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GEO 2008
- Conference date: 03 Mar 2008 - 05 Mar 2008
- Location: Manama, Bahrain
- Published: 03 January 2008
81 - 100 of 385 results
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Geothermal gradient study of Asmari Formation in Dezful Embayment, Zagros, Iran
More LessThis study was focused on determining the geothermal gradient of the Oligocene-Miocene Asmari Reservoir in the Dezful Embayment, Iran. It involved preparing an isothemal map of the reservoir, recognition of a temperature anomaly zone and the study of related parameters, such as Ro and TTI. The geothermal gradient of the Asmari Reservoir and mean geothermal gradient (average slope between the temperature at the surface and the top of Pabdeh Formation) were determined in 180 wells from different oil fields. The results were checked by geochemical analysis (Tmax) and oil-generation modeling. The study showed that the geothermal gradient in the Agha Jari, Haft Kel, Masjid-e-Suleyman and Naft- Safid fields is greater than in other fields. The results
suggested considerable differences in the geothermal gradient between wells in the same field; for example in Marun, Pazanan and the above-noted fields. Variations in the geothermal gradient between wells, implies that their source rocks should show different maturations. For example geochemical studies of Marun and Pazanan fields suggested that the source rock is more mature in wells MN-123 than MN-222 and PZ-23 than PZ-117. Moreover the Oleanane biomarker was found in the oils from these fields. Studies also detected a relationship between an anomalous temperature zone (high gradient) and a paleohigh in the Zagros Basin. Based on a structural study, the boundaries of the paleohigh are correlated to basement lineaments. Investigations further confirm that faults are one of the important factors that produce greater geothermal gradients. Thus by integrating the results of the geochemical and structural studies we found that: (1) the geothermal gradient can vary in oil fields or in wells in the same field. (2) These variations are strongly controlled by basement lineaments, which increase the geothermal gradient. In turn the greater gradient leads to higher maturation (oil generation) of the Pabdeh Formation as confirmed by the Oleanane biomarker. (3) In the high-gradient zone, the oil-production rate is higher than in other zones.
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Uncertainty assessment and risk analysis for a future field development phase in a carbonate reservoir, onshore Abu Dhabi, United Arab Emirates
Quantifying, ranking and weighting of reservoir uncertainties based on several variables can be a real challenge for volumetric estimation. This is because the variables are related to many parameters such as tool measurements, seismic processing, velocity modeling, petrophysical evaluation, geological interpretation, modeling parameters, saturation functions among others. The oil field potential assessment in the current study was based on the first phase of a development drilling campaign and recent appraisal drilling over a less controlled area in shallow waters. A stochastic uncertainty analysis, using the JACTA (GocadTM plug-ins) software, allowed a decision on the location of the latest appraisal well and an inference on the further development phase scheme
for the field. The study included vertical, deviated and horizontal wells within Phase I and new development phase areas. A large number of simulations revealed a statistical distribution of the reservoir volumes and its connectivity. In general, the major uncertainties are from three main categories: structural, petrophysical and fluid parameters. The inter-dependence among parameters was properly captured during the uncertainty workflow. The different realizations from the static model (P90, P50 and P10) were upscaled to fit the dynamic model grid-size limitations. The upscaled models along with the other dynamic data from the fluid properties (pressure, volume and temperature data), special core analysis, well completion and production/injection data were used to build the dynamic simulation models. The P50 model was then initially tested and history-matched before using it to forecast the different development scenarios to select the most viable option against the P90 and P10 models.
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Depositional setting of Cretaceous Reservoirs, southern Yemen and northern Somalia
Authors Osman Salad Hersi and Dale LeckieThe Say’un-Al Masila Basin of southern Yemen and the Al Mado Basin of northern Somalia are Mesozoic sedimentary basins developed during the disintegration of Gondwana. The two basins formed one single rift (Say’un-Al Mado Graben) with intermittent tectonic disturbances, which affected the carbonate-clastic basinfill architecture. The Cretaceous Say’un-Al Mado graben had a funnel shape in plan view, tapering northwestward (in Yemen) and open southeastward (through northern Somalia) to the Tethys Ocean. The Cretaceous fill of the Say’un–Al Mado rift consists of siliciclastic sequences predominant in the western flanks of the basin (Tawila Group in Yemen and Yesomma Formation in northern Somalia), and carbonate sequences predominant in the
southeastern areas (Mahra Group and Tisje Formation, respectively). The sandstones of the Tawila Group (Qishn and Harshiyat formations) and the Yesomma Formation were deposited in a complex system of braided to low sinuosity meandering rivers, tidal-dominated estuarine and deltaic environments. The terrigenous influx decreased southeastward where carbonate sedimentation flourished in a shallow-marine environment (Mahra Group in Yemen and Tisje Formation in northern Somalia). Carbonate sand shoals, lagoonal wackestones, mudstones and rudistic buildups are the main lithofacies of the carbonate strata. The Qishn Formation is highly porous (18 to 23%) and permeable (up to ten darcies) and contains estimated reserves of over one billion barrels of
recoverable oil. Unlike the relatively strong hydrocarbon exploration activity in Yemen, Somalia’s hydrocarbon resources are under-explored. However, the little geological knowledge from the Yesomma and Tisje formations implies they contain good reservoir intervals (up to 300 m thick and 14% porosity) with interbeds of source shales. Many of the drilled wells contain oil stains and gas shows. Maturity of these hydrocarbons ranges from immature to post-mature with good intervals within the oil window.
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Paleomagnetic study of Upper Cretaceous-Lower Tertiary rocks in northeastern Iraq
Authors Basim R.A. Hijab and Ezadin Baban and Emad H. Al KharssanThe following rock units in northeastern Iraq were sampled for a paleomagnetic study: (1) Paleocene-Lower Eocene Naoprdan Limestone Formation at Chwarta and Zainal, (2) Maastrichtian Aqra Limestone Formation at Maukaba and Zardabe, (3) Valanginian-Turonian Balambo Limestone Formation at Azmar locality and igneous gabbros intrusions at Kanaroe and Waraz. Twelve hand samples and 200 oriented drilled cores were collected from these localities. The remnant magnetization (NRM) was measured using a spinner magnetometer (Baghdad University) and the cryogenic magnetometer (Oklahoma University, USA). The remnant magnetization in the Aqra Formation is of a depositional origin and carried by a detrital magnetite grains. In other localities (Chwarta, Zainal, Azmar, Kanaroe and Waraz), secondary haematite or maghemite is dominant. The rocks of the Chwarta, Zainal, Azmar, Kanaroe and Waraz localities are not good indicators for the paleomagnetic direction. Results from Maukaba and Zardabe rocks (Aqra Limestone) provided reliable paleomagnetic results. These rocks showed reverse paleomagnetic directions. All computed virtual geomagnetic poles (VGP) correspond to a reverse polarity, and the overall mean VGPs position of the Maukaba locality is paleo-latitude (Plat) of 44.4° S and paleo-longitude (Plong) of 279°, and for Zardabe locality (Plat = 57.1° S, Plong = 235°) with co-latitude (-14°) and (-13.9°). Accordingly, the paleo-latitude of the Maastrichtian Aqra Limestone basin was between 13.9° and 14° N. This suggests that the Neo-Tethys Ocean was located to the north and northeast of northeastern Iraq during the Maastrichtian time. The closure of this ocean occurred between the Maastrichtian and Early Tertiary. The paleo-position of the Aqra Limestone basin clearly suggests that the northern part of Iraq was still in warm environmental conditions during Maastrichtian times. This means that the oil accumulation can be found in rocks of ages for Maastrichtian and older than Maastrichtian.
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Mesozoic to Recent structural evolution of the eastern Rub’ Al-Khali, Saudi Arabia
Two main structural trends are evident in the eastern Rub’ Al-Khali Basin: a NNE trend, similar to the dominant structural trend in the United Arab Emirates; and a NS trend, similar to the one observed in the major oil fields of Saudi Arabia. Understanding the interplay between these two trends and their relationship to deep-seated older basement structural components, as well as their Phanerozoic reactivation history, is critical to obtaining a robust exploration risk assessment for these structures in this area. Data used to underpin the structural analysis are regional analogue structural data, 2-D seismic data from eastern Saudi Arabia, and structural observations from core and dip-meter logs. Together with geochemical and stratigraphic analyses this has resulted in a robust kinematic model for the structural evolution of the NS-trending structures. Several phases of structural development have resulted in the present-day composite NS-trending arch-like configurations. The main phase of growth occurred during the Late Cretaceous as a result of NW-SE compression, further phases of growth were recognized during the Late Cretaceous Maastrichtian, Paleocene to Early Eocene, Mid- to Late Miocene and Pliocene times. The rotation of the stress field to a present-day ENE-WSW position for the maximum horizontal stress was recognized through observations from core and seismic data and has resulted in several phases of fracturing, including the reactivation of older fracture systems.
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Clay mineralogy of Gurpi Formation at its type section and Ziloee oil field, Dezfool Embayment, Zagros Mountains, Iran
More LessStudying the Tu/K ratio on NGS logs of the Gurpi Formation in well No. 8 of the Ziloee oil field, Izea zone of Zagros Province, indicated the occurrence of smectite and illite. Moreover, field studies and calcimetric analysis were conducted on samples collected from the type section of the Gurpi Formation (Dezfool Embayment of the Zagros Mountains). The samples consist of limestone, marl and shaley marl. However, X-ray diffraction (XRD) analysis of selected samples with lesser amounts of CaCO3 indicated the existence of smectite, illite and chlorite. The coexistence of smectite and illite, and absence of kaolinite, in these deposits indicates temperate climatic conditions prevailed during the latest Cretaceous and Early Paleocene in the Zagros region. Moreover, semiquantitative analysis of the XRD data identified an upward increasing trend of smectite and decreasing trend of illite and chlorite in the sedimentary column. These trends suggest a deepening upward trend in the basin as consistent with global sea-level curves. Based on the covariance trend of illite and chlorite and scanning electron microscope (SEM) images, we suggest a diagenetic transformation of illite to chlorite in these samples. Also the SEM images indicated a diagenetic origin for smectite, which can form during fluid exchange with maphic and detrial clay minerals (e.g. detrial smectite, illite).
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Sedimentation and high-resolution sequence stratigraphy of the Upper Cretaceous Simsima Formation, onshore Abu Dhabi oil field, United Arab Emirates
More LessAn important carbonate oil field, located onshore Abu Dhabi, has been producing from the Upper Cretaceous (Maastrichtian) Simsima Formation since 1983. A detailed sedimentological and high-resolution sequence stratigraphic study has been carried out, integrating approximately 7,000 ft of core material, approximately 3,500 thin sections, and all available well-log data from 46 wells. Core description, together with semi-quantitative petrographic examination of thin sections, established a new depositional model for the Simsima Formation. Sixteen lithofacies types (LF1 to LF16) representing a wide variety of depositional environments, ranging from upper ramp, rudist-bioclastic shoals to open marine mid to outer ramp mud-dominated settings. The newly developed, high-resolution sequence stratigraphic framework suggested that the Simsima Formation comprises one complete third-order composite sequence and the transgressive systems tract of an overlying second third-order composite sequence. These third-order
composite sequences include seventeen high-frequency, fourth-order sequences (HFS). HFS 1 to HFS 12 build the older, third-order composite sequence, HFS 13 to HFS 17 form the transgressive system tract of the overlying, younger third-order composite sequence. The fourthorder, high-frequency sequences were tied to re-processed and re-interpreted 3-D seismic data. Fourth-order sequences 1 to 6 clearly show onlap on a pre-existing high (pre-Simsima unconformity surface) whereas the top part of the Simsima Formation (sequences 13 to 17) show erosion on seismic cross-sections. The established high-resolution sequence stratigraphic framework will provide the layering scheme for the new Simsima 3-D static model, which will be used as input for reservoir flow modeling.
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Geophysical pressure prediction for ultra-deep wells: When the reservoir becomes the enemy
More LessIn recent years, drilling requirements have become more challenging as ultra-deep wells have demonstrated that basic undercompaction models are inadequate to predict pressures in high-pressure/high-temperature (HP-HT) environments. The requirements of these wells have forced pressure prediction to adapt to environments where diagenetic processes and hydrocarbon maturation are dominant (unloaded environments), and where chemical compaction takes over from undercompaction as the dominant factor in determining rock property changes (secondary compaction environments). Adding to the complexity of the pressure prediction process is the interplay between shales and reservoir rocks. As pressure increases, the window between the formation pore pressure and fracture pressure narrows. In HP-HT environments, the lateral extent, structural position, and architecture of the reservoirs become much more critical to the viability of a prospect. They also determine the range of safe depths where a specific reservoir can be penetrated without the risk of a pressure influx that could jeopardize the drilling operation. In this setting, geopressure prediction and reservoir pressure modeling become an essential component of prospect risking. While explorationists desire large reservoir bodies in deep prospects to allow sufficient reserves to justify the high cost of an ultra-deep well, they must also recognize that large reservoir extents can also threaten the viability of the prospect. To mitigate this risk, the exploration team must use all the available information to determine the extent of the reservoir, its structural position, and its interaction with faults and other potential flow conduits. This information can then be integrated with 3-D pressure volumes to predict column heights for specific fluids
and the reservoir pressures at any specific penetration point in the subsurface. The accurate prediction of the reservoir pressures at a specific penetration point can be the difference between an efficiently managed drilling operation and a potentially catastrophic pressure influx event.
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Using biofacies and lithofacies to determine palaeoenvironments and depositional cyclicity of the Sulaiy and Yamama formations of subsurface Saudi Arabia
Authors Geraint W. Hughes and Nassir Naji and Osman VarolThe Sulaiy and Yamama formations of Saudi Arabia consist of Late Jurassic (Tithonian) to Early Cretaceous (Berriasian) carbonates. Although exposed in Saudi Arabia, the Sulaiy is difficult to access and the Yamama is very poorly exposed. The Sulaiy Formation lies unconformably on evaporites of the Hith Formation at outcrop, but overlies carbonates of the Manifa Member of the Hith Formation in the subsurface. The Manifa is currently being evaluated as being genetically linked with the Sulaiy rather than its traditionally assigned Hith Formation. Micropalaeontology and sedimentology of the Sulaiy and Yamama formations in subsurface have revealed a succession of clearly defined shallowing upwards depositional cycles, of 50 ft average thickness. These typically commence with a deep-marine biofacies within wackestones and packstones, capped with a mudstone-wackestone maximum flooding interval and an upper unit of packstone to grainstones containing shallow-marine biofacies. The upper part of the Sulaiy Formation is highstand-dominated with common grainstones that host the Lower Ratawi reservoir and is capped by karst that defines the sequence boundary. The Yamama Formation, in contrast, contains fewer grainstones, and is predominantly transgressive. Although smaller grainstone units host the Upper Ratawi reservoir, it is considered that the highstand-associated, main reservoir facies equivalent to the Lower Ratawi reservoir must have been deposited but was removed by the very extensive episode of erosion that accompanied the major sea-level fall during the Valanginian. It is tantalising to contemplate the destination of the transported highstand grainstones as they would provide excellent stratigraphically trapped pre-Buwaib reservoirs elsewhere within the basin.
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Straight-ray datuming in 3-D media: Fast and flexible
Authors Tariq Alkhalifa, Henk Innemee and and Chris BensonCommon datuming approaches, like the Kirchhoff or finite-difference methods, require reasonable sampling of the sources and receivers. This becomes a serious limitation for datuming data acquired using 3-D conventional land-acquisition layouts, because of the typical sparse spacing of either the sources or receivers. To combat this, we extend Alkhalifah and Bagiani’s (2006) straight-ray datuming (SRD) to handle 3-D acquisition geometries. As in the 2-D case, 3-D SRD is based on the straight-ray assumption
above-and-below the datum with Snell’s Law honored in between. This allows for the application of SRD to common-shot gathers in one operation (no need to sort the data to common receivers). Similarly, it can be applied to common-receiver gathers without the need to sort the data back to common-shot gathers. This feature allows for more flexibility in acquisition as it requires, unlike in the conventional case, either the sources or receivers to have a complete fine coverage of the area. In addition, SRD does not require a detailed description of the near-surface velocity model; information from refraction static or any other commonly used method to obtain near-surface time shift suffice. SRD, in addition to carrying out redatuming, can be used to map irregularly
sampled spatial data at the acquisition surface into regularly sampled data at the datum. In fact, since the operation is a partial migration, it suppresses diffractions generated from inhomogeneities above the datum. The computational cost of applying 3-D SRD is larger than static corrections, but because of the limited spatial extension and analytical formulation, it is far less than Kirchhoff re-datuming.
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New aspects of Saudi Arabian Jurassic biostratigraphy
Authors Geraint W. Hughes, Osman Varol and Nigel P. Hooker and Raymond EnayAge determination of the Saudi Arabian Jurassic carbonate succession was originally based on outcrop macropalaeontology and micropalaeontology, and the essential chronostratigraphy of the formations and members was completed by 1968. It is to the credit of the earlier workers that their age assignments have been largely retained to the present-day. Subsequent biostratigraphic investigations of outcrop samples using ammonite, nautiloid, brachiopod and echinoid macrofossils refined these earlier age determinations. New ammonite and nautiloid determinations have further added to this refinement. In the subsurface, where macrofossils are rarely encountered or preserved within exploratory well samples, lithostratigraphic assignment relies heavily on
lithofacies characteristics. Such methodology becomes difficult within intra-shelf basin areas where the defining shallower lithofacies are either poorly developed or absent. In such circumstances, micropalaeontological evidence is essential, with support from nannofossil and palynology. Current research is being focused on the micropalaeontological, nannofossil and palynological calibration between the exposed, macropalaeontologically dated, type or reference sections and subsurface core and cuttings samples. Of these, palynology is beginning to provide new stratigraphically useful data, including outcrop samples, where palynomorph recovery has previously been assumed to be poor and of limited value. Such an approach, using their biostratigraphic fingerprint, is proving successful to assist exploration activities by identifying formations in historical wells where lithostratigraphic units had been miss-assigned resulting in mis-correlations.
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Micropalaeontology and palaeoenvironments of the Wadi Waqb Member, Jabal Kibrit Formation, and its reservoir equivalent, Saudi Arabian Red Sea
More LessThe Saudi Arabian Red Sea stratigraphy consists of a variety of lithologies that range from evaporites, deep- and shallow-marine siliciclastics and carbonates, biostratigraphically constrained to range from the Late Cretaceous (Campanian) to Late Pliocene. The Midyan area of the northern Red Sea offers a unique window into the Cretaceous and Miocene succession that is otherwise only present in the deep subsurface. The sediments are of hydrocarbon interest because of the presence of source rocks, siliciclastic and carbonate reservoirs. The Wadi Waqb reservoir is hosted within the Wadi Waqb Member of the Jabal Kibrit Formation, and is of Early Miocene age. This member is exposed on the east flanks of the Ifal Plain, where it is represented by a discontinuous
fringing rhodolith and coral reef complex that is welded to steep cliffs of granitic basement. Exposures of the member in Wadi Waqb, located in the middle part of the Midyan region, consist of pelagic, planktonic foraminiferal dominated packstones that contain abundant shallow marine allochthonous bioclasts. These shallowmarine bioclasts are considered to have been derived from the rhodolith-coral reefs exposed to the east. The Wadi Waqb reservoir is located in the central part of the Ifal Plain, approximately midway between the in-situ rhodolith-coral reefs and the mixed allochthonous and authochthonous facies in Wadi Waqb. The reservoir consists of biofacies that compare well with those exposed in Wadi Waqb, and therefore testify to the presence of a deep-marine environment, in excess of 50–75 m water depth, located less than 25 km to the west of the fringing reef source of the shallow bioclasts.
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Micropalaeontology of the Saudi Arabian Rus, Dammam and Dam Formations exposed at the Dammam Dome
Authors Geraint W. Hughes and Saleh EnaizyThe Dammam Dome represents a unique feature in Saudi Arabia as it forms a local topographic high along the otherwise flat extent of the eastern flank of the Kingdom. Its origin is attributed to episodic upwards movement of a deep-seated infra-Cambrian evaporite plug. The Rus, Dammam and Dam formations are exposed, of which their diminished thickness, relative to the adjacent subsurface, testifies to the region being regionally positive during the Tertiary. Micropalaeontological analysis with revised taxonomy of old and new exposures has improved palaeoenvironmental interpretation. The Paleocene to Early Eocene Umm er Radhuma is the lowermost Tertiary formation, but is not exposed in any accessible locations and will not be considered here. The Rus Formation was defined on the Dammam Dome, and includes lower carbonate and upper carbonate-evaporite unit. A new exposure on the Dammam Dome provides evidence for a lowermost Rus unit consisting of interbedded transgressive marls and clean highstand carbonates. An Early Eocene age is assigned on stratigraphic position as microfossils are rare owing to predominantly shallow-marine, periodically hypersaline conditions. The Dammam Formation includes the Midra, Saila, Alveolina and Khobar members. The Alveolina and Khobar members contain rich and diverse benthonic foraminiferal biofacies, including Middle Eocene Alveolina, Nummulites and Discocyclina species. A new Dhahran Member is proposed for the transgressive marls between
the Alveolina and Khobar highstand carbonates. The pre-Neogene angular unconformity underlies the Middle Miocene Dam Formation. The Dam Formation includes a basal stromatolite unit that is overlain by a coral and rich benthonic foraminiferal succession that contains Borelis melo.
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Tectonic controls on Triassic stratigraphy and hydrocarbon prospectivity in Kuwait
The Triassic System in Kuwait comprises ramp carbonates, anhydrites and clastics deposited in supra-tidal to inter-tidal settings. The N-S trending Kuwait Arch with flanking basins (offshore Kuwait in the east and Dibdibba Trough in the west) exercised control on deposition and preservation of Triassic strata and prospectivity. The Triassic encompasses the Upper Khuff, Sudair, Jilh and Minjur formations. The Upper Khuff consists of carbonates, which grade into argillaceous dolomites in the Sudair Formation. An additional dolomudstone-prone unit, provisionally named as Kra Al Maru Formation, is preserved locally between the Sudair and Jilh formations in the Dibdibba Trough. The Jilh Formation is evaporitic, divided by intra-formational salt. The thickness of the Lower Jilh decreases over the Kuwait Arch, whereas the Upper Jilh and Minjur formations thicken to the southeast with increased clastic influx. The tectono-stratigraphic imprint represents re-activation of structural grain inherited from Hercynian and older tectonism. Upper Khuff, Sudair, Kra Al Maru and Lower Jilh are influenced by uplift of the Kuwait Arch. Jilh Salt represents a major interface at the onset of tectonic inversion. The Upper Jilh and Minjur formations are influenced by southeasterly slope and clastic influx
from the south. The Triassic sediments over the Kuwait Arch have diagenetically degraded reservoir properties. Evaporites and dolomudstones with fracture-related reservoir development in western Kuwait and shallowto open-marine carbonates with conventional reservoirs east of the arch are prospective. Recent exploration wells have established flow to surface of sweet gas and gas condensate from Kra Al Maru. The Minjur Formation is prospective in the south where sandstone inter-beds have improved reservoir characteristics.
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Oil below oil-water contacts: Implications on the structural evolution of Minagish Oolite Reservoir, Minagish oil field, Kuwait
Authors Muhammad W. Ibrahim and Tahir El GezeeryA study of the structural evolution of the Minagish oil field revealed that the trapping structure began in Early Cretaceous time as a minor dome at the SSE flank of a NW-trending Jurassic anticline. The Minagish anticline assumed the present-day motif by Maastrichtian time, gently tilted towards the NNE and was dissected by an E-W fault during Tertiary times. The fault separated two main compartments of the Minagish Oolite reservoir: an up-thrown symmetrical northern sector, and a wrenched and down-thrown asymmetrical southern sector. The incipient Minagish structure affected the thickness and deposition of the oolitic facies of the Minagish Oolite. Subsequent regional NNE tilts had a minor effect on shifting the position of superior oolitic facies in relation
to present-day structural peaks of the Minagish Oolite reservoir. However, Tertiary differential displacement of the two main compartments influenced the thickness and position of the occluded tarmat layers, and preserved a record of Tertiary oil/water contacts. The structural evolution of the Minagish Oolite explains the preservation of sealing tarmats within superior oil-bearing reservoir facies above and below the present-day oil/water contact in the northern sector, and the preservation of tarmats within the relatively inferior and water-bearing facies below present-day oil/water contact in the southern sector of the Minagish Oolite reservoir. Hence, technically there appears to be producible oil sealed by tarmats below the present-day oil/water contact in the northern sector of the Minagish Oolite reservoir of Minagish oil field.
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Fault development and hydrocarbon entrapment in the Mutriba area, western Kuwait
Mutriba is a prominent NNW-SSE trending anticline in western Kuwait with confirmed hydrocarbons at the Triassic, Jurassic and Cretaceous levels. A study was conducted to enhance fault imaging and to improve the understanding of structural architecture of this faulted anticline. The seismic data in the Mutriba area is contaminated by multiples and has poor quality and resolution. Nevertheless the application of attribute and image enhancement algorithms on 3-D seismic data successfully mapped the faults. Additionally analytical techniques were applied to investigate the structural evolution through sequential reconstruction. Fault dislocation and formation fracture density were estimated using seismic data and geomechanical models. The Mutriba structure
at pre-Cretaceous levels is dissected by two prominent fault sets trending NNW and EW. The NNW trend is older and is probably related to structural development during Paleozoic time. The younger EW trend offsets the original structural geometry so that the northern segment trends NNW and the southern trend approaches NS. The latter faults appear to have developed during the Late Jurassic and to have been re-activated during Cretaceous and Tertiary times with major uplift. These strike-slip faults cut across the older trend and have segmented the structure into a number of discrete fault blocks. The fault compartmentalization has been studied with regard to hydrocarbon entrapment. Core studies and fracture modeling suggested that the fracture network developed by these fault systems have contributed to improved migration to and within Triassic and Jurassic reservoirs. Fault compartmentalization has controlled Jurassic hydrocarbon occurrences among fault blocks. Integration of regional geological understanding, seismic
and geochemical studies and geomechanical modeling has indicated areas for further exploration.
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Source rock formation and characteristics of Shiranish Formation, Euphrates Graben, Syria
The Euphrates Graben is one of the most important petroliferous basins in Syria. One known source rock is the marine Upper Cretaceous Shiranish Formation, but no detailed information exists about its source rock potential. The aim of the investigation is to: (1) identify the variations in source rock characteristics due to changes in paleoceanography, and (2) to correlate these variations with their effect on the timing of petroleum generation. Two organic facies with different characteristics of petroleum generation were identified: Type II facies with hydrogen index (HI) values of > 350 mg HC/g TOC, and a Type II/III facies with HI values of < 350 mg HC/g TOC. Both organic facies are considered likely sources of paraffinic-naphthenic-aromatic petroleum with variable
amounts of gas based on the pyrolysis gas chromatography scheme of Horsfield (1989). Bulk kinetic experiments have shown that predicted petroleum formation temperatures are closely similar within each of the facies, but different between the facies, with onset (TR 10%) temperatures of 136°C for the Type II facies and 144°C for the Type II/III facies. This corresponds to approximately 600 m difference in burial depth or delayed onset of petroleum generation by 5.75 million years for a 3.3 K/my heating rate. Facies analysis of well logs indicated that Type II/III facies of the lower Shiranish Fm. was influenced by terrestrial input of different intensity. During the Upper Shiranish Formation. a progressive deepening of the depositional environment was probably coupled to an enhanced marine paleoproductivity leading to Type II facies.
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Role of regional structural elements in the hydrocarbon prospectivity of Bahrain offshore blocks
More LessBahrain Island and its offshore exploration blocks are located in the northern Gulf infra-Cambrian Hormuz Salt Basin, a prolific petroleum habitat hosting the major oil fields of the Arabian Plate. The fields are located on the rising flanks of the Qatar Arch to the east and En Nala Anticline (Ghawar-Berri high) to the west, separated by a syncline from which the hydrocarbons were sourced. Exploratory efforts in Bahrain offshore acreages were concentrated on drilling low-relief structural prospects, which gave hydrocarbon indications. Regional lineaments play a dominant role in the generation-migration-entrapment cycle. This presentation will show a conceptual regional structural elements model that integrates all the available data. The objective was to focus
exploratory efforts on identifying fault-bounded traps as the dominant structural play in the offshore area. An integrated review of regional geology, seismic, gravity and satellite image data has brought out three dominant regional lineament trends corresponding to the NW-trending Najd strike-slip system, NE-SW Wadi Al Batin-Dibba trend and NS/NNW basement trend. These trends were reactivated during various phases in the tectonic evolution of the basin. The NE trend was active during Jurassic and the NW trend was dominant during Cretaceous. The oldest, NS-NNW basement trend was reactivated during the Late Cretaceous to Early Tertiary compressional phase resulting in the present-day structures. The predominant structural grain in the area is NS and associated with wrench tectonics analogous to the Abu Dhabi model (Marzouk an Abd El Sattar, 1995). A review of prospectivity of the offshore blocks, based on the present structural model, has brought-out many potential fault-closure traps. Finer scale mapping and
fault-seal analysis are vital to establish trap integrity. The role of these trends in determining preferred flow directions in the reservoirs of the Awali field in Bahrain requires further investigation.
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Salt diapirism in the fold-thrust belt and foreland basin in the eastern Fars Province, Iran
The Hormuz Series crop out as salt plugs in the Zagros Fold-Thrust Belt or as islands forming circular domeshaped structures in the Persian Gulf. The 7 to 12–kmthick sedimentary cover is decoupled from its basement by the Hormuz Salt layer and deformed by large-scale folding and thrusting that started in the Miocene Epoch. Recent emergent diapirs occur above the crests of preexisting domes, at the crest, nose or plunging axes of the folds. We also observed Hormuz residual along some thrust or wrench faults in the inner part of the fold-belt. A study of salt diapirs in the fold-thrust belt and foreland basin of eastern Zagros was based on seismic and well data analysis, field observations and analogue modeling. Several regional cross-sections were constructed from the Persian Gulf to the Zagros Suture Zone. They allowed us to investigate: (1) the kinematic scenarios for the main structural elements; (2) the role of deep-seated fault on deformation; (3) the role of pre-existing dome and salt intrusions during folding; and (4) evaluate the thickness of the Palaeozoic sedimentary pile. Finally, they present a reference for the pre-folding attitude and activity of salt domes in the foreland basin compared with the fold-and-thrust belt area. Salt plugs in the eastern Fars Province initiated as early as the Palaeozoic time, and were reactivated by subsequent tectonic events. They formed either: (1) emergent diapirs forming islands, especially in the Paleogene to Neogene Sea at the front of the fold-thrust belt, or (2) buried domes. Pre-existing salt diapirs strongly influenced the development of the compressive structures formed during the Neogene Zagros folding, as well as the style of deformation and the localization of the folds.
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Improved drilling performance in re-entry wells using high-performance waterbased drilling fluid in Bahrain’s Awali field
Bahrain’s Awali field, the Arabian Gulf’s first field discovered in the 1930s, has declined in production by almost 50% over the past 30 years. Specialized drilling techniques, such as re-entry drilling, have brought new life to the field. Due to the highly deviated and challenging horizontal sections often encountered on re-entry wells in the Middle East, non-aqueous fluid (NAF) systems have typically been required to provide maximum drilling performance, wellbore stability and deliver lower overall well costs. However, environmental constraints, disposal restrictions, and risks associated with the handling of the NAF systems negate the benefit of their use. While providing the necessary level of compliance, conventional water-based mud systems used in the Awali field have proven to be particularly ineffective at providing acceptable rates-of-penetration and wellbore stability. As a result, non-productive time (NPT) has increased and larger holes sizes are needed for successful liner placement. A high-performance water-based mud
(HPWBM) has been successfully used by the Bahrain Petroleum Company (Bapco) in the Awali field as an environmentally compliant and cost effective alternative to traditional NAF. The HPWBM was able to provide considerable improvement in WBM performance in these re-entry wells. It also provided the necessary wellbore stability and reduced formation damage required for open-hole completion. Additionally, pre-planning and communication with Bapco’s engineers resulted in the targeting of potential problems, such as limited hydraulics and zones of poor hole cleaning, allowing corrective action to be taken throughout the drilling process. This presentation discusses case histories of several re-entry wells that have been drilled in the area, along with a detailed overview of the HPWBM system and its benefits. Additionally, a discussion of the engineering that went into the planning and execution of these successful reentry wells is presented.
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