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 the intermediate sections in the deep gas fields of Saudi Arabia is challenging because of a long, intricate geological sequence consisting of hard carbonates (limestone and dolomite) interbedded with anhydrite. Historically, the primary operator has attempted to drill the section using both roller cone tungsten carbide (TCI) and polycrystalline compact (PDC) technology. PDC bits provided better penetration rate and durability, as compared to TCI bits. However, several PDC bits were required to drill the section, which increased the time needed for drilling and tripping at relatively deep intervals. The increased time exposes the well to risks when the hole is open for long intervals.After further analyses and a systematic bit optimization process, three new PDC bit designs were created and used, which established new benchmarks in two of the deep gas fields. Meeting the objective of minimizing the number of bit trips by enhancing PDC bit performance and bit durability to drill longer intervals with a higher penetration rates required a new PDC bit technology in conjunction with optimized motor drive. To address the challenge, the operator, bit vendor, and other service companies worked together to develop an optimized solution to drill these sections.The paper reviews the findings of the study in drilling the intermediate sections in two of the challenging deep gas fields. The study shows that PDC bit damage from encountering harder stringers was the primary impediment to achieving better performance. The impediment was overcome by implementing the new cutter technology and drilling simulation software to optimize the cutting structure design. The paper demonstrates the improvement in the deep gas fields in Saudi Arabia by comparing the performance of the most recent wells, in which the new technologies were implemented, to the earlier wells to illustrate the significant time and drilling cost reduction.
Directional drilling in the build up section at North Oman Field in the Sultanate of Oman is challenging because of highly intercalated and unstable formations. The formation consists primarily of soft to medium hard limestones, dolomites inter- bedded with anhydrite, and a thick layer of unstable shale that forms the cap-rock of the targeted reservoir. The field development plan (FDP) specifies drilling long horizontal wells with two casing strings and a liner, and requires the reservoir section to be placed within the top meter of reservoir rock. Consequently, it is critical to land inside the top meter of the reservoir. The lack of directional control throughout the soft intervals, high dip angles in some of the formations, and the short vertical section from surface to landing point requiring BUR of 5 to 6 degrees/30mts created complications in drilling the build section. With these elements, optimum directional tools steerability is necessary to achieve the well objectives. To overcome these challenges, the operator and drill Bit Company developed an optimization process to design a polycrystalline diamond compact (PDC) bit to use with point-the-bit rotary steerable systems (RSS). The optimization process included increasing the bit steerability and stability to increase the rate of penetration (ROP). This challenge required the development of a new PDC technology with optimized drilling practices and a reliable drive system. Specific bit design algorithms were incorporated with a new bit gage configuration, and drilling simulation software was used to optimize bit cutting structure design in the directional drilling environment. Significant bit design improvements were achieved. Going through field testing, drilling parameter evaluation and optimization, an 8½-in PDC bit design was created that established benchmark performances in the North Oman Field field. The successful development of the PDC bit with the RSS system enabled record bit runs in the build sections, which were drilled in accordance with the FDP with significant ROP improvements compared to conventional motor. This paper reviews the bit design and optimization process that helped to improve the drilling performance and hole geometry, reduce rig days, and enable early delivery of the wells in the challenging Sultanate of Oman drilling environment.
The process of drilling the 12 ¼-in. section in the deep Khuff field offshore Abu Dhabi is challenging because of an intricate geological sequence. This sequence consists of carbonates (limestone and dolomite) and anhydrite that are interbedded with shale and sandstone. In the past, the operator, ADMA, has attempted to efficiently drill the section by using roller cone tungsten carbide (TCI) and polycrystalline compact (PDC) technology. PDC bits yielded a better performance in terms of penetration rate and durability in comparison to the TCI bits. However, because several PDC bits were required to drill the section, the amount of time required for drilling and tripping at a relatively deep interval increased. The increased time exposes the well to many risks that could occur as a result of tripping in a long open hole interval. To reduce the time and risk factors, additional analyses were performed that led to the creation of an optimum PDC design and established new benchmarks in the field at the first trial. The objective of the study was to minimize the number of bit trips by enhancing the PDC bit performance and bit durability to drill longer intervals with a higher rate of penetration (ROP). Meeting this objective required a new PDC technology in conjunction with optimized motor drive. To address the challenge, ADMA, the bit vendor, and other service companies worked together to seek an optimized solution to drill this section efficiently. This paper reviews the findings of the detailed study in drilling the 12 ¼-in. section in typical deep Khuff wells. The study shows that PDC damage from encountering harder stringers was the primary impediment to achieving better performance. The challenge was overcome by implementing a new cutter technology and drilling simulation software to optimize the cutting structure design. The improvement that occurred in Umm Al-Shaif field is demonstrated by comparing the performance of the most recent well, in which the new technologies have been implemented, to the performance of earlier wells to illustrate the significant savings in time and eventual drilling cost. Background This paper focuses on achieved performance and economic savings in the 12 ¼-in. section in Umm Al-Shaif offshore field in which ADMA develops deep Khuff gas wells in United Arab Emirates. The 12 ¼-in. section is drilled from the Hith formation, which is encountered at 9,000 ft depth average, down into the Upper Khuff formation. This drilling interval crosses ten different formations, and the section length ranges between 5,500 and 6,400 ft. The section is drilled tangentially, with an inclination of 30 to 35 degrees, with medium speed positive displacement motors (PDM), but other driver mechanics, such as rotary steerable systems (RSS) and turbines, were used in previous wells. The turbine performance in this field as driver mechanisms was studied by Salman and El Raggal (1999). Until recently, the bit types used to drill this section consisted primarily of PDC drill bits with varying design and cutting structures; however, the performance of most of the bits was less than planned in terms of footage drilled and ROP. Several bits failed prematurely, which resulted unplanned trips and the use of additional bits (Salman and El Raggal 1999). As shown in Table 1, Well X, drilled several years ago, used eleven bits to drill the interval, with an average of 360 ft drilled per bit. Most of the bits were pulled out of the hole because of low ROP, and most of the PDC bits showed severe cutter damage.
Directional drilling the 12-in. curve section in the deep gas fields in Saudi Arabia is very challenging because of the hard formations and harsh drilling conditions. The section consists primarily of hard limestone and dolomites interbedded with anhydrite. The main challenges of drilling this section include multiple bit trips and reduced rates of penetration (ROP).To overcome these challenges, the operator, directional drilling service company, and drill bit company in collaboration developed an optimization process to create and evolve a polycrystalline diamond compact (PDC) bit design to be used on powered rotary steerable systems (PRSS).The objective of the optimization process was to increase the ROP and the durability of existing PDC bits to eventually lead to drilling longer intervals by minimizing the number of bit trips while drilling with PRSS. The challenge required the development of a new PDC technology in conjunction with optimized drilling practices and a reliable drive system. The challenges were overcome by implementing the specific bit design algorithms incorporated with new cutter technology, and using drilling simulation software to optimize the bit cutting structure design in directional drilling environment. Significant improvements in bit design were achieved after closing the model/measure/optimize loop. Through field testing, drilling parameter evaluation, and drilling simulation, a new 12-in. PDC bit was designed that established benchmark performances in the deep gas operations in the Ghawar field.The successful development of the PDC bit in conjunction with the PRSS system led to record runs in the 12-in. build section. Casing-to-casing sections were drilled with an improved ROP of approximately 125%, compared to that of a conventional motor. This paper reviews the bit design and optimization process to develop the fit-for-purpose PDC bit that helped to improve the drilling performance, significantly reduce rig days, and enable early delivery of the wells in challenging deep gas drilling in Saudi Arabia.
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