Managed pressure drilling (MPD) is a step-change from conventional wisdom, not a quantum leap. The technology has proven itself in several environments to be a better, safer way to drill challenging prospects.
Almost 40% of all non-productive drilling time can be attributed to time spent dealing with kicks, lost circulation, sloughing shale, shallow geohazards, and stuck pipe. One major operator’s study showed that ultra deep GoM wells typically cost about 60% more than their AFEs (authority for expenditure), and in some cases it is impossible to reach total depth.
MPD can solve many of these problems and can achieve drilling success on a growing number of prospects that would not be drillable using conventional technologies. MPD uses some of the specialized equipment and disciplines required to safely practice underbalanced drilling (UBD), where an influx of reservoir fluids is invited to minimize invasive mud and cuttings damage to the well’s productivity potential. MPD’s objective is to improve the drillability of the prospect by drilling overbalanced while more precisely managing the wellbore pressure profile. This does not invite an influx of reservoir fluids during the drilling process, so the driller typically is better prepared to deal with any that could be incidental to the operation. A Canadian study of conventional versus managed pressure drilling, using the constant bottomhole pressure (CBHP) variant, indicated MPD increased the rate of penetration and avoided kick/loss scenarios, saving an average of four days of rig time onshore. This savings could easily translate into eight to 12 days when drilling in marine environments like the GoM.
Asia-Pacific track record
The Asia-Pacific region offers a stark contrast to the GoM in terms of operators’ acceptance and application of MPD techniques. In the last two years, Weatherford has completed about 80 onshore and offshore MPD wells in the Asia-Pacific.
Almost 40% of all causes of non-productive time can be attributed to time spent dealing with kicks, lost circulation, sloughing shale, shallow geohazards, and stuck pipe.
In June 2006, the company had 12 rigs practicing MPD in the region. Today, there are 34. The number of operators has more than doubled from seven in June of 2006 to 15 today. And in all cases where operators have tried MPD, they have planned subsequent MPD projects.
One oil company’s first use of the technology was a 2004 land job in an area where offset wells had either exceeded their AFE or failed to reach the depth objective due to severe circulation loss and resulting well control issues. The first success on land saved a lot of mud that would otherwise have been lost into fractured carbonate zones, while avoiding associated differential sticking, twist-offs, and sidetracking. The operator discovered that MPD gave better control of the well throughout the project because the rotating control device (RCD) and choke system allowed surface application of backpressure without interrupting drilling.
The land project was followed by jackup rig projects and then by the world’s first application from a floating rig, a moored semisubmersible offshore East Malaysia. MPD worked as well offshore as it had on land, and the payoff was far greater because of higher daily costs.
Weatherford completed 80 managed pressure drilling projects between 2005 and 2007 in the Asia-Pacific region, not including full underbalanced or geothermal projects.
Today, this oil company’s policy suggests that if a future drilling program’s decision-makers plan to drill prospects conventionally where offset wells have experienced drilling problems, a formal process must be conducted to prove that drilling conventionally is better and safer than MPD.
A major operator’s highly challenging development wells in Sumatera, Indonesia, and an independent operator’s project in Papua New Guinea demonstrate the power of MPD technology. Both projects also demonstrated the advantage of combining MPD with a downhole deployment valve (DDV) tool, which eliminates the need to kill the well for trips out of the hole and saves operating time.
The Sumatera wells produce up to 300 MMcf/d of gas from large limestone fractures, but are difficult to drill conventionally.
Implementing the pressurized mud-cap variation of MPD (PMCD) allowed the well to be drilled quickly with minimal time spent curing losses. A further key was the use of the DDV. The reservoir was located below the severe loss circulation hazard, and without the DDV it would have been nearly impossible to safely trip out after reaching the total depth objective because there was no way to kill the well and/or assure the well remained killed during tripping operations. However, the DDV had been set in place at the bottom of the casing above the void, and it was closed once the drill string was above it. From that point, the pipe was run out quickly, and the well was completed without incident.
The independent operator in Papua New Guinea had similar severe drilling fluid losses, losing all fluid out of the wellbore on two occasions. A well control service company told the operator the well was “undrillable” and that it should be plugged and abandoned. At that point, the operator decided to try MPD.
Using PMCD, the operator was able to re-establish control of the well and to drill the reservoir section in only four days. For the latter part of the drilling process, the constant bottomhole pressure variation was used to negotiate the narrow margin between pore pressure and fracture gradient, a problem that had created numerous kick-loss scenarios in offset wells. The DDV saved time by eliminating the need to kill the well. MPD services for four more wells were confirmed immediately.
Variations of MPD
A number of MPD variations have been used in the Asia-Pacific region to date, including returns flow control (for HSE reasons), CBHP drilling, and pressurized/dynamic mudcap drilling (PMCD/DMCD). These variations of MPD use a closed, pressurizable mud-return system.
In a Canadian field, the CBHP variant of MPD increased the rate of penetration and avoided kick/loss cycles, saving an average of four days of rig time onshore (equivalent to 8-12 days offshore).
CBHP is similar in principle to a method often used to control kicks in conventional wells. The driller increases the speed of the mud pumps to generate more annular friction pressure in the well, which increases the equivalent mud weight (EMW). In CBHP MPD, the driller closes the returns choke, applying hydraulic backpressure to achieve the same effect. Closing the choke when mud pumps are stopped to make up pipe can allow the driller to maintain a constant pressure downhole, eliminating kick/loss cycles. It also addresses some ballooning and breathing issues, common and time-consuming problems on GoM drilling programs.
CBHP MPD is uniquely applicable to negotiating narrow margins between pore pressure and fracture gradient and to drill nearer balanced than conventional wisdom would suggest. Perhaps as important for the GoM, CBHP can address the tendency to err on the heavy side of mud density when drilling into formations with relatively unknown pore pressures, such as sub-salt. This tendency to err on the heavy side of mud density applied to a conventional drilling program is prudent in most cases. However, doing so often results in a grossly overbalanced EMW, which nearly guarantees circulation loss issues are going to be costly and time consuming.
PMCD is designed specifically to get through fractured formations, cavernous voids and other severe circulation loss hazard zones. In this type of drilling, a pre-determined column height of a predetermined viscous mud density is pumped down the annulus of the well. This “mud cap” serves as a barrier to returns to the surface. Then a sacrificial mud - e.g., seawater - is used for drilling. The fluid and cuttings are forced into the very zone that would otherwise have caused severe losses rather than being allowed to return to the surface. There is a significant increase in the rate of penetration while drilling ahead with a much lighter fluid.
DMCD is basically the same as PMCD, except that backpressure on the annular fluid and the height of the annulus barrier can be varied dynamically, usually with no interruption to drilling ahead.
The DDV completes the MPD offering. Set at the bottom of the casing string, the DDV can be closed from the surface after the drillstring is withdrawn far enough to clear it (closing and opening takes about 15 minutes). Closing the DDV eliminates the need to kill the well. Rig time savings can be substantial.
The drillstring can be run out at speed rather than having to be pulled slowly enough not to disturb the wellbore, which in the case of a “breathing” well, can be extremely slow.
