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GEO 2008
- Conference date: 03 Mar 2008 - 05 Mar 2008
- Location: Manama, Bahrain
- Published: 03 January 2008
41 - 60 of 385 results
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Geomechanics contribute to improved well-delivery in deep gas wells, northern Oman
Gas is being developed from the Lower Cambrian Amin Formation at depths of over 4,000 m (true vertical depth sub-sea) in northern Oman. Development drilling in some of the fields has been hampered by well stability problems in the overburden, as well as in the reservoir sections. An extensive data gathering (including timelapse calliper) and geomechanical analysis program was executed to understand the mechanism that control well stability. The derived geomechanical model for a specific northern Omani field confirmed a present-day stress environment with high horizontal compression (in excess of the overburden) as seen elsewhere in northern Oman. In addition, stress orientation and magnitudes appear to vary somewhat across the field, probably due to the proximity of a major active fault zone close to the field. These ambient stress conditions strongly influence wellbore stability during drilling. Five major well failure mechanisms were identified: (1) clay stability, (2) rock matrix failure, (3) fault-related failure, (4) fracture-related losses, and (5) fracture-related rock failure. Time-lapse caliper logs indicated that rock-matrix failure occurs rapidly, after which the borehole becomes stable for at least two months. Utilizing this information, upper and lower mud-window bounds for future vertical development wells were calculated. Subsequently, optimal mud-weight plans for different hole sections, including mediation plans for the various failure mechanisms, were developed. Following the implementation of the study results, together with further optimisation initiatives, significant gains on well-delivery times have been made by up to 50%.
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3-D visualisation on a plate scale model over the Middle East and North Africa
Authors Adam Finn, David M. Casey and D. Macgregor and Peter R. SharlandWith continuing improvements in technology, it is now possible to develop plate-scale regional 3-D subsurface models. We present a new 3-D approach towards understanding stratigraphic development at plate-scale rather than the more traditional field- or play-scale approach. This development requires consistent stratigraphic picks across continents – we have developed a global sequence stratigraphic model that allows us to achieve this. Regional depth maps have been constructed from public sources and then constrained to stratigraphic picks in many hundreds of published wells. Importing these surfaces into an RMS Cube on a grid of 1,000 m x 1,000 m, with dimensions of 3,000 km by 8,000 km, provides a striking plate-scale visualisation tool. Stratigraphic Modelling functionality allows the generation of intermediate surfaces - whilst following set rules, i.e. tie to wells, truncate above/below. Multi-angle cross-sections and views of the regional depth maps enable rapid assessment of adjoining basin stratigraphies,
from which potential seals, reservoirs and sources rocks can be examined. Once the regional depth maps have been constrained first, second and third-order isopach maps can be generated, identifying areas of sediment accumulation and subsidence. 2-D Gross Depositional Environment maps can be draped over corresponding 3-D horizons providing a powerful visual prediction tool for the locations of possible reservoirs. This also enables basin-scale datasets to be potentially extracted from the plate-scale model and developed into 3-D flow simulation grids, allowing petrophysical cell properties and transmissiblities to be entered. All of this offers the opportunity to undertake detailed regional analysis of petroleum systems.
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A novel pre-stack inversion technique investigating a carbonate reservoir’s rock properties
Authors Michael Fleming, Sarah Corrie and Gary Yu and Gary PerryA case study is described that investigated rock properties in a carbonate reservoir. The study used a novel pre-stack seismic inversion technique that integrated both broad-bandwidth seismic data and borehole data into the inversion workflow. The study used a 3-term pre-stack inversion methodology. The methodology is based on the application of the Aki and Richards linearized Zoeppritz equation for P-wave reflection amplitude as a function of incidence angle. A conditioning sequence was applied to the input pre-stack time-migrated gathers including, critically, an imaging step that provided broad-band, high-frequency seismic data. This highfrequency conditioning provides a stable wavelet across the seismic gather. This in-turn allowed both a better measure of the curvature term in the three-term equation, and also constrained the Earth model. Rock reflectivities were calculated from the amplitude-versus-offset (AVO) terms and integrated for the rock properties Pwave velocity (VP), shear modulus (μ) and bulk density
(ρ), with well logs used to constrain the inversion at various stages. These rock properties were combined with a macro-Earth model (created using well data) and high-frequency gather velocity analysis to yield absolute rock properties. The picked horizons were used to guide model population. A key step in the workflow was the generation and analysis of seismically derived and borehole-constrained elastic modulo cross-plots that allow the combination of several elastic parameters into a single composite geobody attribute. The visualization of such attributes, using state-of-the-art computer graphics techniques provided a valuable tool for understanding and interpreting reservoir lithology and fluid content.
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Production logs and well shut-offs in a GOGD giant field
New chemical and mechanical shut-off technology has been applied to a giant carbonate field that is being produced under mixed gas oil gravity drainage (GOGD) and waterflood. The shut-off technologies have aimed to minimise unwanted gas and water influxes by isolating fractures and permeable sub-layers. The trials included: (1) chemical shut-offs in the heels of horizontals to prevent vertical gas coning (fracture/cement bond issues); (2) mechanical shut-offs in the toes to seal gas under-runs through highly fractured layers; and (3) use of external casing elastomers (EZIP) to compartmentalise wells, and even isolate individual fractures malignant to well performance. Wellbore influxes were mapped-out from a campaign of horizontal-well production logs. The results included shut-in pass water-flow logs run in water-cut GOGD wells. They illustrated the inflow and exit of injected or aquifer water at individual fractures that used the wells as conduits for cross flow. Drill-fluid losses into producers have recently provided likely fracture pathways, as confirmed in one case with production logs. Some of these pathways follow a fracture trend that was identified in outcrop data overlying the field but not previously considered in the subsurface. Monitoring the outcome of the shut-off trials has further revealed reservoir behaviours.
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Preservation of pre-rift sediments and development of accommodation zones during the initial phase of Red Sea rifting
Successful exploration in the Red Sea requires a thorough understanding of the structural controls on reservoir and source-rock distribution. Pre-rift reservoirs are one major exploration objective, mainly comprising fluvial to shallow-marine clastics of Early Eocene, Paleocene and Cretaceous age. In the giant October and Ramadan fields in the Gulf of Suez, hydrocarbons sourced from the Upper Cretaceous “Brown Limestone” are produced from pre-rift reservoirs ranging from Cretaceous to pre-Carboniferous in age. Across the Red Sea region, the present-day distribution of pre-rift reservoirs and source rocks is controlled by both depositional paleogeography and the subsequent post-depositional structural history. The underlying Neoproterozoic basement fabric exerts
a fundamental structural control on preservation of prerift sediments. During the initial rifting phase in the Late Eocene to Oligocene, pre-rift sediments were preserved in hanging wall blocks formed by extensional reactivation of two major sets of sub-vertical lineaments: Najd shears trending (azimuth) 125–130o, and faults trending N-S. Along the Saudi Arabian coastal plain, pre-rift sediments are found in hanging walls located in the SW quadrant of the intersection of these two sets of basement lineaments.
Accommodation zones in the Red Sea region formed during the initial rift phase, and their location and trend is again related to the underlying Neoproterozoic basement fabric. The orientation of the Duwi accommodation zone in the northern Egyptian Red Sea is directly linked to the underlying Najd shear trend. Similarly, the newly identified Jeddah accommodation zone in Saudi Arabia (mapped from 2-D seismic data) follows the same Najd shear trend observed in the surrounding basement rocks. Discovery and analysis of the Jeddah accommodation zone will enable more accurate structural mapping of pre-rift fault blocks in the subsurface, together with more accurate prediction of potential syn-rift (Miocene) reservoirs.
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Silurian Tanf Formation prospectivity in the Euphrates Graben Petroleum System, Syria
This study aims to characterise the potential of Silurian strata as a co-source rock in the Euphrates Graben, Syria. The main Paleozoic source rock in the Arabian Plate is found in the Lower Silurian section (Tanf Formation in Syria), which is mature to overmature in the study area. However, the two main source rocks of Upper Cretaceous age in the study area are carbonates of the Shiranish Formation and the lagoonal, cherty Rmah Formation. 82 oil samples from reservoirs of different ages were
analysed by whole oil gas chromatography and detailed analysis of biomarkers and aromatic hydrocarbons by gas chromatography-mass spectrometry. Additionally, 16 Silurian rock samples are still under investigation for this study. Based on compositional parameters such as the pristane/phytane ratio, three geographical areas representing different depositional environments were recognised. In addition, oils from the southeastern part of the graben seem to be highly mature; for example based on light hydrocarbons and the occurrence of diamondoid hydrocarbons whose concentrations are relatively high due to the thermal cracking of the major oil constituents. In contrast, conventional biomarker maturity parameters had already reached equilibrium values in the oils from the southeastern part of the graben due to overmaturity. The gammacerane index shows relatively high values referring to hypersaline conditions. Therefore oil mixing from different sources has to be taken into account. Because Cretaceous source rocks may also reach high maturity levels, compound specific stable carbon and hydrogen isotopes will be elaborated upon as an additional oil-source rock correlation tool to better understand the potential role of the Silurian strata
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Origin of burial diagenetic illite and its effect on porosity and permeability of Unayzah sandstone reservoirs (Permian-Carboniferous) of Saudi Arabia
More LessBurial diagenetic illite and quartz are the primary cements, which affect porosity and permeability in deep Unayzah reservoir sandstones in Saudi Arabia. The ultimate source of illite is the alteration of feldspar, mainly K-feldspar. Feldspar is altered to kaolinite to varying degrees during early burial. During later burial to depths where temperatures exceed about 100oC, remaining feldspar reacts with kaolinite to form illite via the reaction: K-Feldspar + Kaolinite = Illite + Quartz. The amount of illite that forms is limited by the amount of reactant in least supply (kaolinite or feldspar). When either of the two reactants is exhausted, illite can no longer be generated by this reaction. Accordingly, Unayzah sandstones can be classified as Feldspar-Limited or Kaolinite-Limited
based on which reactant is consumed first and thus is the limiting factor on the amount of illite formed. Feldsparlimited sandstones typically have less diagenetic illite than Kaolinite-Limited sandstones. Feldspar-Limited and Kaolinite-Limited sandstones have distinct geographic distributions. The distributions may partly be related to provenance (original feldspar content), but early invasion of meteoric water into the basin margin is interpreted to have played an important role as well. This early leaching of feldspar partly controls the distribution of Feldspar-Limited sandstones and thus the subsequent distribution of illite. There is no evidence to support continued illite formation directly from feldspar after kaolinite is consumed, e.g. 3KAlSi3O8 + 2H+ = KAl2(Si3Al)O10(OH)2 + 2K+ + 6SiO2.
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Origin and evolution of pore water in coastal and inland clastic sabkhas and salt pans of Saudi Arabia
Coastal and inland sabkhas of Saudi Arabia are primarily quartzose clastic sabkhas. In some cases they have developed on older aeolian dunes now submerged beneath the present-day water table. Models of early cementation of ancient sabkha deposits frequently called for precipitation of carbonates and sulfates from sea water by evaporative pumping: the inflow of sea water through the sabkha to replace pore water evaporated at the sabkha surface. The landward extent of the sea-water influence was usually not addressed. Pore water samples collected along transects from the sea, coastal sabkhas and inter-dunal sabkhas, more than 100 km inland, were analyzed to determine the extent of sea-water influence. Included in this study are pore waters from Sabkha
Matti, one of the largest sabkhas in the world. Stable isotopes, ion chemistry and strontium-isotope composition of these sabkha waters indicated that the influence of marine water is limited to a narrow zone within a few kilometers of the coast. Landward of this narrow band, meteoric water appears to be the sole source of sabkha pore waters and is a significant component in some coastal salt pans. Even in the present-day low-lying, hyperarid desert of southern Saudi Arabia, the water table rises inland and the hydraulic head tends to drive meteoric water seaward preventing incursion of marine water into sabkhas except in a narrow band very near the sea. Results of this study have implications for interpreting early cements in ancient desert sediments like the Permian-Carboniferous Unayzah of Saudi Arabia.
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Geochemical characterization of petroleum in Jurassic reservoirs south of Ghawar field, Saudi Arabia): Implications for the petroleum system
Geochemical characteristics of recently discovered petroleum in Jurassic reservoirs of the Halfah, Yabrin, Dirwazah and Tukhman fields, south of Ghawar field (Saudi Arabia) are different from typical Jurassic crudes in the Abqaiq, Ghawar, Mazalij and other fields. The latter fluids correlate well with the excellent oil-prone source rocks from the Tuwaiq Mountain and Hanifa formations of the Arabian Basin. These classic Ghawar-type mediumgravity oils represent high-sulfur crudes (greater than 1%), have pristane/phytane (Pr/Ph) ratios typically less than 0.8 and contain biomarkers indicating that the oils are derived from source rocks deposited in a marine carbonate environment under anoxic, reducing conditions. Characteristic biomarker parameters that support this interpretation are C29-hopane/C30-hopane ratios that exceed 1.0, relatively low abundances of diasteranes, and dibenzothiophene/phenanthrene (DBT/P) ratios typically exceeding 3.0. The Halfah-Yabrin-Dirwazah-Tukhman crudes, south of Ghawar field, have low-sulfur contents (less than 1.0%), Pr/Ph ratios ≥1.0, C29-hopane/C30-hopane ratios less than 1.0, and relatively high amounts of diasteranes and the C24 tetracyclic terpane. Most of the differences in sterane and hopane biomarker distributions compared to the Ghawar-type fluids appear related to differences in the abundance of clay versus carbonate in the source rocks. These data provide evidence for a source rock organic facies change south of Ghawar field. This presentation discusses recent results related to oil-oil and oil-source rock correlations, genetic relationships, and their implications for exploration in the southern part of the Arabian Basin.
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Information management for the asset team
More LessManaging the growing volumes of information and data is fast becoming a significant issue for most E&P asset teams. Schlumberger Information Solutions has developed a unique set of solutions using the ProSourceTM suite of software to manage across multiple projects and multiple data stores the asset team’s information. Data stores include PetrelTM, GeoFrameTM, OpenWorksTM and FinderTM, with connections to any other data stores that are OpenSpiritTM enabled. Key workflows include, globally searching across multiple projects and multiple data stores using a single application console that centralizes the project data management, eliminating project by project data management. Visualizing the information via GIS or in spreadsheets, automated quality control assurance for data integrity using data compare tools which brings confidence and data consistency to the end user, quality tagging of the data, capturing of milestones of interpretation data into a vendor neutral repository for easy retrieval for partners. Creation of an audit trail for your E&P studies and regulatory reporting. If these solutions fit your E&P needs the ProSource suite of solutions can help you manage your E&P asset teams and minimize the time administrating and maximize the
quality and consistency of the data being used by your asset team.
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Reservoir characterisation of a heterogeneous hydrocarbon field, Khuff (Kangan-Dalan) Formation, Middle East
Analysis of previously unpublished data from a major Middle East gas field has resulted in an integrated study of the Khuff Formation. Conceptual geological models for the field will be presented, providing an opportunity for comparison with other published data in the region. Detailed sedimentological work of three extensively cored wells has enabled the identification of a suite of lithofacies, which are grouped into seven facies associations. Depositional settings range from marine grainshoals, through to restricted tidal flat settings with common evidence of exposure. Shallowing-upwards cycles form the basic building blocks in the sequence stratigraphic framework. Cycles are organised into packages, termed high-frequency sequences (HFS), which possibly reflect
fourth-order relative sea-level variation. At a larger scale, HFS’s are grouped to form four major depositional sequences (K4 – K1). These are comparable to the thirdorder sequence described by Sharland et al. (2001). Cycles show distinct trends in thickness variation, which can be traced in all cored wells. Thicker cycles typically occur within marine ooid-grainstone facies of the transgressive systems tract (TST) of large scale sequences, whilst thinner cycles are more typical of restricted facies of the highstand systems tract (HST). Diagenesis has significantly modified the primary depositional facies. The key diagenetic processes include: (1) cementation: primarily calcite and anhydrite; (2) dissolution: dissolution of grains, in particular ooids; (3) dolomitisation: both early evaporitive (in late HST) and hydrothermal processes associated with faults. Reservoir potential is related to the interplay of primary depositional facies and subsequent diagenesis. The best reservoir quality is associated with dolostones, although overdolomitisation and anhydrite cementation are commonly detrimental. TST grainstone facies are prone to calcite cementation; however, dissolution of grains significantly improves porosity. Conceptual geological models have been built based on the HFS stratigraphic framework, and these models are the input for the flow-unit and geo-modelling.
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First microseismic monitoring results for a Middle East carbonate reservoir: Minagish oil field case study, western Kuwait
During the first quarter of 2006, a microseismic monitoring pilot was implemented in Minagish field, western Kuwait. The target zone was the Minagish Oolite, a microporous carbonate reservoir, about 350 ft thick and around 9,600 ft deep (below mean sea level). The monitoring antenna, an SST-500 wireline tool of four 3C-geophones, was temporarily deployed in an abandoned well on the eastern flank of the field. The purpose of the surveillance was: (1) to assess the occurrence of microseisms induced by the production operations and especially the water injection along the flank; then (2) to characterize such microseismicity; and finally (3) to measure the effective network sensitivity with depth. Such a microseismic pilot survey should provide insight on the
added-value that this monitoring technique may bring to the production and reservoir engineers. During the 50 days of effective monitoring, about 2,000 microseisms were identified and 600 events, from magnitude -2.0 to 0.3, were located. The large majority was distributed on the western side of a NNE-trending line as consistent with the direction of the local oil-water contact. A more detailed analysis also highlighted clusters of microseisms between injection-production doublets. In fact, one doublet was believed to be connected, which has been confirmed. Additionally, the depth survey showed that microseismic monitoring was still efficient above the Shu’aiba Formation. The pilot’s objectives were successfully attained and the results were beyond our expectations. Hence, it is proposed to deploy a cost-effective and optimized microseismic network suitable for the entire Minagish field.
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Production attribute mapping workflow to assess remaining resource potential and distribution of water in the First Eocene reservoir at Wafra field, Partitioned Neutral Zone, Saudi Arabia and Kuwait
More LessThe First Eocene reservoir at Wafra field was discovered in 1954 and has produced about 290 million barrels of 17-19o API, high sulfur oil. The estimated oil-originallyin-place exceeds 9 billion barrels. Previous studies, which have relied on static data, were not able to quantitatively predict water-cut and water-saturation trends within this reservoir. A production attribute mapping workflow was developed that incorporated static and dynamic data. The workflow has been used to define the current distribution of oil and water within the reservoir and provide an estimate of remaining hydrocarbons inplace (RHIP) by area and stratigraphic layer. Estimation of RHIP utilizes a workflow in which full-field saturation maps representing reservoir conditions at the end of 2006 are generated using production attribute mapping techniques. The saturation map is combined with original net pay porosity-thickness values to generate a map of RHIP. Defining the current distribution of water within the reservoir is a complex task due to the long
production history and large number of wells in the reservoir. A workflow was developed to map water-cut through time, with a focus on the earliest producers in the reservoir. Preliminary results suggested that the waterfronts initially move primarily from the north and south in structurally low areas. After about 12 months, the waterfronts begin to converge and appear to fully converge within about 120 months. Migration from the southwest may not be related to structure, but may be influenced by facies distribution. Results from the production attribute workflow will be used as part of on-going reservoir management decisions as well as to update current static and dynamic reservoir models.
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Tectono-stratigraphic comparison of two petroliferous provinces in the northeastern Iraqi portion of the Arabian Plate
More LessNortheastern Iraq has two contiguous, petroliferous tectono-stratigraphic provinces that lie at similar regional structural elevations and yet have contrasting play elements, owing to their different Late Mesozoic to Cenozoic evolution: (1) Kirkuk embayment foldbelt (“Kirkuk”, from the Hamrin Mountains northeastward in the Kurdistan part of Iraq), with Tertiary reservoirs in high-relief anticlines; and (2) northwestern Mesopotamian foreland (“NW Mesopotamia”, the northern Mesopotamian Plains, from the Hamrin Mountains southwestward to the Euphrates River), with Cretaceous reservoirs in low-relief traps. Both provinces were within the Gotnia Basin during the Late Jurassic and in similar carbonate-prone depositional environments until the Late Cretaceous. Late Cretaceous obduction of Tethyan ophiolites onto northeastern Arabia created an orogenic load and sedimentary provenance that affected Kirkuk and NW Mesopotamia differently. Kirkuk was in a NWtrending foredeep, with clastic input on its northeast flank and deep-water, reservoir-poor carbonates on its southwest flank. NW Mesopotamia remained part of the Arabian platform with deposition of reservoir-prone carbonates. Tectono-stratigraphic differentiation between the obduction-related Kirkuk foreland basin and the NW Mesopotamian platform lingered through the Paleogene and Early Miocene. The Kirkuk foreland accumulated several hundred meters of Eocene to lower Lower Miocene carbonates that are its principal reservoirs. In contrast, NW Mesopotamia accumulated much thinner Paleogene to Lower Miocene carbonates. Collision of the Arabian and Eurasian plates in the Neogene created first the Taurides and then the Zagros Mountains. Kirkuk underwent northwestward-increasing truncation of Paleogene reservoirs beneath a pre-late Early Miocene unconformity, then rapid burial in the Zagros Foreland Basin, and finally uplift, as large anticlinal traps grew as far southwest as the Hamrin trend. Meanwhile, NW Mesopotamia subsided as part of the Zagros Foredeep.
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Structural genesis of hydrocarbon traps of Iraq
More LessIraq’s hydrocarbons (134 billion barrels of oil and oilequivalent: OPEC, 2004) occur in many structural habitats. Using major fields, we illustrate structural styles from Iraq’s four main hydrocarbon provinces and give interpretations of their genesis. The Kirkuk embayment in northeast Iraq involves Late Miocene and younger SW-verging, fault-propagation folds (Zagros-driven) fed by slip along Lower Jurassic detachments. The principal Tertiary reservoirs at the Kirkuk field include an Eocene through Lower Miocene carbonate-prone section beneath a lower Middle Miocene angular unconformity along which truncation increases to the northwest. The post-unconformity Middle Miocene section carries the topseal. In southern Iraq, within the southwest flank of the Mesopotamian Foredeep (Zagros Foreland Basin), the major traps (e.g. Rumaila and Zubair fields) are large, N-trending anticlines, each with several crestal culminations and gently-dipping flanks (2° to 4°). The Mesozoic reservoirs are little faulted. Long-lived,
episodic evacuation of infra-Cambrian Hormuz Salt beginning as early as Late Jurassic controlled trap-genesis. Basement grain, reactivated during the Hercynian, controlled the N-S trend of the later evacuation synclines. In contrast, Central Iraq’s Mesopotamian traps have NW-trending basement-involved faults, some of which had reverse slip (transpression?) during both the Late Jurassic and the Neogene and others of which had normal slip (transtension?) during the Late Cretaceous. Iraq’s lightly explored Western Desert has Paleozoicsourced exploration potential at depths much shallower than elsewhere in Iraq, owing to (1) post-Late Jurassic to pre-Albian southward tilting, uplift, and erosion; and (2) Late Cretaceous N-S extension. Iraq’s structural styles reflect variable impact, from one region to the next, of (1) basement grain and faults, (2) Hormuz Salt distribution, (3) Hercynian orogeny, (4) creation of Tethyan passive and transform margins and their destruction resulting from Arabia’s collision with Eurasia.
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Integration of sedimentology, sequence stratigraphy, and seismic stratigraphy of the Lower Cretaceous Shu’aiba Formation in an oil field of northwest Abu Dhabi, United Arab Emirates
The Lower Cretaceous (Aptian) Shu’aiba Formation is an important carbonate reservoir of the subsurface of Abu Dhabi. At an oil field located in northwest Abu Dhabi, the reservoir is comprised of interior platform, platform margin, clinoform belt (prograding wedges) and intra-shelf basin deposits. Sedimentologic and petrographic core description identified 12 lithofacies types, ranging from shallow-marine, rudist-rudstone to deep-marine, planktonic foraminifera wackestone and shale. Caprinids (Offneria sp.) dominate the Shu’aiba platform margin and the proximal clinoform belt. Algalstromatoporoid facies and caprotinid debris are indicative of the distal clinoform belt. Planktonic foraminifera wackestone and shales dominate the intra-shelf basin deposits (Bab Member). The Shu’aiba deposits at an oil field located in northwest Abu Dhabi fit well into the sequence stratigraphic framework established for a giant oil field of central Abu Dhabi. Shu’aiba transgressive and early highstand sequence sets are built by the Ap2
and Ap3 sequences, Shu’aiba late highstand sequence set comprises the Ap4 and Ap5 sequences, and the Bab lowstand sequence set is represented by the Ap6 sequence. However, the platform margin appears to be steeper in northwest Abu Dhabi, as the area of the Upper Aptian (Ap4 and Ap5 sequences) distal clinoform belt is narrower than the one encountered at central Abu Dhabi. Three-dimensional seismic analyses allow mapping of the platform to basin geometries. The areal extent of the interior platform, the platform margin, the clinoform belt, and the Bab Basin can be outlined by seismic cross-sections and seismic amplitude maps. All available data were successfully incorporated in a new 3-D static model, addressing uncertainties in terms of structure,
stratigraphy, and reservoir quality.
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The concept of entrapment: Towards expanding the paradigm
More LessThe current conceptualization and approach of exploration sets a specific timing for hydrocarbon migration and entrapment and certain geometries for accumulation. The simplest of those is the anticlinal four-way dip closure in which the lighter hydrocarbons migrate up-dip due to their density contrast with the water to arrive to a pseudo-stagnant state. Such an understanding of a simple fluid behavior led to the discovery of huge reserves worldwide. Although successful, limiting the migration and entrapment model to only such physical conditions can be limiting to our hydrocarbon-finding ability. An expansion of the migration and entrapment model that recognizes the dynamic behavior of hydrocarbons than just the pseudo-stagnant model can define new exploration
opportunities. The model is supported by analyzed discovery fields, laws of physics, physical and numerical models. The new paradigm states that: (1) hydrocarbons are in continuous movement during basin evolution; (2) entrapment is a phase of the hydrocarbon movement; (3) massive volumes of expelled hydrocarbons continue to move on a geological time scale; (4) perfect seals are not in line with known behavior of even the tightest rock over a geological time scale; and (5) hydrocarbons will
become stagnant only in a site of subsurface hydrocarbon energy minima, which is rarely sustained during the life of an accumulation. The above paradigms define a new set of traps and real examples supported by physical and numerical models are presented. A set of mapping techniques to identify those traps is proposed. The Arabian Platform tectonic and depositional history, and hydrodynamic conditions form a hydrocarbon-prospective region to apply such new concepts and techniques.
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Multi-lateral horizontal well application for improving the oil recovery of a mature field, Intisar 103N, Libya
Authors Mohamed M. Gharsalla and Mohamed B. ElghmariThis presentation examines the performance of a horizontal well with multi-lateral completion in the mature Upper Sabil Reservoir in the Paleocene Zelten Formation in Intisar 103N field. The hydrocarbon trap in an anticline that houses 14.4 million stock tank barrels (MMSTB) of oil-initially-in-place. The reservoir is highly under-saturated with oil of 42° API gravity. The initial field development with a vertical well resulted in a poor recovery, 1.3 million barrels of oil in 19 years of production (equivalent to a recovery factor of 9%). The recovery mechanism in the reservoir is mainly rock-fluid expansion with marginal support from flank aquifers. The poor recovery can be attributed to thin pay thickness, poor reservoir quality, large well spacing, and the lack of pressure support from aquifers. The vertical well revealed a nearly constant production rate for the last 17 years indicating the drainage area is much larger than one well can deplete in a reasonable time frame. The incentive of reducing well-spacing existed but the question was how to reduce the well spacing: by drilling many vertical wells or a lesser number of horizontal wells? A reservoir simulation study in 2003 indicated that drilling vertical wells in a very thin reservoir of poor quality was not cost-effective. Hence, an horizontal well was
drilled and completed at the top of the porosity zone with two lateral legs extending 1,632 and 2,811 ft. Two lateral sections were branched-out from the same spot in the well with a 47° angle between them and completed open-hole in the reservoir. The stabilized oil production rate of the horizontal well was approximately three times greater than that of the vertical well, whereas the drilling cost of the horizontal well was about 1.3 times higher. The production from the horizontal well showed no negative impact on the production performance of the existing vertical well. The oil reserves, as a result of putting the horizontal well on stream, are expected to increase by 1.8 million barrel. It is evident that horizontal wells with multi-lateral completions can improve oil
recovery, accelerate oil production and reduce production cost. The reduced pressure gradient in the reservoir,
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Sedimentation framework and tectonostratigraphic development of the Muglad Basin Sudan
More LessThe Muglad Basin, located in southwest Sudan, forma a major part of the Sudan Rift System, which in turn, is a main component of West and Central African Rift System. The rift started to develop during the Late Jurassic and Early Cretaceous times. This intra-continental rift system evolved through a three-phased tectonic history spanning Berriasian to Cenomanian, Coniacian to Maastrichtian and Paleocene to Pliocene. The sediments in the Muglad rift basin consist of Lower Cretaceous to Upper Tertiary non-marine cyclic sequences of lacustrine and fluvial/alluvial facies and directly rest upon the Proterozoic basement. Concentrating on the first rift cycle, this study reviews the sedimentation framework as a function of subsidence and thermal contraction. The
database is mainly from proprietary exploration work consisting of 2-D and 3-D seismic data, well logs, core and borehole image logs. The Abu Gabra Formation is a typical argillaceous facies dominated by cycles of lacustrine shale prograding to deltaic sands. This lacustrine shale provides good hydrocarbon source rock while the deltaic sand proved to be a good quality reservoir. This cyclicity could be due to the fact that accommodation space was created by rift pulses rather than through continuous subsidence. After the cessation of rifting, thermal contraction probably occurred and created accommodation space, which was then gradually filled by the Bentiu Formation, consisting mainly of arenaceous fluvial sequences. These sands represent main reservoir units in the basin. Seismic data, logs and borehole image logs show a clear angular unconformity between Abu Gabra and Bentiu formations.
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Facies analysis and depositional environment of the Upper Devonian Geirud Formation in the Tuyeh area, eastern Alborz Mountains, northern Iran
Authors Elham Ghouchi Asl and Yaghoob LasemiThe Upper Devonian Geirud Formation is a mixed carbonate and siliciclastic succession in the Alborz Mountains of northern Iran. It was deposited on the passive Paleo-Tethys margin of northern Gondwana. It is over 250 m thick and is bounded by the post-Lower Ordovician and the basal Carboniferous unconformities. Facies analysis of the Geirud Formation in the Tuyeh and adjoining areas of eastern Alborz recognized various clastic, mixed carbonate-clastic, carbonate and storm facies related to a ramp platform setting. The clastic facies comprise inter-bedded sandstone and shale demonstrating fining upward (fluvial) and coarsening upward (deltaic/shoreface) cycles. Cross- lamination/cross-bedding and hummocky cross-stratifications have been recognized in the deltaic and shoreface environments. Mixed carbonate-clastic shoal facies consist of cross-bedded sandy echinoderm bioclast grainstone and fossiliferous subarkose. Carbonate facies comprise girvanella bioclast grainstone (inter-tidal), gastropod/foraminifer
mudstone to packstone (lagoon), echinoderm/brachiopod grainstone (barrier) and bioturbated fossiliferous mudstone to packstone (open marine). The carbonate and mixed clastic-carbonate facies are arranged into meter-scale shallowing upward cycles. Both clastic and carbonate storm deposits related to delta/shoreface, lagoon, barrier, proximal open-marine and distal openmarine environments were recognized. The storm facies fine upwards and are characterized by the presence of basal erosional surface, hummocky cross-stratification, intraformational conglomerates and mixed component of various facies.
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