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GEO 2008
- Conference date: 03 Mar 2008 - 05 Mar 2008
- Location: Manama, Bahrain
- Published: 03 January 2008
1 - 50 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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