Traditional exploration drilling practices include targeting the structural crest; maintaining a vertical borehole; and drilling over-balanced for safety reasons. All three drilling practices may threaten success in naturally fractured reservoirs in which well and reservoir flow performance relies on flow through natural fractures. Depending on the deformation mechanism of folds, more folding related natural fractures may develop on the limb of the structure than on the crest. At typical depths, open fractures planes are likely to have a sub vertical orientation; and a deviated borehole, drilled in a direction normal to the natural fractures, will intersect many more fractures than a vertical one. Over-balanced drilling can result in lost circulation of damaging drilling fluids and solids in the natural fractures. Cementing the fractured zones can further plug natural fractures, leaving little behind pipe to provide sought-after productivity from the natural fractures. This paper offers insight on drilling and completion strategies based on experiences in two South American locations with distinct structural styles. One is a Devonian gas discovery in Bolivia and the other a block southwest of Lake Maracaibo with both mature fields and exploration prospects of Cretaceous age. In both instances, the structural style and orientation provide a framework for borehole trajectory planning. Introduction The typical naturally fractured reservoir is found in strata of Cenozoic age and older with formation tops at depths ranging from 80 ft to 16,000 ft and deeper. Often the formation lithology is characterized as hard rock of low porosity and permeability, and the main flow paths are provided by the natural fractures while most of the fluids are stored in the matrix rock. To be economically exploited, the reservoir must offer sufficient reserves, and wells must have sufficient productivity to produce the reservoir fluids at economic rates. For most fractured reservoirs, the matrix rock accounts for the bulk of the reserves. Exceptions are fractured shales and fracture basement rock or granite. In both cases, there are often arguments that the produced fluids may be coming from another formation via the natural fractures. Excluding these very special cases, an important part of the completion strategy is the identification of fractured intervals with sufficient matrix porosity. When depositional and diagenetic trends can be determined, these should influence the selection of prospective drilling locations. When the matrix rock permeability is low, the location of natural fractures become the critical factor in selecting drilling locations, and characterization of the natural fracture system provides insight for planning the well trajectory through the productive formation and designing an optimal completion and stimulation strategy. Formations with sufficient reserves but lacking natural fractures may be candidates for hydraulic fracture stimulation. These will probably be more costly to exploit than will those with natural fractures because the natural fractures will provide contact with more matrix rock, thereby resulting in higher well productivity, provided the well trajectory is designed to contact a maximum number of the most productive natural fractures. Various geological processes (e.g. folding, faulting, etc.) have been postulated to describe the development of fracture systems. These structural features can be studied at the surface or are visible as events in seismic data. The location of folding related fractures and their geometry may be predicted based on the folding mechanism and the stress regime. The two studies discussed in this paper illustrate drilling and completion recommendations for two distinct structural styles. The Caranda Field in Bolivia has an anticlinal structure as part of a wrench fault assembly. Productive reservoirs and exploration prospects in the Colón Block in Venezuela are present in structures interpreted as fault bend folds.3 The description of each case will emphasize what could be learned about the natural fractures from various data and what drilling and completions recommendations were made based on the natural fracture characterization.

Balancing aggressiveness, stability and durability bit behaviours is the principal engineering challenge when designing an application-specific PDC bit. The application this paper addresses is a directionally drilled interbedded abrasive formation that generates dysfunctional drilling torque. This paper demonstrates the engineering process of designing a bit that balances the three major bit behaviours, thereby optimizing drilling efficiency to meet the goals of successfully drilling the required interval while improving rates of penetration. West Kuwait's 12.25" section primarily involves interbedded abrasive sandstone and hard shale sublayers that induce torque fluctuations. The combined result is impact and abrasion wear on cutters causing mid-run reduction in rates of penetration, prematurely terminating the run. The section involves a J-type directional profile drilled using an adjustable-bend mud motor or a rotary steerable system. It starts off drilling vertically till the kick off point followed by building up to the tangent section and holding angle to section end. The high torque and vibrations faced in this application make steering difficult for any directional drive type; further compounding the challenge to achieve higher rates of penetration. Building a solution to match the application involved: Reviewing bit dulls and studying locations of extensive wear on the bit body Comparing current design performance against success metrics in the target application Bit design requirements for specific rotary steerable systems and mud motors to build a universal design that works with all major drive types Consideration of different torsional stability technologies and their appropriateness for our application Field trials across different drive types The engineering process concluded with a seven bladed PDC bit with aggressive cutting structure that successfully completes the interval while improving rates of penetration by over 50%. Trials were implemented across several wells involving the major drive types to verify the new design's effectiveness versus previous designs. Most trials proved the bit was more efficient in directing mechanical specific energy into the formation rather than squandering drilling energy on damaging vibrations. This resulted in rates of penetration higher than the field average through better bit stability and smoother steerability on all directional drive types used in the application. This paper highlights the engineering process and the technology invested in developing a PDC bit for drilling directional runs through mixed abrasive and impact prone formations.

The Umm Gudair 12.25-in. vertical drilling performance section involves several technical challenges for engineering an application-specific PDC bit. The interval consists of two formations that require contradictory bit design principles. The abrasive Zubair formation incorporates sandstones interbedded with hard shale streaks, followed by dual Ratawi intervals of hard shales that are succeeded by compacted limestone. The initial sand interval abrades the cutting structure, resulting in slower rates of penetration in the deeper carbonates. The premature dulling of cutters then causes lower carbonate drilling efficiency. Typically, the section is drilled at 35 feet per hour (fph) and requires 2 bits to complete. After reviewing offsets with faster than average rates of penetration that successfully completed the interval in the same application, a design compromise was achieved. The new optimized bit design is based on a seven-bladed bit with sixteen-mm cutters. Subsequent design iterations optimized the cutter selection and the cutting structure to maximize durability in the sands while remaining aggressive enough to drill the lower carbonates. An iterative design-and-simulate process then followed, simulating bit stability against formation strength data and optimising drilling fluid flow dynamics. The design was adjusted repeatedly based on the simulation results until a balance in aggressiveness, stability and flow was reached. After the design process concluded, optimal drilling parameters for each formation were drawn up from offset wells, and the new design was field tested. Drilling stability improved in the sand interval while cutting structure integrity was sustained into the deeper carbonates, resulting in improved rates of penetration in both intervals. After several runs, the results demonstrated that significant gains in rates of penetration were made; reaching over 90 feet per hour (fph) in some cases, almost doubling current rates of penetration. The post-run dull condition of the bits tended to be virtually new (1-1-WT), and in one instance the bit re-ran on a second well, drilling the interval at 53fph. This paper demonstrates a successful engineering design process for such a challenging section in the Umm Gudair Field. It then highlights the technologies featured in this bit and their value in drilling this application. Finally, field test results are analysed and the improvements in drilling performance and time and monetary savings to the operator are quantified.

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