This paper summarizes the results obtained from a comprehensive, joint-industry field experiment designed to improve the understanding of the mechanics and modeling of the processes involved in the downhole injection of drill cuttings. The project was executed in three phases: drilling of an injection well and two observation wells (Phase 1); conducting more than 20 intermittent cuttings-slurry injections into each of two disposal formations while imaging the created fractures with surface and downhole tiltmeters and downhole accelerometers (Phase 2); and verifying the imaged fracture geometry with comprehensive deviated-well (4) coring and logging programs through the hydraulically fractured intervals (Phase 3).Drill cuttings disposal by downhole injection is an economic and environmentally friendly solution for oil and gas operations under zero-discharge requirements. Disposal injections have been applied in several areas around the world and at significant depths where they will not interfere with surface and subsurface potable water sources. The critical issue associated with this technology is the assurance that the cuttings are permanently and safely isolated in a cost-effective manner.The paper presents results that show that intermittent injections (allowing the fracture to close between injections) create multiple fractures within a disposal domain of limited extent. The paper also includes the conclusions of the project and an operational approach to promote the creation of a cuttings disposal domain. The approach introduces fundamental changes in the design of disposal injections, which until recently was based upon the design assumption that a large, single storage fracture was created by cuttings injections.
This paper was prepared for presentation at the 1999 SPE/IADC Drilling Conference held in Amsterdam, Holland, 9-11 March 1999.
This paper discusses a successful initiative begun six years ago to eliminate differential sticking across global operations. In the five year period from 2004 through 2008, there were only 3 differential sticking events in 3,476 wells drilled with the recommended practices. There were an additional 17 sticking events with designs that did not conform to recommended practices, and 14 of these were freed. The drilling environment was diverse. Overbalances in excess of 1,000 to 2,000 psi were common in multi-darcy rock and high angle, and depleted reservoirs have been drilled with overbalance as high as 7,800 psi in vertical wells. The early focus of the Stuck Pipe Avoidance practices was the elimination of differential sticking. However, some level of sticking occurs routinely in drilling operations and these events only become problematic if the force required to initiate pipe movement exceeds what can be delivered to the stuck point. It is now accepted that sticking cannot be prevented and that elimination of sticking is not a proper design objective. The philosophical objective has now shifted from elimination of sticking to "maintaining conditions that allow the pipe to be pulled free," assuming that it will become differentially stuck. The desire to maintain this ability to move the pipe has required the implementation of a range of practices, some of which were not common in the industry. Changes were made in bottomhole assembly (BHA) design, fluid design, real-time cake shear strength recognition, and real-time cake remediation practices. A finite element (FE) model was also applied to redesign new systems or applications that lie outside the operator's previous experience. The stochastic model predicts cake growth and sticking force and the probability that it will be possible to deliver a force that can free the pipe for any given still-pipe time. The model inputs were calibrated through pullout tests with a variety of fluids to determine mechanical cake strength properties, the rate at which those properties develop, changes in the pressure transient through the cake as it matures, and the cake contact areas and geometry at any point in time. Engineering and operations training also contributed greatly and allowed relatively uniform implementation to be achieved across a large, globally diverse operation in less than one year. A small number of non-compliant designs continued to be used and these contributed greatly to the incidence of stuck pipe in the first three years. Last year, there was only one incident of stuck pipe with a non-compliant design. The paper describes the underlying sticking concepts, the engineering design and field practices used, the modeling capability, and the field results.
In 2007, Hibernia Management and Development Company Ltd. (HMDC) began drilling operations on B-16 57 (OPA2). The plan involved drilling and completing an oil producer to 32,000-ft measured depth (MD) and to a total vertical depth (TVD) and horizontal departure that would put the well outside the worldwide ERD envelope. The well was temporarily plugged and abandoned at ~20,000 ft in the 12¼-in. hole section as a result of a combination of factors including complex geology and wellbore instability.The planning of the redrill began almost immediately and involved the collaborative efforts of the local drill team, the local geoscience team, industry experts from ExxonMobil, and the other HMDC co-venturers and service providers. The final trajectory was a result of HMDC co-venturer collaboration and balanced risk associated with encountering unstable zones and complex lithology. Successfully drilling this well would require an engineered approach to operations as well as incorporating an ultra thin fluid system in the 8½-in. hole section.The successful execution of the redrill was a result of enhanced cooperation between the operations, engineering, and geoscience teams. The application of proven HMDC and ExxonMobil practices for hole cleaning, rate of penetration (ROP) management, and wellbore stability were critical success factors. The increased focus on downhole mechanics and surface limitations through the ExxonMobil Fast Drill Process and the flat time reduction initiative allowed OPA2 to be completed successfully at a depth of 33,209-ft MD, further extending the worldwide ERD envelope. Application of the drill team's standard bit and bottomhole assembly (BHA) design allowed shock and vibration and mechanical specific energy (MSE) to be minimized, resulting in field record rates of penetration (ROPs). Most notably, the 8½-in. hole section was drilled in one shoe-to-shoe bit run in 5.7 days. The nearest offset, completed in 2003 in the same geologic fault block, required eight bit runs and 57.6 days from drill out to TD.
Numerous wellbore instability problems related to drilling through potentially fractured formations have been reported. Often, these rocks are characterized by the abundance of macro and micro scale bedding planes and/or networks of natural fractures. The presence of fractures weakens the rock mechanically and produces potentially higher-permeability fluid-flow paths within the low-permeability rock matrix. Practically, it is difficult to identify fracture size and fracture density without a costly core sample. A number of wellbore stability case studies have therefore been published where the author relied on anecdotal evidence to postulate failure mechanisms involving fractured rock, and recommendations for how to mitigate the observed instability range from increasing to decreasing the wellbore pressure. This paper presents results from a geomechanical investigation of a wellbore instability incident experienced in a fractured shale formation. As part of this assessment, a preserved core was obtained from the fractured shale interval and the presence of fractures was identified both by CAT scan and visual inspection. A series of triaxial tests were conducted to characterize the mechanical properties and failure strength of this shale. This data, combined with wellbore stability modeling, suggests that the residual strength, rather than the peak failure strength, is a more representative measure of a fractured rock's in-situ strength. The Hoek and Brown (1982) failure criterion was found to be particularly suitable for modeling fractured rock. Multi-arm caliper logs from two boreholes through the same fractured shale suggests that wellbore instability is more complex in the fractured interval than in the over- and underlying intact rock. These caliper logs also clearly demonstrate that the borehole quality was significantly improved by increasing the drilling fluid density, which contradicts the conclusions drawn in a number of published wellbore stability case studies (Santarelli et al., 1992; McClellan et al., 1996; Edwards et al., 2004; Fontana et al., 2007).
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