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GEO 2010
- Conference date: 07 Mar 2010 - 10 Mar 2010
- Location: Manama, Bahrain
- Published: 07 March 2010
301 - 400 of 457 results
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Biostratigraphy of Dashtak and Khaneh Kat Formations in Zagros Basin
Dashtak Formation composed of dolomite, anhydrite and limestone whereas Khaneh Kat Formation
composed of dolomite, shale and limestone excluding evaporites, both Formations deposited in a
homocline carbonate ramp with a widespread depositional facies including supratidal, tidal flat, lagoon,
shoal and lower mid ramp. These formations were evaluated in a basin wide cross section including 8
subsurface (Aghar#1, West Aghar#1, Naura#1, Dashtak#1, Dalan#1, Kuh Siah#1, Sartal#1,
Huleylan#1) and 3 outcrop sections (Kuh-E- Surmeh, Kuh-E-Manghasht, Oshteran Kuh). Data gathered
from field observations, thin sections of borehole cutting, geophysical data (GR, Sonic and Neutron
logs) and geochemical analysis were performed (strontium isotope only sartal#1). This study revealed
that Dashtak Formation comprises 4 sequences (middle to late Triassic) and Khaneh Kat Formation
composed of 5 sequences (middle to late Triassic). So, almost lack of considerable biota content
caused changes arise here is a comprehensive biostratigraphy for these formations can not be carry
out. Unfortunately subsequence pervasive dolomitization obliterated those few rare biotas scattered
throughout limestone beds. In some cases the preserved biota represents a wide range (from base to
the top of the formation) and hence can not be used for biostratigraphic per poses. Although relative
high accommodation as they assist the recognition of MFS’s, as it is evident. Tr 40 restricted only to
Khaneh Kat Formation contains Agathammina sp., Valvanids, and Endothyramidae. Tr 50 has been
terminated in an ooid grainstone (shoal environment) rich in bioclasts including Pelecypod,
Agathammina sp., Trocholina Cross, Involutina sp., and Hemigordius sp. Tr 60 was determinate in
limestone beds contain Agathammina, Involutina, Ophthalmidium, Pragsoconulus, Frondiculina sp.,
ostracoda, echinoids, Faverina sp. Iriondic and Glomospira. This surface in Khaneh Kat Formation
located in a limestone bed containing sponge spicules, Pelecypod, echinoids, gastropoda, and algae. Tr
70 was introduced in Sefidar dolomite member but in this research, we consider this surface shifted
downward in a fossiliferous limestone bed and containing Agathammina, Trocholina, Lituosepta,
echinoids, Gastropoda, ostracoda, Aulotorus, Glomospira, and Irandia. In Khaneh Kat Formation this
MFS contains algae, gastropoda, Involutina, Aulotorus and echinoids.
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Sequence Stratigraphy of Pabdeh Formation in Dezful Embayment (Zagros Basin) SW Iran
Authors Mehdi Khoshnoodkia, Hassan Mohseni and Ihsan S. Al-AasmPabdeh Formation (upper Eocene-Oligocene) is a carbonate dominated sedimentary package with shale
-marl intervals. This Formation was studied the type section (Kuh-E-Gurpi) and four boreholes located
in Dezful Embayment (Zagros Basin). The Pabdeh Formation comprises three depositional sequences
bounded by Type I sequence boundary in lower part and both Type I and type II sequence boundaries
in upper part. Uppermost sequence encompassed a subsea marine phreatic diagenetic environment,
whereas sequence one and two evidently experienced burial diagenesis with moderately reducing
conditions in a relatively enclosed system. Sr87/ Sr86 ratios represents a sharp separations between
sequence two and three, whereas low Rb content of these samples suggesting these sediments are not
affected by meteoric fluids in an open system. A double behaviour is expected from the Pabdeh
Formation as the lithology are combination of carbonates and shale alternations, as shales could be
considered as potential source rocks, whereas grainstones of tempestite facies of TST and HST in
second sequence have reservoir characteristics. Hence change of stratigraphic trap exploration is a
scenario for these facies changes within the Pabdeh Formation. Furthermore, extensive fracturing in
upper parts of second sequence (late HST) implies reservoir porosity development in these parts.
Evidences of meteoric water flushing implies in third (last) sequence, leads porosity development in
this sequence.
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Thermal Simulation for a Shallow Limestone - Rubble Reservoir in Bahrain Field
Authors Challa R. Murty, Ali E. AL-Muftah and K. KumarRubble Limestone is the descriptive name given to a massive Limestone unit of the Mishrif formation,
in middle Cretaceous in age. The zone consists of two layers are eroded in the crestal part of the
structure. Large volumes of oil are trapped against the Blue shale at the up structure. The zone has
both heavy & light oil. The amount of Heavy oil is estimated to be 90% of the initial oil in place.
Currently only light oil is being produced. This paper highlights the studies to evaluate Heavy oil
production potential.
Two separate studies were carried out, the first was to describe and characterize Rubble in order to
map the light & heavy oil and the water bearing layers. Geostatistical methods were used to populate
the 3D model of the reservoir with porosity & permeability values. After obtaining an estimate of the
areas of heavy and light oil, a fresh study was initiated to review and evaluate the Heavy oil prospect
and to prepare a suitable thermal EOR pilot plan for the heavy oil recovery. The study included
numerical modeling and simulation of a pilot area and find out the suitable EOR process and design the pilot.
The study indicated that the reservoir has too low matrix permeability and very small fracture volumes
to allow steam chamber formation. SAGD mechanism was therefore found not efficient for this
reservoir. Cyclic Steam Stimulation (CSS) has been simulated using two wells in the pilot area and
found attractive. Cold production from six different Horizontal wells were simulated and tested. They
indicated that cold production followed by CSS will be efficient to recover the Heavy oil. The paper will
describe the results of the study which led to drilling of the Horizontal pilot well for Cold production to
be followed by CSS Thermal process.
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Evolution of the Triassic Yanchang Lake, Ordos Basin, China
Authors Huaqing Liu, Naizhen Fang and Xiangbo LiAs a multi- composite basin developed on the stable Paleozoic craton of north China, the Triassic
Yanchang Formation of the Ordos basin, divided into 10 reservoir units of Chang10 to Chang1 from
base to top, was regarded by many researchers as deposits of a big sag lake basin with unified
subsidence and uplift, in which south and north delta systems were developed symmetrically around
the fixed lake basin center. While based on new data of heave / light minerals, distribution of dark
mudstones, seismic profiles, it is suggested that taking Chang 7 age as the turning point, the
depocenter of the Yanchang Lake migrated at least 30 km southwestwardly from the Wuqi-Fuxian area
of the north Shaanxi province in the middle Triassic to the Huachi-Huangling area of the east Gansu
province in the late Triassic. Controlled by the lake evolution, the delta systems of this basin developed
unsymmetrically. The southwest delta systems extended more basinward in middle Triassic than that
during late Triassic, however the northeast delta systems has the opposition condition. The SW to NE
compression caused by the intensive late Triassic western Qinglin orogenic movement as well as the tilt
of the northeast part of the basin, which was affected by the vertical uplift of Yingshan region, may be
the origin of the conversion of the south and the north depositional system of the Ordos basin during
middle-late Triassic.
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Depositional History and Nummulite Reservoir of the Jahrum (Zagros) and Ziyarat (Alborz) Formations, Iran
Authors Mina Khatibi Mehr, Ali Moallemi and Mohammad Hossein AdabiThe determination of depositional history and hydrocarbon potential of the Paleocene to Late Eocene
carbonates of the Jahrum Formation in Gisakan Mountain, 10 Km east of the Borazjan City (Zagros),
and the Ziyarat Formation of Upper Paleocene to Middle Eocene carbonate sequences in Alborz fold belt
in Iran were the objective of this study.
Major hydrocarbon sources in Iran are within the folded and thrusted Zagros belt in west of Iran.
Almost all hydrocarbon reservoirs in Zagros basin are located within the carbonate anticline structures
with high porosity and permeability due to many small to large fractures. Thus, for accumulation,
distribution and fluid migrations in carbonate hydrocarbon reservoirs, the depositional history of these
formations are very important to study. In both Jahrum and Zeyarat formations, Nummulites are
widespread and it is believed that original mineralogy of Nummulites are low-Mg calcite. However, field
and subsurface observations and thin section studies show that both Jahrum and Zeyarat formations
have excellent reservoir potential due to the presence of large amounts of moldic porosity in
Nummulitic facies. This may indicate that original carbonate mineralogy of Nummulites are aragonite
which would be dissolved due to meteoric diagenesis during the transformation of aragonite to calcite,
leading to dominant molding porosity in both formations. This is the first time, it is reported
Nummulitic facies has reservoir potential for hydrocarbon accumulation due to dissolution of original
carbonate mineralogy in Cenozoic carbonate sequences in Iran. Result of this study can be applied to
other geological settings with Nummulitic facies.
Based on distribution and abundance of large benthic foraminifera, ancient sedimentary environment of
the Jahrum Formation has been reconstructed. Gradual decreases of the sea level and hence the
distribution of large benthic foraminifera resulted in deposition of 6 sedimentary facies along the innermiddle
to outer carbonate ramp system in the Jahrum Formation. These facies, from deep to shallow
parts of the basin, include argillaceous carbonates containing planktonic foraminifera that were
deposited in a hemipelagic to pelagic environment.
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Organic Geochemistry of Crude Oils and Probable Source and Reservoir Rocks of Marun Oil Field, SW Iran
More LessMarun oilfield is one of the main oilfields in Dezful Embayment area, Zagros, Iran which is studied
geochemically in this paper. Forty three cutting samples of 6 wells, 23 extracted rock samples from
different source and reservoir formations (Cretaceous-Tertiary in age, Garau, Gadvan, Dariyan,
Kazhdumi, Sarvak, Gurpi and Pabdeh formations) and 6 crude oils from Bangestan and Khami reservoir
were studied for organic geochemistry and biomarker investigation.
Hopane and sterane biomarker parameters did not help constrain a single formation present in this
region as the source rock for the studied oils. This may be because of the high thermal maturity of the
oils relative to those of previous studies. Previous studies have used extended hopanes and steranes
abundances for correlation purposes. Unfortunately hopane and sterane biomarker correlationparameters
for oils from the Bangestan and Khami formations have stronger statistical correlations
with thermal maturity parameters than with other source indicators. Therefore aromatic biomarkers,
which were less affected by thermal alteration were used. Ratios of methylated triaromatic steroids to
triaromatic steroids and the occurrence of alykylated-trimethyl-benzenes (derivatives of
isorenieratene) suggest that the Kazhdumi Formation, although often proposed as the most regionally
important source rock, does not share biomarker characteristics with oil in the Bangestan and Khami
reservoirs. Another notable feature is that the reservoir oil has distinctly lower thermal maturity values
than bitumen extracted from adjacent source rocks, indicating that the oil and source rock bitumen
originate from different thermal events. The high amount of asphaltene in Dariyan and Sarvak
formations, while there is no evidence for biodegdation and the occurrence of tar mats can be
explained by a complex filling history, involving the mixing of different oil phases. Such a complex
history may also help to explain the poor match of reservoir oils to a single adjacent source rock.
The Marun oilfield can be regarded as a complete petroleum kitchen with a suitable cap rock, carrier
rock to allow oil migration as well as many source rocks matured enough to enter the oil window. But
the oils currently present in the Bangestan and Khami reservoirs exhibit a lower thermal maturity and
different biomarker characteristics to the regions most prolific regional source rock.
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Halite in the Upper Jurassic of the Marib-Jawf Basin, Yemen
Authors George J. Grabowski, G.K. Edgerton, Adil M. Noman, Jeff Ottmann and Charles R. BeemanThe Marib-Jawf Basin is a Kimmeridgian northwest-trending extensional graben in western Yemen.
There are 36 discoveries in the basin, with original EUR of almost 1.7 billion barrels of oil and
condensate and 18 trillion cubic feet of gas. These occur in sandstone reservoirs with halite seal, in
traps formed in part by salt structuring. Evaporite deposits and decolling salt movements are the
critical elements in the development of trap, top seal, and foot seal.
Halite occurs in thick beds in the Safer Formation (Upper Tithonian), up to 750 meters net thickness.
Meter-scale anhydrite beds occur at the top and base of halite beds. The halite is sub-aqueous salt
deposited in restricted-marine basins.
Thinner halite deposits occur in the Alif Formation (Lower Tithonian) in the downdip SE end of the
basin, mostly in the lower Yah Member, but also in the middle Sean Member and the upper Alif
Member. The Safer and Alif formations merge to form the Sabatayn Formation in the Shabwah Basin
SE of the Marib-Jawf.
Intervals of shale, siltstone, sandstone, and thin limestone beds divide the Safer Formation into 5
members. These fluvial-alluvial to paralic- and shelfal-marine deposits formed when the evaporitic
basin was desiccated. The fluvial sandstones in the Safer Formation contain some oil and gas. Fluvial to
deltaic-marine sandstones of the Alif Formation are the major reservoirs, with halite of the Safer
Formation forming the topseal.
Some shale in the Safer Formation is organic-rich (<16% TOC, HI < 955 mg HC/gC). They generated
oil in deeply buried portions of the basin, and the oil occurs in sandstone reservoirs of the Safer
Formation. The oils are low gravity (14-27 API) and 3-6% sulfur, with biomarkers typical of anoxic
hypersaline source rocks (Pr/Ph <1.0, abundant gammacerane, C35 pentacyclic hopanes, and C27
cholestanes).
Halite deformed by gravity sliding on listric faults detached in the basal salt, forming rafts that enclose
the Alif Formation. This created gaps in the Alif Formation, where salt is grounded on the underlying
Lam Formation. Salt flowed into the lowside of normal faults that moved during the Cretaceous. Salt
diapirs are present mainly in the SE end of the basin and the adjacent Shabwah Basin.
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Strontium-Isotope Age Dating and Correlation of Phanerozoic Anhydrites and Unfossiliferous Limestones of Arabia
Authors George J. Grabowski and Chengjie LiuWe are dating anhydrites and limestones that lack age-diagnostic faunas using 87Sr/86Sr ratios. It has
enhanced our correlation of the Miocene and Oligocene, Jurassic, and Triassic-Permian.
Deposits in Iraq that have been considered Middle Miocene are actually older. Sr-isotope ages of
anhydrites from the Fat’ha Formation from many wells give consistent ages of late to middle
Burdigalian (15.6-18.5 Ma). Platform carbonates of the Jeribe Formation are middle to early
Burdigalian in age (18.5-19.6 Ma). The basin-filling evaporites of the Dhiban Formation were deposited
from earliest Burdigalian through late Aquitanian (19.6 to 21.3 Ma). The Euphrates and Serikagni
formations are older still, deposited in the early Aquitanian to late Chattian (21.8-24.3 Ma).
The Kirkuk Group is composed of shelfal, shelf-margin and basinal limestones divided into many
lithostratigraphic units which are not easily correlated without an age framework. The youngest units
are middle to early Chattian (24.4-33.9 Ma), with the Bajawan, Baba and Tarjil formations being late to
middle Rupelian (28.5-32 Ma), and the Shurau, Sheikh Alas and Palani formations are early Rupelian
(32.2-33.9 Ma).
The Hith Formation is middle to early Tithonian (147.5-150.7 Ma). Anhydrites of the underlying Arab
Formation on the Southern Arabian Platform (SAP) are late to middle Kimmeridgian (150.7-153.5 Ma).
Sr ages of the basinal evaporites of the Gotnia Formation in the Gotnia Basin give the same ages.
Thick shelfal limestones below the Arab Formation on the SAP are early Kimmeridgian to as old as
Bajocian (168-171 Ma) in the Lower Araej Formation. Thin basinal Najmah and Naokelekan formations
in the Gotnia Basin are early Kimmeridgian to middle Bathonian (153.5-166.5 Ma). The underlying
Sargelu Formation is early Bathonian to Bajocian (167-168.5 Ma), equivalent to the Upper Araej and
Uwainat formations of the SAP.
Anhydrites in the Alan and Adaiyah formations are middle to early Toarcian (178-183 Ma) and late to
middle Pliensbachian (183-187 Ma), respectively. The Butmah Formation is late Sinemurian to late
Rhaetian (187-200 Ma). The Lower Araej of the SAP is early Toarcian-late Pliensbachian.
The Kurra Chine Formation in Iraq has yielded a Rhaetian Sr age, and the underlying Geli Khana is
dated Ladinian. Anhydrites of the Jilh Formation on the SAP give older ages (Carnian to Anisian),
equivalent to the lower part of the Gulailah Formation (Rhaetian-Norian to Ladinian-Anisian).
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Real Time Deep Electrical Images, a Highly Visual Guide for Proactive Geosteering
Authors Roland Chemali, Michael Bittar, Bronwyn Calleja, Amr Lotfy and Donald HawkinsFor ideal well placement it is now possible to guide real time decisions with deep electrical images of
the surrounding geology. New azimuthal deep resistivity LWD sensors show images of approaching
boundaries long before they cross the well path. Clearly the earlier an approaching boundary is
detected and mapped in space, the longer the window of opportunity to change the course of the well
and to avoid exiting the reservoir. Because the geosteering engineer sees geological events from a
distance and makes decisions in advance of crossing reservoir boundaries, the geosteering operation is
said to be “proactive”.
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Role of Artificial Intelligence in Different Stages of from Advanced Petrophysical Reservoir Characterization Process: Case Study of Iranian Carbonate Reservoirs
Authors Mohammad Bagher Shahvar, Riyaz Kharrat and Mahdi MatinReservoir characterization is a critical stage in simulation of oil and gas reservoirs. An appropriate
characterization yields to a robust simulation model that can enhance the production and reservoir
management. But characterization of carbonate reservoirs has always been faced with difficulties. The
reason is due to the heterogeneity that exits in reservoirs of this type. Heterogeneity causes
complexity in the relationship between different petrophysical parameters and therefore simple
mathematical equations would not be helpful anymore. This problem can be observed in prediction
processes such as rock type and permeability prediction, water saturation estimation and relative
permeability prediction.
Artificial intelligence has been used as a solution to this challenge in the last decade. Role of this
mathematical approach has become such important that ignoring it in a reservoir characterization is impossible.
In this comprehensive case study, using conventional core and wireline log data, application of artificial
intelligence technology is investigated in different stages of petrophysical characterization of two
heterogeneous carbonate reservoirs. These reservoirs are located in two giant oil fields on the southwest of Iran.
All the possible artificial intelligence techniques such as artificial neural networks and fuzzy logic that
can be useful in predicting the static and dynamic properties of the reservoir rocks are considered.
Porosity, absolute permeability, relative permeability, rock types and saturation of the reservoirs
understudy are the parameters that are selected to be estimated by artificial intelligence methods.
Among these parameters, models of porosity, absolute permeability and rock types (flow zone index)
are generated by both artificial neural networks and fuzzy logic, using wireline logs data as inputs, and
then the models are compared with the results of applying multiple regressions. Saturation and relative
permeability also are predicted by artificial neural networks and multiple regressions. This time the
input data are other petrophysical properties.
Obtained results from the models generated by artificial intelligence are more accurate and have more
correspondence with core derived data with respect to the results of applying multiple regressions. This
fact shows the importance of implementing artificial intelligence techniques in modern reservoir characterizations.
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Facies and High-Frequency Sequence Stratigraphy of the Lower Fadhili Carbonate Reservoir, Khurais Field, Saudi Arabia
Authors Abdullah S. Al-Mojel and Langhorne SmithMiddle Jurassic Lower Fadhili Member of the Dhruma Formation in Khurais Field is composed of three
high-frequency sequences, with numerous small-scale fining-upward cycles that vertically partition the
reservoir. The Lower Fadhili was deposited in a shallow marine intra-shelf basin. The reservoir is
overlain and underlain by marls. The reservoir consists mainly of wackestones and packstones with
several thin layers of grainstones capped by hardgrounds/firmgrounds.
The first sequence consists of argillaceous mudstone, beach intraclast-ooid grainstone and shoreface
coated-grain, ooid grainstone. Chondrities burrows occurred only in argillaceous mudstone facies.
Gastropods are common in the beach intraclast-ooid grainstone facies. The sequence is capped by an
exposure surface (hardground). The beach intraclast, ooid grainstone facies was cemented by early
ferroan calcite cement beneath the unconformity, with some reddened strata. Dissolution features
include partially/totally dissolved grains, with meteoric calcite cement common.
Fining-upward small-scale cycles of the second sequence onlap the unconformity. These are dominated
by open marine Pfenderina trochoidea wackestone facies and stromatoporoid packstone/wackestone
facies. The maximum flooding surface can be traced across the field. Grain-rich lithofacies are common
in the highstand systems tract.
The third sequence highstand was dominated by fining-upward cycles of stromatoporoid
packstone/wackestone facies, shallow-marine lagoonal wackestone and shoreface coated-grain
grainstone. Thaumatoporella and Cladocoropsis are abundant in the lagoonal wackestones. These are
capped by thin cycles of shoreface coated-grain grainstone, beach grainstone and marginal marine
green marl/argillaceous mudstone. Progradational and retrogradational stacking patterns of these
lithofacies reflect a low relief carbonate ramp that dipped gently to the north.
High-resolution sequence stratigraphy of the Lower Fadhili reservoir has been beneficial to reservoir
characterization and geological modeling.
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An Integrated Model for Characterizing Heterogeneous Carbonate Reservoirs
Authors Mohammad Bagher Shahvar and Riyaz KharratRaising the world's demand for energy accompanied by decrease in the ease of oil exploration and
production, has forced the oil industry to investigate novel and advanced techniques for different
stages of providing the energy; from early stages of oil exploration to increasing the production from
oil reservoirs by secondary or tertiary recovery.
A critical phase that plays an important role in simulating oil reservoirs and therefore managing the
different field's development plans is reservoir characterization. Poor reservoir characterization may
lead to implementation incorrect methods in field development and reservoir management and cause
losing unrecoverable sources and costs.
Characterization of carbonate rocks is a vital process, because carbonate systems constitute more than
half of the oil reservoirs of the world and also most of the reservoirs in the Middle East. On the other
hand heterogeneity is a problem that causes these types of reservoirs not to obey from general rules
and formula.
Due to the need for a comprehensive model for characterizing carbonate reservoirs, a very extensive
integrated study of all the methods available for different stages of a reservoir characterization process
(reservoir rock typing, rock type prediction, saturation distribution and modeling, dynamic reservoir
characterization, absolute permeability and relative permeability prediction) is done in this paper. For
providing the best model, geophysical and petrophysical approaches are taken into consideration and
are discussed in detail and the best combination and integration of them is presented as a
comprehensive model for characterizing heterogeneous carbonate reservoirs.
Then using conventional core and different wireline logs and also seismic data, this model is used to
characterize numbers of carbonate oil reservoirs of Sarvak formation of Iran.
Applying this model can save time of characterizing carbonate reservoirs and lead to best images of
petrophysical properties of reservoir rocks and the most accurate reservoir simulation models.
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A New Approach to Predict Relative Permeability by Artificial Neural Networks Using the Concept of Hydraulic Units: Case Study of from Iranian Carbonate Reservoir
Authors Mohammad Bagher Shahvar and Riyaz KharratRelative permeability is an important petrophysical parameter that plays a critical role in simulating the
oil reservoirs. Determination of fluid distribution and residual saturation, characterization of two-phase
flow in porous rocks and predicting the future reservoir performance, are just some of the fields that
relative permeability have application. Since laboratory measurements of relative permeability does not
provide accurate values for the reservoir scale, and also are expensive and time consuming, many
efforts have been done to find a way to predict relative permeability.
In this study, relative permeability is considered as a parameter that can be used to distinguish
between different hydraulic units. Each hydraulic unit has its own set of relative permeability curves
that usually are similar within one unit and are different from the set of other units. This fact is used to
differentiate the prediction models of relative permeability based on the hydraulic units. To do this,
flow zone index (FZI) approach is used to determine the hydraulic units of a heterogeneous carbonate
reservoir of a giant Iranian oil field. Then the relationship between major units that constitutes most of
the reservoir rock and relative permeability data are validated using relative permeability curves.
Capillary pressure curves are also used as a tool to investigate the number of units defined by FZI
approach. To build the synthetic models of relative permeability, hydraulic unit number 10 of the
understudy reservoir, is selected. Artificial neural networks that its application in relative permeability
prediction is proved before, is considered to generate prediction model. Besides porosity, end point
saturations and other rock and fluid properties, some functional links are also used as inputs for the
model. Back propagation is the algorithm applied in this study to minimize the error. After training and
testing the networks, some data associated to unit 10 that were not introduced to the network while
training, were used to validate the network performance. Obtained results show a good correlation
between predicted relative permeability and measured ones.
This strategy is applied for both of the water and oil relative permeability prediction and the results are
satisfactory. Using this approach, each hydraulic unit of a reservoir rock will have its own relative
permeability model, enhancing the relative permeability imaging of the whole reservoir rock.
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Prediction of NMR Log Parameters from Petrophysical Data Utilizing Intelligent Systems
Authors Mohammad Mahdi Labani, Karim Salahshoor and AliKadkhodaie IlkhchiNuclear Magnetic Resonance (NMR) log provides useful information for petrophysical study of the
hydrocarbon bearing intervals. Free fluid porosity (effective porosity), rock permeability and bound
fluid volume (BFV) could be obtained by processing and interpretation of NMR data. In this paper,
fuzzy logic and artificial neural network have been utilized as intelligent tools to estimate the NMR log
parameters. The petrophysical data from two wells of South Pars gas field are used for constructing the
intelligent models and then the reliability of the developed models are evaluated via petrophysical data
of a third well from the same field. It is illustrated that the obtained results successfully indicate the
adequacy of fuzzy logic and artificial neural network in synthesizing NMR log parameters. The
combination of the obtained results from the individual fuzzy logic and neural network in a simple
averaging committee machine is demonstrated to provide a significant improvement in the accuracy of
the estimating NMR log parameters from well logs.
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Oilfield English Spoken Here … a Tug-of-War in the Oil Patch
Authors Richard Lau, Nadia Al Hasani, Laura Lau and Constance EideFrom the day Edwin Drake drilled the first oil well in Titusville, Pennsylvania, in 1859, English has been
the lingua franca of the petroleum industry. This standardization has allowed diverse groups from
differing linguistic backgrounds to work together to get the oil to global markets efficiently and
economically. The United Arab Emirates (UAE) with its large numbers of migrant workers and its vast
oil reserves has certainly profited from this standardization.
Founded in 1971, the UAE has become a magnet for the world’s skilled workers and has judiciously
used its copious oil revenues to build a modern society. With citizens comprising less than 20% of the
total residents, English has replaced native Arabic as the dominant language, not only in the oil
industry but also in the daily business world of the UAE. Unified primarily by language, the migrant and
local residents of the UAE, forming differing cultural groups with distinct, ethnic identities, have
experienced some disagreements as the disenfranchised groups seek more inclusion and recognition.
When the Abu Dhabi National Oil Company (ADNOC) opened the Petroleum Institute (PI) in 2001, its
mandate was to educate Emirati young men to become engineers capable of managing ADNOC’s
extensive oil fields and reserves. Since then, the PI has opened its doors to Emirati women in 2006,
and Expatriate men and women in 2007. High school graduates of private and government schools in
the UAE, these students are pursuing engineering studies preparing them for leadership roles within
ADNOC’s Operating Companies (OpCos).
This paper introduces the UAE and ADNOC’s initiative to open a local engineering school. It describes
the PI’s evolving curriculum, demonstrating how it continues to adapt to meet the needs of its
changing population. Clarifying some of the political and economic policies that favor Emirati students
over Expatriate students and men over women, this inquiry will conclude by, first, examining the
implications of the particular standards and expectations for these different groups and, second, by
describing the results of a survey that explore the impact of these changes on the social cohesion
among Emirati and Expatriate men and women competing for recognition in the Institute’s engineering
programs and later for leadership positions within ADNOC.
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Velocity Modeling and Static Corrections for Complex near-Surface - from Alternative Solutions to Improve Seismic Imaging in Muglad Basin
More LessAn important part of statics solution is determination of the velocity and depth of the near-surface
layer. This information can be obtained from an uphole survey, Refraction First break methods and
sometimes from shallow refraction reciprocal surveys. Uphole surveys provide the most reliable results
but the spatial coverage of this method is always limited. Shallow refraction reciprocal surveys are only
effective for a certain geological situations. Refraction First break method are recently attractive, but
the methods recently used are heavily depend on the refractor data quality.
By using of first breaks picks in a range of given CDPs for apparent velocity and intercept time, the
velocity and depth for weathering and near-surface layers can be well estimated based on a local
constant layer assumption. By repeating this process for all CDP ranges, a good refine of a 2D/3D
velocity model can be built. This method improves refraction statics solution.
This paper will present uses of a reasonable amount of direct arrival and refraction picks data from 2D
and 3D Surveys in Muglad Basin to extract the apparent velocity and intercept time from overall
behavior of the picks, Replicating this process on multiple locations across the survey, to build an initial
velocity depth model to be used in calculating the velocity and depth of weathering layers accurately as
an alternative way to solve one of the main challenges in static correction process.
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Toc Determination of Gadvan Formation in South Pars Gas Field, Using Artificial Neural Network Technique
Authors Mehdi Khoshnoodkia, Hassan Mohseni, Omeid Rahmani and Jafar AaliTOC Content in a source rock is potentially affecting logging data (density, sonic, neutron and
resistivity logs). Hence analyses on these logs assist to a reliable assessment of a source rock which is
quick and economically cheap method rather than direct geochemical analysis. A source rock interval
poses less density, low velocity, higher sonic porosity, high GR values and increase in resistivity. In
this research Gadvan Formation was studied in two boreholes as potential source rocks. The log data of
two wells were used to construct intelligent models in a source rock of the south Pars Gas field,
southwest of Iran. A suite of geophysical logs (neutron, density, sonic and resistivity Logs) and cutting
chips samples were used to determine TOC Content of this Formation. Rock- Eval pyrolysis data reveal
that Formation is poor source rock (less than 0.5%), whereas logging data and intelligent methods
calculations suggest the Gadvan Formation as poor source rock. Hence we attempt to correlate
between geophysical data and direct TOC content measurements using ΔLogR, Rock- Eval and neural
network techniques. The results showed that intelligent models were successful for prediction of TOC
content from conventional well log data. In the meanwhile, similar responses from different other
intelligent methods indicated their validity for solving complex problems.
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A New Tool for Fluid Saturation Determination in Cores - Liquid Trapper™ Coring Technology
Authors Abdel Hamid Anis and Bas SchipperA new coring tool which samples core and its fluid contained within pores has been designed,
developed and tested in field trials.
The tool is run as a conventional operation, with minimal modifications to routine coring operations.
The Liquid Trapper™ consists of a specifically designed liner assembly, which through an inflatable seal
system ‘traps’ the liquids escaping from the core during the retrieval of the corebarrel to the surface.
Cores and fluids obtained allow the determination of the fluid saturations representative of formation saturations.
The technique of Liquid Trapper™ coring was originally devised to provide in-situ residual oil
saturations, however, because crude-oil samples are collected, the Liquid Trapper™ also furnishes
additional data and information that is essential for formation evaluation.
The tool has been proven in a number of coring operations for a variety of rock types.
This paper describes the features and operation of the Liquid Trapper™ tool and a case history is
discussed to illustrate its potential use in formation evaluation.
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Detection of Fractures with Dual Oil Base Mud Imager in Jurassic Carbonate Reservoirs, North Kuwait - A Case Study
Najmah, Sargelu and Marrat Formations of Middle to Upper Jurassic age are the prime targets for
hydrocarbon exploration in North Kuwait. These Jurassic carbonate reservoirs, particularly Najmah and
Sargelu, are in general tight. Despite low matrix permeabilities, presence of natural open fractures in
these reservoirs is believed to have enhanced the permeability by several folds, as is evident by
production rates as high as tens mmscf of gas and several thousand barrels of condensate/oil per day.
As such, proper evaluation of fractures is key to exploration and exploitation of these tight carbonate
reservoirs. Image log is one of the key tools used for fracture characterization in the Jurassic
reservoirs. Oil Base Mud Imager, OBMI, which is the tool used for resistivity imaging has the
disadvantage of limited borehole coverage. This limitation was successfully overcome by using Dual
OBMI in one of the recent wells. The aim of this paper is to demonstrate the innovative technique in
Dual OBMI tool and to highlight its advantages over the conventional OBMI tool even with two passes.
In Dual OBMI two OBMI tools are stacked one over another at an angle of 45 degree. Thus there are 8
pads in dual OBMI as compared to 4 pads in conventional OBMI tool. Each pad acquires five
measurements and the data is displayed as a color image oriented with respect to the geometry of the
tool and borehole. With dual OBMI the borehole coverage area is increased by 100%. In 8” hole the
borehole coverage with conventional OBMI is 32%, whereas, it increases to 64% with Dual OBMI.
Increased borehole coverage allows more complex features, both large and small to be properly
identified and described. Structural and stratigraphic features as small as 1cm can be seen, yielding a
wealth of high resolution, azimuthal information. This results in enhancement of the interpretation of
the borehole and the regional geology as well. It has application in structural and stratigraphic analysis
and high resolution net pay count. The following fracture types were determined Using Dual OBMI : (1)
open or closed fractures (2) resistive fractures (3) continuous or discontinuous fractures based and (4)
possible fractures. Dual OBMI also saves rig time as it obviates the practice of two passes with
conventional OBMI to increase the borehole coverage. This technique, not only provides double
borehole coverage, higher resolution but also saves valuable rig time.
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Refined Migration Techniques in Basin and Petroleum Systems Modeling - Is It worth the Effort? a Study from the Jeanne D’Arc Basin Offshore Newfoundland
Authors Friedemann Baur, Rolando di Primio, Hans Wielens and Ralf LittkeCombining compositional predicting PhaseKinetcs with state of the art migration methods such as mapbased
ray-tracing, pressure driven Darcy-flow and capillary pressure driven invasion percolation, allows
to take into account the influence of petroleum composition and its phase behavior even during
hydrocarbon generation, migration and accumulation. In combination with these migration models
different adsorption methods and different critical saturations as well as secondary cracking processes
inside and outside the source rock and different API calculation methods are applied. The question is:
which minor processes can be calibrated independently and can therefore be validated? Or is the
system over-determined and minor processes are just helpful to calibrate and manipulate the system?
In the present study area, the geochemical composition of the Egret source rock and the accumulated
quantities in the Jeanne d’Arc basin are well known. Therefore, we can test and quantify the processes,
which affect the fluids during primary and secondary migration. Chemical properties of the source rock
have been investigated based on 38 samples and PhaseKinetics were determined. The first step was
the evaluation of a heat-flow history through time, using different crustal- and stretching-models. The
heat-flow maps were then calibrated based on available vitrinite reflectance, bottom hole temperature
and apatite fission track data. In a second step different fluid flow simulators were combined with
different types of kinetic data. Additionally, we tested the influence of different equations of states
(EOS), namely Peng-Robinson and the Soave-Redlich-Kwong EOS, on the ensuing phase behavior and
physical properties (e.g. API gravity) of the migrating fluids in the models. We demonstrate also that
some other minor processes are not completely taken into account such as the real nature of the
hysteresis effect of drainage and imbibition for capillary pressure vs. saturation and that real interfacial
tension maps for both gas and oil should be used instead of two constant IFT values. However, defining
all minor processes in detail does not always lead to more accurate results due to the generally high
uncertainties in basin modeling, which causes also a very poor determination of losses during primary
and secondary migration. However, to reproduce and calibrate the general pattern of generation,
migration and accumulation these minor processes can be used very well.
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Magnetically Inferred Basement Structures in the Central Part of the Kuwait Arch
Authors Parmjit Singh, Husain Riyasat and Abdul Aziz H. SajerMagnetic data over the Kuwait Arch concealed by overlying Phanerozoic strata, shows a broad circular
magnetic high over the Kuwait Bay area and a conspicuous E-W trending associated magnetic low on
the north over the Bahrah area of nearly comparable amplitude. The gravity and seismic data shows a
major high over the same area which is as per the tectonic events in the area. The present study is
focused on the conspicuous magnetic low over the crestal part of the dominantly N-S trending Kuwait
Arch where a comparatively complex Bahrah oil field is located. On the basis of magnetic signatures, it
appears that shield elements (basic metavolcanics like basalt and rhyolite with high magnetic
susceptibility) extend beneath Phanerozoic cover resulting in a dipole signature of magnetic anomaly.
In order to infer the basement structures lying beneath the Bahrah and Kuwait Bay areas, magnetic
anomaly data has been processed, filtered and integrated with the gravity and seismic data.
To locate the observed magnetic anomalies directly over the magnetic source bodies that caused these
anomalies, the Total Magnetic Intensity (TMI) data has been transformed into Reduced-To-Pole (RTP)
map. The TMI data also processed for 3D Analytic Signal, produces maxima over magnetic contacts
regardless of the direction of magnetization. The enhancement of magnetic anomalies associated with
faults and other structural discontinuities was achieved by the application of bandpass filter (4-12km)
to the TMI-RTP data which defined the best continuity and resolution of the linear features.
Basement structures, faults and shear zones can easily be traced along linear features which prove the
effectiveness in the interpretation. Faults and shear zones coincide with zones of significant changes in
magnetic and structural characteristics. The NNE-SSW orientation of basement-involved structures
over Bahrah and Kuwait Bay area are easily identified on bandpass filtered TMI-RTP data. The Bahrah
oil & gas wells producing from Cretaceous/Jurassic levels are located on magnetically inferred
basement highs. Basement structural highs control the structural development of the sedimentary
cover. The magnetic data after integration with gravity, seismic, borehole and geologic data reveals
the elements of basement structures over which the Bahrah oil field is located. This study can assist in
effective placement of future wells in Kuwait Bay and Bahrah area.
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Challenges Experienced during Processing of a Transition Zone 3D Seismic Survey in Abu Dhabi
Authors Mohamed A. Mahgoub, Joe Karwatowski, Johan Witte, Thib Hussein and Andre LevequeAcquisition of seismic data in Transition Zone (TZ) areas poses many challenges. Different sources and
receivers are required to acquire data in the land, tidal flat, shallow water and marine environments.
The diverse near-surface conditions and the differences between the various source and receiver types
give rise to a complex cocktail of noises. Furthermore, poor first break picks in the transition zone can
challenge traditional first break refraction statics techniques. As a result, the processing of TZ data
requires unconventional and creative processing techniques to address the data quality issues that are
unique to these types of datasets.
In this project, a 3D TZ seismic survey was acquired in three different, adjacent Abu Dhabi exploration
areas utilizing nine different source and receiver combinations, each designed to accommodate specific
requirements in sabkha, shore, shallow water and marine environments. Among numerous 3D seismic
data processing issues tackled were matching and optimization of phase and amplitude, bandwidth,
dual sensor OBC PZ summation, wavelet processing, pre- and post-stack coherent and incoherent
noise attenuation, statics solutions and imaging.
The results led to a seamless final dataset with optimized resolution and continuity, suitable for refined
structural interpretation and detailed stratigraphic analysis.
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Integrated Diagenesis and Sequence Stratigraphic Study of Tidal Sandstones: the Adedia Formation (Cambro-Ordovician), Sinai, Egypt
Authors Khalid Al Ramadan, Sadoon Morad and Essam El-KhoribyThis work examines the effects meteoric vs. marine diagenesis on Cambro-Ordovician tidal sandstones
owing to fluctuation of relative sea level (RSL). The distribution of diagenetic alterations is thus
constrained within the sequence stratigraphic framework of the succession. Initially, a rise in RSL
resulted in the deposition of transgressive systems tract (TST) sands directly onto crystalline
basement. These sandstones display evidence of limited cementation by marine, grain-fringing
dogtooth-like and fibrous calcite. A fall in RSL resulted in the progradation of a tidal flat complex and
deposition of highstand systems tract (HST) and lowstand systems tract (braided fluvial) sandstones.
Contemporaneous meteoric-water flux into sands of all the systems tracts resulted in the dissolution
and kaolinitization of feldspars, micas and mud intraclasts in all systems tracts. Sequence boundaries
(SB) are marked by fluvial incision of tidal sands and by the development of palaeosols. Mesogenetic
alterations include partial transformation of kaolinite into dickite, intergranular pressure dissolution,
and formation of variable amounts of syntaxial quartz overgrowths in all systems tracts. Telogenetic
alteration (i.e. weathering) in the sandstones includes the formation of goethite and calcite. Thus, the
integration of diagenesis with sequence stratigraphy provides a useful tool with which to understand
reservoir quality distribution in sand-dominated, tidal sediments.
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Sedimentation and Diagenesis for Improved Reservoir Characterization - Upper Cretaceous Carbonate, Onshore Oil Field, Abu Dhabi (United Arab Emirates)
Authors Magdy A. Hozayen and Mohamed T. ShuaibA big carbonate oilfield, located onshore Abu Dhabi, has been producing from the Upper Cretaceous
(Maastrichtian) carbonate reservoir since 1983. Detailed sedimentological, diagenetic, seismically
interpreted high-resolution sequence stratigraphy, flow units and reservoir rock type studies have been
carried out, integrating approximately 7,000 feet of core material, approximately 3,500 thin sections,
and well-log data of 46 wells. Core description along with semi-quantitative petrographic examination
of thin sections allowed establishing a new reservoir characterization model.
The sedimentological study suggested sixteen lithofacies types (LF1 to LF16) representing a wide
variety of depositional environments, ranging from upper ramp, rudist-bioclastic shoals to open marine
mid to outer ramp mud-dominated settings. The 3D seismic interpretation was integrated with the
results of the sedimentological study and seventeen high resolution fourth-order sequences were
defined which were finally utilized the basis for the reservoir model layers. The diagenesis study
showed a variety of diagenetic events and processes. Leaching, calcite cementation and dolomitization
formed a strong diagenetic overprint, and have produced a number of flow units masking the primary
petrophysical properties of the lithofacies. Karsts are developed at certain intervals within the
reservoir. Karst intervals commonly contain solution channels, solution enhanced fractures, collapse
features, and breccias. Challenges encountered during the reservoir rock type characterization process
necessitated the use of various RRT techniques and procedures to achieve a robust reservoir rock type
(RRT) scheme.
The integration of rock texture, facies, diagenesis, the newly developed high-resolution sequence
stratigraphic layering scheme together with the defined flow units suggested that the reservoir
comprises nine reservoir rock types; RRT1 being the best to RRT9 the poorest. A 3D static model was
built and the nine rock types were distributed within the seventeen fourth-order sequence stratigraphic
layers. The new 3D static model will be used as input for reservoir flow modeling.
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Petroleum Charge and Discharge in Central Arabian Basin
Authors Khaled Arouri and Pierre J. Van LaerWith the aim to improve prediction and reduce uncertainty following a number of unexpected results
from drilling, an integrated geological-geochemical-modelling approach was employed to untangle a
complex filling history in a predominantly gas-producing Palaeozoic system of Saudi Arabia.
The occurrence of light oil of variable condensate-to-gas ratios (CGR) both below and above the fieldwide
gas-water contact in the Permo-Carboniferous Unayzah reservoir at the Ghazal field precludes a
simple oil-rim setting. Gas-washing, water-washing, biodegradation, oil dropout, and source kitchen
variations can all be excluded from exerting major control on CGR, which, instead, appears to be
primarily a function of differential charging and discharging, as well as compartmentalization.
Whether the basin received petroleum heavier or less mature than that currently being produced (40°
- 50° API; calculated vitrinite reflectance, Rc ≥ 1.1%), and the likely fate of that oil remained open to
speculation. Fluid inclusions contain only light oil and gas condensate with no evidence for heavier oil.
The lack of heavier oil in these inclusions perhaps relate to reservoir temperature (< 90 °C) being
insufficient to form a significant amount of inclusions of early oil prior to the Late Jurassic. This may
partly explain the paradoxically long lag between the inferred onset of black oil generation (Triassic)
and light oil accumulation inferred from co-existing aqueous inclusions to have started in the Late
Jurassic. Nonetheless, sequential extraction of traces of residual oil adsorbed onto mineral surfaces or
trapped in smaller pores provided temporal resolution of oil charges, including evidence for the
“missing” oil, with maturities as low as 0.89% Rc.
These results (1) dispute the belief that less mature oil was never expelled from the source rock and
(2) suggest the presence of active migration pathways, at least over Ghazal, in Late Jurassic. The
presence of a trap at that time is only weakly supported from palinspastic reconstruction, and may
need better refined mapping of the overburden. Given the regional geology and maturity trends that
suggest charging from south and east, shallower or updip structures located to the west and northwest
— where paleo-oil accumulations may have been displaced or spilled — are a good prospect for additional oil.
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Prediction of Reservoir and Seal Capacity for Exploring Jurassic Carbonate Stratigraphic Traps, Northern Saudi Arabia
The exploration for stratigraphic traps, especially in carbonates, is challenging and requires carefully
detailed analysis of petroleum system elements. Accurately defining the spatial and temporal
distribution of source rock, reservoir, and seal facies is essential for exploring stratigraphic traps. This
study presents an integrated approach for evaluating reservoir and seal capacity of Jurassic carbonates
to explore stratigraphic traps using the Facimage electrofacies prediction and calibrated seismic facies
modeling techniques.
Core-based rock types were generated for selected Jurassic carbonate reservoir formations by
integrating core descriptions, thin-section petrographic data, core plug porosity/permeability, and
capillary pressure (MICP) measurements. Reservoir quality and sealing capacity were thoroughly
evaluated using core-derived pore-throat size and capillary pressure data from a full spectrum of
reservoir and sealing facies. This was followed by calibration of core-derived reservoir and seal facies
to well-log responses by constructing Facimage models for selected “Reference Wells” that are
extensively cored and analyzed. The Facimage models were rigorously tested by validating predicted
electrofacies/capillarity and core-derived rock types, and their sealing capacity. The optimized
Facimage model was used to predict electrofacies that represent rock types of varying reservoir quality
and seal capacity for all the selected “Application Wells” within the area of interest. The derived
electrofacies (rock types) of reservoirs and seals can be upscaled to a seismically detectable level. The
upscaled facies were then output as numerical codes into the calibrated seismic facies modeling of 3D
seismic volumes using state-of-the-art technologies for analysis, integration, and visualization.
The calibrated seismic facies, rock types and porosity models provide lateral and vertical facies
changes of reservoirs and seals within 3D volumes. These are critical elements for exploring
stratigraphic traps. The Middle and Upper Jurassic reservoirs have been taken as examples for the
above approach. Preliminary results have demonstrated that existing stratigraphic trap analogue and
potential new stratigraphic traps can be successfully predicted, as shown in the Upper Fadhili and Arab-
D reservoirs.
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Structural Characterization of a Limestone Target Interval in Abu Dhabi Using Advanced Acquisition and Processing Techniques on a Challenging Seismic Dataset
Recent advances in seismic acquisition, processing and interpretation techniques have had a significant
impact on exploration and production. New methods have been tested and implemented in Abu Dhabi,
to enhance the quality of subsurface imaging of an area with challenging topography, making it difficult
to acquire a decent 3D seismic survey.
This paper discusses the utilization of new and optimized seismic acquisition, processing, reprocessing
and interpretation methods and how it improved seismic imaging allowing reaching of projects goals and objectives.
One of the surveys was acquired in a transition zone area and innovative techniques were used to
obtain good quality data. These techniques included an optimized source-receiver array, monitoring of
the tidal slack periods and smaller source and receiver intervals. Apart from the conventional
techniques for statics solution a horizon based method was also used along with reflection statics which
resulted in better spatial continuity of the data sets. Details regarding the acquisition and processing of
this survey are the subject of another paper by my colleague Mohamed Mahgoub.
The other survey comprises a number of vintage 2D seismic sections of different vintages. Because of
the severe mismatches between the various vintages it was not possible to get an unambiguous
structural interpretation of the prospect in that area. The seismic lines were reprocessed carefully
allowing proper imaging of the relevant seismic reflectors.
The target reservoir intervals comprise a stack of carbonates with low impedance contrast. Attribute
analyses and advanced visualization techniques were utilized to detect facies distribution, structures
and geological changes. Careful interpretation of the data significantly improved the understanding of
the depositional sequences and potential charge history in the area. The confidence in the mapped
prospects has increased significantly as a result of superior acquisition, processing and interpretation practices.
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Al-Khalij Field (Block 6.Qatar) Development Optimization: A New Dedicated Reprocessing
More LessThe scope of this presentation is to illustrate the recently performed seismic processing applied to the
Al-Khalij field, block 6 Qatar. The main objective of this reprocessing was to better define the subtle
fault/fracture pattern over the field, to allow the incorporation of new water breakthrough data
observed in the development wells. Furthermore, results will be used to target future development well
locations over the Al Khalij field. In the framework of this project, particular effort has been put into
attenuating the surface related multiples without damaging the subtle faults/lineaments necessary for
the reservoir delineation and flow understanding. Moreover, the presence in the area of numerous
production facilities and the shallow nature of the reservoir lead to non-negligible effects on the fold
and footprint pattern. The fold in the undershoot area was correctly handled by a 3D multi parametric
interpolation. Geostatistical filtering was used as an alternative solution to tackle the remaining
footprint effect.
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An Outcrop Analog of Kharaib and Shu’Aiba Reservoir: Example of the Urgonian Platform (Lussanenque Area, Gard, SE France)
Authors Aurélien Virgone, Gérard Massonnat and Cécile PabianUrgonian limestone (Lower Cretaceous) of southeastern France is a coeval analogue of the Shuaiba and
Kharaib Formations of the Middle East and can constitute a good reference proxy to illustrate and
understand the internal geometries of these reservoirs. It is also a relevant database for reservoir
modeling and/or EOR studies.
Total Company has proposed an R&D work program focused on the comprehension of geometric and
petrophysical heterogeneities of the Barremo-Aptian carbonate reservoirs, located in Lussanenque area
(Gard, South East France). The present paper allows us to :
present internal geometry of high resolution sequences (vertical and horizontal variations at the
4th/5th order of scale) of outcropping sections and thereby comprehension of internal reservoir
architecture of the Kharaib and Shu’aiba formations, in contrasted paleogeographic domains of
carbonate platform (from internal to the slope), discuss the relationship between sedimentary
discontinuities and early acquisition of porosity, give some palaeogeographic trend for the main environmental belts in relation with the structural
framework and discuss the impact of the facies distribution around the Bab basin.
To achieve these objectives, an integrated workflow using a mixed static and dynamic approach was
used in order to constrain the reservoir architecture.
A huge database was studied, including several key sections and more than 60 vertical wells drilled in
the Urgonian aquifer. Some wells were logged (GR, resistivity, borehole images). This “rock” database
was completed by several dynamical data including 40 well tests and the surveying of 8 springs for one year.
A biostratigraphic framework was updated in order to discuss correlations between the different
studied areas, in agreement with the regional background knowledge (Vercors and Provence areas).
A reliable faciological model and an integrated sequential framework were built based on a detailed thin section analysis.
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Next Generation Technologies for Underbalanced Coil Tubing Geo Steering
Authors Anton Kozlov, Shaker A. Khamees, Julio C. Guzman Munoz and Serve FrantzenTechnology improvements continue to advance the capabilities of coiled tubing directional drilling
(CTDD) worldwide. The recent global increase in CTDD activity and the need for precise wellbore
placement and monitoring of downhole parameters in advance underbalanced re-entry applications has
led to the development of Bottom Hole Assemblies (BHA’s) with increasing functionalities. Saudi
Aramco with its prevailing dedication to expanding the technological envelope has recently successfully
completed the pilot phase of its first Underbalanced Coiled Tubing Drilling (UBCTD) project on the
Haradh gas field. After the success of the pilot phase and with the project moving in to the next stage,
impetus remains to further improve this economical re-entry technique through introduction of new
coiled tubing tools and services.
Through the process of miniaturization and innovation, small-diameter rib steering system has been
developed for CTDD and UBCTD. The introduction of this novel tool is aimed to help overcome the
intrinsic hurdles of conventional CTDD and enhance geosteering capabilities of the CTDD BHAs.
The rib-steering technology has been successfully tested on the North Slope of Alaska and North Texas
and was most recently introduced to the UBCTD project in the Kingdom of Saudi Arabia. Straighter
horizontal laterals and improved steering in openhole sizes as small as 2 3/4-in. ID have consequently
allowed improved precision in geosteering within the narrowest of payzone and extended lateral stepout capability.
This paper provides an overview of the Saudi Aramco UBCTD project, the new rib steering technology
and the benefits realized on this project and potential benefits to other UBCTD projects. The paper also
gives an account of several most recent deployments of the rib steering technology world wide, while
focusing on the ongoing UBCTD project in the Kingdom of Saudi Arabia which provides the perfect
testing ground for new UBCTD technologies. The advances that can be achieved on this current
project, and new UBCTD downhole technologies that can be developed through a close working
relationship between the field operator and the service company, will be applicable in other mature gas
and oil fields for the economical extraction of additional reserves.
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A Novel Approach towards Semi-Automated Lithofacies Identification from Image Logs
Authors Angeleena Thomas, Malcolm Rider, Andrew Curtis and Alasdair MacArthurVisualization is an important aspect of modern hydrocarbon borehole geophysical measurements.
Downhole tools are now able to acquire high-resolution 2D and 3D maps of the acoustic and electrical
properties of the borehole wall and display them in real time as false-colour images of the formations
encountered during drilling. These data now form a huge industry database. However, the
interpretation of these images under-utilizes the data.
To date, the only regularly used quantitative methodology applied to image log interpretation is for the
derivation of orientation data (dip and azimuth). Other, occasional quantitative methods use the
resistivity measurements themselves, and not the images. However, from the images themselves,
much additional information can be extracted, by using advanced object based image analysis software
which is widely available and is successfully employed for analyzing digital images at all scales, from
microscopic cell structures to satellite pictures.
We present a method for identifying lithofacies from image logs employing image analysis methods
used in remote sensing and medical science. The new technique presented synthesizes expert
knowledge and digital image analysis, to recognize physically and/or chemically consistent objects
within an image and relate these to geologically meaningful groups, such as lithofacies. Filters are used
to mark bed boundaries and are created from a derivative log extracted from neutron and density logs
and from bed orientation calculated using automated sinusoid fitting at every pixel depth in image log
within a formal uncertainty framework. The resultant lithofacies classification is then validated through
the interpretation of cored intervals by a geologist.
The image interpretation calibrated to core ensures the accuracy in the result obtained and the good
match between the two gives the confidence to extrapolate the automated image analysis result from
areas with core control to areas with poor to no core recovery. The developed method can be quickly
adapted to other wells or applied field wide by defining the lithofacies in each case and by appropriate
sample selection for each lithofacies. In addition, the methodology is applicable to several kinds of
borehole images, for example wireline electrical borehole wall images, core photographs and the more
specialized LWD images.
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Hydrocarbon Generation Potential and Source Rocks Characteristics of Upper Jurassic - Lower Cretaceous Formations in the Southern Part of the Mesopotamian Basin (Zubair Subzone), Southern Iraq
Authors Qusay H. Abeed, Sabine Heim, Amer Alkhafaji and Ralf LittkeMore than 60 core and oil samples from different wells and different oil and gas fields were selected to
determine the thermal history, hydrocarbon generation and migration in four important formations
from the Upper Jurassic- Lower Cretaceous period of the Mesopotamian Basin (Zubair subzone),
southern Iraq. The study area is situated in the southern part of the basin and covered many important
oil and gas fields in the Basrah province. Only few detailed geochemical studies on this important
petroleum systems have been published so far (Alsaadoni and Aqrawi, 2000). The aim of this study is
to get a more thorough understanding of source and reservoir rock characteristics of the Sulaiy,
Yamama, Ratawi and Zubair formations. Sediment and oil samples from important producing oil and
gas fields like Rumaila, Nahr Umar, Subba, Zubair, Ratawi, West Qurnah and Toba oil fields were
analysed by geochemical and organic petrological methods.
TOC-analyses, Rock-Eval pyrolysis as well as GC-FID and GC-MS measurements on solvent extracted
and fractionated samples were performed. To further estimate the thermal maturity of sedimentary
rocks vitrinite reflectance values were measured.
Results of this analytical work show that the studied formations are mature and have reached the oil
window. Most of the samples in the studied formations can be classified as type II/III or type III
kerogen. This coincides with a suboxic-anoxic depositional environment of Sulaiy and Yamama
formations while the Zubair formation is suggested to derive from a distal suboxic shelf deltaic
environment and the Ratawi formation from an inner shelf neritic environment. Due to the high TOC,
S2 and HI values, the Sulaiy, Ratawi, Yamama formations and the shales within Zubair formation are
considered as good petroleum source rocks.
Detailed molecular geochemical studies revealed a variabiliy in pristane/phytane ratios, CPI values and
biomarker ratios, both for source rocks and oils. These parameters were further used to establish oil
families and to correlate oils with their respective source rocks.
References
-Alsaadoni, Fadhil N. and Aqrawi, Adnan A.M., 2000, Cretaceous sequences stratigraphy and petroleum
potential of the Mesopotamian basin, Iraq: SEPM (Society for Sedimentary Geology), special
publication No.69, ISBN 1-56576-075-1, p.315-334.
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Petroleum Systems and Assessment of Undiscovered Oil and Gas Resources of the Levant Basin, Eastern Mediterranean
More LessThe U.S Geological Survey is currently re-assessing the potential for undiscovered oil and gas
resources in priority basins worldwide, including the Levant Basin. For this study, the Levant Basin is
defined to the east by the Levant transform system, to the north by the Cyprus thrust system, to the
west by the Eratosthenes terrain, and to the south by an assessment boundary with the Nile Delta
Province, which was also assessed for undiscovered oil and gas resources. The Mesozoic-Cenozoic
stratigraphic section in the Levant Basin is as much as 10 km thick and two main petroleum systems
were defined within this stratigraphic section, as most of the volumes of oil and gas probably
originated within these systems. The Mesozoic Composite Petroleum System includes potential and
hypothetical oil and gas source rocks of Triassic, Middle to Upper Jurassic, Lower Cretaceous, and
Upper Cretaceous (Cenomanian-Turonian, Santonian) age. Assessment Units (AU) within the Mesozoic
Composite Petroleum System that were assessed for undiscovered resources include the Carbonate
Reservoirs AU, which encompasses limestone and dolomite reservoirs of Jurassic through Miocene age
formed in reef, fore-reef, back-reef, and deepwater environments and are largely in stratigraphic traps,
and the Clastic Reservoirs AU which includes shelf-edge delta, incised valley fill, confined and
unconfined slope systems, and basin-floor fan reservoirs in stratigraphic and structural traps. The
Neogene Biogenic Gas System includes all source rocks in the Neogene that contributed to known postsalt
occurrences of biogenic gas. The Neogene Biogenic Gas System includes the Neogene Reservoirs
AU that encompasses clastic reservoirs of alluvial fan, fluvial, incised valley fills, shelf-edge delta, slope
systems, and basin-floor fan origin in both structural and stratigraphic traps. Each of these AUs was
assessed for potential undiscovered conventional oil and gas resources in this frontier basin.
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Volumetrics Analysis and Field Development Planning
Authors Gert H. Landeweerd, Luis Garibaldi, Hari Menon and Amit KumarThe process of estimating hydrocarbon-volumes-in-place is usually based on a probabilistic approach
that integrates whatever reliable and relevant data such as geologic/ geophysical interpretations, well
log and core data is available. This approach makes use of the prior (statistical) knowledge of
parameters such as prospect area, reservoir thickness, porosity and permeability - the intrinsic
parameters. The result is a probability (or cumulative-probability) distribution for a range of volumes;
companies typically report the 10%, 50% and 90% probable hydrocarbon volumes.
For field development purposes, we further exploit this approach to plan the exploitation by analysing
which intrinsic parameters “dominate” along different parts of the S-curve, or in other words where to
find the “quick wins” (pick the lower-hanging fruits first) and leave the more risky parts of the field for later.
The method comprises three steps: i) sensitivity analysis, ii) generating a range of scenarios and iii)
generating a development-risk map for the field.
The method will be illustrated by results from an actual field development project.
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Geologic Controls from Pore Pressure Variation in Najmah,Sargelu Formations — A Case Study from Raudhatain Field, North Kuwait
Najmah, Sargelu Formations have a complex petroleum system due to high pressure 17 to 15 ppg.,
low formation porosity and variable fracture porosity. Pore pressure is extremely variable and difficult
to predict.A geological study is done in Raudhatain field to understand pore pressure variation.
Real time pore pressure, well logs, cores and image log fractures are used for the study. Fracture
intensity logs from image log fracture data are generated. Correlations are prepared by integrating
these data and well test result.Structure contour, Isochore and Pressure maps are prepared.
Structure maps at all stratigraphic levels show uniform trend. Open fracture intensity are high at
structural high areas in Lower Najmah Limestone and Sargelu and strike parallel to the regional trend.
Away from structural high area open fracture intensity is moderate with strike parallel to regional
trend. Pore pressure maps at the top of these two intervals show maximum pressure atstructural high
areas and uniform pressure gradient for rest of the area. Isochore maps at the top of these two
intervals show uni directional depositional trend and maximum formation thickness at structural high.
Well tested in Lower Najmah Limestone and Sargelu has surfaced oil.
Open fracture intensity in Upper Najmah Limestone and Najmah Shale are low and limited to structural
high and its strike direction is inconsistent.Sharp contrast in pore pressure are observed between
structural high and areas away from it. Isochore maps at the top of these two intervals show shift in
depositional axis and maximum formation thickness are not always at structural highs.
In Upper Najmah Limestone and Najmah Shale limited fracture connectivity has resulted in more
abrupt pressure variation.Maximum pore pressure are localised at structural highs due to high
concentration of open fractures. In Sargelu and Lower Najmah Limestone high fracture intensity and
consistent fracture strike have resulted in more uniform pressure variation away from structural high.
Open fractures parallel to the regional trend act as conduit for reservoir fluid migration and helped in
transmitting formation pressure. Maximum formation thickness at structural high also resulted in
increase in effective reservoir thickness in Sargelu. The present study is a base work for building
fracture network modeling.
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An Integrated Study of Basement Rocks in the Bayoot Field, Say’Un-Masila Basin, Yemen
An integrated study of high resolution borehole images, petrophysical logs, production data, 3-D
seismic, sidewall cores and cuttings was undertaken on basement rocks from six deviated wells located
in the Say’un-Masila Basin, Yemen. The wells were drilled into the Rudood Ridge, a basement high
positioned in the footwall of a locally significant SW-dipping fault. Hydrocarbon emplacement is through
fault juxtaposition of the fractured basement against Late Jurassic organic-rich shale source rocks of
the Madbi Formation.
Structural analysis of borehole image logs focused on fracture characterisation and determination of
principal horizontal stress directions inferred from borehole breakout, induced fractures and borehole
shape. Structural image facies were used to highlight fracture intensity and internal fabrics. Fracturing
within the basement is intense, with in excess of 20 fractures per metre detected. Fractures have
extremely scattered orientations.
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Determination of Surface Relaxivity from NMR T2 Measurements
Authors Ayham Ashkar, Quentin J. Fisher and Carlos A. GrattoniNuclear magnetic resonance (NMR) is a very useful tool to determine rock properties. The NMR
respond to the hydrogen contained within rocks can be related in a direct or indirect way to porosity,
pore size distribution, rock permeability, capillary pressure, wettability and water saturation. The
magnitude of the T2 signal is used to obtain the matrix independent porosity. Bound and moveable
water can be estimated using the relation between response and saturation. Empirical relationships can
be used to several petrophysical properties, however, more detailed information is needed on surface relaxivity.
To determine the effective surface relaxivity and establish a methodology, sandstone ranging from
tight gas to poorly lithified sands were analyzed. The tests performed included conventional core
analysis (porosity-permeability), back scattered image analysis (BSI), NMR T2 relaxation on both fully
saturated and drained conditions. The permeability of the samples ranges from 0.01 to 1000 mD and
their porosities between 2 to 15%. The mean T2 of the Brine saturated samples ranged from 0.8 to
400 ms. Arithmetic average of T2 cutoff (calculated as the point where Swi intercepts the T2
distribution) is 39.2 ms however values ranged between 1.45 ms and 242 ms where clay content
played a key factor in reducing cutoff time. Back scattered images were used to establish the link
between T2 relaxation and pore area, this relation was then used to obtain the surface relaxivity.
This paper presents an innovative methodology to calculate the effective surface relaxivity using the
signal generated from mean T2 relaxation with the objective of obtaining a better understanding of the
NMR capabilities in assessing in situ reservoir properties. The methodology combines pore volume from
NMR and BSE image analysis. owever, in the case that image data were not available a correlation has
been generated, using a large number of samples, whichcan be used to obtain surface relaxivity only
from NMR T2 data. The surface relaxivity and T2 distribution can then be used to determine formation
capillarity and in consequence be able to model the saturation height function to provide an input to
the geological static model.
The advantage of this method comes from and the direct use of actual data, while the number of
samples analysed enables the final outcome to be generalised, and therefore suitable to be used as
empirical approach when experimental results are not available.
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Cretaceous Sequence Stratigraphy of Westrenzagros Outcrops from Kurdistan Region, N.Iraq
Authors Fadhil A. Ameen and Hero GahribThe exposed Cretaceous sequence in Kurdistan region were studied from four outcrops sections
(Qamchuqa, Dokan, Smaqwly and Safin),and correlated also with oil wells (Taq-Taq and
Chamchaml).They were deposited in pre-foreland and foreland basin within a time framework extends
from the Barremian to the late Maastrchtian including Qamchuqa, Dokan, Gulneri, Kometan, Shiranish
and Tanjero Formations. In this work Cretaceous sequence subdivided into four 3rd order sequences,
bounded by five sequence boundaries of type 1 or 2,and occasioanly type three ,they are; 1-Intra-
Barremian (S.B.T.1),2- Upper Early to middle Cenomanian (S.B.T.2),3- Upper most late Cenomanian
(S.B.T.2),4- Middle Campanian (S.B.T.2),and 5-late Maastrchtian(S.B.T.1).The nature and duartion of
each sequnecs and their bounadries emphasized by large and/or planktonic foraminifera zonations. The
first third order ( Intra-Barremian to lower early Cenomanian) represents by Qamchuqa Formation,
which consists of aggradational to progradational rudist bearing carbonate ramp facies associations
(600m thicK). This sequence was terminated either by drowning or by sub aerial erosion indicated by
Cenomanian unconformity and coincides with the international Cenomanian-Turonian euxinic event
(OAE2).The Late Cenomanian 2nd third order sequence consists of Oligosteginal carbonates are related
to Dokan formation, terminated with submarine erosion .The next third order resembled by Gulneri
Formation (Turonian to E. Campanian) present as condensed section of black shale. The fourth 3rd
sequences ,represnt by Kometan formation of remarkable shallowing upwards succession from deep
outer to middle and inner shelf and capped by hard ground surface within middle Companian
unconformity surface. late Campanian to late Maastrchtian third order sequences of outer shelf ,
turbidities facies and reef build up(Aqra Fn.), occasionally intercalated with oceanic red bed (ORB),
within the Zagros foreland basin acts as the best productive reservoir in the upper Cretaceous of
Kurdistan region.
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Source Rock Characterisation of Sediments from the Tarfaya Basin and Adjacent Areas, Morocco
Thermal maturity information has been compiled for the Tarfaya Basin, Morocco and surrounding
areas. Tarfaya Basin is bounded by the Anti-Atlas, the Reguibat High / Tindouf Basin and the
Mauretanides and developed since the opening of the Atlantic in the Permian to Triassic with
continental extension. Little is known about source rock potential in Tarfaya Basin, excluding
Cenomanian/Turonian black shales which were investigated e.g. by Kolonic et al. and Kuhnt et al. in
great detail. In general Lower Silurian, Upper Devonian, Lower Jurassic, Lower Cretaceous, Albian,
Cenomanian as well as Lower Tertiary shales are considered as source rocks. To get more information
about their potential, cuttings and cores from on- and offshore wells as well as outcrop samples
covering a large area (locations in Tarfaya Basin, Tindouf Basin and Bas Draa area) were collected.
TOC/TC and sulphur measurements, Rock-Eval pyrolysis, vitrinite reflectance measurements and
organic-geochemical analyses were carried out on these samples to get basic information on their
thermal maturity and the potential to generate hydrocarbons. Based on these data the burial and
thermal histories of several wells/pseudo-wells were modelled using PetroMod 1D. The modelling
results lead to the conclusion that in some areas highest temperature was reached at recent times in
accordance with deepest burial. The reconstructed temperature history shows moderate heat flow,
excluding times of rifting at present. The present day heat flow was modelled with values between 50
and 60mW/m2. In other areas, strong erosion took place and diagenetic paleotemperatures exceeded
present-day temperatures by far.
High TOC values were established for Eocene sediments in the southern part of the Tarfaya Basin (up
to 7%). In the Santonian, Coniancian and Campanian TOC values range between 1 and 6% and are
even higher in the Cenomanian/Turonian black shales. Most of the samples are representing a type-II
kerogen, whereas some of the Eocene samples contain type-I kerogen. Maturity of the samples is low,
i.e. they are immature or at the beginning of the oil window. Tmax values range between 400 and
450°C and Production Index is lower than 0.1. Furthermore molecular geochemical data provide a
more specific overview about the depositional environment and the maturity distribution.
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Hydrocarbon Potential of Kazhdumi Formation in Persian Gulf, Offshore Iran
Authors Omeid Rahmani, Hassan Mohseni, Jafar Aali and Mehdi KhoshnoodkiaThe study area is located in one of the most hydrocarbon reservoir of Iran offshore in the Persian Gulf.
Exploration data proved the presence of hydrocarbon in Cretaceous interval of the Zagros Basin.
Because the Kazhdumi formation with predominant black shale lithology is the most effective source
rock of Dezful Embayment that is reached to the oil window, this formation was the first candidate for
a potential source interval in the study area. So this formation was sampled from depth interval of 985
to 1098 m from cuttings of boreholes 2 and 3. Via Rock-Eval pyrolysis, 22 samples were analyzed. TOC
content of these shale samples varies from 0.12 to 1.2 wt. %. Rock-Eval results (e.g. HI vs. Tmax)
represent that Kazhdumi formation comprises type II-III kerogens and didn’t pass through the oil
window (Ro < 0.5) in this region. Accordingly, it is concluded that Kazhdumi formation had no
contribution to any hydrocarbon generation in the study area and an alternative possible source rock
may be considered for further investigations.
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Prediction of Hydrocarbon Generation from Lower Silurian Hot Shale Source Rocks by Using Bulk and Compositional Kinetics Results in the Murzuq Basin, SW Libya
Authors Abdulmonem A. Belaid, Sabine Heim, Mahmud M. Ismail, Rolando di Primio and Ralf LittkeOrganic-rich “hot shales” of the Lower Silurian Tanezzuft formation are regarded as the principal
source rocks for Palaeozoic oil fields in North Africa. Thus, the evolution of the petroleum system of the
Murzuq basin, Southern Libya, is largely controlled by the lateral extension, thickness, organic
geochemical characteristics and maturity of the Tanezzuft hot shale. In this context the petroleum
generation potential of Tanezzuft hot shale samples from the Murzuq basin was studied by geochemical
and petrological methods and a numerical modelling study was performed taking into account the
structural evolution and thermal history of this basin[1].
Core and cutting samples of the Lower Silurian interval were selected from two wells of the northern
and central part of Murzuq basin. High TOC contents and HI-values from Rock-Eval pyrolysis indicate
organic-rich source rocks with moderately hydrogen-rich organic matter, classified as Type II kerogen,
at different maturity levels.
To enhance the geochemical source rock characterisation as well as to predict hydrocarbon phases and
generation [2], bulk and phase kinetics were performed by open system- and closed system pyrolysis.
The bulk kinetic analysis confirmed the early to mid mature level for the northern part and immature to
early mature level for the central part of the basin. The activation energy distribution for the samples is
characterised by a smooth bell-shaped, Gaussian-like distribution, typical of marine type II kerogen.
Temperature and timing of petroleum generation were calculated using activation energies and
frequency factors with a linear geological heating rate of 3.3 K/my [2].
The compositional kinetic analysis was performed to assess the composition of generated petroleum.
The results show that 75 % of hydrocarbons is generated as oil and 25 % as gas fraction. The gas-oil
ratio was calculated and found to increase with increasing the maturity.
[1] Belaid, A., B. Krooss and R. Littke, 2009, Thermal history and source rock characterization of a
Palaeozoic section in the Awbari Trough, Murzuq Basin, SW Libya, Marine and Petroleum Geology, doi:
doi:10.1016/j.marpetgeo.2009.06.006.
[2] di Primio, R., Horsfield, B., 2006, From petroleum type organofacies to hydrocarbon phase
prediction. AAPG Bulletin, v. 90, no. 7, p.1031 - 1058
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Real-Time Data Management Standards Working as a Foundation for Improved Decisions and Work Processes
Authors Nicholas Gibson and David SwissaThis paper will present the case that real-time enabled data management, data mining and
petrotechnical work processes act as a solid foundation for 21st Century oil and gas exploration and
production work processes and can help oil and service companies make better quality decisions in
shorter time periods.
Studies by industry bodies along with cost benefit measurements have demonstrated that
implementation of real-time data management processes within integrated operations facilities can
provide hydrocarbon extraction and service companies with significant savings (e.g. CERA, 2003).
The implementation of real-time data feeds into integrated operations facilities to support and manage
offshore and remote operations have helped address several key strategic industry issues including:
- High costs for drilling operations - including measurement and understanding of non-productive time
(NPT) and invisible lost time
- Quality drilling data management practices from well spud to completion
- Reduction in the experience level of offshore crews
- Scarcity of experienced personnel across the oil industry
- The demographic profile for oilfield personnel, with a large scale “shift change” projected within 10 years
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Pore Pressure Prediction Using Seismic Inversion and Velocity Analysis
Authors Hamid R. Soleymani, SeyedMohsen SeyedAli and Mohammad A. RiahiThe concept of abnormal pressure, especially geopressure, is most important in hydrocarbon
exploration and production. Overpressured formations, in which the pore fluid pressure is higher than
the corresponding hydrostatic pressure, form an excellent trap for hydrocarbons. However, if the pore
fluid pressure exceeds a threshold dictated by the strength of the rock, the seal may have been
breached in the geologic past. This will cause the hydrocarbons to migrate away. This process will be
further facilitated by the presence of hydrocarbons in dipping formations due to fluid migration and
buoyancy effects. Thus, reliable estimates of formation pressure are critical to understanding the
hydrocarbon habitat, from regional to prospect scale.
In addition, Drilling through geopressured zones is challenging, and requires extra care. Knowledge of
the pore pressure in an area is important for several reasons. In overpressured zones, there is often
little difference between the fluid pressure and the reservoir fracture pressure. In order to maintain a
safe and controlled drilling, the mud weight must lie in this interval (i.e. between fluid pressure and
fracture pressure). If a too low mud weight is used (underbalanced drilling) while drilling through high
pressure zones, there is danger of well kicks.
Generally pore pressure can be estimated from elastic wave velocities using a velocity to pore-pressure
transform. velocities obtained from processing seismic reflection data are clearly required, but these
velocities often lack the spatial resolution needed for accurate pore-pressure prediction. This low
spatial resolution results from assumptions such as layered media and hyperbolic moveout.
In this study we obtain velocities at much finer scale at one of the Iranian south east oil fields using
either seismic inversion of amplitudes in conjunction with any acceptable low-frequency model, such as
SCVA or Dix. This is a new approach for generating velocity model and our aim is to obtaining a high
resolution velocity model that is more appropriate for pressure prediction. The next step is calculating
effective stress with Bower's equations (1995) that calibrated using available wells within the basin.
Also the main factors that causes pore pressure to rise abnormally within this field explained in detail.
Finally high resolution pore pressure cube which have enough detail for drilling applications can be
obtained with the use of Terzaghi's empirical equation.
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Acquisition and Processing of 3-D Dual-Sensor Towed Marine Streamer Data
Authors Anthony Day, Tilman Klüver, Andrew Long, Martin Widmaier, Berit Osnes and Adrian BurkeTraditionally, towed marine cables measure the seismic wavefield using only pressure sensors
(hydrophones). By contrast, in a dual-sensor streamer, independent measurements of the total
pressure and particle velocity wavefields are obtained using collocated sensors. These two
measurements of the seismic wavefield can be combined in processing to separate the wavefield into
up- and down-going components. 2-D case examples have demonstrated that this procedure is both
robust and accurate. This concept has now been extended to 3-D acquisition geometries. It has been
shown that 3-D dual-sensor streamer acquisition avoids exposure to weather, sea-state and streamer
spread control downtime by efficiently towing the entire 3-D streamer spread deep and at one common
depth. Removal of the receiver ghost effects simultaneously boosts both low and high frequencies
beyond any result achievable with conventional hydrophone-only streamers, and maximizes low
frequency signal-to-noise content required for accurate seismic inversion and reservoir description.
These applications are illustrated using data examples from a number of 3-D dual-sensor streamer surveys.
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Depositional History and Nummulite Reservoir of the Jahrum (Zagros) and Ziyarat (Alborz) Formations, Iran
Authors Mina Khatibi Mehr, Ali Moallemisa and Mohammad Hossein AdabiThe determination of depositional history and hydrocarbon potential of the Paleocene to Late Eocene
carbonates of the Jahrum Formation in Gisakan Mountain, 10 Km east of the Borazjan City (Zagros),
and the Ziyarat Formation of Upper Paleocene to Middle Eocene carbonate sequences in Alborz fold belt
in Iran were the objective of this study.
Major hydrocarbon sources in Iran are within the folded and thrusted Zagros belt in west of Iran.
Almost all hydrocarbon reservoirs in Zagros basin are located within the carbonate anticline structures
with high porosity and permeability due to many small to large fractures. Thus, for accumulation,
distribution and fluid migrations in carbonate hydrocarbon reservoirs, the depositional history of these
formations are very important to study. In both Jahrum and Zeyarat formations, Nummulites are
widespread and it is believed that original mineralogy of Nummulites are low-Mg calcite. However, field
and subsurface observations and thin section studies show that both Jahrum and Zeyarat formations
have excellent reservoir potential due to the presence of large amounts of moldic porosity in
Nummulitic facies. This may indicate that original carbonate mineralogy of Nummulites are aragonite
which would be dissolved due to meteoric diagenesis during the transformation of aragonite to calcite,
leading to dominant molding porosity in both formations. This is the first time, it is reported
Nummulitic facies has reservoir potential for hydrocarbon accumulation due to dissolution of original
carbonate mineralogy in Cenozoic carbonate sequences in Iran. Result of this study can be applied to
other geological settings with Nummulitic facies.
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Understanding Reservoir Quality in Ara Stringers (South Oman Salt Basin): Diagenetic Relationships in Space and Time
The Ediacaran-Early Cambrian Ara Group of the South Oman Salt Basin consists of six carbonate to
evaporite (rock salt, gypsum) sequences. These Ara Group carbonates are termed A0C to A6C from the
bottom towards the top of the basin. Differential loading of locally 5 km thick Cambrian to Ordovician
clastics onto the mobile rock salt of the Ara Group caused growth of several isolated salt diapirs, which
resulted in strong fragmentation and faulting of the carbonate intervals into several isolated so-called
‘stringers’. These carbonate ‘stringers’ represent a unique intra-salt petroleum system, which has been
successfully explored in recent years.
The goal of this study is twofold. Firstly, to detect trends in the spatial distribution of diagenetic phases
within the stringers and their effect on reservoir properties. Secondly, to unravel the relative timing of
diagenetic phases and to link them to the burial history of the salt basin. Mineralogy, rock fabrics and
geochemistry of ~ 200 samples from several petroleum wells from the late Neoproterozoic A2C interval
were analyzed and combined with pre-existing data.
Our analysis demonstrates that permeability is to a large extend governed by dolomite crystal size. For
a given porosity rock fabrics with larger crystal sizes show higher permeabilities. Crystal size is
strongly controlled by depositional facies. Grainstone and boundstone facies show larger crystal sizes
than mudstone to packstone facies. The crystal size distribution was determined for cored wells by thin
section analysis and estimated for uncored wells from borehole-image-log-derived lithofacies
distribution. The combination of porosity and crystal size information from logging and core data allows
calculation of field-scale permeability maps with high vertical and lateral resolution. These maps
comprise crucial information for better prediction of reservoir quality in the analyzed fields, planning of
new exploration wells and better volumetric calculations.
An integration of the paragenetic sequence derived from thin-section analysis with results from finite
element and discrete element models further helps to constrain the effect of salt tectonics on fracture
formation and fluid evolution within the stringers.
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Magnetotelluric and Radio-Magnetotelluric Investigation, an Example from Midsommar Island, Sweden
Authors Ida Hooshyari Far and Behrooz OskooiElectromagnetic methods are powerful and widespread geophysical methods that can be employed to
delineate the electrical resistivity/conductivity of Earth materials.
Magnetotelluric data and Radio-magnetotelluric data were collected in year 2000 at one site located on
the Midsommar Island, west of Stockholm. This work has been done under coverage of Björkö Energy
Project which has been designed to assess the potential for geothermal energy retrieval by mapping
the structure at depth with geophysical methods and by drilling.
MT sounding data from Midsommar Island including the information from RMT frequencies which
reflects the characteristics of the uppermost part of the subsurface in addition to three MT frequency
bands reflecting the characteristics of the deeper parts of the earth’s upper crust at the site.
The inversion results of the data from Midsommar Island are correlated well with the information from
a bore-hole drilled down to 964 m. the well-log shows conductive material at 900m depth extending to
larger depth. This conductor is clearly predicted by MT data at this site.
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Second Generation 3D Gridding: Changing the Way We Think from Reservoir Modeling
Authors Stan Abele and Jim ThomMaking 2D maps and more recently, 3D models of the subsurface is the mainstay for establishing
funding and operations of oil and gas producers worldwide. Over the past hundred years these maps
and models (including the processes, data types and machines used in generating them) have evolved
to attempt better understanding of the subsurface with the goal of reducing the risks associated with
drilling and field development Although each of the major subsurface geoscience disciplines
(geophysics, geology and engineering) have made a great deal of progress within their individual areas
of expertise it seems that no one has been analyzing the problem at the 30,000 foot level. Most critical
field development and drilling decisions are still made without integrating the data and the human
interaction around interpretation of the data. For the most part, this failure to integrate data is due to
the different scales each of the disciplines measures their data in, often having a range of 5 orders of
magnitudes in difference. Each of the major disciplines are discussing reservoir problems at different
scales (see figure 1). They lack the integrated software tools required to understand how the data
associated with the different scales can be cross referenced to provide insight into the key reservoir
issues. Most often, each of the disciplines retreat back into their specific expertise trying to find ways
to resolve the problem(s), unable to use the information provided by their team members. Finally,
most 3D models will not include the latest information from the field as it takes too long to incorporate
it or the associated specialists needed to assimilate data into the 3D model have been seconded to a
“more important” project. It is expected that due to the demographics of the Oil and Gas Industry that
these same seasoned specialists will be on the endangered species list soon. As costs for field
operations escalate, the industry will need to consider different ways and means to create and update
3D models more quickly, while at the same time incorporating all of the field data from all disciplines
(both old and new) in order to maximize the effectiveness of their field operations.
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How to Think Further Ahead in Hydrocarbon Prospecting
Authors Gert H. Landeweerd and Hari MenonWhen assessing the value of a collection of prospects and leads, we tend to ignore the more complex
and costly development scenarios such as multi-laterals, because we fear that these would erode the
value of our venture. In reality, however, a more costly development scenario may actually make
rather than break an opportunity by integrating the development of a number of prospects that
wouldn’t pass the hurdles when considered in isolation.
The approach we advocate (and actively practice) is based on a simple principle: If one can measure
and model the performance of an asset, then one can optimize it by considering a wide range of
alternative development scenarios at the earliest possible stages of assessment.Think of this simple
example: We work in an area where drilling is very hard (and therefore expensive). As a consequence,
most operators consider the drilling of vertical wells only. However, by being able to model the use of
much more complex well geometries, we can actually assess scenarios that involve the joint
development of a number of accumulations, which may more than offset the much higher cost of the
more complex well geometry.
The presentation will discuss a number of real-life examples.
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Application of Scale Attribute from Continuous Wavelet Transform from a Seismic Section in SW of Iran
Authors Ali Nekoeian and Sayyed Keivan HosseiniSeismic waves are affected by absorption of heterogeneity of the medium. Evaluation of attenuation
from decrement amplitude of seismic waves is often obtained with errors. Since absorption of seismic
energy increases with frequency of waves, it would be possible to investigate with frequency seismic
attribute on existence of heterogeneity. In this study we use time-scale spectrum or a scalogram
obtained from continuous wavelet transform and provide useful average measurements that are
directly interpretable in terms of time-frequency attributes. We prepared an algorithm in Matlab to
apply on real seismic section over one of the hydrocarbon reservoirs located in Persian Gulf-SW Iran.
We use Morlet wavelet as a symmetrical one in our analyzing because center frequency of wavelet at
each scale can be assumed to be inversely proportional to the scale. We investigated on attenuation of
seismic energy with instantaneous dominant frequency attribute which calculated respectively from the
scalogram. Using these kind of attributes, we may avoid the subjective choice of a window length
commonly used in Short Time Fourier Transform (STFT).
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Diagenetic History and Isotope Geochemistry of Pabdeh Formation in Dezful Embayment (Zagros Basin) SW Iran
Authors Mehdi Khoshnoodkia, Hassan Mohseni and Ihsan S. Al-AasmPabdeh Formation (upper Eocene-Oligocene) is a carbonate dominated sedimentary package with shale
-marl intervals. This Formation was studied the type section (Kuh-E-Gurpi) and four boreholes located
in Dezful Embayment (Zagros Basin). The Pabdeh Formation comprises three depositional sequences
bounded by Type I sequence boundary in lower part and both Type I and type II sequence boundaries
in upper part. Uppermost sequence encompassed a subsea marine phreatic diagenetic environment,
whereas sequence one and two evidently experienced burial diagenesis with moderately reducing
conditions in a relatively enclosed system. Sr87/ Sr86 ratios represents a sharp separations between
sequence two and three, whereas low Rb content of these samples suggesting these sediments are not
affected by meteoric fluids in an open system. A double behaviour is expected from the Pabdeh
Formation as the lithology are combination of carbonates and shale alternations, as shales could be
considered as potential source rocks, whereas grainstones of tempestite facies have reservoir
characteristics. Hence change of stratigraphic trap exploration is a scenario for these facies changes
within the Pabdeh Formation. Furthermore, extensive fracturing in upper parts of second sequence
implies reservoir porosity development in these parts. Evidences of meteoric water flushing implies in
third (last) sequence, leads porosity development in this sequence.
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Enhancement of Simulation Models Using Petrophysical Facies
More LessIf you ask a group of geoscientists and engineers “What is Facies?” you will definitely get very different
answers. The strange thing, but funny, is that they are working for long period of time, at the same
office, on modeling the same reservoir within the same field. One more strange (still funny) is that
both of them are exchanging a lot of data and most of these data are facies data (type, properties, categories…).
The wrong definition of facies affects negatively not only on the definition of the reservoir geometry but
also on the population of the reservoir properties. Geoscientists define facies from the geological point
of view based mainly on the lithology, depositional environment, diagenitic history, fossil contents and
other geological criteria. Based on these parameters geoscientists subdivide the facies into lithofacies,
biofacies, microfacies, icnofacies, electrofacies and seismic facies. Engineers look at the facies as a
different group of rocks that have different flow regime. Hence, if the flow of fluids within a body of the
reservoir is consistent this can be considered as one facies. Both definition need to be fine-tuned to get
the best results out of our reservoir models.
This paper suggests starting using the Petrophysical facies where the reservoir modeler uses all basic
Petrophysical reservoir rock properties (porosity, permeability, wettability, capillary pressure and
relative permeability) to differentiate between the different geological bodies within the reservoir rock.
This way we use the factors that control the fluid flow in a rock as a base for differentiating different
geological sittings. That will definitely give us a better chance to define the geometry of each facies
and then help us populate its properties within the defined reservoir bodies.
Out of 21 modeling projects in the Middle East and North Africa region, 16 of them did not obtain the
anticipated history matching because of the wrong definition of facies. Several case studies including
both carbonate and sandstone reservoirs showed a much better history matching after correcting the definition of facies.
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Determining Induced Microseismic Event Position and Origin Time
More LessTo optimize production and thus enhance hydrocarbon recovery, other alternatives are being
considered to better understand hydrocarbon reservoirs. One technology being considered is the use of
passive seismic techniques, which have recently attracted an increasing attention as
an emerging technology for hydrocarbon reservoir monitoring, characterizing, and/or imaging.
Production activities within a hydrocarbon reservoir, such as extracting oil or injecting fluid, result in
changing the in-situ stress conditions of the rock matrix that could trigger microseismic events. These
induced microseismic events are small earthquakes producing high frequency waves, which can be
useful for monitoring the hydrocarbon reservoir, if their hypocenters and origin times can be
determined accurately. Moreover, because the ray-path depends on the slowness model, the
relationship between the arrival time and the slowness is nonlinear.
Therefore, determining the locations of these events is a nonlinear inverse problem and under certain
situations is also a multimodal problem.
We adopt a three-dimensional gridded velocity model in which traveltimes are calculated using the
eikonal equation. An objective function is constructed by fitting the model response traveltimes to a
finite set of observed data through the use of the L1 norm. Then, we employ a
systematic grid search algorithm to minimize the objective function and hence obtain the hypocenter
position and origin time. The algorithm avoids using the derivatives of the objective function and is
comparatively easy to implement and robust to optimize, when used for obtaining
the event location and origin time. In addition, it seeks a global solution for the nonlinear and
multimodal objective function. Thus, it has less chance of being biased to local solutions, and a better
chance of obtaining superior results than the other methods. The results show application of the
algorithm to both synthetic and field data.
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Confocal Microscopy— A New Way to Model Carbonate Porosity in 3D
Authors Neil F. Hurley, Tuanfeng Zhang, Weishu Zhao and Guangping XuCarbonate rocks have complex pore systems, ranging in size from caverns to micropores. 3D models of
fine-scale porosity (<1 mm) are generally made using X-ray micro-Computed Tomography (CT) scans,
with resolution limits on the order of a few microns. Transmitted laser scanning confocal microscopy
(LSCM) and multi-point statistics (MPS) provide an alternative, high-resolution (0.1 μ) method to build
3D digital rock models of appropriate size and shape for pore-network construction and flow modeling.
Confocal microscopy uses point illumination and a pinhole placed in front of a detector to eliminate outof-
focus information. Because each measurement is a single point, confocal devices perform scans
along grids of parallel lines to provide 2D images of sequential planes at specified depths within a
sample. In this study, LSCM is applied to rock samples impregnated with fluorescing epoxy. Reflected
light intensity indicates the physical location of pore spaces. Samples are standard thin sections (30-μ
thick), or rock chips of any thickness. Samples are composed of rock and epoxy, or they may be pore
casts where the rock has been removed by acid.
Reflected light is absorbed and scattered by the material above the focal plane, therefore the depth of
penetration of LSCM is limited to 10-250 μ in rocks, and 500 μ in pore casts. LSCM data stacks
commonly have flat aspect ratios, for example, 20 μ thick by 210 x 210 μ or larger in area. To build
valid 3D models of physical pore systems, the depth of penetration should be at least 2 typical grain
diameters. Therefore, a grain-size limitation exists for LSCM imaging.
3D digital rock models constructed from stacked LSCM scans are used as training images for multipoint
statistical (MPS) modeling. MPS creates conditional simulations that use known results as fixed or
“hard” data. We use MPS to create thick (mm-scale), high-resolution (better than 1 μ) digital rock
models, suitable for pore-network modeling and/or flow simulation. Enlarged models avoid boundary
effects that compromise flow-modeling results. MPS models can be used to address the question: What
model size is needed to capture heterogeneity within a given rock type? Because MPS models are
unconstrained by size or shape, we can use them to test the concept of representative element volume
(REV). REV is the smallest volume that can be modeled to yield consistent results, within acceptable
limits of variance of the modeled property, for example, porosity.
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Quantitative Seismic Attributes for Fractured Reservoir Characterisation
Authors Erika Angerer and Syed M. HahighiIt is a considerable challenge to effectively produce from heterogeneous fractured reservoirs in a
complex structural setting. In this Middle Eastern onshore field the production comes mainly from
fractured igneous intrusive and metamorphic basement rocks and an overlying clastic formation. This
partially eroded and therefore heterogeneously distributed clastic formation can also have significant
fracturing. The presence of this clastic formation has a big impact on production of the drilled wells but
unfortunately it is below seismic resolution and therefore cannot be conventionally mapped on seismic.
The aim of this study was to detect fractured zones and to describe the distribution of the clastic
formation using seismic attributes calibrated to well information. A 400km2, high fold, wide-azimuth
seismic data set was acquired to provide an optimum illumination of the complex reservoir structure.
Azimuthal anisotropy from the wide-azimuth seismic survey proves to be one of the main productivity
indicators in this reservoir. Well production is quantitatively correlated with anisotropy intensity. In
some wells additional matrix porosity contributing to production is present in the heterogeneous
sandstone layer above the basement. The partially eroded sandstone layer can be detected with
seismic inversion. Therefore we find that a combination of these seismic attributes provides a powerful
tool to describe this complex reservoir. The attributes are used for well planning and reservoir modelling.
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Petrogenesis and Tectonic Setting of Island Arc-Metavolcanics from UM Samiuki Area, South Eastern Desert, Egypt
More LessUm Samiuki area is located at South Eastern Desert of Egypt. It occupied by a Neoproterozoic
metavolcanics intruded by metadolerite and latter by granitoid rocks. The metavolcanics of
investigated area are underwent low-grade regional metamorphism related to green-schist facies
during Pan-African Orogeny. It is low-K content and distinguished into tholeiitic and calc-alkaline
affinities. They range from basalt to rhyolite in compositions. Trace elements and rare earth elements
refer that Um Smiuki metavolcanics erupted in island-arc setting and display typical island-arc
geochemical signatures. It characterized by LILE enrichments, low abundances of HFSE as Ti, P, Zr, Hf
and Ta with pronounced Nb anomalies and depleted HREE relative to LREE, this refer to mantle derived
arc magma. Also, low Ti/V and high Ti/Zr ratios, low Nb/Y and Rb/Zr ratios, in adding to lower La/Yb<5
indicate an intra-oceanic arc setting. The constant ratios of La/Yb vs La and Ta/Th vs Sio2 through
magma evolution refer to fractional crystallization of the felsic rocks through an island arc association.
The presence of large amounts of pyroclastic and pillow lava refer that magma erupted in submarine
environment.
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Microfacies of Abu Dhabi Lower Cretaceous Section (United Arab Emirates)
Authors Ahmed A. Abdul Ghani and Abdulla E. Al MansooriThe Lower Cretaceous subsurface section of Abu Dhabi (K_10 to K_90) is composed of a carbonate
sequence reaching 2,900 ft thick, deposited over a time-span of nearly 30 MM years. 60 lithofacies
types have been recognized deposited in different environments, ranging from restricted supertidal to
deep basinal sediments. Thamama Group consists of four formations which, in ascending order, are
Habshan, Lekhwair, Kharaib and Shuaiba. The Habshan Formation is deposited up-dip on a wide and
gentle carbonate ramp developed during the initial Cretaceous flooding of the stable cratonal platform,
and embodies the progradation over, and subsequent filling of the old Middle to Late Jurassic cratonal
margin depression. Habshan Formation consist mainly of grainy, peloial, sometimes intraclastic, and
less commonly, oolitic limestone, with some lime packstone-wackestone; highly dolomitic in the lower
parts. During deposition of the Lekhwair Formation, minor tectonic pulses created a series of minor
transgression and regression. Cyclic sedimentation took place in the area, the lower part consist mainly
of wackestone - mudstone which grade upwards into Skeletal, peloidal packstone-grainstone. Kharaib
Formation is composed of four sedimentary cycles. The porous, grain-supported limestones represent
regressive phases, whereas the dense limestone units represent restricted platform. Shuaiba Formation
is the terminal event in the deposition of Thamama Group, and records the differentiation of the stable
craton in early Aptian time into an intrashelf basin surrounded by shallow carbonate shelf facies.
Shuaiba basinal facies have been termed the Bab Member, consists mainly of dark grey, dense
argillaceous lime mudstone-wackestone and shales. On the shelf margin of this basin, calcareous algae
and foraminifera with biohermal rudists accumulated a bioclastic peloidal, grainstone and floatstonerudstone
sediments.
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Dense Rock Bodies in Lower Cretaceous of East Abu Dhabi (United Arab Emirates)
More LessWeak seismic reflection (Low amplitude) areas of a circular shape have been observed in the Lower
Cretaceous Lekhwair Formation seismic Attribute time maps and sections of East Abu Dhabi area. A
well has been drilled in one of these features, shows that the Late Valanginian rock section came highly
cemented, (dense), with extensive stylolitization and reduction in formation thickness, compared with
a normal thickness and rock characteristics in the near by drilled wells (out side the features). This
phenomenon is limited to that stratigraphic section, and doesn’t affect the overlain Hauterivian rock
section. This features are most likely caused by, either Meteorites (impact from outer space)occured in
the Late Valagnian time, or by an upward forces came from bellow; and this need further investigation.
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Oil to Oil Correlation Studies in Marun and Kupal Oilfields (SW of Iran) Using Gas Chromatography-Mass Spectrometry-Mass Spectrometry (GC/MS/MS)
Authors Hanieh Jafary and Mohammad reza KamaliMarun and Kupal oilfields situated in south east of Ahwaz city next to Agha Jari and Ahwaz oilfields are
among the largest oilfields in the Dezful Embayment. Sarvak Formation constitndes the main reservoir.
In order to investigate geochemical characteristics, the distribution of "molecular fossils" (biomarkers)
in extracts from some specific geologic age in the Marun nd kupal Basins have been analyzed and are
used as the fingerprints for the oil-oil and oil-source correlation. Obviously, not any molecular fossil
related to source and environment can be used as the fingerprints for oil-oil correlation. Some special
biomarkers widely existed in the extracts in the Sarvak reservoir and showed obvious similarity in both
reservoirs, including dinosteranes (m/z=414-98), desmethylsteranes (m/z=414-217), methylsteranes
(m/z=414-231), C24norcholestanes and c28 Steranes originated from dinoflagellates and diatom. The
amazing similarity of the relative contents of these compounds between the marine oils produced in
sarvak reservoir of Kupal and marun oilfields suggests that the Middle Triassic is the very likely main
source for the sarvak reservoir in understudied oilfields. Based on maturity and source rock lithology
parameters of biomarkers, the candidate source rock(s) are carbonates deposited in anoxic conditions
and are thermally mature.
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Distribution of Carbonate Cements within Depositional Facies and Sequence Stratigraphic Framework of Shoreface and Deltaic Sandstones: Evidence from Lower Miocene Succession, the Gulf of Suez Rift, Egypt
Authors Mohamed A. El-Ghali, Essam El-Khoriby, Sadoon Morad and Howri MansurbegThe shoreface-offshore (transgressive systems tract TST and highstand systems tract HST) and coarse
-grained deltaic (lowstand systems tract LST) calcarenite and hybrid arenites of the Mheiherrat
Member of the Rudeis Formation, Early Miocene, the Gulf of Suez, Egypt were pervasively cemented by
carbonate cements and less amounts of zeolite, palygorskite, pyrite and iron oxides. The spatial and
temporal distribution of carbonate cements were constrained within a sequence stratigraphic
framework. The shoreface-offshore TST and HST calcarenite and hybrid arenites, particularly below
parasequence boundaries (BP’s), transgressive surface (TS) and maximum flooding surface (MFS) were
pervasively cemented by (i) grain-coating and inter- and intragranular pore-filling microcrystalline
calcite (e.g. circumgranular isopacheous acicular, and columnar and small amounts of circumgranular
equant) and inter- and intragranular pore-filling coarse-crystalline calcite (e.g. poikilotopic and
overgrowths) with δ18OVPDB = -3.6 to -0.3 ‰ and δ13CVPDB = -2.3 to -0.7 ‰, and (ii) non-ferroan
rhombic dolomite (δ18OVPDB = -3.9 to +0.9‰; δ13CVPDB = -2.5 ‰ to -0.7 ‰). The coarsegrained
deltaic LST calcarenite and hybrid arenites was pervasively cemented by (iv) grain-coating
calcite (e.g. columnar and circumgranular equant) and inter- and intragranular pore-filling coarsecrystalline
calcite (e.g. poikilotopic and overgrowths) with δ18OVPDB = -4.4 to -2.3 ‰; δ13CVPDB = -
2.8 to -1.3 ‰, and (v) small amounts of non-ferroan rhombic dolomite (δ18OVPDB = -4.8 to -2.5 ‰;
δ13CVPDB = -3.3 to -1.5 ‰). Such extensive cementations by carbonates i.e. calcite and dolomite
particularly below BP’s, TS and MFS were being facilitated by the presence of detrital carbonates and
bioclasts. This study demonstrates that the spatial and temporal distribution of diagenetic alterations in
deltaic and shallow marine calcarenite to hybrid arenites can be better predicted when linked to
depositional facies and sequence stratigraphy.
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Depositional and Facies Controls from Infiltrated/Inherited Clay Coatings: Unayzah Sandstones, Saudi Arabia
Authors Salem Shammari, Steve Franks and Osama M. SolimanClay coatings on detrital quartz grains inhibit precipitation of burial diagenetic quartz overgrowths and
help preserve porosity and permeability in Unayzah sandstones. These clay coatings are physically
emplaced, not neoformed (authigenic) clay coats such as fibrous illite or radial chlorite. Understanding
the depositional and facies controls on these clay coatings is necessary to predict reservoir quality in
the Unayzah sands. Petrographic and SEM analysis of sandstones from different depositional settings
and stratigraphic units within the Unayzah were made to investigate the relationships between facies
and the presence of grain coatings.
Grain coatings are found in all investigated depositional environments--eolian, fluvial, lacustrine, glacial
diamictite, and estuarine settings. These coatings are especially abundant in sandstones associated
with clay-rich paleosols. They are presently composed of illite and/or chlorite, but they may have had
precursor clay minerals prior to burial diagenesis (e.g., smectite, sepiolite, or palygorskite). The
relative amounts of clay coatings depend not only on the type of depositional environment, but also on
the stratigraphic unit within which the environment resides. This is interpreted to be a function of
changing paleoclimates during deposition of the Unayzah. For example, in the fluvial setting, the
percentage of clay coatings in the relatively warm fluvial systems in the upper part of the Unayzah A is
much higher than in the cold lower fluvial systems of the Unayzah C.
Moreover, this study shows that the presence of clay coatings is grain-size dependent. For a given
depositional setting (e.g., fluvial environment and its sub environments), there is a direct relationship
between the mean grain size of sandstones and the average percentage of coated grains in all samples
of this facies. In finer-grained facies, as in a distal sheet flood, more clay coatings (~90%) occur. In
coarser-grained facies, as in a fluvial channel, fewer grain coatings (~ 50%) occur.
Chlorite is the dominant clay coating in eolian settings, especially associated with coarser eolian grains
in dune and sand sheet sub-environments recognized in the upper part of the Unayzah (Unayzah A).
Also, in this unit, grains deposited in fluvial settings may be coated with illite or chlorite. In estuarine,
and fluvially dominated estuarine deposits (of the Basal Khuff Clastics), illite is the dominant clay
coating. Both chlorites and illites are present (with different percentages) in the relatively finer grains
deposited in floodplain/playa and interdune/distal sheet flood sub environments of the Unayzah A and
B units.
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Detection of Oil-Filled Channel Using Time-Frequency Spectral Decomposition
Authors Maryam Nejati and Mohammad A. RiahiDue to difficulties in observating many characteristics of a time-series in time domain, it can be studied
in the frequency domain. In fact, amplitude and phase spectrum have the ability to determine a timeseries
for us. Therefore, for a detailed study of time-series, we transform it from one-dimensional
domain to time-frequency domain. Because the transition from time domain to frequency domain
provides possibility to survey frequency content of a signal and consequently it provides detailed study
of many characteristics of the time-series. For this purpose the spectral decomposition which is an
efficient method has been used in recent years (Kastagna and colleagues, 2003). Spectral
decomposition method is an useful tool in interpretation of seismic data and seismic exploration also.
In fact, analysis of data to their spectral components can specify many of structural and stratigraphy
details below the earth surface. Spectral decomposition help us in detection of stratigraphy traps and
frequency content changes due to hydrocabore.
The spectral decomposition allow the interpreter to use the discrete frequency components of the
seismic bandwidth for interpretation and study the exact details of stratigraphy below the earth
(Chapra and Marfort, 2006).
Different spectral decomposition methods include short time Fourier transform (STFT), s transform,
Matching Pursuit and continuous Wavelet transform(CWT), that by using each of these methods we can
enhance the time and frequency resolution.
Continuous Wavelet Transform (CWT) techniques, which are the same as narrow-band spectral
analysis methods, provide frequency spectra with high temporal resolution without the windowing
process associated with other techniques CWT method is useful for detecting hydrocarbore reservoir,
because these reservoir were detected in low frequencies.
Identifying channels and detection the lithology within them have always been a topic of interest
among geophysists. This paper presents a successful application of the CWT method in identifyihng
buried channels in one of southern oil fields of Iran.
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An Integrated Analysis for the Re-Assessment of Hydrocarbon Potential of a Low Prospect Area-a Case Study from Jurassic Marrat Reservoir of Burgan Structure in South East Kuwait
Authors Arun K. Dey, Sunil Kumar, Nikhil C. Banik, Heyam Al-Ammar and Badruzzaman KhanRecent discovery of hydrocarbon from Jurassic section in different parts of Kuwait necessitated a relook
at Jurassic prospects of Burgan area in the light of better understanding of different elements of
hydrocarbon system defining the Jurassic play fairway. An integrated study on interpretation of 3D
seismic, fracture, sequence stratigraphy and analysis of reservoir engineering data have enhanced the
prospectivity of Jurassic Marrat sediment over Burgan structure. The study brings out the structural
features which are in sharp contrast to the earlier subsurface picture. Three sets of fault divide the
main Burgan structure into seven different blocks. Earlier drilling activities are found to be confined to
four blocks leaving other three blocks as totally untested and unexplored. Petrophysical analysis
identified two sections in Middle Marrat as hydrocarbon bearing. The upper section was the better
prospect and was tested in five out of six wells drilled earlier, but none of the well threw any light on
oil water contact (OWC). The reservoir engineering data supplemented with petrophysics and structural
synthesis marks three probable OWCs. A section in the lower part of Middle Marrat, approximately 250
ft below the deepest inferred OWC was tested in one well and found oil bearing. The well was found to
be drilled 150 ft down the structure and as a result the potential of this section could not be
ascertained properly from previous exploratory efforts. The presence of equally prospective equivalent
sedimentary section in other drilled wells enhances the Middle Marrat prospect. Sequence Stratigraphic
analysis identifies the hydrocarbon bearing zones as a part of Highstand Systems Tract that continues
laterally towards north in the Magwa field. The present study has demonstrated the necessity of reassessment
of hydrocarbon prospect for partially explored areas by continuous revision incorporating
the latest data sets, experiences, concepts and technological advancements.
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Calcareous Nannofossils from Middle to Upper Jurassic Sediments of North Kuwait Onshore
By Adi P. KadarBiostratigraphic analysis of Jurassic nannofossil assemblages were performed on a total 188 core
samples, collected every 4 feet interval, from MU-A, MU-C and RA-A wells, North Kuwait Onshore.
Ninety one samples are from MU-A well represent the Middle Marrat, upper Dhruma, Sargelu, Najmah
and lower Jubaila formations, 61 samples from MU-C correspond to the upper Dhruma, Sargelu,
Najmah and lower Jubaila formations. The other 36 samples are from RA-A well represent the upper
Dhruma, Sargelu and Najmah formations. The rocks consists of argillaceous limestone, grainstone,
packstone, bituminous packstone, wackstone dolomite, anhydrite, laminated bituminous calcareous
mudstone and calcareous shale
Samples from the Middle Marrat formation are barren, whereas most of the samples from other
formations contain nannofossils with the total abundance fluctuates from rare to abundance allowing
the identification of maximum flooding surface candidates. Preservation of the nannoflora is poor to
moderate. The diversity of nannofossil assemblages is relatively low, dominated by the most
dissolution resistant species Watznaueria barnesae.
An index species Cyclagelosphaera margerelii is present in the samples of upper Dhruma, Sargelu and
lower Jubaila sediments. The first occurrence (FO) of C. margerelii was reported to occur in Late
Bajocian. The laminated bituminous mudstone of Najmah formation contains common to abundant
nannofossils but most of the specimens are poorly preserved due to most of the inner part of the
coccolith are covered by oil stained. Strong dissolution resistant species Watznaueria barnesae and
high birefringence Watznaueria manivitae however still can be identified. The W. barnesae occurs
abundantly whereas W. manivitae presents sporadically. Nannofossil assemblage in the Jubaila shale is
characterized by the association of Watznaueria barnesae, Watznaueria britannica, Watznaueria
communis and Watznaueria manivitae. Those fossils’s record suggesting that the interval of the upper
Dhruma to Najmah formations falls within Middle Jurassic Upper Bajocian to Upper Jurassic Oxfordian
stages and the lower Jubaila shale is Upper Jurassic Kimmeridgian stage. There is a strong possibility
of stratigraphic discontinuity between the Najmah and Jubaila formations and the time gap is not great
as that suggested by some previous workers.
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Wavelet Transform Modulus Maxima Lines Analysis of Seismic Data for Delineating Reservoir Fluids
Authors Sid-Ali Ouadfeul and Leila AliouaneThe main goal of the proposed idea is to use the wavelet transform modulus maxima lines (WTMM)
method to delineate reservoir fluids. First a seismic seismogram is generated using the convolution of
the Ricker wavelet with the reflectivity function calculated from the measured sonic and density well logs data.
Obtained seismogram is analyzed by the WTMM in order to calculate the singularities spectrum based
on the direct Legendre transform of the spectrum of exponents.
Application of this technique at the real data of a borehole located in the Algerian Sahara is realized.
Thus Singularities spectrum is estimated at corresponding depth of the following fluid types: Gas, Oil,
Water, Gas-Oil and Oil-Water. Consequently, the obtained results allow taking a decision about the
fluid nature containing the reservoirs rocks pores.
We have applied the proposed technique at two other boreholes, obtained results demonstrate that the
wavelet transform modulus maxima lines technique can give more idea about hydrocarbon nature and
can enhance reservoir characterization.
Keywords: WTMM , seismic seismogram, well logs, singularities Spectrum, hydrocarbon nature.
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Origin and Occurrence of Illite Clay Mineral in Unayzah Sandstone Reservoirs in Central Saudi Arabia
Authors Syed R. Zaidi, Shouwen Shen, Ahmed A. Al-Shehry and Sudhir MehtaThe Unayzah (Late Permian) sandstone reservoirs in Central Saudi Arabia are important sources of
light sulfur-free crude oil and gas. However, the quality of the reservoirs can vary significantly based
on the amounts of clay minerals (especially of illite) and quartz cement present in the reservoirs. It has
also been observed that illite clay in amount as little as 2-3 wt% can cause precipitous decline in the
permeability and productivity of a reservoir. In order to evaluate the nature and amount of illite clay in
the Unayzah reservoirs, 69 core plugs from 25 wells spanning a depth (temperature) range of 6200 to
15500 feet were analyzed by XRD and ESEM. The results show that illite clay mineral occurs as
domains, aggregates, pore linings or infillings, coatings around stable grains, and bridges between
grains. Those illite clays can be classified into 5 types based on petrographic analysis: 1) matrix illite;
2) illuviated illite; 3) illite coating; 4) illite from illitization of kaolinite, 5) fibrous illite. Type 1, 2 and 3
are detrital in origin whereas type 4 and 5 are diagenetic. Among the 5 types of illite clays, the fibrous
illite is more important than others as it is a typically diagenetic in nature that grows into pore space
during burial diagenesis. The XRD and ESEM results indicate that up to 11 wt% diagenetic illite is
present in the cores. However, the data do not show any definite illite trend with depth. The data
suggest a large increase in the mount of fibrous illite between 14000 and 14500 ft, but then the trend
appears to reverse itself below 15000 ft, where the amount of illite is reduced by 50%. The study
revealed that diagenetic illite in Unayzah is mainly related to K-feldspar-kaolinite reaction. However, at
shallower depths it appears that the illitization reaction has not gone to completion, which results in
non-equilibrium assemblages of illite, kaolinite and K-feldspar. In the samples enriched with detrital
illite coatings, although kaolinite is converted to illite, there is still significant amount of K-feldspar
present in the rocks. This suggests that detrital clays may be blocking pore fluids from further reaction.
It may be possible to predict illite precipitation using a kinetic model based on Arrhenius approach.
This will lead to better correlations of illite cement with reduction in porosity and permeability and in
identifying potentially good quality reservoirs in areas yet to be drilled.
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3D Seismic AVO Data Established by the Wavelet Transform Modulus Maxima Lines to Characterize Reservoirs Heterogeneities in the 2d Domain
Authors Sid-Ali Ouadfeul and Leila AliouaneThe main goal of this paper is to establish reservoirs media heterogeneities by the wavelet transform
modulus maxima lines, first we gathered amplitude versus offsets AVO amplitudes at the top of the
reservoir and we calculate the 2D wavelet transform after we calculate its maxima and we estimate the
Holder exponent at each one, variation of this coefficient can give more information about the variation
of lithology and fluid nature at any direction. Application of this idea at synthetic 2D seismic model
shows that application on real seismic AVO data and its attributes can give more ideas about reservoirs
heterogeneities.
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4D Evolution of the Maradi Fault System, Oman
Authors Abdullah Al-Gahaffi and Ken McClayThe 4D evolution of multiphase strike-slip fault systems is generally poorly understood due to the
structural complexities that develop along their strike, and their steep fault and stratal dips that are
commonly poorly imaged in seismic surveys. The Maradi strike-slip fault system in Oman is an
important 60 km long dextral strike-slip fault system that is poorly exposed. In the subsurface it is
associated with a number of major hydrocarbon accumulations. In this paper the main elements of the
Maradi fault system have been simulated using scaled analogue modelling. Both wet clay and dry sand
analogue modelling experiments have been run to simulate deformation in a sedimentary cover
sequence above releasing and restraining step-overs in a basement strike-slip fault system. The
experiments were monitored by high-resolution time-lapse photography as well as digital laser
scanning and by PIV monitoring. In this way the surface topographies were monitored (laser scanning)
as well as detailed particle displacements and strain histories were measured (PIV monitoring). In the
releasing step-over experiments an elongate rhomboidal pull-apart graben was developed between the
offset Principal Displacement Zones (PDZs). Terraced oblique-slip extensional sidewall faults system
developed along the boundary of pull-apart basin. These sidewall faults changed kinematics along
strike, from oblique-slip near the PDZs to extensional slip in the middle of the structure. A cross-basin
fault system cut the flat bottom of the pull-apart basin and linked to the offset PDZs.
In the restraining step-over model a lozenge-shaped ‘pop-up structure’ developed. This was bounded
by two sidewall, oblique-contractional faults that were arcuate in shape and curved inwards toward the
main basement faults. At the end of the experiment, the retraining step-over offset PDZs were linked
by a sinistral trans ‘pop-up’ strike slip fault. Detailed displacement analyses and strain analyses are
presented to illustrate the progressive evolution of the structures. The results of the scaled analogue
modelling are compared to natural examples of strike-slip structures along the Maradi fault system in Oman.
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Late Campanian to Paleocene Planktic Foraminiferal Biozonation for Izeh, the Zagros Basin, Iran
Authors Bijan Beiranvand and Ebrahim Ghasemi NejadPlanktonic foraminiferal biostratigraphic study of the Gurpi Formation at Danial section in northeast
Izeh, the Zagros Basin, Iran, provides improved age resolution and good biostratigraphic control for
late Cretaceous to Paleocene strata. Late Cretaceous to Paleocene assemblages are open marine
faunas, and most of the standard tropical/subtropical planktonic foraminiferal zones are represented in
the section. The late Cretaceous proposed biostratigraphic zones include one Late Campanian zone,
Radotruncana calcarata, and five Maastrichtian zones, Globotruncanella havanensis, Globotruncana
aegyptiaca, Gansserina gansseri, Contusotruncana contusa and Abathomphalus mayaroensis (four
subzones; CF1, CF2, CF3, and CF4). On the other hand, eight Paleocene proposed biostratigraphic
zones and subzones are P0-P (P. eugubina-G. cretacea), P1a (P. eugubina), P1b (S.trilocolinoides), P1c
(G.compressa/P.inconstans), P2 (P. uncinata/P. praeangulata), P3a (M. angulata), P3b (M.
velascoensis), and P4a (P. pseudomenardii).
The turning point of the study is relatively complete succession across the Cretaceous-Tertiary (K/T)
transition which is presented by four subzones (R. fructicosa, P. hariaensis, P. palpebra, and P.
hantkeninoides) within the late Maastrichtian and eight zone and subzones within the Paleocene. The
K/T boundary is marked continuously by using the zones CF1 and P0-P at the latest part of the
Maastrichtian and early Danian respectively. This considerably higher resolution in biostratigraphic
zonation is a result of good foraminiferal preservation that may reflects larger, more rapid sea-level
changes, consistent with increasing ice volume during the time interval.
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A Synopsis from the CBM Prospect of the Jamalgonj Coal Field in Bangladesh
More LessThe supersonic present world is facing an intense energy demand which is increasing day by day. That
is why, the energy sector specialists have to put attention to various unconventional resources.Over
the last few decades, coal bed methane(CBM) has become a potential resource for many countries. For
a country like Bangladesh where the available resource is very insufficient to cope up with the need of
energy, CBM can be the flash of hope. The coal fields in Bangladesh fulfill all the pre-requisites for
economically viable CBM extraction among which Jamalgonj coal field has the most feasible criteria.
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An Integrated Approach Involving Biomarker and Isotope Data for Oil to Source Rock Correlation of Najmah and Sargelu Formations, North Kuwait
Authors Rita Andriany and Awatif Al-KhamissThe Najmah and Sargelu formations of Jurassic age are considered as potential source rocks in the
State of Kuwait. A suite of samples consisting of 9 rock extracts from 3 wells in Dhabi, Mutriba and
Raudhatain fields and 8 crude oil samples from 5 wells in Dhabi, Bahrah, Umm Niqa, NW Raudhatain
and West Minagish in northern Kuwait selected as representative data to study to establish oil-source
rocks relationships within Najmah and Sargelu formations in northern Kuwait.
A variety of geochemical parameters including normal alkanes, triterpanes (m/z 191), steranes (m/z
217), carbon isotopes, both saturated and aromatic, were employed as main component variables in
the statistical approach. The multivariate analysis methods - “Hierarchical Cluster Analysis (HCA)” and
“Principle Component Analysis (PCA)” have been adopted to make the process of evaluating correlation
data more objective as well as to speed it up. A series of analytical and interpretation processes were
conducted by measuring and selecting a number of accurate molecular (biomarker) and isotopic parameters.
The HCA technique employs 14 variables of geochemical data. These were grouped into 4 clusters of oil
and rocks samples. The relationship among clusters on the dendogram confirmed high responses of
similarity level. Bahrah and West Minagish crude oils were grouped into a common cluster at similarity
level of 94.53, while Umm Niqa and Raudhatain crude oils grouped together in a different cluster
having similarity level of 98.67. These Crude oil clusters and source rocks are connected by dendogram
at similarity level of 81.28 providing significant evidence that crude oils were generated from Jurassic source rocks.
Continuance approach in PCA technique (14 variables) divided all the samples into three main
quadrants. Crude oil samples from Bahrah, West Minagish, Umm Niqa and Raudhatain fall in quadrant-
III and slightly different in Principle Component from its precursor of source rocks in quadrant-I.
Alteration of the hydrocarbon fluids within reservoir are believed to be responsible for the variations of
geochemical characteristics within oil samples.
It is concluded that integrated statistical techniques that utilize selective suite of sensitive geochemical
variables in both biomarker and carbon isotope data are best suited for establishing oil-source rock
relationships, classifying oil in genetic families, and also addressing problems of reservoir continuity.
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Integration of Well Data Management Processes in a Diverse Data Environment
More LessData management is becoming increasingly critical as E&P companies are expanding their capabilities
to keep pace with world energy demands. As data management becomes more critical, it is also
becoming more difficult to manage and disseminate the significant increase in volumes and complexity
of the E&P data. In addition, in a large company like Saudi Aramco, managing data in a diverse data
environment with multiple data producers presents significant challenges related to data standards,
completeness, quality and timeliness. These data integrity and availability issues can quite often
undermine the confidence in the data and data management effort.
The integration of well data management processes is essential for ensuring data completeness, quality
and timeliness in a diverse data environment. It is also essential for ensuring accurate data can be
delivered to geoscientists in a timely manner. Included in the presentation is the methodology for the
integration of well data management processes and standardization at Saudi Aramco for enhancing the
quality, completeness and timeliness of geological and drilling engineering data in the corporate repositories.
The integration methodology to be presented begins with the understanding of the root causes of the
problems related to data quality, completeness and timeliness of geological and drilling engineering
data. The effective collaboration necessary between the stakeholders is essential. The integration
process is achieved through establishing data standards, a thorough understanding of the data flow,
the roles and responsibilities of the stakeholders, the data management requirements for data quality,
completeness and timeliness as well as the technology required. All these will be presented along with
the successes achieved through automation, productivity gains and benefits.
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Exploration Document Management
Authors John E. Robinson, Al Kok, Rami M. Jawad and Ali AlKhaterSince 2003 the Saudi ARAMCO Exploration Data Management Division has been working to support
Document Management in the Exploration Organization. The task of discovering and archiving
documents in today’s diverse and busy E&P environment is particularly challenging. To meet this
challenge, we developed a framework for document management, and deployed an integrated system
that provides Exploration staff with several methods for document archiving. The framework provides
the workflow and the system provides document archiving options ranging from a simple drag-and
drop application to customized web applications.
The framework requires that quality control (QC) is applied to metadata for each document to ensure
consistent and reliable search results. Web applications allow QC staff to view both the document and
its metadata, and correct the metadata when necessary. The applications are underlain by OracleTM
for recording the existence of documents (document discovery), and progress through the workflow.
The system provides simplified audit and activity reporting. DocumentumTM is used for document and
metadata archive and search. Ultimately, the system provides for document searches that differentiate
between large numbers of similar documents as rapidly as possible.
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Information Management Evolves!
More LessThe Digital Oilfield is now firmly established as a reality as the industry moves beyond initial pilot
implementations. Information Management is recognized as an important foundation for realizing the
value of the digital oilfield.
The Digital Oilfield is however driving significant growth in the amount of information being recorded
and a similar growing demand from the business for quality information to support and enable more
integrated technical applications and work flows. If not managed appropriately, this growth of
information will reduce the ability to quantify and manage the impact of information on the business,
increasingly leading to information bottlenecks in key business processes and technical work flows.
Supporting and enabling the digital oilfield will dictate a move away from the traditional information
management model of solely providing effective capture, management and provision of access to
information. It will require a much increased focus on leveraging the value of information assets
through a tighter integration of data, information, process, technologies and people and a move
towards greater automation of information management processes.
By learning from other industries and focusing on some key information management aspects,
Information Managers will be able to meet the challenge provided by the digital oilfield and transform
the way information is managed in the future. The proposed key aspects discussed include;
- Effective Management Processes - to build credibility and formalise business input
- Capability - develop the digital engineer and be the link between the business and IT
- Application of Lean techniques - reduce complexity, variation and low value work
- Data Quality Management - apply Six Sigma to reduce defects and drive automation
- Enabling Technologies - that deliver quality information in the context of the user
This approach will increase information management credibility, provide greater management clarity,
enhance the value of information assets, enable and automate process, foster cross functional
collaboration and provide business intelligence.
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The Main Results of Investigation of the Crystalline Basement of the Tatarstan
Authors Renat H. Muslimov and Irina N. PlotnikovaThe reservoirs of the basement have been studied, although the technology of studying the
Precambrian is yet to be improved.
Now, Tatarstan boasts of numerous wells drilled down to the crystalline basement, which indicate that
petroleum exploration at great depths does make sense. All previous evaluation of the crystalline
basement's prospects have been primarily based on the conventionally conducted drill-stem formation
tests (DSFT). However, oil and gas inflows from the crystalline basement of the Dnepr-Donetsk trough
showed that the sole use of DSFT results for evaluating the hydrocarbon potentials can be erroneous.
Moreover, the available drilling data from deep wells show that excessively high repressuring and the
use of loaded drilling mud can drive filtrate deeply into the reservoir. When the drilling rate is low, the
time interval between penetration and testing of prospective zones becomes quite long. If reservoir
pressure is equal to or is lower than hydrostatic, mud solution penetrates the reservoir and forms
seals, preventing formation fluid from flowing out during DSFT procedures.
Efficiency of hydrocarbon exploration within the Precambrian crystalline basement can be substantially
increased through the use of 1) a special drilling technology to minimize penetration of drilling mud
into the decompacted/fractured zones of the basement, 2) solutions that would minimize the influence
of drilling fluid on capacity and filtration properties of the reservoir, and 3) specific methods of inflow
stimulation and reservoir studies of the strata with various lithologic, petrographic and reservoir properties.
Seismic profiling and deep sounding revealed that the crystalline basement has a lamellar-and-scaly
structure. Main reflecting horizons have been found to occur below impermeable rocks at a depth of 5
to 7 km. Hydrocarbon fluids can be channeled into oil fields through the basement's fractures and
faults. Hydrocarbon relics from the fractured/brecciated zones indicate that the fluids could have been
driven from the lower horizons to the upper ones by the temperature field and the processes of
compression and decompression.
An obvious depth-related growth in amount of gas, a widening spectrum of methane's homologs,
greater amounts of methane's heavy ones, such as pentane and hexane, and the appearance of helium.
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Evaluating the Petrophysical Parameters of Carbonate Reservoirs, Offshore Abu Dhabi, Using Conventional Core Analysis from Different Scales of Core Samples
More LessA detailed Conventional Core Analysis (CCA) was performed on Jurassic carbonate reservoir samples
from a new field offshore Abu Dhabi. The conventional core analysis study included porosity and
permeability measurements on plugs samples, MICP, core description, and a reservoir characterization
study. Different type of conventional core data were collected, evaluated and incorporated in this
study. The study was performed in order to define depositional environment, facies, and the
distribution of reservoir rock types. This data was then used to define the flow units which are the
building block for a 3D geological model.
Limestone reservoir samples are highly complex and reservoir quality is controlled by the presence of
mud and the amount of diagenesis. In addition, dissolution of semi-stable biogenic components, such
as stromatoporoids, is creating vuggy porosity. This raises the question: Does a plug sample of the
reservoir reflect the petrophysical characteristics of the reservoir and its flow performance?
The CCA study was performed on 1.5 inch plugs (historic data) and 2.5 inch plugs (more recent data).
Sampling often avoids vuggy, fractured and highly cemented areas of the core. The studied field is
faulted and reservoir quality might be affected by late stage diagenesis. In addition, certain reservoir
facies, such as stromatoporoid build-ups exhibit large-scale vuggy porosity. So, plugs are often not the
best sampling technique to represent the reservoir in order to determine petrophysical characteristics
and ultimately the flow performance.
Whole core samples which are representing different lithofacies types were selected from 2 wells to
measure porosity & permeability and conduct CT scans. The whole core data will be used to generate a
relationship with plug-size data to allow upscaling the permeability to be consistent with the dynamic
well flow test data while maintaining the vertical contrast of permeability, which crucial in
characterizing the flow dynamics of stratified reservoir.
Comparing the petrophysical parameters using different scales of reservoir samples (plugs versus
whole core) might help to addressing the role of large scale features such as fractures and diagenesis
(vugs and its connectivity) on reservoir performance and reduce, therefore, the petrophysical
uncertainty in the reservoir models.
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Application of Artificial Neural Networks in Water Saturation Prediction in from Iranian Oil Field
Authors Mohammad Mardi and Mohammad K. GhasemalaskariIn this paper, Artificial Neural Networks (ANNs) has been implemented to calculate water saturation in
Gadvan formation in an Iranian oil field. Core data from 3 wells, (AZN01, AZN03 and AZN04), have
been used to train and test the Network. The procedure was to use wireline logs such as deep
resistivity log (Rt), density log (RHOB), sonic log (DT), gamma ray (GR) and porosity recorded from
cores to be used as input to ANNs and water saturation (Sw) measured in laboratory as target. Four
networks generated, and then the networks were trained with random 60% of input data and tested
with random 20% of data. To make sure of networks well performance, the remained 20% of data
were used to validate the network’s ability of determining an acceptable relationship between inputs
and target (core Sw). A network with the least prediction error was selected to be used as our network
of interest. This network showed the correlation coefficient of 0.979 between the ANNs-predicted water
saturation (output) and target (core-derived Sw) data. Using this network, water saturation of Gadvan
formation was predicted. ANNs-predicted water saturation revealed lower values of water saturation in
the lower part of Gadvan formation in comparison with water saturation computed using Archie’s relationship.
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Management of Information in Preservation Production and Developing Underground Reservoirs by Using Real Time Technology in EOR
By Iman OrakiIndustrial and technological progresses over the past 20 years have provided the data transmission
methods with more reliability, accuracy and rate. Today the Production and Exploration units are using
specific programmable software to know exactly what is going to happen in Real Time underground.
This tools that work mainly by using downhole sensitive measuring sensors can effectively report to
surface unit of what PVT and other desirable parameters are in a real time even when implementing
EOR plants that seemed impossible last decade and that would eventually bring about increasing of
recovery factor at the time of taking critical and financial decisions. This paper deals whit the
relationships between the quality of underground data and Reservoir performance by regarding a pilot
which has been made in our research program and discussing the ideal measuring sensors and the
technical decision making procedure that resulted in a high recovery factor for this pilot.
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Study of Open Fractures in a Permeable Rock Matrix Using a Two Phase Numerical Flow Model and Its Effect from Production
Authors Iman Oraki and Bahram HabibniaThe presence of open fractures in a permeable matrix generates highly heterogeneous permeability
fields which have a large impact on the relative flow of oil and water. This results in highly variable
velocities which generates complex oil-water fronts and strongly heterogeneous water saturation fields.
Such conditions make prediction of reservoir behaviour difficult and efficient recovery problematic. One
of the best known effects is early water breakthrough at wells due to the preferential flow of water
along a connected fracture system. In the present paper the effects of open fractures on the flow of oil
and water are investigated using a two phase numerical flow model with some simple and simulated
and natural fractures patterns. The results are used to investigate the nature of ‘pseudo
curves’ (relative permeability curves for volumes of heterogeneous rock) in the case of fractured permeable rocks.
And we will get a important result that increasing fracture aperture beyond a critical value does not
significantly alter the pseudo relative permeability curves.
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From Outcrops to Reservoir, a Comprehensive Approach to Reservoir Characterization
Authors Ailin Jia, Dongbo He, Chengye Jia and Dewei MengGeneral characteristics of Low Permian clastic reservoirs in Ordos basin Northwest China have been
reviewed by former researchers. The Shihezi Group sandstones normally have quartz content between
80%-90%, up to 8%-12% lithic, While Shanxi Group have quartz content between 65%-90%,
relatively high lithic (He et al. 2003). Petrophysical properties such as permeability and porosity have
been investigated (Nan et al. 2005). The Shihezi Group sandstones have mean permeability of 9.1%
and mean porosity of 0.98mD. The Shanxi Group sandstones have mean permeability of 6.55% and
mean porosity of 10.22mD. Diagenesis phases including compaction, siliceous cementation and genesis
of net pay have been argued and compaction is concluded as the main cause of low permeability (He et
al. 2004, Nan et al. 2005). While studies concentrated on reservoir equivalent outcrops and the fluvial
sedimentary system especially in aspect of channel geometry have not proposed yet.
This paper proposes a comprehensive research compromising outcrop study with available well data
(sand thickness variation, stacking pattern, fluid identification, petrophysical property) derived from
well logging and core analysis, which provide thorough and detailed information for reservoir characterization.
Reservoir equivalent lower Permian Shanxi (P1s) and Shihezi (P1x) outcrop exposures in the SE and
NW of the Ordos basin, Northwest China have been studied. Qualitative data such as bedform
geometry, bedset thickness, lateral continuity and net to gross are used to guide the reservoir
characterization for braided & meandering channel sedimentology. Field surveys provide direct
information which help to micro-facies diagnose and field measurements including width, thickness
provide detailed data to channels geometry. Eletrofacies zonation through well logging extrapolation
helps to diagnose plain distribution of multi-storey channels and single-storey channels. Thus,
conceptual and detailed fluvial depositional models are established.
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Geochemical Logging: A Middle East Case Study of a New Logging Tool
While the traditional “Triple Combo” measurements remain a formation evaluation mainstay, in more
complex environments many assumptions are made during the interpretation work. Lithology is
interpreted from density, Pe, GR and neutron logs assisted by other sources of information such as
cuttings and core analysis, however there are many limitations. Interpretation models can be refined
with direct knowledge of elemental concentrations which are used to solve for complex mineralogy. For
example, in a carbonate reservoir, a direct reading of Magnesium weight percentage provides a
valuable measurement of Dolomite volume. Similarly, Sulphur fractional information provides
knowledge of Anhydrite distribution.
Geochemical logging provides a direct measurement of elemental concentrations and compliments the
typical density, Pe, GR and neutron logs. The latest generation logging tool resolves a wide-range of
elements including the traditionally more difficult-to-measure Magnesium and Aluminium weight
fractions. In this paper we introduce a new Geochemical Elemental Tool with examples taken from both
Siliciclastic and Carbonate Middle-East reservoirs. The important Permian age Siliciclastic reservoir
studied is an eolian dune and interdune facies, which contains varying volumes of diagenetic anhydrite
cement, feldspar and Illite. The elemental concentration of Silicon, Potassium, Sulphur and Aluminium
are inputs used to solve for these minerals in the lithology model. We demonstrate the accuracy of the
elemental weight fraction from the logging tool results by comparison to ICP & XRD measurements
made from core. In addition results are presented of the mineralogy interpretation from the case study wells.
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Understanding Reservoir Heterogeneities of Upper Jurassic Carbonate Reservoirs and Its Critical Impact from Field Development, Offshore Abu Dhabi
Authors Christoph T. Lehmann, Khalil I. Hosani and Mohamed Sayed IbrahemA detailed reservoir characterization study was performed offshore Abu Dhabi in order to capture the
key uncertainties for future field development. This study was performed on the Arab reservoirs and
included detailed core description, sequence stratigraphic interpretation, conventional core analysis,
and a rock typing study in an attempt to understand reservoir heterogeneities across the field and its
impact on the field development plan which include a gas injection as the major development scheme.
The Arab Formation in Abu Dhabi is subdivided into 4 reservoir intervals (Arab A, B, C, and D) which
coincide with third-order sequences. The fourth-order sequence stratigraphic framework represents the
basis for the reservoir layering scheme. Reservoir facies distribution is controlled by fourth-order
sequences superimposed on a large-scale shoaling upward trend. The Transgressive Systems Tract
(TST) of the fourth-order sequences are dominated by off-ramp to fore-shoal deposit while Highstand
Systems Tract (HST) are composed of progradational, peloidal shoal deposits. The reservoir rocks are
limestones and reservoir quality is primarily controlled by facies (grain-dominated versus muddominated
facies) and secondarily by diagenesis.
The Arab, A, B, and C are composed of mixed carbonates and evaporites. The carbonate reservoirs
were deposited in sabkha/shallow lagoonal environment. The TST of the fourth-order sequences is
dominated by shoal to back shoal deposits, while the HST are controlled by restricted shallow subtidal,
intertidal and evaporate deposits. These facies are arranged in meter-scale peritidal and sabkha cycles.
The reservoir is predominantly dolomite with the exception of the Arab C, which includes significant
amount of limestones, which can vary between individual wells. Reservoir quality is strongly controlled
by diagenetic processes such as dolomitization and anhydrite cementation.
This work has a major impact on the planning of the development wells and the type of gas injectors.
The well distribution and completion has been changed to capture the heterogeneities of the reservoir
and may lead to apply smart completion in order to achieve high sweep efficiency. In addition the
heterogeneities also control the gas injection scheme for different reservoirs to avoid the early gas
breakthrough. Therefore, understanding the complex architecture of the Arab reservoirs has a major
impact on the development of these reservoirs.
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Unraveling Complex Velocity Anomalies -A Case Study in Bahrah Area, Kuwait
The role of velocities in understanding seismic data is very significant. Layers or features with a high
seismic velocity surrounded by rocks with a lower seismic velocity causes in the time domain what
appears to be a structural high beneath it. After such features are correctly converted from time to
depth, the apparent structural high is generally reduced in magnitude or sometimes turned out to be
flat. Understanding of depositional environment, tectonic movements and lithology is very important in
converting the seismic section from time to depth domain. One such example is the Bahrah area which
situated on the Kuwait onshore and lies on the Northern plunging anticline of Kuwait arch (fig.1). Very
sharp lateral velocity variations coupled with strong vertical velocity variations extending over very
short intervals caused depth conversion that much more difficult in this area.
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Data Governance Implementation through QC2 Data Center Initiative
Authors Rodziah Daud, Peter Attewell, Omar Akbar and Khairill Affandi Ahmad ShaariSaudi Aramco implements data governance in exploration data management through a workflow
driven, Web-based interface environment, called QC2 (QC Squared) Data Center Initiative. This
implementation ensures that exploration data is structurally managed in accordance with governance
policies, standards, business rules and procedures and also ensures that the process is made
transparent to data proponents and stakeholders.
Exploration data governance policy can be broadly characterized as a) safeguarding the data, and b)
quality assurance of the data. We describe how the QC2 Data Center Initiative enforces solid data flow
for each data type, and by cross reference with the data proponent ensures compliance with these
policies. Specifically the implementation consists of five (5) major components: workflow governance,
QC governance, architecture governance, security and access control governance and reporting governance.
Workflow governance from producer to user provides continuous authoritative data management over
the data life cycle. Data stewardship and solid controls of governance processes are embedded in the
workflow governance.
QC governance enforces consistency and accuracy of data at key stages of the workflow by identifying
and eliminating the root causes of data error through collaboration with data stakeholders. The QC2
Data Center Model is driven by data validation rules (QC-1, QC-2 and QC-3) to ensure good data is
used and bad data is identified.
Architecture governance controls and manages the environment of master data and the exchanges
between master data repositories and applications.
Security and access control governance dictates that role-based data access security is enforced for all
data types. Reporting governance maintains standards of audit reporting and provides transparency
through fully automated quality reporting on demand at every part of the data flow.
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Through Tubing Pulsed Neutron Log in a Heavy Oil Carbonate Reservoir for Time Lapse Monitoring
The most common log type used for cased-hole saturation analysis is Pulsed Neutron Capture log. In
high salinity reservoirs the Sigma log is proved useful for cased-hole saturation monitoring. In low and
mixed salinity reservoirs the C/O log is used as the primary cased-hole saturation monitoring tool.
However the C/O application is limited due to the statistical nature and shallow depth of investigation
of the measurement and the interpretation limitation requiring tool characterization. In this paper we
present a case where C/O logs provided meaningful results in a shallow, high porosity, carbonate,
heavy-oil reservoir undergoing steam injection. The time lapse C/O logs were acquired through tubing
in four observation wells.
The RST* tool, used in this study, measures C/O ratio and uses characterization database to derive
saturation. The measurement is sensitive to borehole and completion type besides saturation. In this
case, although the tool was run through tubing, it was found that the data required very minor offset
to fit with the points representing non tubing characterized tool response. The water filled borehole and
zone of known saturation served as the controlling factors to determine the amount of C/O offset.
The tool also measures the neutron capture spectral data, which was used to derive lithology. The
open-hole suite of logs in the studied wells included ECS* (Elemental Capture Spectroscopy) data
providing lithology. The good match between the cased-hole, through tubing and the open-hole
lithology provided direct indication that the data was comprised of formation signal and increased confidence.
The tool was run through 3 inch tubing in four temperature observation wells completed with 7 inch
casing. The field is subject to steam flood and the logs were run as baseline logs for future steam flood
monitoring. The three passes of C/O log provided data with good statistics in this reservoir. Although
the data was acquired with the objective of time lapse analysis, it provided water saturation within
acceptable uncertainty. The variation between open-hole versus cased-hole saturation was believed to
be due to varying oil gravity not accounted for in case of C/O interpretation and the varying rock
texture, wettability and formation water salinity not accounted for in the resistivity based
interpretation. Due to very low formation water salinity, we believe the possibility that C/O based
results could be more accurate in some zones.
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Sea Level Changes and Depositional Environments of the Late Cretaceous to Paleocene Sedimentary Succession, Izeh, Zagros Basin, Iran
More LessIntegration of micro-biostratigraphy and palynofacies analysis of the Gurpi Formation at the Danial
section, northeast Izeh, Zagros basin, Iran, provide improved age resolution and information on the
reconstruction of depositional environments. The section is a key succession to investigate the late
Cretaceous to Paleocene sea level history. Relatively deep marine dark bluish gray calcareous shale,
marl and argillaceous lime mudstone of the Gurpi Formation, which marks the late Cretaceous -
Paleocene sequence exposed the interval between the Ilam Formation of Santonian age and the
overlying Pabdeh Formation of late Paleocene-Oligocene age. The age of the Gurpi Formation in the
section is estimated to span from late Campanian (Radotruncana calcarata planktonic foraminifera
biozone) to late Paleocene (Globanomalina pseudomenardii planktonic foraminifera zone). The K/T
boundary within the upper part of the formation marks continuously by using the zones CF1 (P.
hantkeninoides; Latest Maastrichtiaqn, 65.3-65Ma) and P0-P (P. eugubina-G. cretacea; base of Danian
age, 65-64.97Ma) respectively.
Results from a sea-level change analysis, based on palynofacies analysis and additional proxies
(percent planktic foraminifera, planktic foraminifera morphogroups, total organic carbon content
(TOC), and geophysical GR log) show a general deepening trend for the investigated sections. As a
result, the sedimentary succession reflects deposition in outer neritic environment and no any tectonic
activities during the Maastrichtian-Paleocene in the basin but more rapid sea-level changes, consistent
with increasing ice volume during the time interval in the world. The area was located near the
palaeoequator and provides tropical to subtropical paleoenvironmental conditions. Finally, six Type-III
sequences was distinguished in the section during the study. Microfacieous analysis of the marls and
argillaceous lime mudstones (Emam Hassan Member) at the middle part of the sediment succession
provides three main microfacies corresponds to two , tree, and four facies belts of Flugle, 2004 that
show relatively deep marine environment at the end of continental slope during sea-level highstand in
outer to inner neritic environments. On the other hand, fossiliferous marly shales and marls at the
lower and upper parts of the succession during sea-level rising characterized by dysaerobic or low
oxygen conditions in outer neritic environments.
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Comparison of Patterns of Permeability Anisotropy Distributions in Jurassic and Cretaceous Carbonate Reservoirs
Authors Ali Sahin and Abdulwahab Z. AliPermeability measurements in most reservoirs display strong dependency on the direction. Therefore,
it is essential to determine permeability variations in different directions within the reservoirs. Such
variation is generally incorporated into engineering applications as the square root of the ratio of the
horizontal to vertical permeability, a parameter known as the anisotropy ratio. This ratio may vary
from one zone to another and even from one layer to another in the reservoir sequence. The pattern of
variation of this ratio provides valuable information about flow behavior within the reservoir.
Based on the whole core data from several vertical wells, permeability anisotropy distributions in three
carbonate reservoirs, including an Upper Jurassic, and two Cretaceous (Early and Middle) reservoirs
from the Arabian Gulf region, were determined. The open-hole log data and the whole core
permeability measurements were plotted together with the calculated anisotropy ratio values to aid
interpretation. Such plots were generated for each well from each reservoir providing basis for the
comparison of anisotropy ratios with the corresponding porosity and permeability values.
The results revealed that the anisotropy ratio distributions closely follow the corresponding
distributions of permeability. The values of anisotropy ratio vary considerably from reservoir to
reservoir. Upper Jurassic reservoir revealed relatively higher values of anisotropy ratios as compared
with Cretaceous reservoirs. Considerable variations have also been observed within each reservoir. In
Upper Jurassic reservoir, some correlation has been observed between anisotropy ratios and porosity
values, indicating close relationship between anisotropy ratios and lithology. In Cretaceous reservoirs,
on the other hand, no obvious relationship between anisotropy ratios and lithology has been depicted.
In all cases, it has also been observed that very high values of the anisotropy ratios are generally due
to unusually low vertical permeability measurements recorded in compact and undisturbed muddy
intervals acting as the barriers to the vertical flow.
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Multiple Incision Levels in Al Shaheen Field Offshore Qatar
Recent acquisition of a large high resolution 3D seismic data over Al Shaheen field offshore Qatar
revealed the presence of several levels of channel incisions, which provide important information about
the geological evolution of this part of the Arabian Plate. The acquisition parameters and subsequent
processing flow were selected for best resolution of shallow targets at some 2000-4000ft. Data quality
was hampered by the shallow water and present-day reefs, small-scale erosional features and
interchanging lithology in the overburden. Ongoing efforts to improve data quality are designed to
further eliminate multiples and to resolve imaging problems caused by the shallow erosional and deep
collapse features and gas chimneys. Further data processing notwithstanding, the analysis of the data
has already allowed us to recognise a number of significant stratigraphic features.
There are four levels of channels, starting as shallow as 100-160ms at Dammam level. Second, the
Umm3 channelized drainage features with steep edges are recognised as one of the major causes of
energy scattering which deteriorates imaging and overall data quality. These are short erosional
channel-like features oriented radially around a topographic paleo-low. Third, top Halul channels which
are also causing significant imaging problems due to a large velocity contrast between the infill and the
surrounding sediments. These channels are long, relatively straight, and have dimensions that allow
them to be easily recognised both on stratigraphic time slices as well as on seismic cross-sections.
Fourth, incision at the top of the Shuaiba platform during sub-areal exposure, which has previously
been established and described, has been confirmed for the whole block. Several levels and dimensions
of channels are evident, with smaller channel systems towards the highest point of Shuaiba platform in
the North and a larger meandering channel system in the South.
Each of these channel levels requires different tools and attributes for their delineation. The geological
significance of these incised channel levels for the Arabian Plate geological evolution is discussed.
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Impact of Accurate Velocities from Signal Fidelity Enhancement for Reliable Seismic Interpretation - Example from Kuwait
Authors Wael A. Zahran, Riyanto Purbokusumo, Nawaf Al-Muatairi and Hamed M. HameedIn September 2008 Kuwait Oil Company (K.S.C.) acquired a 3D seismic survey across Arifjan area, S-E
Kuwait. The primary objective of this survey is to image the Mid-Marrat Jurassic reservoir through
maximizing the signal fidelity and the vertical resolution.
Following the processing of the seismic data, it was clearly recognized that the velocity
analysis/picking, interpretation and velocity field modeling are the most crucial steps for enhancing the
temporal resolution, needless, to say very challenging to achieve.
Accurate velocities have a great impact on flatting the gathers and consequently enhancing the
frequency contents; the subtle changes in both RMS and interval velocities have shown a significant
effect on some of the main processing stages such as residual statics calculation, de-multiple
techniques, imaging and stacking, a special care of handling the velocity analysis and picking was considered.
In addition to the effective data preconditioning prior to the velocity analysis, different powerful
velocity analysis tools were tested to identify the most suitable ones to use. Important processing
steps were applied prior to velocity analysis to precondition the data for such as noise attenuation,
multiple removal and inner trace mute.
Several rounds of interactive velocity picking have been run to fine tune the stacking velocities in order
to achieve the best stacking response. Continuity and resolution of seismic horizons apparent
anisotropic and high order moveout were tested. Finally the Spatial Continuous Velocity Analysis
(SCVA) has been applied to achieve a much higher accuracy in the picking of stacking velocities. These
refined velocities were then passed through a velocity model builder (VMB) to stack the final product
ready for interpretation.
This case study will present the different velocity analysis techniques applied and will focus on the
results achieved using these techniques and its impact on improving the seismic interpretation.
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Fibre Optic Permanent Monitoring System - Towards The Optical Oil Field
Authors Jan Langhammer, Morten Eriksrud and Hilde NakstadPermanent seismic installations at the sea-floor have emerged as a potential tool for oil companies in
their work to actively monitor oil/gas flows and injection processes in order to increase hydrocarbon
recovery and optimize production. The advantage of fibre optic over electric sensors is that the fibre
optic sensor technology is completely passive at the wet-end, i.e. no short circuits will happen, longer
life-time of components, high sensitivity, high dynamic range, less intrinsic noise, no corrosion of
sensing components, fewer parts and potentially cheaper complete receiver systems. Fibre optic multicomponent
ocean-bottom receiver systems for 4D applications can now be produced and installed
successfully at locations where the oil companies would like exploit the life-of-field seismic concept.
The analysis of the data from the pilot tests confirms the systems high degree of vector fidelity, high
signal-to-noise ratio, very good ground-station coupling, reliability and excellent response in general to
wave modes in connection with ocean-bottom seismic. Fibre optic based permanent seismic monitoring
systems represent a great opportunity for the field engineers to optimize production and increase the
hydrocarbon recovery rate from existing fields.
We are advocating optical sensing technology to be an important part of the tool box for the oil
companies in their work to implement the instrumented oil field in a cost efficient way. The “optical oil
field” should represent the next step in technology in connection with reservoir monitoring in order to
increase the hydrocarbon recovery rate.
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Mapping Regional Faults with Geological, Seismic and Potential Field Data - A Case Study from Kuwait
The state of Kuwait is endowed with commercial hydrocarbon accumulations at Triassic, Jurassic,
Cretaceous and Tertiary levels. These accumulations are dominantly structural entrapments affected by
multiple sets of faults. The faults not only play a dominant role in structure formation but also control
flow characteristics of the tight reservoirs by fracturing. In view of the above, a regional fault mapping
initiative has been taken up.
In a synergistic approach gravity, magnetic, 2D and 3D seismic, image log and core data has been
analysed to map the regional fault framework and to evaluate its role in hydrocarbon entrapment.
Innovative visualization techniques such as 3D curvature, spectral decomposition and semblance
volume are employed for enhancing the subtle fault expressions. These faults mapped in the areas of
3D coverage are linked to the regional framework brought out by the 2D and potential field data.
The structural framework of Kuwait is broadly defined by two major elements. The N-S trending Kuwait
Arch is the most conspicuous feature which encompasses Burgan, Bahrah, Sabiriyah and Umm-Niqa
structures. The NW-SE trending West Kuwait High encompasses Umm-Gudair, Minagish, Kahlulah, Kra
Al-Maru and Mutriba structures. These dominant trends are offset by dominantly E-W, ENE-WSW and
NE-SW trending cross faults. These faults and associated structures evolved at different times and as a
result of different causative mechanisms. The Kuwait Arch represents basement-involved deformation
with multiple phases of reactivation while West Kuwait High is located on gravity magnetic lows,
indicate diapirism as the causative mechanism for structuration. The study established the usefulness
of regional fault system mapping in deciphering the tectonic history and controls on hydrocarbon
entrapment in Kuwait.
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Integrated Reservoir Characterization in from Unconventional, Low-Permeability Carbonate Reservoir, Abu Dhabi, United Arab Emirates
As the era of 'easy’ oil draws to a close, the energy sector is shifting focus towards previously
overlooked, unconventional, 'challenged' reservoirs. Unconventional reservoirs will play a vital role in
filling the void as existing, conventional assets move into maturity and irreversible decline. In Abu
Dhabi, low permeability carbonate reservoirs contain enormous volumes of hydrocarbon resource with
substantial potential to replace a large wedge of the current production steam lost to standard reservoir decline.
Reservoir characterization in these assets is a challenge as key static and dynamic information can be
difficult to collect and difficult to interpret using traditional methods stand alone. The key to robust
reservoir characterization relies on the integration and reconciliation of various forms of static and
dynamic data. A comprehensive, mid-appraisal characterization of reservoir quality, vertical
communication and lateral compartmentalization of a multi-billion barrel asset in Abu Dhabi was
completed using seismic, wireline, core, pressure, fluid property and capillary pressure information.
This presentation will focus on the methodology and results of this study and illustrate the gains in
basic reservoir understanding, the identification of critical information gaps to be filled prior to
generating a robust full-field development plan for this reservoir, and how these identified gaps are
used to drive future appraisal efforts.
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Sedimentology and Diagenetic History with Reference to Reservoir Quality, Triassic Lower Jilh (Kra Al Maru Reservoir), Kuwait
More LessThe name Kra Al Maru has been assigned to the additional unit at the lowermost part of the Middle
Triassic Jilh Formation in Mutriba and Kra Al-Maru area in western Kuwait. Stratigraphically the interval
corresponds to the Jilh C Member of Jilh Formation, and it is divisible into a lower (KM-B) and an upper
(KM-A) unit. Microfacies comprises anhydrite, dolomudstone, dolowackestone, argillaceous dolostone
and dolomitic shales with minor dolopackstone, dolograinstone, lime mudstone, lime wackestone.
Carbonaceous matter and terrigenous material is present at places. Anhydrite is present as early
nodules and crystals, as well as late cement and vug fillings. Facies associations of both units are
bioturbated, highly variable with common organic matters. The distinguishing feature of the lower unit
(KM-B) is having less anhydrite than the upper unit (KM-A). The lower unit was deposited in intertidal
to subtidal and lagoonal environments, as a shallowing upward sequence that grade upward to algal
laminated wackestone and anhydrite. The presence of few sub-aerial exposure surfaces indicate
dissolution that might have developed at the end of cycle and are indicative of slightly humid
conditions. The upper unit was deposited in an intertidal to supratidal, Sabkha environments under arid
climate. Diagenetic events include compaction, dolomitization, and replacement by anhydrite,
fracturing and stylolization. Primary porosities were reduced by compaction, overdolomitisation and
late stage cementation. Both cemented and uncemented fractures are observed in the core and
microfractures are seen in core plugs and have led to increased fracture porosity and permeability. The
Lower unit is ranked and pursued as new prospective units within the Jilh Formation.
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Inverted Basins and Deepest Discovered Oil in the Western Desert of Egypt
More LessOil production decline for the Gulf of Suez, Egypt, is faced by increasing production from the western desert.
CreateceousJurassic inverted Basins play the major role in the recent discoveries in the Western desert.
The recent deepest oil discovered by IPR group at depth of 16000 feet is one of these inverted basins.
It shows excellent reservoir parameters and very good oil column.
Excellent 3D seismic data quality helped to infer an accurate structure model and calibration to the
regional structural framework of the area (Syrian Arc system) are the main contributors lead to the discovery.
This paper is a case history for true oil finder team and aggressive drilling company.
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The Surface-Piercing Salt Domes in the Ghaba Salt Basin (Oman): A Comparison to the Intra-Salt Hydrocarbon Play of the Ara Group
In the South Oman Salt Basin the Ara carbonates form an extensively cored, deeply buried intra-salt
hydrocarbon play. Six surface-piercing salt domes in the Ghaba Salt Basin (North Oman) provide the
only outcrop equivalents for carbonates and evaporites of the Ediacaran-Early Cambrian Ara Group
(uppermost Huqf Supergroup). Based on fieldwork, satellite imaging and isotope analysis it is
concluded that most of the carbonate bodies (so-called stringers) in the Ghaba salt domes are time
equivalent to the stratigraphically uppermost stringer intervals in the South Oman Salt Basin (A5-A6).
Maturity analyses demonstrate that the carbonate stringers in the salt domes were transported with
the rising Ara salt from burial depths of [|#24#|] 6 to 10 km to the surface. Petrographic and stable
isotope data show that their diagenetic evolution during shallow and deep burial was very similar to the
Ara carbonate stringer play in the SOSB. However, during the retrograde pathway of salt diapir
evolution, the carbonate stringers were exposed to strong deformation in the diapir stem and
diagenetic alterations related to dedolomitisation. As the salt domes contain facies that are in all
aspects identical to the deeply buried Ara play in the South Oman Salt Basin, this study provides
substantial additional information for hydrocarbon exploration in South Oman. In addition, our work
has implications for the hydrocarbon prospectivity of the Ghaba Salt Basin and possibly of other
Ediacaran-Early Cambrian evaporite basins in the Middle East such as for the time-equivalent ‘Hormuz’
salt basins.
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3D Imaging of Residual Saturation in Carbonates; Exploring the Role of Wettability, Rate and Saturation State
Authors Mark Knackstedt, Tim Senden, Munish Kumar and Adrian SheppardAt the conclusion of flooding in an oil- or gas-bearing carbonate reservoir, a significant fraction of the
original hydrocarbon in place remains in the swept region as trapped residual phase. In addition to the
amount of trapped phase, its microscopic distribution within the pore space of a reservoir rock is
important to gain a better understanding of recovery mechanisms and for the design and
implementation of improved or enhanced recovery processes. Despite the importance of the pore scale
structure and distribution of residual oil, little quantitative information is currently available. In this
study the residual saturation is directly visualized in core material at the pore scale in three
dimensions. In particular, we utilize a new technique for imaging the pore-scale distribution of fluids in
reservoir cores in 3D; the method allows the same reservoir core material to be imaged under different
wettability conditions, saturation states and flooding rates. A range of examples are given for
waterflooding of reservoir carbonates. We observe a strong dependence of the residual hydrocarbon
saturation and distribution on rate and wettability.
The detailed structure of the residual trapped phase is described. This information is correlated to pore
structural information from the 3D image data (pore geometry, connectivity), mineralogy and rock
type as well as to wettability and flow conditions. These results provide an important platform for the
testing, correlation and calibration of pore scale rock typing to multiphase flow properties. This detailed
pore scale information of the residual oil saturation is crucial to the design and implementation of
improved recovery processes and can be related to conditions required for mobilization of residual oil.
Oil recovery mechanisms are directly tested and the differences in the habitat of the residual fluids
under different conditions are directly quantified. The role of wettability is particularly studied. Crude
oil drainage of simpler analogue materials are considered where flat mineral substrate have been
incorporated. After aging and cleaning the planar slabs are removed and analyzed by surface sensitive
techniques, in particular interferometric profilometry, to characterize the distribution of oil-wet and
water-wet sub-regions. The results give some insight into the wettability conditions associated with waterflooding.
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Depth Velocity Model Optimization Using Beam Migration in a Mediterranean Field Offshore Egypt
Authors Ahmed El Bassiony, Bertrand Caselitz, Vira Matsourak and Charles ZeltserPGS opted to use PGS Beam migration for the depth velocity model building in a Mediterranean field
offshore Egypt. The multi-pathing capabilities of PGS Beam migration allow for improved images in
proximity to high velocity contrasts or complex geologic regions, while the rapid turn-around time of
migrations permits easy confirmation of models. Also the removal of random noise during the dip
scanning process provides a good signal to noise gather images suitable for estimating the move-out
errors required for tomography updates. These are the characteristics that makes the Beam migration
a suitable algorithm to build complex velocity models. In our case study, up to 13 iterations were
computed within 12 weeks. During each iteration, most of the time was spent to interpret the results
and no time was lost waiting for the migration to complete. The full fold volume of 200 sq.km. was
migrated in less than one hour enabling the interpretation of more than one possible velocity model.
Once the final velocity model was obtained, the full suite of PSDM algorithms (Beam, Kirchhoff, one
way & two way wave equation) could be applied to achieve the best possible image.
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“Intra-Al Bashair Boundary” (Late Cambrian, Oman): is it a Maximum Flooding Surface or a Sequence Boundary?
Authors Salmeen A. Al Marjibi, Colin P. North and Joyce E. NeilsonThe Late Cambrian age Al Bashair Member of the Andam Formation (Haima Supergroup) of the northcentral
part of Oman consists mainly of thin (< 0.5m) layers of sandstone, siltstone and mudstone that
are occasionally interbedded with various types of thin (<1m) carbonate layers. Carbonate rocks are
absent in the upper half of the succession of the Al Bashair Member and the interval becomes much
muddier than the underlying unit. These features allow the division of the Al Bashair Member
stratigraphically into two units, the Lower Unit and the Upper Unit.
Previously it has been thought the mudstone intervals in the Al Bashair succession were deposited in a
deeper water setting than the carbonate and sandstone strata. Consequently, the increased proportion
of this mudstone in the Upper Unit of the Al Bashair Member was interpreted as representing a
significant relative sea level rise. Thus the contact between the Lower and Upper Units, the “Intra-Al
Bashair Boundary”, was thought to represent a maximum flooding surface.
However, recent detailed study of the succession at outcrop shows that these mudstone intervals are
always associated with terrestrial sedimentary structures including pedogenic slickensides, blocky ped
structure and occasionally desiccation mudcracks, indicating they were subaerially exposed for
sufficient time for soils to form soon after their deposition. This indicates that the succession of the
Upper Unit of the Al Bashair Member generally was deposited in an overall shallower water setting than
the underlying unit, and the “Intra-Al Bashair Boundary” cannot be interpreted as a maximum flooding
surface. Alternative interpretations of the nature of this boundary are considered, including the
possibility that it represents a sequence boundary. What is certain is that the “Intra-Al Bashair
Boundary” should not be correlated regionally with other maximum flooding surfaces across the Arabian Plate.
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Heterogeneity and Reservoir Quality of Yabus and Samaa Formations, Agordeed Field, Melut Rift Basin, Sudan
Authors Amani A. Badi, Omer Ali, Abdalla Farwa and Osman M. AbdullatifThe Tertiary Yabus and Samaa Formations occur within the Melut Rift basin of interior Sudan which is
regionally linked to the central and west African rift system. Yabus and Samaa Formations in Agordeed
oil field are ones of the most productive oil reservoirs in Melut basin and are composed of sandstones
and mudstones lithofacies that differ in size and length along and across the basin. The reservoir
sandstone, which occurs at shallow burial depth, deposited within fluvial/lacustrine environments. This
work aims to describe and characterize the reservoir heterogeneity and to investigate their impact on
reservoir quality and architecture. This study employed a multidisciplinary and integrated approach
that investigated and synthesized stratigraphic, sedimentological, cores, logs, petrographical,
petrophysical and seismic data from Agordeed oil field. The stratigraphic and lithofacies analysis
indicated that Yabus and Samaa formations vary systematically in their facies, sequences and stacking
patterns within the basin. Reservoir heterogeneity exists at multiple scales, where reservoir sandstones
macro- and micro scale heterogeneity shows vertical and lateral variations along and across the basin.
These variations reflect the tectonic, depositional and post depositional controls within the proximal to
distal fluvial, prodelta and lacustrine environments. The porosity and permeability distributions are
controlled by the heterogeneities within the reservoir formation, such as stratigraphic layering, facies,
diagenetic processes, and fracturing. Porosity is enhanced by extensive fracturing and grain dissolution
creating intergranular, intragranular and moldic porosity. In addition, permeability is also increased by
fractures connecting separated the buildups, that affect directly the reservoir quality. Assessing the
different scales of heterogeneity is important to understand their impact on reservoir quality and
architecture in Agordeed Field.
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Mapping and Re-evaluation of the Main Unayzah a Eolian Fairway, Southeast of Ghawar Field, Saudi Arabia: beyond the Porosity Sweet Spot
By Luis GiroldiThe Lower Permian - Upper Carboniferous aged Unayzah Group encompasses some of the main
Paleozoic reservoirs in Saudi Arabia. It constitutes one of the prime targets of Saudi Aramco’s
exploration efforts in the Paleozoic section.
The upper reservoir interval, Unayzah A, is comprised of a series of fluvial, playa, lacustrian and eolian
sandstones, which exhibit lateral variability.
The area southeast of the Ghawar field is characterized by a predominance of eolian sandstones that
constitute the main Unayzah A reservoir. They are relatively continuous within a west-east trending
depositional fairway that has been defined by both well and seismic data.
Early exploration targeting these reservoirs was centered on structural closures and resulted in the
discovery of several large gas fields, like Tinat and Midrikah, the latter having a large stratigraphic trap component.
More recent exploration efforts have been focused in the areas northeast of those fields. A reevaluation
of legacy 3D seismic and interpretation of new 3D seismic and well data has led to an
increased prospectivity within the Unayzah A reservoir interval. Methodologies applied there helped to
refine the mapping of the hydrocarbon potential in the eolian fairway. Close re-examination of preexisting
and new seismic reflectivity and acoustic impedance 3D datasets through visualization,
combined with spectral decomposition and rock properties modeling have given new insights into the
distribution of the eolian reservoirs. High porosity sweet spots and the potential role of syntectonic
structures in controlling sandstone deposition have been recognized.
Stratigraphic plays were identified in an area of about 8,000 sq km where no reliable structural
closures are present. These plays are based on reservoir quality and the presence of lateral seals as
inferred from seismic and well data.
Recent well results have given confidence not only in the ability to detect the porosity sweet spots, but
also to discriminate which ones have higher probability of being filled with hydrocarbons, by combining
rock properties analysis, modeling and pre-stack seismic data interpretation. The ongoing challenge is
to further develop methodologies to discriminate between brine and hydrocarbon filled reservoirs to
help prioritize the prospects already identified.
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