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.
As the demand for natural gas continuously increases to meet electricity production needs, more alternative natural gas sources are usually required to cope with the increased demand in the summer months. In South Iraq, this situation is the main driver for exploiting economically feasible and efficient solutions in finding additional natural gas resources. As a result, the Iraqi government embraces the challenge by drilling deeper formations which are gas bearing, with limited experience in such fields. In the most recent appraisal campaign for these gas fields, performed in 2015 and 2016, one of the main challenges were bits and bottom hole assembly (BHA) failures while drilling through different interbedded and abrasive formations. Changing the bits type, BHA centralization, drive system and drilling parameters did not result in significant benefits. For the 17 ½" section, up to six (6) independent runs were required to successfully drill the entire section. The success was limited due to severe shocks and vibrations, high axial forces and high torque that caused failures on downhole mud motors and bits, leading to fishing operation and severe non-productive time. Other problems like unstable drilling parameters, extremely low rate of penetration (ROP) and poor wellbore quality were observed, leading to excessive reaming and backreaming as well as stuck pipe events and difficulties to maintain well verticality. To avoid and minimize the impact of these challenges, a comprehensive engineering team performed various finite element analysis on the interaction between BHA, drilling bit and formations drilled. The conditions on which the wellbore was maintained in the offset wells with its drilling fluids strategy and drilling parameters were reanalyzed. The bits selections were revised, identifying areas of opportunity to introduce fit for purpose technologies on cutters and bits profile. The ultimate challenge was to drill the full 1800 m of the section in one run avoiding any BHA related failure. The results exceeded expectations in the fourth well, where no BHA related failures were observed, and the drilling bit was able to drill the full 1800 m. Connection practices were also optimized. This enabled an improvement in the wellbore quality based on caliper logs. Improved wellbore conditions allowed a smooth casing run and consecutive cement job. This paper will discuss the engineering methodology followed to achieve this important milestone in one of the few gas fields in Iraq. It will go through the details of the technologies implemented on BHA analysis, bit selection, drilling parameters optimization and drilling fluids strategy implemented. The objective of this paper is to share with the oil and gas industry a methodical approach for efficient drilling, and how to address drilling challenges with technology introduction and engineering design.
Downhole tool failures induced by drill string vibrations was one of the leading causes of non-productive time in a deep exploratory field in southern Iraq. To improve drilling efficiency, it was paramount to understand the primary source of potential drilling dysfunction before commencing field development phase. To overcome the challenge, a finite element analysis (FEA) study was developed to simulate the drillstring transient dynamic behavior from bit back to surface. The model has been utilized to quantify the potential vibration, contact force, torque, displacement and other high-interest parameters of every drillstring component in the wellbore. To fully exploit the modeling algorithms, it is required to input a comprehensive dataset including mechanical rock properties, cutting structure design, bit drive mechanism, drillstring physical characteristics, 3D well profile and expected drilling parameters. Using offset well data, surface and downhole measurements, and a thorough knowledge of drilling equipment, the model creates a virtual drilling environment simulating the downhole drilling conditions enabling the evaluation of the source of inefficiency. Finally, the model is validated for its accuracy by comparing its outcomes with actual field acquired data. By accurately modeling the drillsting interaction with the drilling environment, the operating company was able to evaluate different BHA options to safely drill the wells and by reducing harmful vibrations, minimizing tool failures, increasing ROP, this translates to a reduction of drilling time by 24%. This paper will share with the industry a case study demonstrating the value of the utilization of the advanced dynamic modeling which has been able to save over 500 K$ per well to the operating company by an efficient selection and placement of drill string components. This approach has enabled to outperform past drilling performance and has become the norm in similar fields in southern Iraq.
Drilling highly intercalated formations with Polycrystalline Diamond Compact (PDC) bits has been a challenge in few Southern Iraqi Fields. The established drilling practice for the 17.5-in section has been a two-run strategy - Top section formation is mostly dolomite intercalated with anhydrite drilled with a Tungsten Carbide Insert (TCI) bit, then trip out of hole to change to a PDC bit and drill to section TD. The upper section comprises highly intercalated formations known to induce severe bit and BHA damage. The application of new Conical Diamond Elements (CDEs) backing up traditional PDC cutters on the bit blades had significantly improved bit durability in the bottom half of the section. The subsequent challenge was to apply this CDE technology onto an optimized PDC chassis and achieve a single run section thus eliminating a trip for bit change as well as improving overall Rate of Penetration (ROP) of the section. A Bit and drill string optimization exercise was initiated by the Technology Integration Center to develop a new PDC bit design that could deliver a shoe-to-shoe section. Analysis of offset well data highlighted the need for greater cutter redundancy on the bit to survive high impact loading and optimized cutter arrangement to minimize bit induced instability while drilling through intercalations with highly fluctuating rock strengths. A finite element analysis (FEA)-based modelling system was used to evaluate the dynamic behavior of multiple bit design configurations in various rock scenarios and narrow down to the optimum design for the challenge. The optimization exercise shortlisted a PDC bit design characterized by 8 Blades, 16-mm PDC cutters and CDEs backing-up the nose and shoulder PDC cutting structure. A detailed drilling parameter road map was also generated to ensure optimum drilling parameter application for shoe-to-shoe assurance. The new bit drilled the entire section in single run with a field record average on-bottom ROP of 20 m/hr which was a 11% improvement over the best offset performance with a two-bit strategy. In addition, a trip for bit change was eliminated. A minimum saving of 20 rig hours was realized thus reducing section time by almost one day compared to the offset wells. The bit was pulled out of hole with minor cutter damage indicative of efficient drilling dynamics and opportunities for further performance enhancement through improved parameter management, alternate drive systems and high torque drill pipes. This paper further will discuss how the technology integration and precise engineering design can solve complicated on bottom drilling problems and address the problematic challenges of drilling highly intercalated formations. This strategy enabled a significant time and cost saving compared to drilling the section conventionally.
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