Use of 16-in. vertical sections in onshore deep gas drilling operations in Saudi Arabia presents challenges with a high risk of total drilling fluid loss in interbedded formations. The formations comprise carbonates, limestones, shales, anhydrites, and abrasive sandstone with pyrite inclusions, where the rock hardness is 10 to 15 kpsi unconfined compressive strength (UCS). To minimize the risk of loss, the high bentonite mud system is implemented. The bit consumption averages two tungsten carbide insert (TCI) bits per section, and high average dull grading conditions are observed (IADC 3-4-WT), coupled with low rate of penetration (ROP) performance across the whole section. Though an in-depth offset well study, including bottom-hole assembly (BHA) analysis, bit dull condition review, evaluating the high bentonite mud effect, and the UCS formation trend, the potential to drill the 16-in. section in a pilot well in a satellite field (using hybrid bit technology) was determined. This paper outlines the development of the best drill bit technical solution, optimizing the use of crushing (TCI inserts) and shearing effect (polycrystalline diamond compact – PDC) cutting structure configuration to drill the section in the minimal time and cost possible. The results observed in the pilot well confirmed that one hybrid bit had the ability to drill the total section. A 138-percent increase in the rate of penetration (ROP) versus relevant offsets, and a decrease 2.3 operational days and 50% cost per foot reduction. The hybrid bit reached the total depth (TD) section without any operational issues, where the risk of losses was minimized, and a proportionate normal dull condition in the cutting structure was observed. The technical compatibility of the hybrid technology was demonstrated with outstanding performance for the operator.

With an objective to shorten directional intervals, operators place greater demand on higher Build Up Rates (BURs). The section just before the pay zone involves the most intensive directional work, pushing rotary steerable systems to their capability limits. This paper focuses on a particular interval of hard and soft interbedded carbonates that provides a significant challenge for conventional Polycrystalline Diamond Compact (PDC) bits to provide consistent build up rate and good borehole quality on rotary steerable systems. Throughout this paper we demonstrate the engineering process of designing a bit to increase buildup rate capabilities of rotary steerable systems and improving drilling efficiency through interbedded carbonate formations. The engineering process involved reviewing the critical issues of this application to assure a sound solution. This included: Current build up rates versus Rotary Steerable Systems (RSS) steering capability. Vibrations generated by conventional PDC bits being deployed in the field. Specific cutting structure, depth of cut limiters and gauge requirements for different RSS drive types. Formation strength analysis. Parameters used in drilling the section. Roller cone insert and PDC interaction of the hybrid bit with the formation and how formation deformation generated by one interacts with the other. Roller cone insert design aimed specifically at carbonate formation drilling Various hybrid drill bit and Bottom Hole Assembly (BHA) combinations were evaluated with state-of-the-art drilling response simulator to review the buildup rate capabilities combines with the bit and BHA interaction. The best combination was then successfully trialed on several wells, proving significant improvement compared to current performance with conventional PDC bits. The optimized hybrid bit and BHA combination eliminated drilling vibrations in intervals where extreme vibrations were witnessed with conventional PDC bits, significantly increasing drilling efficiency. Improved torsional stability reduced the load on the directional tools improving the ability to achieve the required doglegs. In softer shale where RSS with conventional PDC's had to control parameters while using maximum steer force to achieve target dog legs of 7°/100ft, the hybrid drill bit achieved 10°/100ft while utilizing only 70% of the steer force. The hybrid drill bit has been proven to be successful with both push-the-bit and point-the-bit RSS systems. Hybrid drill bits have proven to be a solution to problems and limitations of both conventional PDC and roller cone bits in directional drilling. Based on recent refinements in the drilling mechanics of hybrid drill bits to further improve their interaction with directional drilling systems, engineering selected this emerging technology to overcome the challenges in this particular application.

The Brazil ultra-deepwater, pre-salt application has been a very challenging drilling environment since exploration activity began in 2005. The initial pre-salt section contains limestone with random silicified nodules. Over the last few years, operators have collected large amounts of data for service companies to analyze to improve drilling performance through bit design. Using this information, a hybrid bit design with the most advanced cutter and bit technology was developed successfully increasing the distance drilled by 138% and the rate of penetration (ROP) by 171%.Prior to advanced hybrid bit technology, a variety of other drill bit technologies such as polycrystalline diamond compact (PDC) bits and impregnated designs were used in the pre-salt. Historically, impregnated bits had longer runs, but with high mechanical specific energy (MSE) and low ROP, drilling with these bits was not economical. Contrarily, PDC bits can deliver higher ROP but cannot drill as far as impregnated bits. Three hybrid designs, the last one using dual-chamfer technology, were brought into this application to reduce cost-per-meter through better drilling efficiency and ROP. Each successive design managed to exceed customer expectations.Extensive laboratory tests were conducted on the hybrid designs to address the demanding needs of pre-salt applications. These unique bits showed promising results on atmospheric surface rig tests and in pressurized bottomhole simulator testing. Hybrid bits produced much less torque, with smoother torque fluctuations and faster ROPs than roller-cone and PDC bits through the simulated interbedded formations in laboratory testing. Novel dual-chamfer cutters used in the bit have been lab tested on a vertical turret lathe (VTL), a visual pressurized single-point-cutter (VSPC) test machine and a monotonic loading test. Cutter testing showed positive VTL results and increased resistance to diamond fractures.Ultra-deepwater drilling is very demanding and expensive, so operators want to achieve total depth in just one run by avoiding trips to change out the bit or bottomhole assembly (BHA). The improved bit and cutter technology resulted in significant cost savings and confidence for the customer. The performance of the hybrid bit with dual-chamfer cutters was significantly better than offsets, saving the operator approximately USD 9769/m.

China’s Sichuan Basin contains prolific gas fields and presents many drilling challenges due to the complex structural geology. Xujiahe is one of the most challenging formations in the basin. The interbedded and hard, abrasive nature of Xujiahe results in short intervals drilled and low rates of penetration (ROP). Polycrystalline Diamond Compact (PDC) bits have limited drilling efficiency in this formation because impact damage and abrasive wear lead to short intervals drilled and very low ROP. Seven-bladed PDC bits which replaced roller cones were once believed to be the most cost-effective solution. To expedite gas exploration, improve ROP and increase distance drilled in the Gaoshiti-Moxi block, an innovative application-specific engineering drill bit was required. To identify the solution, a cross-functional team from the drilling contractor and the service company conducted extensive technical research into drilling practices. Sophisticated software was used to analyze the rock properties, and to identify the formation drilling problems. Reviews of offset drill bits provided clues to drilling challenges. After a series of technical analyses, an application-specific hybrid bit was designed and tested in this block. Continuous optimization of drilling parameters is implemented by field engineer. The first three trials drilled through this formation, saving two PDC bits and two trips over a 500-meter interval. Post-run review and analysis of the first trials was conducted for further improvement of ROP and interval drilling using drilling parameter and bottomhole assembly (BHA) optimization. One fast run with an average of 45% better ROP was achieved on following runs. This saved seven drilling days and 2.5 runs; an average savings of 180,000USD per well. This paper describes the collaborative solution and detailed technical optimization of hybrid bit performance in Gaoshiti-Moxi Block. Based on the drilling data, economic analysis of this project is also presented. With this cross-functional team’s effort, how this success model may apply on other drilling projects will be also included.

The oil and gas industry has experienced multiple market surges and declines over the past decades. The latest downturn further assures the industry's nature of ‘change.’ Technology plays a key role in the management of change, allowing operators to maximize Return on Investment (ROI) through Cost per Foot (CPF) minimization. The adaptive drill bit was introduced to meet a major drilling operator's increasing demand for enhanced drilling efficiency and Non Productive Time (NPT) reduction. The ‘adaptive drill bit’ embodies a hydro-mechanical apparatus and is entirely autonomous, requiring no input from surface as the system takes action to adapt downhole. Prior to the introduction of this exclusive technology, drill bits have been static devices, incapable of altering their characteristics in response to changes in formation or downhole loading conditions. The smart feature mitigates drilling vibration and hence improves drilling efficiency. In the subject application, the 12.25-in. intermediate curved section is formed of challenging interbedded lithology [20-30K UCS], known to induce high drilling vibration levels. The high drilling vibrations typically jeopardize tools/rig components reliability and reduce drilling energy efficiency, leading to delayed section delivery and NPT. A diverse international team was appointed to develop an optimized solution for this market opportunity. The team introduced the adaptive drill bit and a premium technology Rotary Steerable System (RSS) combined solution to overcome the high torsional vibrations challenge and improve drilling energy efficiency. In Kuwait, the first field deployment of the optimized solution reduced vibration levels by 33% and raised Rate of Penetration (ROP) by 42% from average field performance. The adaptive drill bit and RSS drilled at an average ROP of 44.3 ft/hr through approximately 2,500 feet building from 0 to 35 degrees at minimal steer force, offering 14% ROP leverage from competitor's best. The section was safely delivered one day earlier than offsets with zero NPT. Furthermore, the operator has requested for the technology utilization in three new drilling applications.