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GEO 2010
- Conference date: 07 Mar 2010 - 10 Mar 2010
- Location: Manama, Bahrain
- Published: 07 March 2010
201 - 300 of 457 results
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Generation of in-Situ Stress Map in Gulf of Suez (GOS) and Its Impact from Drilling High Angle Wells, Egypt
Authors Ahmed M. Abuelfotoh and Dhruba J. DuttaThe effect of magnitude and pattern of earth’s in situ stress is generally manifested on the shape of the
borehole in a drilled well. It is well known that the stress around the wellbore causes deformation
depending on many factors ranging from rock strength to the deviation of the wellpath.
In this paper, a stress map is generated from borehole breakout along with other wireline logs from a
reasonably large database. Both vertical and deviated wells covering major part of GoS are considered
for this study. The fact that stress related breakout originates from the maximum tangential stress is
the main criterion here. The tangential stress is combination of forces like earth in situ stresses, drilled
mud weight and pore-pressure of the formation. Complimentary to the magnitude, breakout
orientation indicates the direction of minimum in situ stress in case of vertical wells. Stress evaluation
in deviated wells requires multiple well input in a limited area to generate a stress tensor diagram that
determines stress orientations with confidence. In a deviated well the breakout direction is controlled
by in situ stress with respect to the trajectory of the well. The study reveals that the min horizontal
stress (Sh) in GoS is aligned along two major trends. First, the main NNE - SSW trend, with an
average orientation of 10degN exists in most of the part. The second trend is aligned NE - SW and has
been observed locally at the central eastern and south-western part of GoS, with an average
orientation of 50degN. Most studies of the structural and tectonic history of the GoS have concluded
two age significant orientations for this extensional rift. The early to middle Miocene rifting, yielded Sh
direction of 55-60degN (rift-climax phase). The younger stress fields of the Late Miocene and Pliocene
times rotated progressively counterclockwise and yielded a 15-25degN direction that persisted into
early-late Pleistocene time. The main trend therefore is mainly controlled by this younger stress field of
the GoS rifting.
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Resolving Thin Beds: A New Approach in the Cantabrian Sea
Thin sandstone bodies, ranging between 6.8 m and 11.8 m thickness were identified as reservoirs in a
turbiditic environment of Upper Cretaceous age, located in the Cantabrian Sea, Northern Spain. The
sandstone has extremely high porosity (up to 30%) but the net thickness of the sandstone includes
shale stringers. The sandstone was poorly resolved by recently acquired, high-resolution seismic
reflection data with a typical seismic bandwidth extending from ~0.5 to 60 Hz, peaking at ~22 Hz. A
previous acoustic impedance inversion showed that the sandstone had low acoustic impedance but the
unit was difficult to map due to surrounding shales. Geotrace utilised its Bandwidth Extension (BE)®
algorithm to first improve the resolution of the thin sandstone, before applying RockRes® to better
define the geometric extent of the sandstone. BE® extends the bandwidth of conventional seismic
reflection data on a trace-by-trace basis, at both the high and low frequency ends of the spectrum. It
operates in the Continuous Wavelet Transform domain, using a convolution-like process to extend the
spectrum by a specified number of octaves from harmonics present within the seismic trace. Broader
frequency content of the data serves to resolve thin beds as well as normalising the seismic wavelet for
inversion. RockRes® is a high-fidelity seismic inversion, utilising a three-term linearized approximation
of AVO attributes to derive rock properties. BE® applied to a stacked dataset increased the viable high
frequencies to ~96 Hz and the peak frequency to ~58 Hz. The mapability of the sandstone unit was
markedly increased, revealing the presence of two separate sand bodies. The stratigraphically
overlapping sands have slightly different density and acoustic impedance properties. BE® also aided
definition of small faults in the reservoir interval. Having successfully parameterised BE® on stacked
data Geotrace applied BE® to six angle stacks, which were input into RockRes® in order to better
characterise the reservoir. Acoustic and density logs enabled calibration of both the acoustic impedance
and density inversion terms. The inversion revealed the low acoustic-impedance sands in exquisite
detail and the depositional model for the sandstone has been refined. Where the previous inversion
suggested that the sandstone was one contiguous body, possibly offset by small faults and fed by a
channel-like structure, RockRes® reveals two separate lobes that are compartmentalised.
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Maximising Recovery from Thin Oil Columns Part 1: Geosteering Horizontal Wells to Maximize Oil Recovery - from Integrated Team Effort
Authors Talal Mamary, Georg M. Warrlich, John P. Watkins, Hilal Shabibi and Phil LeightonPetroleum Development Oman (PDO) has been using geosteered horizontal wells in a thin oil column
Cretaceous carbonate field (Shuaiba Fm.) to maximize the oil recovery rates and to minimize attic oil.
The objective of the geosteering in this field is to stay in the pay-zone, an interval of 1.5 meters below
the Shuaiba/Nahr Umr interface without exiting into the Nahr Umr Shale - a challenging tasks for the
steering and drilling teams.
A separation between the log signatures of resistivity measured from attenuation and that measured
from phase is observed in the Nahr Umr shales, but it is absent in the Shuaiba. The increase of this
separation as the drill-bit approaches the Nahr Umr shales while drilling horizontally in the reservoir is
used to place the wells in the pay zone, along with gamma ray log response and cuttings information.
Understanding the geology of the about 5 My long unconformity at the top of the reservoir with
outcrop analogues helped interpreting the drilling data into a clearer picture of the subsurface and
make better geosteering decisions.
Daily updates of the static reservoir model structure and properties with the drilling results help the
geosteering and predictions from geophysical quantitative interpretation volumes (semblance and
discontinuities) reduce the risk of unexpected drilling into fractures and sub-seismic faults.
Close co-opertation between planning, steering and directional-drilling teams at the rig-site are
paramount for successful drilling of these complicated wells.
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Stoichiometric Characterization of Dolomites by Cell and Rietveld Refinements (Middle Triassic, French Jura): A New Approach
Authors Melanie Turpin, Fadi H. Nader and Eric KohlerBy cation substitutions in the dolomite crystal lattice through dissolution-precipitation reactions, the
stoichiometry of the dolomite (%CaCO3), and therefore its stability/reactivity, is bound to change.
Reaching stable forms dolomites are more resistant to further changes and may retain their reservoir
properties. This contribution presents a new approach using the X-ray diffractometry (XRD) technique
coupled with cell and Rietveld refinements on dolomitized rock samples, which enables in one analysis
with few powder material to achieve mineralogical quantification, crystallographic investigation, and
assessment of dolomite stoichiometry.
Core-samples were investigated from Chatelblanc 1 well, representing the stratigraphic contact of the
Upper Muschelkalk and Lettenkohle Formations (Middle Triassic). XRD analyses were combined to
classical petrographic and geochemical data (e.g. major/trace element composition, stable oxygen and
carbon isotopes). The investigated sequence covers an interval about 10m thick, consisting of
limestones (mudstones and bioclastic wacke/grainstones), dolostones and evaporites.
Microscopic examination (transmitted light optical and cathodoluminescence) resulted in identifying (i)
a calcitic and/or dolomitic bulk-rock matrix; (ii) three phases of calcite cements (aragonite
replacement; bioclasts filling; fractures filling) and, (iii) three phases of dolomite cements (early planar
-e; planar-e filling bioclasts; planar-s fracture filling). Stable isotopes results may reveal heating
associated to burial during the emplacement of cements (δ18O-calcite: -6.65 to -0.25‰ VPDB; δ18Odolomite:
-8.27 to -1.89‰ VPDB). Our new analytical approach concerning dolomite stoichiometry
analyses was achieved in two phases. First, an abacus - with crystallographic data on dolomites - was
built from a comprehensive literature review. Such data comprise cell parameters related to the lattice
Ca percentage of various dolomites. Then, using the dolomite cell parameters determined by cell
refinement and this abacus, dolomite stoichiometry could be calculated. This approach resulted in
recognizing distinct groups of dolomites based on their stoichiometric values (while they show similar
petrographic textures) in the investigated Triassic sediments. Dolomites with the highest
nonstoichiometry (~53% CaCO3) are associated with rocks showing the lowest dolomite abundance,
while the more stable (stoichiometric; ~50% CaCO3)with pervasive dolostones.
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Modeling Hydrocarbon Generation in North Melut Basin
Authors Tarig A. Abbas and Berttoti GiovanniThe Melut Basin is in essence a continental rift basin in the generally accepted knowledge, it
experienced three phases of extension from Neocomian to Oligocene times each associated with
thermal subsidence stages and possibly with important episodes of non-deposition and/or erosion. The
basin constitutes part of the larger Central Africa Rift system and, considers as one of major
hydrocarbon provinces in Sudan, which witnessing substantial exploration activities.
During the second rift cycle (Campanian- Maastrichtin) normal faults were reactivated again allowing
for the deposition of organic-rich shale and claystone deposited mainly in lacustrine, marginal
lacustrine and deltaic environments. The organic rich shale and claystone of Galhak and Alrenk
Formations form the principle source rock in the Melut Basin. The source rock kerogen is predominantly
derived from lacustrine algae with subordinate terrestrial woody plants debris.
An attempt has been made in this work to model the hydrocarbon generation of source rocks in north
Melut Basin using Petromod 1D and 2D packages. The principle objective is to investigate the temporal
and spatial variation of thermal maturity of the Cretaceous source rocks in Melut basin. Two seismic
sections and 6 wells were selected for this purpose. 1D models were constructed for all six wells. Database
was generated including information about the stratigraphy, lithology, tectonic event and
geochemical data. Boundary conditions (paleo-heat flow, Paleo-bathymetry and paleo sediment water
interface temperature) are deduced. The resulted model was calibrated with the VRo and BHT data to
produce a best fit between the observed and model curves.
Using the obtained knowledge of 1D hydrocarbon generation model, two geological cross sections were
built from seismic sections, then calibrated and simulated. The resulted models show a considerable
correlation in timing of oil generation and expulsion. The Tertiary strata are immature to marginally
mature basin wide. While the cretaceous source rocks are active at the present day only in basement
high areas while in the deep basinal areas these rocks are over mature. Peak oil generation of Alrenk
and Galhak formations was attained around 54 Ma and 45 respectively. The present day transformation
ratio (TR) of Alrenk source is between 80-90% implying that this unit converted most of its potentiality
to hydrocarbons with very little remain to be expelled.
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Petroleum Prospects of Lebanon
More LessThis contribution presents an updated comprehensive review of the petroleum prospects of Lebanon
through description of the known hydrocarbon shows as well as their host rock formations and
structures. Tectonic and depositional evolutions will be discussed and placed in the larger context of
the eastern Mediterranean Levant region. A generalized model for hydrocarbon migration in Lebanon is
presented disclosing data about Paleozoic, Mesozoic and Cenozoic prospects.
Since no economical petroleum prospects have been exploited to date in Lebanon, the necessary
regional correlations and comparisons with adjacent hydrocarbon producing countries were undertaken
in this contribution. This approach helps in explaining the Lebanese data in a regional framework, filling
certain gaps and confirming or negating proposed ideas. Major lithological rock units are described and
their aspects with respect to hydrocarbon prospects are assessed (source rocks, reservoirs, cap-rocks).
The tectono-sedimentary evolution is reviewed together with the major structural configuration (e.g.
Syrian Arc deformations and basinal inversions, Dead Sea strike-slip fault and transpression). The role
of diagenesis (e.g. dolomitisation, karstification, dissolution) in enhancing reservoir properties is also
highlighted and linked to the major structures and tectonic events that are believed to provide traps.
Hence, the present understanding of the petroleum systems in Lebanon proposes two major plays: (1)
onshore the Qartaba structure (or similar anticlinal structures) - associated to the Syrian Arc
Deformation-, where Triassic (ore pre-Jurassic) prospects are considered to be of major interest; and
(2) offshore northern Lebanon where various Cretaceous and Neogene rock formations may be charged
by the Upper Cretaceous source rocks and sealed with volcanics, marl/clay, and evaporites. Local reef
platfrom structures of Miocene age, sandstone and turbidites (Cretaceous and Cenozoic) offshore
northern Lebanon, especially within the southern Levant Basin, are believed to provide attractive
reservoirs. The timing of hydrocarbon migration should be constrained. Potential reservoirs may be
isolated by the evaporites, volcanics, clays and marls, as well as the Messinian salts which acts as a
heat conductor and may save the underlying source rocks from over-coooking.
This contribution is a general, updated review of the petroleum prospects of Lebanon within its regional
framework.
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Biogenic Silica Particles in Permo-Carboniferous Rocks and Their Significance as Biostratigraphic Indicators
Late Carboniferous to Early Permian clastic rocks of the Unayzah resting on the Hercynian
Unconformity surface in Saudi Arabia, are of great economic significance, bearing significant quantities
of gas and oil. The Unayzah reservoir sequences are often barren of fauna and flora which limits
independent biostratigraphic control and well correlation. The presence of newly discovered siliceous
microfossils may provide a tool for subdividing and correlating these rock successions. These siliceous
microfossils may constitute phytoliths, microscopic silica bodies of various shape and size that form in
the cells of roots, stems and leaves of plants. As major plant groups like gymnosperms, lycopods and
ferns already existed by the end of the Devonian, one might expect that these early land plants also
formed phytoliths in their tissues. Following decay of the plant, the silica bodies may become part of
the sedimentary record. In order to test this hypothesis Permo-Carboniferous rocks from 12 wells,
distributed over a large geographic area in Saudi Arabia, were studied. Biogenic silica particles (BSPs)
were found in all studied wells and lithostratigraphic units. A total of 14 BSPs with some significant
morphological differences were identified and described. BSP assemblages are currently being studied
to determine whether they can provide information on facies, paleoclimate or stratigraphy. The fact
that almost all BSP species were found in all lithostratigraphic units studied suggests that subdivision
of the sedimentary sequences based on conventional first and last occurrence datums of BSPs, is not
promising. On the other hand, BSPs show distinct abundance patterns that may be of stratigraphic
importance. The sample collection from the Unayzah succession has recently been extended in order to
enlarge the areal and stratigraphic coverage. If the outlined studies are successful, BSPs may provide a
new tool for subdividing and correlating terrestrial rock sequences that are often barren of microfossils,
including palynomorphs.
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Fractures as Indicators to 4D Fold Development within the Zagros Fold-and-Thrust Belt, Iran
Authors Daniel Brown, Mike Oehlers and Zsolt SchlederThe Zagros fold and thrust belt represents progressive deformation of Palaeozoic to Cenozoic
sediments above a salt detachment, which in turn overlays inverted extensional faults in the
metamorphic basement. The Cenozoic sediments of the Zagros contain some fine examples of exposed
fractured carbonate sequences.
Using Landsat 7 ETM+ imagery data, regional scale fracture sets have been interpreted across the
anticlines of Kuh-e Khurgu, Kuh-e Devin, Kuh-e Finu and Kuh-e Ginau in the Laristan domain, SE
Zagros. Using Quickbird imagery data, field-scale fracture sets have also been interpreted across Kuh-e
Khurgu. The results of the regional and field-scale fracture analysis show dominant fold axis-parallel,
fold axis-orthogonal, and conjugate NW-SE and NE-SW fold axis-oblique orientations.
Utilising the 0.67m resolution of the Quickbird data allows rapid, field-scale identification of fracture
patterns. Mapping the fracture and joint sets alongside fold aspect ratio analysis illustrates the
deformation evolution of the folds, including the presence of, and disturbance by, reactivated basement faults.
NW-SE orientated fracture patterns dominate anticlinal rose diagrams regardless of fold size, axial
orientation or shape. This abundance confirms a local underlying basement trend striking roughly NWSE.
A balanced cross-section of the area was constructed, using the Landsat 7 ETM+ imagery and the
newly released 30m Global ASTER DEM data, showing salt-cored detachment folds above a series of
reactivated basement thrusts that indicate both thin and thick-skinned deformation.
The results of the satellite image interpretation are then integrated in 3-D Move and a geological model
built. The restoration tools are used to validate the geological model and suggest alternatives where
appropriate. Once a “best fit” structural history has been identified, the data are then used to capture
the geometric strain history through time in 3-D Move. The strain information and other attributes
(e.g. curvature) are used to generate a discrete fracture network that is controlled by the observed data.
A multi-stage, 4-dimensional fracture model is proposed for all four folds of the area. This takes into
account the incremental and progressive development of fractures as strain indicators within the fold.
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Dukhan 3D: from Ultra High Density, Full Wide Azimuth Seismic Survey for the Future
Authors Salva R. Seeni, Scott Robinson, Michel Denis, Ghiath Ajlani and Jean-Jacques PostelThis paper presents a case study on the logistics and acquisition of an ultra high density and full wide
azimuth 3D seismic survey across the Dukhan field in Qatar. This survey represents a step change in
seismic data acquisition with greatly enhanced data quality by full wide azimuth and very dense spatial
sampling. It is expected that this survey will set an industry standard for seismic acquisition leading to
improved field redevelopment.
The Dukhan field is a large oil field in Qatar established in 1941, it contains over 700 wells producing
from 4 major reservoirs. It has a rather complex history of production & development strategies;
starting with natural pressure depletion for more than 20 years, followed by power water injection
since 1989 and gas cap cycling since 1998. As other large mature Middle East oil fields, Dukhan also
witnessed large changes in technology over the last 60 years. In order to maximize the long term
economic recovery from the field, QP is committed to applying leading edge but fit for purpose
technologies. New, state of the art, 3D seismic data combined with updated reservoir models will
enable QP to continue the development of Dukhan field for many years to come.
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Integration of Crosswell Electromagnetic, Geologic, Production and Seismic Data for Characterization, Monitoring and Dynamic Modeling of Water Injection in a Heterogeneous Carbonate Reservoir
Crosswell Electromagnetic (EM) tomography is a recently developed technique to map the interwell
formation resistivity distribution. In this project, time-lapse crosswell EM surveys are used to monitor
saturation changes in a water injection pilot in the basal low-reservoir quality units of a giant carbonate
field in the Middle East. We demonstrate how EM results were used with seismic-derived structural
information, geological data, structural models, time-lapse cased hole logs, pressure transient and
production data to improve reservoir characterization and dynamic modeling.
The evolution of water saturation is derived from measured resistivity distributions, which are obtained
by inversion of the EM measurements with respect to an initial resistivity model. To obtain a detailed
image of saturation changes, this model must incorporate realistic representations of the small-scale
heterogeneities common to carbonate reservoirs. These include layer thickness variations and the
presence of thin dense layers interbedded in some reservoir units. Such details allowed improvements
in the quality and resolution of the EM results, leading to a better understanding of the reservoir
architecture and the behavior of the water flooding process.
Preliminary simulation results using simplified models predicted high vertical sweep across the
reservoir units, without encountering any flow barriers. This was inconsistent with the EM results,
which show that the injected water stays confined within the lower reservoir units, and the measured
injection pressures and flow volumes, which were different from those predicted from simulation.
Successive adjustments were therefore applied on the dynamic model to honor the EM and injection
pressure results. Adjusting the permeability contrast across some layers prevents the upward
movement of the injected water, and is consistent with geological interpretation of continuous stylolitic
dense layers within the lower reservoir. In addition, fracture corridors, identified on seismic attributes
and supported by PLT data and field-wide review of borehole image logs, are used to account for the
injected volume mismatch, yielding the correct injection pressure.
When properly constrained with seismic, geological and production data the EM results provide
important information on the location and behavior of the fluid front and identification of the required
amount of geological detail that needs to be preserved in the dynamic model.
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Tectonic, Depositional, and Thermal History of the Levantine Basin Resulted in Numerous Structural and Stratigraphic Plays
Authors Lisa Marlow, Nigel Wattrus, John Swenson and Christopher KendallThe tectonics, deposition and thermal history of the Levantine Basin was conducive to the generation,
expulsion and migration of hydrocarbons; as indicated by many hydrocarbon shows and a recent major
gas discovery in the basin. Tectonics and deposition have led to the formation of numerous unexplored
structural and stratigraphic traps including: anticlines, flower structures, reefs, talus, turbidites, and
stratal pinchouts adjacent to salt. Traps are ubiquitous in the 15 km thick stratal package of the
Levantine Basin, many with direct hydrocarbon indicators (DHI's) including flat spots, bright spots and
gas chimneys with positive play potential. Tectonics in the Levantine Basin followed a similar
progression to that of the rest of the Southern Tethyan Margin; rift-extension followed by passive
margin and then compression beginning in the Late Cretaceous with the collision of the African-Arabian
Plate with the Eurasian Plate. These tectonic systems along with the reoccurring strike-slip activity
resulted in structural traps throughout the basin: anticlines and flower structures. One of the anticlinal
structures is a trap for the recent "giant" gas discovery from the Tamar Well (5+TCF gas). Deposition
in the basin was equally conducive to trap formation; several stratigraphic traps exist. Triassic salt
deposits (the Kurra Chine equivalent) likely extend well into the Levantine Basin; in fact, seismic
evidence indicates doming of the Triassic Salt through overlying strata and development of traps
adjacent to the salt. Jurassic to Early Cretaceous deposits are dominantly carbonate platform and
interplatform basins; carbonate platforms extend over 200km to the north of the present southern
continental margin. The carbonate platforms, which are up to 75 km in diameter, contain several
stratigraphic traps in the form of reefs atop the platform and the talus and turbidites adjacent to the
platform core. Late Cretaceous chalk deposits that onlap anticlines in addition to the Paleocene and
Oligocene turbidites complete the Pre-Messinian stratigraphic traps.
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Conceptual and Numerical Modeling of Fracture-Related High Temperature Dolomite: Implications for Reservoir Characterization
Authors Fadi H. Nader, Jean-marc Daniel, Olivier Lerat and Brigitte DoligezClassical diagenesis studies make use of a wide range of analytical techniques in order to suggest
conceptual models that explain specific, relatively time-framed, diagenetic processes and their impacts
on reservoirs. Still, these models are qualitative and do not yield "real" data for direct use by reservoir
engineers for rock-typing and geo-modeling. This contribution provides new insights into numerical
modeling of dolomitization following two approaches (geostatistical and geochemical transport
reactive), and attempts to express the conceptual models of hydrothermal dolomitization which is
known to have affected reservoirs in the Middle East, in more quantitative terms.
A 3D geostatistical model representing the Ranero dolomitized Cretaceous platform carbonates was
constructed, covering an area of 5x2km and a depth of 2km. It is based on interpretation of aerial
photographs, geological and topographic maps, as well as field observations. The resulting 3D block
included the stratigraphical units, fractures and the dolomite bodies. Geostatistical simulations
succeeded in reproducing the dolomitized pattern. A relationship was set to restrict the presence of
dolostones to the fractures at depth. A 2D geochemical transport reactive model was built to represent
an HTD front (~350m long; cells: 5x1m) in the Marjaba Jurassic platform carbonates. The nature of
the dolomitizing fluid was constrained based on results of fluid inclusions and crush-leach analyses.
Two aquifer analogues for the end-members of the mixed dolomitized fluids were chosen according to
their similar sedimentological character, mineralogical compositions and ambient temperatures to the
expected sources of evaporative marine-related waters and hydrothermal fluids.
The geostatistical model helped in illustrating the relationships between the hydrothermal dolomite
distribution and the fracture pattern. Numerical reactive transport simulations are valuable not only for
predicting hydrothermal dolomite texture (porosity/permeability) distribution but also for validating the
prescribed dolomitization model. This study provides means to predict fracture-related HTD distribution
and related evolved reservoir properties, achieving, hence, better reservoir characterization.
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Sequence Stratigraphic Analysis of Carbonate and Evaporate of Schun Formation (Paleogene) from Type Locality, Fars Region, Zagros Basin
Authors Asadollah Mahboubi, Reza Moussavi-Harami and Roohallah ShabafroozThe Paleocene-Lower Eocene Sachun Formation in southern Zagros Basin consists of carbonates,
evaporate and silisiclastic sediments. It is overlain conformably by the Jahrum Formation and underlain
conformably by the Tarbur Formation. Field and laboratory studies led to identification of 13 carbonateevaporate
and 2 silisiclastic lithofacies. These identified lithofacies of the Sachun Formation at type
locality, have been deposited in tidal-flat, lagoon, barrier and open marine environments in carbonate
platform of ramp type. Sequence stratigraphic analysis of Sachun Formation at type locality led to
recognition of four large-scale depositional sequences. The upper and lower boundaries of these
depositional sequences are type one. Interpreted sea level curve during deposition of this interval is
relatively similar to world sea level curve but there are some differences that can be related to tectonic
effects of the study area. We hope these data can be used in reconstruction of paleogeography of the
petroliferous Far region during the Paleogene time.
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Critical Factors of Carbonate Pore Systems - Implications for Reservoirs in the Middle East
Authors Oliver Weidlich, Stefan Lubeseder and Klaus FlenderGenerating predictive models for reservoir quality distribution is challenging for carbonate reservoirs.
Usually, quantitative porosity data for these models are exclusively derived from conventional core
plug measurements or log data (log-derived effective porosity, RHOB, DT; NMR in rare cases).
For this study, conventional poro/perm plots from plugs and log data of Cretaceous and Jurassic
carbonates were analysed using data from several wells offshore Qatar. The following observations are
based on data from Kharaib, Yamama, Upper Sulaiy, Lower Sulaiy and Arab samples:
(1) Poro-perm plots of the above stratigraphic units show a significant overlap of data despite some minor trends
(2) Core plug porosity data do not decrease with depths.
(3) Cross plots of log-derived and core plug porosities show no trend, e.g. core plug porosities were
higher, similar or lower than equivalent porosity log data (notably NPHI).
Our observations suggest that additional parameters need to be considered to improve reservoir
models. The concept of reservoir rock types has been repeatedly regarded as an effective tool that
integrates geologic observations with porosity and permeability data. We combine under consideration
of sedimentologic and diagenetic factors conventional porosity data from plugs and logs with image
analysis-based pore size, analysis from high-resolution core photos and thin sections. With this
approach we established a six-fold reservoir rock type concept for the investigated Jurassic-Cretaceous
carbonates to better characterize the variability of pore space and pore geometries of reservoirs units.
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Image Petrophysics - A New Approach to Reservoir Characterization
Authors Manfred Frass and Nicholas HarveyBorehole imaging is the only tool to characterize from very small features like fractures or cross
bedding up to major structural features.
Since the late 80’s, bore hole imaging based on resistivity measurements has been the only tool with
the vertical and horizontal resolution, capable to detect very small bioturbation effects, cross bedding,
vugs and or fractures as well as other structural features such as faults, unconformities or folds. The
main question about this technology has been, how deep into the formation these small features really
are and how they impact the hydrocarbon production.
There are only a few methods to evaluate the fracture extension or the cross bedding effect within the
sand bodies over the reservoirs, one is a dynamic interference test among two or wells, another is the
use of seismic attributes and neural networks to correlate with image logs and/or core data. From the
images the fracture orientation, spacing, aperture are obtained, which could be used to calculate
fracture porosity and permeability as well as vugular porosity and perm distribution around the well
bore using image petrophysics, were each resistivity curve is transformed into a porosity curve
generating an azimuthal property distribution map defining the vertical and the horizontal anisotropy of
each interval of the reservoir. Using this extremely powerful method and integrating with seismic
attributes several is the most advanced method to generate a 3D reservoir model, in any reservoirs.
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Resistivity Borehole Imaging in Challenging Borehole Environments
More LessUntil recently, the acquisition of resistivity borehole image data from well bores less than 6” in
diameter has been impossible, due to the size of conventional borehole imaging tools currently
available on the market. In addition, conventional deployment methods limit efficient rig time
utilization and ultimately lead to higher risk and costs associated with acquiring image data. The
introduction of new logging technology now allows operators to obtain excellent image logs in wells as
slim as 3 inches in diameter, and in wells with challenging hole conditions.
Image logs are required to properly understand formation properties and fractures details; and to help
in future drilling and completion decisions. In Saudi Arabia, the cost savings that are possible by
sidetracking existing well bores makes the drilling and completion of ultra slim lateral wells very desirable.
Access into these wells is achieved by employing numerous conveyance techniques including well
tractors and drill pipe to push logging tools along the horizontal section to TD. The borehole images
can be acquired using small diameter imaging technology with acquisition in real time and in memory.
The combination of conveyance and imaging technologies enable operators to make important
decisions on where to place completion hardware in the well to enable the well to produce to it’s full potential.
This paper describes the new imaging technology and will discuss the image acquisition experience in
the world’s first ultra slim hole and extended reach horizontal sections in Saudi Arabia.
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Understanding and Managing Water Advance in a Heterogeneous Carbonate Reservoir: from Integrated Subsurface Approach
Rapid and uneven water advance is observed in heterogeneous platform-interior carbonate reservoirs
in the south of a super-giant Middle East Field, producing since the early 1960s. Crestal oil production
is supported through peripheral water injectors typically 5-7km from the producing area. Historical
production imbalance has accentuated water movement in the south of the field, with wells ceasing to
flow naturally even with relatively low water cut.
A multidisciplinary approach has been used to understand controls on water encroachment. This
involved integration of geology (core facies, correlation, reservoir properties), geophysics (seismic
attributes, fault / fracture characterization), petrophysics (openhole & time-lapse cased hole logs) and
reservoir engineering data (simulation models, production / injection).
Water advance is focused in certain areas of the field, and within limited stratigraphic layers. In
particular, two prominent ‘water fingers’ are present within most reservoir units at the limit between
the platform interior and thick prograding platform margin belt.
Stratigraphic water fingering is controlled mainly by vertical variations in reservoir quality, particularly
permeability within the 5 main Reservoir Units (named 1 - 5 from bottom to top). Water advance is
less rapid in the lower two and the uppermost Reservoir Units (1, 2 and 5) which show interbedded
stylolitic dense layers and lower matrix permeability (typically 1-10md). Within Units 3 and 4, water
movement is more advanced and initially concentrated along super-high (darcy scale) permeability
layers a few feet thick. Sequence stratigraphic analysis calibrated with core confirms that such layers
are associated with 3rd & 4th Order sequence boundaries, with partial cementation but preserving
vuggy porosity. Within Units 3 and 4, poorer reservoir quality facies (more cemented, coral-rich in Unit
3) and non-reservoir carbonate mudstones (within Unit 4) act as isolated local baffles to horizontal
water movement.
Controls on the location of the two prominent areal water fingers include faulting / fracturing,
stratigraphic contrast between the platform margin and interior, and production / injection imbalance.
An improved understanding of water movement is being used to predict future water breakthrough,
refine infill drilling locations, plan future Artificial Lift requirements, design selective well completions
and optimize field development.
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Basement Characterization for Block 18, Yemen
Authors Raffaela Heinbockel and Amin Al-MaktariIn the fractured basement play of Block 18 a granitic basement is expected to have the best reservoir
potential and the basic igneous rocks (diorite/gabbro) the least reservoir potential. The basement
lithologies of Block 18 may be divided into three reservoir facies, i.e. granite, metamorphic and basic
igneous which are likely to be lateral extensions of basement outcrops. Block 18 basement lineaments
are expected to form complex networks and have developed over a number of phases. Local basement
variations are influenced by a number of factors including basement lithology, the present day stress
field and tectonic factors associated with rifting in the basin.
2.5-D integrated gravity and magnetic modeling and enhancement techniques resulted in an improved
definition of the basement. We identified basement blocks and fault zones and proved the
heterogeneity of the basement in Block 18. We identified igneous bodies within the sedimentary
section and highly magnetic structures within the basement. Based on the modelled densities and
susceptibilities, we are able to classify the basement types as generally granitic in the south, as likely
metamorphic in the central north and as partly basic igneous in the northwest.
Based on the results from seismic, gravity & magnetics, existing wells and regional geological studies
two new wells were drilled. The results from these wells fit with our studies and analyses in terms of
structure and lithology as well as type and direction of fractures. We will present a summary of the HC
shows in these wells.
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Underbalance Drilling in Tight Gas Reservoirs
Authors Thomas Finkbeiner, Satya Perumalla, Daniel Moos and Martin BrudyDeep, tight reservoirs face significant appraisal and development challenges. In particular, it can be
difficult proving the presence and mobility of sufficient quantities of gas to make the reservoir
economically viable. At the same time, drilling costs are extremely high. In this context, underbalanced
drilling (UBD) provides a number of benefits: first, it enables the operator to proof the presence of
producible quantities of gas while the well is being drilled. Underbalanced drilling also can minimize
formation damage and maximize the rate of penetration. This can result in significant savings of drilling
and completion costs relative to conventional drilling. However, not all reservoirs are suitable for UBD
as there is much greater risk of mechanical wellbore instabilities relative to wells drilled overbalanced.
Hence, geomechanical analyses prior to drilling are of particular importance in order to evaluate the
feasibility of UBD operations.
In the past, the stability of UBD wells has been analyzed using conventional approaches, simply by
extending these to stress states in which immediately after the well is drilled one effective principal
stress (the radial stress) is tensile; undrained conditions are assumed to develop instantaneously at
the wellbore. This approach leads to very conservative predictions, with the result that many wells that
would be candidates for UBD are drilled overbalanced.
To apply a less conservative approach, a new analytical model to predict the stability of underbalanced
wells has been developed. Based on the recognition that rocks have scale-dependent strengths, the full
stress concentration is not developed until some time after the bottom of the well is some distance
below the point of interest, and that fluid flow into the advancing wellbore leads to a zone of locally
lower pore pressure that extends beneath the drill-bit, it provides rapid assessments of the limit of safe
underbalance as a function of drilling rate. The model predicts the regions within which spalling and
breakouts will occur. One consequence is that higher permeability leads to the ability to drill both
faster and with a larger underbalance. A second is that smaller hole sizes are predicted to be easier to
drill underbalanced; in cases where there is a high risk of wellbore collapse of the full-sized well this
suggests that drilling an initial pilot well followed by enlargement to full size may mitigate the risk of collapse.
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Integrated Dolomite Characterization of Deep Jurassic Formation, Middle Marrat, Minagish Field, Kuwait: A Case Study
Authors Girija S. Padhy, Bishnu Kumar, Eman A. Al-Mayyas, Naveen Verma and Fahmy M. FawzyThe Minagish Marrat is a deep, over-pressured, tight carbonate reservoir with light Jurassic oil
production history of 24 years. As many as 16 deep wells penetrate this reservoir of which 12 were
completed as naturally flowing producers. Petrophysical characterizations of this complex carbonate
reservoir is a challenging task due to constraints imposed by large well spacing, small well bore
diameter, use of oil based mud, HP-HT coupled with H2S environment. Reservoir characterization away
from wellbore is equally challenging due to inadequate resolution of 3D seismic data at depths
exceeding 11,000 feet. Understanding the role of both primary depositional and secondary digenetic
processes in porosity development through integrated reservoir characterization assumes great
significance in such circumstances.
This paper documents efforts to define accurate mineral model for probabilistic petrophysical analysis
specially dolomite characterization, which plays important role in reservoir development being less
susceptible to porosity reduction under high overburden pressures and deep settings. As evident from
core analysis results (porosity and permeability), dolomitization plays a significant role in increasing
the storage capacity. So quantification of dolomite is highly necessary to not only to understand
reservoir rock quality but also as a key input into the static and dynamic reservoir modeling. However,
the same is difficult in the absence of special logs like neutron capture spectroscopy data which
provides a better solution. Conventional open hole logs (density, neutron and sonic) have their own
limitations and uncertainty involved due to several factors such as: barite mud effect, oil base mud
invasion, complex lithology, sensitivity etc. and hence alone cannot be used with full confidence for a
complete characterization. Notwithstanding this limitation, at this end, an attempt was made to solve
this dolomite volume and build a good mineralogical model through an integrated workflow approach
where information from high resolution sequence stratigraphy, core and electrolog based rock typing,
core analysis and the available conventional logs were used. This integrated approach was followed for
few key wells with all inputs to build the probabilistic multi-mineral model, with reasonable confidence
and define the parameters which were later applied effectively for all other wells in the field for
successful dolomite mapping and identification of the zones of interest. The results were further
incorporated in the static reservoir modeling providing a new dimension to the reservoir
characterization (reported elsewhere). This approach is planned to be validated and calibrated with
neutron capture spectroscopy data in the future wells.
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Drainage Capillary Pressure and Resistivity Index from Short-Wait Porous Plate Experiments
Authors Moustafa Dernaika, Ove Bjorn Wilson and Svein M. SkjævelandReliable experimental capillary pressure and electrical properties as functions of saturation history are
essential as inputs for static and dynamic modeling of a reservoir. The only technique that
simultaneously gives both Pc and Sw-RI relationship as functions of saturation history, and does not
rely on a model with underlying assumptions for calculation, is the standard equilibrium method. This
method is also known as the porous plate technique. The only disadvantage with this method is that it
is time consuming caused by the low flux through the diaphragm (porous plate).
In this paper we present drainage capillary pressure curves and resistivity index measured on reservoir
rock samples by the standard equilibrium method at reservoir conditions. In parallel with this, a sister
plug set has been analyzed by interrupting intermediate capillary displacement pressures before
reaching equilibrium, with the objective of establishing Sw-RI relationship much faster. The results
show that it is possible to establish identical Sw-RI relationship with a time-saving factor of three for
the rock type under study.
Both data sets are analyzed with an extrapolation routine as an attempt to also predict capillary
equilibrium for the fast plug set, i.e. capillary drainage curve. Numerical interpretation of the
experiments has been done as an attempt to investigate factors and optimized design of the
interrupted capillary displacement pressure sequence for various porosity and permeability classes.
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Geochemistry of Saudi Arabian Natural Gas
Authors Peter D. Jenden, Pierre J. Van Laer and Ahmed M. Al-HakamiSaudi Aramco has measured carbon isotope compositions of C1-C5 hydrocarbons and CO2 on hundreds
of gases from exploration tests and producing wells. The isotope data group the gases into
thermogenic families with different sources. For example, δ13C of gases associated with Jurassic
Ghawar-type crudes increases from -54.6 + 3.0 ‰ for C1 to -39.6 + 1.6 ‰ for C2 and -27.6 + 0.9 ‰
for n-C5. In contrast, δ13C of Paleozoic gases increases from -42.1 + 6.1 ‰ for C1 to -31.9 + 4.5 ‰
for C2 and -29.5 + 3.0 ‰ for n-C5. The isotopic characteristics of the Jurassic-Ghawar and Paleozoic
gas families appear heavily influenced by their source kerogen, Type IIS for the former (Upper Jurassic
Hanifa and Tuwaiq Mountain carbonates) and Type II (Silurian Qusaiba hot shale) for the latter.
C1/C1-C5 (mol/mol) of Paleozoic hydrocarbons ranges from 0.65 to 1.00 and is correlated with an
increase in methane δ13C from -47 to -37 ‰. Within this range, we judge that liquids abundance and
isotopes are controlled primarily by source rock maturation. Khuff, Unayzah, Devonian and Silurian-
Ordovician gases are indistinguishable on common interpretive plots such as C1/C1-C5 hydrocarbons
versus methane δ13C, providing evidence for a single dominant Paleozoic source.
Most Paleozoic gases contain less than 10% CO2. δ13C of CO2 in unaltered gases from Khuff carbonate
reservoirs typically fall between -3 and +3 ‰ whereas those from deeper clastic reservoirs fall
between -20 and -5 ‰. Gases containing more than ppm levels of H2S are restricted to the Khuff.
Increasing H2S is accompanied by a decrease in CO2 δ13C to < -25 ‰, arguing that the gases have
been altered by thermochemical sulphate reduction (TSR).
Paleozoic gas-condensates around the Ghawar structure commonly contain less than 15% N2. Nitrogen
abundance here appears to be controlled by mixing between wet thermogenic gas and a high-N2 gas
component of uncertain origin. Khuff gases in coastal and offshore fields contain less than 10% to as
much as 40% N2 and often far less than 1% C2+ hydrocarbons. In one field with incontrovertible
petrographic evidence for TSR, C2+ hydrocarbons are below detection limits and methane and carbon
dioxide both have δ13C of approximately -22 ‰. N2, accounting for 25% of the gas, appears to have
been enriched due to destruction of methane by TSR.
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Elastic Moduli Sensitivity to Reservoir Pore Fluids
More LessA detailed seismic modeling work has been carried out to identify the most appropriate elastic rock
modulus (or moduli) that are sensitive to reservoir pore fluid types. This work is being applied to both
oil and gas bearing clastic and carbonate reservoirs from different fields within Saudi Arabia. The
sensitivity of each modulus to the reservoir pore fluid saturation was also analyzed. Among those
moduli are Vp/Vs ratio, lambda-Rho, and bulk modulus. Modeling results ranked investigated elastic
moduli with regards to their effectiveness as “fluid indicators”. These results also set rules of thumb as
to which modulus is suitable for a given set of reservoir conditions.
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Multi-Scale Assessment of the Middle Eastern Permo-Triassic Khuff Carbonate: Structural Evolution and Its Impact from Reservoir Properties
Authors Valentina Zampetti, Ravi Borkhataria and Marietta VroonThe Khuff Petroleum System Study is a multi-scale, multi-disciplinary analysis that integrates
subsurface and outcrop, rock and fluid samples, and static and dynamic data in order to characterize
the Permo-Triassic Khuff carbonate, one of the major petroleum reservoirs in the Middle East region.
At regional scale, the Khuff carbonate shows a variety of depositional environments (with facies
ranging from coastal plain anhydritic claystone, tidal flat/low-to-high energy lagoonal deposits to openmarine
dolostones alternating with grainy limestones and high-energy shoal-dominated dolostone/thick
grainy limestones) and thicknesses (from near zero at the pinch-out of siliciclastic facies in central
Saudi Arabia, to more than 400 m (1300 ft) in Ghawar field in northern Saudi Arabia, expanding to 800
m (2600 ft) in the North field, Qatar and to nearly 1000 m (3300 ft) in the eastern United Arab Emirates).
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Recognition of Palaeoexposure Surfaces within Cenomanian-Turonian Strata of Southwesterrn Iran: Implications for Reservoir Characteristics
Authors Elham Hajikazemi, Ihsan S. Al-Aasm and Mario ConiglioStable carbon and oxygen isotopes and 87Sr/86Sr ratios determined in surface and subsurface
carbonates of the Sarvak Formation reveal the presence of multiple subaerial exposure surfaces that
resulted from sea-level fluctuations. The sequence boundaries exhibit different degrees of geochemical
alteration with more extensive alteration representing longer duration of subaerial exposure. The δ13C
(range from -6.4‰ to 4.1‰, VPDB) and δ18O values ( ranges from -9.4‰ to -0.9‰, VPDB)
determined for Sarvak matrix carbonates fall well within the Mid-Cretaceous marine values while the
palaeoexposure surfaces are characterized by more negative δ13C and δ18O values and higher
87Sr/86Sr ratios. The most depleted δ13C values in carbonate soils formed due to subaerial exposure
resulted from interaction of marine carbonates with aggressive meteoric water charged with
atmospheric CO2. This caused pronounced karstification and development of favorable reservoir
characteristics including effective porosity and permeability.
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Controls from Dolomite Distribution in a Lower Cretaceous Ramp, Benassal Formation, Serra D’Orpesa, Spain
Well-exposed Aptian shallow-water carbonates of the Benassal Formation in Serra d'Orpesa, Spain
provide an excellent opportunity to document depositional, diagenetic, and structural controls on
dolomite distribution in a ramp setting analogous to conditions observed in some giant Middle Eastern
fields. The Racó del Moro outcrop is the subject of a broader stratigraphic, diagenetic, and modeling
study on the origin of dolomite co-led by researchers at the University of Barcelona and the University
of Barcelona Autònoma in collaboration with ExxonMobil’s FC2 Alliance. Due to excellent lateral
exposure, recent efforts have been focused on characterizing the two-dimensional stratigraphic
architecture, with emphasis on lateral and vertical dolomite distribution across the outcrop. Detailed
field mapping has revealed subtle depositional controls on dolomite distribution, and provides insight
into controls on diagenetic fluid pathways that could enhance reservoir quality and productivity in
carbonate reservoirs. Furthermore, the data collected from detailed field mapping has served as a key
input into construction of a geologic model used to test various fluid flow scenarios. The study plans to
show and discuss the field mapping observations in stratigraphic context and provide scenarios of
controls on dolomite distribution.
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Ocean Bottom Seismic in the Arabic Gulf; We Need to Adapt the Acquisition Parameters to the Local Environment
Authors Karl A. Berteussen and Yefeng SunA summary of our analysis and modelling results from a study of a 2D 4-Component (4C) Ocean
Bottom Seismic (OBS) data set acquired in the shallow-water environment typical of the Arabian Gulf is
presented. Our study illustrates both the challenges and opportunities of application of 4C OBS in such environment.
The 2D 4C OBS data set was acquired with receiver spacing 25 meter in the Arabian Gulf in water
depth of about 10 m and a hard bottom with P-wave velocity varying from 3 to 4.8 km/s. Because of
the shallow water, the hard bottom, and relatively long seismic wavelengths, the problem of energy
partition and P-S wave conversion at the water/rock interface may not be addressed adequately using
classical plane wave theory. We use numerical full waveform elastic modelling to understand the
influence of shallow-water wave interactions between the air/water/rock interfaces on 4C seismic data.
Comparative analysis of field records, logs and synthetic data is then used to investigate and assess
the quality of existing 4C OBS data and their potential.
The preliminary results of this comparison are:
- The quality of multi-component data is dictated by the geological conditions and follows the source
physics and sediment physics. The 4C data could be quite reliable; i.e. the instrument response is
basically good.
- The shallow water environment of the offshore U.A.E is unique and very different from other major
offshore fields such as the N. Sea and the GOM. This results in strong P-S wave conversion at the
water/sediment interface. It also results in an efficient equivalent shear wave source, i.e. this gives a
better way to extract shear-wave information from 4C data which again has important implication for
waveform-based seismic processing and inversion.
- Signal/Noise ratio seems low. This is partly due to inadequate acquisition design (aliasing), but also
due to the inherent complexity of multi-component physics.
- C-wave at cap/reservoir interface is strong which is a good indication for reservoir description; i.e.
bypassed hydrocarbons, permeability heterogeneity and resolution.
In sum we believe that 4C ocean bottom seismic is promising for the offshore U.A.E. fields, but the
acquisition parameters need to be adjusted for the special environment. This implies smaller
shot/receiver spacing and longer time delay between shots, which obviously will have implications on
the acquisition cost.
Finally; more acquisition tests should be done.
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A Basin Modeling Approach to Understand the Heavy Oil Occurrence in Burgan Sand of Cretaceous Age, Burgan Field Kuwait
More LessAt the base of the Burgan oil column (near OOWC) a zone of significantly heavier oil column has been
observed in some of the wells. A study was undertaken with respect to the heavy oil occurrence to
assess the possible processes that could lead to the formation of heavy oil in the Cretaceous reservoirs
of the Burgan and Wara formations. The occurrence of heavy oil in the Greater Burgan Field can be
explained by a combination of multiple processes.
The study demonstrated hydrocarbon charging by two possible source rocks. Besides the well known
Makhul source, role of Kazhdumi source in charging the reservoir was brought to the fore. The
Kazhdumi Formation, a time equivalent of Burgan Formation was deposited in a more distal area of the
Dezful Embayment of the Zargos Fold Belt northeast of Kuwait and is a proven, good to excellent
source rock in the Iranian Zargos Fold Belt.
The initial charge history causes a special distribution of heavy components in the Greater Burgan
Field, which might be the reason for the occurrence of heavy oil mainly in the high permeable layers.
As these components are transported in a liquid phase, additional processes are needed to explain the
heavy oil distribution. There are strong hints, that water washing, supported by the strong edge water
drive, can explain the occurrence of heavy oil in several wells that are positioned in areas of a paleo oil
-water contact. Long preservation times of the main accumulations in the Burgan, Magawa and Ahmadi
fields are likely to cause gravity segregation within the oil columns of these older accumulations.
Biodegradation is believed to have only a limited influence on the heavy oil occurrence.
This study will provide an in depth insight into the heavy oil distribution in the Greater Burgan field , a
key element in the future development plan.
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3D Visualisation of Trapped Hydrocarbons in Carbonates from the Pore Scale: Exploring the Residual Hydrocarbon Phase after Secondary and Tertiary Flooding
Authors Mark Knackstedt, Munish Kumar, Tim Senden and Rob SokAt the conclusion of flooding in an oil- or gas-bearing carbonate reservoir, a significant fraction of the
original hydrocarbon in place remains in the swept region as trapped residual phase. In addition to the
amount of trapped phase, its microscopic distribution within the pore space of a reservoir rock is
important to gain a better understanding of recovery mechanisms and for the design and
implementation of improved or enhanced recovery processes. Despite the importance of the pore scale
structure and distribution of residual oil, little quantitative information is currently available. This study
presents a robust method to obtain this critical information.
Residual saturation visualization is undertaken in core material at the pore scale via microtomographic
imaging. We utilize a new technique for imaging the pore-scale distribution of fluids in reservoir cores
in three dimensions. The method allows reservoir core material to be imaged after different stages of
flooding; e.g. after secondary and tertiary floods. Core flooding can also be performed under different
wettability conditions, saturation states and flooding rates.
Although considerable attention has been paid to the subject of residual oil structure, the amount of
quantitative experimental information on the structure of the residual oil phase in reservoir core
material is limited. The detailed structure of the residual trapped phase is described. This information is
correlated to pore structural information from the 3D image data (pore geometry, connectivity),
mineralogy and rock type. These results provide an important platform for the testing and calibration
of pore scale modelling efforts for multiphase flow.
This detailed pore scale information of the residual oil saturation is crucial to the design and
implementation of improved recovery processes and can be related to conditions required for
mobilization of residual oil. Oil recovery mechanisms are directly tested and the differences in the
habitat of the residual fluids under different conditions are directly quantified.
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Seismic Characterization for Stochastic Modeling of Fractures in Na_SJ Reservoirs of UG Field, West Kuwait
Authors Jalil A. Abdul, Saad Matar, Pauline Convert, Dimitri Rocher and Vincent de GroenIn the context of oil recovery optimization in naturally fractured carbonate reservoirs of West Kuwait,
fracture detection along with lithological distinction offers a great added value as it helps in
characterizing the wells productivity.
This paper describes a seismic workflow for characterizing reservoirs affected by fracture corridors as
well as small scale diffuse fractures. The method is based on the parallel use of two approaches: (1)
seismic attributes analysis performed on post-stack data, and (2) lithology prediction using pre-stack
inversion and characterization.
A multi-variate attribute classification technique is applied to generate zonation maps that highlight
sub-seismic fractured corridors. Statistical cluster analysis is used to identify the seismic classes, and
then to group traces having the same characteristics.
At the end of the process, the interpretation highlights discontinuous zones affected by large-scale
fractures. Ranking of so called “fractured seismic facies” in terms of probability of fracture occurrence
allows generating an index map for the large scale fracture (swarms/corridors). The 3D stochastic
fracture model eventually incorporates this large scale fracture prediction.
Modelling of sub-seismic scale fractures can also be guided by seismic data. Higher fracture density is,
in this reservoir, related to cleaner limestone units. Hence, lithological discrimination based on prestack
attributes (P and S impedances) was performed to predict the lithological changes impacting on
fracture density.
This method associates shaliness at wells with impedance variations. Based on (Ip,Is) crossplots,
discrimination between lime stones and shales was made possible in 3D at the seismic scale. Volumes
and derived maps of shale occurrence were generated to provide guidelines for the simulation of shaly
rock-types in the geological model. This 3D facies model was then used to model the network of small
scale factures.
From this workflow, two types of deliverables based on seismic data and calibrated at wells provide
robust guidelines for 3D stochastic fracture model building within the whole Umm Gudair field area.
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An Approach to Identify the Sink Holes through Seismic Imaging - A Case Study from West Kuwait Field
Authors Jalil A. Abdul, Singha Ray Dipak and Al- Khamees WaleedSink-hole is a closed depression (Karst feature) which drains fluid underground below. Shuaiba
formation of Lower Cretaceous age is known to have Karstic topography with ubiquitous sink-holes
throughout the West Kuwait area. It formed at the intersection of Joints or fault planes and solution of
lime stone, underlying superficial fluvial deposits resulted gradual subsidence, forming a sink hole/
doline features.
While drilling in one of the well of Dharif field, West Kuwait through one of these shallow sink-holes
(unknown before drilling) to reach our targeted reservoir down below in Jurassic is a real horrendous
experience. It immediately starts with severe, unprecedented and uncontrollable lost circulation
(40,000 barrels of Mud) in 22’’ open hole section, causing huge loss of man days/rig days and cost.
Altogether 13 cement plugs were placed. Ultimately well was controlled and reached the target.
Geophysical analysis of a nearby released well of the same field was taken up. The result confirmed the
presence of Sink hole/ Doline feature passing through the well and on the basis of the study, surface
location and well trajectory was shifted.
This paper presents an overview of efforts and methods in imaging those sink-holes in Shuaiba
Formation through seismic attribute analysis and subsequent planning for new future wells bypassing
these Shuaiba sink-hole features, thereby enhancing the safety of the well, efficiency, and cost
effectiveness. After scouting different seismic attributes, the ESP (Event Similarity Prediction) and
Curvature technique were found suitable and most appropriated in the present scenario. It is related to
discontinuities/ dissimilarities observed in the seismic and were used to identify the sink-hole features.
These dissimilarity measurements yield the visual identification of such features as faults, facies
changes and other Geological patterns also. These Sink holes have been identified in all fields ( i.e.
Minagish, Umm Gudair, Abduliya and Dharif ) of West Kuwait and discussed in this paper. Other utility
of these attributes are to identify the locale of water disposable wells. In Minagish field some water
disposable wells also have been planned and drilled on the basis of this analysis.
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Sequence Stratigraphy and Reservoir Compartmentalization in the Lower Wasia, Saudi Arabia
More LessHigh resolution sequence stratigrphy analysis was applied at the Lower part of the Wasia Formation
(Khafji, Safaniya and Mauddud members) of Albian age in the offshore Saudi Arabia. Core analysis,
wire-line logs, biostratigraphy and fluid data were used in the analysis. Two 3rd order sequences were
identified within the Lower part of the Wasia Formation.
The Wasia Formation (Albian/Turonian) in Saudi Arabia is represented by seven members; from
bottom to top are the Khafji, Safaniya, Mauddud, Wara, Ahmadi, Rumaila and Mishrif. The Wasia is
bounded by two pronounced regional unconformities related to major tectonic events: the pre-Wasia
(Albian/Aptian) and pre-Aruma (Campanian/Turonian).
The lower sequence starts at the base of the Khafji member with the low-stand Khafji main sand
followed by transgressive Khafji sand stringers with a maximum flooding limestone marker called Dair
limestone. This sequence was terminated with the high-stand Khafji stray sands; a very thin
continuous sand overlaying the Dair limestone. The upper sequence starts with the low-stand Safaniya
reservoir sandstone followed by the transgressive and maximum flooding surface of the Mauddud
limestone. The sequence ends with the high stand thin carbonates and shales of the upper Mauddud.
Outcrop data has been correlated with the subsurface to establish the regional framework.
Detailed tectono-stratigraphic analysis of the Lower Wasia in the offshore fields indicates that the
Lower Khafji main sand was deposited as fluvial filling of the tectonically-controlled irregular basin
topography. The deposition of the remaining section of the two sequences was primarily controlled by
the sea level eustacy with weak tectonic imprints. Tertiary reactivation of the faults cutting the pre-
Wasia has resulted in compartmentalization of the Lower Wasia reservoirs.
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The Sedimentary Architecture of a Prograding Platform Margin and Its Impact from Production Behavior - an Example from Giant Field “A” Abu Dhabi
Giant Field “A” in Abu Dhabi produces from limestones of the Aptian Shu'aiba Fm with a complex
platform margin architecture. Earlier analysis has revealed that after an initial stage of aggradation the
platform prograded into the Bab basin with a prominent set of clinoforms. A southern platform interior
area of aggradation was separated from the well defined northern clinoforms by a central platform
margin belt with a less distinct seismic signature but a distinct production behavior.
Detailed seismic and core analysis has revealed that this margin actually represents another
prograding clinform belt comprising a 3rd order depositional sequence, which originated during the late
Highstand Systems Tract (HST) of the aggradational late Early Aptian platform phase. There is a
distinct difference in composition and reservoir character between the sediments of the Transgressive
Systems Tract (TST) and the HST. Property differences resulting from cementation at clinoform
boundaries allow the detailed delineation of sedimentary features on depth converted seismic horizon
slices. Clinoform packages are relatively steeply dipping with a depositional slope of up to 3 degrees. A
distinct triangular feature along the progradation front is interpreted to represent a sediment point
source such as a tidal delta draining sand flats on the platform top.
The location of the platform margin and possibly subsequent diagenetic alteration is profoundly
influenced by a deep rooted fault system that became periodically reactivated.
Recognition of the architecture has had a profound impact on understanding production behavior in the
field. Peripheral injected water advances more rapidly in heterogeneous platform interior sediments
forming an areal water finger. The localized water advance is likely aided by fault planes. Its spread
into the crestal parts of the field is retarded by a dense layer associated with a 3rd order maximum
flooding surface and cementation along fault planes. The flood front in the central area is less
advanced, and more even. Individual lower order clinoforms introduce a preferred directional flow
behavior parallel to the platform margin further reducing the influx of water from the platform area.
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Performance Analysis of Automated Technical Review Portal in from Oil Company Environment
A Technical Review Committee of 20 key experts representing all directorates of Kuwait Oil Company
(KOC-TRC) was established by the CEO of the KOC in 19 February 2008 to ensure that the quality of
the KOC abstracts papers and presentations at external technical journals and events reflect the high
standards of Kuwait oil Company.
On 24 March 2009 the KOC Management Committee approved the launch of an automated KOC-TRC
Pilot Portal that was designed by the TRC and developed by Information Solutions (Exploration &
Production) Team of R&T Group. The Portal was created to speed up and streamline the process of
submitting, reviewing and approving submissions intended for external technical events and
publications. Beyond that date all external technical abstracts, papers, posters and oral presentations
authored by members of the KOC Field Directorates were uploaded into the KOC-TRC Portal by KOC
principal authors, reviewed by up to three KOC reviewers; forwarded to the Kuwaiti Ministry of Oil for
endorsement through a dedicated TRC-MoO Portal, and finally returned to the principle authors to
submit for publication.
This paper summarizes more than two years of totally in-house efforts and experience in discussing,
planning, setting reviewing, vetting and ranking rules and forms, followed by designing workflows,
building and piloting a dedicated intra-company automated portal for submitting, anonymously
reviewing and assessing technical publications by an inter-directorate technical review committee.
Followed by diagnosing and addressing bottlenecks in the piloted system.
The piloted cross directorates anonymous reviewers system encouraged more promising and seasoned
professionals alike to submit and participate in reviewing and evaluating technical submittals across
Exploration and Field Development Directorates, and gave the authors and their managers immediate
progress notices and continuous access to their submittals.
** Brian Abbot passed away on 10 November 2008
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Description of Subsidence Phenomena Due to Gas Extraction in Deep Layers with Advanced Three-Phase Constitutive Model
Authors Mathieu Nuth, Lyesse Laloui and Bernhard A. SchreflerIn coastal regions, the land subsidence due to industrial pumping of underground fluids such as
methane is documented on the basis of in situ surveys. Some laboratory characterization of the soils
hosting those fluids have also been published to complement the knowledge on compaction due to
changes of fluid pressures. The withdrawal of gas is simulated in the laboratory by injecting water
under a constant uniaxial or hydrostatic load, which results in the plastic compaction of the samples.
The paper proposes a new attempt to model the observed collapse of samples, as well as the changes
in compressibility and preconsolidation pressure during the process of wetting. The conceptual
framework essentially relies on unsaturated soil mechanics, as the subsidence phenomenon concerns a
three-phase material with solid grains, liquid water and gas. The developed constitutive model provides
a description of the water retention capability of the studied soils that is coupled with the mechanical
behaviour. Consequently, the elasto-plastic volumetric changes within the porous medium incorporate
the effects of saturation and suction, also called capillary effects. The formulation of the
preconsolidation stress is such that the shape of the yield limit depends on suction so that the apparent
added stiffness brought by low saturation is predicted. The modelling framework, based on the
generalization of the effective stress principle to three-phase media, also provides an elasto-plastic
comprehension of the well-known “wetting pore collapse” phenomenon. The ACMEG-s model shows
consistent understanding of changes of compressibility with the quantity of retained water. The
successive phases of isotropic compression and uniaxial mechanical compaction are used for the model
calibration. Interestingly, the phases of plastic compression during injection are captured with
accuracy, which evidence the applicability of this model to the boundary value problems that are the
large scale cases of subsidence.
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Workflow from Seismic to Static Modeling Capturing Key Heterogeneities Impacting Production Performance in a Super-Giant Middle East Carbonate Field
Oil is produced from an Aptian carbonate reservoir averaging 400ft thick with complex internal
reservoir architecture. The lower reservoir units comprise continuous platform and ramp carbonate
layers deposited during overall transgression. A platform dominated by stacked patchy rudist build-ups
and inter build-up ponds developed in the south of the field during later aggradation. Rapid water
advance along high-permeability layers led to irregular water fingering which must be captured in the
static and dynamic models.
Facies architecture and property distributions are very different in the central highstand progradation
and northern late highstand clinoform domains dominated by more steeply dipping reservoir units (1-3
degrees). Non-reservoir carbonate mudstones associated with transgression form local flow barriers
confirmed by pressure and production data.
Different strategies were used in structural and property model building to account for heterogeneities
across the field. The southern platform interior with rapid facies variations of non-reservoir ‘pond’
facies and stacked coral/rudist shoals was modeled using well data combined with seismic attributes.
Production in the north is supported by peripheral water injection, WAG pattern and line-drive gas
injection. Deterministic mapping of 3rd and 4th order clinoform sequences is critical for understanding
fluid movement. A key modeling challenge was to accurately represent the clinoform geometries. With
dips up to 3 degrees downlap of layers occurs within 1-2km, resulting in ambiguous well-based
correlations. High-quality seismic data was used to map clinoform ‘corridors’ and constrain reservoir
thickness. Stochastic methods (SGS) guided by a deterministic layering framework and controlled by a
core/log-based lithofacies model were used to populate the petrophysical properties. The central area
comprises a thick succession of good reservoir quality facies with ‘transparent’ seismic character.
Recent seismic analysis has led to the recognition of clinoforms although they could not be mapped
deterministically. An architecture was established using well correlation guided conceptually by the
overall clinoform shape.
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Petroleum System of the Mesozoic Sab’Atayn Basin of Yemen
Authors Mustafa A. As-Saruri and Rasheed BarabaThe Mesozoic Sab’atayn basin was elongated along the ancient Najd fault system (NW/SE) in the Upper
Jurassic time and had continued up to the Lower Cretaceous. It is filled with syn- and post rift
sediments and includes good source and reservoir rocks. The first petroleum discovery in Yemen was
happened in 1984 in the Marib sector of the basin. This was followed by second discovery in Shabwah
sector in 1986. However, based on the available data, the Hajr sector indicates good hydrocarbon
potential, but no productive field was reported yet. The predominant source rock is the rich bituminous
shale of the Madbi Formation (Kimmeridgian/Lower Tithonian) which involves Lower and Upper Madbi
Shales Members and found throughout the all sectors of the basin. The main reservoir rocks are found
in several stratigraphic levels, but the sandstone of the Alif Member of the Sab’atayn Formation
(Middle/Upper Tithonian) represents the main reservoir in the Marib sector. In addition, there are
several reservoirs are not studied in detail up to date in all stratigraphic levels (fractured basement,
Kuhlan, Shuqrah Formations). The fractured metamorphic basement and the turbidite within the Lam
Member of the Madbi Formation compose the main reservoirs in the Shabwah sector of the basin. The
Tithonian salt was only developed in this basin and represents good seal in all sectors of the Sab'atayn basin.
Lithostratigraphic correlations in surface and subsurface sections as well as paleogeography of the
depositional environments show the differences and the characterization of the hydrocarbon system in
the Sab'atayn basin and distinguish the lateral and vertical variation and facies changes.
The main tectonic trend is NW/SE (Najd Trend), which displays good role through the structuring of the
hydrocarbon play. The traps are characterized by structural elements represented by horst, tilted fault
blocks and less stratigraphic traps. Two source rock types are identified in the Sab'atayn basin; in
which bituminous rich shale of Madbi Formation is of type I and type II kerogens. The organic carbon
content is between 1-10% and the hydrogen index reaches 800 mg HC/g TOC. The shale and
bituminous limestone of the Layadim and Safir Member of the Sab'atayn Formation contains good
source rock including type II and type III kerogens and the organic carbon content is ranging between 0.8 and 4%.
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Charge Evaluation of South East Abu Dhabi (Part I, Petroleum System Analysis)
The Abu Dhabi Company for Onshore Oil Operations (ADCO) is exploring for oil in a contract area in
South East Abu Dhabi (SEAD). In order to understand the regional charge variations and to identify the
best oil prospects, a large-scale petroleum system analysis was carried out. Results of this study
supported portfolio ranking and optimization of the drilling sequence. The petroleum system analysis
was carried out following Shell’s workflows for Integrated Charge Evaluation which comprises of three
main elements: (1) a source rock evaluation, (2) a regional oil typing exercise and (3) a 3-D basin
modelling study. The study was based on ADCO’s and Shell’s regional knowledge, experience and
database. The results obtained revealed that the petroleum systems in SEAD are different from the
main Tuwaiq Mountain / Hanifa (TM/H) petroleum system in Central Arabia. For instance: the oils
recovered from the Hanifa reservoirs in SEAD are different from those in Central Arabia. The absence
of the ‘typical’ TM/H hydrocarbon family in SEAD was supported by the source rock screening, which
revealed that the Tuwaiq Mountain / Hanifa has little to no source potential in the immediate area.
However, several source rock intervals were identified in the Cretaceous Thamama Group, in
agreement with an earlier study by Taher (1997). The regional oil typing suggests that the oils present
in the SEAD were generated by a separate kitchen area to the North and migrated up-dip in a
southerly direction. The source rock maturation and hydrocarbon migration history was modelled in a 3
-D and results are the subject of a separate presentation.
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Biostratigraphy and Palaeoenvironments of the Early to Middle Miocene Lower Fars Formation, North Kuwait
Authors Abdulkader Youssef and Hanan Al-OwihanFull biostratigraphical and palaeoenvironmental analyses have been applied to 220 core samples taken
from 14 cored intervals in Lower Fars Formation, north Kuwait area. The averaged 200 feet thick Lower
Fars Formation is mainly composed of channel deposits intervened with shallow marine to lagoonal
deposits, unconformably underlain and overlain by the Ghar and Dibdibba formations respectively.
The analyses of the foraminifera, ostracoda, palynology and nannopaleontology have identified four
regional marine flooding events in the studied sections. These four marine flooding events have been
found to coincide with those maximum flooding surfaces of the short term eustatic curve identified by
Haq et al., 2005. Four depositional sequences have been defined based on those flooding events and
bounded by erosional unconformities.
Age dating of these flooding events is tentative due to the absence of planktic foraminifera and
nannofossils. The Langhian palynological species are existing along with the long range Early to Middle
Miocene species in the studied intervals. Most of analyzed samples are barren of nannofossils, except
for a single sample, indicating a barrier separating these marine influenced enclosed environments
from the open marine on the eastern direction of the study area.
The palaeoenvironmental analysis has revealed that diverse of palaeoenvironments have been
established during the deposition of Lower Fars Formation; fluvial channels intervening the shallow
marginal marine; coastal marine to estuarine environments, with lagoonal environment formed in the
interdistributary areas.
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Late Cretaceous Seismic Stratigraphy Offshore Batinah Coast
Authors Mohammed A. Al Balushi and Lindsay B. CollinsSeismic interpretations of the late Cretaceous sediments from the deep water area south of Block-18,
in the Gulf of Oman show interesting seismic facies for frontier exploration. Despite absence of well
control in the deepwater area, it’s still valid to interpret seismic facies using the shallow well B from the
near top late Cretaceous unconformity which was interpreted from downlapping of early Tertiary
reflectors on it. These facies could represent the deepwater end of the onshore fluvial origin Al Khawd
Formation, from north Oman. It is more than three seconds thick in the block and occupies low areas
between basement sub-highs. It consists of five seismic facies (sf) from 1 to 5 as shown in the
proposed seismic stratigraphic log. The seismic stratigraphy first started with sub-marine fan deposits
down slope in the basin under subaqueous conditions followed by intervals of seismic facies 2 to 5,
exhibited by the high and low amplitude acoustic facies. It is expected to show better reservoir facies
development from the well B shaly section Moreover, channels show axes trending NE-SW with minor
presence of soft sediment diaprism interpreted at depths greater than 6sec twtt. Generally, structurl
development during late Cretaceous were influnced with start of the Oman Mountains uplift and its
continuous subsequent erosion (Nolan et al, 1990) whereas the study area remained under structural
quiescence which provided potential source rock developments especially within the deeper sections
beside potential reservoir facies represented by prospective channel sands.
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Tectonic Mapping Using Geomorphologic Characterization from Remote Sensing Data
Authors Andreas Laake, Andrew Cutts and Salah Omar AbbasThe joint interpretation of digital elevation models (DEM) and multispectral remote sensing data in
connection with stratigraphic and geologic information reveals the geologic structure of the earth
surface, particularly in desert terrain. The characterization and classification of the DEM using spatial
statistics provides hints regarding formation tops, which are validated by mineral spectroscopy of
multispectral remote sensing data. The idea behind this approach is that the earth surface topography
is the result of geological processes such as deposition, erosion, and tectonics.
In the first step, the DEM is analyzed for geomorphologic terrain class such as table land. Also, terrain
edges and escarpments are extracted using a spatial gradient filter. In hard rock areas, the
escarpments often delineate valleys that follow fault lines. In the second step, individual bands of
multispectral satellite images are combined to form a multiband RGB image that reveals the different
rock types in certain areas. The rocks exposed as outcrops can be associated with their elevation using
the digital elevation model. From the relative elevations, the deposition sequence can be obtained, and
hence, a stratigraphic column. When combined with the tectonic lineaments extracted from the
escarpments of the DEM, tectonic features can be identified.
We have applied the methodology to a pull-apart basin in the eastern Sinai Peninsula, Egypt. Fault
lines parallel to the Gulf of Aqaba left-lateral fault were identified on the surface gradient. Lithology
focused processing of satellite imagery allows the distinction of Precambrian basement, Paleozoic
metamorphic rocks and Mesozoic sandstone and limestone. Where the left-lateral fault system got
stuck an S-shaped pull-apart basin developed. Using the geomorphologic analysis from DEM and
multispectral satellite imagery the pre-erosion surface could be reconstructed and the amount of throw
in the graben fault could be determined.
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An Analysis of the Near Surface Using Remote Sensing for the Prediction of Logistics and Data Quality Risk
Authors Andreas Laake and Andrew CuttsRemote sensing offers the unique ability to view the earth’s surface without actually being in contact
with it. Using multi-spectral satellite data and Digital Elevation Models (DEM) a workflow is presented
to build a topography and a lithology based classification of the near surface. This enables the creation
of logistics and data quality (surface scatter and surface velocity) risk maps :
1.) Logistics planning: areas that are rough, rocky, have uneven terrain or extreme soft ground will
provide significant logistical issues.
2.) Impact of the terrain on data quality: terrain edges and escarpments represent sources for
scattering as do geomorphologic boundaries; areas of low surface velocity usually bear a high risk for
attenuation of high frequencies and ringing of trapped modes.
The geomorphologic analysis based on DEM and multi-spectral remote sensing data extracts spatially
dense information at a resolution of 15 m, which is sufficient for logistics, acquisition and data
processing. The logistic risks represented by limitations for access and maneuver and the data quality
risk from scattering, attenuation, coupling perturbation and reverberations can be mapped. Histograms
for the risk categories can assist in risk assessment during seismic survey design and bidding. The
technique has been validated successfully by surface geology sampling and photos as well as
correlation with seismic data in the Western Desert of Egypt. The results demonstrate that the
interpretation of remote sensing data allow the prediction of risks associated with land seismic acquisition.
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Integrated Approach to 3D near Surface Characterization
Authors Andreas Laake, Andrew Cutts and Claudio StrobbiaGeophysical exploration and reservoir characterization mainly uses surface sources to generate elastic
or electro-magnetic waves which travel through the subsurface where they are reflected at the
reservoir. Eventually, the reflected signals return to the surface where they are detected by surface
receivers. The challenge these techniques face is to correct for the high degree of distortion which the
near-surface layers inflict on the propagation of geophysical waves. Detection and correction, however,
requires a certain degree of knowledge about these layers. We propose a multidisciplinary approach for
the near-surface characterization since the strong vertical and lateral variations of the near-surface
properties are hard to detect using one physical property alone.
An integrated approach to 3D geologic and elastic characterization of the near surface is presented.
The integration of high spatial resolution, relatively low-confidence remote sensing, and geologic data
with sparse spatial resolution, high-confidence geophysical data in a GIS database allows for crosscalibration
of both types of datasets, thus providing calibrated near-surface models. The method
comprises the generation of a 3D near-surface geologic model, from which the input for a 3D elastic
model is obtained. The elastic model is then calibrated with seismic data to provide the final 3D nearsurface
model. The method has been demonstrated at two case histories covering geomorphological
features typical for desert areas in North Africa and the Middle East.
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Exploring the Ordovician Ghudun Play in North Oman: Challenges and Way Forward
More LessAs conventional hydrocarbon plays have become highly mature after more than 50 years of
exploration, Petroleum Development Oman (PDO) is increasingly focusing towards un-conventional
plays. The Ghudun stratigraphic play is one example where Ordovician Ghudun sandstone reservoirs
are sealed, vertically and laterally, by shales of the overlying Ordovician-Silurian Safiq Group. The
Safiq Group consists of three member formations namely Saih Nihayda, Hasirah and Sahmah, listed
from old to young.
Evaluation of the play was initiated with studies reviewing serendipitous Ghudun discoveries and
subsurface data gathered over several decades. From these studies emerged the Ghudun stratigraphic
play with several sub-play segments. The risks and uncertainties associated with the play are spatially
variable, reflecting the various play segments, spans multiple geological domains and has variable oil
and gas charge potential. The main challenge associated with this play is the difficulty in mapping Top
Ghudun on seismic data (due to low impedance contrasts). This challenge forced PDO to seek
alternative technologies such as gravity modeling and advanced seismic techniques e.g. neural net
approaches to effectively unlock the play potential.
The play segment which is described is the Safiq Canyon Play Segment where canyons have eroded
most of Saih Nihayda and some part of Upper Ghudun and are sealed by the Safiq shales. A cluster of
prospects has been matured and a well was drilled in 2008. The drilling results have been
disappointing but they highlighted risks that were not originally captured and technologies have been
recognized which can mitigate these risks. The drilling results have resulted in updating our
understanding of the Ghudun play.
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Exploration Risk Management - A Play Fairway Led Approach
More LessWe describe an integrated framework for exploration risk management, driven by business reserves
and production requirements. A structured approach to play fairway evaluation should underpin
strategies to manage exploration risk. Sub-optimal decision-making results through failure to articulate
geoscience risks. Managing exploration integrates technical evaluation and business needs.
We describe the exploration decision-making framework. The company's reserves and production
growth requirements should drive all exploration investment decisions. The exploration funnel (basin
entry through to production) should be managed so that there are enough high quality opportunities to
meet current and future demand.
Exploration is a risk business and the ability to predict outcomes at portfolio basis is fundamental to
exploration success. We present examples of how a company's risk and volume estimates should be
continually calibrated against past performance. Management must believe in the cost/volume
projections provided by the explorers!
Most companies start a portfolio review exercise by mapping current assets against business demands.
It is vital to take a hard look at the existing portfolio and test its ability to deliver. If it can’t, it will need reshaping.
Geoscience understanding, and the ability to de-risk plays underpin the whole business of exploration.
In most companies staff are the critical resource that needs rationing, not capital. We describe a
structured approach to play fairway evaluation in which we use this as a tool for de-risking plays and
planning investments in time and capital.
We have suggested that the business requirements be presented in terms of a production profile. This
means that exploration outcomes should also be modelled in this way. The classic way of modelling an
outcome of an exploration portfolio is through presenting the risked weighted sum of the production
profiles arising out of the given drilling campaign. However we find that this does not adequately
represent the likely outcomes. Most companies have some high volume wells in their portfolio (perhaps
associated with high risk). Success in these would transform the shape of a company as happens in
most successful exploration companies. We therefore prefer the scenario modelling approach in which
we model success/failure in certain wells.
The story outlined above shows how a structured approach to geoscience enables informed business decision making.
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Understanding the Pore Pressure, Burial History and Rock Properties Using 3D Basin Modeling
More LessThree dimensional modeling of the petroleum system offers the possibility of evaluating the pore
pressure and filling history of tight gas reservoirs by integrating different processes involved in the
evolution of sedimentary basins and corresponding pore fluids. This approach also provides the
possibility of evaluating the rock properties combined with the depositional history of the basin, which
ensures a more geologically coherent process.
Conventional pore pressure prediction workflows such as seismic velocity analysis, petrophysical
methods and real time monitoring of drilling operations have their limitations in this data constrained
setting and play. In many of these areas with deep and tight reservoirs, poor seismic and quality
calibration data, complicate the pore pressure prediction. The data from these methods is further
limited by their static nature, whereas basin modeling provides a dynamic approach.
In this study, 3D basin modeling results were presented from the South Ghawar area of the Arabian
Basin where pore pressure evolution combined with the filling history and rock properties of reservoirs
was investigated. In addition, the effective stress and porosity trends were modeled through time to
understand the controls on reservoir deliverability.
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Structural Development Interpretation of Idd El Shargi Field (Qatar) Based from Wide-Azimuth 4C Seismic Data - New Insights into Salt-Driven Dome Growth, Timing, and Implications for Reservoir Enhancement
More LessIn this paper we present the results of an integrated study addressing the structural evolution of the
Idd El Shargi oil field (Qatar). By combining well and 4C wide azimuth seismic data, we were able to
build a model with a higher level of detail and genetically link the structure evolution in the context of
the regional tectonic history. This project also allowed us to bring new insights into structural control of
reservoir quality enhancement and compartmentalization, with implications for field development activities.
Idd-El Shargi oil field, located offshore Qatar, was discovered in 1960 and started producing in 1964.
The hydrocarbons are mainly produced from stacked fractured carbonate reservoirs situated on a large
NS-trending faulted anticline that has two salt-cored domes named Idd El Shargi North Dome (ISND)
and Idd El Shargi South Dome (ISSD). Current production is sustained with an aggressive field
development program through drilling of long-reach, multi-lateral horizontal producers and water injectors.
Our integrated seismic interpretation indicates that several regional tectonic and salt induced events
have controlled the growth and faulting of Idd El Shargi. The main events and structural patterns can
be summarized chronologically as follows:
Early rifting extension caused N-S oriented basement faulting at the Khuff level. This event can be
correlated with the regional continental extension during opening of the Neo-Tethys ocean (Permian-
Triassic). The basin deepening was marked by the deposition of Sudair formation (marine shales) and
followed by Gulailah and Hamlah formations (with beds of silty marl, and anhydride streaks, graded
with dolomites). At the same time regional extension induced salt diapirism at ISND that was rapidly
followed by salt withdrawal, causing a combination of dome growth and graben formation.
After the major top Triassic unconformity (top Gulailah - Hamlah), the whole region went through a
period of carbonate deposition over a broad platform that extended across the Middle East. No major
salt tectonic events are evidenced at ISND during deposition of Uwainat and Arab formations
(Jurassic); however, NW-SE oriented faults, related to the ongoing regional Zagros rifting, are visible
on the Arab D-Yamama isochrone map. The regional dip at that time was towards NE.
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Formation Evaluation Challenges in HPHT Tight Sand Reservoirs
Authors R.K. Mallick, Theodore Klimentos and Sharad DubeyRising demand for energy has pushed the oil & gas exploration and production operations to harsher
environments. High pressure and high temperature (HPHT) is one of such challenging areas.
Conventionally, wireline log measurements are rated for operations up to 350 degF temperature and
20,000 psi pressure. However, since many reservoirs exceed these pressure and temperature limits,
HPHT wireline tools have been developed. The most significant challenges occur at “Ultra-HPHT”
environment, i.e., at 400-500 deg F and up to 35,000 psi, which represents the practical upper
operating limit of the existing logging tool electronics technology.
Indian HPHT operations have seen remarkable growth in the past few years. More specifically, the gas
field operations in Krishna Godavari (KG) basin, offshore of Andhra Pradesh, east coast of India, qualify
as Ultra HPHT environment. During the KG exploration activities numerous operational challenges were
encountered due to extreme HPHT conditions.
This paper presents experience gained in drilling and formation evaluation of deep tight gas reservoirs
at ultra HPHT conditions in the KG basin. Moreover, new technologies and formation evaluation
methodologies used to address HPHT related challenges are discussed along with recommendations for
future HPHT operations.
More specifically, the paper highlights the data acquisition challenges in the ultra HPHT environment
and presents an innovative formation evaluation technique using wireline logs at HPHT conditions to
optimize the perforation strategy in tight gas reservoirs in the absence of resistivity logs. Moreover,
borehole stability related problems were evaluated and a Mechanical Earth Model was developed to
improve the drilling performance at HPHT conditions. The paper describes the application of the model
in the exploration wildcat environment. The material presented will facilitate other well construction
teams facing challenging drilling objectives in similar hostile remote environments.
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Understanding Fractures through Seismic Data: North Kuwait Case Study
Understanding fracture corridors is the primary driver for successful development of fractured
carbonate reservoirs. This assumes further significance if the carbonate reservoir is characterized by
very low porosity and permeability; producibility of the reservoir is purely dependent on the presence
of natural fractures. Distribution and type of natural fractures is a function of palaeo & present day
stress, structural elements, regional tectonics and diagenetic history. Direct detection of fractures is
below the resolution of conventional seismic data. However, through a combination of seismic derived
attributes integrated with well data, it is possible to better understand the distribution of fracture swarms.
Kuwait Oil Company (KOC) is currently engaged in an early phase of development of a tight fractured
carbonate North Kuwait Jurassic gas play. Considering the limited well control, field development is
heavily reliant on seismic data for fracture characterization. This paper presents our current
understanding of the relationship between fractures observed in the well data and structures, faults
and lineaments interpreted on seismic data. In addition to conventional seismic analysis a suite of
seismic attributes including Dip, Coherence, Edge and 3D Volume curvature were used for mapping
structures, faults and minor lineaments. Well-wise and field-wise analysis of relationships between
seismic derived attribute-pattern and fracture orientation was established. The understanding between
these two different sets of data has helped in locating potential zones of sweet spots for placing
successful delineation and development wells. These seismic attribute volumes were also used as soft
constraint for building the Discrete Fracture Network (DFN) model for populating the fracture network
in the reservoir model. The data presented in this paper are from the Raudhatain, Sabriyah and North
West Raudhatain (NWRA) fields for the Najmah-Sarjelu part of the Jurassic section.
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Integrated Formation Evaluation of High Pressure High Temperature Tight Reservoirs - a Case Study from West Kuwait
Triassic reservoirs in western part of Kuwait have flowed gas and condensates on testing. These
reservoirs are characterized by a complex suite of rocks consisting of dolostones, limestones,
anhydrites, shales and halite.
Conventional reservoir quality is poor as porosity and permeability are negatively affected by multiple
diagenetic events and can easily go undetected by most logging tools which are mainly designed for
conventional reservoirs. Also these occur at greater depths which require high pressure high
temperature drilling, small borehole design, use of oil based mud and specialized cementing practices.
As a result the availability of the full suite of logs is limited and the reservoir facies are difficult to
identify and evaluate quantitatively.
Additionally often salt plugging in both the surface test system and the downhole tubular impedes the
production and masks the interpretation of the gas zone. It was difficult to determine the true rates
from the well due to the high water cut and salt plugging and it is needed to investigate the source of
water production & causes of salt plugging and interpretation of Gas zone to continuous hydrocarbon
production.
Innovative and integrated workflows involving state-of-the-art technologies and incorporating wireline
logs, core, gas chromatography, fracture, thin section petrography, well test and mud logging data
have been employed for identification and evaluation of these reservoirs. These practices have been
instrumental in effective exploration and evaluation of tight, HPHT reservoirs and highlight the need for
synergistic workflows that need to be updated on continuous basis.
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Characterizing Rock Type Variation with Outcrop-Based Lidar Mapping of Permo-Triassic Carbonate Strata, Jebel Akhdar, Oman
Authors Erwin W. Adams and Jerome A. BellianA Permo-Triassic (Wordian-Induan) succession more than 700 m thick is exposed on the Saiq Plateau
in Jebel Akhdar, Oman. The outcrops provide an ideal opportunity to investigate the evolution of a
carbonate depositional system equivalent to important reservoirs in the Arabian Platform, such as the
Khuff Formation. On a field scale, Permo-Triassic carbonate strata in the Middle East are strongly
layered and correlatable over long distances (>10 km), comprising uniform stratigraphic thicknesses
and similar facies associations. Nevertheless, sedimentologic and diagenetic heterogeneity within the
layers is complex creating significant lateral reservoir property variations. The diagenetic overprint,
including cementation, leaching, and dolomitization can be linked strongly to the original sedimentary
texture and fabric governing distinct cement and pore types that define rock types. Most of the
succession exposed on Jebel Akhdar, except for the lower 120 m, is completely dolomitized.
Nevertheless, well-preserved precursor fabrics can be recognized in these dolostones. To help delineate
rock-type partitioning, ground-based lidar and high-resolution GPS were used to record geological
observations in 3D from the cm to km scale. The data were assimilated, visualized, and modeled to
create a digital outcrop model (DOM). A new method of supervised-automated feature extraction using
lidar was developed and tested to identify outcrop-based rock types on the basis of geometrically
corrected surface reflectivity (laser intensity) and roughness (weathering). These parameters were
used to classify outcrop-based rock types and subsequently populate the DOM. Laser intensity can be
used to discriminate fine- from coarse-crystalline dolostones correlative with mud versus grain-rich
textures. The link between intensity and outcrop-based rock types using grain size enables us to
constrain the geocellular outcrop models. These models can be used to reduce uncertainties in static
reservoir models and to test the effect of heterogeneity on dynamic behavior. In addition, the data and
technology can also be used to establish a virtual training dataset.
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Rule-Based Static Modeling of Shoal-Dominated Carbonate Reservoirs
Authors Erwin W. Adams and Claude-Alain HaslerSeveral important carbonate reservoirs in the Arabian Platform, such as the Khuff Formation, are
comprised of carbonate shoal geobodies. While it has been demonstrated that individual carbonate
sand geobodies are correlatable over large distances (more than 10 km) and can have uniform
stratigraphic thicknesses, the internal sedimentologic partitioning of texture and fabric is intricate. In
addition, diagenetic processes, which can either follow or cross cut the depositional architecture,
introduce another level of complexity by altering primary porosity and permeability. To better predict
the significant lateral reservoir property variations associated with carbonate shoal deposition and early
diagenetic overprints, a forward modeling approach is adopted. We choose to use cell-based forward
modelling aiming to reproduce both sedimentary and early diagenetic processes, since these processes
feedback and interlink through time during the development of the initial porosity and permeability
architecture. The cell-based rules that have been postulated are efficient in simplifying the interaction
of complex processes while creating emergent carbonate geometries. The model grid of the approach
can be defined at the scale of the relevant heterogeneities within a subsurface reservoir. The cell-based
forward modeling approach is supported with process-oriented input data from analogs to constrain
modeling parameters and by geometry-oriented studies to constrain fundamental geometries
associated with shoal deposition and early diagenesis. The analogs used are modern-day carbonate
banks, which display diverse external landscape geometries as well internal partitioning of
sedimentological properties. In addition, digital outcrop modelling is used to quantitatively validate the
emergent geometries produced by the cell-based forward models. The outcrop we studied is the
Permian Saiq Formation of the Akhdar Group exposed on the Saiq Plateau in Oman. This outcrop
provides an ideal opportunity to investigate and quantify relevant geometries such as height and
spacing of shoal crests and grain size distributions. Preliminary results are promising as model
geometries are mimicking observations made on these modern-day and outcrop analogs. The
combined forward modeling and quantitative analog approach tries to achieve a significant reduction in
the present uncertainties of spatial prediction of properties in shoal-dominated carbonate reservoirs.
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Capitalizing from the Benefits of Hybrid-System Acquisition Crews: A Mega-Channel to Multi-Target
Authors Roger Haston and C. Jason CrissHistorically, land seismic acquisition has been driven by logistical constraints rather than by the true
geologic imaging requirements. Although the initial ideas that motivate the shooting of a land seismic
survey are geologic in nature, most designs are driven ultimately by the practical limitations of the
equipment being used and the cost to deploy that equipment.
Cable-based systems are, in general, geared for single parameter shooting designs. The technical
complexity and operational constraints of cable-based systems significantly inhibit the ability of a
seismic crew to acquire these complex designs effectively. The adaption of cable-based systems to
dynamic design requirements introduces undesirable operational inefficiencies, resulting in an increase
in equipment, manpower and cost.
There are two efficient ways to achieve multi-parameter shooting: deploying independent nodes on top
of an existing cable-based design or deploying all independent nodes. Deploying recording stations
which are independent of cable constraints enables more complex and multi-parameter designs.
Independent recording nodes allow designs to be more geologically-driven for multiple objectives
without the constraints of channel limitations, cultural and environmental issues that inhibit cable deployment.
Cable-free equipment was integrated successfully into to a relatively large cable-based system
acquiring data in southeast Hungary near the small town of Gyula. One of the benefits of a passive
system is that integration, or slaving, into other systems is an easy process. The case history to be
presented will discuss the process of integration of the two systems in detail.
There has been much discussion of the need of for mega-channel crews (>50,000 channels) to be able
to solve the type of imaging problems the industry expects to face over the coming years. Hybridcrews
represent an obvious pathway that can capitalize on the advantages of both cable and cable-free
systems. Further, concepts like Dynamic Patch Roll that utilize the flexibility of a cable-free system to
create a patch within a patch to lower the amount of total equipment deployed provide a cost effective
method for achieving the imaging goals required by these mega-channel surveys. By utilizing the
advantages of hybrid-crews, the focus moves away from mega-channel and more onto mega-trace.
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Processing New Generation Seismic (NGS) in from Unlimited in-House Centre
Authors Richard Smith, Paul M. Zwartjes, Tom van Dijk, Nigel Benjamin, Teo Wah hong, Richard Cramp and Vic DhawanPetroleum Development Oman (PDO) has upgraded its seismic crews to enable high
channel count and high-productivity acquisition of wide-azimuth (WAZ), finely-sampled seismic data
(“New Generation Seismic”). These crews operate 24 hrs per day using simultaneous vibroseis sourcing
and are consistently setting world-class production records well in excess of 13,000 VPs per day. The
typical PDO WAZ survey acquired by these crews is approximately 2,700 km2 of 4000+ fold data in
25x25 m common midpoint bins. The resulting data volume per survey is approximately 25 billion
seismic traces and 130 Terrabytes.
As a result of these changes the volume of seismic data arriving at PDO’s In-House Seismic Processing
Centre each month has increased by a factor in excess of 10 in the last year alone. Currently the
processing centre receives over 20 Terrabytes of field data per month from two crews. This data
explosion has necessitated large scale upgrades to the processing centre, including substantial
increases in CPU capacity, network bandwidth and online and offline data storage. Total disk storage
for ongoing project work, for instance, is set to rise to 2.8 Petabytes. Despite upgrades, CPU demand
will outstrip local capacity and external resources will be accessed to provide the in-house centre with
“unlimited” CPU.
In addition to the hardware upgrades, geophysical software developments have been equally
important. These developments include data-adaptive ground roll attenuation, software to facilitate
azimuthal velocity analysis, a new 3D Radon multiple attenuation module and the implementation of
Common Offset Vector and 5D interpolation.
The transformation of PDO’s in-house seismic data processing centre to accommodate and fully utilize
New Generation Seismic will be described in this paper.
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Quartz Cementation in a Deep and Hot Sandstone Reservoir: the Devonian Jauf in Ghawar Field, Saudi Arabia
More LessThe estuarine to shallow marine sandstones of the Devonian Jauf Formation form a deep and hot gas
reservoir where clay coatings on detrital grains are essential for the preservation of porosity. In the
absence of clay coats, sandstones have lost almost all porosity due to massive cementation with porefilling
quartz. However, sandstones with extensively clay coated grains also commonly appear to
contain high percentages of quartz cement, which is thought to have nucleated on detrital quartz
grains at breaks in the clay coats and then grown out into the adjacent pore space. The origin of quartz
cement in the clay-coated sandstones and the controls on clay coat distribution are the focus of
ongoing research.
The development of quartz cement in the Jauf reservoir was studied by measuring clay coat surface
coverage of quartz grains in a suite of samples encompassing the range of quartz cement content and
porosity values. It appears that sandstones with less than 90 % surface coverage are pervasively
cemented with quartz, causing almost complete porosity loss in those samples. In those samples, large
parts of the quartz grain surface were unprotected, allowing quartz to nucleate on many detrital quartz
grains. Porosity is only preserved in sandstones with clay coat surface coverage above 90 %. These
samples show a rough trend of decreasing quartz cementation with increasing clay coat coverage,
although quartz cement abundance displays considerable variation for any one clay coat coverage
value. This suggests that breaks in clay coats played a profound role in quartz cementation, although
other factors could also be important.
In practice, the frequency of breaks in clay coats may be evaluated by counting the number of quartz
grains showing associated quartz cement in a thin section. This was tested on an abundantly quartzcemented
sandstone with measured clay coat coverage of 99.8 %. This sample contains a high
frequency of quartz grains with associated quartz cement, suggesting the frequent occurrence of
breaks in clay coats. The frequent breaks would have facilitated the extensive quartz cement growth.
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Petroleum System and Hydrocarbon Potential of Deep Areas Sirte Basin, Libya
Authors Idris A. Abulkhir and Fauzi A. El HajSirte Basin, situated in the north-central part of Libya, is the largest oil producer in Africa. It was
developed as a series of NW-SE trending horsts and grabens (platforms and troughs) by the collapse of
the Sirte Arch in Lower Cretaceous time. Sirte Basin covers more than 500,000 square kilometers of
north-central part of Libya with recoverable reserves of 50 billion barrels of oil and about 40 TCFG,
considered as the most prolific basin in Libya. Exploration activities of Sirte Basin commenced during
late 1950s followed by the first commercial discovery in 1958 (Well A1-32). During the first half of
1960s most of the giant fields were discovered bringing Sirte Basin among the most oil productive
basins in the world.
This paper is the results of combining available geological, geochemical, and basin modeling studies
carried by the National Oil Corporation of Libya (NOC) and other companies, all indicating the presence
of several thick formations of organic facies of different age from Triassic to Paleocene. There is also a
possibility of deeper source rocks which have not been penetrated yet. Various depositional and
environmental conditions as well as different thermal maturities, organic matters, and richness are
reported in these source rocks.
Oil generation in the Sirte Basin started in Eocene time and still continuing in the shallower parts of the
basin. And hydrocarbon migration commenced in Oligocene. Hydrocarbon generations are mainly in the
trough areas as the oil kitchens. Migrations were vertically along the trough bounding major faults up
to the platform areas and further migrations were up-dip into the present structural positions.
Two major discoveries (North Gialo and Block NC98) were made by Waha Oil Company in the deep
areas of the Sirte Basin recently. These are very encouraging indications that still high hydrocarbon
potential exists in the deep trough areas to be discovered by the applications of 3D seismic and
detailed sequence stratigraphy. The estimated hydrocarbon generations and expulsions of the multiple
source rocks of the Sirte Basin are by far exceeding the estimated hydrocarbons found so far (oil inplace
140 billion barrels and estimated gas in-place 60TCF). Therefore, further hydrocarbon discoveries
are expected in forms of structures and/or stratigraphic traps particularly in the deep trough areas.
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A New Era in Land Seismic for the Middle East and Beyond
Authors Timothy Keho and Panos KelamisIn the recent past, the seismic technology focus has been on the marine environment, particularly
deep water. However, we are about to enter a new, exciting era in land seismic for the Middle East and
beyond due to four key trends: world growth in energy demand; exploration and development focus on
low-relief structures, stratigraphic traps, and horizontal well placement; advances in seismic acquisition
technology; and advances in seismic processing due to continually expanding computer capability.
World population growth and rapid economic development in emerging economies will lead to greater
demands for energy. This will motivate more investment in exploration and in increasing recovery
factors for existing fields, which will renew interest in areas where hydrocarbon potential occurs in land
environments.
As large structures are drilled, focus will turn to low-relief structures and stratigraphic traps. These
play types require accurate near surface velocity models for depth conversion. The use of horizontal
wells for field development will continue to grow. The high quality seismic attribute maps required for
placing horizontal wells will motivate solutions for data quality problems originating in the near surface.
This new era will require solutions to near surface challenges, such as energy penetration, scattering,
source generated noise, surface generated multiples, statics, and source and receiver coupling.
Solutions to these problems will become possible due to advances in simultaneous source acquisition
and wireless seismic driven ultra-high channel systems. Within a few years 100,000 channels will be
common. These technologies will lead us to our ultimate goal - acquisition of true 3D data with point
source/receiver, full azimuth, long offset, high density geometries.
Growth in computational capability will foster advances in seismic processing technology for the huge
data volumes that will be one or two orders of magnitude larger than today. Advances in computer
capability will make non-travel time based methods, such as full waveform inversion, practical for
aiding determination of near surface velocity models. Joint inversion with micro-gravity and other nonseismic
data types will become more common. Ultra-high channel counts and point receivers will create
new opportunities in multi-component acquisition and processing. And finer spatial sampling will allow
the near surface to be addressed more commonly as an imaging problem.
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Paleozoic Volcanic Reservoirs of Libya: A Case Study of the Cambro-Ordovician Hofra (Gargaf) Facies of Sirte Group Reservoir, Tagrifit (Ora) Oil Field
More LessCambro-Ordovician Hofra (Gargaf) reservoir of Sirte Group at the Tagrifit (Ora) Oil Field in Central
Sirte Basin is a faulted and fractured North Northeast-South Southwest trending pre-Upper Cretaceous
buried hill. Production history of the reservoir reflects rapid oil production decline curve, early water
encroachment or coning with spots of high peak oil production rate that overlaps with spots of high
cumulative oil production. Such production pattern is common in fractured reservoirs.
The Sirte Group reservoir of the Tagrifit field is lithologically composed in order of abundance of:
1. Orthoquartzite-Quartz-Arenite.
2. Volcanics which are composed of:
a. Porphyritic Rhyolite.
b. Porphyritic Rhyolite-Dacite.
c. Pyroclastic volcanic Tuff and Ash beds.
3. Orthoquartzite breccias in Quartz Arenite matrix.
The reservoir is dissected by a major fracture system (probably striking northwest-southwest and
dipping southwest) and secondary fracture system (probably striking northeast-southeast and dipping
southeast) which provided essential permeability and porosity to produce the Orthoquartzite Quartz
Arenite facies and enhanced the permeability of porous-permeable white Rhyolite-Dacite volcanics.
The study integrated the production history with the available reservoir parameters and concluded that
thickness of producing open-hole sections had no effect on the peak production rate and cumulative
production of oil, and that the main controlling factors of Sirte Group high peak production rate and
high cumulative production within the structural closure of Tagrifit Oil Field are:
1. The presence of matrix poro-permeable Rhyolite-Dacite volcanic facies.
2. The presence of fracture poro-permeable Orthoquartzite Quartz-Arenite facies.
Volcanic rocks are reported in Cambro-Ordovician sandstones reservoirs of the Paleozoic basins of
Libya, their significance and contribution to the production pattern of these reservoirs can be predicted
from the production pattern of analogous volcanic facies in Cambro-Ordovician quartzitic reservoirs of
Tagrifit, Amal, Augila and Nafoora Oil Fields.
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Reducing Uncertainties of in-Place Hydrocarbon Estimates through Proper Monte Carlo Simulation Design: A Case Study
More LessMonte Carlo simulation (MCS) is one of the commonly used methods that provide in-pace hydrocarbons
(IPH) estimates with a measurable uncertainty. Any error in MCS design would lead to an error in the
results. MCS methods are widely covered in the literature, but only few comprehensively cover all
aspects of MCS design and its impact on the results. This paper is divided into two parts: theoretical
and practical; to illustrate the importance of proper MCS design as applied to an actual case study.
In the theoretical part, the major steps of MCS design are discussed in detail and an optimum
procedure is presented. Critical parts of the MCS design, such as number of Iterations and key input
variables selection are presented. Also, dependencies between input parameters, ranking methods and
results are defined.
In the second part, an actual case study is carried out where the theoretical part is applied to field data
taken from an Australian gas field. Twelve cases were designed from the field data to test different
MCS designs. Each case has different input data, distribution shape and dependencies. Also, two
different probabilistic estimates ranking methods, which are the ‘(P10-P90)/P50’ and the ‘Coefficient Of
Variance’ methods, were evaluated. The results indicate that fitting the distributing shape and
truncating it based on the mean of the input properties gave IPH estimate that are higher and have
lower uncertainties compared to the other cases. Therefore it can be concluded that a proper design of
the Monte Carlo simulation results in the reduction of IPH estimates uncertainty.
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3D Geological Modeling in Saudi Aramco - Current Practices and Field Examples
Authors Mohammad A. Al-Khalifa, Abdulaziz Al-Gaoud and Nazih F. NajjarCurrent practices of advanced 3D geological modeling will be discussed and selected field examples will
be presented, where advanced 3D geological modeling technology was utilized. They include objectbased
modeling, seismic data integration, fracture modeling, and engineering dynamic data integration.
3D geological modeling is the science of creating 3D numerical representation of the subsurface and
quantitatively predicting reservoir properties. It plays a vital role in the modern oil and gas industry
with applications that span a wide spectrum, ranging from well planning and reserves assessment to
reservoir simulation and future production predictions. Input data for geological models come from
direct information, i.e., measurements of reservoir rock and fluid properties, and indirect information
such as interpretations and conceptual models. It is very challenging to integrate geological,
geophysical, petrophysical, and engineering data that are recorded at different scales, both vertically
and horizontally - from small scale core measurements to medium scale log data to large scale seismic
interpretations.
At Saudi Aramco, 3D geological models are actively used by reservoir geologists for horizontal and high
-slant well placement and geosteering. The models are updated frequently as new data and
interpretations from newly drilled wells become available. In addition, reservoir engineers use
geological models in their simulation studies to predict the flow and behavior of oil, gas, and water in
the reservoir to optimize production. Knowledge learned from fluid flow simulation is integrated back
into the static model to improve the distribution of reservoir properties. This iterative loop between
geological modeling and dynamic flow simulation is essential to generating the most accurate static
and dynamic models.
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Seismic Evidence of Strike-Slip Tectonostratigraphy in the Hawtah Field
More LessHawtah field is located in Central Saudi Arabia and constitutes a major structure within the Hawtah
trend. The main objective here is to study the paleo-structures which existed during the deposition of
the Lower Permian Unayzah formation and how they affected both its depositional thickness and
stratigraphy. Seismic impedance as well as seismic amplitude has been utilized to map the Unayzah
two-way time (TWT) structure of this complex field. The obtained TWT structure was then used to
compute different seismic attributes to gain insight about the internal reservoir fabric. The TWT
coherency map of the base Qusaibah hot shale indicates a clear presence of a dominating strike-slip
tectonic regime characterized by steep faults that penetrates the Unayzah formation at various levels
depending on the location of the fault within the field structure. Visual comparison between the base
Qusaibah coherency map and that of the reservoir suggests a possible link between the clearly
observed strike-slip faulting at the Qusaibah level and the thickness and lithology changes observed at
the reservoir level. The direct link between the two using seismic cross sections is a subtle issue, due
first to the complex reflectivity within the Qusaibah formation, and second, to the steep angle of the
existing faults, even though it is possible to carry it out successfully at many locations.
The reservoir impedance map, using seismic inversion, is consistent with the available FMI data at a
number of wells within the area providing additional evidence of the link between the observed
Qusaibah faults and the observed heterogeneity within the reservoir. The study concludes that the
entire Hawtah field is a large pop-up structure characterized by a strong strike-slip tectonic control on
both the sedimentology and the stratigraphy of the Unyzah reservoir. This is suggested by the
geometry of the bounding faults of the structure, and also the presence of intra-structure mixed
faulting modes (i.e., both normal and reverse). Careful mapping of the observed faults leads to a
better understanding of the reservoir heterogeneity and lithology, and therefore more robust flow
simulation models and the ability to plan more accurately future drilling operations.
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Facies Mapping within the Late Permian Khuff-C High-Resolution Sequence Stratigraphic Framework in Hawiyah, Ghawar Field; Implications for Reservoir Predictions
Authors Ghazi A. Al Eid and Aus Al TawilOver 7,000 feet of core in 24 wells in the HWYH, S. UTMN and N. HRDH areas in Ghawar were utilized
in a study to generate a high-resolution sequence stratigraphic and facies distribution framework for
the Khuff-C reservoirs. Four high-frequency sequences make up the Late Permian Khuff-C in Ghawar,
where each is bounded by well-defined sequence boundaries. Each sequence is made up of a
Transgressive Systems Tract (TST) and a High Stand Systems Tract (HST), separated by a mappable
Maximum Flooding Surface (MFS). Systems tracts are made up of mappable meter-scale shallowingupward
cycles, for a total of 32 cycles within the entire studied interval.
Two facies maps have been created for each of the 32 cycles across the entire studied area. Each cycle
has a facies mosaic map at the surface of maximum retrogradation and another at the surface of
maximum progradation. The accumulated result of all maps provides the spatial and temporal facies
distribution for the four high-frequency sequences that make up the long-term Khuff C composite sequence.
These are not interval maps but rather they are time-facies maps that represent the facies evolution,
position and facies migration (vertical and lateral) through time. The advantage of this mapping
technique is that it places facies within the context of their times of deposition during a particular event
of sea-level rise and fall, allowing better prediction of reservoir facies occurrences. One key control on
reservoir quality is anhydrite cementation, which works to destroy pore networks. Petrographic studies
suggest that such cementation is likely to have occurred at, or very shortly after, the time of
deposition of reservoir (grainstone) facies. This is demonstrated through the preservation of original
grains encased within tight anhydrite cement networks; all preserved porosity is otherwise moldic. The
high-resolution surface mapping suggests, through superposition of facies maps, that anhydrite
cementation is sourced through brine reflux processes from stacked, cycle-capping, tidal-flat facies
lying directly above. In a down-dip direction, the same stacked tidal flats sourced lighter, magnesiumrich,
brines that laterally dolomitized time-equivalent subtidal calci-silt facies.
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Regional Issues in Jurassic Pore Systems - Echinoderms, Syntaxial Overgrowth Cements and a Fifth Porositon
Authors Edward A. Clerke, Douglas Seedorf and Yasir MubarakRegional and well established carbonate geological and diagenetic processes are re-examined in
Jurassic carbonate reservoirs using the large amount of quantitative mercury injection capillary
pressure (MICP) pore system data acquired by Saudi Aramco in the last eight years. An extensive Berri
field data set included petrographic data and MICP pore system data obtained by Thomeer analysis.
The Berri data from four Jurassic carbonate reservoirs is compared to other data, and specifically the
Ghawar Rosetta Stone data using a regional depositional context. The anticipated increase of Jurassic
carbonate-rim cement to the North of Ghawar is evident. Much more important from a pore system
perspective are the amounts of syntaxial overgrowth cement and the correlative increase of
echinoderms and foraminifera in the Hadriya and Fadhili. These latter increases necessitate a fifth
porositon (F-ESO), an additional maximum pore-throat diameter mode in the Hadriya and Fadhili pore
system models, as compared to the four porositions that describe the pore systems of the Ghawar
Arab D limestone and the Berri Arab and Hanifa. Review of the Abqaiq petrographic and MICP data of
Ross et al. (1995) provide independent support for the four porositons of Clerke et al. (2008) and also
indicate the presence of a fifth (F-ESO) porositon in the Abqaiq Arab D.
The pore system effect of the predicted and present carbonate rim cements is imperceptible.
Echinoderm and foraminifera are very abundant in the Berri Fadhili and show a steady decrease in
abundance upward through the Berri Jurassic section, i.e., the Fadhili, Hadriya, Hanifa and the Arab.
Echinoderm abundance is closely linked to marine salinities and high magnesium calcite. Quantitative
determinations of echinoderm and foraminifera abundance are shown to be correlative to and useful as
a predictor of the pore destructive syntaxial overgrowth cement. Regional models of reservoir quality
distribution could potentially be improved using maps of high precision Ca/Mg ratio relating to the high
magnesium calcite of echinoderms and syntaxial overgrowth cements and maps of echinoderm
abundances and habitats. These regional maps could relate broadly and inversely to reservoir quality
and depositional salinity.
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Application of Magnesium Yield Measurement from Neutron Spectroscopy Tool in Formation Evaluation of Northern Kuwait Fields
Authors Djisan Kho, Mishari Al-Awadi, Mihira N. Acharya and Saad Al-AjmiEvaluation of porosity and lithology has always been done through a combination of density,
photoelectric factor (PEF), neutron, gamma ray, and sonic measurements. None of these gives porosity
or lithology directly. Therefore, common practice includes building petrophysical models to extract
these reservoir properties. Geoscientists involved in petrophysical analysis using multi mineral solvers
are aware of the difficulty and the uncertainty of the process; for example, changing a fluid property in
the model will change the lithology as well as the porosity. The logs themselves are also known to have
their own measurement uncertainties. The density log, for example, is affected by bad hole, lithology,
barite, and light hydrocarbons. The neutron log is affected by lithology, fluid hydrogen index, and the
borehole properties (temperature, pressure, hole size, stand-off, mud cake, mud weight, etc.). The
interpretation is also complicated by the fact that different neutron tools from different logging
companies have different sensitivities to lithology. Sonic log data is also used for interpretation even
though it is affected by fractures, vuggy porosity, anisotropy, etc. The PEF curve is commonly used as
an additional tool to solve for the lithology. However, if the mud contains barite the measurement
becomes unusable.
Dolomite and solid bitumen quantification has been the challenging issues in carbonate evaluation. The
dolomite diagenesis involves the recrystallization which makes the dolomite less susceptible to porosity
reduction caused by overburden pressure. This unique characteristic of the crystallized dolomite makes
it as an important reservoir rock especially in deep carbonate reservoirs. On the hand, the presence of
solid bitumen is always associated with poor reservoir quality. Also, the physical properties of the solid
bitumen cause it to appear as hydrocarbon. If not corrected, the formation evaluation result will give
incorrect porosity and water saturation computation.
New development in neutron capture spectroscopy tool provides significant data to quantify the
mineralogy in carbonate, especially the dolomite content through magnesium yield measurement.
Combination of the spectroscopy data and magnetic resonance data can be used to identify and correct
the solid bitumen effects. Real examples from deep carbonate reservoir in northern Kuwait fields and
the validation against core data will be presented.
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A 32,000 Channel 3D Vibroseis Field Test - Where Is the Signal?
More LessWith the dramatic increase in recording channels and improved productivity methods for Vibroseis
surveys, we can effectively record the full signal and noise seismic wavefield without aliasing. To
evaluate the cost/operations/data quality benefit ratio for high source/receiver density acquisition
designs, Saudi Aramco performed a field test with an effective 32,000 channel Vibroseis survey design
over a known oil and gas development field. The source and receiver line intervals were 100 m
(orthogonal) with 25 m source and receiver station intervals. Three vibrators were used per source
point with a linear upsweep from 4 to 94 Hz to acquire well-sampled, wide-azimuth data with inline
offsets up to 5000 m and cross-line offsets up to 4000 m.
The field test area was specifically selected to observe the benefits of dense spatial sampling over
regions with high amplitude surface waves and back-scattering caused by a complex near-surface. In
addition, we analyze the minimum signal-to-noise level required per trace or ensemble to balance and
preserve the surface-consistent signal bandwidth for a range of decimation volumes. These volumes
simulate either finer spatial sampling or some of our legacy seismic data volumes and are referenced
to our most recent vintage 4,000 channel survey design over the same area.
In this presentation, we demonstrate the effects of variable spatial sampling on signal-to-noise, signal
bandwidth, and interpreted reservoir properties at the oil target.
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Real-Time Petrophysical Integration of NMRWD, FPWD and LWD Triple-Combo in Slim Holes
Authors Yousef M. Al-Shobail, Doug Seifert, Ridvan Akkurt and Saleh DossariReal time petrophysical analysis in slim hole wells is complicated by the presence of heavy oil and tar
zones and the availability of the slim logging tools. The reservoirs in this case study contain heavy oil
and tar in the flanks, and accurate knowledge of viscosity trends becomes essential for the placement
of water injectors. The “tar mats” create a permeability barrier between the water and desired oil.
Optimal pressure support and oil recovery from water injection into these reservoirs requires the well
trajectory be kept as deep as possible in the producible oil column while at the same time, not
encountering the heavy oil or tar mat.
The geometry of these heavy oil and tar deposits have been mapped with previously drilled vertical
wells that act as control points. These wells indicate that the tar mat is neither flat nor uniform in
thickness. Additionally, the well data show an increase in the oil viscosity with depth from the field oil
to the tar mat. Injectors need to be placed in the injectable zone close to the heavy oil tar boundary to
have a good pressure support and obtain desired injection rates and sweep efficiency.
Recent developments and innovations in 4-¾” Logging While Drilling (LWD) technology are allowing for
the better placement of wells. The development of Formation Pressure While Drilling (FPWD)
measurements has shown that formation pressure pretest information can be used to identify
unintentional penetration of the impermeable zone. The more recent introduction of a Slim Hole
Nuclear Magnetic Resonance While Drilling (NMRWD) tool and the development of an in-house
methodology, allow for the characterization of the hydrocarbon components and prediction of the
hydrocarbon viscosity.
The petrophysical integration of real-time formation pressure tests, mobility and viscosity information
along with NMR fluid characterization are being used to optimally place and steer wells, to minimize
contact with the immoveable hydrocarbon, to improve well injection performance and oil recovery.
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Early-Middle Jurassic Marrat Formation Onshore Kuwait: A Depositional Sequence Stratigraphic Framework
Authors Ghaida A. Alsahlan, Abdulkader Youssef, Adi P. Kadar, J.P.G. Fenton and Paul MarshallA high resolution investigation, comprising stratigraphy (biostratigraphy and Strontium isotope
analyses) and sedimentology, of 19 onshore wells in Kuwait has been undertaken. Data from c. 500
core and cutting samples have been integrated with electric wireline log data to establish a
biostratigraphically constrained depositional sequence stratigraphic framework for the tripartite Marrat
Formation of Kuwait. The Marrat Formation rests unconformably on the Minjur Formation, which is no
younger than Hettangian in age. A further hiatus is identified at the base of the overlying Dhruma
Formation, with the probability of some Bajocian strata missing.
A locally applicable microfaunal biozonation has been established for the Marrat Formation, comprising
three zones. The Pseudocyclammina maynci Zone, of Aalenian age, characterises the Upper Marrat.
The Siphovalvulina spp. Zone, of early - middle Toarcian age characterises the bulk of the Middle
Marrat, while the basal part of the Middle Marrat and the upper part of the Lower Marrat is
characterised by the Amijiella amiji Zone (early - middle Toarcian to Pliensbachian - Sinemurian). The
latter zone is tentatively divided into two subzones: the A. amiji and Haurania deserta Subzones.
Palynofloral, nannofloral data and Sr isotope analyses have assisted in age determinations with varying success.
A wide range of shallow, neritic to supra tidal facies are identified. Eleven depositional sequences have
been recognized, most of which are considered to be of third order hierarchical status and calibrated
where possible to those of Gradstein et al. (2004). The Lower Marrat essentially comprises informal
Sequences Si-Pl1 to Si-Pl3 and Sequence Pl8. The uppermost part of Sequence Si-Pl3 and Pl8 are well
constrained using biostratigraphy and Sr isotope results, being dated as earliest late Pliensbachian and
earliest Toarcian respectively. The uppermost part of the Lower Marrat and the Middle Marrat comprise
at least four third order sequences (Toa1 to Toa4), with an early - middle Toarcian age range. An intra-
Marrat Formation unconformity occurs at the base of the Upper Marrat, with the latter comprising three
third order sequences (Aa1, Aa2 and Bj1-Bj2). While the lower two sequences are confidently dated as
Aalenian, the youngest sequence is poorly age constrained.
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High-Resolution Sequence Stratigraphy of the Late Permian Khuff-C in Hawiyah, Ghawar Field
Authors Ghazi A. Al Eid and Aus Al TawilFour high-frequency sequences make up the Late Permian Khuff-C in Ghawar, where each is bounded
by well-defined sequence boundaries on core and logs. Each sequence is made up of a Transgressive
Systems Tract (TST) and a High Stand Systems Tract (HST), separated by a mappable Maximum
Flooding Surface (MFS). Systems tracts are made up of mappable, meter-scale shallowing-upward
cycles, for a total of 32 cycles within the entire studied interval.
Khuff-C1 (KC1) is made up of 10 mappable cycles, where the TST of each cycle starts with flooding
storm beds and restricted dolomudstones that shallow-up to a regional tidal flat cap. The MFS is totally
dolomitized distal lime-mudstone, passing into cross-bedded grainstones. The HST is made up of
prograding grainstone overlain by restricted lagoon and tidal flat mudstones.
Khuff-C Sequence 2 (KC2) consists of seven cycles and is defined by an initial transgressive set of
restricted cycles with storm influenced facies deposited over the thick, extensive tidal-flat sediments of
KC1, which extend field-wide across Ghawar. The middle cycles are made up of storm beds and
intensely burrowed shallow sub-tidal pellet packstones, deepening to dominantly open marine limemudstone
(MFS), and shallowing-up to sand-flat low angle cross-bedded to burrowed peloid
packstones. The upper cycle is made up of shallow sub-tidal embayment lime-mudstone shallowing-up
to breccciated Paleosol, which is the sequence boundary of KC3.
Khuff-C Sequence 3 (KC3) is made up of 10 cycles with four initial transgressive peri-tidal cycles of
lagoonal dolomudstone capped by crinkly laminated to mud-cracked dolomudstone tidal flat facies. This
is overlain by a back-stepping cycle-set of grainstone with their distal bryzoan lime-mudstone
equivalent (MFS). The HST of KC3 is marked by shallow sub-tidal sand flat facies prograding over distal
open marine lime-mudstone. KC3 is marked at the top by a paleosol which also extends across Ghawar.
Finally, Khuff-C Sequence 4 (KC4) consists of five mud-dominated cycles. The base of this sequence is
bounded by a field-wide exposure surface of KC3. The TST is represented by transgressive peri-tidal to
shallow sub-tidal cycles while the prograding grainstones and the anhydrite behind define the HST.
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Multi-Tool Approach to Well Placement in a Heavy Oil Column of the Manifa Field - A Case Study
Authors Mohammad H. Sarraj, Arun Garg, Abdelmoneim B. Badri and Abd Khair Abdul AzizManifa field is located north of the giant Ghawar field in the Eastern Province of Saudi Arabia. The field
is currently under development with more than 300 wells planned for drilling in two major reservoirs,
the Manifa (Upper Jurassic) and the Lower Ratawi (Lower Cretaceous). An approximately 30 to 40 feet
thick column of heavy oil exists in both of these reservoirs. The well test records indicate that the oil
quality degrades towards the flanks of the structure causing complexities in wells placement, especially
for power water injector (PWI) wells. A multi-tool approach has been applied to address the challenge
of placing the PWI wells to achieve the targeted water injection rates.
The successful approach to optimally placing PWI wells combines the use in real time of: a) formation
pressure while drilling (FPWD) for measuring formation pressure and fluid mobility, b) slim-hole
nuclear magnetic resonance (NMR) for providing the free and bound fluid volumes as input to a
viscosity model, c) pyrolytic oil productivity index (POPI) for computing apparent API gravity of the oil,
and d) logging while drilling (LWD) for calculating parameters such as permeability.
Using this multi-tool approach, a significant number of PWI wells have been drilled and geosteered
through sections with a heavy oil column. To date, the injectivity test results of both short and long
term duration have been encouraging.
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Coalbed Methane (CBM) Prospect in Jamalganj Coal Field, Bangladesh
More LessMethane and coal are formed together during coalification, a process in which plant biomass is
converted by biological and geological forces into coal. The Methane that is stored in coal seams and
the surrounding strata are released during coal mining.
Although coalbed methane (CBM) technology is yet to start in Bangladesh there is a good prospect of
CBM development in certain coal fields especially in Jamalganj coal field. The high-volatile to mediumvolatile
bituminous coal of Jamalganj coal field is very suitable for CBM exploration in terms of their
depth of occurrence, thickness of coal seam, coal reserve and areal extent. The thickest seam III (over
40m ) can be a primary target for CBM development especially where it combines with seam IV in the
eastern part of the coalfield. However, there are a number of unknown factors like actual gas content
of coal, the coal permeability, and in-seam pressure that should be evaluated before the commercial
CBM development.
In fact, interest in CBM development in Jamalganj coal field was shown by a multinational company. In
early 1990s, the company submitted a proposal for undertaking exploration and development of CBM
in Jamalganj coal field. They projected a conceptual target of producing 26 billion cubic feet gas per
year. Accordingly, the total gas that could be produced would be about 340 bcf (0.34 Tcf ). However
there was no report of a positive negotiation between the company and the Government of Bangladesh
subsequent to the submission of the report.
Bangladesh is now badly in need of energy resources for her growing economy, that’s why CBM
exploration in Jamalganj coal field can be a very good option. It can provide natural gas that is
equivalent to a small size gas field compared to eastern Bangladesh gas province.
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A Model for Gas Migration into the Khuff Reservoirs
More LessIn the Arabian Gulf region, the distribution of gas accumulations in the Permo-Triassic Khuff
Formation roughly coincides with the distribution of the terminal Proterozoic (Eidacaran)
Hormuz salt basins. This is attributed to the breaching of thick shale/ carbonate/ anhydrite
seals at the base of Khuff Formation by faults that propagated upwards into the Khuff during
the initial development of high-relief salt domes. Once gas entered the Khuff reservoirs, it
migrated laterally into available structures and also spilled towards the edge of the salt
basins, where it was trapped in the initial line of structures along the flanks of the salt
basins. For example, the Khuff gas in the Ghawar structure, which is located to the west of
the Northern Gulf salt basin, was charged laterally from the northeast by progressive
spillage through the Qatif and Abqaiq structures. This is indicated by several lines of
evidence such as the absence of Khuff gas in structural closures located to the west, east,
and south of Ghawar, the presence of effective seals at the base of the Khuff, and the
difficulty in charging the Khuff reservoirs vertically through reactivated Hercynian faults
that also trapped gas in the underlying Permo-Carboniferous and Devonian sandstone reservoirs.
On a regional scale, this model accounts for the spatial association of the Khuff gas
accumulations with the salt basins, and the more widespread presence of gas in Paleozoic
(pre-Khuff) reservoirs both within and outside the salt basins.
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Reservoir Characterization Contributions to Develop Khurais Complex, the Largest Increment in Ksa - a Story of Success
The Khurais complex is located in the central part of the Kingdom of Saudi Arabia, about 250 km
southwest of Dhahran and 80 km to the east of Riyadh. It consists of three main fields: Khurais, Abu
Jifan and Mazalij. Khurais field is the largest among these fields, Approximately 90 km long and
between 5 and 18 km wide. This is the second largest onshore oil field in the Kingdom preceded by
Ghawar field. It was discovered in 1957, while Mazalij and Abu Jifan were discovered in 1972 and
1973, respectively.
One of the key aspects of the Khurais complex development plan is the proper selection of well
locations. This presents three major challenges from the perspective of reservoir characterization,
namely : the subsurface structure, reservoir quality and fluid contacts. New geophysical data recently
acquired made a significant impact in defining the structural geometry and depth uncertainties required
for well placement, and in identifying the fractured areas, which are most probable within the field’s
boundaries. Full-fold 3D seismic data was integrated and interpreted over the entire complex to assist
in this process.
Recent reservoir characterization studies have focused on defining reservoir quality variation in core
data, well log data, seismic data, Image log analysis, facies mapping, gravity data and magnetic data.
The product of these studies is a new fully-integrated conceptual model that contains facies
distributions, reservoir quality indicees, fracture analysis, structural Analysis, detailed stratigraphic
correlations and hydrodynamic information.
Reservoir characterization provided technical operations support during the development of this
increment on a 24/7 basis spanning two years in time. A large number of wells were planed and
maintained in multiple databases and more than 300 wells were geosteered and monitored with
thousands of footage of reservoir contact.
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Depositional Environments and Sequence Stratigraphy of the Aptian/Albian-Lower Campanian Platform to Basin Domain in the Sarkan and Malehkuh Fields in Lurestan, Southwest of Iran
More LessThe purpose of this study was to determine the microfacies, depositional environments and sequence
stratigraphy of the Aptian/Albian-Lower Campanian carbonate platform and of the adjacent basin in the
Sarkan and Malehkuh fields, located in the southeastern part of the Lurestan area in the Zagros Basin.
The ultimate goal is to define the trend of reservoir facies on two transects from five wells of Sarkan
and four wells of the Malehkuh fields, developed based on the available published data. At least twenty
one microfacies along the outer platform/ramp to the basin profile were identified. Five major thirdorder
sequences (from oldest to youngest Ι, ΙΙ, ΙΙΙ, ΙV and V) were identified. In Malehkuh wells the
sequence ΙΙ is a hiatus. Sequences Ι and ΙΙ are represented by the Aptian/Albian-Cenomanian top of
the Garau and Sarvak Formations. Sequence ΙΙΙ corresponds to the Turonian Sarvak Formation.
Sequence ΙV is exclusive to the Coniacian Surgah Formation. Sequence V is delineating the Santonian-
Lower Campanian Ilam Formation. Each of the third-order sequences is comprised of transgressive and
highstand systems tracts. Two transects were established in order to show the relationship among the
identified sedimentary sequences. The best potentials for the hydrocarbon reservoir are found in the
bioclastic toe/base-of-slope aprons and rudist reef formed during the Albian-Cenomanian high stands
and fractured and bioturbated interval within the Surgah and Ilam Formations.
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Cost-Effective, High Density, Wide Azimuth Seismic Sampling
Authors Turki M. Al-Ghamdi, Peter I. Pecholcs and James A. MusserWith most of the giant oil and gas four-way closure reservoirs discovered on land, we are now
challenged with generating low-relief stratigraphic prospects from sparsely sampled spatial grids. To
reduce risk, we propose a cost-efficient sampling scheme, which provides a full range of source and
receiver offsets over a full range of azimuths within a square patch. This increase in source and
receiver density is achieved by reducing the number of geophones per station, increasing the number
of Vibroseis fleets, and using a combination of Slip-Sweep, Independent Simultaneous Source (ISS),
and Distance Separated Simultaneous Source (DS3) recording techniques to maintain high production
levels and high trace density for improved seismic data quality at reservoir objectives.
Recent field tests have shown that a reduction in the number of sensors per receiver group combined
with an increase in source/receiver sampling density has a minimal impact on seismic data quality.
Such trade-offs shift the main focus of random and coherent noise attenuation from the field arrays to
the processing center. With the increase in recording channels and the reduction in the number of
geophones in the field (or the use of single digital sensors per station), the overall cost of a seismic
crew is minimally impacted.
To achieve the optimum wide azimuth square patch design, Vibroseis source points (VPs) can be
positioned outside a dense receiver line patch. Although the source stations in such a design are
typically reoccupied, the overall source productivity can be doubled (or better) by using two or more
simultaneous Vibroseis sources separated by the width of the patch. This distance separation will also
reduce interfering cross-talk and harmonic noise interference from the other Vibroseis sources.
Equivalent sensor roll-rates can be easily achieved by reducing the source line interval (and increasing
the resulting source density for better sampling). This balance between source and receiver effort
provides a superior spatial sampling grid with minimal impact on existing seismic crew configurations.
We show how this new seismic crew configuration and design provides superior reservoir
characterization with only an incremental increase in survey cost.
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Modelling Burial, Thermal and Maturation Histories in Sedimentary Basins for Hydrocarbon Generation: the Galo System
Authors Monzer Makhous, Yurii Galushkin and Paul RodeThis investigation is devoted for basin analysis and one- and two-dimensional modeling of burial,
thermal and maturation histories in sedimentary basins in a scope to evaluate their hydrocarbon
potential. A new original system is elaborated and applied for continental basins: North African basins,
East European basins (West Siberian, South Barents, and the Volga-Ural-West Bashkiria), basins of
passive continental margins in South America and Pacific Australian Antarctica and back-arc basins
(Philippine Sea basins in the East Pacific and Bering Sea basins in the North-West Pacific). The full
paper will be focused on modeling maturation histories of North African basins for evaluation of
hydrocarbon generation history and potential.
Particular attention is focused on specific features of basin evolution: compaction of sediments
deposited at a variable rate, erosion of the sedimentary strata and basement, intrusive and
hydrothermal activity, thermal activation and reactivation of the basement, lateral heat exchange of
multiple-aged blocks of oceanic and continental lithospheres, the jumping of spreading axes, etc.
Alternative methods are applied for control of tectonic subsidence, isostasy and rheology, lithosphere
stretching and thinning, spreading jumping, evaluation of erosion heat, its impact on the thermal
history and links to pre- and post-sedimentation history. Intrusion and hydrothermal activity,
formation and degradation of cryolitic zones (permafrost) in high latitude basins of the Northern and
Southern Hemispheres are modeled in a scope to evaluate their contribution to the thermal history of
basins. Joint analysis of heat flow transfer in the sedimentary cover and the underlying lithosphere and
astenosphere are applied and recommended for better reconstruction of the thermal and maturation histories.
A new approach is applied in the fitting procedure for determination of kinetic reaction parameters of
hydrocarbon generation, applying algorithms with variable frequency factor and integrating geological
stage of organic matter maturation for better estimation of hydrocarbon output.
Measured and calculated vitrinite reflectance by kinetic models and present-day temperatures are used
as main thermal indicators for the modeling control. Maximal temperatures estimate, based on clay
mineral assemblage (and some zeolites), particularly on crystalline polytype features, are used as
complementary independent control parameter.
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Sedimentology, Diagenesis and Reservoir Characteristics of Eocene Carbonate, Sirt Basin, Libya
Authors Giuma H. Swei and Maurice TuckerAbstract: Hydrocarbons in the Sirt Basin Libya have been found in multiple clastic and carbonate
reservoirs from Precambrian to oligocene age. The middle Eocene Nummulite accumulations of Gialo
Formation form important hydrocarbon reservoir interval within the Mesozoic-Cenozoic Sirt Basin that
originated as large scale subsidence and block faulting commencing towards the end of the Early
Cretaceous and continued to develop into the Miocene and perhaps to the present day. Reducing risk in
exploration demands an understanding of reservoir facies development, which is governed by the type
and distribution of depositional facies and their diagenetic history. Six depositional facies have been
identified in respect with the detailed core description, petrographic texture and the faunistic
assemblage. These are: Nummulite Facies, Nummulitic Discocyclina Facies, Nummulitic Operculina
Facies, Discocyclina-Nummulite Facies, Bioclastic facies and Mollusca Facies. These facies and
microfacies can be interpreted as having accumulated in open marine, fore-bank and bank setting.
Well preserved large benthic foraminifera dominate the faunal assemblage in the Gialo Formation
indicates deposition within the photic zone. Present day reservoir characteristics of the Gialo Formation
are the net result of modification to the original depositional characteristics caused by diagenesis.
Theses diagenesis took place on the seafloor, under burial, and in the meteoric diagenetic
environments. Petrographic and petrophysical studies indicate that porosity and permeability in the
Gialo Formation reservoir are the result of the depositional environments of deposition and diagenesis.
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Chemostratigraphic Differentiation between Fluvial and Shore-Face Sands as a Real-Time Geosteering Tool in the Albian Upper Burgan Formation, Minagish Field, West Kuwait
Authors Taher EL-Gezeery and Christian ScheibeThe Albian Upper Burgan Formation of Minagish Oilfield consists of siliciclastic sediments, which were
deposited in fluvial and tide influenced deltaic to shore-face environments. The uppermost unit of the
Formation (U1) is characterised by bioturbated, glauconitic shore-face sands, which are mostly
argillaceous and of poorer reservoir quality. The sands (U2 to U4), consist of:
1) Channel fill sand-bodies with good to excellent reservoir qualities.
2) Sandbar complexes with fair to good reservoir qualities.
Both of the latter facies are influenced by tidal processes that reworked the sediments at time of
deposition. This complexity of the channel geometry makes targeting and the drilling of the best
reservoir facies a serious challenge. Using elemental Chemostratigraphy that uses whole-rock inorganic
geochemistry to characterise and differentiate sedimentary units. This team manage to identify
“geochemical proxies” that distinguish fluvial from tidal shore-face sands of the Burgan reservoir.
Furthermore, the geochemical proxies also differentiated the apparently monotonous sandstone
packages into distinct sub-units that are linked to the underlying mineralogy, e.g. Glauconite and
Dolomite, as described in petrographic studies.
Chemostratigraphy has advanced into a proven real-time application that can be utilised:
1. For improved borehole positioning while drilling.
2. Geochemical data produced from near real-time analyses of cuttings samples (LIBS and ED-XRF) are
successfully used for monitoring and optimizing the wellbore in highly deviated wells through Wara and
Burgan reservoirs drilled in the Field.
3. Applied in slim-hole wells, for which no 'gamma ray at bit' or 'resistivity at bit' tools are available.
In a recent 4¾" borehole, chemostratigraphic data were used for geosteering and correcting the well
path within the Upper Burgan unit U3.
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Horizontal Wells Optimize Production in a Super K Sandstone Reservoir Minagish Field, West Kuwait
Authors Taher EL-Gezeery and Abdulaziz IsmaelBurgan reservoirs of Minagish Field are clastic sandstone reservoirs with super-K permeability. The
upper reservoir layer consists of fluvial sandstones with grain sizes ranging between medium to coarse
sands. The average porosity is about 28% to 35% and the average permeability varies between 0.7 to
10 Darcy. This reservoir has been a challenge due to early water breakthrough resulting from coning
effect. This paper presents a case study where horizontal well technology has been used to mitigate
risk of water coning besides enhancing productivity. At the early stages 6 vertical wells are completed
in Burgan with low production rates. Water coning was a major problem because of the homogeneous
massive nature of the sand bodies that probably have Kv/Kh ratio close to 1. The high ratio between
the oil viscosity and the water viscosity is also a major reason of coning.
Although the first horizontal well drilled in 2005 with 950 feet of net pay achieved unprecedented
production rates, production life was short due to several factors where low stand-off with OWC and
high off-take rates resulted in water coning accentuated by the presence of a fault acting as a conduit
for early water breakthrough.
The second horizontal well was completed at the upper most part of the reservoir where rock quality
has shown a gradation of facies from marine silts and shales to fluvial clean sand package. Only 300ft
of the heel out of 1000ft horizontal section has been penetrated.
Taking into account control on production rates, standoff from the overlying marine shale above and
the oil water contact with no significant faulting to be encountered at the sweet spot, five horizontal
wells were drilled and completed very much successfully, achieving a dry oil production and minimized
the possibility of water conning.
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A Vision for Future Upstream Technologies
More LessThis paper presents my vision of the most influential technologies for the next two decades. Unabated
global demand for energy will translate into growing demand for traditional hydrocarbon resources.
This growing demand represents a significant challenge to which the industry must respond. Several
companies have announced ambitious expansion plans for the next several years. However, demand
growth is expected to be a long-term phenomenon, for which new technologies must be developed to
increase the effectiveness by which hydrocarbon resources are found, developed, and produced.
The paper briefly reviews technologies that I consider the most influential in the past decades, namely
3Dseismic data, horizontal drilling, and geosteering. Each of these technologies has had a profound
effect on the industry, emerging from humble beginnings to mainstream applications. Next, I discuss
my vision of the potentially most influential future technologies. These technologies include extremereservoir-
contact wells, smart inflow-control devices, autonomous fields, passive-seismic monitoring,
gigacell simulation, smart fluids, bionic wells, and nanorobots. Though most of these are just dreams,
significant strides that have been made to achieve them are highlighted.
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Pathways and Possible Impacts of Accidental CO2 Subsurface-Leak in Sabkha’s Environment, Qatar
Authors Fares M. Howari, Abdulali M. Sadiq and R. Al-ThaniIn Qatar, the industrial and energy sectors depend mainly on fossil fuels, the main cause of carbon
dioxide (CO2) emissions. Though the rate of development is high, the lake of arable land and water
resources prevent the development of carbon sinks, forests, and green areas. However, their is no
doubt that Qatar share responsibility with the rest of the world for climate change and hence is working
to diversify the energy pie and look for more environment-friendly energy sources, and shares
responsibility of carbon management. Doha Bank, for example, is planning to launch the Arabian Gulf’s
first carbon credits exchange in 2009/ 10 to tap an emerging market for emissions trading. Still Qatar
potential for the application of CO2 sequestration technologies is huge knowing that onshore deep
saline aquifers of Qatar is as potential large volume carbon dioxide storage sites. Although injection of
supercritical CO2 into deep saline aquifers or oil fields is a promising technique for sequestration of
large amounts of CO2, but some fraction of the injected CO2 were to leak and reach shallow
groundwater aquifers, it would lead to geochemical alterations that could have detrimental effects on
the water quality and other adverse impacts. Thus early detection and characterization of potential
CO2 leak significantly increases the probability that a timely and efficient solution can be found. The
present study presents early results from a joint research between University of Texas and Qatar
University on the possible biogeochemical impacts of accidental leak on the shallow ground water and
shallow subsurface environment as well as subsurface fate and pathways. For example, in cases of
accidental leak, the potential leakage pathways are not necessarily known, but our earlier research
indicate that monitoring must be done across a region as large as 100 km2 in the vicinity of a CO2
injection project. If a leak were to happen from a Dukhan oil field well (as an example of one such
scenario), this would have an impact on the nearby coastal and/or sabkha environment of Doha, Al-
Khor, Al-Wakrah, Umm Sa’id, as well as Salwa areas. The potential for stimulation and enrichment of
the growth of existing cyanobacterial mats and algal planktonic blooms, some of which may be toxic, is
high. The latter effects have further possible consequences on human health as well as on fisheries in
Qatar that are described in this research.
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Gravity Gradiometry Resolution Study and Its Application from Synthetic Data from the Middle East
Authors Constantine Tsingas, Neil Dyer, Mark Davies, Mike Zinger, Adam Fox and Babis KalenderidisGravity Gradiometry has long been known as a fundamentally useful geophysical quantity. Early
applications of Gradiometry surveying required cumbersome instruments that required time consuming
and delicate operation, making effective coverage of large areas difficult and expensive. Modern
instrumentation has enabled Gravity Gradiometry to be performed from an airborne or marine
platform, enabling accurate measurement of gravity gradient over explorationally significant areas in a
reasonable time scale.
The ability of a modern moving platform gradiometer to isolate its measurement from the acceleration
of the aircraft over a bandwidth between ~300m and 100km enables the complete field to be
measured, without spatial aliasing, at low observation height. This allows the survey to capture signal
from subsurface anomalies through the depth range of interest to both mineral and hydrocarbon
explorationists, while facilitating accurate definition of the overburden through integrated
interpretation. A demonstration of the application of this approach, in a typical Middle Eastern salt
structure in areas of seismic uncertainty, is made through the construction of a “realistic synthetic”
gravity gradient dataset, using an Earth Model and imposing realistic survey noise and uncertainty. The
Earth Model parameters are perturbed to demonstrate sensitivity to typical time and depth domain
velocity (structural) uncertainty and density uncertainty to derive the sensitivity of the integrated
technique to variations in the subsurface.
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Emerging Stratigraphic Play Opportunities of the Jurassic of Saudi Arabia through from Enhanced Workflow
The search for stratigraphic traps especially in carbonates is a challenging task and requires careful
detailed analysis of the petroleum system elements. Understanding the spatial relation between
source, reservoir and seal layers constitutes a critical success factor. Building a workflow that
transforms well and seismic data into 3D models allows stratigraphic traps prediction and better
understanding of the stratigraphic trapping components.
With the acquisition of modern 3D seismic data and the advancement in data analysis software, we are
able to build 3D seismic and electrofacies and porosity models that are tied to well based information
such as cores and well logs. The built 3D models allow the investigation of the spatial relations of
source, reservoir and seal units.
A corner stone of our workflow for targeting carbonate stratigraphic traps is to integrate all available
data into 3D models of seismic facies, electrofacies and core data. These models were also transformed
to porosity models using relations from seismic (AI), core measured and well log derived porosities.
This allows analysis of the stratigraphic trap in great details. Highly detailed core data and well log
defined electrofacies, are upscaled and used to calibrate seismic waveform based facies. The seismic
facies volume generated from a combination of seismic attributes allowed lateral stratigraphic
prediction.
A workflow for the deliberate search for carbonate stratigraphic traps includes:
● Stratigraphic and sedimentologic analysis from cores and well-logs and building of depositional
architecture.
● Stratigraphic modeling and Wheeler diagram construction to track lateral and temporal shifts of
depositional facies and electrofacies modeling, which uses a combined analysis of well logs and cores,
for facies definition.
● Seismic modeling and analysis to investigate the link of the facies response to seismic.
● Hybrid clustering classification.
● Seismic trace based 3D model integration of the core lithofacies, the electrofacies, and the seismic
facies to produce facies and porosity models.
● Integration of other petroleum systems elements and visualization of the results.
Application of this workflow to a Jurassic interval in an area in the eastern Saudi Arabia have proven
that carbonate stratigraphic trap can be predicted thus giving us confidence in pursuing these type of traps.
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Particle Swarm and Differential Evolution Optimization - Global Optimization for Geophysical Inversion
More LessInversion of pre- and post-stack seismic data for acoustic and shear impedance is highly non-linear
and ill-posed. In this paper we report on the application of two new global optimization schemes,
namely, Particle Swarm Optimization (PSO) and Differential Evolution (DE) to the problem of stochastic
inversion of post-stack seismic data. A starting model is drawn from a fractional Gaussian distribution
(based on a fractal model) and a suitably defined objective function is optimized in search of
acceptable models using PSO and DE. Our investigations reveal that both the methods have nice
convergence properties. However, the DE converges at least 10 times faster than PSO. We
demonstrate the performance of these methods with application to synthetic and field seismic data.
The social behavior observed in a flock (swarm) of birds and in insects searching food has been
simulated to develop a global optimization strategy popularly known as the Particle Swarm
Optimization (PSO). Particle Swarm Optimization (PSO) emulates the social behaviours in a flock of
birds (swarm) in solving an optimization problem. It utilizes both local and global properties of the
swarm to formulate a novel search strategy that guides the swarm towards the best solution with
constant updating of the cognitive and social knowledge of the particles in the swarm.
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Sequence Stratigraphic Approach to Identify Potential Stratigraphic Plays in Matured Blocks 01/02,Offshore Vietnam
Authors Othman Ali Mahmud, Irdawati Lokman, Shamsudin Jirin and Thang X.TranTo date twenty-six (26) wells have been drilled which resulted in one producing oil field, three
potentially commercial oil discoveries, one potentially commercial gas field and four dry wildcat wells.
Hydrocarbons were found in the Pre-Tertiary basement and Miocene clastics intervals. In previous
years, petroleum exploration in the Oligocene section of Blocks 01&02 was regarded as under-pursued
after a series of drilling campaigns, which yielded no significant results due to poor reservoir quality.
With most of the structural traps tested by these wells, the blocks could be considered as mature. In
pursuing further evaluation of the remaining potential of these blocks, a study based on a seismic
sequence stratigraphic approach was carried out in 2008. The study was aimed at identifying potential
stratigraphic plays and traps in Blocks 01&02 prior to relinquishment of the exploration Petroleum
Sharing Contracts (PSC). At the same time, the study investigated hydrocarbon potential of Oligocene
section in these blocks.
The study has identified six sequence boundaries which subdivide the sedimentary successions into five
(5) sequences. The first three lower sequences are in the Oligocene interval while the other two in
Miocene section. Biostratigraphic data suggests that the Oligocene sequences were deposited in the
lacustrine setting while Early Miocene sequences deposited in the brackish to shallow marine
environments. The potential source rock for petroleum system is believed from the lacustrine shales
while the potential reservoirs for Oligocene sequences interpreted as fluvio deltaic sands in the lake
setting and shallow lake sands. The Miocene sequences sharing similar potential source rock with
Oligocene while the Miocene potential reservoirs spans from lacustrine to shallow marine sands.
Five potential stratigraphic plays were identified from the Oligocene interval in which out of five three
are considered as in the moderate risk category in term of working petroleum system, while the other
two are considered as in the high risk category.
This paper shall discuss the methodology and results of the study i.e., the identified stratigraphic plays
and the hydrocarbon potential of the Oligocene section in Blocks 01&02, Cuu Long Basin, offshore Vietnam.
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Deterministic Versus Stochastic Discrete Fracture Network (DFN) Modeling, Application in a Heterogeneous Naturally Fractured Reservoir
Authors Meyssam Travakkoli, Saeed Khajoee, Reza Malakooti and Mohsen S. BeidokhtiFracture Modeling is a multi-step process involving several disciplines within reservoir characterization
and simulation. The main idea is to build on geological concepts and gathered data such as
interpretation of faults and fractures from image log data and 3D seismic , use field outcrop studies as
analogs for conceptual models, seismic attributes used as fracture drivers, etc. The purpose of
modeling fractures is to create simulation properties with the power to predict the reservoir behavior.
This note applies DFN concept in a unique and comprehensive study of fracture modeling in one of
naturally fractured carbonate reservoir of Middle East.
A Discrete fracture network is a group of planes representing fractures. Fractures of the same type that
are generated at the same time are grouped into a fracture set. Each fracture network containing
fractures has at least one fracture set but may have many.
The simplest fracture sets are defined deterministically as a group of previously defined fractures,
either as a result of fault plane extraction from a seismic cube, or as previously defined fractures.
Fractures modeled stochastically can be described statistically either using numerical input or
properties in the 3D grid. Properties in the 3D grid can vary in 3D and can easily be modeled using
seismic attributes from 3D seismic data.
The Scale up fracture network converts the discrete fracture network (with its defined properties) into
the properties that are essential for running a dual porosity, or dual permeability simulation.
A simple simulation model is developed for three different grid types, using the software ECLIPSE 100,
grid without DFN modeling, deterministic DFN modeling and stochastic DFN modeling. The results of
the reservoir simulation indicate that case with Stochastic DFN has a better result (history match)
rather than cases with Deterministic DFN and the grid without DFN.
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A Permian-Triassic Boundary in the Middle East: A Review
Authors Oliver Weidlich, Aymon Baud, Michaela Bernecker, Leopold Krystyn and Sylvain RichozThe Middle Permian - Early Triassic Khuff Formation occurs throughout the subsurface in the Middle
East and is believed to contain the biggest gas reserves in the region. Along the epeiric Arabian
platform shallow-water carbonates and evaporites prevail in the northern and central part and pass
southward in argillaceous carbonates and siliciclastics. In eastern direction shallow-water carbonates
pass in deep marine deposits of the Neo-Tethys. Outcrops in Saudi Arabia, Iran, UAE and Oman
provide important analogue data for subsurface geologic models.
The Permian-Triassic Boundary (PTB) event, about 251 million years ago, was the time of the most
severe mass extinction during the Phanerozoic that heavily affected marine and terrestrial ecosystems.
Sedimentary rocks of the Khuff Formation and equivalent formations in the Middle East yield abrupt
litho- and biofacies changes which are believed to be the result of events associated with Permian-
Triassic Boundary (also called end-Permian mass extinction in the literature) and the Early Triassic
recovery interval.
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Spatial Modeling of Complex Sandstone Bodies to Maximize Reservoir Contact for Wells Drilled in Clastic Formations
Authors Ahmad A. Dossary and Jose A. Vargas-GuzmanThe gigantic clastic reservoirs in Saudi Arabia contain thick, prolific and continuous sandstone
members; however, incremental development may include numerous laterally discontinuous prolific oil
bearing sandstone bodies intercalated with non-reservoir rocks, in the so-called stringers. The
optimization of hydrocarbon production requires advanced modeling workflows to identify and predict
the spatial distribution of clastic discontinuous rock bodies. This study proposes cross-validation of 3D
models with new well bores to improve future predictions. The modeling approaches include sequence
stratigraphy interpretations and identification of the depositional environment. Object-modeling and
sequential indicator simulation techniques were used to produce multiple realizations of 3D geocellular
facies models that predict the geometry and location of sandstone bodies. New wells were planned and
drilled based on the most probable predictions. Once a well was completed, the real data collected at
the wellbore was compared to multiple geocellular realizations to evaluate an average error at each
location. That error was later used to modify the facies model and workflows. The ultimate goal was to
reduce uncertainty and optimize new wells planning.
The proposed optimization approach, for drilling new wells, was tested in the Cretaceous Safaniya
stringers member of the Wasia formation. Upward increasing gamma ray logging values, and upward
decreasing grain size from core descriptions were interpreted to indicate fining upward sequences
associated with sandstone channels. Localized crevasse splays show coarsening upward and blocky
shapes on the gamma ray. Other bodies identified are bays and mouth bars. These bodies and
sequence boundaries were incorporated into an initial 3D geocellular facies model. Object modeling
was used to populate the 3D model, with objects drawn with realistic shapes and sizes. The models
were cross-validated with new drilling. Each new well provides new logging data values, which were
compared to predictions from various realizations of the 3D geocellular model, and the average error
was plotted against petrophysical properties and gamma ray derivatives. Results are summarized to
recommend corrections in the geological interpretation and modeling approaches. It was concluded
that a hybrid approach - combining both object and sequential indicator modeling techniques - is the
optimum way to predict rock bodies with current technology.
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Carbonate/Evaporite Sequence Stratigraphy of the Subsurface Late Jurassic Arab-C Member, Khursaniyah Field, Eastern Saudi Arabia
Authors Emad A. Busbait, Ishak Ishak, Langhorne Smith and Khalid Al RamadanThis study defines the cycles and sequence stratigraphic framework of the Arab-C Member of the
Khursaniyah Field to enhance the understanding of both sedimentological and depositional models of
the Arab-C reservoir. The sediments of the Arab Formation in the Arabian Peninsula are typically
composed of shallow-water limestones and dolomites interbedded with restricted facies of anhydrites.
Each reservoir layer corresponds to retrogradational - progradational cycles. The reservoir-bearing
Arab-C carbonate in Khursaniyah Field (150 ft thick) is an overall shallowing-upward composite
sequence that can be subdivided into five high-frequency sequences. Each of these high-frequency
sequences can be subdivided into multiple fining-upward small-scale cycles.The lower part of the Arab-
C Member is made up of cycles that fine-upward from intraclastic/oolitic rudstone into skeletal
wackestone and lime mudstone. These are overlain by 9 to 20 ft thick cycles that consist of ooid
grainstones capped by anhydrite. The overall evolution is that the basal sequence consists of ooid
grainstones and rudstones capped by an anhydrite. The second sequence consists of cyclic ooid
grainstones and dolomitized mudstones. The third sequence consists of thick cross-bedded grainstones
(which mark the maximum flooding) capped by thrombolite facies. The fourth sequence consists of
peloidal grainstones capped by thin evaporites and then there is a thin fifth sequence that has a
carbonate stringer in the base that is capped by the regional anhydrite that extends upward to the
base of the Arab-C. Grainstones are mostly in the transgressive portions of the sequences and cycles
while anhydrite, tidal flat facies and thrombolites mostly occur in the highstand parts of the sequences
and cycles. The middle evaporite package thins toward the northeast of the field. Dolomite increases in
the southeast of the field and the thromoblites decrease on the crest of the field. This core/log basedwork
leads to a better correlation framework for the Arab-C Reservoir where the wire line logs alone
are often difficult to correlate. Moreover, the sedimentological work helps to break out facies with
differing porosity and permeability relationships that can be imported into geocellular models for
matching production history and field optimization planning.
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Using Advanced Technologies to Solve Complex Reservoir Challenges in Shedgum Field, Saudi Arabia: A Case Study
Authors Ubong U. Obot, Roberts Iwan, Mohan Javalagi, Wael Al-alqum, Waleed Jawad and Majid Al-OtaibiIn order to meet world energy demand, wells have to be drilled in more challenging frontiers and
within very thin reservoir beds. Conventional geosteering and LWD measurements face considerable
challenges with chasing thin targets. However, geosteering into such thinner reservoirs has been
successfully achieved through the application of next generation LWD measurements. Deep, directional
resistivity (DDR) from the PeriScope LWD allows well placement to be optimized in real time by using
the tool’s sensitivity to approaching bed boundaries and the ability to accurately map distance to such
bed boundaries and formation dip. The PeriScope technology has proven its ability to unlock previously
uneconomic targets in both clastic and carbonate reservoirs all over the world by providing for
proactive well placement.
In Saudi Arabia, Aramco has made use of applying the PeriScope LWD and well placement services for
its more challenging targets. In this paper a case study is outlined where 2 laterals were drilled into a
carbonate reservoir, with and without PeriScope LWD. A comparison is made between results achieved
drilling lateral 1, using PeriScope LWD and in lateral 2, drilling using a conventional LWD approach. In
both cases the objectives of the well was to place the well 1 ft below the top of an anhydrite cap rock
and also to keep the well away from possible water encroachment thereby improving total oil recovery.
Conventional geosteering relies on logs from offset wells and real time measurements. An assumption
is made that the formation follows a layer-cake model, in which properties are assumed to be laterally
continuous. This assumption is often invalid, as smaller scale variations in structure can also
significantly impact on geosteering, especially in thinner targets and provides a considerable challenge
for conventional geosteering. By using PeriScope these changes can be proactively managed in real
time. In this case study lateral 1 was planned and drilled using PeriScope LWD in the BHA while Lateral
2 was later drilled with a conventional LWD BHA. Lateral 1 was placed in a porous stratum from target
entry (TE) to total depth (TD) with no reservoir exit. Whereas 16.8 % borehole-to-reservoir exposure
with formation greater than 0.15 porosity unit was achieved in the lateral drilled with conventional
LWD. The results confirm the added value of proactive well placement through the use of the PeriScope
LWD technology.
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Comprehensive Karst Delineation from 3D Seismic Data
Authors Gaynor Fisher, David Hunt, Arnout Colpaert, Brita G. Wall and Jonathan Henderson3D seismic data has the potential to provide an enormous amount of detailed information about karst
and dissolution features. However, horizon based interpretation is not well suited to the analysis of
such features and, in addition to being very time consuming, reveals little or no information on the
paleokarst network and connectivity between karsts within a carbonate target. Without a good
understanding of karst distribution it is difficult to compile a comprehensive geological model and
appreciate the impact such structures will have on porosity evolution and reservoir quality (Budd et al.,
1995; Neuhaus et al., 2004).
Although karst and dissolution features may be extensive, they can be hard to identify in reflectivity
data due to their variable seismic character. The application of Image Processing and Analysis (IPA)
workflows enables a rapid and detailed examination of Carbonate features, including karsts, as well as
reefs / buildups and clinoforms. The IPA workflow employs attribute analysis to highlight the location
and extent of these features, and then 3D geobody delineation techniques are applied to allow the 3D
geometry of the highlighted features to be examined in detail. A major strength of these workflows is
the built-in capability to detect karsts and dissolution features across a wide range of scales and with
diverse morphologies.
This paper describes the IPA workflow and illustrates its application to the interpretation of upper
Palaezoic carbonates in the Loppa High area of the Norwegian Barents Sea. Here it is estimated that
some 300-500 m of uplift, erosion and karstification of a mixed carbonate-evaporite succession
occurred during c. 20 million years of subaerial exposure (i.e. Roadian-Induan times). Major drainage
systems can be traced across basement rocks and into and through the karstified carbonate
succession. The carbonates are cut by steep km-scale canyons and penetrative sinkholes. The dataset
shows a range of contrasting paleokarst features, so that some of the key seismic attributes and
spectral decomposition methods used to delimit contrasting genetic elements of paleokarst systems
can be illustrated. Results from the seismic data analysis have been quality-controlled against well data
and horizon-based interpretations.
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Borehole-Image Log Interpretation in the Wara and Burgan Palaeotransport System, Greater Burgan Fields, Kuwait
The Wara and Burgan Sandstones are a major oil producer in Kuwait. In our study, the formations
have been characterized using cores, borehole images and open hole log data from 16 wells. Five
lithofacies were determined: (1) massive, cross-bedded and low-angle sandstone units; (2)
structureless, cross-bedded and low-angle argillaceous units; (3) interbedded sand and shale
heterolithic units; (4) structureless and laminated shale units; and (5) undefined carbonate units.
The palaeotransport direction was analyzed separately for the Wara Sandstone and four Members of
the Burgan Sandstone, which are the 3 Sand Upper (3SU), 3 Sand Middle (3SM), 3 Sand Lower (3SL)
and 4 Sand (4S). Results showed bi-modal and tri-modal distribution of palaeocurrents for some
intervals, in agreement with previous interpretations for this field. For the first time, we have identified
a main source of sediment from 1350 (40% of the footage) and 2500 (32% of the footage) with a high
variation (standard deviation = 1200) for the Wara Sandstone.
In 3SU member of the Burgan Formation, 150 was the dominant palaeocurrent direction (45% of the
footage), whereas in member 3SM, the palaeocurrent direction is toward the 450 (50% of the footage).
In member 3SL, palaeocurrents show a trimodal distribution, with the main trends towards 600 and 100
(40% of the footage) and a minor trend towards 2800 (29% of the footage). Finally in member 4S, the
main palaeocurrent direction is towards 650 (49% of the footage).
Eighteen faults were identified with strike azimuths that range from 3100 to 3450 and dip azimuths that
range from 2200 to 2550 (72% of the footage). The NW-SE strike azimuth fits well with the structural
trend of the Greater Burgan fields, which consist of three giants Burgan, Magwa and Ahmadi fields.
The combination of fault (NW-SE trend) and palaeocurrent distribution (mostly with a NE trend)
compartmentalizes the reservoir.
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Effects of Microfacies and Diagenesis on Petrophysical Properties of Sarvak Formation, Fars Area, Southern Iran
Authors Parisa Gholami Zadeh and Mohammad Hossein AdabiThe Lower to Upper Cretaceous (Albian- Turonian) Sarvak Formation, the second major oil and gas
reservoir in Zagros Basin of southern Iran is principally composed of carbonates with minor shale. 15
microfacies were recognized from 287 meters of core and 329 thin sections (colored with red Alizarin)
were collected for petrographic analysis, together with analysis of core and well logs.
Petrophysical properties of carbonates are controlled in part by the original depositional texture, but
also largely by subsequent diagenetic processes. The sedimentary and diagenesis processes together
control the arrangement, distribution and orientation of the major constituents, the open space and
pathways, the fractures and the stylolites in the rock. When working with reservoir quality of carbonate
reservoir rocks, these main fabric elements have to be considered.
In this study, the microfacies were deposited in lagoon, back reef (leeward), reef, fore reef (seaward),
shallow open marine and deep open marine settings. The petrographic analyses indicate that the
Sarvak Formation carbonates have undergone a complex diagenetic history which includes compaction,
cementation, dissolution, dolomitization, neomorphism and fracturing. Cementation and compaction
reduce porosity and leads to low permeability and poor reservoir quality. Dissolution, dolomitization
and fracturing diagenesis processes improved reservoir quality. Dissolution process with generating of
secondary porosity consists of vuggy and muldic has important effect on increasing of porosity, but
most important factor in development of reservoir has been fracturing.
In lagoonal deposits, single unit was distinguished with moldic and vuggy porosities. In shoal/reef
deposits, two units were distinguished in terms of dissolution and grain frequency. In shallow openmarine
deposits, two units were identified with different degrees of fracturing and dolomitization; while
deep open-marine deposits were characterized by a three unit in terms of stylolitization and
dolomitization. Consequently, the shoal/reef deposits with Rudist grainstone and rudstone textures and
interparticle and moldic porosities had the best reservoir quality.
The key challenge in this reservoir analysis was to predict the vertical distribution of petrophysical
properties to improve r eservoir characterization. This research improved our understanding of geologic
controls on the reservoir performance.
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Knowledge Management from Saudi Aramco Exploration
Authors Said M. Qahtani, Raed A. Bahrani, Ahmed M. Rebh, Peter Attewell and John GriffithsThis paper describes the knowledge management system - GeoKnowledge - that we have developed to
ensure that the assets for key knowledge areas are identified in the various corporate repositories,
then collected, integrated and passed to our successor generation as knowledge in a way that can be
accessed and shared usefully and in a timely manner.
In a top-down process for each knowledge area we identify a collection of raw information items from
our corporate repositories with the help of a supporting taxonomy. The meta data for information items
relevant to end-user disciplines is enriched and transferred to a central metadata repository.
The knowledge areas are accessed by a domain-specific search that focuses on specific slices of
content with attributes such as spatial location, and chrono-stratigraphic criterion. To transform the
raw information into useful information and knowledge, we describe the characteristics and inter
relationships that exist using a common and controlled vocabulary.
Management of the knowledge repository includes registration of knowledge sources and encompasses
both content and metadata repositories. Within the repository, issues of knowledge governance are
addressed to include sensitivity classification, access control, and rights management.
Finally we describe our approach to managing the time value of knowledge. By implementing this
process of knowledge management, we help our geoscientists become more productive.
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Evaporites Across Deep Time: Tectonic, Climatic and Rustatic Controls in Marine and Nonmarine Deposits
By John WarrenPlots of the world’s Phanerozoic and Neoproterozoic evaporite deposits, using a GIS base, shows that
Quaternary evaporite deposits are poor counterparts to the greater portion of the world’s Phanerozoic
evaporite deposits. They are only directly relevant to same-scale continental hydrologies of the past
and, as such, can be used to better understand what is needed to create beds rich in salt-cake, sodaash,
borate and lithium salts. These deposits tend be Neogene and mostly occurring in suprasealevel
hydrographically-isolated (endorheic) continental intermontane and desert margin settings that are
subject to the pluvial-interpluvial oscillations of today’s ice-house climate. When compared to ancient
marine evaporites, today’s marine-fed subsealevel deposits tend to be small sea-edge deposits, their
distribution and extent is limited by the current ice-house driven eustacy and a lack of appropriate
hydrographically isolated subsealevel tectonic depressions.
For the past forty years, Quaternary continental lacustrine deposit models have been applied to the
interpretation of ancient marine evaporite basins without recognition of the time-limited nature of this
comparison. Ancient mega-evaporite deposits (platform and/or basinwide deposits) require conditions
epeiric seaways (greenhouse climate) and/or continent-continent proximity. Basinwide evaporite
deposition is facilitated by continent-continent proximity at tectonic plate margins (Late stage E
through stage B in the Wilson cycle). This creates an isostatic response where, in an appropriate arid
climate belt, large portions of the collision suture belt or the incipient opening rift can be subsealevel,
hydrographically isolated (a marine evaporite drawdown basin) and yet fed seawater by a combination
of ongoing seepage and occasional marine overflow. Basinwide evaporite deposits can be classified by
tectonic setting into: convergent (collision basin), divergent (rift basin; prerift, synrift and postrift) and
intracratonic settings.
Ancient platform evaporites can be a subset of basinwide deposits, especially in intracratonic sag
basins, or part of a widespread epeiric marine platform fill. The latter tend to be mega-sulphates and
are associated with hydrographically isolated marine fed saltern and evaporitic mudflat systems in a
greenhouse climatic setting. The lower amplitude 4th and 5th order marine eustatic cycles and the
greater magnitude of marine freeboard during greenhouse climatic periods encourages deposition of
marine platform mega-sulphates. Platform mega-evaporites in intracratonic settings are typically
combinations of halite and sulphate beds. Potash evaporates tend to show a dichotomy of occurrence
with Quaternary deposits formed in small scale endorheic basins, while ancient potash deposits formed
in basinwide settings in situations that, like all basinwides, have no same-scale Quaternary counterparts.
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Reservoir Properties from Unbiased Seismic Inversion
More LessLow frequencies missing from seismic data have to be modeled from log data for inversion to absolute
rock properties. This can result in biased inversion results away from the existing wells. The risk of bias
increases with higher frequency lowpass cutoffs of seismic data: more bandwidth added from the
model (logs) and less from the seismic (measurement). Low frequencies and a broadband spectrum
are also required to avoid errors in layer thickness after seismic inversion and imaging.
Two-streamer and two-source over/under acquisition and processing technology enables effective
source and receiver ghost eliminations that result in seismic data rich in low frequencies down to about
3 Hz. This is about one octave gain over the conventional single streamer technology. As a result,
over/under field data maps deep targets below basalt and a better structural imaging is obtained
compared to conventional seismic data.
Wedge modeling and porosity and fluid substitution modeling using extracted wavelets show that good
inversion results can be achieved with the over/under data using only 3 Hz background models.
Therefore possibility of bias due to low frequency component added from model data during seismic
inversion is either limited or eliminated.
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Overpressures in the Sediments of the South Caspian Basin: Nature and Prediction
Authors Akper Feyzullayev, Said Sadykhov and Yusif ShikhaliyevOn the basis of a systematization and summarization of studies of overpressures in different basins of
the world, the authors identify two basic factors that contribute to overpressures in sedimentary
basins: tectonic stress and the progressive rise in subsoil temperature with depth. A summarization of
the results of all past studies of the patterns of distribution of fluid pressures in the South Caspian
Basin (SCB), from well logs and actual downhole measurements to depths of approximately 7 km,
makes it possible to identify two basic overpressure zones in this interval which are most distinctive in
the Baku Archipelago. Depending on the lithofacies of the section, the top of the first overpressure
zones lies at a depth of 600 to 1200 m. Farther down, to a depth of approximately 4 km, pressure
gradients, while still high, are quite stable. We can observe the start of a new intense overpressure
zone at a depth of 5 km. The authors demonstrate that overpressures in the upper zone are caused by
uneven consolidation (underconsolidation) of rocks, while overpressures in the lower zone are caused
by hydrocarbon generation. The lower overpressure zone is the most intense and results from the
thickness of the shales, the concentration of organic matter in the shales, the type of organic matter,
and the temperature conditions of its transformation into hydrocarbons. In this zone the greatest risk
is associated with the start of gas formation at depths greater than 9 km resulting from more intense
thermal breakdown of kerogen and the cracking of liquid hydrocarbons formed earlier. The results of
the first attempt in the South Caspian Basin (SCB) to predict overpressures directly on the basis of
seismic data are quite consistent with theoretical developments and traditional diagnostic methods.
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Carbonate Reservoir Rock Typing - From Integrated Case Study
Authors Hani Al-Sahn, Amaud Mayer, Ibrahim Al-Ali, Habeeba Al-Housani and Fathy El-WazeerReservoir rock typing is a process by which the reservoir is abstracted into discrete units characterized
by certain static properties and dynamic behavior. The challenges of this process are to find the
correspondence between rock fabrics with their diagenetic alterations and their petrophysical
properties then to distribute these discrete entities in the reservoir. This paper presents a real case
study completed for a major complex carbonate reservoir onshore Abu Dhabi. The study included 3
main elements. The first element is a detailed facies analysis where facies has been described using all
available cores. The second element is a detailed petrographic analysis where diagenetic overprints
were described using 3000 thin sections. The third element is a petrophysical data grouping using
static and dynamic properties.
The main challenge was to establish a systematic relation between the three elements (facies,
diagenesis and petrophysical groups) because, apart from diagenetic modifications, similar carbonate
facies deposited under similar conditions would exhibit different petrophysical properties due to other
factors (e.g. compaction, micrite content and dominant grain types). The study resulted in establishing
a manageable number of Reservoir Rock Types with distinct capillary pressure properties applied to the
cored wells. For non-cored wells, an artificial neural network back-propagation algorithm was applied
to estimate permeability. We achieved permeability prediction with more than 90% correlation
coefficient and then used it with log porosity to assign petrophysical groups using calibrated MICP
driven Winland’s R35 cutoffs. The workflow followed and the techniques applied are presented in this paper.
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Integrating Rock Physics, Seismic Reservoir Characterization and Static Modeling of Carbonates; a Case Study from the UAE
An integrated workflow to generate seismically constrained reservoir models is described. Several key
technologies were used including carbonates rock physics estimation, seismic forward modeling and
comparison to surface 3D seismic, as well as probabilistic seismic inversion.
Using the SUN rock model as a framework, the team derived relationships between the reservoir
properties (like modeled facies, porosity and fluid content) and the elastic properties (Vp, Vs and
density). The theory of the Sun model was chosen as a key for relating reservoir properties to seismic:
relations were identified between Suns frame flexibility factor (describing the elasticity of the rock
frame determined by pore geometry), velocities, densities and porosities. Those relations were
compared to the information on sedimentology, diagenesis, structural position and reservoir rock
types. Detailed well to seismic match enabled estimating a fit-for-purpose average wavelet to be used
over the entire field. The fluid substitution of the well logs, log blocking, and the fluid properties made
it possible to model the fluid content impact on the seismic, and to better understand the impact of peg
-leg multiples still present in the seismic data.
The generation of 3D synthetic seismic based on the static model included the use of the relations
obtained from the rock physics model, the well log blocking and the derived seismic wavelet. The
match between real and modeled synthetic seismic indicates how well the parameters in the static
model describe the reservoir, and the relevance of the variables (rock & fluid properties, layering, and
wavelet) included in the forward modeling. The seismic match was improved by iteratively fine tuning
the different variables used to generate the synthetic seismic. The optimization process highlighted
which variables control the seismic response. These were subsequently used to define the stochastic
parameters and the uncertainties in the probabilistic seismic inversion. The inversion algorithm used
utilizes the constrained static model as input and can invert to any of the variables present in it.
Therefore it was possible to obtain probability distributions for porosity, fluid saturation and rock
rigidity in any location of the reservoir that match the seismic.
The workflow was applied to the Bab field in Abu Dhabi, UAE. The resulting static model reflects more
accurately the lateral variability of the rock properties while preserving vertical resolution.
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Meteoric Diagenesis of Microporous Carbonates. Example of the Mishrif Fm. (Cenomanian - Early Turonian) of Qatar (Middle-East)
Shallow marine carbonate sediments of the Mishrif Formation (Mid-Cenomanian to Early Turonian)
were deposited on a low energy ramp, before a Mid-Turonian relative sea-level fall. Depositional
environments vary from inner ramp to open mid-ramp, with very shallow rudist biostromes. In the
predominant mud-supported sediments (mudstones, wackestones…), the heterogeneity of reservoir
properties (e.g. porosity, permeability, pore access radii distribution…) is closely related to microtextures
of the micritic matrix. Microporosity is relatively constant, high (up to 35%) and represents up
to 98% of the total porosity. Permeability is low (below 1mD) to moderate (up to 100mD).
Using cathodoluminescence (CL), scanning electron microscopy and isotopic analyses, 240 samples
coming from seven cored wells of a Mishrif oil field have been studied to characterize the sedimentary
and diagenetic factors that have controlled reservoir properties.
Micritic facies with the best permeability (up to 100mD) and the higher pore threshold radius (PTR - up
than 0.5μm) generally show coarse, badly sorted and poorly luminescent micrites. These micrites are
spatially and chronologically associated with eogenetic phases indicating the development of an
important oxidizing vadose interval (up to 30m thick) below the Mid-Turonian exposure surface: (1)
endokarstic cavities; (2) rare poorly luminescent sparry low magnesium calcite (LMC) with low δ18O
and low δ13C; (3) corrosion gulfs on early spars. In this vadose zone, the development of coarse
(crystallometry > 2μm), poorly luminescent micrites with similar geochemical signature is explained by
the early dissolution of fine aragonite and HMC particles leading to a simultaneous overgrowth of LMC particles.
Below the vadose zone most of micritic facies are associated with low permeability and PTR (less than
10mD and 0.5μm, respectively). Micrites are finer (crystallometry less than 2μm), well sorted and
luminescent under CL. This micritic pole is explained by a mineralogical stabilization of micritic particles
that ends later, in poorly oxygenated waters, probably after the deposition of the Laffan shales that
sealing the Mishrif reservoir.
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New Insight into Gas Source-Tracking: A Predictive Model for Kinetics and δ13C of CH4 Generated from Methylated Monoaromatics during Thermal Cracking of Oil in High-Temperature Reservoirs
The scope of the present study was to validate an approach that could be used in order to elaborate an
integrated model predicting the kinetics and δ13C of gases generated during thermal cracking of oil in
high-temperature (HT) reservoirs. For this feasibility study we have focused on methylated
monoaromatic hydrocarbons (MMH) present in oil using the model compound 1,2,4-trimethylbenzene
(TMB) and we have proceeded in 4 steps.
1) Pyrolysis experiments at 395, 425, 450, and 475°C and 100 bar were performed in order to study
the whole range of TMB conversions. All pyrolysis fractions were recovered and quantified. Products up
to C18 were quantified individually.
2) A mechanistic kinetic model was achieved for thermal cracking of TMB until 70% conversion. It
involved 122 reversible free-radical reactions and 47 species up to C18. It allowed the characterization
of CH4 generation processes involving components up to C18 at all temperatures.
3) A lumped kinetic model was achieved for thermal cracking of TMB on the whole range of conversions
using the mechanistic model in order to constrain its reduced reaction scheme. This scheme was
composed of 4 pathways for CH4 generation: (Pa) the dimerization of TMB, (Pb) its demethylation into
xylenes, (Pc) the condensation reactions of dimers and C18+ compounds, and (Pd) the dimerization of
xylenes and their demethylation into toluene. Associated activation energies were in the range 52-61
kcal/mol and frequency factors all close to 10^12 s^-1. Below 5% conversion, Pb and Pc governed
CH4 generation, followed by Pa. Above 5% conversion, Pc became the main source of CH4, followed Pb
and Pa, respectively. Pd showed negligible CH4 yields up to 95% conversion. Simulations under
conditions met in HT reservoirs revealed that the thermal stability increased in the series methylated
polyaromatics < MMH < saturates. They also demonstrated the CH4 generation potential of MMH and
the risk for heavy components generation when conversion increased.
4) Pa, Pb, and Pc were selected as relevant contributions to δ13C(CH4) until 100% TMB conversion.
Kinetics for the generation of 12CH4 and 13CH4 were expressed separately. Associated ratio of
frequency factors Ω = 1.028 and variations of activation energy ΔEi ranged from 36 to 79 cal/mol.
Simulations under conditions met in HT reservoirs were performed and illustrated the importance to
determine the magnitude of the isotopic precursor effect for natural compounds.
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