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 deep basin of British Columbia, Canada contains the Montney and Doig plays, which are categorized as tight gas sands. Both are considered major unconventional gas plays containing vast quantities of gas in the west and oil in the coarser eastern facies. The formations have high initial formation pressure which promotes production, however during drilling causing drilling challenges. It is especially difficult when drilling through the abnormally pressured Doig transit zone. This is further complicated when a trip is required for the bit as the swabbing effect, if not properly managed, can easily escalade into a well control event. Due to the overpressured and geologically fractured formations, it is very difficult to trip the drill string out of the well safely without using specialized techniques. MPT is one such method that can be utilized in these scenarios. Managed Pressure Tripping allows the driller to control bottomhole pressure (BHP) in different types of abnormally pressured zones, and simultaneously eliminating the swabbing effects by holding surface back pressure (SBP) with the managed pressure drilling (MPD) system. Applying MPT techniques on subnormal and overpressured formations results in safe and cost effective drilling operations. This paper presents a case study where advanced Managed Pressure Tripping (MPT) technology was successfully applied in the Altares field in British Columbia, Canada, to mitigate well control challenges associated with swabbing. The study elaborates on recommended operational procedures, engineering calculations, equipment set up and process flow diagrams along with the analyzed graphical data.
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.
In the continual search for Oil and Gas, more and more exploration wells are being drilled in High Pressure-High Temperature (HPHT) environments. Pore and Fracture pressure prediction and understanding the true drilling window in HPHT exploration wells poses significant challenges. Once the pressure profile is ascertained, then the next challenge is to drill and cement the well within those limits to avoid kicks, losses and maintain the integrity of the well. There are special challenges in cementing HPHT wells. These wells typically have a narrow drilling window which could make it very difficult to manage the bottom hole pressure correctly while cementing the open hole section. In any stage of cementing in this type of wells, hydrostatic, dynamic and circulating effects should be considered. These tight windows in HPHT wells, combined with the effect of temperature and pressure on mud density possess significant risks for cementing operation. Also physical and chemical behavior of cement changes in high pressure and temperature. This paper details the advantages of applying advanced Managed Pressure Drilling (MPD) technology during coiled tubing cementing operations in a case study HPHT well. This advanced technique not only allows for maintaining a Constant Bottom Hole Pressure (CBHP) but also reduces the additional costs associated with cement weight and additives. Furthermore, real time flow monitoring eliminates the down hole fluid losses which in conjunction with CBHP reduce formation damage. A precise managed pressure coiled tubing cementing program was analyzed and planned inclusive of operational procedures and risks management. The well was displaced to a lighter drilling fluid through coiled tubing, while keeping bottom hole pressure (BHP) constant slightly over the formation pressure by applying surface back pressure (SBP). Four different densities of cement slurries were pumped in the hole through coiled tubing and held bottom hole pressure constant during the entire cementing operation within 30 kg/m3 (0.25 ppg) pore pressure and fracture pressure window. Held annular pressure constant with the help of SBP during the eight hours of cement setting time to ensure that hydrostatic pressure would remain in place. This document demonstrates the successful application of managed pressure coiled tubing cementing operation. It also elaborates the recommended operational procedures, integrated MPD and Coiled tubing equipment setup, along with real-time graphs and data from the case study well.
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