35/1-1, northern North Sea. This could easily have resulted in erroneous interpretations regarding age and depositional environment of the source rock of the oil. However, the steranes used for interpretation of facies are shown to be unaffected by the mud additive. A study of shows from well 35/1-1 suggested the source of these to be an atypical developed Upper Jurassic source rock, despite the hopane signature suggesting a carbonaceous Permian source. The main argument was that a Permian source would imply higher maturities than observed. The present study reveals that the hopanes in the shows are contaminated completely by the mud additive used during drilling and, hence, a Permian source is ruled out successfully.

This paper demonstrates that if one biomarker group from the mud additive overprints that of the indigenous oil show this does not preclude other biomarker groups from truly representing the oil show.
Petroleum systems in rift basins – a collective approach inSoutheast Asian basins
Authors: Doust Harry , Sumner H. Scott
Published: October 2008

This paper synthesizes some of the main conclusions reached in a recent regional review of the Tertiary basins of Southeast Asia, carried out by Shell. Four distinctive types of petroleum systems, correlating with the four main stages of basin evolution (early to late syn-rift and early to late post-rift), are developed widely in the basins. These petroleum system types have characteristic interbedded environmentally controlled source, reservoir and seal lithofacies which, in combination with the structural trap style, determine the hydrocarbon habitat. Variations in the tectonostratigraphic evolution consequent on differences in, for example, basin palaeogeographical position and proximity to late Tertiary collision events, are reflected in differences in the representation of the four petroleum system types. In turn, this is reflected in the overall hydrocarbon volumes found, the average field sizes and the ratio of oil to gas. The recognition of analogous petroleum systems (‘petroleum system types’) and reservoir lithofacies play types in well-explored basins can facilitate prediction of hydrocarbon prospectivity in less well-known rift/post-rift basins and plays, and thereby contribute to future exploration evaluation in these provinces.
Cretaceous tectonostratigraphy and the development of the Cauvery Basin, southeast India
Authors: Watkinson Matthew P. , Hart Malcolm B. , Joshi Archana
Published: October 2008

The late Jurassic to early Cretaceous rifting between India/Australia and India/Antarctica resulted in the formation of a number of NE–SW-trending basins in the Indian Precambrian crystalline basement. The Cauvery Basin is the southernmost basin along the eastern margin of the Indian Sub-Continent, covering much of this part of India and extending a considerable distance offshore. The basin comprises several ‘depressions’, or sub-basins, with the Ariyalur–Pondicherry Depression in the north. The exposed successions are in the southern part of this sub-basin.

The result of fieldwork (1994–8) has been a reassessment of the lithostratigraphy and the tectonostratigraphic history of the Ariyalur outcrop. Three major sedimentary groups were identified: the syn-rift Gondwana Group (of early Cretaceous age), the syn-rift Uttatur Group (of Albian to Coniacian age) and the post-rift Ariyalur Group (of Santonian to Maastrichtian age). Both microfaunal and macrofaunal information were used to develop a biostratigraphic framework for the basin and a new tectonostratigraphic model. This new model for the development of the basin is significantly different to that used by the Oil and Natural Gas Commission of India. Structures exposed onshore, which have been interpreted as Albian reefs, are interpreted here as irregularly shaped limestone olistoliths/olistostromes produced by intra-Cretaceous rifting and slumping within the basin. The paper discusses this model for the basin history which is calibrated by updated foraminiferal (and macrofossil) biostratigraphy.
Assessing the effect of geological uncertainty on recovery estimates in shallow-marine reservoirs: the application of reservoir engineering to the SAIGUP project
Authors: Matthews John D. , Carter Jonathan N. , Stephen Karl D. , Zimmerman Robert W. , Skorstad Arne , Manzocchi Tom , Howell John A.
Published: October 2008

Reservoir management is a balancing act between making timely operational decisions and the need to obtain data on which such decisions can be made. There is a further problem: estimates of recovery for prospective development plans are subject to uncertainty because of the uncertainty of the geological description within the simulation model.

The SAIGUP project was designed to analyse the sensitivity of estimates of recovery due to geological uncertainty in a suite of shallow-marine reservoir models. However, although it was generic, it had the hallmarks of active reservoir management, because those members of the team responsible for deriving the notional development plans for individual models via reservoir simulation, and computing the recoveries, had to work in parallel with others under time and budget constraints.

This paper describes the way the reservoir engineering was carried out to achieve these objectives, the assumptions made, the reasoning behind them, and how the principles could be used in other studies. Sample results are also presented, although the bulk of the results are presented in other papers in the project series. One surprising result was that faults that impede flow can improve recovery. The underlying physical explanation for this behaviour is provided.
On the occurrence and formation of open fractures in the Jurassic reservoir sandstones of the Snøhvit Field, SW Barents Sea
Authors: Wennberg Ole Petter , Malm Ove , Needham Tim , Edwards Ewart , Ottesen Signe , Karlsen Frode , Rennan Lars , Knipe Rob
Published: October 2008

Open fractures were described in core and Formation Micro Image (FMI) image logs in the Jurassic sandstones of the Tubåen, Nordmela and Stø formations in the Snøhvit Field, and 3D fracture network properties analysed using Computer Tomography (CT)scanning in selected core samples. The most frequent open fracture type is short stylolite-related fractures (F1), but longer open fractures are also present, with no obvious relationship to stylolites (F2). The F1 fracture densities are related generally to the clay content of the host rock, which controls the occurrence and spacing of the stylolites. The fractures are steep, with a N–S-dominant strike azimuth and significant spread. Although, generally, the F1 fractures are short, a percolating and 3D connected open fracture network across the core was found in most of the CT-scan samples. Open fractures were also found in the damage zone of a lately reactivated fault. The formation of the open fractures in the Snøhvit Field is related most likely to thermoelastic processes during removal of overburden in late Tertiary time. The presence of open fractures may influence reservoir flow, particularly in intervals containing a high frequency of stylolites and in the damage zones of reactivated faults.
Maximum Likelihood Deconvolution for sequence analysis and improved structural resolution in the Vindhyan Basin, India
Authors: Chatterjee S. M. , Dutta Somaditya
Published: October 2008

Exploration in the Proterozoic Vindhyan Basin in the north-central part of India has received much attention because a number of basins coeval to it (Amadeus and McArthur basins, Australia and Lena–Tunguska petroleum province, Siberia) are known hydrocarbon producers. The assemblage of interbedded clastics and carbonates in the thick Vindhyan sedimentary column is considered to be favourable for a petroleum system. This is supported by discovery of oil and gas in Vindhyan sediments.

Wavelet processing and application of Maximum Likelihood Deconvolution (MLD) to post-stack seismic data have enhanced resolution significantly to facilitate identification of various stratigraphic features, including reflection pattern termination in the Jabera–Damoh area in the southeastern part of the basin. Sixteen seismic sequences correlatable with well data have been identified from the wavelet-processed data. MLD has also improved structural resolution and made identification of faults easier. This paper shows that MLD is a powerful tool for seismic sequence stratigraphy.
Mineralogical control on mudstone compaction: a study of Late Cretaceous to Early Tertiary mudstones of the Vøring and Møre basins, Norwegian Sea
Authors: Peltonen Christer , Marcussen Øyvind , Bjørlykke Knut , Jahren Jens
Published: October 2008

The Late Cretaceous to Early Tertiary sediments of the Vøring and Møre basins are predominantly composed of fine-grained mudstones. Variations in the mineralogy and chemistry of these mudstones provide information regarding facies, provenance and burial history, and may also be used to predict rock properties. Over 300 cuttings’ samples from five wells were analysed by XRD. The results show significant changes in mineralogy as a function of burial depth, as well as important lateral variations throughout the basins. Eocene mudstones with up to 55% smectite probably represent a northern equivalent of the Balder Formation (North Sea). The underlying Late Cretaceous sequence probably had less primary smectite derived from volcanic ash, as indicated by the lower iron content. The distribution of smectite is also limited by its thermal stability, thus providing important constraints on the temperature history. These mudstone sequences may appear to be relatively homogeneous based on gamma-ray and shale volume calculations from wireline logs, but mineralogical and geochemical analyses from cuttings show that they vary significantly in composition. The smectite content is greatest in the south (
c
. 55%) and decreases significantly northward (
c
. 20%), indicating a marked regional control on velocity/porosity–depth curves. Mudstones containing high smectite content are characterized by lower velocities, lower densities and higher porosities when compared with published burial curves. Stratigraphic and regional variations in velocity and density are important for seismic interpretation and are significant for basin modelling.