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GEO 2008
- Conference date: 03 Mar 2008 - 05 Mar 2008
- Location: Manama, Bahrain
- Published: 03 January 2008
1 - 100 of 385 results
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Sandstone-body geometry, facies architecture and depositional model of Ordovician Barik Sandstone, Oman
Authors Iftikhar A. Abbasi and Abdulrahman Al-HarthyThe Lower Paleozoic siliciclastics sediments of the Haima Supergroup in the Al-Haushi-Huqf area of central Oman are subdivided into a number of formations and members based on lithological characteristics of various rock sequences. One of the distinct sandstone sequences, the Barik Sandstone (Late Cambrian-Early Ordovician) of the Andam Formation is a major deep gas reservoir in central Oman. The sandstone bodies are the prospective reservoir rocks, whereas thick shale and clay inter-beds act as effective seals. Parts of the Barik Sandstone, especially the lower and middle parts, are exposed in isolated outcrops in the Al-Haushi-Huqf area as inter-bedded, multi-storied sandstone, and green and red shale. The sandstone bodies are generally up to 2.0
m thick and can be traced laterally for a few hundred metres to a few kilometres. Most of the sandstone bodies show both lateral and vertical amalgamation. Two types of sandstone facies are identified on the basis of field relationship: (1) a white sandstone facies usually capping thick red and green shale beds; and (2) a brown crossbedded sandstone facies overlying the white sandstone facies. An attempt was made to study the relationship of fluvial, fluvio-deltaic and tidal processes on the basis of lithofacies characteristics. This presentation summarizes the results of a preliminary study carried out in the Al-Haushi-Huqf area to analyze the characteristics of the sandstone-body geometry, internal architecture, provenance and diagenetic changes in the lower and middle parts of the member.
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An innovative approach to characterizing fractures for a large carbonate field of Kuwait by integrating borehole data with the 3-D surface seismic
Developing fractured carbonate reservoirs has always been demanding for the geoscientists of the oil industry. The main challenge, in this regard, has been modeling the fracture system. To build a DFN (discrete fracture network) model, different geostatistical techniques are used to extrapolate the fractures beyond the well locations and populate them between the well control. However, due to inherent uncertainty DFN predictions have not always been correct, so the industry needs a way by which DFN models can be constructed with a higher degree of certainty. This presentation discusses an innovative workflow by which the borehole-scale fracture data is integrated with the surface seismic using the Fracture Cluster Mapping (FCM) technique to locate fracture clusters. The most important step in this approach is to obtain a good understanding of the fracture system intersected by boreholes that have certain expressions on the drilling record, borehole images, petrophysical logs, cores and production data. Generally the discrete fracture occurrences would not have any expression on the surface seismic. However when fractures of bigger dimensions form clusters/swarms, they tend to have larger vertical and horizontal extents, as observed in several outcrops in the Middle East and other countries. In this workflow, surface-seismic data processing is optimized for it to be used for fracture clusters / corridors detection. Having a good understanding of fractures’ pattern in the field and optimally processed 3-D seismic data, Ant Tracker (which is an essential part of FCM for automatic extraction of lineaments from the seismic data) is run on the seismic cube. The Ant Tracker set of parameters are conditioned based on the fracture data, gathered from boreholes, in such a way that they highlight fracture clusters/corridors of certain orientations and width. The workflow was tested on the study area of about 1,400 square km for the carbonates of low porosity, low permeability and about 3,000 ft thickness. There were 12 wells drilled in the study area and ten of them had image logs and cores (from selected zones) to get information on fractures. One well test, one production log, and mud loss data from half of the wells, and total well production data were used to understand the fracture behavior. Wellbore images and cores in the study area invariably showed existence of fracture clusters/ swarms of width greater than 100 ft and length greater than 500 ft.
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Whole-core analysis for effective characterization of inter-well permeability from a horizontal well
More LessWhole-core analysis is critical for characterizing porosity and directional permeability in heterogeneous, fractured and/or anisotropic rocks. Whole-core measurements are essential because small-scale heterogeneity may not be appropriately represented in plug measurements. Additionally, for characterization of multi-phase flow properties (special core analysis) in heterogeneous rocks, whole-core analysis is required. Special whole-core analyses are not frequently conducted on whole cores because of experimental difficulties, such as establishing representative water saturation. It is rare that cores are taken and whole-core analysis is conducted from a horizontal well in a carbonate reservoir. The objectives and results of this presentation are: (1) show permeability variability at inter-well scale from a horizontal well in a carbonate reservoir in Abu Dhabi. (2) Compare vertical permeability in whole cores obtained from a horizontal well to vertical permeability obtained from an adjacent vertical core. (3) Analyze gas-oil relative permeability measurements conducted on whole cores. These were modeled and compared with gas-oil relative permeability data at plug scale. Klinkenberg-corrected permeability on whole cores under reservoir net-confining stress was measured and the results were compared with plug analysis from the same interval. (4) Demonstrate quality-control and data-analysis procedures for whole-core analysis. Uncertainty in routine and special whole-core analysis data were quantified and quality-control and
data-analysis procedure are presented.
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The origins of interfacial tension and implication on the wettability of carbonate oil reservoirs
More LessThe distribution of water saturation within an oil reservoir is of paramount importance for hydrocarbon volume, reserves and production assessment. Inter-facial interactions between oil, brine and rock determine the fluid saturations and distributions within the pore system. Only two fundamental electrostatic forces, acting between neutral molecules, are responsible for all of these interactions, i.e. the dispersive and the polar forces. It will be demonstrated that the latter interaction is the dominant force field for all the interactions at the interfaces with water and control the capillarity of an oil reservoir. These molecular forces determine the inter-facial tension between crudes and brines (σ) and the contact angle (ө) between the liquids’ interface and the surface of the rock. The resulting quantity σ.cos(ө) is the effective capillary stress resisting the buoyancy of the penetrating oil and strongly determines the ultimate amount of oil in the pores. Experimental work on these quantities has not progressed greatly over the last decennia, in particular for those related to carbonate reservoirs. In this presentation the physics related to intra-molecular attraction and the resulting inter-facial interaction is analysed. For example it will be shown that the gases dissolved in the crudes greatly affect the electrostatic properties of the crudes, effectively reducing the interactions with the brines and reservoir rocks. Moreover, it will be demonstrated that, owing to the properties of the carbonate rocks, the σ.cos(ө) values for carbonate oil reservoirs could be substantially lower than for clastic reservoirs. All these conclusions affect the apparent wettability of the reservoirs, with possible far-reaching consequences for reserves and production.
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Fiber-optic 4C seabed cable for 4-D permanent reservoir monitoring
Authors J. Brett Bunn and S. Rune Tenghamn and Steven J. MaasWe present an optical system that utilizes passive optical telemetry and sensors to replace traditional seismic acquisition hardware that uses conventional sensors and in-sea electronic modules. The optical system eliminates the costly electronics and problems associated with them, providing a more reliable, less expensive, safer system to operate. We then will describe the system construction and compare data quality between the fiber optic and conventional systems. The optical system utilizes Dense
Wavelength Division Multiplexing (DWDM) to optically power the sensors; optical interferometers are used to construct sensors. An optoelectronic/acquisition cabinet provides laser source to the optical sensors. The source passes through an interferometer, where outside stresses cause a phase shift in the light passing through the interferometer. The phase information is extracted back in the cabinet to output a signal equivalent to the input stress. Field test of an optical cable was conducted 2006 using a
conventional reference cable. The cables were deployed parallel to each other in the Gulf of Mexico. Advances in fiber optic technology provide a system for 4-D reservoir monitoring. A successful demonstration in the Gulf of Mexico shows the optical system meets the requirements permanent reservoir monitoring. Advances in a 3-axis optical accelerometer, have turned this system into a practical tool for 4C permanent reservoir monitoring. We have demonstrated the systems capabilities in deepwater with high channel count over many kilometers while maintaining high dynamic range, low crosstalk and low distortion. The optical system is an excellent fit for and a preferred solution for permanent reservoir monitoring systems.
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Residual water-bottom multiple attenuation in the Arabian Gulf
Authors Roy Burnstad and Mahmoud E. HedefaThis presentation will discuss the identification and resolution of a water-bottom multiple problem encountered in the Arabian Gulf. In 2002, Saudi Aramco acquired and processed an ocean-bottom cable (OBC) survey configured with hydrophone and geophone sensors designed to attenuate seismic energy trapped in the water layer. Subsequent interpretation of the 3-D data volume at the target horizon revealed wavelet variations that mimicked the water-depth profile. This was of concern, as the target was not expected to be conformable to the water bottom. An investigation of the issue determined a significant amount of unwanted energy remained in the data, even after use of industry standard processing and acquisition methods. After careful analysis we found that rapid changes in the water-bottom reflection coefficient may have compromised the results by inadequately suppressing water-borne energy. A key diagnostic display in the common water-depth domain indicated it was possible to isolate the periodicity of this unwanted energy such that inverse filters could target and suppress it. A new workflow was then designed such that an algorithm utilizing multi-domain deconvolution could identify and suppress the errant energy while maintaining structural and wavelet integrity at the target horizon. The new workflow proved to be more efficient than traditional single channel deconvolution methods with respect to isolating the periodic nature of the water-borne energy. A repeat of the diagnostic displays indicated the new
workflow was measurably more effective at suppressing the residual water bottom multiple.
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Stratigraphic processing for AVO and AVZ analysis
Authors Roy Burnstad and Timothy H. KehoWe present a stratigraphic processing flow which prepares wide-azimuth, long-offset, 3-D seismic data for amplitude-versus-offset (AVO) and amplitude-versus -azimuth (AVZ) analysis. Simultaneous analysis of the variation of amplitude with offset and azimuth is necessary for an integrated study of lithology, fluids and fractures. The processing flow extends the general concepts of AVO processing to include the azimuth domain. Our approach is target oriented. We use an interpreted seismic horizon to define the design window for pre-stack operators. We begin by applying all available time corrections from previous processing. This includes datum statics, residual statics, normal moveout corrections and structural time corrections. By using structural time corrections
we are taking advantage of the gently dipping nature of the geology as typically found in the Eastern Province of Saudi Arabia. Next we apply 3-D linear noise removal simultaneously on all offsets and azimuths. We then run cascaded multi-channel, surface consistent, amplitude and frequency analysis. Each pass includes separate terms for source, receiver, offset and azimuth. We use azimuth- and offset-friendly algorithms. This means that unless the record is operated on as a whole, each process must accommodate offset and azimuth terms. At several stages during the processing flow we employ quantitative quality control checks by analyzing a variety of pre-stack attributes along key horizons. Finally, we define an important quality control guideline that
states our AVZ decomposition must bear similarities to the anisotropy ellipse. We illustrate this approach using a wide-azimuth, long-offset, survey recently acquired over a Jurassic reservoir in Saudi Arabia.
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Impact of an integrated reservoir geological model on well placement: A case study from Saudi Arabia
More LessThe objective of this study is to build an integrated geological model for a Jurassic reservoir in Saudi Arabia utilizing all available static and dynamic data to optimize field development plan and well placement. The Late Jurassic Arab Formation is one of the most important reservoirs in the Middle East. During this period a carbonate platform developed in most of the Arabian Gulf and extended to the Zagros Mountains in Iran and central Iraq. The reservoir consists of 45–50 ft of packstone to grainstone reservoir overlain by 5–15 ft of anhydrite. A total of 533 ft of cores from 13 wells have been studied and also results from 54 wells including well logs and well performance have been used. In this study, different sources of data with different scales were integrated to
produce a single model that best represents the reservoir. This project was carried out through three main stages. The first stage was a detailed reservoir characterization study for the reservoir including core description, rock and facies types, pore geometry and diagenesis. The second stage involved univariate and multivariate statistical analysis of input data such as well logs. In the third stage, an integrated stochastic reservoir model was built using different geostatistical modeling techniques. This newly generated model captured the reservoir heterogeneities and was used to optimize placement of horizontal wells and to predict reservoir performance. So far a total of seven horizontal wells have been drilled with 29,000 footage based on this study and the results
are very satisfactory in matching expectation.
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Effluent water disposal in two giant oil fields in northern Kuwait
Authors Peter F. Cameron and Ali N. Khan and Noel LucasTwo major carbonate reservoirs are being used for effluent water disposal in the Raudhatain and Sabiriyah oil fields in northern Kuwait. These are the Paleocene Radhuma and Maastrichian Tayarat formations. A detailed reservoir characterization study of these formations was initiated in 2006. The purpose of the study was to develop an understanding of the injectivity capabilities of the reservoirs and to determine the medium-term plan for water-injection capability over the period to 2010 to ensure zero surface disposal of water to evaporation pits. A 3-D model was built, which included the 39 major faults located in both fields. Seismic inversion was applied, and a petrophysical interpretation of the limited log data set was used to populate the property model. The model
illustrated that the upper Radhuma layers have the best porosity and permeability, although to date the injectivity data suggested a lower Tayarat dolomite layer has the best capability for water disposal. Dynamic testing and history-matching of the model demonstrated that the crestal area of both fields will likely pressure-up in the near-term, especially in the immediate vicinity of the disposal wells, but the flanks of both fields will undergo relatively moderate pressure build-up over a four-year injectivity period. The dynamic modeling suggested that the flank and mid-flank areas of both fields, where porosity and permeability are present, may be the best areas to locate effluent water wells that will have good injectivity and moderate pressure gain over a sustained time period.
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An integrated approach to predict filling history and fluid composition of satellite prospects
More LessIn mature basins, most of the exploration is oriented towards satellite prospects. The difficulty in their detection lies in a reliable evaluation of their economic interest. Indeed, the interest in such prospects is very sensitive to the trap volume and the quality and composition of the producible hydrocarbon fluids. Trap volume and hydrocarbon quality can only be predicted through a detailed reconstruction of the reservoir and its hydrocarbon infilling evolution. It is necessary to take into account, as a function of the geological time: (1) the structural evolution and faulting of the area; (2) the initial facies distribution and diagenesis; and (3) the fluid maturation and migration with a fine compositional description. Such a time-related filling is classically taken into account at basin-scale but rarely applied to the fetch area of giant fields where the satellites are searched for. Here we propose an integrated approach that takes advantage of the well-known geochemical information from the discovered large structures to calibrate the trapping and composition of the satellite structures. The approach, which uses softwares originally developed for basinscale exploration, is based on the combination of tools for structural reconstruction (Kine3D), fine simulation of facies distribution (Dionisos), high-resolution compositional kinetics and migration/dismigration scenarios (TemisSuite) and uncertainty evaluation (QUBS).
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Value of NMR logging to heavy oil reservoir characterization
Authors Songhua Chen, Dan Georgi and Jason Chen and Wei ShaoRecent advancements in nuclear magnetic resonance (NMR) logging have made it possible to address the particularly challenging heavy-oil reservoir characterization problem. Because viscosity varies substantially in different heavy-oil fields, no single NMR technique works for all situations. Three methods were employed for characterizing heavy-oil reservoirs in clean sands, shaly sands, and formations containing bitumen/tar, respectively. In clean sand or some carbonate formations, direct NMR fluid-typing is usually sufficient for quantifying heavy oils. For shaly sands, where NMR responses to heavy oil and bound water significantly overlap, we developed a conventional log-constrained inversion technique to better discern heavy oil from bound water. For bitumen at
low-reservoir temperature, NMR relaxation time is too short to detect by the current NMR logging tools; analysis of porosity deficit is a robust means to identify and quantify tar mats. Those techniques have been successfully employed in Venezuela, Kazakhstan, Canada, USA and the Middle East. In contradistinction to cuttings, NMR logs allow us to precisely determine the depth of heavy oil that is crucial for water-flooding applications. Also, NMR can quantify movable water in the heavy-oil reservoirs – critical information for predicting producibility. Furthermore, NMR provides crude oil constituent information far beyond a single bulk-viscosity estimate. This can be used for identifying sweet spots in heavyoil reservoirs. The component analysis is essential for
separating light and heavy oil volumes with their corresponding viscosities in dual-charged reservoirs where each charge to the reservoir brought in oils having different viscosities.
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Minor reservoirs in northern Kuwait: Reserves growth and production opportunities
More LessIn the Development Plan of Kuwait Oil Company, production from several minor reservoirs in northern Kuwait is scheduled to increase by about 10-fold by 2015–16. These reservoirs were not previously studied in detail because of limited experienced staff, most of whom had focused on the accelerated development of the major reservoirs in the country. Some of the minor reservoirs are complex, discontinuous and require further delineation. In some fields they are stacked and can potentially add many billions of barrels of oil in reserves growth. In order to accelerate the appraisal of these reservoirs, a multi-pronged approach was adopted to identify reserves growth and increased production opportunities. The approach involved: (1) identifying existing wells for testing; (2) deepening and testing of planned wells to the deeper Cretaceous Zubair and Ratawi reservoirs; (3) utilizing the Jurassic wells that penetrated through the Zubair and Ratawi reservoirs to acquire data; (4) identify opportunities to acquire data in wells penetrating
through Tuba and Mid Burgan during the ongoing drilling activities for major reservoirs; and (5) continued surveillance in the Burgan and Mauddud reservoirs in Bahra field, so as to assess the pressure-production performance. In order to expedite the tasks, a managementlevel steering committee was formed to supervise the implementation of a blueprint that listed all the activities in terms of timelines, priority matrices.
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Application of neural network in intelligent reservoir characterization: A case study from Ahwaz oil field, southwest Iran
Authors Habib Akhondi, Mohammad Reza Kamali and and Ali KadkhodaiyPorosity and permeability are the most important hydrocarbon reservoir properties. There are two methods for determining porosity: directly by core analysis with helium injection, and indirectly by well-log analysis. Similarly, permeability can be determined in the laboratory from core samples by dry-air injection or well-testing methods. These methods are costly and time-consuming. Due to economic reasons and the inability to core horizontal wells, core data is available in a limited number of wells. However, most wells have well-log data. In the present study, intelligent computing neural networks, which are widely used nowadays in the petroleum industry, were used to predict porosity and permeability in the Asmari Formation. The MATLAB software was used to process neural networks for core and well logs data, including porosity and permeability. These networks were developed using an error backpropagation algorithm within feed-forward networks. After comparing the measured and network-predicted results, the parameters of the artificial neural networks (ANN) were adjusted for a desired network. The correlation coefficient between the core results and the ANNpredicted porosity and permeability were 0.92 and 0.82, respectively. These results show that intelligent neural network models predicted porosity and permeability accurately. Finally, the above-mentioned networks were generalized to a third well that had no core data.
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Meeting the challenges of static modeling of a mid-life giant Middle Eastern oil field, Abu Dhabi, United Arab Emirates
A giant carbonate oil field, located in Abu Dhabi, has been producing from Lower Cretaceous reservoirs since 1973. The current field development plan (FDP) is based on a reservoir model, which has evolved in stages, with input from many field and laboratory studies over the past 20 years. The most recent static model has been built incorporating the results from significant new core characterization and sequence stratigraphic studies (over 110 cored wells), in addition to a more thorough integration of well, geological, production and 3-D (and 4-D) seismic data. Modeling such a large and active field (more than 600 wellbores) presents real data management challenges. These challenges include the choice of geo-modeling software, accessing and maintaining the corporate database, and ensuring that all engineering and geosciences disciplines are able to easily contribute and use the final integrated model. This new Phase-3 static model has been built primarily to provide a more detailed reservoir description to the dynamic model to further optimize the FDP, as we complete the current infill drilling campaign and move to the tighter infill production. The model is also meant to provide a longer-term, more robust geological characterization for future enhanced oil recovery (EOR) activities. A recurring theme for the team is also the challenge to find the appropriate balance between incorporating 3-D seismic data and using data from the densely located wellbores. Other new demands on our modeling workflows include the need to quantify volumetric uncertainties by generating model scenario’s and multiple realizations for proven SEC (US State Securities and Exchange Commission) deterministic and probabilistic reserves reporting. The new workflows will also allow a more rapid model updating as new wells are drilled.
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Multi-survey acquisition and processing in the Nile Delta
Authors Michael Cogan and Magdy AbdelAty and Tamer Abdel RahmanThe challenges associated with acquiring and processing multi-environment data in Egypt’s Nile Delta are presented. In 2006, approximately 1,200 square km of new land, transition (TZ) and ocean-bottom cable (OBC) seismic data were added to approximately 1,600 square km of existing data in the western Nile Delta. Two contractors, operating in concert with two recording systems, three source types, and four different detector types proved operationally challenging but not impossible to coordinate. Continuous processing of the field data resulted in several fast-track volumes providing interpreters with new data to analyze. Following the successful acquisition and delivery of preliminary processing volumes, the project area was expanded considerably to include data from adjoining surveys. Merging the newly acquired land, TZ, and OBC 3-D seismic data with existing multi-vintage streamer and OBC data provides nearly 3,000 square km of continuous data for pre and post data interpretation and analysis. There are, however, significant data processing challenges in producing a continuous volume. The challenges included deriving a consistent demultiple solution for adjoining land, OBC and towed marine data, as well as regularizing the noise levels in these diverse data sets. To achieve a seamless final data set, a broad portfolio of demultiple and noise-attenuation techniques were needed. Results from the multi-survey methodology will be presented. With increasing activity in the Mediterranean Sea and Nile Delta, data-sharing agreements are becoming more common. This has brought into focus the need for robust data processing solutions for multi-vintage data, as well as acquisition systems and crews that can operate cooperatively.
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Depositional architecture of the Upper Shu’aiba Formation exploration play in the greater Lekhwair area, Block 6, northern Oman
More LessThe success of the Late Aptian, Upper Shu’aiba Formation play in Block 6, northern Oman has been driven by an increased understanding of the depositional architecture of the basin. It is founded on the integration of seismic attribute data with a well-based sequence stratigraphic framework, palaeo-environmental data and data from analogue fields. The Upper Shu’aiba sequence was deposited along the southern margin of the Bab Basin in the Late Aptian, during a regional lowstand. In northern Oman, deposition occurred in a strait between the isolated Safah Platform and the early-Late Aptian Shu’aiba margin to the southeast. The succession on the northern flank of the strait, which is largely mirrored on the south, is characterized by progradational geometries, with carbonate shoals intercalated with argillaceous limestones or marls. The shoal trends can be imaged seismically as a succession of amplitude and spectral decomposition tuning belts and have been modelled in PetrelTM. The clinoforms have ramp or distally steepened ramp morphologies, with palaeo-water depths ranging from 100 m to less than 5 m, with facies transitions from outer-ramp mudstones, through mid-ramp wackestones and packstones into inner-ramp shoal or build-up facies, locally with low-energy backshoal facies. The shoals vary from rudist-dominated rudstones and floatstones in Ufuq to coated-grain and miliolid-dominated grainstones in Dafiq, which reflect variations in depositional energy regimes and accommodation space during the gradual infilling
of the strait from the north (and south). Reservoir properties are largely controlled by the primary depositional fabric, however, significant diagenetic overprinting, both enhances and degrades the reservoirs.
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Improving understanding of 3-D distribution of diagenetic processes with digital outcrop modeling: Example from the Natih Formation, Jabal Madmar, Oman
One of the challenges in carbonate reservoir characterization is to quantify the 3-D distribution of diagenetic processes responsible for determining poroperm distributions. Digital outcrop modeling techniques (GPS, Lidar) are normally used to map the 3-D distribution of depositional facies, but can be also used to quantify the extent of diagenesis, associated diagenetic products and processes. Commonly, the interiors of Middle East carbonate platforms are modeled in a homogeneous layer-cake fashion. Nevertheless, several km-scale (i.e. inter-well-scale) outcrops of epeiric platform carbonates revealed a complicated internal stratigraphic architecture, comprising depositional geometries such as platform-top incisions and clinoforms. These clinoforms
and incisions have a wide range of heterogeneities due to the diagenetic overprint, such as dolomitization, early meteoric cementation, silicification and late leaching. One of the objectives of this study was to quantify the diagenetic processes observed in the field and determine their origin in the context of structural and basin evolution. These data then can be used to improve subsurface reservoir models in inter-well correlations, and can provide analogue data for exploration and appraisal. Digital outcrop modeling combined with detailed sampling, petrography (transmitted-light, ultravioletfluorescence, and cathodoluminesce microscopy), and geochemistry (stable carbon and oxygen isotopes, fluid inclusions, X-ray, and BSEM) was used to determine the 3-D distribution and origin of dolomitized incisions and silicified clinoforms of the outcrops of Jabal Madmar, Oman. These data have been linked with the structural evolution and basin evolution of the field area, in order to provide predictive rules for the subsurface.
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Structural Evolution of the Hawasina Window (Oman Mts) and its Relation to Hydrocarbon Generation
Extensive field studies in the Hawasina Window region
of the Oman Mountains led to the recognition of
four major structural processes, linked with: (1) intraoceanic
obduction; (2) emplacement of ophiolites onto
the Arabian continental margin; (3) unroofing of the
subthrust margin; and (4) Tertiary folding and extension.
The first Cenomanian process is not relevant to the
formation of hydrocarbons in the Arabian margin. The
second Turonian process led to the formation of out-ofsequence
nappes and ductile extension. It provided tectonic
burial of the margin. An omnipresent NE-vergent
syn-cleavage folding is also associated to emplacement.
The shortly following tectonic unroofing rafted ophiolite
blocks away from the window areas. Break-up of the
nappes is suggested along a pre-existing strike-slip fault
system. Isostatic compensation led to uplift and folding
of the nappe succession. Finally the Tertiary Period was
characterised by across-strike normal faulting and numerous
steps of folding, ramp-thrusting and transpression.
This process uplifted potential reservoir sections in
Late Tertiary times. The play concept proposes classical
Natih source rocks and reservoirs in the autochtchon.
Since original porosity is reduced due to tectonic loading,
fracture porosities in the limestones and Upper
Permian-Triassic dolomites are considered viable in the
reservoir rocks. Seals are formed by shaly sections of the
autochtchon (Salil, Nahr Umr and Muti formations) and
of a regional evaporitic detachment at the base of the
Hawasina Nappes. The major upwarp of autochtchon
and three local antiforms in the Hawasina Window form
the potential trap(s). Vitrinite reflectance and clay mineralogy
both reflect anchimetamorphic conditions for the
Hawasina Nappes. Thermal conditions probably did not
exceed late-stage, gas maturity levels. The main burial is estimated to have lasted for 10 million years. Therefore
the Hawasina Window area is considered gas-prone.
Both MOL Hungarian Oil & Gas Plc and Hawasina LLC
Oman Branch wish to thank the Exploration Directorate
of Ministry of Oil & Gas of the Sultanate of Oman for the
continuous support to the work.
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Fracture reactivation and diagenesis in the Asmari Reservoirs (Dezful Embayment, southwest Iran) during the Zagros Orogeny: Implications for fractured reservoirs modeling workflows
Production from the Asmari carbonates of the Dezful Embayment, southwest Iran, provides a textbook example of the dynamic behavior of fractured reservoirs. In these reservoirs, fracture modeling is therefore a key task of any characterization workflow. This study presents recent findings on the relationship between fracturing, diagenesis and folding in the Zagros Foreland Basin and their practical consequences on fractured reservoirs modeling workflows. Based on the structural description of outcrops, the synthesis of image log interpretations and the analysis of fracture filling (both in outcrop and subsurface), we first propose a chronologic framework for the fracturing events in relation to paragenetic sequence in the Asmari Formation. This emphasizes the
pre-folding origin of the main fracture sets affecting the formation. During these early events, the pre-Hercynian NS basement trends that affected the Arabian Plate, strongly controlled the spatial distribution of fractures. This stage of fracturing was associated to the growth of burial stylolites and successive stages of dolomite and calcite cementations. In a second stage, during folding, most of the deformation was accommodated by reactivation of pre-existing fractures. These fractures were associated with the precipitation of ferroan calcite in the exposed rocks, anhydrite in the reservoir and the first stages of hydrocarbon emplacement. A 100 x 100 square km 3-D model, which includes outcrops and reservoirs, will be discussed. Contrary to the growing use of such
a method to control fracture density, we advocate that it better provides a good proxy for fracture reactivation potential and associated flow paths.
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Passive seismic field pilot for Arab-D Reservoir monitoring
Authors Shiv N. Dasgupta and Mike A. JervisPassive seismic methods have been traditionally applied to study the Earth’s internal structure using earthquake data. It is only recently that these methods have been used in petroleum reservoir delineation. Monitoring of fluid pathways in a producing reservoir is imperative for optimal reservoir management and maximal oil recovery. A pilot microseismic experiment has been designed and implemented in a Saudi Arabian oil field for mapping of Arab-D Reservoir drainage patterns. The experiment is unique because of the large array of permanent multicomponent seismic sensors that are deployed at various levels in the borehole and over a surface area surrounding the borehole. The passive microseisms are recorded simultaneously in the surface and borehole sensors. The
field pilot will test the ability for recording microseismic events caused by Arab-D Reservoir production and injection activities. The combined surface and boreholebased measurements are designed to provide a wide areal coverage over the reservoir. The sensor network is designed to capture events of greater than Richter magnitude -3, with frequencies from 10 to 1,000 Hertz within two kilometers of the hypocenters. In addition to microseismic, permanent pressure and temperature sensors were installed in the wellbore. Fluid-flow anisotropy in the area is evident from production behavior and well test data but the flow pathways and mechanism for the anisotropy are not resolved. Microseismic data could provide the location and relative fracture density that will improve the reservoir-flow, simulation models. Monitoring microseismic events over time will enable better prediction of fluid-flow behavior and the planning of production and injection well locations for optimizing reservoir production and ultimate recovery.
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Jurassic sequence stratigraphy in the Raudhatain-Sabiriyah area of northern Kuwait
More LessExploration of multiple Jurassic carbonate reservoirs has increased after the discovery of hydrocarbons below the prolific Tertiary-Cretaceous section across Kuwait. The Jurassic of northern Kuwait has been studied in terms of sequence stratigraphy based on 2,686 ft of core and 12 borehole wireline logs. Six sequences have been identified. The key surfaces are sequence boundaries, maximum flooding and flooding surfaces. Each sequence comprises a transgressive systems tract (TST) and a highstand systems tract (HST). Sequence 1 corresponds to the Lower Marrat section, which consists of at least six carbonate/evaporite cycles. Sequences 2 and 3 are referred to the Middle Marrat where carbonates are arranged in shoaling upward parasequences ranging from
a few feet to 10s of feet in thickness. Sequence 4 corresponds to the Upper Marrat section where evaporites occur below an MFS revealing a transgressive depositional environment. The Dhruma and Sargelu formations comprise Sequence 5, whereas Sequence 6 consists of the Najmah shale overlain by Najmah carbonate. The study of cores, combined with petrophysical analysis, has identified seven different lithofacies: lime grainstones to packstones, lime packstones to wackestones, lime wackestones and mudstones, algal boundstone, crystalline dolomite, bituminuous calcareous shale and anhydrite. The results of the study show an improved understanding of the Jurassic carbonate depositional architecture, and its control of hydrocarbon generation and entrapment in northern Kuwait. The results will be used for further exploration and development work in the area.
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Tectonic fracture network characterization in the giant Hassi-Messaoud oil field, Algeria
The objective of this presentation is to show the methodology used to characterize the tectonic fracture network in the giant Hassi Messaoud oil field located in Algeria. This field is characterized by a significant number of wells (One Thousand Five Hundred) and data of various origins and forms. The data includes borehole image logs in 100 horizontal wells, cores from 1,000 wells, 2,500 square km of 3-D seismic, as well as dynamic data (production, pressure and water/gas breakthrough) for most of the wells. The fractures are complex objects to analyze. Because their scale is greater than the diameter of the borehole, it is necessary to take into account all the indices (seismic, physical and dynamic) to characterize them. In the Hassi-Messaoud field, tectonic fractures are clustered and associated with faults, and/or organized in fracture swarms. When they are cemented and the matrix is damaged by silica, they behave as barriers. In contrast, when the fractures are open, they provide a preferential path for fluid flow. The fracture network induces anisotropy of permeability, which has a strong impact on the development of the field. A synthetic map, which combined all available information, was constructed to predict and model conductive and barrier trends. The fracture network characterization improved the development of this mature field.
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Lateral facies variations of Upper Cretaceous carbonate ramp deposits, Jebel Nefusah, northwest Libya
More LessThe Upper Cretaceous (Cenomanian) platform carbonates of Jebel Nefusah, northwestern Libya, were deposited as part of a regional prograding low-angle ramp system. These deposits are well-exposed in the Jebel Nefusah area but are poorly documented in the literature. Strata in this area are relatively undeformed making this system ideal for the study of lateral facies variation. The Cenomanian Stage is a major cyclic transgressive event over the regional unconformity that overlies the Aptian-Albian fluvio-deltaic sandstones of the Chicla Formation. The system contains an extensive oolitic to rudist-rich member that serves as an alternative analogue for Middle Eastern reservoir-prone facies. Field stops at 17 localities and five detailed sections over an area of 200 km form the base of a stratigraphic correlation panel, including the stacking pattern and depositional context of the recognised members. A geological model is proposed showing three third-order systems tracts during Cenomanian platform evolution. The first unit (less than 40 m thick) consists of inner ramp, tidally-influenced shallowing upward sequences. The second unit is characterised by progradational, inner-ramp oolitic shoal (40 m thick), which pass laterally into the mid- to outer ramp bioclastic, rudist boundstone and rudstone facies. This facies is a regionally developed (more than 200 km wide) member, 4–8 m in thickness. The two units are known as the highly dolomitised Ain Tobi Formation. A third regressive unit, the Yefren Formation, reaching 80 m in
thickness, is formed by restricted inner-ramp marls with inter-bedded evaporitic gypsum layers. The depositional environment corresponds to a supra-tidal to sabkha setting. The architecture and geometry of the Cenomanian passive ramp system was controlled by eustatic sea-level changes rather than localised, abrupt tectonic events.
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Seismic array response in the presence of laterally varying thickness of the weathering layer
Authors Jubran Akram and Abdullatif Al-ShuhailWavelet response analysis of seismic arrays is a more convenient and direct method of analysis than using their conventional time-harmonic responses. This is because wavelets, rather than sinusoids, are actually generated by the seismic source. This study involves an investigation of the effect of lateral variations in thickness of the weathering layer over the array length on the array response. Three types of variations were studied; namely, dipping-bottom boundary, channel and irregular bottom boundary of the weathering layer. The investigated parameters were the number of elements (12 and 24 elements), the weighting function (equal and triangular), the incident wavelet (Ricker and Klauder) and the error amount. The degradation in the root-mean square (RMS) amplitude responses generally increased with the error amount. RMS amplitude responses were more degraded in the channel case than the other two cases. Errors affected triangularly weighted arrays more than equally weighted arrays. Klauder wavelet
array responses were more affected by these errors than Ricker wavelet responses. Vertically traveling waves (i.e. signals) were more affected than the horizontally traveling waves (i.e. noise). Since these variations cannot be inferred from the surface topography, they can affect the array responses without being detected, unlike topographic and element’s positional errors. Therefore, it is recommended to test for these effects prior to array layout. Solutions to this problem are to record single-element
data and correct these during processing before summing, or to move the array away from the sources of these effects.
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Stratigraphic framework of the Natih Formation in Oman
More LessCarbonates of the Albian to Turonian Natih Formation are important hydrocarbon reservoirs in Oman. A regional sequence stratigraphic study integrating seismic and well data of interior Oman led to a better understanding of the reservoir and seal distribution as well as the stratigraphic trapping potential. Deposition took place on an epeiric shelf with carbonate platform development at the ocean-ward margin, located in northern and eastern Oman, whereas clastics predominated along the exposed Arabian Shield in the southwest. Lateral shifts in clastic and carbonate facies belts, driven by changes in relative sea level and climate, resulted in a hierarchical stacking of depositional cycles of several 10s up to some 150 m thick. Two major flooding events, with widespread deposition of pelagic carbonates, occurred in the Late Albian and Late Cenomanian. Both are associated with the creation of significant depositional topography (up to 100 m) as a result of aggradational carbonate growth along the margin. This was followed
by a strong platform progradation over more than 100 km towards the interior of the epeiric shelf. Variations in the type and amount of sediment input, both in time and space, caused major variations in reservoir geometry and properties within these prograding complexes. A major fall in sea level in the Mid-Cenomanian led to exposure and channel incision of the platforms and a major influx of clastics. Fine-grained clastics also covered most of the Lower Cenomanian platform during the initial stage of the following relative sea-level rise. Quartz sands trapped between the exposed carbonate platforms may provide opportunities for stratigraphic traps.
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Multi-disciplinary inversion of Earth models
Authors Olivier Dubrule and Igor Escobar and Danila KuznetsovNow that Earth-modelling packages are used routinely by most petroleum companies, efforts are under way to adapt multi-disciplinary data inversion techniques to better constrain these models by geological, geophysical and dynamic data. There is a convergence between techniques developed in various fields of application, such as Bayesian or geostatistical inversion, regularisationbased optimisation or data assimilation. Geostatistical conditional simulations are usually built using sequential gaussian simulation or by generating non-conditional simulations and conditioning them with a kriged correction. These approaches allow conditioning simulations by any kind of data, as long as these data can be approximated by a linear combination of the inverted
Earth model parameters. Kriging, the average of all realisations, gives the best estimate in a least-squares sense. This is illustrated by examples where we invert multioffset seismic data into higher-resolution realisations of the logarithm of P- and S-impedances. Sensitivities to the various input parameters, such as the variogram, are discussed in detail. In this linear context, a regularized inversion of borehole and seismic data should lead to similar results to those obtained by kriging. In the same
way, both geostatistical stochastic inversion and Kalman Filtering should produce similar a posteriori probability density functions of model parameters. Unfortunately, the forward model cannot always be approximated by a linear operator. This happens when production data must constrain a 3-D dynamic reservoir model. In these situations, algorithms such as Markov Chain Monte Carlo (MCMC) are required. Ensemble Kalman Filtering (EnKF) appears to be less time-consuming than many other MCMC methods, albeit it is not quite as rigorous. An example is given of a recent application of EnKF to an inversion problem on a UK field.
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A novel approach to reservoir characterization using seismic inversion, rock physics and Bayesian classification scheme
More LessRock-physics analysis can provide the relationship between the parameters (or seismic attributes) that govern seismic-wave propagation (e.g. Vp, Vs and density in isotropic media) and the reservoir property of interest, such as rock or fluid type, porosity, pressure and saturation. In this process, we need to account for the quality of the seismic data and derive the appropriate uncertainties associated with the seismic data, such as noise, resolution, and inversion artifacts into the reservoir property estimation. In this presentation, we show how to quantitatively propagate seismic data quality issues such as resolution, noise, and inversion accuracy into the lithology estimation in a clastic basin. The method consists of several steps: seismic inversion to obtain elastic
parameters, petrophysical well-log analysis to define a classification scheme based on Bayes’ Theory and probability density functions (PDF); upscaling the PDF’s to seismic scale using Backus’ Theory and finally, applying the final scheme on seismic attributes (Vp, Vs and density) derived from the first step. The use of full-waveform inversion and Bayesian classification techniques provides a mathematical framework that enables us to model and directly relate data quality input into the uncertainty associated with reservoir properties prediction. The final output of this process is a map in 2-D and a cube in 3-D, of rock and fluid types with confidence levels associated with each property at each common mid-point (CMP) and time sample. We illustrate the
procedure with examples from several clastics basins: Gulf of Mexico and India. This methodology can be easily applied to data from carbonates areas as well where inversion techniques are known to yield porosity, pay and fracture properties.
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Designing seismic surveys in Greater Burgan field, Kuwait, utilizing forward modeling concepts
The Greater Burgan field consists of the Burgan, Magwa and Ahmadi structures. The Burgan structure is an anticlinal dome with a large number of faults. The three main reservoir units in the Greater Burgan field are the Wara, Mauddud, and the massive Burgan sandstones. The deeper reservoirs, namely the Lower Cretaceous Ratawi and Minagish limestones and the Jurassic Marrat Formation also contain significant oil reserves but are less substantial. Between 1976 and 1987, 2-D seismic data were acquired across the field. From 1996–1998 3-D conventional seismic data was acquired and during 2005, two pilot surveys were acquired utilizing single-sensor technology to assess the applicability of this technology in enhancing both spatial and temporal resolution.
Processing and analysis of legacy and single-sensor data indicated that the signal/noise ratio and bandwidth of the reflection response might be strongly influenced by near-surface transmission effects. We used finitedifference modeling to understand these effects and to test whether various acquisition techniques employing surface and buried sources and/or receivers might improve data quality. Near-surface visco-elastic property estimates, derived from log data, combined with geostatistical simulations of lateral Earth properties were used to generate 1-D and 2-D models. These data were processed to illustrate the effects of the shallow geological section on deeper reflection returns. It is anticipated that based on this study future field trials can be designed so as to provide a step change in the seismic data quality in the Greater Burgan field.
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Controlling structural uncertainties in static and dynamic modeling of faulted reservoirs
More LessModeling and reservoir management became an issue in an highly faulted onshore Abu Dhabi field. This presentation reviews the methodologies of controlling structural uncertainties in building the 3-D geological model for the reservoir. The great number of faults and their components such as throw, continuity and segmentation were the major issues in building the structural framework of the model. Integration of well logs and seismic data was implemented to enhance the seismic interpretation, aiming at defining the sub-seismic fault patterns, types and throws. Special attention was focused on the conductive nature of the fault plane and the communication among reservoirs. The driver behind this analysis was the recognition from available dynamic sources that the reservoir zones at the fault planes act as hydraulic communication corridors and have a controlling influence on the reservoir development strategies. Moreover, fault information derived from different seismic interpretation has not effectively clarified the issues. More than 30 wells that intersect faults were reviewed to define the fault throws accurately. The throw of many faults were found to be greater than interpreted from seismic data. Other faults were characterized as fault zones composed of many sub-seismic faults. In addition, the borehole image logs over the fault zone indicated conductive features within the fault plane. This investigation improved the understanding of zonal juxtaposition at the faults and the potential of hydraulic communication pathways between the reservoir zones. As a consequence of this work, both the 3-D static and dynamic models became more robust.
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Well placement services used in optimizing production in a large carbonate reservoir
Authors Osama El-Gendi, Rafael Cullen, Waleed Jawad and Sr.and Marian PopescuThe Ratawi reservoir in the Wafra field is a Lower Cretaceous oolitic limestone located in the Partitioned Neutral Zone between Kuwait and Saudi Arabia. The development of the field started with 95 vertical wells, which were drilled between 1956 and 1999. The strong water drive resulted in severe coning in the vertical wells in 1999, a very successful campaign of horizontal drilling commenced (new drilling and horizontal sidetracks). As a result, Ratawi production increased 50% in a 2-year period. The horizontal development plan can be divided into three phases: (1) 1999–2002: 53 horizontal wells were drilled geometrically, using only MWD/gammaray measurements; (2) 2003–2004: 41 wells were drilled using geostopping strategy based on resistivity; and (3) 2005 to present: 26 wells were drilled by geosteering, well placement, using the geological and log-while-drilling resistivity forward model. In this phase geosteering was crucial to remain in a very narrow target of ± 5 feet from the top of the pay zone and away from water coning, water breakthrough and the current oil water contact. Due to the successful implementation of the well placement services, all 20 planned horizontal sidetracks wells for 2007 will be drilled using this method. This case study highlights the benefits of steering in field development in terms of efficiency improvements in geological analysis. It also shows how well-steering decision-making maximized oil production through optimum well placement.
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Locating and evaluating bypassed oil in the Minagish Oolite reservoir, Minagish field, West Kuwait
More LessLocating and producing bypassed oil due to water injection is one of the most challenging problems in reservoir management. A successful case from Minagish field in west Kuwait is presented. The Minagish Oolite reservoir is a limestone sequence, about 400 ft thick, whose facies consists of high-permeability ooidal grainstones, interbedded with low-permeability facies that act as baffles and barriers. A tarmat zone is known to occur at the base of the oil column leg. Integration of well-surveillance, geological and 3-D seismic data led to a better understanding of the distribution of bypassed oil above the oil-water contact (OWC) and/or tarmat. Also simulation sensitivity study included core studies, analysis of offset wells, and inverted 3-D seismic data indicated the possibility
of high oil production rates. A 78° deviated well was drilled down the northeast flank of the Minagish structure. The geological uncertainties associated with this well path were: (1) structural top; (2) reservoir quality; and (3) the presence and thickness of tarmat zone(s). To minimize the risk associated with these uncertainties, two advanced measurement technologies were utilized while drilling. A magnetic resonance imaging LWD (logging-while-drilling) tool was employed to characterize fluids in real time to discriminate bypassed zones of light oil from tarmats. Also, laser-induced breakdown spectroscopy was used to measure the elemental geochemistry of cuttings while-drilling, in order to chemostratigraphically confirm borehole position and identify tarmats. Tarmats could be identified with this technology from elevated levels of Ni and V (and sometime S) in the tar mat zones. Use of these technologies resulted in the identification of two zones of mobile oil in the upper reservoir above the tarmat, as well as a highpermeability layer influenced by water coming from nearby injector wells.
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Effect of clay content on Tertiary oil recovery
More LessThis work deals with the study of oil displacement by surfactant slug driven by a protective slug of a polymer solution against the driving water. The study is performed on a dimensionally scaled laboratory model. The used porous medium consists mainly of packed sand, but with variable percentages of clay. The results indicated that the recoverable oil is generally affected by both the surfactant slug concentration and clay content. It is directly proportional to the surfactant slug concentration and inversely to the clay content. An optimum value of surfactant slug concentration at each clay content was also determined. The Tertiary oil recovery of a sandstone reservoir, like that of the Rudeis formation pay zone in July oil field can by increased with increasing the surfactant slug concentration according to three considerations: (1) In the case where the clay content is less than 10%, it is more efficient to use a large pore volume of surfactant slug with low concentration 4–5% (2) For clay content greater than 15%, it is recommended to use a small pore volume of surfactant slug, with high concentration (greater than 5%) to compensate for the surfactant loss and consumption. (3) When clay content exceeds 20%, it is not recommended to use the surfactant polymer flood method.
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Near-surface attenuation estimation of P and S waves from Middle East data
Authors Nizare El Yadari and Fabian Ernst and Wim A. MulderSeismic waves propagating through the Earth are attenuated by conversion of a fraction of the elastic energy to heat. In seismic studies, attenuation provides more information about rock properties than available from seismic velocities alone. This is particularly important for the characterization and monitoring of hydrocarbon reservoirs because attenuation affects both the amplitude and the phase of the seismic data. In laboratory, as well as field measurements, accurate estimation of attenuation is difficult since seismic amplitudes are not only affected by intrinsic damping, but also by other mechanisms such as geometrical spreading, reflections, refractions, scattering and topography. These effects should be accounted for if we want to measure the true intrinsic
attenuation. Current attenuation-estimation methods lack accuracy and rarely use the complete seismogram for recovering attenuation properties. To improve this situation, we developed a method to recover the nearsurface attenuation properties for realistic geological settings. The method was based on visco-acoustic wavepropagation modelling and included the influence of the source wavelet and the presence of significant surface topography. The technique provided an acceptable result when applied to a data set recorded in the Middle East. Here, we extend the method to the visco-elastic case. Numerical simulations and measurements on field data demonstrate its effectiveness.
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What would be the minimum subsurface information before making a decision to develop the field? A case study from El Toor field, Muglad Basin, Sudan
Authors Musab Mohamd Elamhi and Ahmed Abdalla MohammedThe El Toor field was discovered in 1996 and oil production started in early 2000. Cumulative production as of 2004 was 34 million stock tank barrels (MMSTB). El Toor is a fault-bounded anticlinal structure in the Muglad Basin, Sudan. The main reservoir consists of the sandstones of the Lower Cretaceous Bentiu Formation. The Upper Cretaceous Aradeiba E and F sands are secondary oil accumulations. Both sandstone reservoirs are layered and separated by continuous barriers over most of the field. After one year of sustained production, wells started to produce water. Both PCP and ESP are used for artificial lift. A team from the Sudanese Petroleum Corporation (Sudapet) has conducted a field development plan (FDP) to evaluate long-term production, reserve
estimation and techno-economics. The El Toor field FDP will be presented as a case study. The FDP study maximized our geological and reservoir knowledge of the field and specifically the lateral quality of the reservoirs. The subsurface information that was required for the FDP included: (1) seismic data control; (2) structure maps; (3) pay-zone thickness; (4) facies information; (5) petrophysical data; (6) core analysis; (7) fluid contact; (8) fluid properties; (9) water salinity; (10) estimated original-oil-in-place; and (11) well test analysis. The Greater Nile Petroleum Operating Company provided Sudapet with all the available subsurface data. The main problem was the lack of core and VSP data and accordingly data from neighboring fields was used. This resulted in uncertainty for the seismic velocity and difficulty in correlating core porosity to log porosity. The study recommended cutting cores and running vertical seismic profiles (VSP) in the future infill wells.
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Potential of Iraqi oil system
By Karim AkrawiEarly exploration surveys in Iraq started at the end of 19th Century. In 1901 the first exploration well in the Middle East, Chai Sorkh-1, was drilled in northern Iraq by a German Company. In 1909, using an old cable tool drilling rig, the first discovery well, Chai Sorkh-9, encountered heavy oil. The first commercial discovery in Iraq was in the Naft Khan-1 well near the Iranian border. In 1925 the Iraq Petroleum Company (IPC) obtained a concession agreement that covered nearly all of the country for 75 years, without relinquishment. In 1927, the first significant oil discovery in Iraq was in well Kirkuk-1, which tested about 100,000 barrels of oil per day. The Iraqi resources are unique when compared to other Middle East countries because Iraq is one of the vastest and least-explored countries in the region. It has an ideal petroleum system with multiple source rocks, reservoirs, cap rocks and trapping systems. The petroleum system extends from the shallow Cenozoic down to deep Paleozoic sequences. Iraq may prove to have one of the greatest petroleum resource bases in the world, with potential oil resources in excess of 215 billions barrels and proven reserves in the region of 114 billions barrels. Moreover, its exploration and development costs are low – amongst the lowest in the Middle East countries. Iraq also is estimated to contain at least 110 trillion cubic ft of natural gas. The country is a focal point for regional and international security issues. Nevertheless, Iraq’s oil is especially attractive to the major international oil companies for several reasons including geographical location, low-risk exploration, low cost per barrel, good oil quality, multiple pipeline access and huge recoverable reserves.
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Diagenetic history and its control on reservoir properties in a heterogeneous carbonate field, Kangan/Dalan Formation, Iran
A section of 445 m through the middle-upper Khuff Formation from three wells was selected for the study. A detailed description of the depositional facies and depositional cyclicity was first performed. The diagenetic processes were described by investigating more than 800 thin sections. A paragenetic sequence was established and the most important diagenetic processes with respect to reservoir quality were identified. All thin sections were described and categorized according to diagenetic facies. Important factors in this type of classification are mineralogy, cement type, cement volume and poretypes. The distribution of diagenetic facies will typically not correspond to the lithofacies distribution, since similar lithofacies may be subjected to different diagenetic
processes, even within short distances. However, a higher-order correlation between sedimentary units and diagenetic facies can be demonstrated. The study has shown that this reservoir has been subjected to heavy diagenesis and that these processes, to a large degree, have altered the primary properties of the sediments. A better correlation between reservoir quality and diagenetic facies, rather than to sedimentary facies, can be demonstrated. The diagenetic overprinting therefore has a major control on reservoir quality distribution in the section, which therefore has important implications for the fluid-flow properties of the reservoir. The diagenetic facies have been grouped into associations according to their reservoir properties. These groups were identified with a high level of confidence on wireline logs making it possible to predict diagenesis and reservoir type outside cored sections.
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Geophysical reservoir monitoring: Where we are!
In our land environment, areal reservoir monitoring is not just 4-D seismic. It can best be achieved by a combination of various geophysical techniques integrated with well-based surveillance methods. These techniques include active seismic (surface and downhole), passive seismic (microseismic), surface deformation (GPS and satellite), electromagnetic induction, and gravity measurements. Enhanced oil recovery (EOR) projects are the prime candidates for the application of geophysical reservoir monitoring techniques because of the expected large acoustic effect and the large potential value. With EOR techniques becoming ever more important the use of reservoir monitoring techniques will increase significantly. Over the years several blockers for time-lapse
(4D) seismic have been identified including: (1) limited changes of acoustic properties at seismic scale caused by low yearly production rates, (2) poor sweep, (3) stiff carbonate matrix, (4) dense surface infrastructure, (5) small areal scale of an injection pattern, (6) lack of suitable baseline surveys, and (6) difficult reservoirs. The critical success factor for those geophysical reservoir-monitoring projects is the full integration with the well-based monitoring data into the dynamic reservoir model. Involvement at the beginning of a field development program by geophysicists is essential for the success of such projects, as tailor-made solutions require adequate attention for project management, scoping, justification, technical design, tendering and contracting. Based on recent experiences a five-step approach evolved for geophysical reservoir monitoring projects. These include: (1) opportunity screening and selection of relevant technologies, (2) detailed design, (3) implementation, (4) data acquisition and processing, and (5) detailed integrated interpretation.
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A fully-integrated approach for rock typing: A new approach to reservoir characterization
More LessThe goal of this study was to develop a methodology for rock-typing in reservoir characterization and modeling. Our proposed method is a multi-disciplinary approach to identify the optimal number (statically and dynamically) of effective rock-types from well logs, core descriptions, routine core analysis and Special Core Analysis (SCAL) data, based on partitioning, correlation and comparability. This approach was used with the aid of multi-variate statistical and neural-network methods. The method consisted of three parts: (1) data partitioning and electrofacies determination using multi-variate statistical methods of Principal Component Analysis (PCA), cluster analysis and neural networks, to classify the data into a desired number of electrofacies; (2) electrofacies-derived correlation with core descriptions using correspondence analysis for the identification of an optimal number of static rock types; (3) dynamic rock-typing (DRT), which is determined by the interpretation of SCAL data (capillary pressure and relative permeability curves) within flow units. We applied our technique to a recently discovered giant carbonate reservoir in southern Iran. We focused on limited data from six exploration wells and sought more accurate results to define rock types for an effective
model and reservoir simulation. In this reservoir, by applying the proposed methodology, seven electrofacies were identified from well log data. By using correspondence analysis on the identified electrofacies and core description facies, five static rock types were recognized. At the final stage, two dynamic rock types in which fluid flow occurs were obtained using SCAL data of available core samples.
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Ara stringer carbonate modelling: A case history
More LessThe Ediacaran-Early Cambrian Ara Group intra-salt carbonates located in the South Oman Salt Basin are a unique hydrocarbon system, which currently produce oil and gas from the oldest (producing) reservoirs to be found. The depositional model, facies associations and subsequent diagenetic overprint of these reservoir units provide a challenge to reservoir description and static model construction. A field in southern Oman offers an excellent example of how these reservoirs are modelled. The first step is to capture the uncertainties in facies architecture and property distribution. The second step involves integrating these uncertainties iteratively with dynamic data to produce a robust reservoir model. The field was discovered in 1978 and was brought on stream
in 1982. With ever increasing gas-to-oil ratio (GOR), additional oil production is constrained by the ability to handle the produced additional gas. A robust depositional model exists for the A4C Ara Group carbonate stringer. The reservoir zonation is based on sequence stratigraphic correlations that form the framework for the reservoir architecture and reservoir zones. Reservoir properties are highly variable. There is evidence for a porosity/depth trend, which may or may not be related to porosity reduction below a hydrocarbon-water contact. There is pervasive salt, anhydrite and bitumen plugging throughout the reservoir, however the effects of these plugging agents are localised. The A4C stringer exhibits an excellent relationship between facies and porosity, with porosity modelling biased towards facies, using facies transition simulation. There is no evidence of compartmentalisation, as confirmed by interference and formation pressure data, which exhibit good connectivity and communication between the wells. Flow units have been identified based on the integration of static and production log data. These have improved the history-match for the field and also our ability to predict production and GOR from the producing wells.
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Supporting exploration and production with satellite radar data processed by means of the PSInSAR™ technique
More LessPermanent Scatterers SAR Interferometry (PSInSAR™) is today one of the most advanced and successful remote sensing technology used for surface deformation monitoring. In PSInSAR™ long series of satellite radar acquisitions, gathered repeatedly over the same target area, are processed. The analysis resolves, with millimetric precision, surface motions and small-scale features, including displacement rates of individual targets as oil pump, pipeline, plants, buildings, etc. PSInSAR™ data provides a depiction of spatial deformation over the surveyed area with an unprecedented accuracy. Information about surface displacements leads to a better understanding of the terrain and better coordination of production drilling. During production, the possible risks to the local environment can be continuously monitored. The dynamic of ground displacements of an oil-field area in the Middle East, subsidence phenomena and seismic faults in North America and Europe are some of the case studies that will be presented. These
examples will show the potentialities of the PSInSAR™ in assessing the environmental impact of drilling activities and storage areas.
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Geomechanics contribute to improved well-delivery in deep gas wells, northern Oman
Gas is being developed from the Lower Cambrian Amin Formation at depths of over 4,000 m (true vertical depth sub-sea) in northern Oman. Development drilling in some of the fields has been hampered by well stability problems in the overburden, as well as in the reservoir sections. An extensive data gathering (including timelapse calliper) and geomechanical analysis program was executed to understand the mechanism that control well stability. The derived geomechanical model for a specific northern Omani field confirmed a present-day stress environment with high horizontal compression (in excess of the overburden) as seen elsewhere in northern Oman. In addition, stress orientation and magnitudes appear to vary somewhat across the field, probably due to the proximity of a major active fault zone close to the field. These ambient stress conditions strongly influence wellbore stability during drilling. Five major well failure mechanisms were identified: (1) clay stability, (2) rock matrix failure, (3) fault-related failure, (4) fracture-related losses, and (5) fracture-related rock failure. Time-lapse caliper logs indicated that rock-matrix failure occurs rapidly, after which the borehole becomes stable for at least two months. Utilizing this information, upper and lower mud-window bounds for future vertical development wells were calculated. Subsequently, optimal mud-weight plans for different hole sections, including mediation plans for the various failure mechanisms, were developed. Following the implementation of the study results, together with further optimisation initiatives, significant gains on well-delivery times have been made by up to 50%.
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3-D visualisation on a plate scale model over the Middle East and North Africa
Authors Adam Finn, David M. Casey and D. Macgregor and Peter R. SharlandWith continuing improvements in technology, it is now possible to develop plate-scale regional 3-D subsurface models. We present a new 3-D approach towards understanding stratigraphic development at plate-scale rather than the more traditional field- or play-scale approach. This development requires consistent stratigraphic picks across continents – we have developed a global sequence stratigraphic model that allows us to achieve this. Regional depth maps have been constructed from public sources and then constrained to stratigraphic picks in many hundreds of published wells. Importing these surfaces into an RMS Cube on a grid of 1,000 m x 1,000 m, with dimensions of 3,000 km by 8,000 km, provides a striking plate-scale visualisation tool. Stratigraphic Modelling functionality allows the generation of intermediate surfaces - whilst following set rules, i.e. tie to wells, truncate above/below. Multi-angle cross-sections and views of the regional depth maps enable rapid assessment of adjoining basin stratigraphies,
from which potential seals, reservoirs and sources rocks can be examined. Once the regional depth maps have been constrained first, second and third-order isopach maps can be generated, identifying areas of sediment accumulation and subsidence. 2-D Gross Depositional Environment maps can be draped over corresponding 3-D horizons providing a powerful visual prediction tool for the locations of possible reservoirs. This also enables basin-scale datasets to be potentially extracted from the plate-scale model and developed into 3-D flow simulation grids, allowing petrophysical cell properties and transmissiblities to be entered. All of this offers the opportunity to undertake detailed regional analysis of petroleum systems.
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A novel pre-stack inversion technique investigating a carbonate reservoir’s rock properties
Authors Michael Fleming, Sarah Corrie and Gary Yu and Gary PerryA case study is described that investigated rock properties in a carbonate reservoir. The study used a novel pre-stack seismic inversion technique that integrated both broad-bandwidth seismic data and borehole data into the inversion workflow. The study used a 3-term pre-stack inversion methodology. The methodology is based on the application of the Aki and Richards linearized Zoeppritz equation for P-wave reflection amplitude as a function of incidence angle. A conditioning sequence was applied to the input pre-stack time-migrated gathers including, critically, an imaging step that provided broad-band, high-frequency seismic data. This highfrequency conditioning provides a stable wavelet across the seismic gather. This in-turn allowed both a better measure of the curvature term in the three-term equation, and also constrained the Earth model. Rock reflectivities were calculated from the amplitude-versus-offset (AVO) terms and integrated for the rock properties Pwave velocity (VP), shear modulus (μ) and bulk density
(ρ), with well logs used to constrain the inversion at various stages. These rock properties were combined with a macro-Earth model (created using well data) and high-frequency gather velocity analysis to yield absolute rock properties. The picked horizons were used to guide model population. A key step in the workflow was the generation and analysis of seismically derived and borehole-constrained elastic modulo cross-plots that allow the combination of several elastic parameters into a single composite geobody attribute. The visualization of such attributes, using state-of-the-art computer graphics techniques provided a valuable tool for understanding and interpreting reservoir lithology and fluid content.
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Production logs and well shut-offs in a GOGD giant field
New chemical and mechanical shut-off technology has been applied to a giant carbonate field that is being produced under mixed gas oil gravity drainage (GOGD) and waterflood. The shut-off technologies have aimed to minimise unwanted gas and water influxes by isolating fractures and permeable sub-layers. The trials included: (1) chemical shut-offs in the heels of horizontals to prevent vertical gas coning (fracture/cement bond issues); (2) mechanical shut-offs in the toes to seal gas under-runs through highly fractured layers; and (3) use of external casing elastomers (EZIP) to compartmentalise wells, and even isolate individual fractures malignant to well performance. Wellbore influxes were mapped-out from a campaign of horizontal-well production logs. The results included shut-in pass water-flow logs run in water-cut GOGD wells. They illustrated the inflow and exit of injected or aquifer water at individual fractures that used the wells as conduits for cross flow. Drill-fluid losses into producers have recently provided likely fracture pathways, as confirmed in one case with production logs. Some of these pathways follow a fracture trend that was identified in outcrop data overlying the field but not previously considered in the subsurface. Monitoring the outcome of the shut-off trials has further revealed reservoir behaviours.
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Preservation of pre-rift sediments and development of accommodation zones during the initial phase of Red Sea rifting
Successful exploration in the Red Sea requires a thorough understanding of the structural controls on reservoir and source-rock distribution. Pre-rift reservoirs are one major exploration objective, mainly comprising fluvial to shallow-marine clastics of Early Eocene, Paleocene and Cretaceous age. In the giant October and Ramadan fields in the Gulf of Suez, hydrocarbons sourced from the Upper Cretaceous “Brown Limestone” are produced from pre-rift reservoirs ranging from Cretaceous to pre-Carboniferous in age. Across the Red Sea region, the present-day distribution of pre-rift reservoirs and source rocks is controlled by both depositional paleogeography and the subsequent post-depositional structural history. The underlying Neoproterozoic basement fabric exerts
a fundamental structural control on preservation of prerift sediments. During the initial rifting phase in the Late Eocene to Oligocene, pre-rift sediments were preserved in hanging wall blocks formed by extensional reactivation of two major sets of sub-vertical lineaments: Najd shears trending (azimuth) 125–130o, and faults trending N-S. Along the Saudi Arabian coastal plain, pre-rift sediments are found in hanging walls located in the SW quadrant of the intersection of these two sets of basement lineaments.
Accommodation zones in the Red Sea region formed during the initial rift phase, and their location and trend is again related to the underlying Neoproterozoic basement fabric. The orientation of the Duwi accommodation zone in the northern Egyptian Red Sea is directly linked to the underlying Najd shear trend. Similarly, the newly identified Jeddah accommodation zone in Saudi Arabia (mapped from 2-D seismic data) follows the same Najd shear trend observed in the surrounding basement rocks. Discovery and analysis of the Jeddah accommodation zone will enable more accurate structural mapping of pre-rift fault blocks in the subsurface, together with more accurate prediction of potential syn-rift (Miocene) reservoirs.
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Silurian Tanf Formation prospectivity in the Euphrates Graben Petroleum System, Syria
This study aims to characterise the potential of Silurian strata as a co-source rock in the Euphrates Graben, Syria. The main Paleozoic source rock in the Arabian Plate is found in the Lower Silurian section (Tanf Formation in Syria), which is mature to overmature in the study area. However, the two main source rocks of Upper Cretaceous age in the study area are carbonates of the Shiranish Formation and the lagoonal, cherty Rmah Formation. 82 oil samples from reservoirs of different ages were
analysed by whole oil gas chromatography and detailed analysis of biomarkers and aromatic hydrocarbons by gas chromatography-mass spectrometry. Additionally, 16 Silurian rock samples are still under investigation for this study. Based on compositional parameters such as the pristane/phytane ratio, three geographical areas representing different depositional environments were recognised. In addition, oils from the southeastern part of the graben seem to be highly mature; for example based on light hydrocarbons and the occurrence of diamondoid hydrocarbons whose concentrations are relatively high due to the thermal cracking of the major oil constituents. In contrast, conventional biomarker maturity parameters had already reached equilibrium values in the oils from the southeastern part of the graben due to overmaturity. The gammacerane index shows relatively high values referring to hypersaline conditions. Therefore oil mixing from different sources has to be taken into account. Because Cretaceous source rocks may also reach high maturity levels, compound specific stable carbon and hydrogen isotopes will be elaborated upon as an additional oil-source rock correlation tool to better understand the potential role of the Silurian strata
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Origin of burial diagenetic illite and its effect on porosity and permeability of Unayzah sandstone reservoirs (Permian-Carboniferous) of Saudi Arabia
More LessBurial diagenetic illite and quartz are the primary cements, which affect porosity and permeability in deep Unayzah reservoir sandstones in Saudi Arabia. The ultimate source of illite is the alteration of feldspar, mainly K-feldspar. Feldspar is altered to kaolinite to varying degrees during early burial. During later burial to depths where temperatures exceed about 100oC, remaining feldspar reacts with kaolinite to form illite via the reaction: K-Feldspar + Kaolinite = Illite + Quartz. The amount of illite that forms is limited by the amount of reactant in least supply (kaolinite or feldspar). When either of the two reactants is exhausted, illite can no longer be generated by this reaction. Accordingly, Unayzah sandstones can be classified as Feldspar-Limited or Kaolinite-Limited
based on which reactant is consumed first and thus is the limiting factor on the amount of illite formed. Feldsparlimited sandstones typically have less diagenetic illite than Kaolinite-Limited sandstones. Feldspar-Limited and Kaolinite-Limited sandstones have distinct geographic distributions. The distributions may partly be related to provenance (original feldspar content), but early invasion of meteoric water into the basin margin is interpreted to have played an important role as well. This early leaching of feldspar partly controls the distribution of Feldspar-Limited sandstones and thus the subsequent distribution of illite. There is no evidence to support continued illite formation directly from feldspar after kaolinite is consumed, e.g. 3KAlSi3O8 + 2H+ = KAl2(Si3Al)O10(OH)2 + 2K+ + 6SiO2.
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Origin and evolution of pore water in coastal and inland clastic sabkhas and salt pans of Saudi Arabia
Coastal and inland sabkhas of Saudi Arabia are primarily quartzose clastic sabkhas. In some cases they have developed on older aeolian dunes now submerged beneath the present-day water table. Models of early cementation of ancient sabkha deposits frequently called for precipitation of carbonates and sulfates from sea water by evaporative pumping: the inflow of sea water through the sabkha to replace pore water evaporated at the sabkha surface. The landward extent of the sea-water influence was usually not addressed. Pore water samples collected along transects from the sea, coastal sabkhas and inter-dunal sabkhas, more than 100 km inland, were analyzed to determine the extent of sea-water influence. Included in this study are pore waters from Sabkha
Matti, one of the largest sabkhas in the world. Stable isotopes, ion chemistry and strontium-isotope composition of these sabkha waters indicated that the influence of marine water is limited to a narrow zone within a few kilometers of the coast. Landward of this narrow band, meteoric water appears to be the sole source of sabkha pore waters and is a significant component in some coastal salt pans. Even in the present-day low-lying, hyperarid desert of southern Saudi Arabia, the water table rises inland and the hydraulic head tends to drive meteoric water seaward preventing incursion of marine water into sabkhas except in a narrow band very near the sea. Results of this study have implications for interpreting early cements in ancient desert sediments like the Permian-Carboniferous Unayzah of Saudi Arabia.
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Geochemical characterization of petroleum in Jurassic reservoirs south of Ghawar field, Saudi Arabia): Implications for the petroleum system
Geochemical characteristics of recently discovered petroleum in Jurassic reservoirs of the Halfah, Yabrin, Dirwazah and Tukhman fields, south of Ghawar field (Saudi Arabia) are different from typical Jurassic crudes in the Abqaiq, Ghawar, Mazalij and other fields. The latter fluids correlate well with the excellent oil-prone source rocks from the Tuwaiq Mountain and Hanifa formations of the Arabian Basin. These classic Ghawar-type mediumgravity oils represent high-sulfur crudes (greater than 1%), have pristane/phytane (Pr/Ph) ratios typically less than 0.8 and contain biomarkers indicating that the oils are derived from source rocks deposited in a marine carbonate environment under anoxic, reducing conditions. Characteristic biomarker parameters that support this interpretation are C29-hopane/C30-hopane ratios that exceed 1.0, relatively low abundances of diasteranes, and dibenzothiophene/phenanthrene (DBT/P) ratios typically exceeding 3.0. The Halfah-Yabrin-Dirwazah-Tukhman crudes, south of Ghawar field, have low-sulfur contents (less than 1.0%), Pr/Ph ratios ≥1.0, C29-hopane/C30-hopane ratios less than 1.0, and relatively high amounts of diasteranes and the C24 tetracyclic terpane. Most of the differences in sterane and hopane biomarker distributions compared to the Ghawar-type fluids appear related to differences in the abundance of clay versus carbonate in the source rocks. These data provide evidence for a source rock organic facies change south of Ghawar field. This presentation discusses recent results related to oil-oil and oil-source rock correlations, genetic relationships, and their implications for exploration in the southern part of the Arabian Basin.
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Information management for the asset team
More LessManaging the growing volumes of information and data is fast becoming a significant issue for most E&P asset teams. Schlumberger Information Solutions has developed a unique set of solutions using the ProSourceTM suite of software to manage across multiple projects and multiple data stores the asset team’s information. Data stores include PetrelTM, GeoFrameTM, OpenWorksTM and FinderTM, with connections to any other data stores that are OpenSpiritTM enabled. Key workflows include, globally searching across multiple projects and multiple data stores using a single application console that centralizes the project data management, eliminating project by project data management. Visualizing the information via GIS or in spreadsheets, automated quality control assurance for data integrity using data compare tools which brings confidence and data consistency to the end user, quality tagging of the data, capturing of milestones of interpretation data into a vendor neutral repository for easy retrieval for partners. Creation of an audit trail for your E&P studies and regulatory reporting. If these solutions fit your E&P needs the ProSource suite of solutions can help you manage your E&P asset teams and minimize the time administrating and maximize the
quality and consistency of the data being used by your asset team.
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Reservoir characterisation of a heterogeneous hydrocarbon field, Khuff (Kangan-Dalan) Formation, Middle East
Analysis of previously unpublished data from a major Middle East gas field has resulted in an integrated study of the Khuff Formation. Conceptual geological models for the field will be presented, providing an opportunity for comparison with other published data in the region. Detailed sedimentological work of three extensively cored wells has enabled the identification of a suite of lithofacies, which are grouped into seven facies associations. Depositional settings range from marine grainshoals, through to restricted tidal flat settings with common evidence of exposure. Shallowing-upwards cycles form the basic building blocks in the sequence stratigraphic framework. Cycles are organised into packages, termed high-frequency sequences (HFS), which possibly reflect
fourth-order relative sea-level variation. At a larger scale, HFS’s are grouped to form four major depositional sequences (K4 – K1). These are comparable to the thirdorder sequence described by Sharland et al. (2001). Cycles show distinct trends in thickness variation, which can be traced in all cored wells. Thicker cycles typically occur within marine ooid-grainstone facies of the transgressive systems tract (TST) of large scale sequences, whilst thinner cycles are more typical of restricted facies of the highstand systems tract (HST). Diagenesis has significantly modified the primary depositional facies. The key diagenetic processes include: (1) cementation: primarily calcite and anhydrite; (2) dissolution: dissolution of grains, in particular ooids; (3) dolomitisation: both early evaporitive (in late HST) and hydrothermal processes associated with faults. Reservoir potential is related to the interplay of primary depositional facies and subsequent diagenesis. The best reservoir quality is associated with dolostones, although overdolomitisation and anhydrite cementation are commonly detrimental. TST grainstone facies are prone to calcite cementation; however, dissolution of grains significantly improves porosity. Conceptual geological models have been built based on the HFS stratigraphic framework, and these models are the input for the flow-unit and geo-modelling.
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First microseismic monitoring results for a Middle East carbonate reservoir: Minagish oil field case study, western Kuwait
During the first quarter of 2006, a microseismic monitoring pilot was implemented in Minagish field, western Kuwait. The target zone was the Minagish Oolite, a microporous carbonate reservoir, about 350 ft thick and around 9,600 ft deep (below mean sea level). The monitoring antenna, an SST-500 wireline tool of four 3C-geophones, was temporarily deployed in an abandoned well on the eastern flank of the field. The purpose of the surveillance was: (1) to assess the occurrence of microseisms induced by the production operations and especially the water injection along the flank; then (2) to characterize such microseismicity; and finally (3) to measure the effective network sensitivity with depth. Such a microseismic pilot survey should provide insight on the
added-value that this monitoring technique may bring to the production and reservoir engineers. During the 50 days of effective monitoring, about 2,000 microseisms were identified and 600 events, from magnitude -2.0 to 0.3, were located. The large majority was distributed on the western side of a NNE-trending line as consistent with the direction of the local oil-water contact. A more detailed analysis also highlighted clusters of microseisms between injection-production doublets. In fact, one doublet was believed to be connected, which has been confirmed. Additionally, the depth survey showed that microseismic monitoring was still efficient above the Shu’aiba Formation. The pilot’s objectives were successfully attained and the results were beyond our expectations. Hence, it is proposed to deploy a cost-effective and optimized microseismic network suitable for the entire Minagish field.
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Production attribute mapping workflow to assess remaining resource potential and distribution of water in the First Eocene reservoir at Wafra field, Partitioned Neutral Zone, Saudi Arabia and Kuwait
More LessThe First Eocene reservoir at Wafra field was discovered in 1954 and has produced about 290 million barrels of 17-19o API, high sulfur oil. The estimated oil-originallyin-place exceeds 9 billion barrels. Previous studies, which have relied on static data, were not able to quantitatively predict water-cut and water-saturation trends within this reservoir. A production attribute mapping workflow was developed that incorporated static and dynamic data. The workflow has been used to define the current distribution of oil and water within the reservoir and provide an estimate of remaining hydrocarbons inplace (RHIP) by area and stratigraphic layer. Estimation of RHIP utilizes a workflow in which full-field saturation maps representing reservoir conditions at the end of 2006 are generated using production attribute mapping techniques. The saturation map is combined with original net pay porosity-thickness values to generate a map of RHIP. Defining the current distribution of water within the reservoir is a complex task due to the long
production history and large number of wells in the reservoir. A workflow was developed to map water-cut through time, with a focus on the earliest producers in the reservoir. Preliminary results suggested that the waterfronts initially move primarily from the north and south in structurally low areas. After about 12 months, the waterfronts begin to converge and appear to fully converge within about 120 months. Migration from the southwest may not be related to structure, but may be influenced by facies distribution. Results from the production attribute workflow will be used as part of on-going reservoir management decisions as well as to update current static and dynamic reservoir models.
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Tectono-stratigraphic comparison of two petroliferous provinces in the northeastern Iraqi portion of the Arabian Plate
More LessNortheastern Iraq has two contiguous, petroliferous tectono-stratigraphic provinces that lie at similar regional structural elevations and yet have contrasting play elements, owing to their different Late Mesozoic to Cenozoic evolution: (1) Kirkuk embayment foldbelt (“Kirkuk”, from the Hamrin Mountains northeastward in the Kurdistan part of Iraq), with Tertiary reservoirs in high-relief anticlines; and (2) northwestern Mesopotamian foreland (“NW Mesopotamia”, the northern Mesopotamian Plains, from the Hamrin Mountains southwestward to the Euphrates River), with Cretaceous reservoirs in low-relief traps. Both provinces were within the Gotnia Basin during the Late Jurassic and in similar carbonate-prone depositional environments until the Late Cretaceous. Late Cretaceous obduction of Tethyan ophiolites onto northeastern Arabia created an orogenic load and sedimentary provenance that affected Kirkuk and NW Mesopotamia differently. Kirkuk was in a NWtrending foredeep, with clastic input on its northeast flank and deep-water, reservoir-poor carbonates on its southwest flank. NW Mesopotamia remained part of the Arabian platform with deposition of reservoir-prone carbonates. Tectono-stratigraphic differentiation between the obduction-related Kirkuk foreland basin and the NW Mesopotamian platform lingered through the Paleogene and Early Miocene. The Kirkuk foreland accumulated several hundred meters of Eocene to lower Lower Miocene carbonates that are its principal reservoirs. In contrast, NW Mesopotamia accumulated much thinner Paleogene to Lower Miocene carbonates. Collision of the Arabian and Eurasian plates in the Neogene created first the Taurides and then the Zagros Mountains. Kirkuk underwent northwestward-increasing truncation of Paleogene reservoirs beneath a pre-late Early Miocene unconformity, then rapid burial in the Zagros Foreland Basin, and finally uplift, as large anticlinal traps grew as far southwest as the Hamrin trend. Meanwhile, NW Mesopotamia subsided as part of the Zagros Foredeep.
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Structural genesis of hydrocarbon traps of Iraq
More LessIraq’s hydrocarbons (134 billion barrels of oil and oilequivalent: OPEC, 2004) occur in many structural habitats. Using major fields, we illustrate structural styles from Iraq’s four main hydrocarbon provinces and give interpretations of their genesis. The Kirkuk embayment in northeast Iraq involves Late Miocene and younger SW-verging, fault-propagation folds (Zagros-driven) fed by slip along Lower Jurassic detachments. The principal Tertiary reservoirs at the Kirkuk field include an Eocene through Lower Miocene carbonate-prone section beneath a lower Middle Miocene angular unconformity along which truncation increases to the northwest. The post-unconformity Middle Miocene section carries the topseal. In southern Iraq, within the southwest flank of the Mesopotamian Foredeep (Zagros Foreland Basin), the major traps (e.g. Rumaila and Zubair fields) are large, N-trending anticlines, each with several crestal culminations and gently-dipping flanks (2° to 4°). The Mesozoic reservoirs are little faulted. Long-lived,
episodic evacuation of infra-Cambrian Hormuz Salt beginning as early as Late Jurassic controlled trap-genesis. Basement grain, reactivated during the Hercynian, controlled the N-S trend of the later evacuation synclines. In contrast, Central Iraq’s Mesopotamian traps have NW-trending basement-involved faults, some of which had reverse slip (transpression?) during both the Late Jurassic and the Neogene and others of which had normal slip (transtension?) during the Late Cretaceous. Iraq’s lightly explored Western Desert has Paleozoicsourced exploration potential at depths much shallower than elsewhere in Iraq, owing to (1) post-Late Jurassic to pre-Albian southward tilting, uplift, and erosion; and (2) Late Cretaceous N-S extension. Iraq’s structural styles reflect variable impact, from one region to the next, of (1) basement grain and faults, (2) Hormuz Salt distribution, (3) Hercynian orogeny, (4) creation of Tethyan passive and transform margins and their destruction resulting from Arabia’s collision with Eurasia.
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Integration of sedimentology, sequence stratigraphy, and seismic stratigraphy of the Lower Cretaceous Shu’aiba Formation in an oil field of northwest Abu Dhabi, United Arab Emirates
The Lower Cretaceous (Aptian) Shu’aiba Formation is an important carbonate reservoir of the subsurface of Abu Dhabi. At an oil field located in northwest Abu Dhabi, the reservoir is comprised of interior platform, platform margin, clinoform belt (prograding wedges) and intra-shelf basin deposits. Sedimentologic and petrographic core description identified 12 lithofacies types, ranging from shallow-marine, rudist-rudstone to deep-marine, planktonic foraminifera wackestone and shale. Caprinids (Offneria sp.) dominate the Shu’aiba platform margin and the proximal clinoform belt. Algalstromatoporoid facies and caprotinid debris are indicative of the distal clinoform belt. Planktonic foraminifera wackestone and shales dominate the intra-shelf basin deposits (Bab Member). The Shu’aiba deposits at an oil field located in northwest Abu Dhabi fit well into the sequence stratigraphic framework established for a giant oil field of central Abu Dhabi. Shu’aiba transgressive and early highstand sequence sets are built by the Ap2
and Ap3 sequences, Shu’aiba late highstand sequence set comprises the Ap4 and Ap5 sequences, and the Bab lowstand sequence set is represented by the Ap6 sequence. However, the platform margin appears to be steeper in northwest Abu Dhabi, as the area of the Upper Aptian (Ap4 and Ap5 sequences) distal clinoform belt is narrower than the one encountered at central Abu Dhabi. Three-dimensional seismic analyses allow mapping of the platform to basin geometries. The areal extent of the interior platform, the platform margin, the clinoform belt, and the Bab Basin can be outlined by seismic cross-sections and seismic amplitude maps. All available data were successfully incorporated in a new 3-D static model, addressing uncertainties in terms of structure,
stratigraphy, and reservoir quality.
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The concept of entrapment: Towards expanding the paradigm
More LessThe current conceptualization and approach of exploration sets a specific timing for hydrocarbon migration and entrapment and certain geometries for accumulation. The simplest of those is the anticlinal four-way dip closure in which the lighter hydrocarbons migrate up-dip due to their density contrast with the water to arrive to a pseudo-stagnant state. Such an understanding of a simple fluid behavior led to the discovery of huge reserves worldwide. Although successful, limiting the migration and entrapment model to only such physical conditions can be limiting to our hydrocarbon-finding ability. An expansion of the migration and entrapment model that recognizes the dynamic behavior of hydrocarbons than just the pseudo-stagnant model can define new exploration
opportunities. The model is supported by analyzed discovery fields, laws of physics, physical and numerical models. The new paradigm states that: (1) hydrocarbons are in continuous movement during basin evolution; (2) entrapment is a phase of the hydrocarbon movement; (3) massive volumes of expelled hydrocarbons continue to move on a geological time scale; (4) perfect seals are not in line with known behavior of even the tightest rock over a geological time scale; and (5) hydrocarbons will
become stagnant only in a site of subsurface hydrocarbon energy minima, which is rarely sustained during the life of an accumulation. The above paradigms define a new set of traps and real examples supported by physical and numerical models are presented. A set of mapping techniques to identify those traps is proposed. The Arabian Platform tectonic and depositional history, and hydrodynamic conditions form a hydrocarbon-prospective region to apply such new concepts and techniques.
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Multi-lateral horizontal well application for improving the oil recovery of a mature field, Intisar 103N, Libya
Authors Mohamed M. Gharsalla and Mohamed B. ElghmariThis presentation examines the performance of a horizontal well with multi-lateral completion in the mature Upper Sabil Reservoir in the Paleocene Zelten Formation in Intisar 103N field. The hydrocarbon trap in an anticline that houses 14.4 million stock tank barrels (MMSTB) of oil-initially-in-place. The reservoir is highly under-saturated with oil of 42° API gravity. The initial field development with a vertical well resulted in a poor recovery, 1.3 million barrels of oil in 19 years of production (equivalent to a recovery factor of 9%). The recovery mechanism in the reservoir is mainly rock-fluid expansion with marginal support from flank aquifers. The poor recovery can be attributed to thin pay thickness, poor reservoir quality, large well spacing, and the lack of pressure support from aquifers. The vertical well revealed a nearly constant production rate for the last 17 years indicating the drainage area is much larger than one well can deplete in a reasonable time frame. The incentive of reducing well-spacing existed but the question was how to reduce the well spacing: by drilling many vertical wells or a lesser number of horizontal wells? A reservoir simulation study in 2003 indicated that drilling vertical wells in a very thin reservoir of poor quality was not cost-effective. Hence, an horizontal well was
drilled and completed at the top of the porosity zone with two lateral legs extending 1,632 and 2,811 ft. Two lateral sections were branched-out from the same spot in the well with a 47° angle between them and completed open-hole in the reservoir. The stabilized oil production rate of the horizontal well was approximately three times greater than that of the vertical well, whereas the drilling cost of the horizontal well was about 1.3 times higher. The production from the horizontal well showed no negative impact on the production performance of the existing vertical well. The oil reserves, as a result of putting the horizontal well on stream, are expected to increase by 1.8 million barrel. It is evident that horizontal wells with multi-lateral completions can improve oil
recovery, accelerate oil production and reduce production cost. The reduced pressure gradient in the reservoir,
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Sedimentation framework and tectonostratigraphic development of the Muglad Basin Sudan
More LessThe Muglad Basin, located in southwest Sudan, forma a major part of the Sudan Rift System, which in turn, is a main component of West and Central African Rift System. The rift started to develop during the Late Jurassic and Early Cretaceous times. This intra-continental rift system evolved through a three-phased tectonic history spanning Berriasian to Cenomanian, Coniacian to Maastrichtian and Paleocene to Pliocene. The sediments in the Muglad rift basin consist of Lower Cretaceous to Upper Tertiary non-marine cyclic sequences of lacustrine and fluvial/alluvial facies and directly rest upon the Proterozoic basement. Concentrating on the first rift cycle, this study reviews the sedimentation framework as a function of subsidence and thermal contraction. The
database is mainly from proprietary exploration work consisting of 2-D and 3-D seismic data, well logs, core and borehole image logs. The Abu Gabra Formation is a typical argillaceous facies dominated by cycles of lacustrine shale prograding to deltaic sands. This lacustrine shale provides good hydrocarbon source rock while the deltaic sand proved to be a good quality reservoir. This cyclicity could be due to the fact that accommodation space was created by rift pulses rather than through continuous subsidence. After the cessation of rifting, thermal contraction probably occurred and created accommodation space, which was then gradually filled by the Bentiu Formation, consisting mainly of arenaceous fluvial sequences. These sands represent main reservoir units in the basin. Seismic data, logs and borehole image logs show a clear angular unconformity between Abu Gabra and Bentiu formations.
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Facies analysis and depositional environment of the Upper Devonian Geirud Formation in the Tuyeh area, eastern Alborz Mountains, northern Iran
Authors Elham Ghouchi Asl and Yaghoob LasemiThe Upper Devonian Geirud Formation is a mixed carbonate and siliciclastic succession in the Alborz Mountains of northern Iran. It was deposited on the passive Paleo-Tethys margin of northern Gondwana. It is over 250 m thick and is bounded by the post-Lower Ordovician and the basal Carboniferous unconformities. Facies analysis of the Geirud Formation in the Tuyeh and adjoining areas of eastern Alborz recognized various clastic, mixed carbonate-clastic, carbonate and storm facies related to a ramp platform setting. The clastic facies comprise inter-bedded sandstone and shale demonstrating fining upward (fluvial) and coarsening upward (deltaic/shoreface) cycles. Cross- lamination/cross-bedding and hummocky cross-stratifications have been recognized in the deltaic and shoreface environments. Mixed carbonate-clastic shoal facies consist of cross-bedded sandy echinoderm bioclast grainstone and fossiliferous subarkose. Carbonate facies comprise girvanella bioclast grainstone (inter-tidal), gastropod/foraminifer
mudstone to packstone (lagoon), echinoderm/brachiopod grainstone (barrier) and bioturbated fossiliferous mudstone to packstone (open marine). The carbonate and mixed clastic-carbonate facies are arranged into meter-scale shallowing upward cycles. Both clastic and carbonate storm deposits related to delta/shoreface, lagoon, barrier, proximal open-marine and distal openmarine environments were recognized. The storm facies fine upwards and are characterized by the presence of basal erosional surface, hummocky cross-stratification, intraformational conglomerates and mixed component of various facies.
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From planting the seeds to harvesting the crop
By Ibrahim GobaAs the world’s largest petroleum company (in terms of proven reserves and production), Saudi Aramco, is acutely aware of the current shortage in specialists in such fields as geology and geophysics. By 2010, the exploration and production industry is estimated to have a 38% shortfall of engineers and geoscientists if no action is taken to fill the gap. This presentation demonstrates how the Exploration Organization of Saudi Aramco focuses on developing geoscientists to meet the present and future demands for geoscientists. To implement Saudi Aramco’s strategy, the company has established a multi-phase process. This begins with the College Degree Program (CDP), a company-wide educational program offering college degree scholarships in a variety of selected specialities. The aim of the CDP program is to introduce the participants, as early as possible, to critical technologies. Under this program the Exploration Organization sponsors a number of carefully selected Saudi Arabian high-school graduates who want to pursue undergraduate degrees in Geology or Geophysics. Exploration nurtures these young candidates through their undergraduate studies and provides them with the guidance necessary to ensure their success. The organization’s role does not end with graduation. To maintain the technical quality of the professionals, these graduates are carefully developed through a series of well-planned programs over a 10 to 12 year span. They attend targeted technical courses during this time, and also participate in directed projects and assignments. The main advantage of these programs is that they ensure alignment of the professional’s individual development and the organization’s business requirements. The most prominent programs are the Professional Development
Program (PDP) and the Specialist Development Program (SDP). The PDP develops newly graduated professionals. This on-the-job training program provides them hands-on training in all the organization’s departments, which complements their graduate studies. The SDP provides more specific and focused career paths supplemented by the guidance of a mentor. The professional becomes a specialist in one of the geosciences. We have established that this initial investment in selection, education,
screening and hiring of candidates, along with focused training and mentoring, returns high dividends. This phase of planning for the future was started in the 1990s. We are now reaping the rewards of this foresight. While many companies are facing recruitment problems, our Technical Development Programs have provided the organization with the critical manpower needed to ensure Saudi Aramco’s position as the leader in the Oil & Gas industry.
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Valanginian-Turonian secondorder sequences from the southern Tethys and their exploration significance
The Valanginian-Turonian stratigraphic sequences described from Arabia by Sharland et al. (2001, 2004) can be grouped into two second-order sequences recognisable in successions from Morocco to Yemen. The analysis of sequences from outside the Arabian Plate has improved the biostratigraphic resolution with which the sequences can be dated and correlated, whilst improvements have also been made to the criteria used for the physical placement of the surfaces in any given succession. Within both sequences the second-order MFS is coincident with an Oceanic Anoxic Event – a time of enhanced production and preservation of organic carbon. Early Aptian MFS K80 calibrates to OAE1a, whilst basal Turonian MFS K140 calibrates to OAE2. Where these MFS occur in intra-shelf basins, they are linked to locally important source rocks - intra-Shu’aiba in the United Arab Emirates, Oman and Iran (K80); Natih B (Oman), Bahloul (Tunisia) (K140). Key second-order sequence boundaries occur in the Early Valanginian (K40 SB) and latest Aptian (K90 SB). Biostratigraphic calibration of these boundaries from correlative conformity locations demonstrates that they are also present in basins across the globe. They must therefore be primarily eustatic in origin. However, across the southern Tethys these sequence boundaries were also tectonically enhanced (primarily in response to increases in Atlantic spreading rates). This drove pronounced clastic sediment supply from the shield and the consequential presence of clastic reservoirs, associated with the lowstand and transgressive systems tracts, overlying these sequence boundaries. Source rocks may also have developed because of freshwater overhang in front of the deltas so formed.
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AVO inversion for Lame’s parameters in a VTI medium and its applications in reservoir characterization
More LessSeismic attribute analysis is a powerful tool in reservoir characterization, seismic interpretation, monitoring and simulation of hydrocarbon reservoirs. Seismic attributes can be used to map geological features, reservoir properties and to interpret depositional environments. Goodway et al. (1997) were the first authors to show how to extract Lame’s parameters (lambda and μ) using attributes that are estimated from pre-stack seismic data. Amplitude-versus-offset (AVO) inversion for Lame’s parameters provides additional insights in complex geological settings. Conventional methods for extracting Lame’s parameters consider relations between changes in seismic amplitude and the offsets of the source and receiver. These methods, however, are only effective in
an isotropic medium. On the other hand, the properties of anisotropic rocks are important for seismic imaging, seismic interpretation and reservoir characterization. They also affect the quality of pre-stack seismic analysis, amplitude analysis, velocity analysis, and rock-property inversion. In this presentation, we introduce a formula for extracting Lame’s parameters in a VTI medium. We show the application of the inversion method to this formula for extracting reflection coefficients of P- and S-wave velocities in a VTI medium. Finally, we show the application of this method to a carbonate reservoir in southwest Iran. Results of this research indicate that if anisotropy parameters are used in steps while extracting lambda and μ, we can distinguish between reservoir zones with different lithology and fluid content.
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Mapping the Upper Shuaiba in northern Oman: How to get the best out of difficult seismic data and specifically how to pick the formation top and identify the presence of good reservoir?
Authors Christophe Gonguet and Kees De Leeuw and Gordon CoyThe Upper Shu’aiba stratigraphic play is being pursued in the northern part of Petroleum Development Oman’s (PDO) Block 6 (Petroleum Development Oman). To date, three fields have been discovered and our understanding of the play and its seismic expression has progressed significantly. The area is mostly covered by 3-D data of poor to medium quality, characterised by the pervasive presence of inter-bed multiples. Furthermore, when good reservoir subcrops the Nahr Umr regional shale, there is no impedance contrast and the expected Top Shu’aiba hard-kick will actually be Base Reservoir. The Bab Basin is a shallow basin with limited accommodation space showing progradation of low-angle clinoforms, alternating clean carbonate and argillaceous units. The targeted reservoir units generally consist in proximal, high-energy shoal/build-up facies. A regional high-resolution sequence stratigraphic model shows progradational H207 infill of the basin from its respective margins. The combined seismic response of successive inclined units may cause a tuning effect. In these cases some weak clinoform geometries may be seen on vertical sections and tuning bands appear on amplitude maps in spectral decomposition seismic volumes. The seismic approach is coupled with building and updating the sequence based PetrelTM 3-D geological model. This integration has become an essential part of our exploration process. Finally, we increase the value of the seismic data from reprocessing (multiple attenuation and velocity picking) and sparse-spike inversion. Also our current acquisition of new higher fold 3-D data and better sampling of the near-surface should contribute to improved imaging of the reservoir units.
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Sequence stratigraphy and depositional history of the Eocene-Miocene carbonates and evaporites in the subsurface of the northern Mesopotamian Basin, northeast Iraq
Authors George Grabowski and Chengjie Liu and Augustus O. WilsonOur integrated study of plankton biostratigraphy, petrography, Sr87/Sr86 age dating, and well-log correlation for IPC wells is leading to a new, unified sequencestratigraphic framework and a revised depositional history for the Middle Eocene to Lower Miocene in
northeast Iraq. Subaerial-exposure and flooding surfaces define progradational shelf-margin sequences in the Upper-Middle Eocene limestones of the Avanah and Pila Spi formations. The shelf margins become steeper towards the top, reflecting increasing accommodation in the basin. Time-equivalent basinal carbonates of the Jaddala Formation have flooding surfaces and interpreted hardground surfaces that define parasequences that are uniform in thickness. Two sets of progradational shelfal to shelf-margin limestones of the Oligocene Kirkuk Group pass laterally into basinal globigerinid limestones. Tops of shelfal sequences were subaerially exposed and eroded, and the prograding shelf margins again become steeper towards the top. The Ibrahim Formation is time-equivalent to the Tarjil Formation and part of the Palani Formation and in places to the upper part of the Jaddala. The Anah and Azkand formations are approximately time-equivalent to the Bajawan and Baba formations. The Serikagni Formation consists of
many parasequences of basinal carbonates defined by regional flooding surfaces and is Chattian. It is overlain by the Euphrates Formation, a shelfal deposit with multiple higher-order cycles bounded by subaerial-exposure surfaces and anhydrites. The overlying Dhiban Formation consists of basin-filling anhydrite and argillaceous-limestone beds. The anhydrites are dated to 21.0–22.2 Ma, placing the Euphrates and Dhiban formations within the late-Aquitanian lowstand. The overlying Jeribe Formation consists of shelfal limestones of the Late-Aquitanian HST and the basal-Burdigalian sequence, which are separated by a regional subaerialexposure surface. Shoaling-upward parasequences stack aggradationally and lap onto the margins of the basin.
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Subduction-related deformation processes in the Makran accretionary prism, offshore Iran
Authors Gianluca Grando and Ken McClayThe Makran accretionary prism is regarded as one of the most extensive subduction complexes on Earth. It provides an ideal example of an accretionary prism to study processes related to subduction at plate boundaries, such as frontal accretion and sediment underplating-underthrusting. The rear portion of the wedge is uplifted and extended by normal faulting and ductile flow. Spectacular shale diapirs and mud volcanoes are present all along the external part of the prism and can be seen on the regional 2-D-seismic section presented in this study. The Himalayan Turbidites sequence is the main detachment level for the imbricate fan and extensional faults of the Makran accretionary prism. It is also assumed to be the main source for rising shale diapirs and mud volcanoes along the imbricated thrusts within the wedge. Evidence of active sediment remobilization is prevalent in the mid-slope morphotectonic province of the accretionary prism. It is proposed that the initiation of diapirism appears to be spatially coincident with the onset of underplating processes in the rear portion of the prism. The rapid uplift of the prism and the onset of extensional faults favour the extrusion of overpressured sediments and fluids/gas along thrust faults on the seaward side of the prism. The extensional faults above the deep zone of underplating have been mildly inverted, which implies there has been episodic alternation of compression and extension.
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Seismic physical modeling for the Arabian Peninsula: Laboratory set-up and early results
Authors Robert J. Greaves and Mike Jervis and Mohammed AlfarajThe geology of Saudi Arabia is covered by variable and complex overburden, which makes it difficult to image subsurface reservoirs in some areas. Therefore, novel processing and data acquisition methods need to be developed that yield improvements to seismic images, while maintaining a cost-effective approach. Constructing scaled physical models, with the expected geological and geophysical characteristics of the problem areas, provides a low-cost means for testing and evaluating different seismic acquisition and processing techniques. In 2006, Saudi Aramco commissioned the building of a physical modeling system in order to develop a capability to simulate the seismic data acquisition in various oil field and exploration target areas. This, in turn, would allow the data, acquired with an emphasis on representing a complex overburden, to be processed with knowledge of ground-truth geology and geophysics. The system uses ultrasonic sources and receivers to simulate seismic data acquisition. The modeling system can record 16 receiver channels and is probably the most advanced automated recording system in the world. Land surveys are simulated by the receivers being in direct contact with the surface so that statics and other near-surface anomalies can be investigated. Marine surveys are simulated by adding water and moving submerged sources and receivers above the model. It is capable of simulating a wide range of vibrator and explosive source signatures with any receiver array configuration. Conventional 2-
D, 3-D, 3C, walk-away VSP, cross-well tomography, and micro-seismicity can all be simulated. This presentation will discuss the unique recording capabilities offered by this physical modeling system, and review data recorded to simulate seismic acquisition conditions over a typical Arabian Peninsula subsurface geology overlain by a complex overburden.
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Understanding subsurface pressure data signature in a hydrogeological context
More LessPressure data are often used to understand the conductive properties of the rock framework, such as compartmentalization and sealing. While using such data is well-justified, the lack of understanding of basinal hydrogeology prevents a more comprehensive and thus accurate interpretation. Using a wealth of pressure data from mature basins and a numerical basin-hydrogeology model, a set of guidelines for understanding the pressure regimes and their implication on the hydrocarbon system are outlined. In subaerially exposed basins, the upper 10,000 ft or so are usually normally-pressured and dominated by a gravity-driven flow system. In these basins groundwater descends starting at topographic highs and then flows laterally before it ascends at
topographic lows. Intermediate and local flow systems also develop at a smaller scale due to local topographic variations. Sometimes the flow may be short-circuited by flow conduits between horizons, such as evaporite or shale layers. The gravity-driven flow system is usually superimposed on a deeper, abnormally-pressured system whose genesis can be due to multiple aspects. Among those are compaction, hydrocarbon generation and tectonic compression. The movement of groundwater within these systems and the interaction of such flow systems with the geological framework can generate a multitude of pressure signatures, both on a local and regional scale, which when properly interpreted, can lead to better exploration and development strategies. The
developed guidelines are outlined and applied to flow systems observed in the Arabian Platform and the potential implications on understanding the hydrocarbon system is proposed in view of the observed data.
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Refining the carbonate paradigm for revamping mature oil fields: Integration of regional-scale and high-resolution stratigraphy in the Upper Cretaceous Natih Formation, Oman
Seismic stratigraphy is commonly used by industry, at regional scales, to identify and define plays and targets. This study combines a high-resolution sequence stratigraphic study carried out by fieldwork on outcrop, together with seismic forward modelling of both regional scale features and discrete geobodies, and the iteration with high-resolution 3-D industry seismic covering areas adjacent to the outcrops. The resulting high-resolution seismic stratigraphic and sequence stratigraphic interpretations of a targeted field lying further away were significantly enhanced by the general regional model. Iteration between 3-D seismic, cored wells, outcrops and forward modelling has clarified the packaging of strata, or architectural elements, at different scales. Individual geobodies, at the scale of geomorphic units such as channels or carbonate shoals, may be resolved on attribute maps but are generally sub-seismic in scale. A larger-scale grouping of strata, architectural elements, here named “depositional assemblages”, is defined by both clinoform geometries and by seismic stratigraphic context. Facies associations of such units, identified from cored wells, proved to be significantly different, defining assemblage-specific depositional systems. The combination of high resolution sequence stratigraphy from outcrop studies, with the analysis of corresponding 3-D seismic and with forward seismic modelling provides a significantly more detailed geological model upon which to base the static reservoir models required to assess the
re-engineering potential of a mature giant field.
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Low-frequency hydrocarbon microtremors: Case studies around the world
Authors Robert M. Habiger and Erik Saenger and Stefan SchmalholzA growing number of surveys at different oil and gas fields throughout the world have established the presence of hydrocarbon microtremors with a high degree of correlation to the proven location of these reservoirs. These tremors can be used as a direct hydrocarbon indicator for the optimization of borehole placement during exploration, appraisal and production. The ever-present seismic background noise of the Earth acts as the driving force for the generation of hydrocarbon indicating signals. In contrast to conventional 2-D and 3-D seismic technologies, the investigation of hydrocarbon microtremors may be entirely passive not requiring artificial seismic excitation sources. The results of several surveys over gas and oil fields in different countries are presented.
Data were acquired using ultra-sensitive, portable 3-component broadband seismometers with various survey designs. The raw data was processed in multiple steps. Data processing included removing or attenuating signals that are not related to subsurface structures (mainly surface noise generated by road traffic, industrial activities, wind and rain) and correcting the dataset for temporal and near-surface geology-related variations. Finally, maps of different seismic attributes were integrated to form a hydrocarbon potential map. The results are compared with known information of the reservoir (geological model including reservoir depth, drainage area of producing wells and information from borehole measurements). A systematic analysis allows determining reservoir-specific characteristics of hydrocarbon microtremors occurring around the world.
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Feasibility study of steam injection in one of Iranian naturally fractured heavy-oil fields
Authors Ashkan Haghshenas and Mahmood AmaniSteam injection in naturally fractured heavy-oil reservoirs provides an extremely challenging problem but also a potentially effective and efficient improved-oil-recovery method. Coupling of the two distinct and contrasting matrix and fracture systems results in a highly non-linear problem, which becomes even more complicated due to the steep changes in fluid properties caused by the thermal effects of steam injection. Modeling and designing an optimum steam-injection operation in such systems requires an accurate characterization and representation of a naturally fractured heavy-oil reservoir and steam injection operation parameters and dynamics. This study focused on an undeveloped Iranian fractured heavy-oil field. A thermal dual-porosity model was developed for a sector of this field, and some sensitivity analysis tests were performed. A comprehensive and comparative study was conducted in order to understand the relative effects of naturally fractured heavy-oil system and injection operation properties on the oil-recovery performance. This work showed that steam injection could take oil recovery from zero to about 17%, and therefore would qualify for producing this field. The results indicated the importance of grid-block size, injection rates, temperature and quality of injections on the simulation process. The study should help us to design the optimal recovery operation and pressure-maintenance program. It also determines the confidence level for an oil-recovery operation in this field using steam injection.
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Novel-liner system improves coring performance, rig safety and wellsite processing
Authors Larry M. Hall and Bob T. WilsonA one-piece aluminum inner barrel liner system has been employed to protect and containerize core material during coring operations with conventional and wireline core barrels. The system offered enhanced safety features and improved core handling on the rig floor. The integral one-piece liners securely containerized the core during acquisition and prevented jamming, leading to increased core recovery when compared to other liner systems. Vent holes allowed expelled gas to escape during recovery to the surface, improving safety during core retrieval and handling. The companion non-rotating inner tube stabilizer system eased separation of the 30-ft liner joints, thus improving wellsite handling procedures and safety during extended core runs. The design allowed the liners to be opened quickly and easily at the surface for rapid examination and sampling of the core material. Case history data from Arabian Gulf wells are presented.
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Modern seismic imaging of a vintage 3-D seismic survey offshore northern Emirates
Authors Michael A. Hall and Svetlana Bidikhova and John FaragherThis presentation covers the issues involved in the prestack imaging of a vintage offshore 3-D dataset and preparing it for modern processing technologies. The spatial sampling of 3-D seismic surveys was considerably more coarse two decades ago than it is today. Within the survey is a substantial gap in short offsets due to the under-shooting of platforms. This paucity of acquired data creates problems for pre-stack migration, especially around the under-shoot areas. The data acquisition used an analogue streamer resulting in strong variations in sensitivity between hydrophone groups. The data suffered from several issues relating not only to acquisition but to transcription and this presentation will address how these were satisfactorily dealt with. Common to
this part of the Arabian Gulf is a guided wave noise train that obscures reflections on the longer offsets. An effective attenuation of this unwanted noise is presented that preserves the desired signal and allows the inclusion of longer offset data into the stack. This region is also renowned for severe multiple reflection problems both from the water layer and from strongly reflecting interfaces in the Earth itself. A new approach will be shown to attenuating both surface related and inter-bed multiple reflection energy. Well data and geological information were carefully integrated in the construction of the velocity model to yield improved imaging of the primary reflection data. Comparisons will be made for pre-stack time migration using the sparsely recorded data only against interpolating and regularizing this data prior to migration.
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CHFR can better monitor gas sand pay zones hydrocarbon potential
Authors Gharib M. Hamada and Ahmed A. HegazyThe ability to detect and evaluate bypassed hydrocarbon and track fluid movement in sandstone reservoir is vital in the quest to improve production and increase recovery. The main technique, which has been used for monitoring reservoir saturations, is the thermal decay time (TDT) tool. However it is difficult to interpret the TDT data in reservoirs with low-salinity formation water. This problem cannot be solved because TDT measurements depend on the salt content in formation brine. Instead the cased hole formation resistivity tool (CHFR) is proposed to overcome many of the limitations associated with pulsed-neutron tools. This presentation compares the results of reservoir-saturation monitoring obtained from TDT and CHFR logs recorded in wells in an oil field in
the Sinai Peninsula, Egypt. The results are referenced to open-hole resistivity logs. It was found that water saturations calculated from CHFR logs are more accurate than TDT log in most cases. Moreover, when a quick decision is required the initial interpretation of CHFR logs always agreed with its quantitative interpretation. In contrast the quick interpretation at TDT log was generally found to be very difficult, and not to agree with its quantitative interpretation.
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Implications of lineaments trends from Ghawar field and adjacent areas
More LessLineaments traced from satellite images (scale 1:250,000, band 7) over the giant Ghawar field and adjacent areas indicated major trends of N55°W and N35°E, and minor and lesser trends of N15°E, N5°W, and N35°W. The total number of traced lineaments was 413 with variable lengths of 2 to 5 km. The major N55oW and minor N35°W, N25°W and N45°W trends are generally coincident with the NW-trending high-angle wrench faults that cut the older Paleozoic and basement rocks (Najd Fault System). The major and minor NW and major NE (N35°E) trends may also be related to structures formed by the Zagros stress regime, which acted in the NE-SW direction during Early Tertiary and continues at present. The Zagros stress regime may also have partially caused
and/or enhanced structures trending N15°W and N5°W. Those northerly trends are also parallel to the major faults system present within the Precambrian Shield. The general trend of the Ghawar field also follows this general northerly trend. Minor N65°–75°E and N65°W trends may be related to structural features formed by the Oman stress regime (acted in E-W direction during Paleozoic and Mesozoic times).
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Enhanced seismic interpretation using multiple seismic volumes over an offshore field, Abu Dhabi, United Arab Emirates
New seismic data reprocessing has improved seismic interpretations for a major Middle East offshore oil field. Significant new fault patterns have been identified within a Kharaib carbonate reservoir using multiple seismic volumes. These were generated from post-stack reprocessing of a full-field 1,500 square km data volume and full reprocessing from field tape of a crestal 200 square km data set. The new fault framework will be incorporated into geologic models for simulation modeling that will help drive the development plan for the field. The full-field post-stack reprocessing flow was designed to reduce noise, thereby enhancing stratigraphic detail and fault definition. Near-, mid-, far-, and full-stacks, spectral whitening and spectral decomposed data show different
degrees of resolution. The full reprocessing from field tape used a processing flow that was specifically designed to address severe water-bottom energy surface noise and variable short-period reverberatory multiples. It used separate processing flows for hydrophone and geophone data. Noise reduction from the reprocessing allowed consistent and efficient automated horizon picking. The interpretation approach included the generation of new horizons and a disciplined approach to fault identification using multiple volumes and attributes. From the new data, automated horizons were picked, which led to better identification of small faults using horizon-based attributes. The new data allowed us to identify pervasive NE-SW and N-S faults in parts of the field and to subdivide major faults into smaller faults at different stratigraphic levels. These encouraging results motivated us to plan full-field full reprocessing from field tape.
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A method to determine acquisition equivalency
Authors Richard Hastings-James and Peter van BaarenOften a choice must be made between different acquisition schemes when designing a seismic survey. Therefore it is of interest to quantitatively compare designs in terms of the quality of data that they will produce. Such a comparison is necessarily complex, and involves many considerations that are target-specific, including data azimuth and offset distribution. However, there are certain attributes that can be calculated that are largely target-independent, and which are of fundamental importance to data quality, resolution, and final image quality. These attributes include signal bandwidth and signal-to-noise ratio. In this presentation we calculate on the basis of acquisition geometry, field effort and local conditions the signal bandwidth and signal-to-noise ratio of the acquired data, including the effects random and coherent noise. Conditions for equivalency between two crews of differing configurations are presented. Equivalency in effect permits the direct substitution of a crew of one configuration by the other crew of a different configuration with no change to signal-to-noise ratio and bandwidth. In particular this analysis permits a direct quantitative comparison between single-sensor and conventional acquisition.
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Accelerating development of geoscientists and applications engineers using competency mapping and certification processes
Authors Frank P. Hearn and D.K. Trichel and Mark HarrisDue to rapid growth, major workforce age gaps, and a large workforce population nearing retirement, traditional formal training programs that stretch over years of personal development are no longer effective. Training alone doesn’t ensure competency. New methods that combine mentoring and targeted competency development are needed to drive personal development and effectively transfer skill and knowledge from senior to the recently hired or inexperienced workforce. A formal program has been developed utilizing competency mapping and a certification process that provides clear direction for self and guided development of internal Geoscientists and Applications Engineers. This program is designed to accelerate development in areas of company core competencies, guide and align career path expectations with personal development and act as a retention mechanism for senior geoscientists by broadening technical career opportunities. The program consists of a competency map, a list of core competencies and skills that define the competency map, a formal certification process and tracking system that ensures the Geoscientist meets or exceeds the requirement for each core competency, and guidance counselors (mentors) who oversee the Geoscientist through the entire certification process. Nine standard geoscience certifications and six advanced geoscience certifications are offered in areas of Geology, Geophysics, Geomechanics, Formation Evaluation and Petrophysics, Reservoir Navigation, Integrated Pressure Management, Wellbore Integrity, Completions and Production, and Reservoir Engineering. The program is flexible and efficient. It fosters personalized development plans through engagement between mentors and candidates and ensures learning and development specifically targets areas where skill gaps exist. It also provides an essential tie between competency development, required peripheral training and the Geoscience and Applications engineering career ladder.
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Efficient high-resolution seismic data for near-surface corrections
Authors Tariq Alkhalifa, Ramzy AlZayer and and Majed AlMalkiAccurate corrections for topography and near-surface complexities of surface seismic data from the Arabian Peninsula require accurate modeling of the near-surface and an effective correction algorithm that uses of the model. Refraction and residual statics-based modeling, though they help improve results, have fallen short of what is required in complex regions in the area. In fact, almost all the existing near-surface correction methods require an accurate near-surface velocity model. In some cases, however, the model is impossible to estimate from conventional low-resolution seismic data in which the near-surface inhomogeneities occur within the near-field region of wave propagation. Through numerical modeling, we show that a reasonably accurate shallow-velocity
model can be obtained from applying conventional horizon-based velocity analysis on shallow high-resolution seismic data. The model proved to be effective in correcting the conventional deep seismic image using either the simple static shifts or wave-equation datuming. We also present a novel idea to acquire high-resolution shallow seismic data in a cost-effective way. The novelty of the approach is in the spacing of the receivers, in which we used conventional acquisition configurations to acquire the high-resolution data with minimal additional cost. We investigated the resolution limits achieved from conventional configurations. A real experiment in the Riyadh region shows the possible resolution limits obtainable using this approach.
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Cablefree land acquisition technologies: Choices, benefits and case studies
Authors Robert G. Heath and William AyresInternationally, a growing section of the oil industry acknowledges that cable-free land seismic systems are here to stay. Such technology economically answers the demand for improved HSE exposure and massively increased channel counts for better geophysical imaging, especially of mature fields. However, for viable operations with 15–50,000 live channels, it is imperative to review what can be expected from the latest hardware. This study researches cable-free recording, while looking at new approaches to acquisition, both active and passive. It offers an appraisal of the benefits of this new approach, especially as it applies to the challenges affecting the Middle East. We demonstrate that planning surveys and operating cable-free systems offer opportunities
to implement new approaches and methodologies which make the most of what this new technology has to offer. With this knowledge, we can plan to use its advantages for maximum effect, and increase competition in the market. Results will be presented, including data acquired with cable-free hardware and case studies of systems used internationally in real field conditions. Knowledge and experience of the cable-free’s pros and cons are growing. Some experts predict that more than half the channels sold by 2010 will be cable-free. We offer real data presentations and recommendations of the way forward for active and permanent (4-D) recording. We conclude that the cable-free approach to, land exploration geophysics opens up new possibilities for making
progress in all of these areas.
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Geothermal gradient study of Asmari Formation in Dezful Embayment, Zagros, Iran
More LessThis study was focused on determining the geothermal gradient of the Oligocene-Miocene Asmari Reservoir in the Dezful Embayment, Iran. It involved preparing an isothemal map of the reservoir, recognition of a temperature anomaly zone and the study of related parameters, such as Ro and TTI. The geothermal gradient of the Asmari Reservoir and mean geothermal gradient (average slope between the temperature at the surface and the top of Pabdeh Formation) were determined in 180 wells from different oil fields. The results were checked by geochemical analysis (Tmax) and oil-generation modeling. The study showed that the geothermal gradient in the Agha Jari, Haft Kel, Masjid-e-Suleyman and Naft- Safid fields is greater than in other fields. The results
suggested considerable differences in the geothermal gradient between wells in the same field; for example in Marun, Pazanan and the above-noted fields. Variations in the geothermal gradient between wells, implies that their source rocks should show different maturations. For example geochemical studies of Marun and Pazanan fields suggested that the source rock is more mature in wells MN-123 than MN-222 and PZ-23 than PZ-117. Moreover the Oleanane biomarker was found in the oils from these fields. Studies also detected a relationship between an anomalous temperature zone (high gradient) and a paleohigh in the Zagros Basin. Based on a structural study, the boundaries of the paleohigh are correlated to basement lineaments. Investigations further confirm that faults are one of the important factors that produce greater geothermal gradients. Thus by integrating the results of the geochemical and structural studies we found that: (1) the geothermal gradient can vary in oil fields or in wells in the same field. (2) These variations are strongly controlled by basement lineaments, which increase the geothermal gradient. In turn the greater gradient leads to higher maturation (oil generation) of the Pabdeh Formation as confirmed by the Oleanane biomarker. (3) In the high-gradient zone, the oil-production rate is higher than in other zones.
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Uncertainty assessment and risk analysis for a future field development phase in a carbonate reservoir, onshore Abu Dhabi, United Arab Emirates
Quantifying, ranking and weighting of reservoir uncertainties based on several variables can be a real challenge for volumetric estimation. This is because the variables are related to many parameters such as tool measurements, seismic processing, velocity modeling, petrophysical evaluation, geological interpretation, modeling parameters, saturation functions among others. The oil field potential assessment in the current study was based on the first phase of a development drilling campaign and recent appraisal drilling over a less controlled area in shallow waters. A stochastic uncertainty analysis, using the JACTA (GocadTM plug-ins) software, allowed a decision on the location of the latest appraisal well and an inference on the further development phase scheme
for the field. The study included vertical, deviated and horizontal wells within Phase I and new development phase areas. A large number of simulations revealed a statistical distribution of the reservoir volumes and its connectivity. In general, the major uncertainties are from three main categories: structural, petrophysical and fluid parameters. The inter-dependence among parameters was properly captured during the uncertainty workflow. The different realizations from the static model (P90, P50 and P10) were upscaled to fit the dynamic model grid-size limitations. The upscaled models along with the other dynamic data from the fluid properties (pressure, volume and temperature data), special core analysis, well completion and production/injection data were used to build the dynamic simulation models. The P50 model was then initially tested and history-matched before using it to forecast the different development scenarios to select the most viable option against the P90 and P10 models.
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Depositional setting of Cretaceous Reservoirs, southern Yemen and northern Somalia
Authors Osman Salad Hersi and Dale LeckieThe Say’un-Al Masila Basin of southern Yemen and the Al Mado Basin of northern Somalia are Mesozoic sedimentary basins developed during the disintegration of Gondwana. The two basins formed one single rift (Say’un-Al Mado Graben) with intermittent tectonic disturbances, which affected the carbonate-clastic basinfill architecture. The Cretaceous Say’un-Al Mado graben had a funnel shape in plan view, tapering northwestward (in Yemen) and open southeastward (through northern Somalia) to the Tethys Ocean. The Cretaceous fill of the Say’un–Al Mado rift consists of siliciclastic sequences predominant in the western flanks of the basin (Tawila Group in Yemen and Yesomma Formation in northern Somalia), and carbonate sequences predominant in the
southeastern areas (Mahra Group and Tisje Formation, respectively). The sandstones of the Tawila Group (Qishn and Harshiyat formations) and the Yesomma Formation were deposited in a complex system of braided to low sinuosity meandering rivers, tidal-dominated estuarine and deltaic environments. The terrigenous influx decreased southeastward where carbonate sedimentation flourished in a shallow-marine environment (Mahra Group in Yemen and Tisje Formation in northern Somalia). Carbonate sand shoals, lagoonal wackestones, mudstones and rudistic buildups are the main lithofacies of the carbonate strata. The Qishn Formation is highly porous (18 to 23%) and permeable (up to ten darcies) and contains estimated reserves of over one billion barrels of
recoverable oil. Unlike the relatively strong hydrocarbon exploration activity in Yemen, Somalia’s hydrocarbon resources are under-explored. However, the little geological knowledge from the Yesomma and Tisje formations implies they contain good reservoir intervals (up to 300 m thick and 14% porosity) with interbeds of source shales. Many of the drilled wells contain oil stains and gas shows. Maturity of these hydrocarbons ranges from immature to post-mature with good intervals within the oil window.
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Paleomagnetic study of Upper Cretaceous-Lower Tertiary rocks in northeastern Iraq
Authors Basim R.A. Hijab and Ezadin Baban and Emad H. Al KharssanThe following rock units in northeastern Iraq were sampled for a paleomagnetic study: (1) Paleocene-Lower Eocene Naoprdan Limestone Formation at Chwarta and Zainal, (2) Maastrichtian Aqra Limestone Formation at Maukaba and Zardabe, (3) Valanginian-Turonian Balambo Limestone Formation at Azmar locality and igneous gabbros intrusions at Kanaroe and Waraz. Twelve hand samples and 200 oriented drilled cores were collected from these localities. The remnant magnetization (NRM) was measured using a spinner magnetometer (Baghdad University) and the cryogenic magnetometer (Oklahoma University, USA). The remnant magnetization in the Aqra Formation is of a depositional origin and carried by a detrital magnetite grains. In other localities (Chwarta, Zainal, Azmar, Kanaroe and Waraz), secondary haematite or maghemite is dominant. The rocks of the Chwarta, Zainal, Azmar, Kanaroe and Waraz localities are not good indicators for the paleomagnetic direction. Results from Maukaba and Zardabe rocks (Aqra Limestone) provided reliable paleomagnetic results. These rocks showed reverse paleomagnetic directions. All computed virtual geomagnetic poles (VGP) correspond to a reverse polarity, and the overall mean VGPs position of the Maukaba locality is paleo-latitude (Plat) of 44.4° S and paleo-longitude (Plong) of 279°, and for Zardabe locality (Plat = 57.1° S, Plong = 235°) with co-latitude (-14°) and (-13.9°). Accordingly, the paleo-latitude of the Maastrichtian Aqra Limestone basin was between 13.9° and 14° N. This suggests that the Neo-Tethys Ocean was located to the north and northeast of northeastern Iraq during the Maastrichtian time. The closure of this ocean occurred between the Maastrichtian and Early Tertiary. The paleo-position of the Aqra Limestone basin clearly suggests that the northern part of Iraq was still in warm environmental conditions during Maastrichtian times. This means that the oil accumulation can be found in rocks of ages for Maastrichtian and older than Maastrichtian.
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Mesozoic to Recent structural evolution of the eastern Rub’ Al-Khali, Saudi Arabia
Two main structural trends are evident in the eastern Rub’ Al-Khali Basin: a NNE trend, similar to the dominant structural trend in the United Arab Emirates; and a NS trend, similar to the one observed in the major oil fields of Saudi Arabia. Understanding the interplay between these two trends and their relationship to deep-seated older basement structural components, as well as their Phanerozoic reactivation history, is critical to obtaining a robust exploration risk assessment for these structures in this area. Data used to underpin the structural analysis are regional analogue structural data, 2-D seismic data from eastern Saudi Arabia, and structural observations from core and dip-meter logs. Together with geochemical and stratigraphic analyses this has resulted in a robust kinematic model for the structural evolution of the NS-trending structures. Several phases of structural development have resulted in the present-day composite NS-trending arch-like configurations. The main phase of growth occurred during the Late Cretaceous as a result of NW-SE compression, further phases of growth were recognized during the Late Cretaceous Maastrichtian, Paleocene to Early Eocene, Mid- to Late Miocene and Pliocene times. The rotation of the stress field to a present-day ENE-WSW position for the maximum horizontal stress was recognized through observations from core and seismic data and has resulted in several phases of fracturing, including the reactivation of older fracture systems.
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Clay mineralogy of Gurpi Formation at its type section and Ziloee oil field, Dezfool Embayment, Zagros Mountains, Iran
More LessStudying the Tu/K ratio on NGS logs of the Gurpi Formation in well No. 8 of the Ziloee oil field, Izea zone of Zagros Province, indicated the occurrence of smectite and illite. Moreover, field studies and calcimetric analysis were conducted on samples collected from the type section of the Gurpi Formation (Dezfool Embayment of the Zagros Mountains). The samples consist of limestone, marl and shaley marl. However, X-ray diffraction (XRD) analysis of selected samples with lesser amounts of CaCO3 indicated the existence of smectite, illite and chlorite. The coexistence of smectite and illite, and absence of kaolinite, in these deposits indicates temperate climatic conditions prevailed during the latest Cretaceous and Early Paleocene in the Zagros region. Moreover, semiquantitative analysis of the XRD data identified an upward increasing trend of smectite and decreasing trend of illite and chlorite in the sedimentary column. These trends suggest a deepening upward trend in the basin as consistent with global sea-level curves. Based on the covariance trend of illite and chlorite and scanning electron microscope (SEM) images, we suggest a diagenetic transformation of illite to chlorite in these samples. Also the SEM images indicated a diagenetic origin for smectite, which can form during fluid exchange with maphic and detrial clay minerals (e.g. detrial smectite, illite).
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Sedimentation and high-resolution sequence stratigraphy of the Upper Cretaceous Simsima Formation, onshore Abu Dhabi oil field, United Arab Emirates
More LessAn important carbonate oil field, located onshore Abu Dhabi, has been producing from the Upper Cretaceous (Maastrichtian) Simsima Formation since 1983. A detailed sedimentological and high-resolution sequence stratigraphic study has been carried out, integrating approximately 7,000 ft of core material, approximately 3,500 thin sections, and all available well-log data from 46 wells. Core description, together with semi-quantitative petrographic examination of thin sections, established a new depositional model for the Simsima Formation. 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 newly developed, high-resolution sequence stratigraphic framework suggested that the Simsima Formation comprises one complete third-order composite sequence and the transgressive systems tract of an overlying second third-order composite sequence. These third-order
composite sequences include seventeen high-frequency, fourth-order sequences (HFS). HFS 1 to HFS 12 build the older, third-order composite sequence, HFS 13 to HFS 17 form the transgressive system tract of the overlying, younger third-order composite sequence. The fourthorder, high-frequency sequences were tied to re-processed and re-interpreted 3-D seismic data. Fourth-order sequences 1 to 6 clearly show onlap on a pre-existing high (pre-Simsima unconformity surface) whereas the top part of the Simsima Formation (sequences 13 to 17) show erosion on seismic cross-sections. The established high-resolution sequence stratigraphic framework will provide the layering scheme for the new Simsima 3-D static model, which will be used as input for reservoir flow modeling.
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Geophysical pressure prediction for ultra-deep wells: When the reservoir becomes the enemy
More LessIn recent years, drilling requirements have become more challenging as ultra-deep wells have demonstrated that basic undercompaction models are inadequate to predict pressures in high-pressure/high-temperature (HP-HT) environments. The requirements of these wells have forced pressure prediction to adapt to environments where diagenetic processes and hydrocarbon maturation are dominant (unloaded environments), and where chemical compaction takes over from undercompaction as the dominant factor in determining rock property changes (secondary compaction environments). Adding to the complexity of the pressure prediction process is the interplay between shales and reservoir rocks. As pressure increases, the window between the formation pore pressure and fracture pressure narrows. In HP-HT environments, the lateral extent, structural position, and architecture of the reservoirs become much more critical to the viability of a prospect. They also determine the range of safe depths where a specific reservoir can be penetrated without the risk of a pressure influx that could jeopardize the drilling operation. In this setting, geopressure prediction and reservoir pressure modeling become an essential component of prospect risking. While explorationists desire large reservoir bodies in deep prospects to allow sufficient reserves to justify the high cost of an ultra-deep well, they must also recognize that large reservoir extents can also threaten the viability of the prospect. To mitigate this risk, the exploration team must use all the available information to determine the extent of the reservoir, its structural position, and its interaction with faults and other potential flow conduits. This information can then be integrated with 3-D pressure volumes to predict column heights for specific fluids
and the reservoir pressures at any specific penetration point in the subsurface. The accurate prediction of the reservoir pressures at a specific penetration point can be the difference between an efficiently managed drilling operation and a potentially catastrophic pressure influx event.
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Using biofacies and lithofacies to determine palaeoenvironments and depositional cyclicity of the Sulaiy and Yamama formations of subsurface Saudi Arabia
Authors Geraint W. Hughes and Nassir Naji and Osman VarolThe Sulaiy and Yamama formations of Saudi Arabia consist of Late Jurassic (Tithonian) to Early Cretaceous (Berriasian) carbonates. Although exposed in Saudi Arabia, the Sulaiy is difficult to access and the Yamama is very poorly exposed. The Sulaiy Formation lies unconformably on evaporites of the Hith Formation at outcrop, but overlies carbonates of the Manifa Member of the Hith Formation in the subsurface. The Manifa is currently being evaluated as being genetically linked with the Sulaiy rather than its traditionally assigned Hith Formation. Micropalaeontology and sedimentology of the Sulaiy and Yamama formations in subsurface have revealed a succession of clearly defined shallowing upwards depositional cycles, of 50 ft average thickness. These typically commence with a deep-marine biofacies within wackestones and packstones, capped with a mudstone-wackestone maximum flooding interval and an upper unit of packstone to grainstones containing shallow-marine biofacies. The upper part of the Sulaiy Formation is highstand-dominated with common grainstones that host the Lower Ratawi reservoir and is capped by karst that defines the sequence boundary. The Yamama Formation, in contrast, contains fewer grainstones, and is predominantly transgressive. Although smaller grainstone units host the Upper Ratawi reservoir, it is considered that the highstand-associated, main reservoir facies equivalent to the Lower Ratawi reservoir must have been deposited but was removed by the very extensive episode of erosion that accompanied the major sea-level fall during the Valanginian. It is tantalising to contemplate the destination of the transported highstand grainstones as they would provide excellent stratigraphically trapped pre-Buwaib reservoirs elsewhere within the basin.
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Straight-ray datuming in 3-D media: Fast and flexible
Authors Tariq Alkhalifa, Henk Innemee and and Chris BensonCommon datuming approaches, like the Kirchhoff or finite-difference methods, require reasonable sampling of the sources and receivers. This becomes a serious limitation for datuming data acquired using 3-D conventional land-acquisition layouts, because of the typical sparse spacing of either the sources or receivers. To combat this, we extend Alkhalifah and Bagiani’s (2006) straight-ray datuming (SRD) to handle 3-D acquisition geometries. As in the 2-D case, 3-D SRD is based on the straight-ray assumption
above-and-below the datum with Snell’s Law honored in between. This allows for the application of SRD to common-shot gathers in one operation (no need to sort the data to common receivers). Similarly, it can be applied to common-receiver gathers without the need to sort the data back to common-shot gathers. This feature allows for more flexibility in acquisition as it requires, unlike in the conventional case, either the sources or receivers to have a complete fine coverage of the area. In addition, SRD does not require a detailed description of the near-surface velocity model; information from refraction static or any other commonly used method to obtain near-surface time shift suffice. SRD, in addition to carrying out redatuming, can be used to map irregularly
sampled spatial data at the acquisition surface into regularly sampled data at the datum. In fact, since the operation is a partial migration, it suppresses diffractions generated from inhomogeneities above the datum. The computational cost of applying 3-D SRD is larger than static corrections, but because of the limited spatial extension and analytical formulation, it is far less than Kirchhoff re-datuming.
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New aspects of Saudi Arabian Jurassic biostratigraphy
Authors Geraint W. Hughes, Osman Varol and Nigel P. Hooker and Raymond EnayAge determination of the Saudi Arabian Jurassic carbonate succession was originally based on outcrop macropalaeontology and micropalaeontology, and the essential chronostratigraphy of the formations and members was completed by 1968. It is to the credit of the earlier workers that their age assignments have been largely retained to the present-day. Subsequent biostratigraphic investigations of outcrop samples using ammonite, nautiloid, brachiopod and echinoid macrofossils refined these earlier age determinations. New ammonite and nautiloid determinations have further added to this refinement. In the subsurface, where macrofossils are rarely encountered or preserved within exploratory well samples, lithostratigraphic assignment relies heavily on
lithofacies characteristics. Such methodology becomes difficult within intra-shelf basin areas where the defining shallower lithofacies are either poorly developed or absent. In such circumstances, micropalaeontological evidence is essential, with support from nannofossil and palynology. Current research is being focused on the micropalaeontological, nannofossil and palynological calibration between the exposed, macropalaeontologically dated, type or reference sections and subsurface core and cuttings samples. Of these, palynology is beginning to provide new stratigraphically useful data, including outcrop samples, where palynomorph recovery has previously been assumed to be poor and of limited value. Such an approach, using their biostratigraphic fingerprint, is proving successful to assist exploration activities by identifying formations in historical wells where lithostratigraphic units had been miss-assigned resulting in mis-correlations.
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Micropalaeontology and palaeoenvironments of the Wadi Waqb Member, Jabal Kibrit Formation, and its reservoir equivalent, Saudi Arabian Red Sea
More LessThe Saudi Arabian Red Sea stratigraphy consists of a variety of lithologies that range from evaporites, deep- and shallow-marine siliciclastics and carbonates, biostratigraphically constrained to range from the Late Cretaceous (Campanian) to Late Pliocene. The Midyan area of the northern Red Sea offers a unique window into the Cretaceous and Miocene succession that is otherwise only present in the deep subsurface. The sediments are of hydrocarbon interest because of the presence of source rocks, siliciclastic and carbonate reservoirs. The Wadi Waqb reservoir is hosted within the Wadi Waqb Member of the Jabal Kibrit Formation, and is of Early Miocene age. This member is exposed on the east flanks of the Ifal Plain, where it is represented by a discontinuous
fringing rhodolith and coral reef complex that is welded to steep cliffs of granitic basement. Exposures of the member in Wadi Waqb, located in the middle part of the Midyan region, consist of pelagic, planktonic foraminiferal dominated packstones that contain abundant shallow marine allochthonous bioclasts. These shallowmarine bioclasts are considered to have been derived from the rhodolith-coral reefs exposed to the east. The Wadi Waqb reservoir is located in the central part of the Ifal Plain, approximately midway between the in-situ rhodolith-coral reefs and the mixed allochthonous and authochthonous facies in Wadi Waqb. The reservoir consists of biofacies that compare well with those exposed in Wadi Waqb, and therefore testify to the presence of a deep-marine environment, in excess of 50–75 m water depth, located less than 25 km to the west of the fringing reef source of the shallow bioclasts.
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Micropalaeontology of the Saudi Arabian Rus, Dammam and Dam Formations exposed at the Dammam Dome
Authors Geraint W. Hughes and Saleh EnaizyThe Dammam Dome represents a unique feature in Saudi Arabia as it forms a local topographic high along the otherwise flat extent of the eastern flank of the Kingdom. Its origin is attributed to episodic upwards movement of a deep-seated infra-Cambrian evaporite plug. The Rus, Dammam and Dam formations are exposed, of which their diminished thickness, relative to the adjacent subsurface, testifies to the region being regionally positive during the Tertiary. Micropalaeontological analysis with revised taxonomy of old and new exposures has improved palaeoenvironmental interpretation. The Paleocene to Early Eocene Umm er Radhuma is the lowermost Tertiary formation, but is not exposed in any accessible locations and will not be considered here. The Rus Formation was defined on the Dammam Dome, and includes lower carbonate and upper carbonate-evaporite unit. A new exposure on the Dammam Dome provides evidence for a lowermost Rus unit consisting of interbedded transgressive marls and clean highstand carbonates. An Early Eocene age is assigned on stratigraphic position as microfossils are rare owing to predominantly shallow-marine, periodically hypersaline conditions. The Dammam Formation includes the Midra, Saila, Alveolina and Khobar members. The Alveolina and Khobar members contain rich and diverse benthonic foraminiferal biofacies, including Middle Eocene Alveolina, Nummulites and Discocyclina species. A new Dhahran Member is proposed for the transgressive marls between
the Alveolina and Khobar highstand carbonates. The pre-Neogene angular unconformity underlies the Middle Miocene Dam Formation. The Dam Formation includes a basal stromatolite unit that is overlain by a coral and rich benthonic foraminiferal succession that contains Borelis melo.
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Tectonic controls on Triassic stratigraphy and hydrocarbon prospectivity in Kuwait
The Triassic System in Kuwait comprises ramp carbonates, anhydrites and clastics deposited in supra-tidal to inter-tidal settings. The N-S trending Kuwait Arch with flanking basins (offshore Kuwait in the east and Dibdibba Trough in the west) exercised control on deposition and preservation of Triassic strata and prospectivity. The Triassic encompasses the Upper Khuff, Sudair, Jilh and Minjur formations. The Upper Khuff consists of carbonates, which grade into argillaceous dolomites in the Sudair Formation. An additional dolomudstone-prone unit, provisionally named as Kra Al Maru Formation, is preserved locally between the Sudair and Jilh formations in the Dibdibba Trough. The Jilh Formation is evaporitic, divided by intra-formational salt. The thickness of the Lower Jilh decreases over the Kuwait Arch, whereas the Upper Jilh and Minjur formations thicken to the southeast with increased clastic influx. The tectono-stratigraphic imprint represents re-activation of structural grain inherited from Hercynian and older tectonism. Upper Khuff, Sudair, Kra Al Maru and Lower Jilh are influenced by uplift of the Kuwait Arch. Jilh Salt represents a major interface at the onset of tectonic inversion. The Upper Jilh and Minjur formations are influenced by southeasterly slope and clastic influx
from the south. The Triassic sediments over the Kuwait Arch have diagenetically degraded reservoir properties. Evaporites and dolomudstones with fracture-related reservoir development in western Kuwait and shallowto open-marine carbonates with conventional reservoirs east of the arch are prospective. Recent exploration wells have established flow to surface of sweet gas and gas condensate from Kra Al Maru. The Minjur Formation is prospective in the south where sandstone inter-beds have improved reservoir characteristics.
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Oil below oil-water contacts: Implications on the structural evolution of Minagish Oolite Reservoir, Minagish oil field, Kuwait
Authors Muhammad W. Ibrahim and Tahir El GezeeryA study of the structural evolution of the Minagish oil field revealed that the trapping structure began in Early Cretaceous time as a minor dome at the SSE flank of a NW-trending Jurassic anticline. The Minagish anticline assumed the present-day motif by Maastrichtian time, gently tilted towards the NNE and was dissected by an E-W fault during Tertiary times. The fault separated two main compartments of the Minagish Oolite reservoir: an up-thrown symmetrical northern sector, and a wrenched and down-thrown asymmetrical southern sector. The incipient Minagish structure affected the thickness and deposition of the oolitic facies of the Minagish Oolite. Subsequent regional NNE tilts had a minor effect on shifting the position of superior oolitic facies in relation
to present-day structural peaks of the Minagish Oolite reservoir. However, Tertiary differential displacement of the two main compartments influenced the thickness and position of the occluded tarmat layers, and preserved a record of Tertiary oil/water contacts. The structural evolution of the Minagish Oolite explains the preservation of sealing tarmats within superior oil-bearing reservoir facies above and below the present-day oil/water contact in the northern sector, and the preservation of tarmats within the relatively inferior and water-bearing facies below present-day oil/water contact in the southern sector of the Minagish Oolite reservoir. Hence, technically there appears to be producible oil sealed by tarmats below the present-day oil/water contact in the northern sector of the Minagish Oolite reservoir of Minagish oil field.
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Fault development and hydrocarbon entrapment in the Mutriba area, western Kuwait
Mutriba is a prominent NNW-SSE trending anticline in western Kuwait with confirmed hydrocarbons at the Triassic, Jurassic and Cretaceous levels. A study was conducted to enhance fault imaging and to improve the understanding of structural architecture of this faulted anticline. The seismic data in the Mutriba area is contaminated by multiples and has poor quality and resolution. Nevertheless the application of attribute and image enhancement algorithms on 3-D seismic data successfully mapped the faults. Additionally analytical techniques were applied to investigate the structural evolution through sequential reconstruction. Fault dislocation and formation fracture density were estimated using seismic data and geomechanical models. The Mutriba structure
at pre-Cretaceous levels is dissected by two prominent fault sets trending NNW and EW. The NNW trend is older and is probably related to structural development during Paleozoic time. The younger EW trend offsets the original structural geometry so that the northern segment trends NNW and the southern trend approaches NS. The latter faults appear to have developed during the Late Jurassic and to have been re-activated during Cretaceous and Tertiary times with major uplift. These strike-slip faults cut across the older trend and have segmented the structure into a number of discrete fault blocks. The fault compartmentalization has been studied with regard to hydrocarbon entrapment. Core studies and fracture modeling suggested that the fracture network developed by these fault systems have contributed to improved migration to and within Triassic and Jurassic reservoirs. Fault compartmentalization has controlled Jurassic hydrocarbon occurrences among fault blocks. Integration of regional geological understanding, seismic
and geochemical studies and geomechanical modeling has indicated areas for further exploration.
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Source rock formation and characteristics of Shiranish Formation, Euphrates Graben, Syria
The Euphrates Graben is one of the most important petroliferous basins in Syria. One known source rock is the marine Upper Cretaceous Shiranish Formation, but no detailed information exists about its source rock potential. The aim of the investigation is to: (1) identify the variations in source rock characteristics due to changes in paleoceanography, and (2) to correlate these variations with their effect on the timing of petroleum generation. Two organic facies with different characteristics of petroleum generation were identified: Type II facies with hydrogen index (HI) values of > 350 mg HC/g TOC, and a Type II/III facies with HI values of < 350 mg HC/g TOC. Both organic facies are considered likely sources of paraffinic-naphthenic-aromatic petroleum with variable
amounts of gas based on the pyrolysis gas chromatography scheme of Horsfield (1989). Bulk kinetic experiments have shown that predicted petroleum formation temperatures are closely similar within each of the facies, but different between the facies, with onset (TR 10%) temperatures of 136°C for the Type II facies and 144°C for the Type II/III facies. This corresponds to approximately 600 m difference in burial depth or delayed onset of petroleum generation by 5.75 million years for a 3.3 K/my heating rate. Facies analysis of well logs indicated that Type II/III facies of the lower Shiranish Fm. was influenced by terrestrial input of different intensity. During the Upper Shiranish Formation. a progressive deepening of the depositional environment was probably coupled to an enhanced marine paleoproductivity leading to Type II facies.
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Role of regional structural elements in the hydrocarbon prospectivity of Bahrain offshore blocks
More LessBahrain Island and its offshore exploration blocks are located in the northern Gulf infra-Cambrian Hormuz Salt Basin, a prolific petroleum habitat hosting the major oil fields of the Arabian Plate. The fields are located on the rising flanks of the Qatar Arch to the east and En Nala Anticline (Ghawar-Berri high) to the west, separated by a syncline from which the hydrocarbons were sourced. Exploratory efforts in Bahrain offshore acreages were concentrated on drilling low-relief structural prospects, which gave hydrocarbon indications. Regional lineaments play a dominant role in the generation-migration-entrapment cycle. This presentation will show a conceptual regional structural elements model that integrates all the available data. The objective was to focus
exploratory efforts on identifying fault-bounded traps as the dominant structural play in the offshore area. An integrated review of regional geology, seismic, gravity and satellite image data has brought out three dominant regional lineament trends corresponding to the NW-trending Najd strike-slip system, NE-SW Wadi Al Batin-Dibba trend and NS/NNW basement trend. These trends were reactivated during various phases in the tectonic evolution of the basin. The NE trend was active during Jurassic and the NW trend was dominant during Cretaceous. The oldest, NS-NNW basement trend was reactivated during the Late Cretaceous to Early Tertiary compressional phase resulting in the present-day structures. The predominant structural grain in the area is NS and associated with wrench tectonics analogous to the Abu Dhabi model (Marzouk an Abd El Sattar, 1995). A review of prospectivity of the offshore blocks, based on the present structural model, has brought-out many potential fault-closure traps. Finer scale mapping and
fault-seal analysis are vital to establish trap integrity. The role of these trends in determining preferred flow directions in the reservoirs of the Awali field in Bahrain requires further investigation.
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Salt diapirism in the fold-thrust belt and foreland basin in the eastern Fars Province, Iran
The Hormuz Series crop out as salt plugs in the Zagros Fold-Thrust Belt or as islands forming circular domeshaped structures in the Persian Gulf. The 7 to 12–kmthick sedimentary cover is decoupled from its basement by the Hormuz Salt layer and deformed by large-scale folding and thrusting that started in the Miocene Epoch. Recent emergent diapirs occur above the crests of preexisting domes, at the crest, nose or plunging axes of the folds. We also observed Hormuz residual along some thrust or wrench faults in the inner part of the fold-belt. A study of salt diapirs in the fold-thrust belt and foreland basin of eastern Zagros was based on seismic and well data analysis, field observations and analogue modeling. Several regional cross-sections were constructed from the Persian Gulf to the Zagros Suture Zone. They allowed us to investigate: (1) the kinematic scenarios for the main structural elements; (2) the role of deep-seated fault on deformation; (3) the role of pre-existing dome and salt intrusions during folding; and (4) evaluate the thickness of the Palaeozoic sedimentary pile. Finally, they present a reference for the pre-folding attitude and activity of salt domes in the foreland basin compared with the fold-and-thrust belt area. Salt plugs in the eastern Fars Province initiated as early as the Palaeozoic time, and were reactivated by subsequent tectonic events. They formed either: (1) emergent diapirs forming islands, especially in the Paleogene to Neogene Sea at the front of the fold-thrust belt, or (2) buried domes. Pre-existing salt diapirs strongly influenced the development of the compressive structures formed during the Neogene Zagros folding, as well as the style of deformation and the localization of the folds.
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Improved drilling performance in re-entry wells using high-performance waterbased drilling fluid in Bahrain’s Awali field
Bahrain’s Awali field, the Arabian Gulf’s first field discovered in the 1930s, has declined in production by almost 50% over the past 30 years. Specialized drilling techniques, such as re-entry drilling, have brought new life to the field. Due to the highly deviated and challenging horizontal sections often encountered on re-entry wells in the Middle East, non-aqueous fluid (NAF) systems have typically been required to provide maximum drilling performance, wellbore stability and deliver lower overall well costs. However, environmental constraints, disposal restrictions, and risks associated with the handling of the NAF systems negate the benefit of their use. While providing the necessary level of compliance, conventional water-based mud systems used in the Awali field have proven to be particularly ineffective at providing acceptable rates-of-penetration and wellbore stability. As a result, non-productive time (NPT) has increased and larger holes sizes are needed for successful liner placement. A high-performance water-based mud
(HPWBM) has been successfully used by the Bahrain Petroleum Company (Bapco) in the Awali field as an environmentally compliant and cost effective alternative to traditional NAF. The HPWBM was able to provide considerable improvement in WBM performance in these re-entry wells. It also provided the necessary wellbore stability and reduced formation damage required for open-hole completion. Additionally, pre-planning and communication with Bapco’s engineers resulted in the targeting of potential problems, such as limited hydraulics and zones of poor hole cleaning, allowing corrective action to be taken throughout the drilling process. This presentation discusses case histories of several re-entry wells that have been drilled in the area, along with a detailed overview of the HPWBM system and its benefits. Additionally, a discussion of the engineering that went into the planning and execution of these successful reentry wells is presented.
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