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GEO 2010
- Conference date: 07 Mar 2010 - 10 Mar 2010
- Location: Manama, Bahrain
- Published: 07 March 2010
101 - 200 of 457 results
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Prediction of Reservoir Heterogeneity and Quality: Examples and Lessons from Outcrop Analogs from Wajid Sandstone, Saudi Arabia
Authors Osman M. Abdullatif, Mohamed Makkawi and Mohamed MahgoubThis study tends to characterize the reservoir rock heterogeneity and quality using sedimentological,
statistical and geostatistical approaches. Paleozoic fluvial and shallow marine outcrop reservoir analogs
from the Wajid Sandstone in south west Saudi Arabia are the target for this study. The impact of
depositional and post depositional parameters on porosity and permeability distribution were
investigated on macro- to micro-scale. The study revealed wide range of facies, environments, textural
and compositional variations at outcrop scale. The porosity and permeability distribution show
variability and complex patterns most probably reflecting different scale of depositional and diagenetic
influences. The complex relations among parameters may be attributed to variable interrelationships.
At the macro to meso-scale these include the meter-scale statigraphic hierarchy, depositional cyclcity
and lateral and vertical facies changes. While at micro-scale petrographic features such as grain size,
sorting, matrix and cement content and type all seem to be influential. The geostatistical porosity and
permeability models show some agreement and differences which can also be attributed to the
aforementioned controlling factors.
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Reservoir Porosity and Permeability Prediction from Petrographic Data Using Artificial Neural Network - A Case Study from Saudi Arabia
Authors Osman M. Abdullatif and Mohamed SitouahUnderstanding reservoir heterogeneity is essential for the assessing and the prediction of the reservoir
properties and quality. This study investigates the prediction of the reservoir petrophysical properties
of the Ordovician Upper Dibsiyah Member of the Wajid Sandstone in south west Saudi Arabia. The
Artificial Neural Networks (ANNS) technique is used here to study the pattern recognition and
correlation among the petrographic thin section data such as grain size, sorting, matrix % and
cementation % and perophysical properties of the reservoir such as porosity, permeability and lithofacies.
For this purpose, artificial intelligence techniques were designed and developed and these are the
multilayer perception (MLP) and the general regression neural network (GRNN). The good agreement
between core data and precdicted values by neural netwoks demonstrate a successful implementation
and validation of the network’s ability to map a complex non-linear relationship between petrographic
data, permeability and porosity. The GRNN technique provides better prediction of the reservoir
properties than that obtained from the use of the MLP technique.
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Characterisation of the Mid-Cretaceous Mishrif Reservoir of the Southern Mesopotamian Basin, Iraq
Authors Adnan A. Aqrawi, T.A. Mahdi, G.H. Sherwani and A.D. HorburyThe Cenomanian-early Turonian Mishrif Formation reservoir of the Mesopotamian Basin accommodates
more than one third of the proven Iraqi oil reserves within rudist-bearing stratigraphic units. Difficulty
in predicting the presence of reservoir units is due to the complex palaeogeography. Extensive
accumulation of rudist banks occurred along an exterior shelf margin of the basin along an axis that
runs from Hamrin to Badra and southeast of that, with interior margins around an intrashelf basin.
Buildups were stacked or sometimes shingled as thicker shallowing-up cycles of several smaller-scale
accommodation cycles. As a result, each field shows different combinations of pay zones, barriers and
seal geometries.
The sequence stratigraphic analysis led to three complete 3rd order sequences being distinguished.
Eustatic sea level changes controlled development of the sequence stratigraphy. Tectonism primarily
defined the sites of platform development that complicated the architectural heterogeneity of the
depositional sequences.
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Can Q Explain Observations Made from a VSP?
Authors Hamish Wilson, Scott W. Peters and Robert W. WileyWe present some downgoing direct arrivals from a VSP which show a higher frequency content on
some deeper depth levels than observed on some shallower depth levels. An increase in frequency with
increased depth must be caused by a mechanism other than Q. If we could develop an understanding
of what causes this increase in frequency with depth, we will have extracted new information from our
seismic data.
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Application of a Sequence Stratigraphic Framework for the Wasia Formation: A Basis for Mapping Lithofacies Variability and Petroleum Systems in the Rub’ Al-Khali Basin of Saudi Arabia
Authors David P. Taylor, David L. Ternes and Wyn HughesThe Albian-Turonian age Wasia Formation in the Rub’ Al-Khali Basin of Saudi Arabia represents a time
of shallow-water carbonate progradation directed northeasterly into an intrashelf basin. Up to 150
kilometres of lateral progradation is observed on the windward western side of the intrashelf basin,
terminating with a rimmed carbonate shoal platform with up to 900 feet of relief. New biostratigraphic
interpretations have provided a basis for identifying third-order and fourth-order cycles within the
Wasia Formation, and can be tied to log and seismic data, allowing construction of chronostratigraphic
lithofacies maps. Higher frequency depositional cyclicity is observed and it is possible to interpret
individual depositional assemblages comprising bioclastic shoals and rudist-bank facies, in areas with
3D seismic coverage and well control.
Based on new micropaleontological data, the Mishrif Member of the Wasia Formation, consists of up to
four 4th-order depositional sequences. Each sequence commences with a planktonic foraminiferal
dominated biofacies that represents deep marine conditions of the transgressive system tract (TST).
Highstand system tract (HST) associated foraminiferal and rudist biofacies are represented by shallow
marine carbonates typically deposited in shoal and localised rudist-banks. These deepening and
shallowing cycles have been correlated across the eastern Rub’ Al-Khali, and designated Mishrif TST1-
HST1, TST2-HST2, TST3-HST3 and TST4-HST4 in ascending order. Mishrif source rocks correspond to
the Mishrif TST1 sequence and the overlying Mishrif HST1 reservoir sequence is sealed by the next
transgressive cycle, MishrifTST2. This reservoir-seal cyclicity continues in some places up to TST4-
HST4, which is ultimately sealed by regionally extensive shales of the Aruma Formation.
There are two proven petroleum systems within the Wasia Formation, the Safaniya-Mauddud and the
self-sourcing Mishrif petroleum system. New 3D seismic data provides the opportunity to apply a
sequence stratigraphic framework that constrains these petroleum systems. Third-order scale
geometries are clearly imaged for the Wasia Formation and 4th-order sequences can be identified
locally. Internal seismic reflection geometries have been characterised into lithofacies associations.
Horizon and time slices through the seismic volume are effective tools for mapping the distribution of
these lithofacies. Automatic voxel tracking delineates discrete depositional assemblages.
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Improved Extraction and Quality Control of Pre-Stack Seismic Attributes
Authors Roy Burnstad and Timothy KehoWe present a procedure for improved extraction and quality control of pre-stack seismic attributes
from wide azimuth 3D land surveys. Both the pre-processing and extraction stages of the procedure
rely on a target oriented, multi-term decomposition algorithm similar to that used in surface consistent
processes; such as, statics, amplitude balancing and deconvolution. Quality control plots indicate that
the decomposition procedure produces pre-stack attributes, which correlate better with porosity
models derived from well logs. Decomposition allows consideration of other effects, such as anisotropy
prior to Poisson reflectivity estimation from amplitude versus offset measurements. Our method
utilizes normalization at two stages: first, during processing, trace normalization factors are computed
using a large time window defined by the target horizon, and second, normalization is applied to the
extracted attributes. During the first stage, a large background time window is selected for
normalization on a swath-by-swath basis in a source, receiver, offset and azimuth consistent manner.
Both the offset and azimuth terms in this step do not vary significantly with spatial position. The
second stage consists of four components: (1) swath-by-swath amplitude mode before noise removal,
(2) swath-by-swath deconvolution mode, (3) swath-by-swath amplitude mode post-deconvolution, and
(4) survey wide amplitude mode prior to AVO measurements. The second stage occurs after AVO
analysis. Here we normalize target Poisson reflectivity measurements by an estimate taken across a
large background time window. This stage is performed in a sub-surface consistent manner with offset
and azimuth terms allowed to vary spatially across the survey area. Application to a 3D survey over a
carbonate oil field in Saudi Arabia showed correlation of pre-stack attributes with the oil water contact.
Synthetic models indicate that the correlation is due to porosity variation, not fluid type.
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Land Seismic Data Regularization: Overcoming Urban Acquisition Limitations
Authors Roy Burnstad and Abdulrahim A. Al-MubarakPrior to future reservoir development, Saudi Aramco embarked on an urban 3D seismic data acquisition
project over the Dammam oil field located in the Eastern Province of Saudi Arabia. As expected, the
250 km2 vibroseis survey proved to be a processing challenge. Field data quality was impacted by (1)
an outcropping hard layer with extensive faulting and fracturing from reservoir to surface, (2)
restricted source size and access within urban areas, (3) variable receiver array dimensions within
urban areas, (4) high levels of source generated, scattered and cultural noise, and (5) complex near
surface geology. It soon became apparent that irregular positioning of source locations throughout
urban areas meant noise suppression procedures could only be applied in two dimensions. To
implement more powerful three dimensional filtering, a solution for irregular source positioning became
the central issue. Extensive testing resulted in an innovative data regularization workflow designed to
proceed 3D noise filtering.
Initial processing steps using standard noise removal techniques were unable to produce an
interpretable volume. A number of pre-stack custom techniques, such as frequency domain median
filtering and frequency-distance deconvolution, were then implemented. Unfortunately, pre-stack time
migration stacked images continued to be disappointing. A study was convened to identify underlying
reasons for the failure of post-stack images when noise suppression appeared to work pre-stack. A
data regularization workflow to allow 3D noise suppression was identified as the best solution.
Comparison of post-stack images proved fault details could be imaged, thus providing a usable 3D
volume for field development.
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Sequence Stratigraphic Study of the Albian Succession and Evaluation of the Source and Reservoir Rocks in the North of Fars Province (Zagros)
More LessAlbian sedimentary interval (Kazhdumi Fm) were measured in six outcrop sections in northern part of
Fars area. Based on field and microfacies results, the interval dominantly are composed of limestone
attributing in inner ramp and mid ramp environments. The Albian successions in this area forms one
3rd sedimentary sequence .The Lower SB is characterized by erosional surface which probably are
caused by tectonic(between Aptian and Albian) and top of sequance boundary is SB2.at the end of
Aptian Zagros was effected by Austrian phase(orogeny phase) and created a high by epirogenic
movements.
In order to determination conditions of source and reservoir rocks in this area forty eight samples from
kazdumi Fm. In tweleve stratigraphic surface sections and drilled wells were experienced geochemically
including Rock Eval., Ro%, and GC.
According to geochemical studies, In spite of most parts of the Zagros Albian deposits in this area not
only is not capable for source rocks but also shows reservoir characteristics. also regarding to
sedimentology studies, presence of grainstone to packstone facies, porosity and shallow environments
recognize reservoir rocks.
besides intercalations of shale and marl in some parts of successions are immature geochemocally and
take place in early generated oil (window oil). Towards main Zagros fault maturity of shales has been
increased and this quantity in synclines for hydrocarbon production is considerable.
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Jurassic Carbonate Tight Gas in North Kuwait: Exploration through Initial Production
Kuwait Oil Company (KOC), as part of the strategy to meet the domestic gas demand, is currently
developing the six North Kuwait Jurassic age tight gas reservoirs. Till early 1990s majority of the
exploration and production activity in Kuwait was focused on the shallow conventional Cretaceous
targets. A paradigm shift in exploration activity with focus on unconventional reservoirs, driven by
detailed seismic studies and revised depositional models, led to the discovery of six North Kuwait
Jurassic gas fields. These reservoirs, Najmah-Sarjelu and Middle Marrat, are characterized by low
porosity (average < 5pu), low permeability (average <0.1mD) and in deep (> 13500f t depth) HP/HT
(average 11000psi/280F) sour conditions. Sub-vertical natural fractures are the main contributors for
production for the Najmah-Sarjelu reservoir. Though Dolomitization improved reservoir characteristics
of Middle Marrat in part of the area, natural fractures play a dominant role in aiding production from
this reservoir. A dual porosity Geocellular model, encompassing this large area (~1800sq km) having
large gross reservoir thickness (~2200ft), with limited 39 well control is built to understand the HCIP
and as an input for the simulation model. A detailed interpretation of log, core, and seismic data
helped in refining the depositional model. The Discrete Fracture Network (DFN) models are constrained
by seismic attributes for realistic fracture population in the inter-well space. This paper presents the
journey from exploration to early production with focus on challenges being faced and the mitigation
strategies adopted in modeling and developing these fields.
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Shargi Shale Challenge from Geology to Drilling
More LessThe Fiqa Formation is an argillaceous to carbonate sequence which is present over most of North
Oman. It is Late Cretaceous in age and the lower member is a shale unit known as the Shargi Shale
(Santonian to early Campanian).
Drilling this sequence has been a challenge for PDO through out the years. The shale frequently reacts
with the drilling mud fluids, although reactions can behave differently in some cases. The amount of
time the shales are exposed to the drilling fluids is, however, important since the more exposure; the
more the shales swell, often resulting in caving. The consequences of these drilling issues are oversized
hole, pack-off tendency, induced losses, stuck pipe and frequently result in severe problems in
running and cementing casing..
Recent technology developments have been introduced and deployed and future technological
improvements are to be implemented. Changing drilling parameters have resulted in mitigating the
effect of caving and changes in well design have allowed the sections to be drilled faster meaning less
exposure, reducing drilling problems. Significant improvements have been seen in drilling performance
in terms of time and cost.
The paper plans to present case studies based on the experiences gained so far. The case studies are
taken from Gas Exploration drilling in North Oman. They will show how various thickness of Shargi
Shale in the area were encountered and how each was dealt with. Learning gained from drilling these
wells has enabled PDO to reduce shale exposure times and prevent the shales swelling and reduce
caving into the hole.
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Meeting Today’s Exploration and Development Challenges with Wide Azimuth Seismic Acquisition
Authors Funmi R. Ebiwonjumi, Zuwena Rawahi, Cees van Eden, Mohammed Mazrui and Martin HealeyRecent challenges in the global economy call for efficiency in all aspects of the oil and gas exploration
and exploitation processes. The South Oman Salt Basin comprises of over 7 km basin fill complex with
a mix of clastics, carbonates and evaporites deposited over a period of 600 million years. The
prospective sequence of isolated Ara carbonate stringers occurs near the base of the mobile Ara Gp
evaporates that constitute the main structural control on both intra-salt and post-salt deposits. The
area lacked good quality seismic data for consistent interpretation of the self-sourced Ara carbonate
stringers. The low confidence in seismic picks, culminating into broad depth uncertainty ranges, in
prospecting for the sometimes tectonically altered stringers necessitated a new fit-for-purpose seismic.
The recent acquisition of wide azimuth (WAZ) seismic data over the greater Birba area brought relief in
exploring and developing the Ara play. By deploying receivers over a large area (8 x 12 km), the WAZ
geometry allows sampling of the complete wave-front reflected from the subsurface. This improvement
comes with the associated challenge of multi-data cube interpretation, huge IT infrastructure
requirements and the need for 24 hours operations. Evaluation of the WAZ seismic (first delivery)
showed improvement in ease of interpretation (loop definition and continuity), better structural
definition, enhanced attributes (frequency and amplitude) and improved well-to-seismic matches. This
implies a more consistent interpretation of Top Salt with the added value of an improved depth
conversion of the intra-salt carbonate stringers. The new WAZ seismic data increased the confidence in
the exploration and development evaluation of the Ara stringer play. The improved subsurface imaging
will improve our subsurface de-risking efficiency.
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Practical Implementation of Wave-Equation Datuming for Resolving Near-Surface Problems
Authors Khaled Al Dulaijan and Saleh M. Al-SalehComplicated near surface geology and rugged topography can degrade the quality of the seismic
images. Time shifts or statics are still the work horse for resolving near-surface related problems.
These shifts are usually computed from simple near-surface velocity models. More recently, refraction
tomography was used to build more sophisticated models. The limitation of statics is that they are
based on vertical ray-path assumption. When this assumption is violated, as in areas of complex
geology, this solution fails to resolve the distortions caused by the lateral velocity variations. Waveequation
datuming (WED) is a powerful tool to resolve near-surface related problems. It was
introduced about thirty years ago but still is not a production tool yet, due to its need for accurate
velocity models. Unlike conventional near-surface solutions, WED does not fail for complex nearsurface
models, such as those of refraction tomography.
In this paper, the evolution of conventional near-surface solutions is reviewed, and then those
solutions are compared to WED. Also, we discuss how WED can practically be implemented in a
production environment by showing a processing workflow, which can handle the data regularization
and interpolation as well as velocity model building. This is demonstrated using a 2D seismic line
acquired in an area with a challenging near surface geology.
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A Study from Source Rock Causing False Bright Spots
Authors Ravindra K. Singh, Mohammed G. Al-Otaibi and Harianto H. SoepriatnaA strong 3-D seismic amplitude anomaly, thought to be associated with the Upper Jurassic Hanifa
reservoir, was interpreted to be due to an increase in the porosity of Hanifa carbonates. The Hanifa
formation overlain by the Jubaila source rocks is present in the Jafurah basin, east of the Ghawar Field
in Saudi Arabia. After drilling exploratory well 1, the targeted Hanifa carbonates proved tight with
porosity generally less than five percent. A post drilling study was taken to evaluate the rock properties
and the cause of the seismic bright anomaly. The study investigated the effect of reservoir thickness,
porosity, lithology, pore fluid type, and total organic content (TOC) on acoustic impedance; in both the
Hanifa and Jubaila formations. Synthetic normal incident traces were generated to understand the
effect of changes in these reservoir properties on the seismic. This paper summarizes the results of
investigations for finding the cause of seismic amplitude anomalies as seen at the top of the Hanifa
carbonates.
It was concluded that porosity is the dominant factor in the strength of the observed anomalous
seismic amplitude in study area. The porosity was mainly caused by high TOC in the Jubaila source
rock. The study finds an inverse proportional relation of TOC with the acoustic impedance. As the
acoustic impedance decreases with increasing TOC within Jubaila, the impedance contrast between the
base Jubaila and the top Hanifa increases. Hence, amplitude brightening would result at the Hanifa top
due to increased TOC within the Jubaila formation.
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A Genetic Algorithms Approach for Prediction of Compressional and Shear Wave Velocities from Petrophysical Data: from Example from Sarvak Carbonate Reservoir, Iran
More LessCompressional and shear wave velocities (Vp and Vs) are important reservoir characteristics which
have many applications in prtrophysical, geophysical and geomechanical studies. These parameters
(especially Vs) are obtained directly from core analysis in the laboratory or by Dipole Sonic Imager
(DSI) tools. Since the laboratory methods are very expensive and time consuming; and the
conventional sonic tools can not measure Vs, studies are led to find new methods for wave velocity
estimation. Many researchers have tried to predict Vs from well log data, Most of these studies have
been carried out for Vs estimation in sandstone reservoirs. Since carbonate rocks are considered as the
major parts of the world's oil and gas reservoirs there is a need to study more about Vs and Vp
estimation in these types of reservoirs. In this study Vp and Vs were predicted from well log data using
genetic algorithms (GAs) technique in an Iranian carbonate reservoir (Sarvak Formation). A total of
3030 data points of two wells from Sarvak carbonate reservoir which have Vp, Vs and conventional
well log data were used. These data were divided into two parts, one part used for constructing GAs
models and the other part used for models testing. The measured mean squared error of predicted Vp
and Vs in the test data was 0.0296 and 0.0153 respectively. Prediction in carbonate rocks is so difficult
because of diagenetic processes; however, GAs give reliable results. Therefore using this methodology
Vp and Vs can be obtained for Sarvak Formation in other wells of Abadan Plain which have no Vp and
Vs data.
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Geophysical Reservoir Monitoring Technologies: Screening to Field Implementation for a Carbonate Field Undergoing Steam Injection
When it comes to geophysical monitoring of mature fields undergoing Enhanced Oil Recovery (EOR),
new challenges demand new ideas. However, with a myriad of products and solutions available for
reservoir monitoring, it is important to select technical solutions that increase value by either
‘illuminating’ oil that would otherwise be missed or by aiding in improving reservoir management by
increasing production and/or reducing risk to infrastructure.
Petroleum Development of Oman (PDO) has over the years developed a workflow to best assess, pilot
and implement such technologies. Here we share an example for a carbonate field in the North of
Oman that is scheduled for full field implementation of steam injection. For this field, PDO have piloted
several technologies, some of which have proven to be of value during the pilots and others that have
been rejected. The feasibilities which can involve field trials have included several geophysical
surveillance technologies include surface deformation through Satellite (InSAR) and GPS, microseismic,
VSP, permanent source and receivers as well as microgravity to name a few.
Here we present some examples such as field trials and design studies done to justify full field
implementation of technologies such as micro-seismic monitoring. We also show how based on some
analysis results we concluded to reject 4D seismic surveillance in this case. We demonstrate how
successful technologies were selected and how we hope they can aid in increasing the field’s oil
recovery and create additional value.
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Mapping the Internal Structure of Sand Dunes in the Jafurah Desert of Eastern Saudi Arabia Using Ground Penetrating Radar
Authors Ademola A. Adetunji, Abdullatif A. Al-Shuhail and Gabor KorvinThree-Dimensional Ground Penetrating Radar (GPR) surveys were conducted in two locations to map
the internal structure of sand dunes in eastern Saudi Arabia. The 400 MHz antenna that was used
achieved a 4 m to 6 m penetration depth. The excellent resolution of about 8 cm made it possible to
identify the major internal features, such as cross-stratification and bounding surfaces.
The recorded radargrams proved useful in understanding the dune’s growth and migration in this area.
Results suggest that GPR is an important tool in any study of recent sand dunes as analogues of
hydrocarbon sandstone reservoirs of aeolian origin.
Laboratory analyses showed the presence of elevated amounts of iron-oxide-bearing minerals in some
dark layers of the sand in the study area. These elevated iron amounts might be the reason behind the
strong electromagnetic impedance contrasts that ultimately generate reflections on the GPR images.
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Maximising Recovery from Thin Oil Columns Part 2: Using Geophysics for Improved Reservoir Quality Prediction and Better Drilling Performance
Authors Fuping Zhu and Georg WarrlichPetroleum Development Oman (PDO) is currently developing a Cretaceous (Shuaiba Fm.) matrix
carbonate reservoir with a transitional thin oil column of 10 to 15m as a waterflood with over 1000m
long horizontal producers and injectors.
In-depth geophysical studies added significant value in a number of areas: improved understanding of
the reservoir extent, predrill prediction of porosity and fractures from quantitative interpretation (QI)
work and borehole seismics to accurately predict the distance from the horizontal producers to the top reservoir.
An improved velocity model utilizing regional wells from a 40km radius greatly reduced the depth
uncertainties to < 0.5% and predicted an extension of the field to the SE, resulting in a STOIIP increase of 20%.
QI volumes provided rock property and reservoir quality prediction for well placement and sequencing.
The porosity distribution predicted from acoustic impedance (AI) ahead of the main drilling campaign
was confirmed by the drilling results and continues to guide the well lengths and sequencing
successfully. Semblance and discontinuity extractions predicted subseismic faults and fractures along
the planned wells and improved well placement and reduced drilling risks.
Borehole Acoustic Reflection Survey (BARS), based on seismic data acquired post-drilling in the
borehole with a sonic tool, proves useful in validating distance from borehole to reservoir top and
recognizing subseismic faults. Results are used in subsequent side-track strategy, nearby well
placement to reduce unswept attic oil and understanding production behavior.
In conclusion, geophysics has demonstrated impacts on field extension, reservoir modeling and optimal
oil production beyond routine formation structure and fault definitions.
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Geochemical Characterization of Petroleum in Fahliyan Reservoir, Abadan Palin, Iran
More LessGeochemical investigation and basin modeling were used to infer the age, lithology, organic matter
input, depositional environment and burial history and timing of source rocks generation. The study
focused on the geochemical studies to better understanding the origin of the recently discovered oils in
lower cretaceous" Fahliyan formation" From Mahshar, Juffiar and Arvand Fields in Abadan plain of
Iran.. Biomarkers parameters of Pr /nC17 and Ph/nC18, pristan/Phytan versus carbon isotope ratio,
sterane ternary diagram, C29 Hopane /C 30 Hopane, Gammacerane /C31R Hopane,dibanzothiophen /
phenanterane ratio, shows that oils are derived from source rocks deposited in marine marl- carbonate
environment under suboxic - anoxic conditions with higher plant input , low salinity and type two
kerogen . The level of maturity is in peak oil generation zone and age related to source rock is between
Jurassic to Middle Cretaceous (StrC28/C29 = 0.5 to 0.7). Geochemical correlations among the oils and
prospective source rocks shows the oils genetically were originate from Garau (Lower Cretaceous) and
Sargalu (Mid-Upper Jurassic) formations. The Rock-Eval pyrolysis of cuttings samples from Garau and
Sargalu Formations in the wells of studied area are contain very good quantities organic matter, oilprone
maturity (zone of generation and expulsion), Type II of kerogen organic matter. For
reorganization of kerogen chemical structure at the molecular level in source rock evaluation, the
pyrolsis gas chromatography was carried out in one sample in Garau formation. The results indicate
organic matter of Kerogen is rich in aliphatic chains and poor in aromatic structure that corresponded
to Type II of kerogen. The phenols and thiophens compounds detected in sample indicate a
contribution of woody lignin (from higher land plants) in environment. One dimensional petroleum
system modeling of three wells built up to evaluate petroleum system of burial - thermal history,
source rock maturity and timing of generation with beicipFranlab genex software. In juffair and Arvand,
Models results indicate the peak oil generation of Sargalu source rock started during early Oligocene,
Grau late Miocene to present day . In Mahshar well, maturation started earlier and peak oil generation
occurred in late cretaceous for Sargalu and Oligocene to present day for Garau formations.
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Chimney Detection as a Tool in Hydrocarbon Exploration and Prospect Evaluation: A Case Study from Iran
Authors Sousan Sepahvand and Haleh RameshFinding new prospects with the lowest exploration risk is the main aim of hydrocarbon exploration.
Chimney detection is a technique which can be used as an exploration tool that provides important
information for prospect evaluation and charged or non-charged prospects identification.The petroleum
system activity can be established by this technique.It provides the spatial link between source rock,
reservoir rock, spill-points and geohazards.
The method applies multi trace seismic attributes, neural network modeling and the interpreter's
insight. It is necessary to integrate the chimney technique with geological information to get correct
and comprehensive results.
Gas chimney is a chaotic and noisy part of seismic data, where the continuity of reflectors is missing .It
often contains many very small reflectors, dipping in every direction. This study has been done to
determine how gas chimney detects hydrocarbon existence in underlying structure.
At first, seismic interpreter selects chaotic parts of seismic section as chimney and background as nonchimney,
the interpreter's knowledge and expert view help to choose these pick points.
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Modern Lessons for the Interpretation of Ancient Sabkhas: Examples from the Holocene of Qatar
Authors Jeremy Jameson, Mike G. Kozar and David D. PulsHolocene coastal and sabkha deposits of Qatar illustrate depositional and diagenetic trends that aid in
interpretation of ancient, evaporate-carbonate reservoir sequences. Recent data from offshore and on
land provide new insights into evaporate distribution, facies and stacking patterns of sediments
deposited during the Holocene sea level rise. Comparison of coastal deposits from different regions of
Qatar formed during the Holocene sea level rise reveals new insights into characterization of ancient rocks
Coastal Holocene sediments form a predictable profile from offshore to onshore, varying with sediment
supply, circulation, and bathymetry. Windward-facing coasts are characterized by narrow, coarse
grained facies belts dominated initially by fringing coral reefs, followed by formation of mobile sand
belts and islands with algal flats, mangroves, and sheets of aeolian sands. Oblique and protected
coasts are characterized by finer grain sizes, mixed carbonate and quartz sands formed in a mosaic of
subtidal, beach intertidal and aeolian settings. The leeward coasts are marked by quartz sands and
extremely high rates of coastline progradation.
Most coastlines are marked by low relief, with the result that high-frequency oscillations in sea level
are responsible for major offsets in facies tracts. Age dating reveals that inland sabkhas are relicts of a
high stand in sea level ~4000-6000 years ago. These areas are presently eroding. Extensive pedogenic
modification of original marine sediments (by burrowing, infiltration, micrite precipitation) creates
characteristic textures. Groundwater modification includes extensive precipitation of CaSO4 (nearly all
gypsum), minor halite, micrite, and dolomite. Gypsum precipitation near the water table may reach 20
-40% of sediment volume and extend over square kilometers.
Modern Qatar sabkhas are characterized by facies offsets at cycle breaks, laterally extensive erosional
surfaces and associated gypsum precipitation. Documentation of these features aids in recognition of
ancient sabkhas. Neither the sedimentary structures nor the biota are distinctive. Recognition of a
sabkha relies on understanding styles of diagenesis that modify sediment texture and interparticle
porosity. This process approach helps aid in sabkha recognition and to explain styles of diagenesis that
control reservoir properties.
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Fractures Detection Using Multi-Azimuth Diffractions Focusing Measure: A Feasibility Study from the Arab D Reservoir
Authors Abdulfattah A. Aldajani and Sergey Fomel3D azimuthal P-wave post stack seismic data has been analyzed to investigate the feasibility of using
multi azimuth scattering and diffractions focusing measure to detect azimuthal anisotropy anomalies at
the Arab D carbonate reservoir; hence, assisting in the identification of potential fractures (i.e. sweet
spots). Earlier studies and numerical examples demonstrated the azimuthal variations of scattering in
vertically fractured media. Azimuthal variations of the focusing measure for the scattering energy and
diffractions are estimated from stack data along a test 3D multi-azimuth sub-line, after segmenting the
data into four azimuthal sectors (stacks), each 45 degrees wide, and separating the diffractions and
scattering from the reflections, using the plane wave destruction technique. The analysis suggest the
presence of azimuthal anisotropy anomalies in the focusing measure and they are generally oriented W
-E (~N85E). This conclusion is consistent with the results obtained by using an independent seismic
technique which is based on a different but more accurate 3D analysis using 3D azimuthal pre-stack
reflection moveout, to study the amplitude variations with offset and azimuth (AVOA) and the normal
moveout (NMO) velocity. The intensity of the azimuthal anisotropy anomalies in the focusing measure
(hence, potential fractures), along the seismic profile, is also consistent with the results obtained from
3D prestack azimuthal anisotropy reflection moveout analysis. The structural geology of the area
supports the outcome of this study. This is the first attempt to apply azimuthal scattering and
diffraction focusing measure technology as a tool for fracture detection in Saudi Arabia. The technique
is fast since it is applied on stack data, as opposed to 3D prestack reflection moveout. This technology
could be applied to fracture detection by complementing existing seismic methods; especially in cases
where the 3D seismic azimuthal data acquisition is rather challenged and the application of full 3D prestack
AVOA and NMO velocity analysis for the target reservoir is less adequate.
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Application of 3D Seismic Multi-Attribute and Neural Network Technique for Reservoir Prediction: A Case Study for the Marrat Formation, Kuwait
More LessThe use of 3D seismic attributes for predicting reservoir properties away from the well bore has been
used routinely in the industry. Recently a study utilizing multi attribute analysis and neutral network
technique applied to one of the Marrat reservoirs in west Kuwait has not only described the reservoir
geometry but has also opened up new areas for exploration. Further, the seismic derived porosity
volume has been also integrated with the geological model for future well placement.
The Middle Marrat limestone reservoir of Jurassic age in the Dharif field is one of the major oil
producers in the area. This field discovered in 1988, is an elongated anticline trending NNE-SSW, with
a major fault to the west. The reservoir thickness varies from 50-230ft and porosities ranging from 12
to 20%. Since a Pilot water injection program is being initiated, a good reservoir description would be
essential for planning a successful injection program.
The seismic derived porosity volume derived from neural network analysis has been a key in identifying
inter-well areas as well as regions away from the wells with good porosity which is consistent with the
available geological information. Incorporating the porosity volume as a “soft constraint” to the
available geological model has further refined the model and is expected to assist in effective
placement of future wells.
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Geophysical Monitoring of Steam Flood in from Omani Heavy Oil Field
Authors Faisal A. AL-Kindi, Matthew Burreson and Donnie EnnsOccidental is conducting a geophysical monitoring program to aid optimization of production from a
heavy oil field in central Oman. The Permian age Gharif reservoir consists of three stacked sandstone
units spread over a gross interval of about 50 meters with average porosities of 30%. Oil recovery is
stimulated by steam injection into each of the three reservoirs to lower oil viscosity. Steam injection
and production alter reservoir properties such as temperature, pressure and saturation. A 4D modeling
study was carried out to investigate the impact of these reservoir changes on compressibility and
rigidity of the rocks. Synthetic seismic models were derived from our understanding of the reservoir
rock properties combined with the history matched reservoir models. The modeling predicts a change
in the reservoir interval velocities of approximately 10-15%, resulting in a change in acoustic
impedance that should be large enough to observe in surface seismic data. Modeling also suggests that
changes in the reservoir properties will be localized close to the steam injectors and that these
anomalies could be strong enough to identify in surface seismic without time lapse differencing. A
crosswell tomography survey was acquired through a well that injects steam into all three reservoirs.
The cross well survey confirms a reduction in reservoir interval velocity by 10% associated with the
steam injection. Comparison of the crosswell tomography cross section with the equivalent predicted
velocity section from the reservoir simulation highlights differences between the reservoir simulation
prediction and how steam is actually affecting the reservoir. Petrophysical and production surveillance
data have helped our understanding of these differences. The crosswell tomography helped in
assessing the connectivity vertically between the three reservoirs and horizontally between the study
wells as the resolution is higher in the cross well than in the surface seismic. The crosswell tomography
and modeled seismic response also serve to calibrate the surface seismic response which is needed to
highlight field wide lateral reservoir changes. Information gained from geophysical monitoring that is
correlated with observation and production data is important for monitoring steam movement in the
subsurface and optimizing field production.
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Utilizing Massive 3DVSP Data for Improved Structural Definition of Jurassic Reservoirs in Raudhatain and Sabiriyah Fields, Kuwait
The Raudhatain and Sabiriyah fields are situated in north Kuwait. In the Raudhatain Field, the Jurassic
reservoirs, Najmah-Sargelu and Marrat ,have two distinct northern and southern culminations,
separated by an intervening fault boundary; while in the Sabiriyah field the reservoirs are divided into
up thrown and down thrown sides along a NNE-SSW fault. In both the fields, the faults and associated
fracture networks have a significant impact on production.
In 2009, Kuwait Oil Company (KOC) acquired two massive 3DVSP survey in the Raudhatain and
Sabiriyah fields. The primary objective of the surveys were to improve the structural definition of the
Jurassic reservoirs, especially the Marrat reservoir and also to test the feasibility of characterizing the
fractured reservoirs using anisotropy information. The surveys consisted of 100-level multi-component
tool, combined with around 10,000 source points covering an area of around 64 square kilometers.
This is probably one of the largest onshore surveys in the region.
The high resolution and better signal to noise ratio in the VSP data, is expected to provide improved
structural definition in the vicinity of the well. This information will be utilized in locating future
appraisal wells. In order to reduce the survey time, a test was also conducted on four 2D lines of 6km
length, using four fleets of two vibrators, utilizing the High Fidelity Vibratory Seismic (HFVS) technique.
While the processing is ongoing, the results of the test are expected to produce data quality which will
be equivalent or better than conventional methods.
Based on the outcome of these surveys, future 3DVSP’s maybe acquired to help in developing the fields.
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Devonian Miospore Stratigraphy and Palaeogeography of the Northern Margin of Western Gondwana
Authors Pierre Breuer, Philippe Steemans and Merrell MillerWell-preserved Devonian miospore assemblages from Saudi Arabia and North Africa allow a good
correlation of the studied sections and the establishment of a biozonation for the northern margin of
Western Gondwana. More than 200 miospore species, including many new species endemic to Western
Gondwana, have been identified in 16 sections. Although the standard Devonian miospore zonations
established in Euramerica are commonly used in most palynological studies, they are not always easily
applicable to Western Gondwanan localities because of the endemic nature of the assemblages.
Therefore, a new regional biozonation based on Gondwanan miospore species has been established. It
consists of nine assemblage zones, eight interval zones and two acme zones, from the late Pragian to
the early Frasnian. A biozonation based on the first downhole occurrence of species is also developed
for oil exploration. This provisional downward biozonation consists of eight interval zones. Although it
seems relatively reliable by comparison with the previously defined upward biozonation, it needs to be
further tested. The review of the miospore assemblages from the literature has allowed evaluation the
provincialism of assemblages on a worldwide scale for the Emsian-Givetian interval. Coefficient of
similarity has been calculated between palynofloras from northern and southern Euramerica and
eastern, southwestern and northwestern Gondwana. The resulting low values correspond to low to
moderate similarity of miospore assemblages. The provincialism may be explained by a latitudinal
climatic gradient as no significant palaeogeographic barrier is known during this time. Despite a certain
degree of provincialism, floristic interchanges existed. Saudi Arabia and North Africa constituted an
intermediate warm temperate region and shared taxa mainly from more arid Euramerican localities in
the north, and cooler Southwestern Gondwanan localities in higher latitudes. It seems that a
progressive homogenization of the vegetation took place in Middle Devonian as the standard
Euramerican biozones are more easily recognized in Givetian than in Eifelian and Emsian. This
transition from provincialism to cosmopolitanism during the Devonian is not only shown by palynofloras
but also by the palaeogeographic distribution of many other fossil groups. It is likely due to a decrease
of the latitudinal climatic gradient in Middle Devonian.
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Characterization of a Class IV AVO Sand in Central Saudi Arabia
Authors Husam M. AlMustafa and Luis GiroldiRock physics modeling plus AVO inversion are combined to provide a heuristic approach to the
characterization of the Unayzah A Sands in Central Saudi Arabia. These sands exhibit a Class IV AVO
anomaly (large negative amplitude that dims slightly with increasing offset). Wells in the study area
are used to construct a detailed petro-elastic model (PEM) to relate elastic properties in a physically
consistent manner to the reservoir properties such as lithology, porosity and water saturation. This
involves computing interval properties such as VpVs ratio, acoustic impedance, gradient impedance
and interface properties such as intercept and gradient for different facies (oil saturated-, gas
saturated-, brine saturated-sands and overlying shale). The established rock physics relationships are
used to extract likely hydrocarbon charged-geobodies from seismic derived AVO attributes and
simultaneous inversion results. Validity of the results is based on the detection of the anomalous zones
on the different attributes.
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Ichnology of the Early Devonian Jauf Formation in Northern Saudi Arabia
Authors Stanislaw Leszczynski, Pierre Breuer and Merrell MillerThe Jauf Formation in northern Saudi Arabia embraces a several hundred meters thick succession of
mixed siliclastic-carbonate marginal marine and shallow marine deposits dated as late Pragian to late
Emsian. Sedimentological logging of two pairs of core holes (JNDL-3, JNDL-4 and BAQA-1, BAQA-2),
located about 350 km apart, has supplied original data on bioturbation structures recorded in the Jauf
formation. In northern Saudi Arabia, the formation is divided into five members differing in lithofacies.
Combined cores form a 270 m thick composite section of the Jauf Formation. This study aims primarily
to show the most distinct types of bioturbation structures recorded in the examined cores, their
distribution in the succession and relationship to lithofacies, palynofacies, and depositional
environments. The investigated deposits display highly variable, lithofacies controlled bioturbation style
and intensity. The most intense burrowing occurs in deposits dominated by fine-grained sand and
green mud. A tendency of an increase of bioturbation intensity in heteroliths consisting of interbedded
very thin sandstone, siltstone and mudstone layers suggest that the totally burrowed beds originally
also were heteroliths. Their total burrowing results from slow sedimentation rate, rather high fertility,
low salinity and satisfactory aeration of the depositional setting. The ichnofossils most distinct in
succession divisions dominated with fine-grained sand and mud which in vertical sections show
patterns corresponding to Spirophyton-Zoophycos, Rhizocorallium and Phycodes flabellum were
produced by opportunistic organisms adapted for areas strongly influenced by fresh water and land (in
brackish water). Their distribution in the succession corresponds with the distribution of Spirophyton,
Rhizocorallium and Phycodes flabellum in other areas. The absence or subordinate occurrence of
burrows in mudstone to grainstone type limestones results in part from their mass deposition by storm
processes. Common interbedding of non burrowed black mudstones and restriction of bioturbation
structures to faint sediment mottling, indicate sedimentation in areas hostile for macrobenthos, and
particularly for the deep sediment penetration. The boundary between the Jauf and the underlying
Tawil formations is distinctively marked by plant root structures.
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Buried Evaporite Paleokarsts in the Arab Evaporites and the Hith Formation, Saudi Arabia
Authors Karl Leyrer and Franz O. MeyerEvaporites represent a major lithology in the hydrocarbon-rich Upper Jurassic section of Saudi Arabia.
In many places these evaporites form competent seals and provide a framework for potential stratigraphic traps.
Despite this obvious importance, little is published about the internal architecture of Arab and Hith
Formation evaporite sections. In-depth study of the anhydrite sections and their relationship to
interbedded carbonate stringers and reservoirs help clarify interpretation issues concerning evaporite
fabric patterns, internal organization and their sequence stratigraphic position in the Upper Jurassic.
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The Main Advantages to Use the Integration between Geology and Artificial Intelligence Techniques to Interpret Image Logs, an Example from Algeria
Authors Raffaele Di Cuia, Denis Ferraretti, Giacomo Gamberoni and Eric PortierImage logs hold important information about the subsurface sequences and they provide information
about bedding and fault/fracture spatial distribution and characteristics. They can supply insight on the
rock texture, textural organization and porosity types and distribution. To reduce the subjectivity of the
interpretation and cut the interpretation time we developed and tested a new semi-automatic process
for image log interpretation using a new software.
This process led to the development of an expert system (called I2AM) that exploits image processing
algorithms and clustering techniques, to analyze and classify borehole images. This system
extrapolates the maximum amount of information from the image logs by considering not only the
surfaces that cut the borehole but also the textural features of the images.
Once the image log are analysed the application of clustering techniques to the values extracted from
the borehole images supply a consistent classification of the images and the propagation of this
classification along the logged section. In this way, we can automatically extract rock properties
information with two main advantages: (i) avoid the subjectivity of the interpretation, (ii) reduce the
interpretation time. The final results of this process is a set of “image facies” identified along the image
log obtained by a largely automated log interpretation, although some level of human interaction and
correction is still necessary.
We define the clustering application as semi-automatic because the interpreter can decide, based on
his geological background and on the geological characteristics of the logged section, to keep the
clusters/classes proposed by the system or modify the number of clusters/classes. The clustering
process and the propagation of the classes along the logged section is very fast (30 seconds) allowing
an interactive approach, producing several scenarios with different number of classes and/or allowing a
quick update of the image log interpretation once more data/knowledge is acquired.
This approach was tested on 5 wells from north Africa where a previous image log interpretation was
performed. The new interpretation based on this system made 3 years later (with more data and
information) produced more refined results in very short time.
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Origin, Distribution and Petrophysical Properties of High Porosity/Permeability Sub-Horizontal Drains within a Dolomitised Sequence: Lessons Learned from Outcrop Analogue
Authors Raffaele Di Cuia, Alberto Riva, Bruno Caline and Cecile Pabian-GoyhenecheDolomite sequences and intervals often show the best reservoir potentials and are considered as key
productive zones. It is difficult to completely unravel the diagenetic evolution of a carbonate sequence
because of the complexity and variety of the processes that affect the rocks through their evolution.
This is mainly due to the interactions between different processes and, in subsurface, because of the
lack of complete datasets or the limited spatial representativity of well data. The origins and spatial
variability of reservoir properties in structurally-controlled, partially dolomitised reservoirs are poorly
understood because of their complexity. The use of outcrop analogues for better understanding
subsurface reservoirs is essential to reduce some of the main reservoir uncertainties. The geometry,
internal heterogeneity and petrophysical properties of dolomite bodies were studied in a Jurassic
partially dolomitised outcrop analogue in the Southern Alps using an integrated, multidisciplinary
approach. Dolomitisation of the lower part of the studied section led to the development of good
petrophysical properties for a potential hydrocarbon reservoir, in particular by the formation of porosity
systems interconnected with fracture and fault networks, hence assuring a consistent permeability
through the entire sequence. The dolomitisation process determined a highly variable porosity network
controlled by the original facies, the degree of dolomitisation and the structural framework. Near open
fracture swarms or faults, the dolomitisation front tends to uprise, sometimes generating vertical
chimneys that can cross the overlying sedimentary succession. In these zones the dolomite is massive,
with a complete reworking of the original limestone, sometimes with strong evidence of hydro
fracturing related to overpressured fluids.From these vertical dolomite bodies, high porosity and
permeability bedding-parallel dolomitic bodies develop with lenticular or planar shape. These bodies
can be 10’s of meters in length and 1-3 meters in thickness and are often stacked one on top of the
other along major fault zones.Based on core samples the porosity associated to these dolomitic bodies
can be up to 25-30% with an extremely good connectivity. Matrix porosity and permeability, directly
measured on plug analysis, vary respectively between 0.5-25% and 0.05-40 mDarcy. These
petrophysical data appear strongly related to the diagenetic facies associations.
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Integrated Static Reservoir Modeling of a Khuff Reservoir, North Oman
The Khuff Formation of the Arabian Peninsula comprises mixed carbonate/evaporitic sequences of Late
Permian - Early Triassic age deposited on a widespread epeiric ramp attached to the Arabian Shield.
The Upper Khuff oil and gas reservoir is characterized by lithological and reservoir quality
heterogeneities as result of both depositional history and diagenetic overprint.
Further to its gas discovery and initial production, PDO has recently updated the Upper Khuff geomodel
by integrating new data, such as reprocessed seismic volumes, appraisal well results, and core and fluid data.
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Geological and Near-Surface Geophysical Data Comparison Helps Integration of Outcrop and Subsurface Data for Fractured Carbonate Reservoirs Description
Authors Raffaele Di Cuia, Davide Casabianca, Alberto Riva, Emanuele Forte and Mara MarianThe heterogeneity of fractured carbonate reservoirs invariably controls their flow performance and
economic value. Depositional facies, diagenesis and fractures, their distribution, spatial and genetic
relationships are the sources of the heterogeneity of storage and flow properties within these
reservoirs. Understanding such spatial and genetic relationships between sedimentary facies,
diagenesis and fractures is fundamental to adequately describe fractured carbonate reservoirs, model
their dynamic performance and identify the most appropriate development and management strategies.
Particularly for fractured carbonates, outcrops are essential sources of information, in three-dimensions
and at a wide range of scales, for making plausible and useful descriptions of the elements listed
above. The challenge remains the effective use of outcrops in a subsurface modelling project where the
co-located information are wellbore and seismic data. We aim to tackle this challenge starting from
comparing the different information provided by direct geological observation and remote sensing and
the different models resulting from using one or the other dataset in isolation.
We have selected a large quarry excavated within shallow water Cretaceous carbonates of the Apulian
platform in the Italian Apennines foreland where the two datasets have been acquired. Geological
(sedimentological, diagenetic, structural) data obtained from direct and detailed outcrop observations
and measurements provide the means for building a detailed, geologically consistent 3D model through
interpolation between available 2D exposures. Geophysical data consisting of a 3D survey and 2D lines
acquired using ground penetrating radar (GPR), provides more spatially continuous (albeit lower
resolution and at times geologically inconsistent) geometric information.
Comparison between the models resulting from the two different datasets highlights some important
pitfalls related to scale, resolution, interpolation and extrapolation assumptions that modellers
invariably have to make when building reservoir models with detrimental effects to the usefulness of
these as prediction tools. This work provides insights on the modes of integrating outcrop and
subsurface datasets for building fractured carbonate reservoirs models.
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Stratigraphic Framework and Exploration Potential of Early Jurassic Marrat Formation, Northern Saudi Arabia
The Marrat carbonate reservoir produces a significant volume of hydrocarbons in the Partitioned
Neutral Zone (PNZ) and Kuwait. This play has emerged as an increasingly important Jurassic
exploration target in Saudi Arabia, the PNZ and Kuwait. The Marrat Formation is unconformably
underlain by late Triassic Minjur Formation clastics and overlain unconformably by middle Jurassic
“Dhruma Shale”. It comprises a composite 3rd order sequence with the Lower, Middle and Upper
Marrat each comprising 4th order sequences.
The Lower Marrat consists of mixed clastics and carbonates with anhydritic interbeds. It is the earliest
basin-fill in response to early Jurassic marine transgression that flooded the platform from the
northeast, progressively onlapping onto the Qatar Arch and the Arabian Shield. The Lower Marrat was
deposited in a very shallow, and relatively low energy environment with limited accommodation space.
The cleaner, grainy carbonates are confined predominantly to the northern onshore and offshore areas.
Overlying the Lower Marrat carbonates is the “Lower Marrat Shale”, which thickens to the southwest
and thins substantially to the northeast, suggesting a possible siliciclastic influx from the Arabian
Shield. The top of the Lower Marrat was locally eroded and marks a 4th order sequence boundary.
Renewed flooding and moderately increased accommodation space during the Middle Marrat resulted in
the major transgression and maximum flooding onto the platform with widespread carbonate
deposition. An extensive shoaling complex and backshoal flats, with mixed skeletal and oolitic
grainstones-packstones, were developed as aggrading and generally north-easterly prograding
highstand systems in the northeast onshore and offshore areas. Latest Middle Marrat sediments are
mostly anhydrites, which provide an excellent marker and top seal for the Middle Marrat across the
region. The Upper Marrat consists of shaley carbonates and thinly intercalated evaporites, particularly
in southerly and westerly, more restricted areas. The post-Marrat subaerial unconformity has been
identified in the subsurface through well-log correlations and is evident in a recently cored shallow well
in an outcrop south of Riyadh.
Exploration opportunities for the Marrat play have been identified by integrating the reservoir fairways,
source rocks and seals through 3D basin modeling. Potential stratigraphic traps within Marrat
carbonate reservoirs may add additional hydrocarbon resources.
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Migration Velocity Analysis Using the Common Image Cube
More LessDownward-continuation methods are very sensitive to velocity models (Berkhout, 1982; Yilmaz and
Chambers, 1984; Claerbout, 1985; Al-Yahya, 1989; Deregowski, 1990; Liu and Bleistein, 1994; Varela
et al., 1998). Using inaccurate velocity models in these methods can generate low quality images.
Their sensitivity to velocity errors, however, makes them a good tool for velocity analysis. Using
migration methods for estimating velocities is generally known as migration velocity analysis (MVA).
Migration velocity analysis consists of the domain in which it is carried out, and the inversion scheme
used to update the velocity model. There are different domains and inversions schemes for MVA. In
this paper, some well known domains for migration velocity analysis will be presented and linked to
each other. These domains include residual curvature analysis (RCA, Al-Yahya, 1989), depth focusing
analysis (DFA, Faye and Jeannot, 1986), and the common focus point (CFP, Berkhout, 1997.a)
analysis. Presenting them using the same migration method, shot profile migration, makes them easier
to understand and compare. I then show how different aspects of the RCA, DFA, and CFP methods can
be combined into a unified domain for migration velocity analysis. I will call this approach the common
image cube analysis (CICA). Instead of just taking the zero-lag cross-correlation at each depth level as
in RCA, all the cross-correlation lags are stored. The result is a cube that contains more prestack
information than the other methods.
This cube was first mentioned by Faye and Jeannot (1986). More recently, different slices of this cube
were shown by Wang et al. (2005) to relate focusing errors to velocity updates using tomography. The
CFP approach offers more prestack information than the RCA and DFA approaches, but less prestack
information than the CICA approach. Since the RCA, DFA, and CFP approaches have been shown by
numerous authors (see e.g. Al-Yahya, 1989; Faye and Jeannot, 1986; Berkhout, 1997b; Berkhout,
2001) as appropriate domains for MVA, the CICA is also expected to do so, since it is just the
integration of different aspects of these methods. In fact, the traveltime tomography that is currently
used in CFP (Cox, 2001; Thorbecke, 1997; Berkhout, 1997b; Berkhout, 2001) can be used in CICA to
update the velocity model. The CICA is a promising tool for MVA, but requires developing some
software in order to compare it with other approaches.
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3-D Seismic Evidence of Tertiary - Cretaceous Karsts and Cretaceous Marine Channels from Offshore Oil-Field in Abu Dhabi and Outcrop Analogs from United Arab Emirates
Tertiary to Cretaceous age karsts and Cretaceous marine channels were observed from recent 3D
seismic interpretation of an offshore Abu Dhabi oil-field. The seismic evidence of karst features was
investigated using full-stack, spectral whitened, and discontinuity volumes. In addition, circular
features were detected at specific sequence boundaries after examining curvature maps, disturbed
amplitudes, velocity effects, and attenuation attributes. Several karsts and collapse disturbances tend
to be associated with anhydrite beds overlaying thick carbonate intervals and seem to be limited to the
Tertiary stratigraphic column; other karsts were observed to be limited to Cretaceous dolomite and
limestone reservoir intervals. The Tertiary age karsts were observed to cause seismic reflectors and
amplitude disturbance at various depths, whereas the Cretaceous age karsts tend to be limited in
radius and depth and have more limited effect on seismic response. The Cretaceous marine channels
were also observed to cause seismic reflectors and amplitude disturbance at various depths but with
opposite velocity response of both karst systems.
In the attempt to better understand the limit of some karsts and marine channels, well data (wireline
log, conventional core, and thin-section) were investigated within the karst areas and integrated with
3D seismic data. 3D seismic based geometries and attributes were analyzed to evaluate the possibility
of detecting the karsts damage-zone and marine channels limit versus velocity effect with depth due to
fill material. Another effect investigated is that of fracture-fault zone distribution relative to karst
localization and possible deep fault relationship to each marine channel cut.
Analogue karst features of a similar age-range (Tertiary and younger) to the seismic examples occur
within Jebel Hafeet in the onshore UAE, where solution effects, debris fill, mineralization, and collapse
effects can be observed and compared with the offshore examples. Here, structural discontinuities also
enhance the karstic features. Cretaceous marine channels outcrop analogs additionally were
investigated in northern Emirates.
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The Multiple Challenges of Processing a 3D Marine Streamer Survey
Authors Omar Hassoun and Pierre LegerMultiple reverberations, linear refraction noise, aliasing, and random noise were just a few of the
challenges faced while processing a 3D Marine Streamer data set in the Arabian Gulf. The purpose of
this paper is to present the processing sequence that was undertaken to distinguish between the
primary reflections from the multiples and unwanted noise. In presenting the processing flow, we will
examine the methods used to reduce the multiples as well as other undesirable noise that seriously
affects the geoscientists’ ability to search for oil and gas reservoirs. An attempt is made to present a
complete processing sequence over the test area. In keeping with this aim, a short discussion of near
surface effects is presented as well as issues involving interpolation, regularization and scaling. Before
the issue of noise attenuation was tackled, it was observed that the greatest structural complexity is
most evident along prestack migrated cross lines. With this in mind, a conservative approach was
taken to attack the noise in the safest possible way. By adopting this approach, we are able to
establish a safe reference PSTM that would be used to evaluate the effectiveness of any noise
attenuation. The processing flow adopted is shown to make significant progress against the major
challenges presented by the 3D Marine Streamer data set.
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Innovative Processing Strategy for 3D Shallow Marine OBC Seismic Data of Giant Offshore Oil Field in Abu Dhabi, United Arab Emirates
Authors Joe Reilly, Andrew P. Shatilo, Zyg J. Shevchek, Raed El-Awawdeh, Naeema Khouri and Jie ZhangAt a giant oil-field offshore Abu Dhabi, U.A.E., an ocean-bottom cable (OBC) seismic survey was
conducted to acquire seismic data in areas of shallow water and intensely developed production
infrastructure. OBC data are acquired utilizing two types of detectors: hydrophones (fluid-pressure
change detectors) and single- or multi-component geophones (particle-velocity or acceleration
detectors). The conventional seismic processing strategy is to sum the two sensors very early in the
processing sequence. However, due to numerous factors, the differences between the physical
measurement characteristics of hydrophones and geophones, their data character (including noise
levels, multiple content, coupling effects) can be very dissimilar. In this project a strategy was
employed which avoided summing of the separate sensor data until just prior to imaging. This allowed
us to investigate the differences between the two data types, optimize the processing flow for the
individual sensors and then sum the sensor data in a manner which maximized the primary signal
content in the dataset. Investigations of the raw field data clearly defined significantly different
responses of the separate senor data to the surface wave field. This was attenuated by the utilization
of a “physics based” 3D surface wave mitigation algorithm applied to the separate sensor datasets. In
addition, the separate sensors clearly demonstrated wavelet character changes beyond what would be
predicted from conventional ghost filter modeling. As a result, different wavelet shaping filters and
surface consistent amplitude compensation corrections were required to be applied to the two sensor
types. In addition, the very small scale (<10ms) statics were observed to vary on the hydrophone and
geophone data, again necessitating separate compensation for this phenomenon.
Finally, interpretive driven deconvolution, residual amplitude compensation, attribute validation and
zero phasing were applied to the data in order to maximally condition it for subsequent quantitative
and qualitative analysis. In this paper, we show a step change in seismic imaging quality on a shallowwater
Arabian Gulf dataset as a result of this processing strategy. We will compare our results with
those obtained using more conventional approaches.
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Scanning Anisotropy Parameters in Inhomogeneous Media
More LessParameter estimation in an inhomogeneous anisotropic medium offers many challenges, chief among
them is the trade off between inhomogeneity and anisotropy. It is especially hard to estimate the
nonhyperbolicity parameter η in complex media. Using perturbation theory and shanks transform, I
expand the solutions of the anisotropic eikonal equation for transversely isotropic (TI) media with
vertical symmetry axis (VTI) in terms of the independent parameter η in a generally inhomogeneous
elliptically anisotropic medium background. This new VTI traveltime solution is based on a set of
precomputed traveltimes extracted from solving a number of linear partial differential equations
sequentially. These traveltimes serve as the coefficients of a Taylor-type expansion of the traveltime in
terms of η. Shanks transform is used to predict the transient behavior of the expansion and improve its
accuracy. A homogeneous medium simplification of the expansion provides classical nonhyperbolic
moveout descriptions of the traveltime that are more accurate than other recently driven
approximations. In addition, this formula provides a tool to scan for anisotropic parameters in a
general inhomogeneous medium. A Marmousi test demonstrates the accuracy of this approximation.
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Carbonate Enhanced Seismic Mapping Using Post-Stack Band-Pass Frequency Seismic Volume Filtering of Two Offshore Fields in Abu Dhabi, United Arab Emirates
Authors Raed El-Awawdeh, Jie Zhang, Zyg J. Shevchek, Naeema Khouri, Assif Mirza, Christopher Harris and Joe ReillyDuring recent carbonate seismic interpretation projects of two offshore fields in Abu Dhabi, UAE,
several carbonate/anhydrite intervals were mapped using Band-Pass frequency filtered 3D seismic
volumes. Two types of band pass filtered seismic volumes were used to enhance Eocene/Palaeocene
and Cretaceous carbonate reservoir intervals, where either Low-Pass or High-Pass frequency filters
were designed specifically for the specific geologic purpose and target interval.
The first offshore field high resolution 3D seismic volume covers a salt-diaper pierced shallow
carbonate and anhydrite layers with complex salt-tectonic fault and karsts geometries. Interpretations
for several carbonate / anhydrite intervals, and faults are needed to be accurately mapped for highly
deviated well-bores targeting karsted and faulted Rus (Eocene Anhydrite) and Umer Radhuma
(Palaeocene Carbonate) geologic intervals. Significant seismic reflection events and fault displacement
image improvements of shallow seismic high to low impedance reflectors were accomplished by using a
Low-Pass frequency filter with a 6 - 35Hz frequency range. Continuity of seismic events and fault
offsets were enhanced significantly and confirmed by well-ties and subsequent time/depth conversion
model. The second offshore field 3D seismic volume covers a giant offshore Oil field where the main
seismic mapping targets were Kharaib (Cretaceous Carbonate) reservoir faulted intervals. Similar to
the first field positive results, significant seismic continuity and fault displacement image improvements
were accomplished by using a High-Pass frequency filter with a 60- 100Hz frequency range.
The key objective of this paper is to show the significance of certain seismic frequency ranges which
enhance specific geologic features at both early and late carbonate depositional systems, also to
explain the workflow developed specifically to tackle seismic frequency ranges for well drilling
operations and reservoir characterization purposes in carbonate depositional settings.
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Depth Imaging Strategy for Low Relief Carbonate Platform Giant Oil Field Offshore Abu Dhabi, United Arab Emirates
An offshore Abu Dhabi low relief carbonate platform giant oil-field is characterized by various structural
complexities that significantly affect reservoir and deeper level intervals. Inter-bedded clastics and
carbonates within the overburden produce rapid velocity inversions and lateral variations that cannot
be explicitly accommodated by time migration algorithms. Imaging challenges due to shallow geology,
such as presence of faulting and small scale features of about 500m or smaller in diameter. Project
goal was to determine the potential uplift to interpretation of depth imaging over conventional time
migration, including the time stretched to depth technique. The depth imaging velocity model created
as a result of this project accounts for both the long and the short wavelength velocity anomalies and
was constructed by explicitly including all available well data information, interpretation and seismic
velocity information. Due to seismic data high amplitude coherent and random noise, strategic data
conditioning flows were applied to ensure that high frequency data was retained in the stack, to
attenuate the noise, mitigate acquisition footprint and some of the overburden effects. To limit the
migration noise and to better account for the effects of the small scale structures, hybrid time/depth
imaging scheme was created which utilizes 3D dynamically corrected DMO sub bin stacks, followed by
zero offset wave equation migration. This was determined to be more effective than a conventional
Kirchhoff approach. The migration of each individual offset group with a velocity model that honors the
3D complexity found in the overburden allows each offset group to focus differently, thus providing
uplift over the post-stack depth migration, without sacrificing the benefits of signal-to-noise
enhancement through sub-stack. To accurately evaluate the potential interpretation uplift of prestack
over post stack depth imaging and time imaging, it was necessary to implement a fairly exotic postmigration
processing flow to ensure that the depth imaging products had similar signal-to-noise, waveshaping
and de-multiple characteristics as the time migrated products. Results from time-to-depth
stretching, time migration, post-stack depth migration, prestack depth migration, and conventional
Kirchhoff prestack time (or depth) migration comparisons will be demonstrated and discussed.
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Movable Oil Identification and Viscosity Estimation in Lower Fars Heavy Oil Reservoir – A Case Study
Authors Khalid Ahmed, Mansoor A. Rampurwala and Girija S. PadhyReservoir fluid typing is one of the key parameters in well completion and field development planning.
While the resistivity and nuclear logs provide basic information about fluid type, detailed but noncontinuous
fluid profiling is obtained from downhole PVT sampling. The recent advancement in NMR
logging helps immensely for the continuous fluid identification.
The Lower Fars formation in Kuwait is a shallow unconsolidated sandstone heavy oil reservoir. The oil
viscosity in the field varies from tens to thousands of centipoises both vertically and laterally. In-situ
PVT-quality Fluid sampling with wireline formation testers in this low pressure reservoir is quite
challenging and time consuming. Advanced NMR logging technique deployed was successful in
identifying movable oil and to provide a continuous oil viscosity profile.
The presence of clay within heavy oil sand affects fluid identification as the clay bound water and
heavy oil NMR signals overlay and occur at fast relaxation domain. The standard diffusion method has
poor resolution at early T2 domain and interpretation suffers from the effect of restricted diffusion. The
advanced NMR logging tool provides measurement at multiple radial depths and the diffusion
measurement is found useful in identifying movable oil in such environment. An integrated approach
combining advanced NMR log with the nuclear and resistivity logs is used to identify movable oil and
fluid type variation and to estimate a continuous oil viscosity profile. NMR Station measurements
helped to enhance signal to noise ratio to increase confidence in log interpretation. The viscosity profile
estimated using this approach correlate quite well with the PVT sample analysis available in the field.
The next logical step is the optimization of workflow to produce consistent and more quantitative
viscosity results, which may require lab NMR measurement of Lower Fars oil samples and core calibration.
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Evaluating Basin-Centered Gas Potential in Southwest Ghawar, Saudi Arabia
More LessA regional study was conducted to evaluate the potential for a basin-centered gas (BCG) accumulation
system in the Silurian-Permian sequence at a basin located southwest of the Ghawar field.
Analyzing the critical interaction between the thermal maturity of the Silurian Qusaiba source rock, the
low permeability of the Silurian-Permeain reservoir rocks and their relationship with reservoir pressure
and fluid type distribution indicates a high potential for an effective basin-centered gas system. Local
breaching of the system’s effectivity is reflected by the presence of water on the flanks of the basincentered
gas accumulation and around faults located in the center of the basin.
This study uses a newly established evaluation process for generating basin-centered gas play
concepts. The evaluation process focuses on analyzing six critical elements denoted as “BCG System
Elements.” The BCG System Elements include the thermal maturity of the source rock, proximity to
source rock, reservoir quality, abnormality of reservoir pressures, regional fluid distribution, and the
effectivity of interactions among these five elements.
Finding and evaluating BCG is one of the major challenges for gas exploration in Saudi Arabia as it
would result in substantial addition to the current gas reserves. Promoting the BCG from a play concept
to an operational E&P project requires using new paradigms in exploration, drilling and production processes.
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Seismic Geomorphology of Palaeozic Reservoirs in the South Ghawar Area, Saudi Arabia
Authors Stanley R. Wharton and Thomas LorettoThe evaluation of Paleozoic depositional megasequences in the South Ghawar area is complex, as the
area has been influenced by periods of early Paleozoic glaciation, marine transgression, and tectonism.
Early Ordovician glacial advance and retreat generated distinct elongated paleovalleys within which
subsequent megasequence deposition occurred. The Hercynian orogeny influenced the
paleotopography, upon which Carboniferous and Permian sequences have distinct onlapping
relationships to the north and west of the Hercynian depocenter. A seismic/geomorphological analysis
was applied in the basin in order to elucidate depositional styles of Paleozoic sequences, onlap
relationships, unconformities, and tectonic styles associated with hydrocarbon migration.
Using pre-stack time migrated data, seismic attribute volumes were generated for multi-volume, multiattribute
analysis. The geomorphological extent of the depositional sequences was analyzed, in order
to reflect the infilling stages of sequences within and beyond a major paleovalley near the base of the
Qusaiba. Key mapped horizons in Paleozoic megasequences from Permian to near Base Qusaiba
enabled assessment of isochores, which indicate thinning trends towards the flanks of the depocenter.
Both the Wudayhi and Ghazal structures are major Hercynian eroded features that controlled
Carboniferous Unayzah deposition. Well data and palynological picks were used to constrain key
paleosurfaces, and seismic facies analysis calibrated to wells helped define gross depositional
environments that have variable progradational directions through time. The multi-volume, multiattribute
data analyses assisted with evaluation of the depositional sequences. The steeper flanks of
the basin, however, have varying sequence relationships and complexities related to pinchouts and
drapes onto Hercynian-related structure.
Structural analysis using automatic fault mapping routines on coherency data enabled quick
assessment of complex subregional structural styles that are dominated by strike-slip tectonics.
The seismic geomorphology approach enabled the definition of the morphology of the sequences and
depositional styles within the basin. Although unconformity traps on basin flanks were more difficult to
define, they present significant exploration opportunities. This approach enables the targeting of key
areas for exploration, with focus on unconventional traps.
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Study Case: Challenges of ADMA-OPCO’s Gas Well Situation in Fracture Zone, Offshore Operations, Abu Dhabi, United Arab Emirates
Authors Ahmed S. Al-Kaabi, Hamdan M. Al-Menhali and Khalfan H. Al-MansooriADMA-OPCO Well Value Assurance Team planned to drill a well which situated between two faults. The
primary objective of the well is to inject 120 MMSCFD of gas in order to achieve the injection target
into Upper Jurassic reservoir. This is one of ADMA-OPCO’s Key Performance Indicators (KPI’s). The well
was fully analyzed and evaluated from engineering and geoscientist aspect to maximize the value and
reduce the drilling risk and reservoir uncertainty. In May 2009, the well was drilled successfully until it
reached the lower Cretaceous zones. Severe mud losses occurred at this level. A multi-discipline review
of the problems encountered was undertaken by the team and a series of procedures and options were
developed to cure the problem. This multi-discipline team work involved the following analysis: (1)
petroleum engineering analysis which included well prognosis and drilling actions; (2) geoscientist
analysis, which included the geophysical and geological data and (3) reservoir engineering analysis to
evaluate the reservoir properties in the sections above and immediately below the bit. The Purpose of
this paper is to highlight the importance of integrating many teams to solve such as situations and to
emphasize the role of the geoscientist in the well drilling process and decisions. In addition to that
ADMA-OPCO would like to share the experience of tackling such a challenging situation.
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Fault Detection Using Azimuthal Coherence Attribute: Case Study, Central Saudi Arabia
Authors Faisal M. Al-Qahtani, Abdullatif A. Al-Shuhail and Saleh Al-DossaryDelineating faults is a challenging task, particularly if the faults run parallel to the strike azimuth.
Normally, dip azimuth faults can be identified easily by traditional time slice methods. The coherence
attribute is widely used for fault interpretation and determining orientation in addition to analysis of
stratigraphic features. Chopra introduced a new method (Chopra 2002) taking advantage of the
azimuthal variation of seismic signature and coherence. Chopra's (2002) approach calculates the
coherence between azimuthal data subset stack volumes. This study will produce four sub-volumes,
sorted according to different azimuths plus the original volume. After that, we will apply the coherence
attribute to all volumes and then compare coherency volumes having different azimuths with the
original volume. The result of azimuthal coherence technique shows better fault mapping, especially
those faults whose trends are perpendicular to the sorting azimuth. This study reports the occurrence
of a system of discontinuity, trending northwest to southeast, which appears in the coherence time
slice through the NE-SW azimuth-limited volume. In addition, the coherence time slice of the E-W
azimuth-limited volume reveals more discontinuities where we expect faults and fractures to exist.
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Sidetracks Drilling Supported by Hydrodynamical Models of Reservoir
Authors Alexander B. Starostin and Alexander BasakIn our report we present full cycle of reservoir modelling ending with targets for sidetrack drilling.
Many giant oil fields in Siberia started from 70s and still produce more than 1 mln sbl/day. These oil
fields are covered by the net of the wells and experience the fast watering of the wells. The operators
find sidetrack drilling is a profound way to decrease the drilling costs and to slow down the watering.
However, after 40 years of exploitation successful sidetracks in the reservoir require thorough analysis
of geology and production. As a service software company Roxar cooperates with operators closely in
order to find the best targets for sidetracks. We build a hydrodynamical models of reservoir sector with
100-200 wells of 20-40 years of exploitation. It takes about 2-3 months to make history matching of
the model. With matched model we get up-to-date and detailed picture of reservoir. Analysis of
pressure, mobile reserves and other parameters from the model brings to the precise targets of
sidetrack. In practice the model covering 20-50km2 gives immediate solution for 4-10 sidetracks.
Firstly we present the typical situations on the oil-field in Siberia and the contribution of modelling to
the production process. Next we present the results of sidetracks released after 3D modelling. We
demonstrate the whole cycle of modelling on examples from our project with TNK-BP, Samotlor oil
field. We compare the real production of sidetracks and our forecasts whose had initiated their drilling.
Other problems of reservoir engineering like boundaries of sector models, reservoir pressure matching,
implementing hydrofractures into the model and so on are also discussed.
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Quality Fracture Network Assessment for IOR Feasibility Case Study in Fractured Carbonate Rock-UAE
Authors Manhal Sirat and David KuehnThe implementation of the Improved Oil Recovery (IOR) methods to increment the recovery factor in
naturally fractured reservoirs is often expensive and time-consuming; therefore, a detailed quality
reservoir assessment of key attributes of the fracture network in an analogue outcrop carbonate rocks
will help unravel its impact on the IOR pilot.
Detailed fracture analysis was conducted on collected data from the Eocene-Miocene outcrop exposure
of the fractured carbonate rocks in Jabal Hafit anticline/Abu Dhabi. This paper aims to assess the effect
of critical fracture parameters such as geometry, interconnectivity, density, aperture, size, mechanical
layering and ambient stress condition on fractures openness and reactivation mechanisms. It also
introduces a method to estimate the seal potential ratio based on aperture measurements of
representative fractures chosen over areas of different structural settings in Hafit structure.
Results indicate that there are two fracture systems; an older E-W trending and a younger N-S striking
system, which have been formed in at least two different tectonic settings from Cretaceous to present.
Each of these systems is divided into three vertical to sub-vertical fracture sets; an extensional (joints)
and two conjugate shear sets (faults). Some of these extensional fractures and faults are partially or
entirely sealed by calcite or clay gouge filling. Fracture density shows a log-normal relationship with
bed thickness, which increases in dolomitized limestone facies, in the crestal area and in the vicinity of
pre-existing faults and shear zones. Fracture size is inevitably constrained by the outcrops exposure.
Fractures aperture varied between 0.5 to more than 30 cm, depending on fracture geometries,
positions in the anticline and lithology, and calcite fillings.
We consider that only fractures of the second system is preferred for fluid flow along corridors that are
held opened by the current N-S to NE-SW ambient stresses unless locally sealed by clay or calcite
mineralization. However, at the vicinity of a fault, the estimation of fractures openness depends on the
fault geometry and the associated in-situ stress tensors around the fault. Fractures connectivity is
controlled by individual fracture set geometry together with the current in-situ stress. Riedle and
diffused fractures connect those opened fractures and faults of this system together with the bedding
planes giving rise to a dual permeability reservoir.
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Geological Modeling of Complex Fluvial Lacustrine System, Case Study from Oil Field Central Muglad Basin - Sudan
Authors Musab M. Elamhi and Ahmed M. MohamedSudan is the largest country in Africa with an area of 2.5 million Km2 and common borders to eight
countries. Muglad Basin is a northwest-southeast trending rift Basin in Central Sudan. Blocks 1, 2 and
4 lie in the Central part of this Basin. Greater Nile Petroleum Operating Company operates these Blocks.
Muglad Basin is characterized by more than 15000 m of non marine clastic sediments; these clastic
sediments in the study area are likely to be sourced by northern and eastern paleo-highlands.
The combination of both continental (reservoir) and lacustrine (seal / source) rocks in conjunction with
the tectonics has created favorable juxtaposition of source, reservoir and seal.
The area of study has been relatively presented itself as a technical challenge to the operating
company. A team from Greater Nile Petroleum Operating Company (GNPOC) and Sudapet has
conducted geological modeling for the three main Upper and Lower Cretaceous reservoirs, namely the
Aradieba, Bentiu and Abu Gabra Formations.
The study comprised a 3D stratigraphic, facies and structural model building for the key horizons using
Petrel Software to capture reservoir variability.
Seismic attribute gave a clear expression of faulting and shows that all the productive wells were
located on a low frequency and low to high amplitude. The core data used in this study were
correlatable with the Petrophysical interpretation models. This oilfield has a multi-oil-water contact.
The petrophysical properties were modeled constrained by facies. The static model identified sand
bodies’ architecture that gave an increase in both oil originally in place (OOIP) and estimated ultimate
recovery (EUR).
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The Late Aptian-Early Albian Carbonate Crisis - Evidence for Glacio-Eustacy and Environmental Change from the Arabian Plate (Offshore Qatar)
The Mid-Cretaceous carbonate succession of the Arabian Plate is interrupted by a phase of exposure
and condensed siliciclastic sedimentation spanning the Late Aptian and Early Albian. This dramatic
change in sedimentation pattern is attributed to a glacio-eustatic sea level fall, dramatically
documented with incised valleys in offshore Qatar, and was followed by a phase of condensed, iron-rich
siliciclastic sedimentation at the end of the subsequent sea level rise. This anomalous facies pattern
produced a unique, thin, but high-pay siliciclastic reservoir.
Based on a dataset of 25 cored wells, a high resolution seismic dataset, and extensive palynological
analyses, a high resolution sequence stratigraphic model has been built. The lower sequence boundary
is the incised valley floor that penetrates approximately 25 meters into the underlaying Shu’aiba
Formation with a maximum valley width of 8 kilometers. A cored well in the middle of this channel
shows that the fill sediment consists of plant material-rich, bi-directional cross-bedded, mediumgrained
sandstones changing upward to bioturbated sandstones. This succession is interpreted based
on sedimentary facies and palynofacies as an estuarine environment, displaying a deepening upward
trend of a transgressive back fill succession. The overlaying highstand deposits are thin (approximately
6 to 7 meters) and consist mainly of oolitic ironstone, locally admixed with glauconite and sandstones.
This succession has been dated as Late Aptian and ?Early Albian age. The top sequence boundary is
placed at the base of a thin, but regionally extensive sandstone bed, rich in glauconite, that has been
dated as Middle Albian, and forms the beginning of the next sequence.
The offshore Qatar dataset provides detailed insight in this little known, but geologically and
economically significant part of the Arabian Plate stratigraphy. It provides a conceptual depositional
model, and unequivocal evidence for late Aptian sea level fluctuations and sedimentation that will have
affected other petroleum systems on this Plate.
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Fracture Characterization and Modeling of Unconventional Najmah-Sargelu Reservoirs of Umm Gudair Field, West Kuwait
Najmah-Sargelu (NJ-SR) unconventional naturally fractured carbonate reservoirs are spread across
many fields in West Kuwait, some of which, such as Umm Gudair are on production for last 25 years.
Natural fractures have a significant impact on the reservoir performance as it affects well productivity.
Therefore, understanding their significance through fracture characterization is helpful in well
placement and field development. This paper presents an overview of efforts in building a 3D
stochastic fracture model for reservoir characterization of Umm Gudair field. This model is generated in
FracaFlow© through the analysis and integration of well data like cores (including oriented core), bore
hole images (BHI), well-logs, mud losses, production logging and well test data along with 3D QSeismic
data through structural, seismic attribute and seismic facies analyses.
The impact of lithology on fracture occurrence was quantified based on rock-typing and distributed
using a high resolution sequence stratigraphy framework. Rock types are a real 3D fracture driver &
provide a reliable means of adjusting the density of diffuse fracture in the Najmah-Sargelu Reservoirs
of Umm Gudair Field. Three sets of diffuse fractures were identified from bore hole image data: N20°E,
EW and N170°E. Large-scale fracture corridors including sub-seismic faults, identified from seismic
analysis were calibrated with core and BHI fractures through fracture data analysis workflows. The
model finally incorporates two scales of tectonic fractures: diffuse fractures and large-scale fractures
that have a direct bearing on well and field production behavior.
The fracture calibration was performed using the dynamic data set such as production log and well
wise production data. Synthetic well tests were simulated and matched with the real build-up data at
wells. These data were then used to propagate 3D fracture properties (fracture porosity, fracture
permeability and equivalent block size) for constructing reservoir simulation model.
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Outcrop Characterization of the Khuff Formation from Production to Exploration Scale (Oman Mountains, Sultanate of Oman)
Authors Bastian Koehrer, Thomas Aigner, Michael Poppelreiter, Paolo Bizarro and Sulaiman KindyWe present complete sedimentological-stratigraphic outcrop descriptions of Khuff time-equivalent
strata (Saiq and Mahil Formations) from the Oman Mountains. These were used to 1) establish
conceptual depositional models of the Khuff Formation highlighting nature and dimensions of reservoir
geobodies and to 2) contribute to a regionally Khuff stratigraphic framework by integrating bio-, chemo
-, litho and sequence stratigraphy.
Primary textural heterogeneities within these outcrops were mapped-out from production (2x2km) - to
exploration-scale (50x50km). Digital field geology was combined with traditional sedimentological
investigations to place all observations in a 3D-framework for modeling purposes. Based on 1D- and
2D-outcrop data, hierarchical 3D-static reservoir models were generated.
On a 2x2km outcrop-scale, walked-out reservoir bodies show general layer-cake geometries of
grainstone bodies. Reservoir bodies tend to have a standard deviation of 13% in thickness. This
variability may influence volume calculations in producing Khuff reservoirs.
The 8x8km production-scale model revealed the importance of cyclicity on reservoir geometries.
Considerable differences regarding percentage, thickness and lateral extend of individual grainstone
geobodies within different stratigraphic intervals of the Khuff were observed in the outcrop. Reservoir
facies developed preferentially in the regressive parts of cycles of multiple hierarchies.
Finally, an exploration-scale model of the Khuff Formation showed systematic lateral facies changes in
a 50x50km area. Reservoir body distribution and stratigraphic architecture appear influenced by the
Pre-Khuff topography, local paleohighs and paleogeographic position.
The results of the study are applicable to Khuff reservoir characterization and correlation from
production- to exploration-scale.
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Paradigm Change: Seal Turns into Reservoir - from Outcrop and Modeling Study of a Sudair Formation Equivalent in the Oman Mountains (Jebel Al Akhdar Area)
The deposition of evaporites and shales over most of the Arabian platform during the Lower Triassic
provides seals for hydrocarbon accumulations in the underlying Khuff Formation. Our work on wellexposed
outcrops of the Mahil Formation in the Oman Mountains (a time-equivalent unit to the Sudair
Formation in the subsurface) reveals abundant potential reservoir units. A major aim of the ongoing
study is to find relationships between shoal thickness and lateral extent as well as to unravel the
overall geometries of shoal reservoir bodies in low-accommodation settings.
Sedimentological analyses of several sections in the region of Jebel Al Akhdar yielded 3 facies
associations with a total of 12 facies types of a mostly backshoal to shoal setting. Except for few
meters thick exposure-related layers at the top of one of the investigated sections, no occurrences of
any sabkha-associates were detected. An integration of facies types in stacking patterns revealed three
basic cycle motifs.
Potential seal units only occur in the detrital-rich backshoal cycle type in the lowest Middle Mahil
Formation and consist of laminated claystones and bioturbated mud-/wackestones. The remaining
major part of the about 260 m thick formation is mainly built by dolomitic backshoal to shoal cycles
with a high reservoir potential. Shoal deposits consist either of oolitic- or peloidal-rich grainstones that
strongly determine reservoir quality.
Sequence stratigraphic correlations based on litho-, chemo-, and biostratigraphy show subtle pinchouts
and facies changes on the scale of tens of kilometers. Thicker grainstone bodies are laterally more
extensive and are correlatable within 5th order cycles on a field scale.
A field-scale static reservoir model was created using the outcrop sections as pseudo-well logs.
Correlating the sections on a north-south transect indicated a deepening trend to the North by a shift
from a mainly backshoal-associated setting around the center of the Jebel Al Akhdar anticline to more
shoal-associated facies types at the northern flank of the anticline. This proximal-distal trend and the
overall cyclicity could be well reproduced with stratigraphic forward modeling using the software
Dionisos, suggesting that relative sealevel changes form major controls on the depositional
architecture.
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Regional Geological Modeling of Marrat Formation in West Kuwait with Special Reference to Jurassic Petroleum System
Authors Rasha AL-Muraikhi and Naveen VermaThe Marrat formation is considered to be one of the most important carbonate oil reservoirs in West
Kuwait oil fields area. This work focuses on the regional geology of Marrat based on deep wells in
conjunction with 3D seismic data. The paper documents construction of a regional 3D geo- model to
understand the geology of Marrat and their bearing on its Petroleum System.
Wells and 3D seismic data has been used to identify main structural elements of West Kuwait and their
tectonic evolution, particularly since Jurassic period in view of their influence on Marrat basin
architecture and depositional fabric. Tectono-stratigraphic analysis of Gotnia Formation has also been
carried out to understand the Jurassic Basin evolution through time. The area has four main anticlinal
structures namely Abduliya, Dharif, Minagish and Umm Gudair with known multiple Jurassic oil
entrapments. These structures were found to be effected by three main compressional forces during
the Pre-Jurassic, Jurassic and Cretaceous times.
The Marrat formation was divided into 3 main parasequences , upper, middle and lower. The upper
Middle Marrat was further subdivided into 13 sub-layers. The lithology is derived from electro-logs
calibrated with cores. Detailed Rock typing was accomplished using neural network technique that
resulted in identification of eight carbonate/ evaporate rock types grouped into five litho-facies.
The geological layering based on sequence stratigraphy combined with 3D seismic data provided the
framework for structural model while, the litho-facies were propagated in property model honoring well
control. This high resolution 3D modeling and visualization proved valuable in interpretation the
primary depositional and secondary digenetic processes that left their imprints on Marrat rocks. The
porous and permeable aggradational and progadational carbonate parasequences of Middle Marrat
constitute the main oil accumulations where reservoir quality is strongly controlled by structure,
primary depositional fabrics, as well as extensive dolomitisation.
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Fluid Property and Geochemical Evaluation of from Exploration Well in the South Rub' Al Khali Basin: Implications for the Regional Subsurface Model
The sampling and analysis of sour gas and its associated condensate is a difficult task: H2S is highly
reactive and the route from reservoir to laboratory is covered with potential ‘sulphur sinks’. The downhole
sampling program is further complicated by the fact that gases with high H2S concentrations tend
to have low condensate gas ratio’s (CGR’s) and the slightest drilling mud contamination can potentially
effect the fluid composition and lead to erroneous concentrations of H2S. Yet, accurate fluid property
data like H2S content and condensate gas ratio (CGR) are critical for reserve estimates and economic
evaluation, for field development planning and for facility design.
The South Rub Al-Khali Company Limited (SRAK) recently completed a deep exploration well which
targeted objectives at several stratigraphic levels. The well found sour gas in the Jurassic Arab
Formation and an extensive down-hole sampling program was initiated to acquire representative fluid
samples from all potential Arab pay-zones. In addition, a comprehensive geochemical analysis program
was carried out with the objective to update the regional hydrocarbon habitat and basin models.
This paper discusses the integration of all fluid property, geochemical and basin modeling data, which
together provide a rigorous quality check of the sampling and analysis program. H2S concentration and
CGR, for instance, are not independent parameters, as both are governed by Thermochemical Sulphate
Reduction (TSR), the in-reservoir process that leads to the formation of H2S and CO2. Also the
molecular and isotopic composition of the gases are dependent on the TSR process and provide an
important consistency check. Subsurface temperatures and source rock quality and maturity data were
used to calibrate the regional basin model and to update the understanding of the hydrocarbon habitat
of the Southern Gulf region. Finally, the newly acquired subsurface temperatures provided further
insight into the hydro-dynamic flow regime of the South Rub al Khali Basin, which were described
earlier after the first SRAK exploration well.
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FMI Formation Microimager - High Resolution Solution Tool to Reveal Structural Complexity, Western Desert, Egypt
Authors Elie G. Haddad and Ahmed M. AbuelfotohThe Formation Micro Imager tool provides high resolution electrical images, which is capable of
detecting any features within the studied formation. In majority of cases, FMI can replace an expensive
coring cost depending on the finer scale details identified beside image contrast and extended borehole coverage.
A very well known oil company in Egypt is drilling in Western Desert province with high profile drilling
program, almost 10 wells per month, and as all the structural complexity is being solved by their high
resolution seismic sections, hardly any problem or well misplacing they faced before. This is before
they drill one of their development wells, in which they encountered a very unusual section; where all
the supplementary data and the conventional open hole logs beside ditch cutting and microscopic
examination didn’t reveal any fair solution to them.
FMI images were kept as their last chance trying to understand how this dilemma could be solved. FMI
overall image quality was very good, which contributed efficiently to the structural interpretation
results. The processed FMI* image showed strong and distinctive evidence for the severe cataclastic
deformation, rocks breakage, fractures and brecciation owing to the crushing and pulverization
processes along the sub- seismic faults planes cutting through the studied formation.
The studied well is vertical over the entire logged interval, hence penetrated the investigated zone
parallel to two (sub-vertical) main cross-cutting faults; therefore the well was penetrating through the
breccia zone along the fault plane for a considerable distance. This resulted in a great thickness, about
30 m, which was imaged over that fault breccia zone.
FMI was the only tool capable of solving this structural complexity and mixed lithology that were never
been solved unless cored, and hence increasing the well capital expenditures as compared to a single FMI run.
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Using Spectroscopy Logs to Enhance Formation Evaluation and to Guide High-Resolution Facies Determination in the Nile Delta, Egypt
Authors Marie Van Steene, Adel Farghaly and Ahmed Abu El FotohA wide variation in rock quality exists in the sands and shaly sands of the Nile Delta. The mineralogy is
complex, including the presence of feldspars, calcite, heavy minerals, and several different clay types.
To improve evaluation of these gas-bearing reservoirs, neutron capture spectroscopy data is routinely
acquired. The spectroscopy tool measures elemental concentrations, which are then converted into
mineral concentrations.
Comparison of core mineralogical data with log spectroscopy data showed that the clay content from
the standard clay matched the core data in the clean sand zones. However, in the more shaly parts of
the reservoir, clay content from the spectroscopy model was overestimated.
Because of the relatively complex mineralogy, a linear calibration of minerals log data to core data was
found not to be appropriate. It was, however, found that the clay volume could be more accurately
computed from a multimineral solver using the elemental spectroscopy logs (rather than the mineral
volumes output from the spectroscopy model). The computation process is described. It was also found
that the aluminum log from direct aluminum yield measurement leads to the best clay estimation, as
opposed to using the aluminum log from the aluminum emulator algorithm.
Results of the clay volume computation were used to calibrate the NMR clay cutoffs.
The mineralogical evaluation was further combined with calibrated microresistivity image data to
generate a high-resolution lithofacies column, generating an accurate stratigraphic interpretation.
Moreover, cutoffs were applied to generate a high-resolution sand count, sorting the reservoir units
from the poorest to the best quality sands.
Examples illustrate how the use of the spectroscopy data enhanced standard formation evaluation in
these shaly sand reservoirs. The examples also demonstrate that combining mineralogical information
with high-resolution images can improve the understanding of the distribution of the best reservoir
quality in the well.
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Multi-Scale Imaging Process for Computations of Porosity and Permeability from Carbonate Rocks
Authors Abraham S. Grader, Amos Nur, Chuck Baldwin and Elizabeth DiazReservoir rock material collected during drilling is one of the main sources used to derive reservoir fluid
transport and rock mechanics properties. Carbonate reservoir may have heterogeneities that create
multi porosity/permeability systems that are very difficult to describe, and to determine their flow
properties. Conventional methods use laboratory procedures to perform experiments that yield directly
or indirectly required rock properties. Some of these procedures, such as the determination of relative
permeabilities, may take several months to perform.
Also, in some cases, it is very difficult, or impractical to perform the experiments in the first place. Yet,
as reservoir characterization is becoming ever more important for oil and gas production, a much
larger portion of reservoir rocks, from cuttings to full cores, will need to be analyzed than what are
currently evaluated. This paper offers an example of the use of digital rock physics to determine
porosity, permeability, and relative permeabilities for a carbonate sample using multi-scale imaging.
Digital rock physics using the Lattice Boltzmann (LBM) for fluid dynamic calculations is at a point where
for a proper digital pore space the resulting flow properties calculated are reasonably correct. The main
issue facing digital rock physics is the need to up scale the computed properties to the scale of the core.
The process presented in this paper includes sample preparation, imaging, image processing, property
computations, and property integration to the core scale. The sample is subjected to a descending
scale of x-ray CT imaging, along with physical sub-sampling of the core. The descending size of
scanning leads to increased resolution of the three-dimensional digital core, keeping the sample
volumes registered in place. The resulting digital rocks are segmented and the pore structure is
determined on the x-ray CT grid system. The resulting three-dimensional pore structure, that is the
same as the actual pore structure subjected to resolution limits, is used as the input grid system for
direct fluid dynamic computations that are second order accurate representation of the Navier-Stokes
fluid flow equations. These computations yield porosity, absolute permeability, relative permeabilities,
and capillary pressure. In this paper we focus only on porosity and permeabilities. Multiple scale
imaging permits the estimation of permeability at the core scale.
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Bayesian DHI Using Passive Seismic Low Frequency Data
Authors Nima Riahi, Mike Kelly, Martine Ruiz and Weiwei YangWe present a procedure for producing a Bayesian DHI using low frequency passive seismic (LFPS)
data. The approach utilizes two LFPS attributes to classify and determine the likelihood of hydrocarbon
presence in the subsurface. These attributes are based on statistical characteristics of the empirically
observed hydrocarbon (HC) tremor. It is shown that these characteristics provide a more accurate and
complete description of the tremor energy as compared to an integrated single value measure. An
interpreter-driven Bayesian classification is employed both to accommodate uncertainties in the data
and to provide a risk estimate. The class models are built from a subset of exemplar receivers which
are selected by an interpreter based on tremor quality and low noise interference. Prior knowledge
from wells or structural information from active seismic can also be incorporated into the analysis.
The process is tested over four fields with known surface projection of the oil-water contact (OWC).
Prediction results correlate well with reservoir locations. A classification success rate based on the
proposed process is calculated. Due to the relatively small number of measurement locations (~50-
100), the significances of the results are checked through standard statistical tests including Monte
Carlo simulations.
The approach provides a rigorous method for producing quantitative HC probability maps that are easy
to interpret and can be used for risk analysis. Possible applications for the method include: (1) more
informed drilling decisions over fields with none or poor active seismic data, (2) expanding production
into areas near existing wells (exploitation), (3) interpretation aid for ambiguous features in
conventional seismic attributes.
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Azimuthal Residual Velocity Analysis in Offset Vector for WAZ Imaging
Authors Didier Lecerf, Jean-Luc Boelle, Amhed Belmokhtar and Abdeljebbar LadmekWide azimuth acquisition provides full azimuthal illumination of the subsurface structures for a more
accurate image. Additionally, analysing azimuthal variations of the seismic response may offer
information on fracture orientation. To meet both objectives, it is essential that the wide azimuth
character of the data is preserved throughout the processing sequences in order to get full benefit of
true 3D algorithms. In this perspective, the use of the offset vector binning concept on dense wide
azimuth datasets is advantageous as it preserves offset and azimuth information even after migration.
The offset vector binning uses the same cartesian system as the acquisition geometry and hence
ensures an optimum distribution of seismic traces in each Common Offset Vector (COV) volume.
Conventional sectoring approach using polar coordinate system provides cubes with holes and over
folds, which requires an offset and azimuth interpolation process with careful fold compensation.
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Charge Evaluation of South East Abu Dhabi(Part II, Basin Modeling)
The objectives of the basin modeling part of the South East Abu Dhabi (SEAD) charge evaluation study were twofold:
(1) to reconstruct the charge history and explain the known hydrocarbon accumulations including
distribution of various oil families
(2) to provide a framework for the charge risking in ADCO’s exploration portfolio.
The basin model was constructed in ADCO’s offices in Abu Dhabi, using the modeling software
PetroMod®. Key input for the model were 29 regional depth maps and 10 associated erosion maps
constructed based on the latest 2 and 3D seismic. Isopach maps of the Middle Cretaceous and Base
Tertiary tectonic events were created to allow accurate modelling of the basin tilt, which drives the
hydrocarbon migration. The model was calibrated with temperature data from available 46 wells and
pressure data from 15 wells. The Bab and Hanifa/Jubaila Formations were identified as the main source
intervals, with additional contributions from 2nd order source rocks in the Thamama dense zones. Oil
and gas migration from these source rocks and the filling of accumulations in the Hanifa, Habshan,
Asab, Thamama and Bab reservoirs were all modelled in an integrated way.
The model clearly demonstrates that the formation of the Oman foredeep and the tilting of the basin
are the main drivers behind the oil generation and migration to SEAD. The migration of the oil
generated by the Hanifa/Jubaila source interval in the North is largely lateral until the oil reached the
main east-west trending fault zone in SEAD, where vertical leakage along the fault planes took place
with most of the oil accumulating in the shallow Thamama reservoirs. The model accurately explains
the distribution of various oil families, all discovered accumulations and their phase, as well as the
temperature and maturity profile of the basin. New model allowed ADCO to update its existing charge
risking matrix and strategy towards de-risking prospects in SEAD.
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Managing Talent to Improve Your Team’s Performance
Authors Tony F. Marsh and Peter S. FordHow do you know you have the correct mix of Talent for your Team? And, even if you do, is it being
effectively managed? We present a 5-step methodology that ensures your Team performs successfully
and effectively.
First we need to establish the strategic direction of the team. (I can’t know if I have the right people on
the bus if I don’t know where the bus is going.) The functions and responsibilities are defined to
achieve the stated strategy.
Next we establish the correct mix of skill sets needed to successfully, and effectively, carry out the
strategic efforts of the team. These would include both technical and intangible skills.
The third step is to organise the required skills into desired roles or positions resulting in a set of Job
Profiles. At this point the optimal team structure has been developed.
Next, you have to gather information from the people who are available to you, to best match their
skills and responsibilities with the optimal roles you have defined. A Gap Analysis will identify skill gaps
that, unless addressed, will prevent the team from being a high performing team.
The final step is to develop the team members to eliminate any skill gaps and thus ensure the team’s
strategic objectives set in the first step are being met. Our methodology allows an individual's skill and
performance levels to be objectively measured and compared over a period of time and thus the
individual's development can be effectively managed.
We have found that interactive web technology makes our methodology easy to apply and provides the
team and the individual with the instant results that they need. We present a real world application of
the methodology in an oil exploration team with staff from diverse backgrounds.
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Precambrian Fractured Basement Reservoirs as a New Unconventional Oil Resources in Melut Rift Basin, Southeastern Sudan
More LessSeveral large rift basins have been identified in central Sudan, amongst which is the Early Cretaceous
Melut basin. The rift zones are generally northwest- to southeast-striking and exhibit half-graben
symmetries. The basins are filled by continental clastic sediments, at some places more than 10 km
thick. These extensive rift-related basins are the target for oil and gas exploration. The Sudanese rift
basins are underlain by Precambrian basement rocks, which outcropping particularly in the southwest,
centre and northeast of Sudan.
Oil potentiality of naturally fractured basement reservoirs in North Melut Basin is manifested by the
discovery of Ruman-N-2 well. An attempt has been made by the Exploration department of Petrodar
Operating Company (PDOC) to understand hydrocarbon production and trapping mechanism in
basement rocks.
Ruman North field represents a structure high in the basement created by fault tectonics. This
basement high was generally continuously uplifted for long periods of geologic time and was subject to
a long period of weathering and erosion .About 400 barrel oil per day have been tested from fractures
in Precambrian metamorphic basement rocks. The depth of the well is 922m, with hydrocarbons found
between 863m and 915m in the basement fractures. The well appears to have only two major
contributing open fracture zones which were not imaged in the seismic data. Open fractures
characterized by decrease in velocity & density, and energy loss in Stoneley response.
The drilling results revealed that basement rocks underlying the Melut basin comprises various types of
granitoids, schist, marble and mafic ultra-mafic materials that altered in different degree to serpentine,
talc and carbonate materials. Such rocks regarded as non-reservoirs for long time and failed to draw
the attention of the exploration activities.
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3D High Resolution Parabolic Radon Filtering
Authors Pierre Hugonnet, Jean-Luc Boelle, Majda Mihoub and Philippe Herrmann2D parabolic Radon filtering is a widely used method for multiple attenuation, based on velocity
discrimination between the primaries and multiples. The CMP gathers after NMO are modelled by a
superposition of constant amplitude parabolas:
t = tau + q.h^2, (h = offset)
The most curved parabolas, assumed to be the multiples (slower than the primaries), are retained and
subtracted from the data. High Resolution (sparseness) constraints introduced in the Radon domain
further improve the capability of the method to process spatially aliased data and to preserve the primaries.
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Plate History and Arabian Play Elements 1. Imprint of Pan-African Amalgamation from Lower Palaeozoic Successions
Authors Pieter Spaak, Geert Konert, Anton Koopman and Andrea GootjesExploring for hydrocarbons in mature basins as well as in frontier areas have specific challenges but
require a common approach. In mature areas, easy and obvious objectives have already been targeted
whereas in frontier basins, choices and decisions have to be made on very little data. In both scenarios
de-risking plays and polarizing a portfolio of opportunities should be based on a good knowledge of the
entire geological evolution and its impact on the various play elements. At the base of this knowledge
lies the understanding the plate tectonic development that requires reviewing a region in a wider context.
Specifically for this conference, two important plate tectonic events and their implications for Arabian
geology and play concepts will be reviwed:
1. The basement and the early, ‘Pan-African’ amalgamation history
2. The Pangea break-up and Mesozoic to Cenozoic plate history
This first contribution summarises the formation history of the Gondwana Supercontinent and the
impact of Pan-African lineaments on Phanerozoic sedimentation patterns. Subsequently, the
differences in Proterozoic and Lower Palaeozoic successions across the Arabian Plate are placed in a
plate tectonic context.
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Challenges in Conditioning Seismic Data for AVO Offshore Saudi Arabia
Authors Mahmoud E. Hedefa, Kevin Erickson and Rafed KasimUnless sufficient S/N ratios can be achieved for both target and reference events, an AVO analysis is
likely to prove fruitless, multiples and mode-conversion interference is most insidious when
unrecognized and multiples with the same velocity as the primary and mode conversions (P-SV)
interfere with our primary signals, drastically distort the amplitude behavior versus offset. As shown in
the figure below the large distortions in the signal are caused by crossing multiples and conversions at
specific offset ranges with the gathers. A major challenge in the seismic data processing industry is the
attenuation of such multiples and noise that contaminate the signal which lead to inaccurate AVO
analysis. The proper separation and removal of both multiple and other coherent noise energy from the
seismic data can be a very challenging task in the AVO data conditioning. Adding to the challenges in
picking the target on the pre stack migrated gathers, is the variable stratigraphic nature of the target
and the associated sand stringers.
Here, we present a comprehensive workflow that can identify and remove unwanted multiples and
various noise energies using fully in house built programs and leading intelligent filter technology (LIFT).
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A Tale of Two Glaciations
Authors Pieter Spaak and Malcolm RossTwo major glacial events left their imprint on the Palaeozoic successions of Arabia. Glacial and postglacial
sediments of the Al Khlata and Unayzah ‘formations’ are the reservoirs of numerous Permo-
Carboniferous fields in southern and central Arabia. Latest Ordovician glacial deposits and erosional
remnants form the target of wells and prospects in south and north Arabia. Moreover, the Base Silurian
post-glacial flood is the most significant (Qusaiba) source rock of the region.
The extent of the Late Ordovician and Permo-Carboniferous ‘ice-sheet’ is tremendous, covering in both
cases very large parts of Gondwana. In that context, it is remarkable that during the Devonian, icecover
over Gondwana is limited, notwithstanding a ‘very polar’ position of the super-continent in that period.
In this contribution, we will document the observations outlined above and will discuss the combination
of plate configuration, polar position and the Hadley Circulation as a possible explanation for a relative
ice-free Devonian compared to the preceding and subsequent periods.
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Plate History and Arabian Play Elements 2. Imprint of Pangea Breakup from Palaeo- & Mesozoic Successions
Authors Geert Konert, Anton Koopman, Pieter Spaak, Cees Van Oosterhout and Malcolm RossExploring for hydrocarbons in mature basins as well as in frontier areas have specific challenges but
require a common approach. In mature areas, easy and obvious objectives have already been targeted
whereas in frontier basins, choices and decisions have to be made on very little data. In both scenarios
de-risking plays and polarizing a portfolio of opportunities should be based on a good knowledge of the
entire geological evolution and its impact on the various play elements. At the base of this knowledge
lies the understanding the plate tectonic development that requires reviewing a region in a wider context.
Specifically for this conference, two important plate tectonic events and their implications for Arabian
geology and play concepts will be reviwed:
1. The basement and the early, ‘Pan-African’ amalgamation history
2. The Pangea break-up and Mesozoic to Cenozoic plate history
This second contribution summarises the break up history of Pangea in the Mediterranean and Middle
East regions and the subsequent collision of the resultant parts with Eurasia during the Tertiary. The
impact of plate processes and changes in plate kinematics on high level play parameters of some key
mature and frontier plays will be illustrated with examples from Morocco to Oman.
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Advanced Technique for Reservoir Thermal Properties Determination and Pore Space Characterization
Data on the thermal conductivity, thermal diffusivity, volumetric heat capacity, and the coefficient of
the linear thermal expansion of rocks are important for the optimization of thermal enhanced oil
recovery (EOR). Other crucial optimization factors include the theoretical modeling of heat and mass
transfer in reservoirs, the interpretation of temperature logging data, and the prediction of the physical
properties of other formations from the correlations found between thermal and other physical properties.
A new experimental and theoretical concept has been developed for the simultaneous determination of
the above-mentioned thermal properties of cores and core cuttings at normal and formation
thermodynamical conditions. The concept also covers the prediction of pore-space geometry from
thermal experiment data.
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Geological Heterogeneity in the Wafra First Eocene Reservoir, Partitioned Neutral Zone (PNZ) - Implications for Steamflood Development
Authors William S. Meddaugh, Niall Toomey, Willaim Dawson, William T. Osterloh and David BargeThe Paleocene/Eocene age First Eocene dolomite reservoir at Wafra Field in the PNZ (Saudi Arabia and
Kuwait) is estimated to hold more than 10 billion barrels of 18-22 API, high sulfur oil. Current
estimates suggest that only 5-10% of the OOIP may be produced during primary development.
Consequently, steam flooding is being investigated as an appropriate secondary development option. A
pilot consisting of single, very small 5-spot pattern with center injector has been used to demonstrate
long term steam injectivity as well as to evaluate aspects of the reservoir response to steam injection.
Critical to the economic success of the project will be a thorough understanding of the impact of both
areal and vertical reservoir heterogeneity on steam migration. Analysis of temperature and
petrophysical logs obtained in a temperature observation well located 35 feet from the injector have
showed that a vertical barrier to steam migration exists approximately 80 feet above the base of the
completions in the injector. Two, relatively thick (5-10 feet), very low porosity and very low
permeability evaporite-rich zones (mainly coalesced nodular to possibly bedded anhydrite with some
gypsum) that were regarded as the most likely barriers prior to the start of steam injection did not act
as barriers. Rather, an interval characterized by numerous thin, variously cemented (including celestite
and native sulfur cements), exposure surfaces or hardgrounds seems to provide the vertical barrier.
This zone is also characterized by generally low porosity and low permeability as well as very light oil
stain. Detailed studies, including micro-permeameter measurements, thin section analysis, and
quantitative mineralogical studies, are being used to further characterize the steam barrier interval.
The geological and stratigraphic assessments of heterogeneity are supplemented by a history-matched
thermal simulation model that suggests that the evaporite-rich zones may have acted as short term
baffles but that the “ultimate” barrier is coincident with the interval characterized by abundant
exposure surfaces or hardgrounds.
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Paleobiogeography of the Permian Neo-Tethys Shores
Authors Lucia Angiolini, Giovanni Muttoni, Gaia Crippa and Vincenzo VernaThe Permian was a period of marked climate change and plate tectonic reconfiguration. Climate
changed from glacial conditions at the dawn of the period to warm conditions in the Middle Permian.
The Cimmerian terranes migrated from southern Gondwanan paleolatitudes in the Early Permian to
subequatorial paleolatitudes by the Middle-Late Permian as the result of the opening of the Neo-Tethys
Ocean. This opening was asymmetrical, with higher seafloor spreading rates for the central Cimmerian
terranes (central Afghanistan, Pakistan Karakoram) than for the western terranes (Iran), and it took
place contemporaneously with the transformation of Pangea from an Irvingian B to a Wegenerian Atype
configuration. During this Early to Middle Permian tectono-climatic transition, bioprovincial
patterns evolved rapidly across the southern and northern margins of the opening Neo-Tethys Ocean,
as testified by the rich fossil record.
Here we place climate-sensitive biotic associations on paleomagnetically based paleogeographic
reconstructions of the Gondwanan margin and the Cimmerian blocks for the Early and Middle Permian
and use them to reconstruct the evolution of oceanic circulation patterns, latitudinal thermal gradients,
and biogeography in this time interval. We show that, in the Early Permian, the tropical Gondwanan
margin and the western Cimmerian terranes benefited from a warm subtropical surface current gyre,
which was confined to low latitudes. At the same time at higher southern latitudes, the central
Cimmerian terranes were affected by cold surface currents promoted by the Gondwanan ice caps that
distributed cold biota toward the tropics. These results suggest that low latitude sea surface
temperature did not undergo significant cooling during the Gondwanan glaciation and that there was a
steep thermal gradient between the compressed tropical belt and the expanded cold high latitude belt.
This situation changed abruptly in the Middle Permian with the creation of current gyres in the newly
opened Neo-Tethys Ocean that arranged biotic associations in distinct bioprovinces. Wordian
brachiopods from the western Cimmerian terranes contain a significant proportion of Gondwanan taxa
some of which are restricted to the Gondwanan margin (Tunisia, Turkey, Oman). Coeval brachiopods
from central Cimmerian terranes are instead different and pertain to a separate, low-latitude
bioprovince supporting the paleomagnetically derived differential drift of Cimmerian terranes.
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Geophysical Benefits of from Improved Seismic Vibrator
Authors Michael Hall, John Wei and Tom PhillipsVibroseis, a key source in land seismic exploration, has recently experienced many initiatives to
increase productivity and seismic data quality. Most of these innovations deal with the signals used to
generate the Vibroseis sweep and techniques for simultaneous acquisition.
This paper deals with physical modifications to the Vibrator itself designed to enhance performance at
both low and high ends of the frequency spectrum and also attempt to provide a more accurate
measure of the ground force from the weighted sum.
Most of the recently introduced simultaneous Vibroseis techniques rely on the measured weighted sum
as a good indicator of the actual ground force or the source signature for the Vibrator. In reality it is
common for there to be substantial differences between the weighted sum and the ground force,
especially as a function of varying near surface conditions. Modelling was undertaken to investigate
how the physical properties of a Hydraulic Vibrator could be modified to improve this relationship while
also extending the useful bandwidth. As a result of this modelling modifications were made to a
production hydraulic Vibrator, which was then tested against the production Vibrator both on load cells
and at a site in Texas with an instrumented well plus a 2D surface line.
Analysis of these tests will be presented to confirm that the expected improvements were achieved.
The implications of this are several fold. The bandwidth at the low frequency end of the spectrum can
be usefully extended below 5Hz with considerably less harmonic distortion; this will aid in the
exploration for deeper targets and also improve the accuracy of inverting seismic data to match well
log data. The bandwidth at the high end can be similarly improved by about 6dB at 150Hz enabling
improved resolution for quantitative analysis of shallower reservoirs. The overall reduced harmonic
distortion means that more of the energy generated by the Vibrator goes into the fundamental
Vibroseis signal yielding a higher energy level of useful signal. The weighted sum is also closer to the
ground force put into the earth by the Vibrator. This, along with the reduced harmonic distortion will
enable improved separation of overlapped source signals in simultaneous Vibroseis acquisition schemes.
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Digital Reservoir Properties from Cuttings: Case Studies from Tight Gas Sand and Carbonate Rocks
Authors Elizabeth Diaz, Guoping Li, Boaz Nur, Jack Dvorkin and Ted ZaleskiExperimental quantification of rock properties requires regular-shaped intact fragments of rock. These
fragments (plugs) are cut from cores extracted from wells. Coring is expensive in general and,
arguably, impossible where new drilling technologies (e.g., coiled tubing) are employed.
One application of Ingrain’s technology was in quantifying carbonate reservoir properties from drill
cuttings that were collected from a deep deviated well. Naturally, the configuration of the well
prevented the operator from extracting core material. As a result, digital rock physics lab was the only
option to understand this reservoir and design production strategy.
A large number of these cuttings were imaged, segmented, and digitally tested at Ingrain. The
resulting porosity, permeability, and elastic-wave velocity were consistent with the operator’s
expectation based on the well’s performance.
Using the latest-generation CT (computed tomography) scanners to capture in 3D the actual fabric of
reservoir rock samples -- the pore-space and mineral matrix geometry and fabric -- at resolutions as
high as 100 nanometers, physical measurements that require weeks or months in a physical lab can
now be completed in a matter of days, on a massive scale, and on any rock material, including sidewall
plugs and drill cuttings.
With the digital rock physics technology advancing rapidly, we also envision that, in the near future,
complicated natural pore-scale processes (fine particle migration, formation damage, diagenesis, and
chemical reactions) will be virtually simulated.
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Risk and Portfolio Management for Exploration and Development with SAP-PPM
Authors Axel Emmerich and Georg WeissmüllerHandling exploration and production portfolios in the upstream oil&gas industry involves assessing risk
or chance of success, overall timing, availability of resources or equipment and balancing large
investments with possible revenues. This analysis in a multidimensional space is most oftenly a task
carried out by entire departments or groups of individuals in oil&gas companies. Corporate standards
hereby usually form a framework to ensure assessment and ranking of projects with constant quality
and objectiveness. In most cases, the ranking of these exploration and development projects and
subsequent decisions drive a company's strategy over years. Hence a portfolio process and toolset that
both provide visibility and transparency across all influencing factors and input parameters are required.
A portfolio decision-making process was developed following years of best practice research within the
largest oil&gas companies. The underlying process is based on a common assessment of the chance of
geological, drilling/completion and economical success. The objectivity of the overall process is assured
by questionnaires enabled for true company-wide collaboration e.g. in peer-review teams as well as by
rigid decision milestones. In portfolio management, this process is being tracked, overall quality
assured, results analysed and lateron published to the upper management.
However, those - nevertheless important - non-financial and financial KPIs most oftenly blur the sight
on the proper risk of projects. And in many cases the correct ranking in which projects should be
executed is not determined. A proper risk and portfolio management process takes into consideration
the skill level and the availability of appropriate resources and or equipment. This fact is overlooked in
many exploration and development projects where timely project execution is essential. In addition to
that, many companies handle portfolio management in quite different ways and qualities on a global
scale. Risk is not assessed in the same manner and how it should have been in the different
subsidiaries of leading E&P companies.
In order to avoid such a biased ranking of E&P projects, a centralised corporate risk and portfolio
solution is required. This will ultimately result in greater success and increased reserves as well as
better project delivery on time.
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Devonian Spore Assemblages from the Jubah, Jauf and Tawil Formations, South of Ghawar Field, Eastern Saudi Arabia
Authors Abdulla M. Al-Ghazi, Mansour Al-Ruwaili and Merrell MillerAn exploration well located south of Ghawar Field contains one of the most complete early upper and
Lower Devonian successions in the area. The palynological control from this well provides a Devonian
reference section for this area that will help refine regional correlations. An apparently complete
succession of operational palynological zones (Al-Hajri et al., GeoArabia, 1999) from the Frasnian-
Givetian/upper Eifelian D2 Palynozone to the Lochkovian D4B Palynozone was identified in this well.
The upper part of the Jubah Formation, typically represented by the D0 to D1 Palynozones, was
truncated by the Hercynian erosion. D2 Palynozone was recognized from 15,000-15,350 ft and is
indicative of the presence of ?Frasnian-late Eifelian age sediments. This interval is dominated by
terrestrial palynofloras. D3A Palynozone spans the Jubah/Jauf formational boundary and occurs from
the 15,350-15,690 ft interval. D3B Palynosubzone, which caps the Jauf reservoir, occurs in the
15,690/15,710 ft sample (D3A and D3B are late Emsian in age). The D3B event is the only acritarch
(leiosphere) dominated palynological event recognized in the succession. The D3/D4-D4A palynozones
of Emsian-Pragian age are present in the 15,710-15,890 ft interval and span the Jauf/Tawil formational
boundary. Lochkovian D4B was recognized from 15,890-16,090 ft and suggests the presence of the
Tawil Formation. The section below the D3B Palynozone is dominated by terrestrial palynomorph
assemblages.
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Modeling Smectite to Illite Transformation and the Effect on Compaction and Overpressure Development
Authors Yunlai Yang and James E. IliffeSmectite illite (I/S) transformation is part of lithification process of fine grained sediments. We
constructed and calibrated a coupled kinetic I/S transformation and mechanical compaction model in
which Arrhenius equation describing the rate of transformation and I/S grains collapse accounting for
porosity reduction and overpressure development contributed by the I/S transformation. Overpressure
contribution is resulted from the transfer of effective stress born by the I/S grains to pore water due to
the collapse of I/S grains. The model is controlled by two major factors: the initial expandable fraction
in I/S and the temperature – time history.
All together 320 mudstone samples were analyzed by high quality XRD analysis for their mineral
contents and expandable content in the mixed-layer illite/smectite.
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Ara Formation Depositional Architecture and Controls from Reservoir Development - Sultanate of Oman
Authors Zuwena Al-Rawahi, John Grotzinger, Joao Rodrigues, Sri Vaddey and Huub JansenAn integrated subsurface approach to understand reservoir development of a unique Precambrian
hydrocarbon system in the South Oman Salt Basin (SOSB) is presented here. New well data and
recently re-processed PreSDM data were used to improve the basement fault and overburden tectonic
models. Existing depositional models have been refined to identify reservoir fairways and aid in play
segment risking.
The Precambrian Ara Formation comprises six (A1-A6C) carbonate-evaporite cycles, most of which are
totally encased in salt. Hydrocarbons are produced from the overpressured to hydrostatically-pressured
dolomite “stringer” intervals which define the focus of the study. Some of the complexities in predicting
reservoir sweetspots for exploration of the Ara carbonate stringers are: 1) Slabs encased in salt can
only be jump-correlated seismically to another slab hence palaogeographic reconstruction is hampered
by salt halokinesis; 2) Primary reservoir quality is complicated by diagenesis and charge timing; 3)
Post-charge reactivation of structures affects hydrocarbon column, -phase, and distribution of
pressures.
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Tertiary Petroleum Geology of the Southern Mediterranean: A Regional Correlation from Northern Tunisia to the Levantine Basin
Authors Christine Fildes, Alexis Godet, Michael Simmons, Owen Sutcliffe and Duncan MacGregorThe Tertiary petroleum system of the southern Mediterranean has resulted in major discoveries that
can be placed in the context of the sequence stratigraphy scheme developed by Sharland et al. (2001)
for the Arabian Plate and further updated by Simmons et al. (2007) (with some further modifications).
Throughout Tertiary times significant falls in sea-level driven by eustacy have been identified, as have
associated lowstand deposits that can be correlated regionally.
The Nile Delta is proving to be a world class hydrocarbon province with an abundance of potential
source rocks within the Lower Miocene, Oligocene and possibly the Mesozoic. The most prolific plays to
date are associated with Pliocene reservoirs, which can be linked to a latest Messinian sea-level fall. In
the adjacent Levantine Basin, the Mari B Field gas discoveries offshore Israel have been made in
Pliocene sediments that also correspond to the same lowstand described offshore Egypt. Another
important play is within the Miocene, constituted by submarine sandy fans related to a sea-level fall
recorded in the Langhian and Messinian of the Nile Delta (Ng 30 and Ng40 SB).
Other potential plays have been postulated, especially those associated with Oligocene lowstand and
transgressive sediments that display good reservoir quality within the Satis oilfield. Elsewhere in North
Africa this play is of interest, especially offshore Northern Tunisia where the deepwater turbidites of the
Numidian Flysch (Late Oligocene to Early Miocene; Pg50 and Ng10 SB) exhibit excellent reservoir
potential and are a proven play in Sicily.
Finally, the offshore Sirt Basin is a promising frontier basin, and as with the Nile Delta, the Messinian
lowstand is an important time for reservoir and seal formation. The palaeo-Sahabi river system drained
from Lake Chad in to the offshore Sirt Basin during the Zeit Wet Phase. This river system has left a
significant erosional imprint on the east flank of the Tibesti and near the coast of the Gulf of Sirt, which
indicates a large sediment supply during this time creating large lowstand fans and delta deposits in
the offshore Sirt Basin.
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Pore Network Modeling: A Route to Improved Reservoir Quality Assessment in Arabian Reservoirs
Authors Ian Billing, Clemens P. van Dijk and Mustafa TouatiFrequently in reservoir quality assessment, it is that which is not easily seen which has the biggest
impact on fluid flow behavior. The work presented here looks at the problems of quantifying two very
different reservoirs, the carbonates of the Jurassic Arab-D Reservoir and the clastics of the Devonian
Jauf Formation, both of which are impacted by pore system attributes beyond the resolution of a
standard optical microscope. In this study we highlight the results of the 3D pore network modeling on
these samples, contrasting this with the conventional approach to porosity and permeability calculation.
Studies of the Arab-D reservoirs in Saudi Arabia highlight the importance of microporosity as a
significant factor affecting porosity-permeability transforms. Generally, such pores are less than 10
microns in size, but can account for over 50% of the pore volume in a sample. The more
microporosity, the greater the deviation away from the average porosity-permeability trend.
Modeling of the pore network in clastics of the Jauf Formation is complicated by the texture and
mineralogy of the sandstones. The grains are often covered with a thin layer of illite, comprising flakes
which are oriented radially to the grain surface. High microporosity within this layer and the thin nature
of the flakes results in a diffuse layer around each grain, lowering the permeability.
If we wish to model and predict permeability by transforming porosity data (such as obtained from
wireline logs), then it is imperative to know the amount of microporosity. Given the problems of
optically imaging microporosity in carbonates and sandstones, coupled with the complexities of a three
-dimensional pore system, a 3D modeling tool was used to capture and model these samples.
Thin sections and scanning electron microscope images from the samples were studied statistically in
2D and then the characteristics of the grains reproduced in 3D replicating the depositional mode of the
grains, their compaction and diagenesis. An algorithm for pore network extraction then built a
topologically-equivalent network consisting of balls representing the pore bodies and cylindrical
segments representing pore throats. Porosity and permeabilities were obtained by calculating the
proportion of voids space and by applying a pore flow code using elementary mechanisms of pore
filling. Additionally, the Lattice Boltzmann Method has also been used to calculate pore flow inside the
3D image itself.
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Biosteering the Upper Permian Khuff C Reservoirs in Saudi Arabia
Authors Geraint W. Hughes, Saleh S. Enezy and Samir RashidCoiled-tube, under-balance drilling is being used to improve gas and condensate recovery from the
Khuff C reservoir in Haradh area of southern Ghawar Field. The 2 5/8” diameter coiled-tube inhibits
access of conventional wireline logging tools except gamma and LWD, and the only source of
stratigraphic control is micropalaeontological and petrographic data gathered while drilling, referred to
as biosteering. Recent experience has shown that coiled-tube drilling can successfully be steered using
rapid thin-section production with micropalaeontological and petrographic analysis of cuttings samples.
Stratigraphic location is achieved by reference to a local biozonation based either on core or cuttings
samples from the mother bore or adjacent wells. Although of shallow marine origin, Khuff C
depositional environments were found to be highly varied over short distances, and it is necessary to
establish reference biofacies-based biozonations for each well using, where possible, the closest cored
well. Stratigraphic control is possible to within 2ft vertical accuracy, and enables near real-time critical
instructions to be communicated to the directional driller ahead of the gamma data. As the “eyes” of
the drill, this technique has enabled maintenance of the bit within the target reservoir and resulted in
significant increase in gas and condensate production.
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Qatar Integrated Charge Evaluation: Sensitivity and Uncertainty Analysis Study Using Experimental Design
As part of a regional review of the Palaeozoic petroleum system of Qatar, an integrated charge study
was undertaken to investigate the distribution of hydrocarbons in Palaeozoic reservoirs. The charge
study, uses geochemical analyses and 3D basin modelling to detail the structural development and trap
filling history of Khuff reservoirs as well as determining generation and expulsion behaviour from the
Silurian aged Qusaiba Formation source rock.
The key results of the study are; (i) Qusaiba specific source rock kinetics combined with realistic
thickness and richness estimates can explain the reported gas volumes, (ii) Reservoir fluid phase is
governed by the recent PVT history, and even slight changes in pressure or temperature can result in
phase change within the reservoir.
In order to test the sensitivity of the results to uncertainty in the input parameters, experimental
design was employed. In the initial screening phase, input variables were varied to discover which of
these had most influence on the volumes, GOR, CGR and API of the discovered fluids. The results show
that while the depth and thickness of the source rock had the most influence on absolute volumes, the
fluid composition and phase was most affected by depth, hydrogen index and expulsion kinetics of the
source rock. In addition, the magnitude of uplifts associated with Tertiary unconformities had a
significant effect on the phase of reservoir fluids. The uncertainty ranges in the output resulting from
uncertainties in the inputs are currently being investigated.
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The Impact of Geostatistical Model Parameters from Fluid Flow: Detailed Modeling of the Large Scale Steamflood Pilot (LSP) Area, Wafra First Eocene Reservoir, Partitioned Neutral Zone (PNZ)
Authors William S. Meddaugh, Hong Tang and Niall ToomeyThe First Eocene reservoir at Wafra Field in the PNZ is a Paleocene/Eocene age dolomite reservoir. The
40-acre, LSP steamflood project consists of 56 new wells (producers, injectors, and temperature
observation wells), of which four are cored through the producing interval. The project area also
includes four older wells, one of which was cored.
Semivariogram models computed from the LSP wells (25-100 m well spacing) have correlation lengths
on the order of 200-300 m whereas previous full field studies determined correlation lengths of 1500-
2000 m using the primary development wells (500 m typical spacing). To test the impact of
semivariogram model parameters and data density on fluid flow response five sets of static reservoir
models were built. The fine scale static models (5 m areal grids, 4.5 million total cells) were simulated
without up-scaling using 3D streamline simulation. The dynamic scenarios selected were designed to
reduce the noise of well distance, sweep direction and material balance error on the results. Analysis of
variance (ANOVA) shows, with above 95% confidence, that models built using short semivariogram
ranges have significantly higher recovery than models built using large semivariogram range. The
conditioning well density does not significantly impact recovery.
The effect of areal grid size was also examined. Static models were generated using 10 m, 20 m, and
40 m areal grid sizes and fluid flow response investigated using 3D streamline simulation. The results
suggest that grid size may also significantly impact recovery as models generated using the 40 m grid
size gave more optimistic results compared to models generated using the smaller areal grid sizes.
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Nodular Chert Occurrences in the Upper Jurassic Diyab Formation, Abu Dhabi, U.A.E
Authors Aamir Siddiqui and Mitsuyoshi KanekoThe Upper Jurassic Diyab Formation was deposited during a marine transgression resulting from
regional subsidence. The Diyab Formation consists of argillaceous lime mudstones and wackestones
that change laterally eastward into peloidal packstones, grainstones, and dolomitic packstones. In Abu
Dhabi, the Diyab Formation is subdivided into three informal members: lower, middle, and upper based
on the lithology and gamma ray signatures.
Diagenetic silica occurrences in the Diyab intervals have been identified by conducting visual inspection
of cores as well as petrographic analyses on some core samples. Silicification of carbonate host rock
involves the precipitation of silica in the form of pore-filling silica cement as well as the replacement of
carbonate by chert. Early mechanical compaction and sediment dewatering played important role in
the siliceous skeletal particles dissolution, migration of silica rich fluids and the consequent
precipitation of chert. Nodular chert is the most common diagenetic silica form observed in the Diyab
Formation, whereas selective replacements and silica cement within carbonate samples also observed.
Most occurrences of nodular chert are encountered near and inside dolomitic layers of upper zone of
the Diyab reservoir. Chert in carbonate rocks is generally known to be biogenic origin. However, within
the Diyab reservoir occurrence is closely associated with the infiltrated brine which also caused
dolomitization in the carbonate rocks. These minor chert replacements have not significantly affected
reservoir quality, but their recognition is important in calibration of wireline log responses for lithology.
Microfractures also developed within the nodules due to the brittle nature of chert and these fractures
may also aid in the fluid transport within the reservoir.
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The Dhruma Formation of Saudi Arabia: Bajocian to Bathonian Micropalaeontology and Sedimentology
The Faridah, Sharar and Lower Fadhili hydrocarbon reservoirs of subsurface Saudi Arabia represent
grain-dominated terminations of a succession of shoaling-upwards depositional cycles. They are hosted
within the Dhruma Formation and a recent study of outcrops and shallow cores drilled in the outcrop
belt has revealed the palaeoenvironmental and lithostratigraphic locations of the reservoir facies as
well as a regionally significant seismic reflector known as the Dhruma Shale. The age of the Dhruma
Formation is based primarily on ammonites and nautiloids but supplemented by micropalaeontological
and palynological evidence. Carbon and oxygen isotope determinations complement the
biostratigraphic evidence. The Dhruma lies unconformably on the Early Jurassic (Middle to Late
Toarcian) Marrat Formation and is unconformably overlain by the Middle Jurassic (Middle to Late
Callovian) Tuwaiq Formation. An allostratigraphic, sequence-based reinterpretation of the originally
defined Dhruma now assigns the Atash and Hisyan Members, previously of the uppermost Dhruma
Formation, to the overlying Tuwaiq Mountain Formation.
The Dhruma Formation at outcrop consists sedimentologically of a thick succession of shoalingupwards
depositional cycles, each of which commences with calcareous mudstones (marls) that contain
moderately deep marine foraminifera with pelagic bivalves, and terminate with clean, locally crossbedded
to hummocky cross-bedded and ooid-bearing carbonates that contain very shallow marine
foraminifera and associated microfossils.
The study concludes that the Dhruma Formation was deposited as a succession of high-frequency
depositional cycles. The outcrop has provided new information on the palaeoenvironment and
lithostratigraphy of the Dhruma Shale, Faridah, Sharar and Lower Fadhili reservoirs and will have
significant impact on further exploration activities to identify these reservoirs in the subsurface.
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Sequence Stratigraphy and Reservoir Characterisation of Barren Fluvial Sequences Using Rock-Typing Analyses of Core and Cuttings
Accurate reservoir modelling relies primarily on the type, quality and amount of subsurface available
data. Despite recent improvements in the resolution and reliability of data acquisition and
interpretation tools, both using seismic and sophisticated wire line logging techniques, real direct
reservoir observation is still represented primarily by cores or sidewall cores. Because of the
operational complications and high costs associated with this type of data acquisition, cores or sidewall
cores are typically limited to either a portion of the reservoir section, or to a small number of wells
in a given area. These constraints inevitably raise questions as to how representative the core data
are, especially when used to describe complex reservoirs characterised by lateral and vertical
heterogeneity in facies, geometry and properties.
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Flow Units Characterization in a Dual Porosity-Permeability Carbonate Reservoir: A Case Study from Western Offshore, India
Authors Ajay Kumar, Aks Kakani, Calvert Stefan, Sutapa Bhadra, Arpana Sarkar and Chandramani ShrivastvaUnderstanding the distribution of flow units in complex carbonate reservoir is of utmost importance in
development planning and production optimization. The variation in reservoir properties along with the
texture in carbonate reservoirs is a clear manifestation of the complex diagenetic changes the
carbonates were subjected to. Proper analysis of the impact of such processes is imperative for decent
reservoir characterization and subsequent dynamic modeling.
There is little correlation between pore volume, geometry, grain size, shape and sorting in case of the
carbonate reservoirs. The facies variation as identified on the image logs add to the heterogeneity of
the reservoirs and give rise to different flow units conceptually. Determining facies type and
distribution is necessity for effective reservoir management. Conventional logs alone are insufficient to
identify and characterize the facies types, porosity distribution etc. The present study outlines a
technique to integrate heterogeneity analysis with dual porosity to provide accurate and quantifiable
permeability units of the reservoir.
Study area is situated in northern part of western offshore basin, India. It is oil producing carbonate
reservoir having different units. The reservoir is heterogeneous in nature with high and low porosity
units. An integrated formation evaluation technique using LWD, NMR, Electrical Imaging and Formation
tester data, improved the understanding of reservoir heterogeneity. Image data shows different degree
of diagenesis in carbonates resulting in complex textural variation. Porosity analysis from borehole
image and NMR measurements show intensive solution activity and provides porosity distribution and
quantification of vuggy fraction.
In order to link log data to the hydraulic properties of the reservoir and to provide useful and
consistent porosity analysis in carbonate, pore system has been partitioned into three components:
micropores, mesopores and macropores based on their pore throat diameter. Permeability is then
reconstructed based on various porosity distributions. Porosity partitioning permeability analysis shows
good match with MDT mobility as well as core permeability as compared to TIMUR and NMR derived
permeability. Integrating the entire data set differentiates quantifiable flow units and results in better
reservoir characterization. This is a novel methodology to differentiate permeable units in such
heterogeneous carbonate reservoirs.
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Effects of Dolomitization in Reservoir Quality of Sarvak Formation (Cretaceous) in One of the Giant Oil Field in SW Iran
More LessSarvak Formation with Albian-Cenomanian age is one of the major oil producing units in the Zagros
Basin. In the studied wells, Sarvak is about 637 meters thick and can be divided into two parts in
ascending order: the lower part is 257 meters and is composed of interbedded fine grained limestone
with pelagic fauna and shale and the upper part is 380 meter thick and consists of dolomitized neritic
limestones with interbedded of fine grained limestones. Based on petrographic (207 thin-sections of
cutting) and petrophysical studies of well logs, the effects of dolomitization on reservoir characteristics
of the sarvak Formation have been evaluated. According to crystal size and shape as well as presence
of dolomite in different lithofacies, three types of dolomite have been identified. Type one is fine
grained (5-60 microns) that has formed at the early stage and type two is medium grained (60-250
microns) and type three is coarse grained (250-500 microns) that both of them formed the burial at
the later stage of diagenesis. Based on petrography and well log analysis, the second type dolomite
has increased the quality (porosity and permeability) of the reservoir rocks in this field.
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Hydrocarbon Discoveries in Melut Rift Basin, Sudan
More LessMelut Basin is one of the extensional Sudanese interior rift basin located in the upper Nile State
southeast of Sudan.
The basin is characterized by three rift phases started from early Cretaceous, late Cretaceous and mid
Tertiary. The sedimentary infill of Melut basin was dominated by continental siliclastic sediments
deposited mainly in lacustrine and faluvial setting.
The structural architecture of Melut basin is characterized by a series of half grabens developed by
several types of normal fault tectonics, these grabens create separated sub-basin namely: north Melut
sub-basin, Central Melut sub-basin and south Melut sub-basin. The trap styles are fault dependent
closures, in terms of faulted anticlines, fault nose, and fault steps.
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Downthrown Trap Infill Analysis, Case Study from Melut Basin Sudan
More LessMelut basin is early to late cretaceous rift basin covered by thick sequence of non-marine sediments,
which vary in age from Cretaceous to Tertiary. Exploration results have indicated proven hydrocarbon
system in both Tertiary and Cretaceous sections. This petroleum system has a perfect assemblage of
source, reservoir and top seal. The source is the Cretaceous lacustrine shale of Galhak Formation. The
reservoir is the braided stream sandstones of Yabus formation, and the top seal is the fluvial shale of
Adar formation.
The majority of trap style in Melut basin are structural faulted block requiring fault seal on one or more
bounding faults. There fore the lateral seal play as a critical role to assess the trap infill probability.
In exploration context the challenge is to adopt role that the fault either connect juxtaposed reservoirs
or make a side barrier, prevent escape of hydrocarbon from lower structure. Effective fault seal model
analysis and calibration depend on the quality of available data.
The methodology applied in the analysis of fault seal potentiality in Melut basin encompasses,
identifying reservoir juxtaposition areas over the fault surface; using the mapped horizons and refined
reservoir stratigraphy defined by isochors at the fault surface; and deriving an empirical relationship
between rock type and fault displacement to assess the likely hood of sealing fault rocks being
developed. Shale thickness and amount of displacement play an important role to estimate SGR in the
fault zone. Buoyancy pressure profiles are used examination to identify which data analysis techniques
and seal-failure criteria best predict the observed hydrocarbon contacts in a given area. They can also
be used to verify the threshold shale gouge ratio values that represent the onset of fault sealing.
Results from hydrocarbon test of drilled well multiple provide a means for adopting same way of
analysis and therefore lead to improved prospect risking.
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Modeling Pore Pressure Profiles in Carbonates
Authors Stephen O‘Connor, Richard Swarbrick, Steve Jenkins, Sam Green and Phill CleggCarbonate reservoirs are the targets of many drilling programs around the world. In other cases,
carbonate rocks need to be drilled through to reach deeper reservoirs. Understanding the pressure
regimes in these carbonates is vital both for safe drilling and for reducing uncertainty in actual
reservoir pressures. As there is no relationship between effective stress and porosity/velocity in
carbonates, approaches based on changes in porosity using seismic velocity and/or log data such as
sonic and resistivity measurements will give false magnitudes of overpressure in these carbonate units.
Therefore another approach is required, one based on understanding the mechanisms of pressure
generation and build-up in a basin (a geological approach), “calibrated” using available (although often
rare) direct pressure measurements in permeable horizons within these units, coupled with shalebased
prediction techniques in any clastic intervals above and below the carbonates.
A geological approach based on lithology can be used to predict pressure in carbonates. Data needed
includes porosity and permeability characteristics of the carbonates, where low permeability marls and
wackestones produce different pressure profiles in comparison with high-energy, more permeable,
reefal carbonates such as grainstones and packstones. The latter group of carbonates may be
sufficiently well plumbed to allow hydrodynamic flow, leading to hydrocarbon/water contacts, a feature
of some of the larger Middle East oil and gas fields. A significant control on the internal pressure
regime of carbonates are the pressures of any associated clastics, both above and below the
carbonates, i.e. carbonates themselves do normally generate overpressure but have pressure
transition zones that reflect the pressures above and below. The shape of the transition zone relates to
the carbonate permeability whereby high permeability pressures are hydrostat parallel and low
permeability carbonates have pressure transition zones coupling top and base pressures. Using case
study material from the North Sea Chalks and SE Asia Limestones, as well as from Middle East
analogues, we will illustrate how a combination of these techniques can be used to model the pore
pressure profiles better through and within carbonates.
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Prediction of Unayzah Reservoir Quality Ahead-of-the-Bit
More LessRecent research at Saudi Aramco have examined the feasibility of predicting areas of good reservoir
quality - “sweet spots” - in the Permo-Carboniferous Unayzah reservoir away from areas of well control
using stratigraphic forward modeling. The Unayzah Group reservoir interval was deposited above the
Hercynian Unconformity over a 56 Ma. time period during the upper Carboniferous to lower Permian in
central and eastern Saudi Arabia, and consists of a succession of sandstones and siltstones that reflect
changing climatic conditions, from glacial and peri-glacial conditions in the lower Unayzah (Unayzah-C
and lower -B), to fluvial, lacustrine and ultimately eolian conditions in the upper Unayzah (upper
Unayzah-B and -A). Stratigraphic Forward Modeling has been applied to predict the distribution of
facies, grain size, porosity, and reservoir architecture in this diverse suite of rocks. Initial conditions
and paleotopography were established above the Hercynian Unconformity, with sediment erosion,
transport, and deposition modeled along this surface; lower Unayzah (especially the Unayzah-C)
sediments were modeled as the products of fluvial depositional systems intercalated with repeated
glacial advances and retreats. Modern analogues for this interval include glacial outwash plains in front
of retreating glaciers in Iceland and Argentina. Middle Unayzah sediments were modeled as
predominantly fluvial and lacustrine systems that arose during glacial retreat and collapse, while upper
Unayzah sediments were modeled as the result of primarily eolian deposition. Modern analogues for
upper Unayzah eolian sedimentation occur in modern-day Saudi Arabia. Model results correspond to
observed sedimentary facies and initial reservoir quality in cores and logs, and with stratal geometries
defined to the limit of seismic resolution. Results from this research will be used in conjunction with
diagenetic modeling in Saudi Aramco’s on-going reservoir quality prediction effort to develop better pre
-drill risk estimates for exploration efforts in this interval.
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Biofacies and Palaeoenvironments of the Khuff C Carbonates in Southern Ghawar Field, Saudi Arabia
Authors Geraint W. Hughes and Dhahran Saudi AramcoSemi-quantitative micropalaeontological analysis of closely-spaced core samples from the Upper
Permian Khuff C carbonates in the Haradh area of southern Ghawar Field has revealed rich and diverse
foraminiferal assemblages and associated microfossils, including bryozoa, calcareous algae,
brachiopods, echinoids, ostracods, rare sponge spicules and cyanobacterial sheaths. The foraminifera
are typically very small and include agglutinated, microgranular, miliolid and calcareous hyaline forms
that display a variety of morphotypes that assist to refine the depositional environment. In addition to
the considerable biofacies variations in ascending stratigraphic order within individual wells, lateral
variations are present that together reveal regional and temporal palaeoenvironmental changes. These
changes can be related to successive transgressive - regressive depositional cycles that compare
readily with the distribution of porosity. Rock fabrics range from dense mudstones through
wackestones, peloidal packstones to ooid grainstones. Porosity types encountered within the Khuff C
reservoir include interparticle, mouldic and intercrystal. Diagenetic alteration of the primary fabrics
includes cementation by calcite, dolomite and anhydrite, of which pervasive dolomitization is
responsible for creating porosity within otherwise non-porous carbonates. The close association
between biofacies and reservoir porosity distribution has led to the recent application of rigsite
micropalaeontological analysis to biosteer under-balanced coiled-tube development drilling of the Khuff
C reservoirs.
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The Palaeoenvironmental and Microstratigraphic Significance of Microcoprolites in Saudi Arabian Upper Jurassic Carbonates
Authors Geraint W. Hughes and Dhahran Saudi AramcoReservoir carbonates of the Arab Formation B and A units and Hith Formation contain beds in which
microcoprolites are well preserved. Species of the tubule-bearing, rod-like Favreina are attributed to F.
salevensis and F. fontana and represent derivation from a decapod crustacean source. Contorted
ribbon-like microcoproliths of Prethecoprolithus centripetalus represent derivation from a mollusc
source. Their association with cyanobacterial microgranules, often in stromatolitic layers, and
monospecific unornamented cyprid ostracods, Terebella lapilloides and absence of foraminifera
suggests a bacterial grazing mode of life within a stressed, marine environment that may have
experienced elevated salinity and temperature. The ascending succession from: (a) microfaunallybarren
anhydrite lithofacies; (b) microfossil-barren, granular cyanobacterial microbialite -
Decastronema / Aeolisaccus biofacies; (c) ostracod biofacies; (d) Favreina-Prethocoprolithus - ostracod
- cerithid gastropod biofacies; (e) Trocholina - Redmondoides - Palaeopfenderina - Mangashtia -
Clypeina-Salpingoporella - Thaumatoporella biofacies; to (f) concentric ooid biofacies. These facies are
considered to represent a parasequence within a shallow marine palaeoenvironment. The alternation of
such stressed carbonate units and evaporitic sediments is considered to represent episodic flooding of
a playa-like evaporitic basin, in which the foraminiferal biofacies probably represents the maximum
flooding event and best circulation of marine water. Microcoproliths provide intra-reservoir stratigraphic
events to complement micropalaeontologically sparse carbonates and would be expected to provide
valuable micro-biocomponents to assist coiled-tube biosteering of late Jurassic carbonate reservoirs.
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3D Facies Modelling the Concarena - Reconstruction and Quantification of from Archetype Triassic Carbonate Platform in the Southern Alps (Italy)
Authors Michael Seeling and Axel EmmerichThe Concarena platform is an outstanding example for the transition from Ladinian to Carnian carbonate
platform development in the Southern Alps. Two major stages of platform evolution are recorded,
separated by a marked overturn from slight progradation to pathological progradation sensu Bosellini
(1989). Due to the excellent preservation of all facies belts, a static 3D facies model can be constructed
allowing for a detailed reconstruction of its geometric evolution. The geomodel is based upon outcrop
studies with sampling and mapping campaigns, foto panel interpretation of unaccessible mountain
faces, high resolution satellite imagery (Quickbird data) and digital elevation model (Iconos data). Minmax
scenarios for carbonate production at platform top, reef and slope were established using 2D
stratigraphic forward simulation. The volumetric determination of accumulated sediments allows for the
first time the quantification and comparison of the carbonate factory at platform top, reef and slope
during two platform stages originating from different A’/S’ conditions and separated by a turn-around
point in base-level change. Whereas this turn-around point is recorded in other areas of the Lombardic
Alps by a marked subaerial exposure surface on platform tops, high total subsidence rates at Concarena
prevent the platform from distinct long-term emersion. The comparison of production rates adds further
evidence to the importance of changing A’/S’ conditions for platform development from aggradation to
progradation and hence to the slope-shedding model sensu Kenter et al. (2005) for high-rising
carbonate platforms. This study furthermore underlines and quantifies the influence of "Tubiphytes" on
the development of Triassic carbonate platforms. Large mounds-up to 4m in diameter and 1.5m in
height-made up exclusively of "Tubiphytes" multisiphonatus are situated in back reef environments and
uppermost slope settings. This is the second reported but strongly different occurrence of this
"Tubiphytes" species outside the type locality on Hydra (Carnian "Pantokrator Limestone", Greece).
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High Resolution Sequence Stratigraphy and Reservoir Development of the Kurrachine Dolomite, Ash Shaer Field, Palmyra, Syria
Authors Peter Gutteridge, Jonathan Hall and Lana HamdounThe Triassic Kurrachine Dolomite Formation of the Ash Shaer Field, Palymyra, Syria comprises
repeated cycles of shale, dolomitised carbonate mudstone and wackestone, peritidal limestone and
subaqueous anhydrite deposited in a restricted intra-shelf basin, sometimes connected to the
Neotethys Ocean.
The aim of this paper is to demonstrate a high resolution sequence stratigraphic model for the
Kurrachine Dolomite that may explain and predict the distribution of porosity through the reservoir.
Cycles observed and described in core were used to validate the field stratigraphy, such that Fischer
plot analyses could be extended to uncored logged intervals for each well. The corresponding
correlations of cycle number versus net deviation of cycle thickness from average cycle thickness
demonstrates the influence and control of high and low order sea level variations on porosity
development and preservation. High frequency sequence stratigraphy has aided the identification and
characterisation correlatable productive intervals in the Triassic Upper and Middle Kurrachine of the
Ash Shaer Field, Palmyra province. This has enhanced our understanding of reservoir connectivity and
stacking providing a valuable tool for improved development well planning. The following cycle types
were defined:
Subtidal cycles: are argillaceous laminated and bioturbated carbonate mudstone and shales. Cycle
boundaries are non-emergent. Maximum flooding events are bioclast-rich shales that may form fieldscale
correlative layers. These cycles are mainly limestone with little dolomitisation.
Subtidal cycles with anhydrite: anhydrite beds occur in the subtidal cycles that formed during drawdown
events and may form field-scale correlative layers. Dolomitisation is much more prevalent in
these cycles than the subtidal cycles.
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Evolution in Thermal Oil-Gas Petrophysics Due to Development of Optical Scanning Technology
By Yuri PopovReservoir thermal properties play an important role in thermal enhanced oil recovery (EOR) methods,
temperature logging data interpretation, and the modeling of heat and mass transfer in reservoirs and
wells. Nevertheless, up to now it has proved complicated to obtain reliable data on reservoir thermal properties.
The situation changed when an optical scanning method and two optical scanning instruments were
developed for measuring thermal conductivity, diffusivity, and the volumetric heat capacity on full
cores and core plugs at laboratory conditions. Optical scanning has allowed us to record the variations
of thermal conductivity and diffusivity along the inhomogeneous sample and to determine thermal
conductivity and diffusivity tensor components for three-dimensional anisotropy.
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Maximising Recovery from Thin Oil Columns Part 3: Maintaining from ‘Evergreen’ Subsurface Model to Optimise a Waterflood Development
Over the last three years the first stages of a waterflooding project comprising 200 horizontal
producers and injectors were implemented in a thin oil column (20m) transition zone carbonate field
(Shuaiba formation) in the Sultanate of Oman. The reservoir is composed of a high porosity, low
permeability matrix. Porosity and rock quality vary across the field to such a degree that wells in some
areas of the field are not economic. Therefore prediction of reservoir quality is critical to a successful
field development. The field development plan (FDP) that underpins this project utilised sequence
stratigraphy, acoustic impedance and production behaviour of existing wells to create static and
dynamic models which formed the basis for the development well patterns.
This paper focuses on the updates made to the static model since the FDP model, integrating drilling
results from the first 60 wells of the project and continued reservoir characterisation and modelling
work, to ensure that the planned wells remain economic and the well sequencing and placement
optimised. Automated workflows were established to incorporate drilling data on a day to day basis for
improved reservoir performance predications and well design. Information from appraisal wells and
production behaviour from the production wells was used for improved well sequencing and property
model rebuilding. Updated methodologies for rock typing, permeability and saturation height functions
were established. The overburden model is updated to give accurate formation top predictions for the
drillers.
Keeping an ‘evergreen model’ has proven a best practise to ensure continuously optimised drilling and
recovery from the field.
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Characterization of Glaciogenic Reservoirs Using High-Resolution Quantitative Mineralogical and Textural Analysis of Drill Cuttings
Authors Adriaan Janszen, Andrea Moscariello, Matthew R. Power and Jonathon SliwinskiIn the past decade glaciogenic deposits from Palaeozoic age in North Africa and the Middle East have
been recognised as important reservoirs for hydrocarbons. However, the sedimentary system
associated with glaciers and ice-sheets is highly complex and still poorly understood. This often results
in large exploration and development risks due to potentially large uncertainties in the reservoir
stratigraphy, facies and 3D architecture.
Glaciogenic reservoirs are often associated with deeply incised valleys (i.e. tunnel valleys). These are
formed under ice-sheets by overpressured meltwater and can reach up to 600 meters in depth, tens of
kilometers in length and 5 kilometers in width. As the sedimentary mechanisms and depositional
environments can be highly variable, the subsequent infill of the valleys is vertically and laterally
extremely heterogeneous. The heterogeneity of the sedimentary infill often results in problematic
subsurface correlation. This is made even more difficult by the absence of biomarkers or marker beds
that can be traced on a regional scale.
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Integrated Formation Evaluation in Horizontal Wells for Completion Optimization: Case Studies from a Complex Carbonate Reservoir in India
Authors Arnab Ghosh, Sutapa Bhadra, Theodore Klimentos, S. Chandrasekaran, S. Anand, V. Garg and S. BagThe carbonate formations of Mumbai High field are the most prolific oil reservoirs in India. These
geologically young Miocene carbonates are very complex in nature with extensive lateral
heterogeneity. Mumbai High field was put on production in the year 1976. The field has been under
water-injection for many years for reservoir pressure maintenance. Presently, some of these layers are
producing with high water-cut in drain-hole sections. The main objective of the present study was to
enhance productivity and reduce the high-water cut in the newly drilled drain-holes using a workflow of
integrated formation evaluation and effective completion strategy.
Carbonate formation evaluation using conventional well-logs to optimize completion has higher
uncertainty in high-angle and / or horizontal wells. Integration of advanced well-log data, i.e., dipole
shear sonic, formation micro-resistivity imaging, nuclear magnetic resonance and elemental capture
spectroscopy helped to reduce this uncertainty and optimize the completion strategy. Formation
textural heterogeneity from micro-resistivity image data helped to identify isolated and connected
vugular porosities. Moreover, detection of solution enhanced features and fractures were obtained by
combining formation micro-resistivity image and Stoneley-wave data. Pore size distribution for free
and bound fluid porosity and continuous permeability, determined from NMR, was used to delineate
lateral variations in this carbonate reservoir. Accurate lithology characterization in association with
heavy minerals, i.e., pyrite was possible from different dry weight elemental concentrations using
elemental capture spectroscopy data.
Slotted / cased liner completions have been used in horizontal wells for borehole stability and well
integrity purposes. However, these completions may have lower productivity relative to equivalent
open hole completions, if the perforated liners are not positioned correctly. The present study has
shown that optimizing the performance of the completion can increase well productivity in a cost
effective manner. The present case studies established an integrated formation evaluation approach for
completion optimization in a timely manner, which resulted in a significant increase of oil production
and reduced water-cut. This methodology can be used effectively in Mumbai High horizontal wells, as
well as, other carbonate reservoirs.
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Deformation Monitoring of Oil Platforms, Oil Fields and Understanding Reservoirs Using High Accuracy GNSS/GPS Networks
Authors Paul G. Althaus, Norbert Benecke and Karsten ZimmermannSince the beginning of Global Navigation Satellite Systems (GNSS) in the early 1980ies by American
GPS satellites, this technology became a common part of our daily life. Apart from widening the use of
GNSS systems in our daily activities, efforts have also been undertaken to strongly enhance the
precision and accuracy of GNSS observations. By using highly sophisticated equipment and postprocessing
procedures, the accuracy of measurements can be enhanced up to a few millimetres for a
permanent observation in horizontal and vertical direction. In many cases, GNSS monitoring therefore
will substitute levelling and subsidence monitoring with traditional techniques. These networks can
operate locally in a small area of only several sqm up to covering large areas of hundreds of sqkm at a time.
Typical applications of this high precision on line monitoring are the short- and long-term behaviour of
industrial plants, oil platforms, structures or oil fields. The highest demands on the accuracy of GNSS
surveying systems are often made on projects related to monitoring time dependent behaviour and
deformation of buildings, structures and areas. Monitoring and evaluating the smaller changes will
allow to anticipate the potentially occurring stronger changes, which are unwanted or may even cause
unsafe situations, but the focus often is to reveal smallest impacts from deep underground operations
and geologic inhomogenities.
The precise monitoring of reservoir exploitation and management and the deformations that may result
at surface allow a better understanding of the underlying processes, which in turn has led to improved
operating procedures aimed at minimising such deformation effects and / or enhancing reservoir exploitation.
Such effect is also well known, examined and documented also in the mining sector worldwide for the
last 130 years. This presentation shows the current state of GNSS technology, the methodological
approach, the post processing of GNSS data and the excellent results that are obtainable. Case studies
are shown from oil and gas and mining projects.
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Structures of the Kirkuk Embayment, Northern Iraq; Foreland Structures Or Zagros Fold Belt Structures?
More LessSeveral anticlines in northern Iraq and Syria have been studied through the construction of balanced
and restored cross sections. Based upon structural analysis each of the studied anticlines is a faultpropagation
fold that developed due to Zagros related recent inversion of much older normal faults.
Studies on the Iranian part of the Zagros fold belt have suggested that the regional variation in the
character of the fold belt is related to weak detachment surfaces in the stratigraphic section, primarily
the decollement developed near the top of the Hormuz salt where the salt is present. No evidence for
Hormuz salt has been found within the Kirkuk Embayment, and although detachment surfaces
contribute the area’s structural character, the prominent folds appear to originate mainly from
basement involved faults.
Two distinct inversion structural trends exist; an EW system and a NW system of inverted grabens. In
Syria, several of the faults associated with the EW trending system cuts the basement on seismic data
and have stratigraphic relationships suggesting that their displacement originated in the
Neoproterozoic. In Iraq where a thicker sedimentary section is present, the available seismic data does
not show the complete sedimentary section or fault systems’ trajectories. While the NW fault system of
inverted normal faults could be linked to the Zagros Orogen by a decollement surface in the
sedimentary section, regional relationships and potential-field data suggest that this trend also is
basement involved and has a Neoproterozoic origin.
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