March 2007
Special Focus

Simple managed pressure drilling method brings benefits

The first three wells to use a new closed-loop MPD system have confirmed its effectiveness on multiple well types.

Vol. 228 No. 3  

Managed Pressure Drilling

Simple managed pressure drilling
method brings benefits

First wells using a new MPD system confirm its effectiveness on multiple well types.

Helio Santos, Impact Solutions Group; and Joe Kinder, Secure Drilling

Managed Pressure Drilling (MPD) involves a collection of tools, processes and equipment to manage the annular pressure profile in an oil or gas drilling operation. Key to this is a more precise determination of the wellbore pressure limits (pore and fracture) and keeping the pressure within the safety limits. It is not surprising, then, that the oil industry is seeing this new drilling method as the best alternative for successfully drilling wells in difficult environments, where conventional drilling has failed.

MPD can be used in a variety of ways, from simply managing the friction in the annulus or modifying fluid properties and flow rates, to more complex issues like:

• Using equipment to keep circulating, while making connection

• Using pumps inside the wellbore to reduce the fluid pressure

• Keeping the well closed with the return going through a choke to apply backpressure at the surface.

To understand how different MPD techniques can be employed, a simple distinction of MPD well types is offered:

• Standard—statically overbalanced at all times

• Special—statically underbalanced sometimes.

Secure Drilling is a closed-loop MPD system based on the Micro-Flux Control method. It can be used to drill standard or special MPD wells, depending on a well’s complexity and needs. The system uses a rotating control device to keep the well closed to the atmosphere at all times and a specialized manifold with a very small footprint that includes redundant chokes, a flow meter and data acquisition and control electronics. The simplicity of this system makes it very attractive for use on almost every well. Downhole pressure sensors and additional surface equipment are usually needed when using the system on its special mode.

An interesting feature, while in spiral mode, is its ability to switch between standard and special modes, providing that the additional equipment is available and rigged up. This way, part of the well can be drilled using standard mode, while the problematic hole segment(s) can be drilled using the special option.


In its simplest configuration, the system can be used on any well and rig, since there is no change to any safety or design criteria. The choke is always run fully open all the time to apply the minimum backpressure possible at the surface. Since the system continuously monitors the flows and pressures, it detects influxes and losses very early, controls any influx automatically and keeps the total influx volume in the well to less than 5 bbl. In addition, this simple configuration can identify many other normal drilling problems, such as:

• Washout

• Mud pump problems: efficiency and leakage

• Torquing drillstring

• Leak-off test accuracy

• Casing test accuracy

• Surge/swab pressure monitoring while moving pipe

• Swabbing a kick while backreaming

• Confirmation of static underbalance

• Connection gas

• Trip gas

• HPHT fingerprinting

• Distinguishing downhole influx from gas (or air) at surface.


In this option the surface backpressure can be controlled to drill the well under various situations. One scenario is to keep a desired wellbore pressure. Friction loss changes constantly; the driller can compensate for this by applying extra backpressure at the surface. Normally, this is beneficial when the well is drilled statically underbalanced. This requires reviewing drilling, connection, tripping, logging, casing and cementing, well control procedures, extensive rig crew training, wellsite experts to control and manage the operation and, in many cases, special applications for drilling permits.


After successful tests conducted from October 2005 until March 2006 at the Well Control Facility at Louisiana State University (LSU) in the US, the system was used to drill its first wells in 2006: two wells for Petrobras and one for Chevron. The main objective of these companies was to evaluate the system in drilling conditions, with the goal of using it in complex scenarios, including deep water.

The agreed program was first to use the system on simple onshore wells, then move to offshore fixed platforms, before going onto a floater rig. All three wells were drilled using the standard MPD option. The system was subjected to progressively demanding environments, Table 1. The wells confirmed the ruggedness of the entire system under more than 100°F ambient temperature, including the electronics that acquired and processed the data used to make the control decisions, the equipment (chokes, flowmeter and valves) and software. In these field wells, the chokes and flowmeter did not experience plugging, even at penetration rates up to 270 ft/hr in a 12¼-in. hole section.

TABLE 1. Test well parameters
Table 1


Since standard mode was used in all three wells, the choke was fully opened while drilling, and during connections the pressure was allowed to drop to zero. The intention was to confirm the kind of information obtainable when the pumps were off. Flow-out was continuously monitored and, if the well was statically underbalanced, it was detected immediately. While drilling, the system was ready to identify a kick and, after kick confirmation, close the choke automatically to control the influx.

The rotating control head used on all three wells was rated at 500 psi with rotation. When using the standard MPD option, this low pressure is more than enough for most cases. All connections were made in such a way that all standard drilling, tripping, connections, logging, casing and cementing procedures were kept the same, Fig. 1. The rig crew did not need to change anything. This was a key component of the new technology’s acceptance by personnel. Extra time, required to connect the trip tank and flow line hoses, is just one hour when the system is used on the same rig. The equipment’s small footprint was another key element contributing to its acceptance, Fig. 2.

Fig. 1. Connections at the wellhead were designed to keep all procedures conventional, including drilling, connections, tripping, logging casing and cementing.

Fig. 1. Connections at the wellhead were designed to keep all procedures conventional, including drilling, connections, tripping, logging casing and cementing. 


Fig. 2. The system�s manifold in use drilling Well 3, in Brazil. The equipment�s small footprint aided its acceptance.

Fig. 2. The system�s manifold in use drilling Well 3, in Brazil. The equipment�s small footprint aided its acceptance. 

Before drilling the cement and casing shoe for each hole section, a series of flow exercises was conducted. Fingerprinting of pipe movement, backreaming and flow-out when starting and stopping the pumps is critical for abnormality identification while drilling.


The first positive surprise came from the system’s accuracy in detecting small flow-out variations during flow exercises inside the casing, Fig. 3. The movement of the pipe has a strong influence on flow-out, indicated by the red line on the left track. When the pipe is moving up, flow-out indicates a fluid loss equivalent to the wet volume of the pipe. The opposite is true when moving the pipe down. The accuracy of the system can be confirmed by the upsets in the flow-out curve. Those upsets are the tool joints, which confirm the ability to detect a few gallons of flow difference.

Fig. 3. Fingerprinting of pipe movement inside the casing. The upsets showing the tool joints confirm the system�s accuracy in detecting micro-fluxes.

Fig. 3. Fingerprinting of pipe movement inside the casing. The upsets showing the tool joints confirm the system�s accuracy in detecting micro-fluxes. 


The system was used to identify influxes when the pumps were off, as well as kicks swabbed while backreaming, both while using oil-based mud. These two conditions confirmed that MPD can be very effective drilling wells along the pore-pressure curve, since it can detect volume changes when the mud weight is very close to the pore pressure.

Figure 4 shows the fingerprinting of a pump shut down inside the casing. Observe that the flow-out goes to zero on a continuous downward trend, as expected. During one of the connections, after stopping the pump, the flow-out started to decrease, but, after some time, it increased, Fig. 5. This is clearly abnormal behavior and the influx was immediately detected. The gas influx that was detected in real time was also seen at the surface after bottoms-up over one hour later. Correlation with mud-logging information at the rig was 100%.

Fig. 4. Fingerprinting of a pump shut down inside the casing.

Fig. 4. Fingerprinting of a pump shut down inside the casing. 


Fig. 5. Detection of an influx during a connection.

Fig. 5. Detection of an influx during a connection. 



In this case, it was just a momentary influx, since the subsequently flow-out went to zero. However, this is a clear indication that the mud weight is very close to balance. The operator’s representative decided to increase the mud weight. This event did not occur on the following connection, Fig. 6, confirming the correct decision to increase the mud weight.

Fig. 6. A normal connection after increasing the mud weight shows that no influx was detected and that there was no need to further increase the mud weight at this stage.

Fig. 6. A normal connection after increasing the mud weight shows that no influx was detected and that there was no need to further increase the mud weight at this stage. 


One of the most important aspects of these first wells was to confirm the benefits of the system, even in standard mode. These included:

• Clear identification of the need (or lack) to increase the mud weight

• Early drilling problem identification, allowing early treatment

• Reduction of NPT

• Avoiding well shut-in at least three times on a single well

• Continued safe drilling, even after pressure-while-drilling data transmission was interrupted by tool problems

• Continued safe drilling after rig instrumentation failed.

So, in addition to the increased safety provided by the kick detection and control feature, the simple standard mode proved to be very useful. It provided valuable savings, even in a relatively simple conventional well. For problematic wells, such as HPHT, with narrow margin, ballooning, kicks and losses, MPD should provide significant value and usefulness.


MPD can be used in a variety of ways on a well, and companies should make the most of this flexibility. Contrary to earlier thinking, MPD can be used on virtually any well with significant benefits, not just on challenging ones. It is not a niche market, as many believed a few years ago, similar to underbalanced drilling. For example, on a challenging well, where conventional drilling cannot be used due to a very narrow mud-weight window, application is straightforward. The well will probably need to be statically underbalanced and, when circulation is interrupted, the driller will need to compensate for the reduced static mud weight with backpressure. There are some alternatives being developed that will allow easy circulation during connections. These will make it simpler to drill a well safely while statically underbalanced.

However, with the results obtained from different MPD approaches, this alternative drilling can be used on virtually any well, since common drilling problems can be identified in the very beginning and drilling closer to pore pressure can be accomplished safely. MPD’s quick reaction to any influx or loss event provides added safety, which is lacking when the well is drilled conventionally, i.e., opened to the atmosphere.

MPD can also be applied when needed. This means a section of the well can be drilled in a conventional overbalanced condition, if there is no challenge in that hole section. In other sections, the mud weight at the start of the section can be reduced from the standard value, lowering the safety margins. The mud weight can be increased when there is a clear indication that the well is very close to pore pressure. In very problematic sections, where the well would have be to drilled statically underbalanced to reach TD, the hole section can start with an overbalanced condition and be changed to special mode as needed.

Coupled with these possibilities, the MPD system will also constantly monitor the safety margins while drilling, establish whether drilling can proceed deeper and determine whether casing needs to be set. MPD cannot change the formation’s pore pressure, but it can better define the actual values as influxes are detected. Based on the influxes and losses detected, the limits of the well are established. Then, we can very easily and safely determine whether there is sufficient margin to continue drilling or whether it is time to stop and set casing.


Two more wells using the normal mode will be drilled for Petrobras in coming months. One well, using the special mode, was drilled for Chevron offshore Angola, where the friction pressure was compensated with surface backpressure during connections. Other wells using the special mode will be drilled for Statoil in the North Sea and Cypress E&P in the US.

With the data being collected and reviewed, a careful evaluation of how best to use MPD is underway with the operators’ cooperation. The main goal is to optimize operations, making the rigs ready to use MPD at any time, and evolving operations to a point where MPD becomes the norm, not the exception.

Offshore operations from a fixed platform or a jackup do not present a major problem. However, MPD from floaters requires a more elaborate approach. Petrobras and Chevron, as well as some rig contractors, like Transocean, are involved in detailing equipment needs and procedures to allow MPD on floaters routinely. Work is in progress with service suppliers to develop the missing pieces with the expectation that within one to two years MPD from floaters will become a straightforward operation.

The benefits of using MPD in a deepwater setting are very appealing, considering the high cost of operations and the savings potential of using MPD to drill those wells. WO




 Helio Santos earned a BS and MS in civil engineering from the Catholic University in Rio de Janeiro and a PhD in geological engineering from the University of Oklahoma. He joined Petrobras as a drilling engineer in 1983. In 1986, Santos was transferred to Petrobras' Research Center where he worked on drilling projects in wellbore stability, optimization, underbalanced drilling, offshore drilling, deepwater drilling, extended reach and horizontal wells. In 2001, he joined Impact Engineering Solutions as vice president of technology. In 2004, Santos became president of Impact Solutions Group and is now also director of Secure Drilling, a joint venture formed with The Expro Group.


 Joe Kinder is President of Secure Drilling, LP, a joint venture of the Expro Group and Impact Solutions Group formed in 2006 to commercialize Impact's Micro Flux Control technology. Prior to joining Secure Drilling, he was with PowerWell Services, predecessor to Expro, as engineering manager. Joe has been involved with many facets of engineering and operations supporting underbalanced and managed pressure drilling since 1994, when he began with RBOP Oil Tools. Kinder is a graduate of the University of Houston in mechanical engineering and serves as chairman of IADC's Underbalanced Operations and Managed Pressure Drilling Committee.


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