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Copyright 2011, IADC/SPE Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition This paper was prepared for presentation at the IADC/SPE Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition held in Denver, Colorado, USA, 5-6 April 2011. This paper was selected for presentation by an IADC/SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the International Association of Drilling Contractors or the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the International Association of Drilling Contractors, or the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the International Association of Drilling Contractors or the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of IADC/SPE copyright. Abstract From the effect of global energy demands, many oil industries are forced to search for hydrocarbons in more challenging environments. For example, drilling under high pressure-high temperature (HPHT) conditions has become common practice over the past 15 years, and new technologies are being developed to keep up with the need to drill safely and efficiently, minimize formation damage, and improve the production rate. The decision to drill two highly deviated and horizontal gas wells in the "S" field located in South Sumatera, Indonesia led to a detailed drilling strategy for managing the HPHT - sour gas environment and the narrow pressure window. Subsurface simulation confirmed that these well designs will provide additional gas recovery compared to existing vertical wells and also extend the plateau time production accordingly. The main challenge was to connect two vertical wells into one horizontal that would contribute to 60% of gas recovery from this structure.
Abstract 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.
Abstract Managed Pressure Drilling (MPD) solutions are no longer the anomaly to Operator strategies, but rather another tool in their belts. With this continual utilization, MPD is evolving to become compact, more effective and safer. The inventive use of a Nitrogen Backup Unit (NBU) has eliminated the reliance of MPD operations on sizable Auxiliary Pumps. The core function of MPD operations is maintaining the total wellbore pressure by manipulating surface applied back pressure. MPD relies on circulating fluid as back pressure is generated by restricting flow against its choke(s). While drilling, fluid circulation is a given; however, that is not the case during static conditions such as drill string connections. The NBU solves this issue by injecting a small volume of nitrogen into the MPD lines upstream of the choke at a pre-set pressure. This supplements the back pressure control at surface should additional pressure be needed after closing the choke or if pressure diminishes during long static periods. Prior to the NBU design, the only effective solution was an Auxiliary Pump setup. This solution doubles the choke manifold footprint, relies on mechanical maintenance, and requires additional dedicated personnel at times. Most critically, the Auxiliary Pump lags the operation minutes before each use and is therefore functioned before static conditions when possible. However, unplanned and sudden events are commonplace – such as Rig Pump failures. When drilling formations with narrow pressure margins, unsafe gases, or crucial hole instability pressure limits, a few minutes can result in considerable and costly outcomes. Once installed during initial rig-up, the NBU is capable of injecting nitrogen-sourced back pressure instantaneously at the literal click of a button – avoiding costly and sometimes hazardous conditions. The NBU modernizes MPD operations and renders the Auxiliary Pump setup outdated in many applications. This paper details this innovative implementation of maintaining wellbore pressure, highlights several field examples of the NBU maintaining back pressure at critical times and shows how the layout used minimizes the operational footprint.
Summary As the industry pushes the boundary of technology to drill narrow-margin wells, combining safe drilling practices with drilling efficiency is becoming ever more challenging. The practice of drilling with managed-pressure drilling (MPD) by use of statically underbalanced mud weight (MW) is gaining increasing acceptance in high-pressure/high-temperature (HP/HT) well construction. This paper describes the planning and execution of using mud-cap fluid in the drilling of an ultranarrow-margin (0.50-lbm/gal window at the planning stage) HPHT well from a jack-up rig. Drilling equivalent circulating density with overbalanced MW at acceptable flow rate would have exceeded the formation-fracture gradient and resulted in a loss of well integrity. To avoid this outcome, the HP/HT section of the well was drilled with statically underbalanced MW. Displacing well to kill-weight fluid at acceptable flow rates before any trip out of hole was not viable. Planning focused on how to maximize operational efficiency with a cap fluid to trip in and out of hole without compromising openhole integrity and well safety. In this paper, we discuss the design of the mud-cap fluid, selection of change over depth, risks associated with use of the cap fluid, determination of available window for mud-cap placement and removal, planning and execution of mud-cap placement and removal, challenges of running and displacing the cap fluid with a liner, and lessons learned from the repeated use of the technique throughout the well-construction phase, including coring and wireline logging under MPD conditions. Significant operational efficiency was gained from the use of cap fluids, making it possible to drill a well that would otherwise have been near impossible to drill with minimum lost time.
Abstract As the industry pushes the boundary of technology to drill narrow margin wells, combining safe drilling practices with drilling efficiency is becoming ever more challenging. The practice of drilling with Managed Pressure Drilling (MPD) using statically underbalanced mud weight is gaining increasing acceptance in High Pressure High Temperature (HPHT) well construction. This paper describes the planning and execution of using mud cap fluid in the drilling of an ultra-narrow margin (0.50ppg window at the planning stage) HPHT well from a Jack Up rig. Drilling Equivalent Circulating Density (ECD) with overbalanced mud weight at acceptable flow rate would have exceeded the formation fracture gradient and resulted in a loss of well integrity. To avoid this outcome, the HPHT section of the well was drilled with statically underbalanced mud weight. Displacing well to kill weight fluid at acceptable flow rates prior to any trip out of hole was not viable. Planning focused on how to maximise operational efficiency by using a cap fluid to trip in and out of hole without compromising open hole integrity and well safety. In this paper, we discuss the design of the mud cap fluid, selection of Changeover Depth (CoD), risks associated with use of the cap fluid, determination of available window for mud cap placement and removal, planning and execution of mud cap placement and removal, challenges of running and displacing the cap fluid with a liner and, lessons learnt from repeated use of the technique throughout the well construction phase, including coring and wireline logging under MPD conditions. Significant operational efficiency was gained from the use of cap fluids, making it possible to drill a well which would otherwise have been near impossible to drill with minimum lost time.