Cherty formations are notoriously challenging for fixed cutter drill bits and present a costly challenge for operators who routinely experience short intervals and numerous trips. The predominant limitation is short bit life due to mechanical failure of the cutters. This paper details how an inter-company collaboration led to the development of a design philosophy and a novel shaped cutter technology that resulted in a step change in drilling efficiency and drilling consistency in chert formations. A collaboration between companies was initiated that commenced with a comprehensive study into the cutter-rock interaction to identify the failure mechanism of chert. The results of the research were then used to determine the critical design levers required to overcome these challenges, extended bit life and maximize drilling efficiency. Two fixed cutter drill bits in the 6-in. and 8.5-in. hole sizes that incorporated the new design philosophy and shaped cutter technology were designed. These bits were then field tested in the Egypt Gulf of Suez interbedded carbonates application characterized with the presence of dark brown chert. The new 6-in. and 8.5-in. designs were tested twelve times across four different fields. The runs were then evaluated against durability, rate of penetration (ROP) and cost per foot (CPF) compared to field offsets. In the 6 in. section, the new design drilled the entire section of 3,369-ft that includes 381-ft cherty formation with one bit compared to three bits previously required to drill the same interval. For the same offsets, an improvement of between 50-85% in ROP was achieved. The CPF assessment demonstrated drilling cost reduction between 24-75% across the fields tested. In the 8½ in. section, the new design drilled the entire section of 6,141 ft that includes 296-ft cherty formation with one bit compared to four bits previously required to drill the same interval. ROP wise, an improvement between 59-178% was achieved which corresponded to a CPF reduction of between 41-69% across the fields tested. These field tests demonstrate ground-breaking results in the durability, ROP and CPF performance metrics measured. Furthermore, the number of runs and diverse nature of the fields tested demonstrate the consistency of this new approach to drill cherty formations with full directional control and mitigating downhole vibration severity. A re-examination of the failure mechanism of chert drilling and the root cause behind drilling deficiencies in cherty applications conducted in a collaborative environment has paved the way for a step change in drilling performance. Novel design philosophies were created, laboratory tested, and field validated for consistency of the trials. As the drilling industry continues to explore unchartered applications to ensures cost efficient solutions is paramount to success

As shaped polycrystalline diamond compact (PDC) cutter geometries become more prevalent across the industry, this paper statistically reviews field testing of novel shaped PDC cutters in a variety of challenging applications. Firstly, the paper identifies the improvement in efficiency when compared with conventional PDC cutter geometries. Secondly, it confirms the reliability and robustness of the aforementioned shaped cutter geometries. After several years of field testing shaped PDC cutter geometries, the question of how they hold up against conventional cylinder-shaped cutters remains unanswered. This study looks at drill bits that have the same overall design; however, each bit has different shape configurations that are deployed in a range of hole sizes and drilling applications. Data was collected from more than 100 runs and included advanced dull evaluation techniques, data mining, and comparative analyses. During data collation and interpretation, several statistical methods were used to improve the accuracy of comparisons and observing trends. These results are statistically profound, they show that in the majority of cases, shaped cutter geometries enhance drilling efficiency either in line or beyond laboratory testing. For a comparable parameter envelop, an improvement of between 20-40% in rate of penetration (ROP) was observed in various hole sizes, particularly in carbonates through Arabian Gulf reservoir formations. The reliability assessment, which speaks to the number of runs per serial number, has shown an improvement over conventional type cutters and in some cases reaching six re-runs. Cutter robustness was deduced by comparing the average interval drilled, while also reviewing the overall dull in context to the typical dull condition. When considering all three metrics over the large data set, it can be concluded that shaped cutters have, at a minimum, equivalency in both robustness and reliability, but, more importantly, bring an efficiency advantage over their legacy generation of PDC cutters. When considering the deployment of shaped cutter technology, the study has highlighted a significant flexibility in vertical, directional, and extended lateral applications from hard and abrasive rock to highly interbedded formations. Overall, shaped cutter efficiency and robustness have been validated in the laboratory and now proven to bring greater change in drilling performance and reliability. This paper pushes beyond the claims within laboratory testing and statistically proves the robustness, reliability, and efficiency of shaped cutter geometries within the drill bit market. Not only is their usage growth now statistically proven, but a methodology has been developed to comparatively assess this technology during field testing. As PDC shaped cutter technology continues to grow, it is important to define its limitation along with determining where to deploy its strengths to obtain peak drilling performance.

Wellbore conditioning has become prominent in recent years as operators strive to reduce flat time costs. This paper examines how an eccentric wellbore conditioning tool (WCT) improves drilling performance and reduces flat time in challenging sections. Torque and drag are common challenges in extended laterals, with micro-doglegs and ledges being major culprits, especially in hard carbonate formations. The performance of the WCT is benchmarked in terms of flat time components: trip speed, system torque, rate of penetration (ROP), casing operations, and on-bottom performance. The paper also scrutinizes the allowable parameter envelope for wells drilled with and without the WCT. Laboratory testing was conducted to observe the behavior and effects of the eccentric WCT when confronted by the major wellbore conditioning challenges. Following these initial laboratory tests, a proprietary software program was created to determine the WCT's ideal bottom hole assembly (BHA) placement for field trials. Several field trials were conducted to validate the placement software's accuracy as well as the key benefits achieved by the WCT. Development testing has proven that the WCT's capabilities reliably improve wellbore quality and reduce overall torque and drag. Also, a proprietary software program confirmed the most effective WCT placement. Overall, there was a net flat time reduction and a marked improvement in ROP—up to 35% when directly compared with and without the WCT. Reduced system torque and less stress on downhole tools enable a wider and, more importantly, higher drilling parameter window. A new generation of eccentric WCTs has been introduced to solve a legacy drilling pain. Poor wellbore conditioning contributes to significant flat time costs for operators worldwide. A proven, effective solution has been long overdue; however, the WCT has shown to be a cost-effective tool, improving flat time and drilling performance. The benchmarking and exploration of drilling performance and reduced flat time provided by wellbore conditioning tools will allow others to exploit lessons learned and recapture drilling efficiency.

As oil and gas wells become deeper, drilling longer intervals is becoming a major milestone for drill bit companies, as the process comes with a variety of challenges affecting the durability of drill bits. Among the major challenges are thermal and impact damage in polycrystalline diamond compact (PDC) cutters, which can significantly affect the performance and longevity of a drill bit. While cutter technology development remains an important arena to address said challenges, there exists a need to also address these through the design process. This paper presents the development and deployment of a new drill bit analysis method that addresses thermal damage by optimizing the design, which has been field validated across the globe. The analysis involves estimating the thermal input load and the available cooling rate for every cutter on a drill bit during drilling conditions. The data is then used to optimize and apply changes to the design. The analysis considers all the critical and relevant operational parameters to calculate these indices. The outcome of the so-called thermal index analysis enables the design team to make informed decisions to improve the design of the drill bit and to minimize the extent of thermal damage in cutters. The improvements made in the design include changes in cutting structure to affect cutting forces and, eventually, the thermal input load during the drilling process. This stage in practice can bring down the temperature of the cutting edge by 20%, as calculated analytically. Another major change that can affect the results is hydraulic design of the bit, which includes the location of the nozzles as well as their orientation and size. In test cases, the cooling rate improved by 50% while keeping the same flow rate though the bit. Several field trials have validated the correlation of thermal index analysis to drill bit dulls. This analysis is now in the field evaluation and testing phase, where it is being used during the design process to improve bits with thermal damage. The field-testing phase has been primarily conducted in thermally challenging applications across the Middle East, North Africa region, and in West Texas.

The essence of reservoir simulation is to forecast field performance, ultimate recovery and to evaluate the effects of different operational conditions on recovery while keeping the economics of each scenario in view. It is important to note that in simulation one of the characteristics of a history match is that the outcome is a non-unique solution and it is influenced by many factors including porosity, permeability, thickness, saturation, PVT, relative permeability etc. A combination of these parameters result in a match and is not unique to that reservoir, thus this may not perfectly represent the condition of that reservoir. A common area of struggle is the transition of a model from pre-production vintage to a history matched solution where the only additional data available is production without having to build the model from scratch. It is therefore important to have a rule of thumb to validate the robustness of a simulation pre-production forecast prior to the onset of production. The effect of this may result in a pessimistic or overly optimistic model which translates to a non-representative reserves addition. The Fotis reservoir has been used as a case study to highlight the importance of a robust pre-production forecast prior to the onset of production and history match. Fotis is a NAG reservoir with a fault assisted dip closure trap. The reservoir sand is interpreted to be deposited in a shallow marine setting (consisting of shoreface and channels deposits). Reservoir properties are good (Avg Por. 17%; perm ~700 mD). Base case In-Place volume is about half a Tscf. Some 27% of the inplace volumes have so far been produced. The reservoir simulation model went live in 2010 without a history match because there was no production and pressure data. Production commenced in 2011. Well and Reservoir Management Philosophy for the reservoir was to produce the well at 100MMscf/d thus this was captured in the model though model forecast plateau seemed conservative for the low case model. The model was history matched in 2015 post the acquisition of pressure data. Inability to achieve history match within acceptable limits on the low case, even as the current well production rate of 100MMscf/d was sustained confirm the conservative nature of the low case model. This paper analyzes and highlights pitfalls to be avoided in the pre-production models and how multi-disciplinary solutions could drive a more representative output that supports robust life cycle predictions from the model.