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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.
Purwagautama, G. (PT Medco E&P Indonesia) | Afandi, Idi Yusup (PT Medco E&P Indonesia) | Rachman, Syahriza Ghany (PT Medco E&P Indonesia) | Purwanto, Arga (Halliburton) | Radley, David (HES - Geobalance)
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. Managed pressure drilling (MPD) was the main option for drilling this well in terms of drilling risk, compared to conventional techniques.
Thibodeaux, H. (Chevron) | Williams, J. (Chevron) | Duhe, N. (Chevron) | Milazzo, J. (Chevron) | Kvalo, M. (Schlumberger) | Deplaude, O. (Schlumberger) | Vargas, N. (Schlumberger) | Hobin, J. (Schlumberger) | Jesudas, J. (Schlumberger) | Clements, J. (Schlumberger)
The Permian basin has been one of the main drivers leading the recovery of recent drilling activity on U.S. land. It has been a focus for drilling activity that has targeted conventional reservoirs since the first well was drilled in 1925. Through the depletion of conventional reservoirs, fracture pressure in these zones has decreased due to the reduction in pore pressure. Some of these previously drilled reservoirs throughout the Permian Basin have been selected for the reinjection of produced water which has caused abnormal pore pressures to occur. The combination of having both loss and injection zones exposed in the same drilling interval has resulted in challenges for operators as they have to navigate the resulting mud weight windows of highly developed fields of the Midland and Delaware Basins. As development throughout the Permian basin continues, these mud weight windows will only become more difficult to manage.
In one of Chevron's highly developed Midland Basin fields, managing the exposed injection and loss zones in the intermediate hole section proved to be challenging. This hole section had routinely experienced severe to complete losses upon entering the Upper Spraberry formation as a result of trying to manage higher pressures inflicted by the San Andres formation, a shallower injection zone. The mud weight could not be reduced to mitigate these losses without inducing an influx from the San Andres. Circulation could often not be reestablished upon entering the Spraberry formations which resulted in mud cap or blind drilling in order to reach section total depth (TD). These losses and overall wellbore conditions introduced higher risk and consequences in the form of well control events, wellbore instability, and mechanically or differentially sticking 9-5/8" casing prior to reaching planned set point. The immediate solution to isolate the wellbore problems was to implement a contingency liner, which comes at a premium and decreases drilling and completions efficiencies of the production hole section.
Managed pressure drilling techniques were identified as a solution to simultaneously navigate a shallow injection zone and a deeper loss zone within the same hole section. The necessary equivalent mud weight profile was established through the reduction of MW and the addition of surface back pressure. This enabled a higher equivalent mud weight to be held at the shallow injection zone and a lower equivalent mud weight to be held across the loss zones. Additionally, managed pressure cementing techniques were used to achieve a similar pressure profile during cementing operations in order to increase the likelihood of maintaining returns while placing cement across the loss zones.
Managed pressure drilling and cementing techniques implemented in this field contributed to the elimination of contingency liners and significant non-productive time in hole sections where both injection zones and loss zones were exposed. As laterals are extending beyond 10,000’ across the Permian Basin, the team has collectively proven the concept that the MPD system is part of an equipment package that can eliminate contingency liners and deliver the preferred sizes of production hole and production casing that is crucial to successfully reaching TD and efficiently placing hydraulic fracturing jobs at optimal rates.
As the industry pushes the boundary of technology to drill narrow margin wells, safe drilling practices and maintain 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 HPHT well construction. This paper describes the planning and execution of using mud cap fluid in the drilling of an ultra-narrow margin (0.5ppg window at planning stage) HPHT well from a Jack Up rig.
Drilling ECD with overbalanced mud weight would have exceeded formation fracture gradient resulting is lost circulation, therefore the HPHT section of the well was drilled with statically underbalanced mud weight. With no viable option to displace well to kill weight fluid prior to any trip out of hole, planning focused on how to maximize operational gains from use of cap fluid on different trips out of hole without compromising open hole integrity and well safety.
In this paper, we will discuss the design of the cap fluid, selection of changeover depth (CoD), risks associated with use of 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 out cap fluid with 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 fluid, making it possible to drill a well which would have been impossible to drill with minimal lost time.
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) HP/HT 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.