The Burgan Reservoir having vertically stacked channel sands, fault network connected to the aquifer and hydrocarbon viscosity of about 40cp has the potential for premature water breakthrough leaving behind zones of by-passed oil. Placing and completion of horizontal wells in such reservoirs is a challenge necessitating collaborative approach from petroleum geoscience, reservoir engineering and petroleum engineering. The current work scope describes placing of the horizontal wells in this kind of heterogeneous reservoir through an integrated approach involving all segments of petroleum geoscience. The workflow incorporates utilization of real-time geochemical analysis (XRF) on rock cuttings, LWD data and real-time petrophysical evaluation to geosteer the smart multi-lateral wells in zones of highest flow potential and less structural complexity. The pre job planning had two components such as: (i) building a geosteering model based on offset well logs, geological and geophysical information and (ii) preparation of geochemical model based on XRF analysis of core chips from offset wells. The later model was calibrated through logs and utilized further to predict key rock attributes such as: (a) detailed lithological variations generally beyond the resolution of LWD logs, (b) detailed mineralogy to determine the diagenetic overprint and (c) depositional environment of different Burgan sand facies. The real-time geosteering operation was guided not only by the LWD tools but also through the continuous interpretation and integration of XRF and petrophysical analysis.Azimuthal Litho-density Images were interpreted in real-time not only to understand the formation dip but most importantly to identify cluster of fractures/faults, which was further complemented with XRF and seismic data analysis. Nature of the fractures/faults (open or healed, contribution to porosity and communication with water zone) were inferred from the several cross plots and Dipole-sonic data in real time and further validated with XRF obtained elemental markers. Several other cross plots along with quick volumetric analysis provided information on rock quality/type and fluid saturations.The integrated approach not only has resulted in successful geosteering and placing the wells with maximum reservoir contact but also was very instrumental for (i) isolation of potential trouble zones, (ii) segmentation of horizontal sections and (iii) optimization of nozzle sizes of the ICDs and hence planning of smart completion designs.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe Minagish field has several reservoirs with oil accumulated primarily in lower Cretaceous Minagish Oolite -middle member (MMO) rocks. This giant carbonate hydrocarbon accumulation in the Minagish field was discovered in 1958 and accounts for > 80% of oil production in the Field. The Lower Minagish end member consists largely of clean to slightly argillaceous and/or carbonaceous fine grained peloidal packstones that were deposited in a low energy platform setting equivalent to very gently sloping outer ramp.Two significant flooding events divide the Lower Minagish Formation into three main productive zones upper, middle and lower. The contact between lower and middle member is an irregular one with a gradual diagenetic transition from limestone to tight dolostone.The Lower member has a gross pay of about 220ft above recorded lowest known oil (LKO) at about 10,000 feet tvdss close to the top of the Makhul carbonates (which forms the bottom seal of the reservoir). The recent conventional cores and image log data from the crest of the structure show that the Lower Minagish has faults and fractures which could provide permeability assist. There are 130 wells have been drilled in this field targeting Minagish Oolite (middle member); however 10 wells have recently been deepened to evaluate the oil potential of the Lower Minagish (LMN) and the underlying Makhul Formations. Five wells tested in the upper and middle zones have tested at production rates in the range of 400 to 4300 BOPD with the oil from the upper and middle zones having an API of 31° to 20.5°. This is significantly lower than the Minagish Oolite oil with an API range of 28° to 32°. This indicates probably a later reservoir filling than the Minagish Oolite oil emplacement. The discovery of this new oil is expected to enhance the STOIIP of the field. Although only wells in the northern block have been drilled and tested so far, the 3-D Seismic mapping suggests possible deeper oil down to in the southern block.
The subject upper Cretaceous carbonate formation has been characterized as a heterogeneous reservoir with varying facies and petrophysical properties. Distribution of facies strongly varied not only with depth, but also laterally across the field. Upper part of the reservoir is dominated by natural fractures whereas lower part is predominantly argillaceous with mud enrichment. In addition, presence of laminations and vugs enhanced the heterogeneity of the reservoir. Very few wells were drilled and some of them were fractured. This paper demonstrates how geomechanical and integrated reservoir characterization has shown value in well placement strategy. Built number of well-based geomechanical models with data from all wells in order to capture reservoir heterogeneity in models. These models quantified the distribution of rock mechanical properties and pore-pressure as well as present day principle stresses. In addition, these models were integrated with geological model as well as seismic data to generate a 3D geomechanical model. After a thorough rock typing and petrophysical classification, some patterns were recognized in terms of presence of natural fractures in certain layers. However, the production contribution of these natural fractures was unclear. Upon combining all available sensitive fracture indicators, a DFN model was built and calibrated. Finally, the 3D geomechanical model combined present day in-situ stress and pore pressure magnitudes, mechanical properties of all rock facies and natural fracture occurrences at field scale. A thorough well production analysis was also performed to validate the role of natural fractures during production. After systematic integration of diverse sub-surface data sets in 3D geomechanical model, some natural fracture subsets were identified that are optimally oriented to become critically stressed at present day stress regime. Upon further analysis, a new parameter "Index of Critically Stressed Fractures (iCSF)" was created that captured the spatial distribution of networked fracture sets in 3D model that are geomechanically favorable for fluid flow. Number of geomechanical sweetspots were identified at field scale and correlated these areas with other data. It was also recommended to stimulate wells with certain practices. Integration of geomechanical models with production analysis and natural fracture indicators delivered value in identifying geomechanical sweetspots that have potential to flow. Distribution of these sweet spots provided a strategy for well placement as well as stimulation. In addition, this paper also exhibits logical integration of findings from geosciences and engineering disciplines to make informed decisions on well planning in order to maximize the production from challenging reservoirs.
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