The most recent IADC / SPE MPD / UBD conference was held Jan 29 - 30 in Abu Dhabi. Transocean did not present anything on the recent job in India but hopefully we will hear about it at the next conference.
The IADC definition of MPD is...
Managed Pressure Drilling (MPD) - an adaptive drilling process used to precisely control the annular pressure profile throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the annular hydraulic pressure profile accordingly. It is the intention of MPD to avoid continuous influx of formation fluids to the surface. Any influx incidental to the operation will be safely contained using an appropriate process.
- MPD process employs a collection of tools and techniques which may mitigate the risks and costs associated with drilling wells that have narrow downhole environmental limits, by proactively managing the annular hydraulic pressure profile.
- MPD may include control of back pressure, fluid density, fluid rheology, annular fluid level, circulating friction, and hole geometry, or combinations thereof.
- MPD may allow faster corrective action to deal with observed pressure variations. The ability to dynamically control annular pressures facilitates drilling of what might otherwise be economically unattainable prospects.
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I have been working on Managed Pressure Drilling for the past 6 years and before that was also working on Underbalanced Drilling. Forgive me if the following is somewhat long winded but I know how much students like to read.
At Balance has performed approximately 30 jobs to date using a fully automated system which utilizes an integrated hydraulics model to maintain a constant bottomhole pressure at a selected depth. I'll add that At Balance is currently the only company that has proved they can do this.
Typically the mud weight is reduced so that backpressure can compensated for the loss of frictional when the pumps are turned off. The bottomhole pressure is only equal at one point in the borehole when the pumps are running or stopped because the pressure drop when pumping has a pressure along the length of the wellbore versus when holding backpressure which is a pressure across the choke. The change in pressure along the open hole section as distance increases from the control point needs to be considered but is typically a magnitude less than when drilling conventionally, hence the advantage of using MPD in tight pressure windows.
Projects have ranged from onshore US to offshore Myanmar for a myriad of applications but most notably due to the narrow margin between fracture and borehole stability pressure or fracture and pore pressure. In Myanmar the job was to provide kick detection using a Coriolis flow meter and automatically control the kick. This was extensively tested prior to drilling the well. Kick detection during drilling was approximately a 1 gallon influx - as hard as that is to believe, due to the sensitivity of the flow meter and tuning out the noise. This was a floater application and while there was no significant noise due to heave effects while drilling, we could tell which pump was noisier than the other.
Many of the wells that At Balance has drilled were wells that could not have been drilled without using MPD. While there are wells that can be drilled to TD, the cost of doing so due to fighting kicks, losses and cuttings / cavings transport are mitigated by using managed pressure drilling to stay in the narrow window. This was the case where we were on a Transocean rig in Malaysia for Talisman - presented at the recent MPD conference.
Of course it costs money to do MPD but the risk costs are considerably less because of the ability to get the well to TD without problems. MPD also stands for Makes Problems Disappear - Ken Armagost (sp?) ConnocoPhillips at the 2005 MPD / UBD conference in San Antonio.
Sure, methods to shut-in on connections have been around for years - you did what you had to do to get the job done and managed to get away with it, sometimes. I wouldn't say that all methods are equal though and there are times when you can drill a well with a "Bloke on the Choke" although in critical applications such as when the hydrostatic pressure is less than pore pressure, any system failure or failure to react in a timely manner will result in a kick.
As for the "Bloke (being a person) on the Choke", I don't care how good he is, something usually goes wrong at 0230 hrs when he's stepped away to relieve himself and he's not watching the choke! I can't understand why someone would pay to try and monitor a well manually when it can be done automatically. Well control is hard enough in steady state conditions but with pump rates changing and changes in depth, it's almost impossible to keep the bottomhole pressure constant. Once a computer system has been trained properly it's quite easy - just not easy building the thing!
A recent MPD project in the GOM was only approved by the MMS because the system was fully automated and there were other control methods in place in the event the system failed. Personally, I would prefer to maintain control of the well by controlling the bottomhole pressure in real time, particularly when transitioning from pumps on to pumps off.
Statoil / Hydro recently used the NOV Continuous Circulation System along with the Secure Drilling to drill an HPHT well in Norway. As stated by Statoil, there was a great deal of trouble with both systems but did manage to get the well to TD safely, whereas they would not otherwise have been able to drill the well. Typically Statoil circulates bottoms up after each connection on an HPHT well to ensure they have not taken a kick since it is very difficult to determine if a kick has occurred as it may be masked due to temperature changes during static conditions. CCS made it possible to continue drilling since circulation was not stopped. I asked them if they wouldn't consider using the same method of all HPHT wells regardless of the pressure window and the answer was, well, I'll take it as a no, so draw your own conclusions as to why, because I didn't ask that question. As mentioned, when using the constant bottomhole pressure method using a choke, the pressure change compared to conventional methods is an order lower so it is reasonable to expect that the risk of a kick is likely in the same order, regardless of pressure change, which from simulations I have done, bottomhole pressure increases approximately 50 due to temperature - which additionally reduces the risk the of a kick in an HPHT well.
It is possible to detect kicks much sooner when using a closed system and a Coriolis meter but this also needs to be proven and maintained. Since this is a single phase meter it is sensitive to gas but can tolerate the normal amounts of gas experienced while drilling. There have been several Early Kick Detection systems developed over the years and typically are too complex for the drilling crew to manage and maintain so require a third party to manage the system. In the context of MPD though the systems should be integrated.
As for automated kick control, I will provide a word of warning - systems that claim to control kicks based on a comparison of liquid flow out versus liquid flow are dangerous and recommend you run away as fast as you can! In the old days this was known as the -Barrel in - Barrel Out- or -Constant Pit Level method and is no longer practiced because it doesn't work! It would work if all barrels were equal, but if it's a gas kick then the reservoir barrel and surface stock tank barrel are significantly different since as the gas rises and expands the liquid barrels out increase. The choke continues to be closed which in effect compresses the gas bubble as it rises and also increases the bottomhole pressure. Theoretically this continues until the surface pressure equals the bottomhole pressure in order to keep the volume equal but in practice some part of the well break down first.
There is a well control consortium paying LSU to look at MPD well control and they continue to publish, most recently at the last IADC / SPE MPD / UBD conference.
Do I think all wells should be drilled this way? Not at all, since not all require BOP's. From there it is a matter of doing a cost benefit analysis. As the benefits are better understood and the cost of the systems comes down, the number of wells drilled with MPD systems will be substantial. If done properly, I think it is a safer and more efficient way to drill.
I can also be contacted at don.reitsma@atbalance.com or see our website at www.atbalance.com which has a lot of information and publications on Managed Pressure Drilling. We're more than happy to help with MPD education.
The IADC definition of MPD is...
Managed Pressure Drilling (MPD) - an adaptive drilling process used to precisely control the annular pressure profile throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the annular hydraulic pressure profile accordingly. It is the intention of MPD to avoid continuous influx of formation fluids to the surface. Any influx incidental to the operation will be safely contained using an appropriate process.
- MPD process employs a collection of tools and techniques which may mitigate the risks and costs associated with drilling wells that have narrow downhole environmental limits, by proactively managing the annular hydraulic pressure profile.
- MPD may include control of back pressure, fluid density, fluid rheology, annular fluid level, circulating friction, and hole geometry, or combinations thereof.
- MPD may allow faster corrective action to deal with observed pressure variations. The ability to dynamically control annular pressures facilitates drilling of what might otherwise be economically unattainable prospects.
----------
I have been working on Managed Pressure Drilling for the past 6 years and before that was also working on Underbalanced Drilling. Forgive me if the following is somewhat long winded but I know how much students like to read.
At Balance has performed approximately 30 jobs to date using a fully automated system which utilizes an integrated hydraulics model to maintain a constant bottomhole pressure at a selected depth. I'll add that At Balance is currently the only company that has proved they can do this.
Typically the mud weight is reduced so that backpressure can compensated for the loss of frictional when the pumps are turned off. The bottomhole pressure is only equal at one point in the borehole when the pumps are running or stopped because the pressure drop when pumping has a pressure along the length of the wellbore versus when holding backpressure which is a pressure across the choke. The change in pressure along the open hole section as distance increases from the control point needs to be considered but is typically a magnitude less than when drilling conventionally, hence the advantage of using MPD in tight pressure windows.
Projects have ranged from onshore US to offshore Myanmar for a myriad of applications but most notably due to the narrow margin between fracture and borehole stability pressure or fracture and pore pressure. In Myanmar the job was to provide kick detection using a Coriolis flow meter and automatically control the kick. This was extensively tested prior to drilling the well. Kick detection during drilling was approximately a 1 gallon influx - as hard as that is to believe, due to the sensitivity of the flow meter and tuning out the noise. This was a floater application and while there was no significant noise due to heave effects while drilling, we could tell which pump was noisier than the other.
Many of the wells that At Balance has drilled were wells that could not have been drilled without using MPD. While there are wells that can be drilled to TD, the cost of doing so due to fighting kicks, losses and cuttings / cavings transport are mitigated by using managed pressure drilling to stay in the narrow window. This was the case where we were on a Transocean rig in Malaysia for Talisman - presented at the recent MPD conference.
Of course it costs money to do MPD but the risk costs are considerably less because of the ability to get the well to TD without problems. MPD also stands for Makes Problems Disappear - Ken Armagost (sp?) ConnocoPhillips at the 2005 MPD / UBD conference in San Antonio.
Sure, methods to shut-in on connections have been around for years - you did what you had to do to get the job done and managed to get away with it, sometimes. I wouldn't say that all methods are equal though and there are times when you can drill a well with a "Bloke on the Choke" although in critical applications such as when the hydrostatic pressure is less than pore pressure, any system failure or failure to react in a timely manner will result in a kick.
As for the "Bloke (being a person) on the Choke", I don't care how good he is, something usually goes wrong at 0230 hrs when he's stepped away to relieve himself and he's not watching the choke! I can't understand why someone would pay to try and monitor a well manually when it can be done automatically. Well control is hard enough in steady state conditions but with pump rates changing and changes in depth, it's almost impossible to keep the bottomhole pressure constant. Once a computer system has been trained properly it's quite easy - just not easy building the thing!
A recent MPD project in the GOM was only approved by the MMS because the system was fully automated and there were other control methods in place in the event the system failed. Personally, I would prefer to maintain control of the well by controlling the bottomhole pressure in real time, particularly when transitioning from pumps on to pumps off.
Statoil / Hydro recently used the NOV Continuous Circulation System along with the Secure Drilling to drill an HPHT well in Norway. As stated by Statoil, there was a great deal of trouble with both systems but did manage to get the well to TD safely, whereas they would not otherwise have been able to drill the well. Typically Statoil circulates bottoms up after each connection on an HPHT well to ensure they have not taken a kick since it is very difficult to determine if a kick has occurred as it may be masked due to temperature changes during static conditions. CCS made it possible to continue drilling since circulation was not stopped. I asked them if they wouldn't consider using the same method of all HPHT wells regardless of the pressure window and the answer was, well, I'll take it as a no, so draw your own conclusions as to why, because I didn't ask that question. As mentioned, when using the constant bottomhole pressure method using a choke, the pressure change compared to conventional methods is an order lower so it is reasonable to expect that the risk of a kick is likely in the same order, regardless of pressure change, which from simulations I have done, bottomhole pressure increases approximately 50 due to temperature - which additionally reduces the risk the of a kick in an HPHT well.
It is possible to detect kicks much sooner when using a closed system and a Coriolis meter but this also needs to be proven and maintained. Since this is a single phase meter it is sensitive to gas but can tolerate the normal amounts of gas experienced while drilling. There have been several Early Kick Detection systems developed over the years and typically are too complex for the drilling crew to manage and maintain so require a third party to manage the system. In the context of MPD though the systems should be integrated.
As for automated kick control, I will provide a word of warning - systems that claim to control kicks based on a comparison of liquid flow out versus liquid flow are dangerous and recommend you run away as fast as you can! In the old days this was known as the -Barrel in - Barrel Out- or -Constant Pit Level method and is no longer practiced because it doesn't work! It would work if all barrels were equal, but if it's a gas kick then the reservoir barrel and surface stock tank barrel are significantly different since as the gas rises and expands the liquid barrels out increase. The choke continues to be closed which in effect compresses the gas bubble as it rises and also increases the bottomhole pressure. Theoretically this continues until the surface pressure equals the bottomhole pressure in order to keep the volume equal but in practice some part of the well break down first.
There is a well control consortium paying LSU to look at MPD well control and they continue to publish, most recently at the last IADC / SPE MPD / UBD conference.
Do I think all wells should be drilled this way? Not at all, since not all require BOP's. From there it is a matter of doing a cost benefit analysis. As the benefits are better understood and the cost of the systems comes down, the number of wells drilled with MPD systems will be substantial. If done properly, I think it is a safer and more efficient way to drill.
I can also be contacted at don.reitsma@atbalance.com or see our website at www.atbalance.com which has a lot of information and publications on Managed Pressure Drilling. We're more than happy to help with MPD education.
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