This article discusses two managed-pressure drilling (MPD) techniques used to overcome differing subsurface challenges. Both techniques relied upon minimizing changes in the bottomhole pressure (BHP) by eliminating or mitigating changes in frictional pressure.
Coiled tubing MPD
The reservoir consisted of a large, highly permeable, homogenous sand section with
|Figure 1. How the BHP was maintained by manipulating the surface pressure. When the well was static, backpressure was applied to the annulus to maintain the necessary BHP at 1,000 psi over the hydrostatic pressure provided by the base mud weight. When circulation commenced and the annular friction pressure rose, the surface pressure decreased to compensate, maintaining the effective BHP constant. The reverse applied when pumping stopped: additional surface pressure was applied to compensate for loss in the annular friction pressure.
occasional shale layers throughout. The oil had been originally accessed via long horizontal wells placed in the middle of the oil rim. Over the years, due to unintentional gas production and strong water drive, the oil had migrated upwards. As a result, many of the wells had watered out, leaving a substantial amount of stranded reserves. In order to access these reserves, a proposal was made to sidetrack a couple of the existing wells at the heel in order to target the trapped reserves at the top of the sand.
The original drilling infrastructure had become non-operable, and the cost to reinstate the equipment to access the targets was prohibitive.
In order to avoid this expenditure coiled tubing (CT) was selected to drill the wells. Additional savings were made by drilling through-tubing. However, by drilling through-tubing the hole size was limited to less than 3 1/2 in., resulting in high circulating pressures and an increased risk of differential sticking.
Hydraulic modeling suggested that a conventional weighted drilling fluid suitable for providing
||Figure 2. How pressure depletion of the reservoir has resulted in a decrease in both pore and fracture gradients in the lower zone. This has resulted in a reduction in the drilling window at the transition zone to around 400 psi. If a base mud weight equivalent to the orange line had been used, the ECD at drilling flow rates would have exceeded the fracture gradient in the lower zone. To mitigate this, a base mud weight (represented by the green line) was chosen that was insufficient to provide an adequate well control barrier against the pore pressure in the upper zone. The necessary equivalent BHP was provided by applying additional surface pressure (orange line). The additional ECD while circulating was compensated for by reducing the surface backpressure, thereby maintaining the ECD within the drilling window.
adequate wellbore stability would create an effective circulating mud weight that would result in a pressure differential of 2,500 psi over the pore pressure. As coil cannot be rotated this was of prime concern. After reviewing various alternatives, use of MPD was selected.
The Dynamic Annular Pressure Control (DAPC) system selected from @balance incorporated a hydraulics simulator that in turn controlled an automatic surface choke and an automatic electric mud pump to manage pressures in the well bore. This system allowed the use of a mud weight that was 200 psi overbalanced in relation to the pore pressure. Although this was insufficient to provide adequate borehole stability to the shales that would be encountered, additional pressure was provided by imposing a surface pressure when the well was static. This pressure was then reduced when circulating to compensate for annular friction pressure losses (Figure 1).
The system was controlled by a computer that used a number of parameters to accurately calculate the pressure loss, including:
• Wellhead pressure;
• Circulating pressure;
• Choke setting;
• CT depth and amount at surface;
• Mud parameters; and
• Flow rate in and out.
The calculated BHP was corroborated through the use of a pressure while drilling (PWD) sub.
The project proved the application of MPD and successfully mitigated the high risk of differential sticking that had initially been identified when using CT drilling. Additional benefits included the ability to use a simpler (and cheaper) mud system. Reducing the overbalance on the formation while drilling significantly improved the resultant productivity index (PI) of the well when compared to all of the other offset wells on the platform.
Jointed pipe MPD
The second case history was carried out on a compartmentalized high-pressure/ high-temperature (HP/HT) reservoir. In this case, the development plan called for production to commence prior to the completion of the main phase of the drilling program. As with many HP/HT fields, pressure depletion occurred rapidly at the onset of production.
Along with a reduction in pore pressure, the fracture gradient also decreased, culminating in a reduction of the drilling margin between the upper zone that was required to be drilled through and the lower, progressively depleting target zone.
Simulations showed that by the time the last three wells were to be drilled, the drilling window between the pore and fracture pressure would be minimal, resulting in one or all of the following: loss of the wells during the drilling process, prematurely ending the drilling program or reduced production until the final wells were completed.
The initial drilling window at the start of the drilling campaign was in excess of 1,500 psi. As demonstrated in Figure 2, the drilling window decreased as the reservoir pressure depleted in the lower zone. At the end of the project this window was expected to decrease to as low as 115 psi.
Before MPD was chosen, a number of alternative solutions were investigated to determine the various effects on being able to complete the drilling program. These included expandable casings, contingency liner systems, alternative mud systems and the use of stress cage effects.
Primarily, two different MPD techniques were combined in the solution:
a Continuous Circulation System (CCS) from National Oilwell Varco and an automated choke to control the backpressure on the well annulus. The CCS allowed circulation to continue through the drill pipe while connections were being either made up or broken out, minimizing the pressure effects associated with surge and swab and gel strength of stationary mud. It also, to a lesser extent, minimized temperature effects on the mud.
The automated choke system compensated for the ECD effects and stabilized the BHP within the acceptable drilling window criteria. It could not, however, compensate for sudden changes to the system such as rapidly accelerating or decelerating the pipe or altering the pump rate too quickly. These had to be managed through implantation and adherence to good drilling practices.
The use of these technologies in conjunction with a rotating control head provided substantial benefits ranging from the reduction in exposure to losses, kicks and stuck pipe and extensive time and cost savings.
The application of automatic choke regulation and the continuous circulation system provided a number of benefits resulting in a nearly constant pressure at target depth. Pressure fluctuations did occur but were significantly reduced from those that would have been seen without using MPD equipment.