Drilling companies are constantly evaluating ways to improve the efficiency and safety of their operations, the way the returns of the well are circulated while drilling has remained unchanged for decades, however, having a circulating system open to the atmosphere imposes a risk to the drilling crew in the rig flow. Conventional influx detection methods can easily allow the gasification of the mud column in the annulus before it is noticeable and H2S or flammable gas alarm can be triggered before any action is taken. A rotating control device (RCD) is a piece of equipment that diverts the returns of the well from the rig floor while allowing the drill pipe to be rotated and reciprocated, that means tripping and drilling operations can be performed while the well is isolated from the rig floor by the RCD. The RCD is a key component in Managed Pressure Drilling (MPD) operations as it is responsible for containing the annular surface pressure and preserving the integrity of the circulation system, hence maintaining a slight overbalance condition on the well, additionally the RCD can be deployed independently for other applications that enhance the safety and optimize the costs of the drilling operation. For this reason, efforts are made to ensure that optimum operating conditions are present to reduce the chances of system failure. Historical data detailing the performance of RCD systems, including total stripped footage, total rotating hours and failure mechanisms were used to evaluate the reliability of this technology and to set operating limits to optimize its performance. Historically there are conditions that are known to reduce the life span of RCD bearing assemblies, such as misalignment of the Blowout Preventer (BOP) stack, hard banding or bad condition of drill pipe tool joints, excessive drill pipe vibration, temperature and type of fluid out of the well, among others. Ensuring that the operating limits are observed regarding rotating speed, pressure and temperature were observed to be key to maximizing the life cycle. It was observed that the base technology over which RCDs are designed is far from recent and new additions to the current setup are needed to "smarten up" an otherwise very basic piece of equipment, this with the intention of obtain better data regarding its operating conditions and the parameters that affect its performance. New technologies in terms of elastomer compounds, seal design improvements, monitoring systems and implementation of artificial intelligence are some of the upcoming developments discussed in this document and that are to be implemented in the short and medium term in RCD operations in Kingdom of Saudi Arabia.
The field of interest involves penetrating a predominantly dolomite and dolomitic limestone formation associated with highly pressurized saltwater equivalent to as high as 157 pcf (21 ppg). The most over-pressurized zones are encountered across the ±1,000 ft. base layer of this formation where the majority of flow incidents occurs. This is further exacerbated by the extremely narrow mud window of 0.5-1.0 pcf (0.07-0.14 ppg) between the pore pressure and fracture pressure. Such conditions may lead to risky operations that include well control, high mud weight (MW) design complications, differential sticking, drillstring design limitations, liner equipment failure, poor cement job, etc. Fully automated managed pressure drilling (MPD) systems are utilized to drill the 12 in. hole section and walk the tight window across this rock. This approach allows for applying surface back-pressure (SBP) and accurately holding constant bottomhole pressure (BHP) while keeping constant MW throughout the drilling operation. This operation also witnessed the application and utilization of fully automated MPD systems as means to run and cement a 9-5/8 in. liner across this troublesome zone. Conventionally running liners in excessively high kill MW of ±155 pcf (20.72 ppg) while dealing with tight margins is particularly challenging as it yields total losses due to the surge effect. Conventional cement jobs also mandate filling the hole with high kill MW before the cementing operation, inducing losses and resulting in poor well integrity, leaking liner packer, wet casing shoe, etc. Utilizing MPD systems to run and cement the 9-5/8 in. liner allowed for multistage hole displacement, filling the hole with a lighter MW, and maintaining constant BHP throughout the entire operation regardless of any surface tool failure (pump cavitation, leaking cement head, and surface lines, etc.). This paper details the planning and design phase along with the operational sequence of running and cementing the 9-5/8 in. liner with fully automated MPD systems. A case study will be highlighted to establish lessons learned and best practices.
This document presents the successful application of pro-active Managed Pressure Drilling (MPD) to drill one section through three different sands; the one in the middle with a low fracture pressure, the lower sand with a formation pressure higher than the frac gradient of the weak formation. The wrong decision to apply MPD in a reactive way leads to NPT, influxes, mud losses and increased risks. It is shown how the conventional procedures to drill and make the trips are replaced by tailored MPD procedures leading to successful results. The Client understands the high value of proactive MPD, not only to drill but also to during trips. The drilling commenced with a MW of 1.6 g/cc and after 100 m the MW was increased to 1.62 g/cc (it is a routine procedure in the field to increase the mud density prior to reaching the expected high pressure zones while drilling conventionally). Some meters after start drilling the low frac gradient sand total mud losses were observed. The MW was reduced from 1.62 to 1.52 g/cc and MPD was implemented in a proactive manner whereby the BHP was maintained constant. The big challenge was to control the well at all times avoiding a catastrophic condition.
Managed pressure drilling (MPD) helps operators efficiently navigate through narrow pore pressure-fracture pressure windows. The challenges encountered during one onshore drilling campaign included pore pressure uncertainty, high pressure influxes, total losses and high incidences of differential sticking, which at times led to abandoning wells when drilled conventionally. The case study highlights how these challenges were counteracted with the implementation of a fully automated MPD system. MPD is a safer and more effective drilling technique, as compared to conventional drilling, especially in wells with narrow drilling windows and downhole hazards. A fully automated, early kick detection and control system that enables nearly instantaneous, precise adjustments to the bottomhole pressure adds great value to the client's operations. It has been observed that in wells with a narrow window, precise determination of downhole pressure margins (i.e. pore pressure, wellbore stability and fracture pressure) and precise control of bottomhole pressure are imperative to complete the well without well-control incidents. A fully automated MPD system helps to achieve these goals. Prior to the start of drilling with MPD, the exact formation pressure is determined by conducting pore pressure tests, and then during drilling the target bottomhole pressure can be precisely adjusted almost instantly by adjusting the surface pressure at the MPD choke. The MPD system greatly reduces the time to stabilize well conditions when encountering well control problems or downhole losses. This paper summarizes the implementation of the fully automated MPD system as a sophisticated tool to precisely control such situations instantly, saving time, associated mud costs and hence optimize the overall drilling process. This paper describes a few MPD milestones in drilling the 8 3/8-in. and 12-in. hole sections in the field despite of difficulties including total losses and high-pressure influxes leading to well control events. The primary objective of MPD application in this field was to drill to the liner landing point by adjusting the bottomhole pressure (BHP) in real-time to eliminate the problems caused by uncertainty in the over pressured target formation and minimizing or eliminating the downhole fluid losses in the lower formations. The paper describes results from two case studies. In the first case, the well was drilled with a 1 pound per cubic foot (pcf) (0.13 ppg) narrow window, with accurate detection and control of influxes while mitigating losses. In the second case, initially the bottomhole mud-losses were minimized instantly and later the well was precisely displaced under partial losses to a lighter mud to save mud costs while maintaining well control.
Formation pressure heterogeneity in a reservoir can represent a significant challenge when a high overbalance condition is created in a zone with low pore pressure; leading to total losses, and potential stuck pipe events which subsequently increase well costs and non-productive time. This paper describes a case involving high differential pressure between the heel of the reservoir, and toe of the lateral, and where drilling in an up dip direction increased the complexity of the operation. The original well design considered drilling the entire reservoir section in one 6 1/8–in. section. However, to mitigate identified operational challenges, the 7-in. liner depth was adjusted to cover the high pressure section of the reservoir, thus isolating the weaker reservoir zones at well total depth. Managed pressure drilling (MPD) was deployed to drill both sections to reduce the overall overbalance condition and to provide an additional method to determine the pore pressure. Furthermore, the 7-in. liner was run in MPD mode to minimize the chances of differential sticking; and cemented in place using Managed Pressure Cementing (MPC) technique to mitigate against inducing downhole losses during the cementing operation which would have impacted zonal isolation efficiency, and the long term well integrity leading to possible sustained casing pressures (SCP). Managed Pressure Drilling (MPD) is an adaptive drilling technique that is used to precisely assess the formation pressure and manage the bottomhole pressure accordingly. MPD allows the use of a lighter mud density to reduce the overbalance condition and by manipulating the annular surface pressure a condition of constant bottom-hole pressure can be maintained. MPD was implemented to determine the formation pressure and define the optimal mud density for the operation during drilling, and while running and cementing the liner, thus mitigating the risk of potential losses and differential stuck pipe.
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