MPD enables onshore efficiency and well control
Many of today’s drilling prospects are challenging, expensive, and in some cases undrillable. Managed-pressure drilling techniques are increasingly being applied as a solution to overcome barriers and increase drilling performance.
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MPD equipment setup on Shell Bullmoose d-A80-A/93-P-3 location. (Image courtesy of Real Results)
Practical MPD evolution
Interestingly, the MPD techniques being used today slowly began evolving on US land programs about 15 years ago. Then it was not uncommon for a drilling contractor to discover that the mud used to run a job was too light for the pressure into which it was being drilled, putting the well in danger of a kick. To mitigate the situation, a rotating control device (RCD) and a choke were used to simulate the required hydrostatic pressure.
“At that time, these techniques were not referred to as MPD,” said Hannegan. “But this is where the application began in its most basic form.” Over the last couple of decades, lessons learned from early experiences in pressure management have been combined with technology and advanced engineering to develop tools and equipment that have transformed the industry.
“The oil and gas industry has also benefited greatly from observing and benchmarking best practices from process industries like pulp and paper, chemicals, and petroleum refining,” he said. “These industries are known for closed, pressurized fluid systems that promote better control and hazard mitigation. By taking their lead and bottling circulating fluid so that it can be pressurized instead of openly exposing it to the atmosphere immediately underneath the rig floor, the mud weight in the drilled formation can be very precisely controlled. This is an evolution from the conventional wisdom that has been used to circulate fluid systems for the past century.”
There are four MPD variations practiced on land:
● Returns Flow Control is the health, safety, and environment variation where the circulating system is closed by means of a RCD to safely divert solution gas from the rig floor;
●The Constant Bottomhole Pressure variation is useful for narrow, relatively unknown drilling windows. With CBHP a choke is used to manage the backpressure on the well to control the bottomhole pressure or to manipulate the pressure gradient to potentially drill longer hole sections between casing points;
● Pressurized Mud Cap Drilling is used for severe lost circulation or drilling into sour formations; and
● Dual Gradient hydraulically tricks the well into thinking the rig is closer than it really is by removing some of the weight of the mud and cuttings and injecting light liquids into the annulus return path.
Prospects that cannot be drilled conventionally must be drilled with the most precise wellbore pressure management tools available. Successful application of MPD techniques requires detailed understanding of the potential benefits and limitations. This is demonstrated by the approach taken and results achieved drilling the Nikanassin formation in Canada.
Canadian MPD land application
Bullmoose field, located in the 93-P-3 land block of northeastern British Columbia, Canada, is a highly competitive sour gas play. Over the past seven years, Shell Canada has participated in four exploration wells and one development well in this area. The operator’s most recent objective was to increase drilling speed in the ultra-hard and abrasive Nikanassin formation by implementing an MPD program. The Nikanassin is a Jurassic formation consisting of interbedded marine sandstones and shales, with the occasional coal seam. The thickness can vary from 3,281 to 5,906 ft (1,000 to 1,800 m), requiring multiple tri-cone bits to drill the interval and making bit selection difficult.
Several performance drilling technologies were reviewed in finding this solution to minimize drilling time and cost. MPD, using a flocculated water system, was selected based on offset information and rock samples that indicated the potential for rate of penetration (ROP) benefits and pressure management capabilities. Considerable planning and risk assessment ensued, including selection of appropriate equipment.
A primary component was the IP 1000 RCD. The RCD was nippled up on a blowout preventer with three rams (dual pipe rams, dual choke lines, and one blind ram) and annular returns directed through dual manual choke manifold and sample catchers. Returns were then sent to the horizontal separator. The rig choke was connected to the second inlet of the MPD choke manifold so that well control operations could be conducted through either the rig’s degasser or the service company’s separation package.
From the separation package, drilling mud and solids are pumped back to the rig’s shaker and mud tanks. While making connections, fluid was pumped through the kill line, allowing the choke operators to maintain constant backpressure on the well.
The result was a job that met all the short-term key performance indicators established for the project. This included drilling with increased ROP compared to the offset wells, reducing the overall well costs, and completing the MPD operation without any HSE incidents. Compared to the previously drilled Shell Bullmoose a-62-F/93-P-3, the total days spent in the Nikanassin, including trip time, were reduced by approximately 24 days; the cost was reduced by 50% for the interval.
The MPD package, including surface backpressure control capabilities, gave operations personnel and the drilling contractor the confidence to drill into the potentially higher pressured zones with the normally weighted flocculated water system.
Conclusion
MPD success achieved on land programs is fueling continued innovation around the technology and its use. It is also fostering a significant level of trust and commitment between operators and service providers as applied technology and engineering strength are used to program and model conditions in the well that more precisely and efficiently manage pressure.
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