Advanced Managed Pressure Drilling (MPD) technology was used onshore in Western Canada to optimize ROP while drilling horizontally through the potentially sour shale formation using a low solids, low density synthetic base mud system. The Montney shale formation is very challenging to drill conventionally and has the potential for drilling into high pressure fractures which may contain sour gas. The overall objective consisted of using a lower density synthetic base mud system to optimize the ROP, thereby saving on overall drilling costs by reducing the number of drilling days and also drill the well safely due to the possibility of high pressure fractures and potentially sour gas. The main challenge was to increase ROP while still maintaining a constant bottomhole pressure to prevent any gas inflow into the wellbore. In order to optimize drilling efficiencies and save on drilling time, advanced MPD technology was applied in combination with a low density (770 kg/m3) synthetic based mud while holding surface back pressure (SBP) in dynamic and static conditions to maintain a constant bottomhole equivalent circulating density (ECD). The system's annular pressure control mode was used to hold a desired ECD at a pre-determined position within the wellbore; In this case the heel was chosen. Constant bottomhole pressure operations were maintained throughout the entire project. The desired ECD was achieved and the well was kept at balance with the pore pressure. The advanced MPD system also provided the ability to monitor, detect and control an influx at the bit much earlier than conventional MPD and drilling systems which provided additional safety to the location. While drilling conventionally the ROP was extremely slow averaging 3.32 m/hr. The results greatly improved using advanced MPD technology with average ROP's between 7.4–10.5 m/hr. This application also brought value to the project by reducing mud costs, increasing overall ROP as compared to conventional offset ROP data, maintaining constant bottomhole pressure with flexibility to adjust pressures as the well dictated, increasing safety through detection and control of micro influxes while drilling, reducing bits used as compared to conventional offset bit record data and minimizing any gas to surface. Achieving the goal of increasing the ROP and safely drilling the well to TD reduced the number of drilling days by at least 13 days, thereby reducing the overall AFE of the well. This paper will include engineering analysis of the project compared to offset data along with graphs and tables. It will further include detailed explanation of pre-engineering and execution methods of advanced MPD in order to achieve ROP optimization and reduce your drilling cost.
The drilling industry is an expensive part of the oil and gas sector, especially when drilling through a combination of low pressure and high pressure formations in exploration wells. When these zones are experienced while drilling, maintaining the BHP inside the drilling window is critical to ensure drilling fluid is not lost or formation fluids are not gained. Conventional solutions to help mitigate drilling through the troublesome formations include isolating thief zones, pumping LCM and cementing. These remedies could increase the overall project cost and add delays. One common problem associated with these solutions is how do you verify that the problem is corrected before drilling continues? From having analyzed a case study from the Duvernay wells in Western Canada, it demonstrates that Managed Pressure Drilling (MPD) was applied with lighter drilling fluids to help adjust the bottom-hole pressure (BHP) as desired before the problematic formations. Through the Winterburn formation, constant losses were recorded and LCM was squeezed by applying the required surface-back-pressure (SBP). A formation limit test for the Winterburn formation was recorded and the bottom-hole equivalent circulating density (BH ECD) at 1495 kg/m3, showed 283 liters losses. Due to continued losses into Winterburn Formation, 1.5 m3 of 1100 kg/m3 LCM pill was mixed, spotted into the annular and then squeezed on top of the formation. The LCM squeezing operation was started by applying 11,500 kPa static SBP which increased the BH ECD to 1700 kg/m3. After the LCM squeeze operation the well was reamed, and an extra 6 meters was drilled before performing a new formation integrity test (FIT). The second FIT was performed at the bottom of the formation and BH ECD had increased up to 1575 kg/m3 by applying 6,800 kPa SBP and the healing lost circulation zones were continued while drilling unconventionally through the MPD system. In the Beaverhill Lake formation, overpressured zones were encountered but drilling continued and dealt with both abnormal formation pressures. Lost circulation occurred in Winterburn formation with low pore pressure. The constant mud losses in this formation indicated that this problem was resulted from formation permeability, porosity and fractures that can be resolved by squeezing LCM. MPD brought value to the project by performing FIT in each formation, by monitoring and controlling precise LCM and cement squeeze operations. It also provided a solution for both types of abnormal formation problems as drilling continued and maintaining BHP inside the drilling window, increasing the overall safety of the project by detecting micro influxes and controlling them safely. According to the pressure profile window, this paper illustrates how MPD successfully drilled through an upper formation of low pore pressure, with lost circulation problem, and lower formation with abnormal higher pore pressure without setting a casing between them. It also discusses the effect an MPD-LCM squeeze has on the fracture gradient of a formation and how the drilling window can be increased and manipulated to the operator's advantage.
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.
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