Geomechanical data from the public domain for offset wells in the Horn River Basin, north–east British Columbia, Canada, were analyzed to obtain in–situ stress and rock mechanical properties in Devonian gas shale members that are under development. Static rock mechanical properties (e.g., Young’s modulus, unconfined compressive strength, peak cohesion) were calculated from wireline logs from offset wells for the shale members of interest. Derived static Young’s moduli for these shale members range from 18 to 31 GPa, and estimated unconfined compressive strength values range from 41 to 63 MPa. Assuming an average peak friction angle of 35°, the calculated peak cohesion values range from 11 to 16 MPa. From three offset wells, the average vertical stress gradient at the top of the Devonian shales was estimated to be 24.8 kPa/m. Borehole breakouts and anisotropy of the sonic log velocities from offset wells were analyzed to estimate the current orientations of the in–situ minimum and maximum horizontal stresses. The predicted orientations of the in–situ horizontal stress were compared to the well azimuths of drilled offset horizontal wells surrounding the property of interest. This regional data show that the dominant orientation of the in–situ minimum horizontal stress is NNW–SSE. Hence, hydraulic fractures will propagate perpendicular to this in an ENE–WSW orientation. The average orientation of the horizontal wells drilled by the other operators in the basin to date is NNW–SSE, with a wide scatter of other well orientations. There was insufficient data in the public domain (e.g., oriented caliper logs) to assess whether orientations or magnitudes of the horizontal stress vary over the basin, or whether they are affected by small or large faults. The average contrast of the magnitude of the horizontal in–situ stress between the shale members of interest was determined from the dynamic Poisson's ratio to understand the propensity for a hydraulic fracture to grow vertically out of zone. The result suggests relatively small contrasts may exist between the shale members. Recommendations were provided for obtaining site– specific in–situ stress data and rock mechanical properties.
The integrity of the wellbore plays an important role in petroleum operations (e.g., drilling, completion, production). Hole failure problems cost the petroleum industry several billions of dollars each year. Prevention of wellbore failure requires a strong understanding of the interaction between formation strength, in-situ stresses, and drilling practices. As in-situ stress and rock strength cannot be easily controlled, adjusting the drilling practices (i.e., selecting optimal trajectory and bottom-hole pressure) is the usual way to inhibit wellbore failure. Drilling in the problematic Kolosh formation in Kurdistan has always been associated with several wellbore stability problems (e.g., hole washout, stuck pipe, extra cuttings/cavings, tight holes). This has caused large amounts of non-productive time to drilling programs and the drilling of sidetracks in some of the wells in this field. A review of the drilling reports and dual-caliper logs from offset wells in the area revealed large amounts of washouts in the middle Kolosh section. These indicators demonstrated the requirement for performing a geomechanical modeling and wellbore stability study to mitigate such problems in future drilling operations. In this paper, local in-situ stress magnitudes, orientations, and formation pressures were characterized. For this purpose, data was analyzed from offset wells (e.g., borehole breakout data, bulk density logs, wireline formation tests, drillstem tests, pressure build-up tests, formation pressure data in this area). The mechanical properties of the formation (including dynamic and static Young's modulus, Poisson's ratio, and rock strength) were evaluated using sonic, density, and gamma ray logs. A rock mechanical properties database and data management software was applied to correlate the calculated dynamic elastic properties to the most appropriate static rock strength and stiffness parameters for a base case wellbore stability model and subsequent sensitivity analyses. 2D elastoplastic and 3D linear elastic models were used to back-analyze the hole collapse and enlargement in the selected offset wells to evaluate and calibrate the geomechanical model. Wellbore stability software was used for this purpose. Finally, a mud weight window was defined, and the optimum profile of the mud weight was recommended for drilling through the Kolosh formations. Due to a narrow mud weight window, additional potential problems were investigated including the possibility of fracturing at the top of Kolosh formation. Finally, relevant solutions were presented.
The integrity of the wellbore plays an important role in petroleum operations. Hole failure problems cost the petroleum industry several billions of dollars each year. Prevention of wellbore failure requires a strong understanding of the interaction between formation strength, in-situ stresses, and drilling practices. As in-situ stress and rock strength cannot be easily controlled, adjusting the drilling practices is the usual way to inhibit wellbore failure. Drilling in the problematic Kolosh formation in Kurdistan has always been associated with several wellbore stability problems. This has caused large amounts of non-productive time to drilling programs and the drilling of sidetracks in some of the wells in this field. A review of the drilling reports and dual-caliper logs from offset wells in the area revealed large amounts of washouts in the middle Kolosh section. These indicators demonstrated the requirement for performing a geomechanical modeling and wellbore stability study to mitigate such problems in future drilling operations. In this paper, local in-situ stress magnitudes, orientations, and formation pressures were characterized. For this purpose, data was analyzed from offset wells (e.g., borehole breakout data, bulk density logs, wireline formation tests, drillstem tests, pressure build-up tests, formation pressure data in this area). The mechanical properties of the formation (including dynamic and static Young's modulus, Poisson's ratio, and rock strength) were evaluated using sonic, density, and gamma ray logs. A rock mechanical properties database and data management software was applied to correlate the calculated dynamic elastic properties to the most appropriate static rock strength and stiffness parameters for a base case wellbore stability model and subsequent sensitivity analyses. 2D elastoplastic and 3D linear elastic models were used to back-analyze the hole collapse and enlargement in the selected offset wells to evaluate and calibrate the geomechanical model. Wellbore stability software was used for this purpose. Finally, a mud weight window was defined, and the optimum profile of the mud weight was recommended for drilling through the Kolosh formations. Due to a narrow mud weight window, additional potential problems were investigated including the possibility of fracturing at the top of Kolosh formation. Finally, relevant solutions were presented.
The Upper Devonian Grosmont Formation, located in the West Athabasca Oil Sands Deposit, contains an estimated 406 billion barrels of bitumen. The reservoir is a heavily karsted and fractured, bitumen-saturated carbonate. Initial thermal horizontal well development is currently underway in this resource. These horizontal wells have similar logistics, well construction and materials challenges to those in the McMurray Formation. Laricina has been actively developing the Grosmont Formation. Production from the pilot began in 2011 and many lessons have been learned. The next phase of development is a 10,700 bbl/day commercial project scheduled for first steam in 2014. The Grosmont, despite many drilling challenges such as severe lost circulation, also provides many opportunities not typically achievable in clastic oil sands developments. Carbonate rock is typically a good candidate for open-hole completions due to its geomechanical properties. This paper will discuss the geomechanical investigation evaluating borehole stability during drilling and completion, steam injection and production operations.
The focus of this study is to improve our technical understanding of anticipated drilling hazards in the Arctic Circle, especially hazards relating to drilling into and adjacent to evaporitic (salt) structures and associated tectonics. We explore current drilling technologies available to us to mitigate any anticipated drilling hazard. We demonstrate applicable operational experiences from other areas similar to drilling in the Arctic. The Arctic's vast oil and gas potential has spurred exploration since mid-20th century. Government institutions such as the Geological Survey of Canada and historic companies such as Panarctic provide critical information on geology and petroleum discoveries. U.S. Geological Survey (2008) published Arctic mean estimated undiscovered technically recoverable conventional oil and gas resources at a total of 412 billion barrels of oil equivalent (BBOE). Exploration in the Arctic varies in complexity mainly based on the depth drilled and hazards encountered. The remoteness of drilling anywhere in the Arctic makes both onshore and offshore operations generally more complex than drilling elsewhere in the world. To put it in perspective, our research into drilling time in deepwater Nova Scotia show for the majority of high complexity wells, non-productive time (NPT) can exceed 24% of total drilling time, and half of documented NPT is contributed to formation related problems. Our geological analysis has found that Arctic petroleum basins and margins such as the Sverdrup Basin and East Canada and show comparable salt tectonics to Nova Scotian continental margin, offshore Brazil and Angola. Salt diapirs, salt domes, and thicken salt sections are common occurrences. Associate structures such as anticlines, extensional growth faults, wrench faults are observed in these basins. Extensional growth faults, listric normal faults, thrust faults, flank-salt shears, and brecciated fault zones are associated with salt bodies. These structures are planes of weakness. Depending on effective in-situ stress conditions these faults and intense natural fractures can become critically stressed and induce slip on plane. Salt rheology and geochemistry pose higher drilling risk than drilling through other rocks. Salt creeps towards borehole during drilling, and plastic yielding around borehole is unavoidable when drilling through salt body. Boundary zone tends to be heavily naturally fractured, brecciated, or sheared, and rock may become unconsolidated and lose its cohesiveness. Taking heavy losses in naturally fractured boundary zone may occur. Abnormal pressure exists and taking a kick while drilling out of salt body is not uncommon. Public domain documentation available for Arctic region support the hazards identified by our geological analysis and also suggest that a great deal of downhole uncertainty exists during early exploration. In analogous setting outside of the Arctic Circle, drilling problems related to pressure uncertainty, tight windows and wellbore stability are referenced throughout and the lessons learned suggest limiting the uncertainty when possible and the use of contingency planning. Based on the similarities in the structural geometry of petroleum basin in Arctic and select basins in other parts of the world, it seems logical that lessons learned from these areas away from the Arctic, e.g., offshore Nova Scotia, Brazil, and Angola should provide some assistance with the planning and execution of Arctic drilling activities. All information collection during this study has been referenced throughout. This information will be beneficial for continued support of drilling in salt tectonic structural provinces in the Arctic and anywhere else in the world.
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