MPD is a ten-year-old technology that keeps drilling pressure at, or slightly above, reservoir pressure, which, it is argued, in most circumstances gives better control of the annular pressure profile throughout the wellbore than under-balanced or over-balanced techniques, where the pressure is maintained below or above that in the reservoir.
MPD uses a rotating control device (RCD), a drilling choke manifold (DCM) for back pressure management and a multiphase separator, which combine to give a closed-pressure environment that can be precisely controlled.
In the view of Derrick Lewis, global operations manager at Halliburton business line Geobalance Measured Pressured Drilling Service, MPD offers considerable benefits in terms of an additional barrier with the RCD, the ability to mitigate lost circulation and well-control incidents, and the ability to tell if the well is taking an influx or ballooning, as well as an increase in rate of penetration (ROP), which is generally experienced with MPD.
"If you compile these," he says, "and look at eliminating the non-productive time (NPT) events, while maximising drilling operations, MPD adds up very quickly as being economical for operations."
The true definition of MPD
Lewis is, however, leery of recent statistics that suggested that, in the US, 75% of onshore and 25% of offshore are using MPD. These statistics may be for the use of an RCD in a stand-alone application, which does not in itself make it a MPD operation.
"MPD means a lot of things to different people," he says. "If you look at the true definition of MPD versus under-balanced or over-balanced drilling, it is all about the intent. The intention of drilling the well at reservoir pressure or just above is the short definition of MPD."
Nevertheless, Lewis says it is amazing that the technique is not being used for more E&P projects.
"The majority of wells could be addressed with MPD. There are also benign wells that could benefit from the use of MPD – if you don’t have concerns about slow rates of penetration, and you don’t have any well-control issues, and are not worried about taking a kick, lost circulation and differential sticking. While there might be a fiscal benefit from MPD for those types of wells, the economic benefit then probably would not justify it."
He adds that wells drilled with pure air or nitrogen, for higher rates of penetration and wells that experience high lost circulation, typical of formations drilled in the Permian Basin, would not benefit from using MPD. These types of wells are actually using a form of under-balanced drilling.
"There are also some wells where the pore pressure and the fracture gradient are so narrow that MPD would not be successful, and those wells will need to be drilled under-balanced, or have successive strings of casing set."
The economics of MPD
MPD comes as either a manual or automated system. Lewis says that his customers generally favour the latter because of the accuracy, reaction or response to many events that allow them to optimise the drilling operation, by producing real-time modelling of what is taking place down hole.
Lewis asserts that successful MPD needs to be part of the well design from the start. "Often we get called to provide managed pressure drilling on a well that is already being drilled. They may have already taken kicks and set plugs, and established underground communication between areas of low and high pressure, what are considered underground blowouts.
"Basically the pore pressure and fracture gradient window no longer exist. It has all been reduced. So under-balanced or mud cap drilling would be required to finish the well. Whereas if MPD had been used to start drilling that zone, we would have stood a very good chance through the control of bottom hole pressure, of drilling successfully through that narrow pore pressure fracture gradient window and not damage the reservoir or dilute the production."
The economics of MPD has to be balanced, Lewis explains, against the potential costs of NPT, poor drilling optimisation and safety-related incidents. "The economics is what you always have to look at. But it is hard to look at the economics of safety for an incident that you have prevented if you didn’t experience it."
A typical land-based MPD operation might represent 10-20% of the overall well cost, he says – at the lower end if it is not implemented through the entire well section, and also depending on whether it is a directional or straight hole, and using oil or water-based fluids.
On a proportional level, MPD on jack-ups is likely to be 5-10% of total investment and, in deep water, would drop to 2-5%.
Deepwater logistics
MPD deployment offshore currently faces a number of challenges. The technology is mostly used on jack-up rigs sitting on a shelf, where there is no rig movement.
"The jack-up environment is mostly not problematic for MPD, " says Lewis, "because you have your BOPs, your blowout prevention equipment, right there above the water underneath your drilling rig, very similar to what is encountered on the land drilling. The RCD is fixed directly on top of the BOP.
"However, current technology, especially in deep water, does not allow us to put the RCD on top of the BOP stack on the sea floor. Another problem is that not all risers have the same pressure rating you would experience with casing."
Lewis points out that in the event of a kick, if the RCD is on top of the riser, there is concern about that riser’s burst rating.
"We also have to be concerned with the movement of the floating rig in relation to the riser, because we have a pressure seal in the RCD, which needs to have the pipe centred, not moving about with the sway and yaw typically experienced with the wave action on these floating rigs."
Challenges and solutions
Though dynamic positioning can overcome movement to a certain extent, there will inevitably be some motion to contend with. If enough pressure is put on it, this will cause the pipe to side load on the element in the RCD, releasing gas to the surface. A number of solutions are being worked on, including below tension-ring RCDs.
The ultimate solution, believes Lewis, will be to develop an RCD that will sit on top of the subsea BOP stack. "The technology is not there yet," he says. "We have had companies working on that for many years.
There are, he says, additional challenges, which is that the pressure sealing elements within the RCD wear out. "If that element is at 7,000ft of water, how are you going to change it? The other challenge is your well-control situation when you are trying to change this element: the amount of hydraulic horse power that you need at the surface to be able to control pressure more than a mile below the surface."
However, within its present operation environments, Lewis has no doubt of MPD’s value.
"I have been on both sides of the fence," he says, "I have worked as an operator and in the service industry. If I had had this tool back then, I can see just how much easier my life would have been and what better production these wells would have been able to deliver for my asset teams. Saying that, if I didn’t believe in the business, I would have stepped out of it years ago. MPD is the most exciting drilling optimisation and reservoir solution tool that I see in the industry right now."
