The Managed Pressure Drilling (MPD) technology had been widely utilized when there is a narrow PP-FG window. This paper summarizes the fact that it's all about MPD awareness and increased knowledge of the system that will mitigate not only the drilling hazards but shall also aid in improving the overall efficiency in drilling operations, saving both cost and time. MPD primarily helps operators drilling through narrow pore pressure - fracture gradient windows, thus minimizing the hazards of well control complications like high pressure influxes or mud losses and the same time mitigating the differential stuck tendency due to the extra over balance. Both of these are prime MPD applications where a corrective approach is utilized when the well has encountered influx or losses situation and all conventional options are exhausted. It has been seen that mostly these two aspects are the driving factors to select the well candidates for MPD during planning phase. Although, without any doubt these are major decisive factors for any well to be an MPD candidate, there are a lot of other factors that add value to the overall drilling process when using MPD technology. These factors include: i)- Precise Drilling window determination, prior to start drilling ii)-Using lighter mud weight iii)- Early kick-loss detection system iv)- Improved well control, v)- Handling mud cut without interrupting drilling, vi)- Improved Bore hole stability and ballooning, vii)- Higher pump-rates, viii)- Efficient Tripping in or out of well ix)- Liner trip and cementing, x)- Added safety factor This paper summarizes the stats of all these value added benefits in a 26 well campaign field. This case study highlights unsung attributes of MPD that adds value to the overall drilling process, clearly aiding in mitigating several hazards that would lead to the complicated well control situations resulting in significant non productive time, NPT and well abandonments. MPD had been used in the region to avoid drilling hazards, but we believed it offered more benefits. We analyzed a bunch of wells and found out that there was definite improvement in the drilling efficiency. The case study includes 26 wells in a challenging formation bearing unpredictable and inconsistent high pressures and 10 gas bearing extended horizontal wells with hard target formations. This publication summarizes all MPD attributes with statistical information that contributed to the success of the operations. Emphasis is on highlighting the factors which are usually taken for granted along with MPD main objectives. These benefits are highlighted for future pre-operational planning of well feasibility studies to improve the overall operational efficiency and the possibility of MPD applications other than just narrow window navigation. Managed pressure drilling optimizes the complete drilling and post drilling process and mitigates drilling hazards. It allows timesaving, reduction of mud costs and drilling un-drillable wells while optimizing overall process. Experience while drilling through the campaign field has proven that using MPD helps to optimize the drilling process and reduce associated costs to well control, lost circulation, stuck pipe and ballooning events. The paper implies that considering all these unsung attributes of MPD, each well should be evaluated for MPD technology during the planning phase to minimize the aforementioned drilling hazards than applying corrective actions. Mud weight, BHA design, drilling parameters and casing design can also be tailored accordingly to suit MPD operations, and enhancing overall drilling and completion processes. The paper emphasizes that MPD has been considered in the planning phase due to the narrow PP-FG window criteria, but there is a lot more added value that directly improve the overall drilling efficiency.
An inventive application for Roller Cone (TCI) and Polycrystalline Diamond Compact (PDC) bits (all sizes) that involves reusing the bits in future wells for similar well design types. With factory drilling being carried out in one of the Gas field (among other areas in gas) with over 50 runs a year provides an excellent opportunity to utilize rerun bits, both TCI and PDC, that have a 90-95% life remaining. Using this approach provides an effective and efficient way of cost saving during drilling. While the cost of new bits in the country is very high compared to markets outside, mainly due to logistics issues with recent and continuous enhancements in bit designs, it makes complete sense to reuse these bits; especially when a huge inventory is available due to so many rigs drilling the similar type well designs in one or similar gas fields. The main criterion is to keep a track of all sizes of bits used on all gas rigs in the area and in the tool house (warehouse). Often, a particular size bit, either TCI or PDC, is used to drill a very short interval in a particular section due to a technical reason for the bit in the well being pulled out of hole, and is almost in brand new condition. Having an up-to-date inventory of these bits from the gas rigs, the tool house, and bit vendors makes it easy to identify such bits and utilize them in new wells, which provides significant cost savings. Using the rerun bit approach immediately takes the bit cost for that particular hole section to 0$ and so we can achieve additional drilling optimization by utilizing a mud motor in that section, i.e., 12-in., 8-3/8 in., or 5-7/8 in., and further increasing the rate of penetration (ROP) by maintaining the same cost/ft ($/ft) in the section and even breaking bit record runs. In the last few wells it has been evident that by using this approach, the cost/ft for the 12-in. section drilling in the Gas Field field is seen as low as 52% of the new bit for the same year; providing a benchmark for the field. This would not have been possible without utilizing the rerun bits from previous wells. This approach is proving to be very beneficial. As a result of a number of these TCI and PDC bits available in reusable condition as a result of a large number of wells drilled every year in gas fields, significant cost savings have been achieved, which translates into millions of dollars in savings. The rerun bits have substantial advantages over the new bits, primarily due to cost savings and enhanced bit designs with high durability and bit life over the last decade. For particular application in gas drilling, it is clear that having a large inventory of rerun bits available for almost all hole sizes will enable drilling cost optimization.
Most recently, the oil industry has focused on drilling dynamics management as a critical process to maximize drilling system energy for an optimum rate of penetration (ROP). The goal is to maintain the physical integrity of the drill string avoiding nonproductive time associated with twistoff events. The process becomes more complex while drilling in total mud loss scenarios which is called blind drilling. The downhole drilling dynamic in total mud losses is quite complex because of the constant fluctuation of the wellbore buoyancy factor, which gives the string an extra induced drilling motion, plus the lack of fluid support above the dynamic fluid level. This harsh drilling environment becomes tougher while drilling the tophole section because of the high clearance between the tubular and the borehole. The clearance gives extra room to the string to experience a high level of shock and vibration, which negatively affects the drilling performance, the physical integrity of the drillstring, and can lead to twistoff events. To overcome this challenging scenario, a complete suite of real-time high-frequency drilling dynamic data tool was added to the drillstring. The addition of this tool increased the understanding of the primary sources of fatigue encountered while drilling the tophole section. Taking into consideration the total mud losses, it was important to determine the predominant drilling motions and level of vibration. To make this determination, it was necessary to perform a drilling dynamic modeling for optimum bottom hole assembly (BHA) design, considering available tubulars, and defining drilling parameter guideline with the mechanical specific energy (MSE) footprint for proper shock/vibration prevention and mitigation. During the downhole data capture stage, it became apparent the magnitude of the harsh drilling condition experienced while drilling could not be identified using surface parameters. However, the MSE can alert when harsh drilling conditions are present because of the energy loss observed. Additionally, the following drilling motions and level of vibrations were identified: BHA chaotic whirl, high torsional and lateral vibration, lateral and torsional vibration directly proportional to surface revolutions per minute (RPM), and whirl severity affected by surface parameters and proximity to the loss zone within a 900 ft from the bit area of influence. To reduce the risk of BHA whirl and high-level vibration, the BHA stiffness ratio was improved incorporating 6 5/8-in heavy-weight drill pipe and standardizing the BHA stabilization, reinforcing with a drilling parameters road map and MSE footprint for shock/vibration prevention and mitigation. This new engineering approach using high-frequency drilling dynamic data reduces the number of twistoff events per year by 67%. This reduces the average from 15 to five events annually with no compliance issues found based on the recommended guidelines for those events. As a result, the number of twistsoff events per 100 runs was reduced by 59%, demonstrating the potential to completely eradicate twistoff events on tophole section.
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