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GEO 2008
- Conference date: 03 Mar 2008 - 05 Mar 2008
- Location: Manama, Bahrain
- Published: 03 January 2008
341 - 360 of 385 results
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Land seismic noise suppression: Tough challenge, intelligent implementation
Authors Khalid Al-Rufaii and Weihong ZhuLand data, unlike marine data, are associated with complex surface and near-surface geology, which generate a suite of coherent and non-coherent noises. The suppression of such types of seismic noise has long been a great challenge for both 2-D and 3-D seismic data processing. This is because signal and noise share the same range of seismic characteristics such as velocity and frequency. In this presentation, we introduce a new methodology for noise suppression that is based on the principle of localized
transforms. We demonstrate that utilizing localized transforms, unlike other conventional methods, ensures preserving the integrity of the seismic signal in terms of its amplitude and frequency contents. Our methodology focused on the suppression of mainly two types of seismic noise: linear and strong-energy randomly generated noise. Our approach is model-based and operates in 2-D and 3-D pre-stack modes. A key characteristic is that it tapers and scales-down the noise rather than muting it out. The linear noise is first suppressed by implementing a localized 3-D filter in the frequency-wave number (FKx-Ky) domain. Next, for each localized filtered data, an average amplitude spectrum is computed. Finally, a certain threshold value is assigned for trimming or scalingdown the linear noise, followed by an inverse transform back to the time-offset domain. These steps are repeated continuously with overlaps in time and space. The strong energy noise, being narrow band-limited, is tapered in a slightly different manner. The processes involve 1-D Fast Fourier Transform (FFT), decomposition via band-pass filtering, and median-filtering. The effectiveness of our proposed noise-suppression methodology is illustrated with both synthetic and field land data example.
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Uncertainties and risks associated with prospectivity of Mauddud Formation in the Bahrah area, Kuwait
The Bahrah area is located on the Kuwait Arch, between the giant Burgan field to the south and the Sabiriyah field to the north. Although the first exploration well in Kuwait was drilled in the Bahrah area in 1936, exploration and delineation of Bahrah’s reserves remained difficult due to the complexity of the structural setting, minor oil columns, widely varying oil and reservoir qualities, and uncertainties associated with seismic mapping. Out of 16 penetrations so far, only three wells have been completed in the Mauddud Formation, of which two are producers. Data acquired to date represent different vintages of wireline logs, seismic surveys and scant pressure records. Observed contacts (oil-water-contact, ODT and WUT) on logs and structural closures do not appear to be consistent. This may be due to uncertainties in timedepth conversion and/or trapping mechanism related to the role of faults and/or stratigraphic components, all of which remain to be understood. Oil samples collected from the Mauddud show variations in API gravities ranging between 23° and 29°. The oil qualities, saturation profiles and structural development during the geologic past appear to be related. Careful interpretation has revealed that better quality oil can be predicted in areas where early migration and retention of oil conformed to lesser post-migration structural deformation. To address the exploration challenges, a strategy has been devised towards intensive data acquisition including cores and fluids. This will enable us to establish a vertical zonation
in terms of reservoir and oil qualities, and to propose horizontal wells in sweet zones.
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Use of reservoir compartments concept in management of western flank area of a mature field in Kuwait
Authors Ghiyath A.H. Al-Sabeq and Maximilliano P. RivasThe objective of this study was to apply the concept of compartmentalization in the Greater Burgan field. It focused on a western flank area of a specific reservoir and applied the best reservoir management techniques to find or delineate pockets of bypassed oil. The developed sands in the field are continuous and act as such for a long time during production. However, the identified compartmentalization effect was only evident at a later stage following the long production interval associated with a single oil-water contact behavior. This was a result of variations in the regional water contacts, which had structural and stratigraphic implications in the study area. The task involved the determination of the volume and location of remaining oil, and subsequently the technical
and economic assessment methods to recover it. The remaining mobile oil is located in a number of predictable locations in the reservoirs depending on their structural style and facies. The main task is to re-develop the bypassed oil rims and attic oil in faulted sandstone reservoirs. The compartments were assumed to have the same oil-water contact. Attic oil along faults is perhaps the simplest configuration to redevelop and contains sizeable oil volumes. Calculations of the remaining oilin-place used the most recent maps with updated Pulsed Neutron Capture log data interpretation to generate the most recent oil-water contact data. The study included benefits such as: (1) a better way of estimating and identifying remaining oil in a particular compartment; and (2) easier diagnosis of reservoir actions needed by reservoir management.
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Index fossils of the Late Palaeocene-Early Eocene Jafnayn Formation, Al Batinah Coast, northern Oman
Authors Abdul Razak S. Al-Sayigh and Osman S. HersiThe Jafnayn Formation is an Early Paleogene carbonate unit that crops out widely along the Al Batinah coastal plain of northern Oman. It unconformably overlies the uppermost Cretaceous Al-Khod Conglomerates and is overlain by the Lower to Middle Eocene Rusayl Formation. The Jafnayn Formation is informally divided into two members that are separated by a biostratigraphically identified unconformity. The lower member comprises an upsection sequence of low to moderate energy, inner-shelf to lagoonal strata of (1) mudstones and wackestones, (2) massively-bedded, pseudonodular, bioturbated wacke-packstones, and (3) bioclastic mudstones. The lower member is dated as Late Palaeocene (Thanetian) based on the occurrence of the foraminifera Lockhartia
diversa, Daviesina persica, Kathina sp. and Nummulitoides margaretae (NP8?). The upper member is Middle to Early Eocene (Ypresian) as suggested by the occurrence of Sakesaria cotteri, Heterostegina ruida and Nummulites globulus. It comprises coral and red algal-rich, well-bedded, occasionally rudaceous, nodular packstones-grainstones and cross-bedded calcarenites deposited in a shallow (less than 10 m), fairly high-energy open-marine shoal environment with nearby patch reefs supplying coral debris. The base of the upper member is marked by a locally distinctive thin (1–3 m) pebble bed rich in various siliciclastic grains and clasts reworked from the underlying member. The pebble bed was deposited immediately after a distinctive depositional hiatus corresponding to the upper part of the Upper Palaeocene and lower part of the Lower Eocene i.e. approximately two nannoplankton zones (NP9–NP10) representing the upper part of the Alveolina (Glomalveolina) levis zone to the lower part of the A. ucumiformis/ A. trempina zones. Although this hiatus is recognised lithologically and biostratigraphically at Wadi Rusayl, at other localities it is only detected through detailed micropalaeontological analysis.
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Tectonic evolution of the Jurassic Humma Marrat structure, Kuwait and Saudi Arabia Partitioned Neutral (Divided) Zone
More LessThe Humma structure is an elongated, NNW-oriented, doubly plunging anticline situated in the southwestern corner of the Partitioned Neutral (Divided) Zone (PNZ) between Kuwait and Saudi Arabia. It produces from the Jurassic Marrat reservoirs and is the only Jurassic producer in the PNZ. It was discovered in 1998 following several unsuccessful wells that targeted Cretaceous reservoirs beginning in the 1950s. Data from open-hole logs (formation imaging tools, magnetic resonance elemental capture spectroscopy, shear sonic, and Stonely permeability) have been integrated with both the oriented core data and 3-D seismic interpretation to reveal the stratigraphic genesis and the tectonic evolution of the Humma structure. The complexity of the Jurassic Marrat reservoirs is attributed to the rapid change in facies from north to south, as well as from base to top. Depositional environments for the Lower Marrat are predominantly low-energy inner-shelf (inner ramp to lagoonal) settings. The Lower Marrat reservoirs possess a combination of inter-crystalline and moldic porosity with tectonic fracture to breccia porosity. The Middle Marrat reservoirs are a stacked succession of individual and overall shallowing upward cycles. Deposition was in a protected sub-tidal, open shelf lagoon to largely filled intra-shelf basin as part of a progradational parasequence set. Open fractures of massive dolomite matrix characterize the Middle Marrat reservoirs. Both kinematic and dynamic analyses for the Humma structure revealed that the NNW-trending structural axis for the Humma closure is in-parallel with the major fault that bounds the structure. The NE-SW to NW-SE oriented open fractures are the manifestation of a dextral strike-slip wrench tectonic system as depicted by a simple shear tectonic model. The tectonic evolution of the Humma structure was initiated in the Late Jurassic (Kimmeridgian), culminated during the Early Cretaceous and continued throughout the Late Cretaceous. The simple-shear tectonic model applied to the Humma field is
well-expressed by a flower structure associated with both the Jurassic Marrat and Cretaceous Thammama Group. The expression is also interpreted from 3-D seismic of the Shu’aiba Formation, oriented core and borehole image data. The tectonic model applied herein is believed to be applicable elsewhere in the Gulf region. The data integration, assimilation and analysis approach, proposed in this presentation, is recommended for similar complex reservoir studies in other parts of the Gulf region.
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Stratigraphic framework of the Mafraq Formation, northern Oman
Authors Hamad Al-Shuaily, Omar Al-Ja’Aidi and Henk Droste and John AitkenThe mixed clastic-carbonate Mafraq Formation (Late Triassic-Middle Jurassic) is the lowermost unit of the Sahtan Group in Oman. The formation comprises a fluvial to shallow-marine succession that onlaps the tilted Akhdar Group (Permo-Triassic) unconformity from the northwest to the southeast. Despite producible gas and oil indicators, the Mafraq Formation has remained largely underexplored and is poorly understood in Oman. A regional stratigraphic framework for the Mafraq Formation has been developed, which incorporates seismic, well, outcrop, core and biostratigraphic data. This permitted an assessment of the depositional and structural controls on the distribution of the Mafraq Formation. Improved understanding of the Mafraq play suggests potential for both conventional and stratigraphic trapping configurations. The Mafraq Formation is a complex diachronous depositional system including offshore, shallow-marine, coastal-plain, fluvial and alluvial-plain environments with stratal termination patterns visible on seismic. Several transgressive-regressive cycles can be identified including: (1) a Late Triassic regression that resulted in the deposition of fluvial sandstones in the northwest; 2) a Late Toarcian regression leading to the deposition of a fluvial system in the central part of northern Oman; (3) an Early Aalenian flooding that deposited shallowmarine oolitic limestone in the northwest; and (4) a Midand Late Bajocian flooding resulting in the deposition of marine sandstone in the southeast. Two principle trap types have been identified, namely conventional structural traps (either fault-bounded or salt-induced) and stratigraphic traps including isolated channel, pinchout, truncation and onlap traps. The play is largely dependent on reservoir and seal thickness variations
controlled by primary depositional processes and halokinesis and fault-related accommodation.
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Parameter estimation of velocity function in unconsolidated sand via semblance velocity analysis
Authors Abdullatif A. Al-Shuhail and Abdulrahman A. Al-ShuhailPrevious theoretical and field studies suggest the existence of continuous velocity-depth functions in unconsolidated sand layers. One such function is V(z) = V0 √(1+kz1/3), where V0 and k are the velocity function parameters which depend strongly on the layer porosity (Φ) and water saturation (Sw), and to a lesser extent, on the properties of the sand matrix, pore water and air. To properly understand seismic wave propagation in an unconsolidated sand layer, it is important to know its velocity-function parameters. This study proposes a procedure to estimate the velocity-function parameters in unconsolidated sand layers. Velocity-function parameters are generally independent.....PDF
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Learnings from a vertical seismic profiling (VSP) programme
More LessPetroleum Development Oman (PDO) has been acquiring VSP (vertical seismic profile) data for the past 30 years. The different types of VSP data have been used for different objectives. ZOVSPs (zero-offset vertical seismic profile) and OVSPs (offset vertical seismic profile) are considered valuable and are used for time-to-depth calibration, seismic-to-well matching and identification of multiples on surface seismic. The OVSP is normally carried-out in deviated wells or over steeply dipping layers.We will show that the processing of ZOVSP and OVSP is not trivial and how erroneous processing steps or changing assumptions can lead to very different results. This will be demonstrated with a case study of processing ZOVSP with different contractors. WAWVSPs (walk
away vertical seismic profile) have typically been used in an attempt to obtain better structural imaging and for time-lapse studies with limited or no successes. In PDO the confidence level in WAWVSPs is often low, resulting from an often-observed poor match of the processed WAVSP data with surface seismic data. This mismatch is observed in the form of: (1) considerable differences in structural dip; (2) events that could be interpreted as faults, which are not present in the surface seismic; and (3) wrong amplitudes differing from surface seismic. In addition to these problems, the bandwidth of the VSP data is not higher than surface seismic, contrary to expectation. These problems will be illustrated with examples of processed WAWVSPs from different fields.
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Sequence stratigraphy and basin modeling of the Eocene succession from Kurdistan region, northeastern Iraq
More LessThe Eocene strata of the Zagros segment in Sulaimaniya area, northeastern Iraq, have been interpreted to contain two third-order sequences. The oldest Ypresian third-order sequence is represented by transgressive and highstand (TST and HST) system tracts and reflects syn-sedimentary tectonic activities, mostly resembled by Sinjar formation. It is divided into two fourth-order cycles each consisting of parasequence sets. The overlying Lutetian third-order sequence consists of carbonates deposited in a ramp setting. It is also divided into two fourth-order sequences that consist of highly permeable and porous carbonates. The red molasses of the Gercus Formation indicate a lowstand fan deposit and a probably fifth-order cycle. The youngest Eocene third-order
sequence is represented by the evaporites and carbonates of the Sagerma Formation, and probably reflects climatic changes. Remnants of the foreland basin, located in front of the Cretaceous accretionary complex, played an important role in the paleo-configuration of the Eocene ramp-rimmed shelf basin. This is reflected by a stratigraphic gap and unconformity (sequence boundary type 1) at the Paleocene/Eocene boundary. The Ypresian basin evolved from a shallow-marine ramp, to shoal and mixed carbonates–siliciclastics sequences. In contrast, the Lutetian basin started as a Nummulitic algal carbonates ramp that underwent a catch-up phase followed by a rapid give-up stage. The Nummulitic carbonates are very thick, and contain good hydrocarbon
reservoirs. The carbonate ramp is overlain by thin Gercus red clastics, whereas in the southern sector it is overlain by lagoonal carbonates and evaporites. This paleogeography may reflect the reactivation of a strikeslip fault that changed the ramp basin to rimmed shelf. Forming a very thick, permeable, Nummulitic reservoir, and reflecting the early phase of the continent-continent collision between the Arabian and Iranian plates during the Middle Eocene.
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Revised lithostratigraphy and biostratigraphy of the Tarbur type section, Kuh-e-Gadvan, northeast of Shiraz, Fars area, Iran
The type section of the Upper Cretaceous (Maastrichtian) Tarbur Formation (692 m thick) was defined by James and Wynd (1965, AAPG Bulletin, v., 49, p. 2218) in the paper: Stratigraphic nomenclature of Iranian oil consortium agreement area. We have revised the definition based on field observation and thin section studies. Above the Tarbur Formation, we did not recognize the previously defined Sachun Formation, consisting of red and green marls. Instead we found the upper boundary of the Tarbur Formation to be bounded by a fault, which renders it indistinguishable from the Sachun Formation. Accordingly we propose a new type section for the Tarbur Formation in Kuh-e-Chel Cheshmeh, Kherameh, southeast of Shiraz city. Our study also recognized that marls with pelagic facies that yielded abundant planktonic foraminifera (Gansserina gansseri- Contusotruncana contusa subzone) are Mid-Maastrichtian in age. These marls may occur as a tongue followed by alternating marls and limestones, and finally by a thick-to-massive rudist reefal limestone (34 m thick).
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Sachun type section lithostratigraphic and biostratigraphic reappraisal, Kuh-e Sachun, Fars province, Iran
More LessThe type section of the Paleocene-Early Eocene Sachun Formation (revised age and thickness 944 m, previously 1,444 m) was originally defined by James and Wynd (1965, AAPG Bulletin, v. 49, p. 2220-2221) in the paper: Stratigraphic nomenclature of Iranian oil consortium agreement area. The type section of the formation in Kuh-e-Sachun, south of Darab city, was reappraised using new field data and microscopic studies. New evidence showed that no evaporitic sediments occur in the lower third of the formation; instead this section consists of thick-bedded to massive rudistic reefal limestone with pelagic and coraliferous marls. The lower section resembles in lithology, facies and morphology the underlying Tarbur Formation. A palaeosol horizon was observed between the Tarbur and Sachun formations and it is correlated to the Cretaceous-Tertiary (KT) boundary. The new data, together with field data from the Tarbur Formation, required revising the definition of both formations. The boundary between them has been
repositioned between the Tarbur rudistic limestone and the first Sachun evaporites. These revisions, including the revised age and thickness, resolve the contradictions in the published definitions, and clarify the stratigraphy in boreholes and outcrops in the Fars Province.
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Correlation of upper-Khuff equivalent Palaeotethyan sediments of the Alborz Mountains, northern Iran
Late Permian upper-Khuff equivalent sediments (thickness up to 200 m) crop out over large parts of the Alborz Mountains, northern Iran, and are represented both by continental and marine facies. The continental facies is represented by the Gheshlagh Formation cropping out mostly to the south and east, consisting of fluvial quartzarenites and lateritic horizons with occasional dark shales (with plant fragments) inter-bedded. This unit inter-fingers with the marine Nesen Formation, which in places is very organic rich. In the Central Alborz, the Nesen Sequence thins out rapidly and in the south, it is usually less than 20 m thick. Preliminary analyses on the vitrinite reflectance of the Nesen Formation suggests that Ro falls in the lower part of the oil-window.The organic matter appears to be mostly of land plant origin. The Nesen Formation is rich in fossils including brachiopods (which form very diversified assemblages), palynomorphs, rugose corals, small foraminifers and fusulinids. Five brachiopod biozones have been erected allowing detailed correlation between five widely separated sections between Elikah (in the west), Dashnt-Nadir Bear, Mangol and Abrendan (in the east). The brachiopods suggest a Late Permian (Wuchiapingian-Changhsingian) age for the biozones. Independent evidence supports this assignment including the presence of the Wuchiapingian-Lower Changhsingian conodont Hindeodus julfensis and the Changhsingian palynomorph Triquitrites proratus. Trends in δ13C from carbonates indicate the presence of the Permian-Triassic boundary close the base of the overlying Elikah Formation and biotic trends, including proportional extinction rates, there can be related to mass extinction.
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Origin of H2S and hydrocarbons from the Permian-Triassic Khuff Formation using fluid inclusion technology
Authors Abdelghayoum S. Ahmed, Richard Worden and and Tom HarlandFluid-inclusion analysis was conducted from onshore and offshore fields in Saudi Arabia, supported by detailed petrography and integration with existing geochemistry, reservoir and sedimentological data. The objectives were to determine the temperature of thermochemical sulphate reduction (TSR) and H2S generation, petroleum phases and API, gas-to-oil ratio (GOR) of liquid petroleum in inclusions, as well as filling history. Results confirmed that H2S in the Khuff Formation is due to TSR. The absolute
quantity of produced H2S is reflected by the quantity of anhydrite that was converted to calcite, and was taken to suggest degree of TSR advancement. Petrographic and fluid-inclusion data suggested that TSR was controlled by temperatures, distribution of finely disseminated anhydrite and hydrocarbon liquid or gas phase in the Khuff reservoirs. Fluid-inclusion analysis revealed that the initial charge was oil, later displaced by condensate and dry gas. The analysis also showed that TSR occurred at temperature between 110° and 135° C. Oil found as inclusions is consistent with the emplacement of a maturity-controlled sequence beginning with 35° API oil through to a 55° API oil at temperatures of up to 140° C, with methane-dominant gas emplacement above 140° C
to approximately 155° C. The absence of oil inclusions in other wells could be due to: (1) oil never having resided in the Khuff Formation in these wells because they were too deep for a palaeo-oil floor, or the lack of source rock in local areas for the reservoir; (2) an insufficient number of samples were examined to find rare oil inclusions; (3) oil, initially trapped, leaked-out of inclusions into free pore space and was then diluted by gas; and/or (4) oil cracking to gas within fluid inclusions.
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Predicting the Mishrif Reservoir quality in the Mesopotamian Basin, southern Iraq
Authors Adnan A.M. Aqrawi and Andy D. HorburyThe middle Cretaceous Mishrif Formation contains a widespread carbonate succession of Cenomanian-Early Turonian age in the Mesopotamian Basin of southern Iraq. More than one third of the proven Iraqi reserves are found within the rudist-bearing carbonate reservoirs of the Mishrif Formation. Rudist facies coincide with the crestal areas of many fields in the region, particularly in those anticlines that show evidence of synsedimentary structural growth. However, other structures have also proven to be non-productive at this level because of the presence of tight or microporous offshore facies instead of rudist-bearing reservoir facies. Difficulty in predicting reservoir distribution is due to the complex palaeogeography. It would appear that following drowning of the uniform and extensive Albian carbonate platform, the Mishrif Formation was established along a NW-oriented zone that is largely bounded by the East Baghdad and Hamrin-Makhul structures and their continuation towards Iran (as the Bala Rud zone). To the southwest of
this zone, the intra-shelf basin carbonates of the Rumaila Formation were deposited. Whereas to the northeast, the sub-basinal carbonates of the Dokan Formation were deposited. Across the Mishrif Formation facies belt, sequences show stacked or sometimes shingled geometries. As a result, each field shows different combinations of pay zones, barriers and seal geometries. Detailed palaeogeographical reconstruction on a systems tract basis can be used to construct play fairway maps for exploring
this carbonate system, particularly with respect to finding stratigraphic traps. Many existing anticlines, tested by one or more wells that are thought to be ‘dry’, may turn out to have productive facies along strike, or down-dip on the flanks. In addition, pure stratigraphic traps may be found in relatively undeformed ‘synclinal’ areas between the major anticlines. However, exploring such trap types will require 3-D seismic to pin-point tune the positions of the external and internal shelf margins via the application of high-resolution sequence stratigraphy.
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Comparison of LP sparse spike, model-based and band-limited methods of seismic inversion: A case study
Authors Abdonabi Arianfar and Maziar HaghighiSeismic inversion involves converting a seismic section into an acoustic impedance section. In this presentation, three methods of seismic inversion techniques including LP sparse-spike, model-based and band-limited will be discussed to show the capability of each one in inverting 3-D seismic data for the reservoir under study. First, a zero phase wavelet was statistically extracted from the seismic data at the reservoir interval. Then, well logs to be used in the inversion process (sonic and density) were edited to eliminate spikes and noise bursts to avoid generation of spurious reflections. A synthetic seismogram was computed for each well using the well-driven reflection coefficients and the statistical zero phase wavelet. Good correlations were obtained between each synthetic seismogram and the seismic data at the well locations by squeezing-and-stretching the synthetic seismograms. Squeezing and stretching the synthetic seismogram in time domain is equal to phase rotation in frequency domain. It should also be noted that misunderstanding of the phase concept is the main cause of the error in seismic interpretation; hence the calibration process of the synthetic seismograms with the surface seismic should be carried out carefully. After the calibration stage, a nonzero
phase wavelet was extracted using the wells and seismic data and seismic data was inverted using this wavelet for all three methods. In comparison with other methods, the acoustic impedance resulted from the LP sparse-spike technique had the best correlation with the well-driven acoustic impedance. The total impedance correlation of this method was 0.846 over the whole field under study. The model-based method did not achieve good results, most likely because of the limited number of picked horizons in the reservoir interval. The results of the band-limited method were close to those of the LP method, as theoretically expected. Finally the LP sparsespike method was selected as the best one to invert the seismic cube.
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CO2 Injection in the nearly depleted K12-B North Sea gas field
Two different CO2 injection field tests were carried-out in the nearly depleted K12-B gasfield, offshore Netherlands, in different compartments. The CO2 originating from the produced gas (the methane contains a fraction of 13% CO2), is separated on the production platform and reinjected into the reservoir. The first test, completed in 2004, consisted of CO2 injection through a single well in a depleted reservoir compartment to test the injectivity. The second test is ongoing in a nearly depleted reservoir
compartment comprising two gas production wells and one CO2 injection well. This presentation describes the simulation results based on a detailed geological model and history match to the production data until December 2005. A highly accurate match has been obtained. In March 2005, two tracers have been added to the injected CO2 such that injected CO2 could be discriminated from resident CO2. Breakthrough of the tracers has been observed for both producing wells after 130 days (in 2005) and 463 days (in 2006). For the first well the simulation results for CO2 breakthrough have been compared to the tracer time. Results were accurate within a few days. For the second well the comparison has not yet been made since injection and production data were not available at the time of writing this abstract. This work is in progress.
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Platform cover and sedimentary basins of Yemen: Lithological characterization and hydrocarbon prospectivity
More LessBased on lithostratigaphic and geological studies, and structural patterns of the platform cover of the southern Arabian Peninsula, three types of depositional sedimentary basins were recognized. (1) Paleozoic Basins: (a) the southern flank of the Rub’ Al-Khali Basin contains Paleozoic and Mesozoic sedimentary successions and is bounded by the Hadramawt Arch (oriented approximately E-W). (b) The San’a Basin, in which deposition started in the Paleozoic and continued up to the Late Jurassic times. (c) The southern Permian-Triassic Socotra Basin is probably linked with the Karoo Rift. (2). Mesozoic sedimentary rift basins initiated along the ancient Najd Fault System (NW-trending) in the Late Jurassic. Subsidence continued up to the Early Cretaceous in the
west and in Late Cretaceous/Paleogene? in the east. These basins evolved as sub-parallel features, and their axes rotated from NW in the west, to WNW in the centre and to W-E directions in the east. Five sedimentary rift basins are developed from west to east; Siham-Ad-Dali’, Sab’atayn, Balhaf, Say’un-Masilah and Jiza’-Qamar. (3). Cenozoic sedimentary rift basins developed and formed along major ENE-oriented transform faults, mostly in the offshore area along the northern side of the Gulf of Aden (Aden-Abyan in the west, Hawrah in the centre and the Mukalla-Sayhut in the east) and along a NNWtrending fault system parallel to the main Red Sea trend (Tihamah basin). The rift basins along the Gulf of Aden propagated from east to west in the late Early Oligocene and continued up to the Pleistocene. The Tihamah Basin developed on- and offshore during the Late Oligocene and continued up to the Pleistocene as a result of Red Sea rifting. This study will discuss the hydrocarbon system of all the sedimentary basins in detail. It will review the proven and potential source rocks, reservoirs (and their quality), seals and traps styles.
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Evaluation of cementation factor in Iranian carbonate reservoirs
More LessThe cementation factor is one of the most important parameters in the equation to calculate water saturation. A lack of data on the cementation factor, due to limited core samples, introduces great uncertainty in estimating water saturation and consequently original-oil-in-place. For zones without any core analysis the cementation factor can be estimated by correlations based on laboratory measurements and log analysis data. This method results in a continuous estimate of the cementation factor. This presentation will describe a case study for a carbonate reservoir in the Sarvak Formation, the second-most oil-productive formation in Iran. Most petrophysical parameters in Iran’s reservoirs usually do not clearly correlate with one another, thus causing great uncertainty in reservoir evaluations. Initially, we investigated all those parameters that may affect the cementation factor. The most important ones were identified and correlated to the factor based on laboratory data from two oil fields. Log interpretation results were also used to confirm the laboratory data. The results were compared to previous correlations and constants that are commonly used in oil companies to predict water saturation. All the cementation-factor correlations have the same values for high-porosity reservoirs. For low-porosity reservoirs the correlation trends were completely different. Thus, using an improper correlation causes significant errors for water-saturation determination. In this study, it has been shown that the Shell formula, which is usually used for estimation of the cementation factor in Iranian oil reservoirs, may not be an appropriate choice for the Sarvak Formation.
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Data in harmony: Use of discovery metadata, taxonomy and thesaurus in Saudi Aramco Exploration
Authors Peter Attewell and John Griffiths and Abdulaziz Al-MoqbelWe describe the method used in Saudi Aramco Exploration to build and implement our standard set of generic discovery metadata elements, taxonomy and thesaurus. The goal of this work is to implement consistent metadata and to reduce exploration cycle time by enabling end-users to quickly find and retrieve data even when distributed across several databases and repositories. The data management group first developed a discovery metadata standard – the correct minimum set of attributes necessary to retrieve exploration data, which include well logs, seismic data, core samples, as well as geospatial data. We developed a thesaurus based on industry standards and modified to our requirements; this was used to generate a unique taxonomy for Saudi Aramco exploration. The taxonomy helped unstructured data content to be categorized and added further richness to metadata. The resulting data harmonization enabled geoscientists to share a common vocabulary at appropriate business levels, independent
of organization and geographical location. Information on data access, versioning and content ownership were essential for inclusion to ensure proper protection and maintenance. The use of a standard discovery metadata enabled a centralized metadata catalogue for all exploration data types to be designed. Practical implementation involved continual user consultation and cooperative liaison with software developers and end-users. We will show examples of the significant value gained by sharing common metadata across a decentralized working environment, and implementing a thesaurus to enable rich metadata extraction capabilities.
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Early development of a compartmentalized, naturally fractured formation with compositional fluid behavior
This presentation describes a systematic approach to simultaneously appraise and develop a string of discoveries in naturally fractured reservoirs while mitigating geological risk. The key to success in economic optimization was in full alignment of diverse and specialized skills of technical professionals, integrated data management and technology implementation. The consultant/client team provided the needed analyses. At decision time, 12 wells over 5 structures and two formations in a 1,100 square km area had produced rich gas and volatile oil during short-term tests in several wells. In the naturally fractured formations, reservoir extent and continuity is a major risk that needs to be mitigated. Multiple fluid properties added another dimension to the reservoir complexity. The traditional approach before making major capital investment in wells and facilities under high uncertainty, was to collect additional data by drilling appraisal, delineation wells and test their performance. This approach would have deferred strategic
development of the much needed gas and lowered the net present value (NPV) of the successful case. The reservoir-centric view provided an alternative. A multi-disciplinary knowledge of analogous formations, rock and fluid properties and fracture geometry was incorporated in a dynamic model calibrated with limited test data. The model allowed the team to run multiple characterization scenarios to calculate production forecasts. Economic modeling provided NPV values that pointed towards a staged approach in facilities construction with mitigated risk. An early production facility was planned to obtain long-term test data from a few key wells. Staged development will provide early cash flow while maintaining flexibility in plant capacity, design and location throughout
the development cycle. Aggressive drilling activities are being implemented in order to meet the strategic production targets.
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