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Interbedded formations are challenging to drill due to its potential to trigger torsional instability issues while drilling at low depth-of-cut (DOC), which could damage the bit due to impact and result in low penetration rate or an undesired trip. Wells drilled in the Guyana-Suriname Basin face a similar challenge as the wells penetrate interbedded shale and carbonates, causing conventional polycrystalline diamond compact (PDC) bits to lose their cutting efficiency due to impact damage while drilling the hard, interbedded formation.
Using a detailed bench-marking methodology, offset drilling data was analyzed and the results were utilized to optimize bit design to meet these challenges. Mechanical specific energy (MSE), which quantifies drilling efficiency, indicates formation changes and signals the advanced dull condition or damage. When coupled with dull bit forensics, MSE provides insight for iterative bit design optimization to mitigate drilling challenges.
The outcome of a detailed benchmarking process led to the selection and deployment of a 12¼-in. hybrid bit to drill directionally through interbedded formation, which significantly improved drilling performance and bit durability. The hybrid bit combined PDC and tungsten carbide insert (TCI) rolling cutting elements and delivered balanced aggressiveness to improve torisonal stability. Post-well analysis showed rolling DOC control offered by the hybrid bit delivered higher penetration rate. The comparison of the drilling mechanics of the hybrid versus PDC highlighted limited drilling efficiency of PDC bits in interbedded formation. The hybrid bit drilled 54% more carbonates than the best PDC offset run. Drilling dynamics data also highlighted lower levels of vibrations with the hybrid bit. In addition, the hybrid dull condition was better than the PDC bits, suggesting improved durability compared to the previously-used PDC bits.
This paper demonstrates time and depth based surface and downhole drilling data, when supplemented with rock strength analysis using a suitable benchmarking process, can provide insight about drilling mechanics. When matched with an application specific bit, it leads to sustained drilling performance improvement.
Summary In this paper, we provide some new insights into stick/slip vibration in drilling with polycrystalline diamond compact (PDC) bits. Fiftysix field runs under various drilling conditions were collected with the help of on-bit vibration sensors. Two types of stick/slip vibrations were identified: cutting-action-induced stick/slip and friction-induced stick/slip. Methods were developed to determine whether a stick/slip occurrence is induced by cutting action or by friction. Statistical analysis found that bit drilling efficiency (DE) is well correlated with the occurrence of cutting-action-induced bit stick/slip vibration. If a PDC bit is designed so that its DE is greater than a critical value, then the cutting-action-induced bit stick/slip vibration is not expected in drilling. Introduction Stick/slip vibration in drilling is one of the primary causes of cutter damage of PDC bits and early failures of downhole tools (Ledgerwood et al. 2013). Early efforts to address this issue were to measure downhole stick/slip by instrumenting vibration sensors near the PDC bits (Lamine et al. 1998) and near the roller cone bits (Chen et al. 2002). After the occurrence of stick/slip vibration in drilling is confirmed, efforts have been focused on understanding the root cause of stick/slip vibration of a PDC bit and the mitigation of stick/slip vibration during drilling. To better understand the root cause of stick/slip vibration of a PDC bit, three assumptions have been developed in the past three decades.
This paper provides some new insights into stick-slip vibration in drilling with polycrystalline diamond compact (PDC) bits. Fifty-six field runs under various drilling conditions were collected with the help of onbit vibration sensors. Stick-slip vibration occurrence during drilling was analyzed. Two types of stick-slip vibrations were identified: cutting action-induced stick-slip and friction-induced stick-slip. Methods were developed to determine whether a stick-slip occurrence is induced by cutting action or by friction. Statistical analysis found that bit drilling efficiency is well correlated with the occurrence of cutting action-induced bit stick-slip vibration. If a PDC bit is designed so that its drilling efficiency is greater than a critical value, then the cutting action-induced bit stick-slip vibration is not expected in drilling. Increasing the aggressiveness of the cutting structure of a PDC bit within a limited critical depth of cut is found to be helpful to mitigate bit stick-slip vibration.
Regardless of how good a new product or method may be to a drilling operation, the result is always measured in terms of cost per foot or meter. Lowest cost per foot indicates to drilling engineers and supervisors which products to use most advantageously in each situation. Reduced costs lead directly to higher profits or the difference between profit and loss. For those in administration, engineering, manufacturing, and sales, cost calculations are used to evaluate the effectiveness of any product or method, new or old. Because drilling costs are so important, everyone involved should know how to make a few simple cost calculations.
Developing reserves offshore East Malaysia, especially in deep water, often requires the operator to drill -through formations that consists of compact carbonate with high unconfined compressive strength (UCS). Efficiently penetrating these carbonate formations with conventional PDC bits has been challenging; typically, when a bit encounters this formation, a high vibration level is induced that leads to impact cutter damage, forcing a round trip for a new bit and causing nonproductive time (NPT) and additional cost for a new bit. Consequently, the cost impact is more severe to the operator, especially in deep water environments.
Traditionally, an operator has used four- and five-bladed PDC bits to drill this formation because this configuration had set a benchmark in this field compared with roller cone bits. However, a recent engineering analysis on a recently drilled offset well showed that a minimum of two PDC bits are required to reach the section total depth (TD). On the first run, the bit was pulled out of hole (POOH) due to slow ROP 6.2 m/h) and received a poor dull grade (6-7-HC-ROP). Although the second PDC bit produced slightly higher ROP compared with the first bit, it was POOH with broken cutters.
A research initiative was launched to investigate new types of cutting elements. The project was successful and yielded an innovative conical-shaped polycrystalline diamond element (CDE). This element has twice the diamond thickness of conventional PDC cutters, resulting in higher impact strength and more resistance toward abrasive wear by approximately 25%. A new bit type was designed with the CDEs strategically placed across the bit face from gauge to the bit center utilizing FEA-based modeling system. The placement of CDEs is mainly to support and protect the conventional PDC cutters from impact damage and to strengthen the overall cutting structure.
The 8½-in CDE bit was run and drilled the entire 8½-in hole section through the hard carbonate formation to TD at a significantly higher ROP compared with the offset well. Although the CDE bit was POOH due to downhole tool failure and graded 1-2-BT-DTF, the same bit was rerun and successfully completed the hole section in good condition and dull graded as 1-3-BT-TD. Compared with the offset well that required two conventional PDCs to reach TD, the CDE bit delivered more drilled interval at a higher ROP while providing a smooth, high-quality wellbore, enabling casing to be set on the first attempt. Also, the dynamic response predicted by the modeling system matched the bit, BHA, and drill string vibration profile recorded during the actual field run. Improvement in drilling performance for this run has saved the operator 15 hours for the same drilling interval.
Boussahaba, Hocine (Halliburton) | Sugumar, Jayaram (Halliburton) | Vrnak, Kyle (Halliburton) | Benyoucef, Lyes (Halliburton) | Fadtare, Ashish (Kuwait Oil Company) | Al-Shammari, Altaf (Kuwait Oil Company) | Al-Failakawi, Khaled (Kuwait Oil Company) | Dutta, Abhjeet (Kuwait Oil Company) | Al-Khaldy, Meshal (Kuwait Oil Company)
Drilling the section is a major challenge because the long interval consists of nonuniform lithology with variations in compressive strengths, and it contains an abrasive ultrahard sandstone, a compact hard shale with a low rate of penetration (ROP) performance, and carbonates with shale, oolite, and sand traces. The interval is commonly drilled using either two or three new PDC bits, and extra trips are expected. Efforts were made to substitute the numerous PDC bit runs with one customized and reliable design that can overcome formation hardness and variations in compressive strength and maintain the same ROP to total depth (TD) with limited success, even though the idea of backup cutters has existed for decades. A new, durable PDC design was implemented with the objective of helping improve the ROPs across all intervals. The innovative backup cutter placement design and minimal critical depth of cut for each primary and backup cutter in the same radial position are the most desirable solutions. The new and innovative PDC cutters' distribution structure using the new bit design software coupled with an innovative backup cutter placement minimized the calculated bit wear and maintained the cutters' sharpness along the entire section without needing an extra trip or a new second bit, which produced the best performance achieved in the northwestern Kuwait fields. The new bit design achieved the longest footage drilled in Kuwait for a single bit of 9 1/4-in.
Centeno, Manuel (Schlumberger) | Krikor, Ara (Schlumberger) | Herrera, Delimar Cristobal (Schlumberger) | Sanderson, Martin (Schlumberger) | Carasco, Anant (Schlumberger) | Dundin, Alexander (Schlumberger) | Salaheldin, Ahmed (Schlumberger) | Jokhi, Ayomarz (Schlumberger) | Ibrahim, Sameh (Schlumberger) | Wehaidah, Talal (Kuwait Oil Company)
The complexity of drilling highly deviated wells in Kuwait drives the need for step changing in the well construction mindset, where severe to complete loss of circulation in Shuaiba formation significantly deteriorate the shale layers in Wara and Burgan formations leading to uncontrolled wellbore stability events. Casing while drilling (CWD) and two-stage cementing with a light density cement slurry were introduced as a technology system to drill the highly deviated complex wells through unstable and highly fractured formations. Fit for purpose engineering processes, advanced software solutions, a tailored bit and a bottom hole assembly dynamically simulated for drilling stability and directional tendency behavior were designed. A special light density cement slurry with high compressive strength was also designed to tackle the lost circulation issues when cementing the casing string. The paper will describe how the technologies can work as one system to solve complicated wellbore problems and address the problematic challenges of drilling unstable shales and fractured formations in the same section of the wellbore. This strategy enabled a significant time saving compared to drilling the section conventionally, removing Non-Productive Time (NPT) resulting from additional trips, cement plugs, stuck pipe, and subsequent sidetracks.
Finding a safe and efficient approach to drilling in challenging applications is a difficult task for drillers because each field is unique. The industry's common ambition is to use various technologies to increase the mechanical penetration rate and reduce overall drilling time. Most recent studies show that drilling bits play an important role in drilling optimization and help to overcome most of the challenges connected with the rock destruction process and tool lifecycle.
In recent years, 3D PDC cutters such as ridge diamond elements (RDE), rolling PDC cutters (RC), and conical diamond elements (CDE) have helped to further improve the drilling efficiency in a majority of applications worldwide.
The PDC bit brazed with unique 3D cutters moved the industry set benchmark performance standards to the next level by improving cutter durability and efficiency in drilling. These cutters, depending on the shape, can improve ROP, durability, and can improve overall cutting efficiency.
Field tests were conducted in multiple applications with multiple customers in RCA and the authors will present several case studies that will document performance improvement in challenging drilling applications. The results clearly show that the combination of this unique 3D cutter has helped operators to bring a step change in performance by improving ROP and footage drilled. In some cases, operators were able to drill the entire section with the bits equipped with 3D cutter combinations where traditionally more than one bit was used to complete the section. Customization of 3D cutters in the appropriate location of the bit is key to this success.
Zhang, Hongying (Beijing Petroleum Machinery Co., Ltd, CNPC Engineering and Technology R&D Company) | Chen, Huihui (Beijing Petroleum Machinery Co., Ltd, CNPC) | Liu, Feng (Beijing Petroleum Machinery Co., Ltd, CNPC) | Wang, Na (Beijing Petroleum Machinery Co., Ltd, CNPC) | Huang, Yanfu (Beijing Petroleum Machinery Co., Ltd, CNPC) | Fang, Zhimeng (Beijing Petroleum Machinery Co., Ltd, CNPC) | Pan, Xingming (Beijing Petroleum Machinery Co., Ltd, CNPC)
A novel design of PDC bit with hollowed cutters is presented that uses the principle of hydraulic lubricating and water jetting mechanism to improve ROP. Engineering results show its advantage compared to solid fixed cutters which are commonly used in today’s drilling industry.
The structure of the new PDC bit is as follows: each cutter contains a specific fluid channel, which is tailor made; the bit body contains many fluid channels; Compared with the existing conventional PDC bit, the main distinctive features are: the cutters are hollowed, each cutter contains a fluid channel in the centre of itself; and the bit body has fluid passages which are communicating with each hollowed cutter, allowing the drilling fluid flows from the inside of the bit to the outside of each cutter.
The failures of a PDC bit are mostly due to premature wear or cracks of compound cutters; the wear or cracks are due to mechanical and thermal effects. To improve the service life of cutters can effectively increase the life of the drill bit. According to thermal stress analysis, the position where the frictional heat concentrated is in the centre of the cutter, which will result in the generation and expansion of thermal cracks, which in turn leads to failure of the cutter and loss of ROP. Therefore, the cutter with fluid passage will improve the way of thermal concentration and expansion, thereby prolonging the life of the drill bit, reducing the number of trips, improving single run drilling footage, therefore the drilling efficiency is increased. During the drilling operation, the rock cuttings cannot flow out timely, and may accumulate on the drill bit, which is commonly referred to as mud balling. The presence of mud balling will reduce the cutting capability of the drill bit and decrease the ROP. The new PDC bit with hollowed cutters has self-cooling and self-cleaning functions to mitigate the thermal effect, while the pressurized flow from the micro-hole of the cutter has the effect of water jetting, which in turn increases the ROP.
The novelty of the new PDC bit is in the capability to solve the issues of low ROP and short service life of today’s tough drilling conditions, to meet the requirement of a single trip to complete the total depth.
A new Protocol ("DMX") is presented for 3d DFFN (Discrete Fault and Fracture Network) modelling, a numerical code developed over the last 20 years in order to converge towards a more realistic Discontinuity (fault and fracture) Network representation in space. The protocol introduces the following new features: Fracture interaction, truncation, termination and cross cutting in 3d space based on newly designed collision algorithms and fracture propagation principles; Modelling at any scale range of unlimited basic 3d fracture shapes, specific 3d fracture morphology, and 3d fracture aperture types; A complete integration between classical geological/geomechanical drivers such as stress ellipse, fault zones with 3d slip vectors, and different fold models (axial plane, fold axis and bedding orientation conditioning), geological assembly modelling such as joint spacing and set dependency, offset/faulting, and probabilistic conditioning of any of the parameters and drivers. Examples of the application of the protocol are presented to illustrate few of the unlimited amount of combinations that can be generated in 3d space. Furthermore, an example of the complete flow chart of a calibration to real observed cases is provided. The protocol constitutes a complete game change and opens a range of technological challenges for the future applications in Mining, Civil Engineering and Conventional and Unconventional Oil and Gas Exploration and Production.