This paper describes an innovative concept for the smallest polycrystalline diamond compact (PDC) cutter size with non-planar diamond table used on a fixed cutter drill bit. This unique PDC cutter significantly increases durability, enhancing the bit life to drill more footage in multi-lateral applications driven by motor or turbine in two different challenging formations. Collaboration between a national oil company and a drill bits provider resulted in achieving consistent records in footage while maintaining good rate of penetration (ROP). This 8.2 mm diameter PDC cutter equipped with unique geometry was used on a 3.625 in. fixed cutter (PDC) drill bit design. Main objective of the unique geometry on this non-planar diamond table is to improve cooling efficiency compared to the standard diamond table of a PDC cutter. Traditionally, PDC cutter technology relies on the cutter's thermal stability and abrasion resistance. Often, those two properties may not provide sufficient durability in abrasive formations. Initially, this unique geometry was used on bigger PDC cutters including 13 mm and 16 mm where a performance improvement was achieved, leading to the decision to scale-down to the smallest PDC cutter size. Two different 3.625 in. fixed-cutter drill bit designs were used with non-planar diamond table PDC cutters and successfully passed the client requirement and trial testing criteria. Based on the field deployment results, drilling performance in the field was monitored and compared to standard diamond table PDC drill bit designs also used in the past as the benchmark. Shaped non-planar diamond table bit designs surpassed the footage of standard diamond table PDC cutter bit designs by 12% and 36% respectively with two different bit designs. Other performance aspect including dull condition were also monitored and showed similar wear progression as seen with other bit designs used in the application. This innovative concept demonstrates that the non-planar diamond table PDC cutter successfully delivers more footage per bit run. This led to increase overall performance with deployments on coiled tubing drilling rigs across this difficult drilling environment in the challenging wells drilled in the Middle East. The novel technology achieves all drilling objectives with fewer drill bits and fewer trips, delivering the target footage at improved ROP.

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The tendency of PDC (Polycrystalline Diamond Compact) bits to ball in soft shale formations when drilling with WBM is well documented, especially in deep/high-pressure applications. The capacity of shale to absorb water causes the formation to stick to the bit body and cutting structure compromising drilling efficiency. Balling also clogs the nozzles and junk slots reducing hydraulic effectiveness/cooling leading to accelerated cutter wear and premature bit failure. In Saudi Arabia's fields, a typical well requires approximately 1,600–2,200 ft of a 12-in. vertical borehole or 3,000 ft of a 12-in. directional borehole to be drilled through carbonates, shale and claystone lithologies. The middle part of the section is composed of mainly claystone, which is the most problematic zone. In recent wells, bit balling incidents through the claystone interval was reducing average rate of penetration (ROP) to less than 10 ft/hr, and in certain cases forced to pull out of hole (POOH). PDC bits with various hydraulics configurations and non-stick coatings were tested in an attempt to alleviate balling issues. The thin layer eroded before the bit entered the problematic zone, exposing the rough bit body. An R&D initiative determined mechanical and electrochemical sticking contributes to bit balling. The investigation revealed a coarse bit body increases surface area and adhesive force. When mud flow stops an electrostatic force can cause clay to stick to the bit surface. Based on these findings a new type nickel-phosphorus electroplating process was implemented that creates a thick/durable coating with an extremely strong chemical bond. This paper reviews the investigation process and findings of three case studies in the Saudi Arabian fields. The new anti balling coating was applied to a seven bladed PDC design and run on a powered point-the-bit rotary steerable system. The bottom-hole assembly (BHA) drilled the entire section achieving a field ROP record. Drill bits with the new anti-balling coating were also tested in vertical wells in different gas fields setting new bit performance benchmarks. Application Review In a large gas field in Saudi Arabia, containing several distinctive sub-fields, a 12 in. hole size section needs to be drilled through a mixed sequence of rocks that are comprised of limestones, dolomites, anhydrites, siltstones and shales. A particularly problematic section of the well occurs through a shale formation that is reactive to hydration. In this section, bit balling, as well as stabilizer balling, is a known occurrence with the water-based mud that is utilized. This causes a drastic reduction in ROP and sometimes bits are pulled prematurely but they are typically in good condition once seen at surface (Fig. 1). Field experience has shown that the cutting structure is partially balled up while drilling, causing the low rates of penetration. Use of drilling fluid additives to help reduce the potential risks of bit balling has been investigated and introduced into the application, showing some improvements. The overall drilling performance through this interval, especially the low ROP, is still a major concern for the operator in these wells.

Drilling rate of penetration (ROP) is one of the variables that influences well delivery timing and cost. ROP is affected by many factors, including but not limited to well profile, bottom hole assembly (BHA) design, challenging formations per section, and drill bit selection. In one of the drilling project in the Middle East, the primary method chosen to improve well delivery is to focus on optimizing the drill bit design in order to improve ROP while delivering other drilling objectives. As the project progressed, the ROP plateaued in most of sections in the field. The drilling team collaborated with the drill bit engineering to launch a drill bit optimization campaign in various hole sizes ranging from 16-in. to 6⅛-in. Since fixed-cutter bits are predominantly used in these sections, improvements are made to the existing drill bit designs by replacing the cutting elements with more efficient three-dimensional polycrystalline diamond compact cutters (3DC). 3DC cutters have different shapes, uniquely designed to tackle different drilling challenges. Using an in-house petrophysical log analysis program, each of the formations drilled in this field was analyzed, drilling challenges and ROP values were compared against previous performance. This information paired with finite element analysis (FEA) for dynamic drilling simulation was used to the optimize drill bit selection. This workflow was followed to avoid costly field tests and ensure that the newly designed drill bit performs flawlessly downhole. Other design elements, such as choosing bit body material, were also incorporated by converting matrix-bodied to steel-bodied, which not only improved the ROP but also reduced the cost-per-foot (CPF). Initially the bit optimization program enabled ROP improvement in the 16-in. section by 36 percent from 55 ft/h to 75 ft/h by replacing the roller-cone bit with a matrix-bodied fixed-cutter bit. Moreover, the drilling team further improved their performance, achieving 118 ft/hr. ROP when using the steel-bodied bit. The ROP in 12¼-in. section improved by 50% from 30 ft/h to 45 ft/h when the 3DC bit was used. Prior to using the 3DC bits, the existing bit design with the conventional flat PDC cutters was tested and showed minor ROP improvements. Similarly, two different 3DC cutters were introduced in the 8½-in. section and successfully improved overall ROP by 20%. In addition, the 6⅛-in. section showed 35-percent improvement in ROP following several design iterations that utilized two different types of 3DC cutters. By the end of the drill bit optimization campaign, the operator was able to improve the drilling curve and save up to 2.5 days per well. The 3DC cutters also helped eliminate the risk of bit failure in the 8½-in. section, wherein offset wells several bits were required to complete the section. With the performance mindset new technology deployment made faster to test new bit designs. This helped with getting early data point for analysis before being able to test in the different fields in the area.

Because of high formation pressure in certain formations, there are three different casing designs available, including slim-bore wells and big-bore wells. The slim-bore wells are 12-in hole section applications, and big-bore wells drilled as 16-in hole sections. In 12-in slim-bore wells, a major challenge is to drill through different carbonate formations with unconfined compressive strength (UCS) between 10,000 and 30,000 psi with hard streaks peaking at 40,000 psi toward section end. Another challenge in the lower section is high formation abrasiveness, which increases PDC cutter wear rate and slows ROP to an unacceptable rate of less than 10 ft/h before reaching TD. The challenges of this extensively drilled application are well known, and the most efficient bit design to date is a seven-bladed PDC with 16-mm cutters. The existing PDC delivers an acceptable ROP, but its dull condition suggests that a more efficient cutting structure would improve project economics in areas of slim-bore wells where the operator expected poor performance. An R&D project to improve PDC bit performance produced a Conical Diamond Element (CDE) with twice the diamond thickness of a conventional PDC cutter. The CDE provides superior resistance to abrasive wear and impact load damage. To extract the maximum benefit from the CDE's enhanced durability, design engineers used a finite element analysis- based modeling system to position the element at bit center on the baseline design by reducing cutter volume. The new design would increase drilling efficiency at the center of the borehole, leading to higher ROP. This new type of PDC has also proven to reduce damage from torsional vibration for improved stability and borehole quality. The modeling system was also used to identify rpm and WOB combinations most likely to improve ROP and dynamic stability drilling through the difficult carbonate formations. Two new 12-in bits were run in the satellite field wells and set new back-to-back benchmarks for the fastest ROP on their first run. In the X field, this bit achieved an 18% improvement in ROP (73.1 ft/h) compared with four offsets drilled with conventional PDC, resulting in a 10% reduction in cost per foot. In the Y field, the central CDE-type bit achieved a 9% improvement in ROP (72.8 ft/h) compared with a direct offset resulting in an 8% reduction in cost per foot. The authors will discuss operational challenges and the technical justification for running the CDE equipped PDC bit. The paper concludes with a discussion of economic benefits for the operator by utilizing this new technology.