IADC/SPE 136513 Advantages of Managed Pressure Drilling and the Recent Deployment of the Technology in Vietnam Steve Nas / Weatherford Solutions; Ben Gedge and Felbert Palao / Weatherford Vietnam; Nguyen Viet Bot / PetroVietnam Drilling & Well Servcie Corporation
Copyright 2010, IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition This paper was prepared for presentation at the IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition held in Ho Chi Minh City, Vietnam, 1–3 November 2010. This paper was selected for presentation by an IADC/SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the International Association of Drilling Contractors or the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the International Association of Drilling Contractors or the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the International Association of Drilling Contractors or the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of IADC/SPE copyright.
Abstract Managed Pressure Drilling (MPD) is a technology that accurately controls the annular pressure while drilling and completing wells. The intention of MPD is to avoid continuous influx of formation formation fluids to the surface. surface. Any influx incidental to the operation will be controlled and circulated out and an overbalanced condition will be restored. MPD can be used to reduce well construction times, which in today’s high cost rig market is appealing to any exploration, appraisal or field development development team. The MPD technology can, can, to a certain degree reduce drilling fluid fluid related formation impairment, and can through the reduction of the mud weight reduce the cost of mud losses as well as the related non productive time that is spend in curing curing losses. MPD technology is now deployed extensively in the Asia-Pacific Region by many operators, to alleviate a range of pressure related drilling problems. The main applications for MPD include pressurized mud cap to deal with the kick/loss situations in fractured carbonates as well as constant bottom hole pressure systems in wells with narrow pore pressure fracture pressure windows or in depleted reservoirs. This paper is intended to enhance the understanding of the value delivered through the use of MPD techniques, together with recommended equipment equipment designs for each application. Some case studies will be used to quantify value delivery for a range of equipment designs and to better define the operational issues associated with MPD operations.
Introduction Since 2005, over 200 wells in the Asia Pacific Region have been drilled using MPD techniques by a number of operating companies. MPD has delivered direct cost and time savings by eliminating the non-productive time associated with losses and other related well control events. Being able to control wellbore pressures by using a closed wellbore system and introducing the application of some simple techniques has allowed previously “undrillable” wells to be successfully drilled to TD. Operators plan and budget wells for a certain number of days and then find that in the best case some 20% time spent on curing losses and kicks is added to their well times. Yet other operators have encountered losses and well control issues that double or even triple their planned well timings. Exceeding planned well times not only pushes drilling budgets past acceptable limits, but it also has a knock on effect on the rig sequence especially if the rig is shared by other operators in the region. Rigging up MPD equipment has allowed successful drilling of the fractured carbonates on all of the wells where the equipment was rigged up. Not all of the wells encountered losses, and on these wells the equipment was rigged up but not used. On the wells that did encounter the loss / kick scenarios, MPD enabled all of these wells to be drilled to TD without significant delays.
Reasons for MPD The main applications of MPD in Asia Pacific are the drilling of fractured carbonate formations. Total losses are often experienced when fractures and vugs are encountered, and once fluid hydrostatic is lost, gas in the upper part of the carbonate reservoir migrates rapidly to surface, resulting in a well control situation. Once the losses are cured and the well is brought
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under control, drilling resumes until the next fracture is encountered. At that point, the entire process of killing the well and curing losses often repeats itself. Curing the losses with LCM, gunk squeezes or cement can be successful, but very often this has detrimental effects on the productivity of the reservoir. Using underbalanced drilling (UBD) techniques is not suitable as hydrocarbon delivery from a fractured carbonate reservoir can be large and handling large volumes of hydrocarbons, especially on an offshore rig whilst drilling, adds to operational complications. Furthermore, crew size and equipment spread for an offshore UBD operation becomes a further limiting factor in the application of UBD offshore. The ability to drill these wells using MPD techniques has been proven to be highly successful. MPD techniques are now also being applied more and more to all kinds of wells. The emergence of MPD techniques in mature and depleted reservoirs has opened a number of infill drilling opportunities. In the depleted reservoirs the ability to significantly reduce mud weights and still drill the virgin pressured reservoir provides a real advantage. In the High Pressure High Temperature (HPHT) wells, the use of a closed wellbore can eliminate problems such as wellbore breathing or ballooning and influx control. The use of a closed wellbore also allows drillstring movement during well control operations and this eliminates potential stuck pipe incidents.
MPD Techniques A total of four (4) MPD variations have been recognized. These variations are listed as: HSE or Returns Flow Control (RFC) Constant Bottom Hole Pressure (CBHP) Dual Gradient (DG) Pressurized Mud Cap Drilling (PMCD) • • • •
Three further techniques are often mentioned with MPD, but these are considered as sub-categories of the four MPD variations. Floating Mud Cap is considered as a subcategory of the Pressurized Mud Cap technique. Friction Management and Continuous Circulation Systems are both classified as sub-categories of the Constant Bottom Hole Pressure variation.
HSE or Returns Flow Control (RFC) This technique does not control any annular pressure, but it can be considered as an essential part of the MPD definition as we are tooling up to safely and more efficiently react to any downhole surprises. We also positively divert annulus returns away from the rig floor, to prevent any gas, including and especially H2S from spilling onto the rig floor. It is used as a safety measure. If an influx is taken whilst drilling the well, or trip gas or connection gas spills onto the rig floor, the flow line to the shakers is closed and flow is immediately diverted to the rig choke manifold, where the influx is safely controlled and circulated out of the hole. The use of the rotating control device (RCD) avoids the need for the closing of the BOP minimizes the potential for hydrocarbon release onto the drill floor, and it allows pipe movement whilst circulating out an influx or dealing with gas cut mud. Constant Bottom Hole Pressure (CBHP) The constant bottom hole pressure (CBHP) method is used for wells where the bottom hole pressure needs to be accurately controlled to maintain the pressure within a narrow pore pressure and fracture pressure window. As circulation is stopped for connections, the bottom hole circulating pressure reduces as a result of the loss of the annular friction losses or Equivalent Circulating Density (ECD). Using MPD, this pressure loss can be compensated for by trapping surface pressure in the well. Once circulation re-starts, the surface pressure pressure is reduced to take the ECD into account and this keeps the bottom hole pressure constant. Friction Management Friction management techniques are used in HPHT or in Extended Reach wells, where the annular pressure is maintained to keep the bottom hole pressure as constant as possible. In HPHT wells, this is done by maintaining some kind of annular circulation through the use of a concentric casing string. In ERD wells, the annular pressure loss often needs to be reduced to achieve the required length and reach of the well. This can now be achieved through the use of an annular pump. The pump is placed in the cased section of the well and pumps annular fluid back to surface thus reducing the annular friction pressures. These friction management techniques are considered part of the CBHP variation. Continuous Circulation Systems This technique can also be considered under the CBHP variation. It keeps the ECD constant by not interrupting circulation during drilling operations. The method is used on wells where the annular friction pressure needs to be constant and/or to prevent cuttings settling in extended reach horizontal sections of the wellbore. The circulation can be maintained during connections or other interruptions to drilling progress by using a special circulating BOP system or via continuous circulating subs being added to the drill string.
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Dual Gradient (DG) The dual gradient (DG) concept is best known for deepwater applications, where the marine riser is displaced to seawater to avoid the mud column extending all the way from the rotary table to the seabed. Displacing the top of the well to seawater simulates the rig being placed on the seabed; this avoids the high overbalance and the potential loss of circulation. However, any application where a second fluid system is used in the same wellbore can be classed as DG drilling. The DG concept is also applied in many MPD wells where a so called “top kill” is used to control the well. This is where a low density “underbalanced” fluid is used in the bottom of the well and the well is controlled during tripping operations by placing a higher density fluid at the top of the well. No deepwater DG operations have yet been condu cted in Asia Pacific. Pressurized Pressurized Mud Cap Drilling (PMCD) This is the most common MPD method used in Asia Pacific. This method is used to control wells that experience total losses and kicks in the same well bore. The application of pressurized mud cap drilling (PMCD) is widely used in fractured and vugular carbonate reservoirs where total fluid losses are experienced. To use PMCD, total losses must be experienced. To use this technique, the losses must be large enough to take all of the fluids pumped down the drillstring and all of the cuttings generated during the drilling process. If circulation, even partial circulation, was to be established, the mud cap would be circulated out of the well. If circulation is possible, a well cannot use the PMCD method, and the CBHP method will have to be used. PMCD may be practiced in some situations where a total loss scenario is not encountered, but where total losses can be induced by increasing the wellbore pressure profile.
Floating Mud Cap Drilling (FMCD) Floating mud cap drilling (FMCD) is considered as a sub category of the PMCD technique. FMCD operations are used if the annular fluid cannot be designed to provide surface pressure in the annulus, in which case the mud cap is called floating. In an FMCD operation, sacrificial fluid (normally water) is pumped down the drillpipe, as in PMCD. The pressure of the reservoir can be below hydrostatic so that the annulus cannot be kept full of fluid. The annulus fluid level will drop down to a balance point in the well. The top of the fluid in the well may be too deep to monitor and this will make it very difficult to monitor any influx or gas migration. The FMCD method is in effect drilling blind and there is only limited annular pressure control. Some new technology such as wired drillpipe may unlock FMCD techniques by allowing pressure monitoring along the drillstring, thus providing enhanced well control options. Fluid technologies using lightweight solid additives such as glass beads are also being considered considered to achieve mud cap operations when drilling sub-hydrostatically sub-hydrostatically pressured pressured reservoirs.
MPD Requirements Typically, the following main points will need to be considered: Installation of RCD, mainly associated with space requirements between the RCD and the bottom of the rotary table. Return flow line system that allows MPD operations as well as conventional drilling operations MPD choke manifold and gas handling equipment. Marine riser issues for MPD operations on floating rigs It is rare that significant rig modifications are required for MPD operations. On some land rigs, additional space is required between the annular and the rotary rotary table to fit the RCD. This additional space is normally created by raising raising the substructure of the rig. On offshore rigs, the only modifications normally required are the welding of tie-in points for the main flow line to ensure returns can be taken back to the shakers.
Equipment Requirements Depending on the MPD method required, the rig up will vary a little. The RCD is required in all of the operations. The rig Secondary well control equipment should not be used for routine drilling operations. Once that policy is applied the remainder of the equipment requirements are easily identifiable. For PMCD operations, a flow spool is normally installed below the RCD to allow fluid to be pumped into the annulus. The rig up for this set up is shown in Fig 6. The manifold on the left hand side of the RCD is the bleed off manifold that is used to be able to keep the well full from the trip tank. It also allows any pressure to bled off from the stack should this be required when changing RCD packers. For CBHP operations, a separate MPD choke manifold must be installed in the return flow line to allow back pressure to be applied during the drilling process. If a choke is used and surface pressure is to be applied during connections, then the ability to energize the choke by pumping across the wellhead may also have to be incorporated. In critical CBHP operations, a flow meter is often installed as an integral part of the choke manifold to ensure that early kick detection systems can be incorporated in the MPD equipment.
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Well Engineering Requirements Planning for MPD operations is not very complex, but most operators will require some engineering to be conducted on their drilling programs to justify MPD and to gain some assurance that the correct MPD method has been selected. These drilling program requirements requirements normally include: • • •
•
• • • • • • •
A discussion of all drilling concerns and the rationale for using MPD and the selected MPD method. An overview of any non-conventional circulation methods used in MPD, especially when using PMCD techniques. Pressure prognosis plots with pore pressures, fracture pressures and, where possible, overburden and hole stability pressures for all the MPD intervals. A geological description of the well including uncertainties, and the probabilities of large pore and fracture pressure variations. Casing design calculations with safety factors. A proposed schematic and design considerations for the MPD equipment including gas handling equipment. Circulation system design specifications and redundancies used in MPD. Installation and location layout drawings for MPD equipment. Kick detection methods and a well control matrix. MPD procedures that will be used, including pressure test requirements for MPD equipment. Hazard identification (HAZID) / hazard and operability (HAZOP) results.
MPD Projects in Vietnam A number of MPD projects have already been conducted in Vietnam. The main drivers for using MPD in Vietnam are two fold: 1. High fluid losses coupled with gas migration in carbonates. 2. Partial or total losses when drilling the fractured granite basement reservoirs. reservoirs. Cuu Long basin. In the Cuu Long basin the normal procedure is to fill the annulus with seawater when losses occur. However, periodic gas migration to surface is still experienced even with high annulus injection rates. The use of a Rotating Marine Diverter Insert (RMDI) allows continuous drilling while diverting the gas. The Marine Diverter Insert enables the existing marine diverter on a jackup rig to function as a rotating control device. It seals off the well bore and allows fluid and gas to be diverted below the rig floor without the need to close the annular preventer. Nam Con Son Basin In the Nam Con Son Basin, offshore Vietnam an MPD package was installed to drill through the Nam Con Son Limestone formation. A previous well drilled the same formation with severe losses and associated gas migration problems and experienced as a result high NPT was experienced to cure the problems. The MPD package was rigged up as insurance to enable switching to PMCD when severe losses are encountered. Losses encountered during drilling the limestone were as high as 400bbls/hour, but the losses were cured with LCM and it was not required to switch to PMCD. The MPD package was an insurance solution. If the same problem of massive losses and gas migration in previous wells had occurred in this well, a ready solution would have been available to enable drilling to proceed without any delays.
Ca Ngu Vang Field Managed Pressure Drilling was used on a six well development program in the Ca Ngu Vang Field. The primary objective was to drill the fractured granite basement reservoir. The first three wells in the development program encountered high loss rates when drilling the basement reservoir. This resulted in very high brine and salt cost and a suspension in drilling operations due to the interruption of brine and salt supply especially during the monsoon season, and the inability to drill to planned depth once the loss rate exceeded the rig’s mud mixing capacity. Basement Interval m
Brine Density ppg
Loss Rate bbls/hr
Total Brine losses bbls
4,084 - 6,123 4,975 - 6,330 4,100 - 5,477
9.6 - 9.8 9.6 - 10.4 9.8 - 10.2
20 - 160 20-60 40 - 250
55,000 19,000 137,000
Time Associated with well control issues Hrs 298 82 197
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The application of MPD technology was sought as a solution to the brine management problem. The fluid loss rate in the granite basement was a direct proportion of the amount of overbalance to the formation, the use of the MPD equipment allowed the brine weight to be reduced and therefore reduce the fluid loss rate. The MPD system was designed for drilling with a significantly lighter fluid and holding surface pressures during connections. The well is drilled overbalanced with the brine weight controlled so that the ECD at drilling rates (450-600gpm) is slightly above the formation pressure. The amount of overbalance is minimized to reduce the fluid losses to the formation. During connections, the flow line valve is closed and surface pressure is applied at the RCD to compensate for the loss of annular friction pressure. This was achieved by pumping fluid slowly down the kill line. MPD was first used during drilling of the reservoir section for the 4th well in the field development program. Using MPD in the reservoir reduced the ECD by 350psi or 0.4ppg equivalent (compared to conventional drilling), which resulted in significantly reduced drilling fluid losses. A comparison was conducted to optimize the MPD program Brine weight 9.7 ppg 9.8 ppg 10.0 ppg
Losses Static losses 35 bbls/hr Static losses 60 bbls/hr Static losses 95 bbls/hr
Brine weight ppg 9.8 ppg 9.8 ppg 9.8 ppg
Circulating Rate gpm 350 gpm 450 gpm 550 gpm
Losses bbls/hr Dynamic Losses 95 bbls/hr Dynamic Losses 110 bbls/hr Dynamic Losses 120 bbls/hr
The comparison indicated that the loss rates were almost liniar with the pressure applied to the bottom of the well. With the RCD installed the fluid weight was reduced to 9.2 ppg with a final dynamic loss rate of 6% of the total fluid rate as compared to a loss rate of 15 to 20% of the total fluid rate without the RCD installed. The loss rate at 9.2 ppg represents a total loss rate of some 1200 bbls/day as opposed to a loss rate of 4000 bbls/day without the RCD installed. The latter loss rate being an unsustainable loss rate based on rig mixing and brine supply capacity. The limit for brine supply to the rig based on the earlier wells was established at 2500 bbls/day. Further benefits that were realized were efficient hole cleaning and a subsequent reduction in torque and drag. With the higher flowrates, hole cleaning efficiency improved and the final trip out of the hole encountered significantly less drag. The penetration rate increased but there are too other many factors, such as bit type and formation issues to conclusively compare brine weight with penetration rate improvements. In the previous wells two shocksub failures were encountered. The chromium plating on the mandrell of both tools failed, which was possibly a result of the relatively high chloride environment while drilling. A reduction in brine density also means a reduction in chlorise concentration, which could lead to a reduction in tool failures. Only one bit run was made with the RCD in place and therefore only the final trip out of the hole was made with the bearing assembly and seal in place. After killing the drillstring with 10 ppg brine, the drillstring was stripped back from TD at 6526m to above the last shoe. It was intended to start pumping trip weight brine at 9.8 ppg down the annulus whilst stripping. The stripping operation was trouble free and this increased the confidence that stripping could be accomplished without the need to pump thus realizing further brine savings. Well Clean up was a short operation and this was accomplished in just 18 hours before a stable flow was achieved. Nitrogen lifting operations were not required, plus the well clean up benefitted from the reduction in brine volume lost and the lower mud weight used to drill the well. This allowed the rig to d rill deeper than any previous wells. The well reached a depth o f 6,526m, the deepest basement well to date in Vietnam. The operator also realized a much faster well clean up due the reduction of the drilling fluid lost to the formation.
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The objectives of MPD in a fractured basement were realized with the ability to drill the well to target using less time. The more efficient hole cleaning resulted in lower torque and drag and resulted in a much faster cleanup prior to handing the well over to production. The subsequent 5th and 6th well in the development program also drilled the granite basement using the MPD system, with similar successful results.
Conclusions Knowing what kind of MPD is required is one the most important lesson learned in the many wells drilled in Asia Pacific. Rigging up for CBHP using an RCD and a choke manifold and then finding out that with total losses, PMCD operations are required causes significant delays, as now a flow spool and the associated hoses will be required to pump fluid into the annulus. The opposite applies to PMCD operations where losses are only marginal. Now the mud cap cannot be maintained and it may be that a CBHP system with a choke manifold is required. Gate valves cannot be opened with pressure, so rigging up for flow control and finding that when the flow line gate valves are closed for a connection, surface pressure builds up, causes issues with opening the system without going through the rig choke manifold. Rig alignment and drillpipe condition are all important for RCD rubber life. Stripping 20,000 ft of drillpipe through a set of dual rubbers is possible if the rig is aligned and the drillpipe i s in good condition and surface pressures are kept low. Plugging of the 6 in return line and valves is often raised as a concern, yet this has not occurred in any of the operations conducted. Even when drilling larger hole sizes, these return lines can be used. Rig modifications for most MPD operations are minimal. The tie in of the return flow line to the shakers is the most complex modification that is normally required. On some rigs, additional tie-ins to the standpipe manifold need to be made, but existing tie-in points often exist and are used. The main modifications required are often additional sub bases on land rigs to raise the rig high enough to accommodate the RCD. MPD operations have been conducted on all types of rigs with minimal down time caused by MPD equipment. MPD operations have resulted in considerable savings by enabling drilling to continue in a kick loss scenario or in wells where well control issues occur at almost every connection. Drilling with a closed wellbore and simply allowing pipe to be rotated when killing a well and by so doing, avoiding stuck pipe can already result in large savings.
Glossary BOP Blow out Preventer CBHP Constant bottom hole pressure DG Dual gradient ECD Equivalent circulating density ERD Extended Reach Drilling FMCD Floating mud cap drilling H2S Hydrogen Sulphide Gas HAZID Hazard identification identification study HAZOP Hazard operability study HPHT High Pressure High Temperature HSE Health, Safety and Environment LCM Lost Circulation Material MPD Managed Pressure Drilling PMCD Pressurized Mud Cap Drilling RCD Rotating Control Device RFC Returns Flow Control TD Total Depth UBD Underbalanced Drilling
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References Terwogt. J.H, Mäkiaho. L.B, van Beelen. N, Gedge. B.J, Jenkins, J. 2005 Pressured Mud Cap Drilling from A Semi-Submersible Drilling Rig. SPE paper 92294 presented at the SPE/IADC Drilling Conference, 23-25 February 2005, Amsterdam, Netherlands. Managed Pressure Drilling Projects. 2008. NTL No 2008-G07. United States Department of the Interior Minerals Management Service Gulf of Mexico Region. Hannegan. D, Fisher. K, Managed Pressure Drilling in Marine Environments. IPTC paper 10173 presented at the international Petroleum technology Conference held in Doha, Qatar 21-23 November 2005. Hannegan. D. Case Studies--Offshore Managed Pressure Drilling. SPE paper 101855 presented at the SPE Annual Technical Conference and Exhibition, 24-27 September 2006, San Antonio, Texas, USA. Kozicz. J. Managed-Pressure Drilling—Recent Experience, Potential Efficiency Gains, and Future Opportunities. SPE paper 103753, presented at the IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition, 13-15 November 2006, Bangkok, Thailand. DOI : 10.2118/103753-MS Nas, Steve, Wuest, Chad, Toralde, Shaun, Offshore Offshore Managed Pressure Drilling Experiences Experiences in Asia Pacific, SPE paper 119875 presented presented at the SPE/IADC Drilling Conference and Exhibition held in Amsterdam, The Netherlands, 17–19 March 2009
Figures
Fig 1. RCD with drilling nipple to allow conventional drilling returns
Fig 2. MPD rig up for Returns Flow Control
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Fig 3. Rig up for Pressurized Mud Cap Drilling operations
Fig 4. Rig up for Constant Bottom Hole Pressure applications
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Fig 5. Riser Cap
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TM
installation
Fig 6. Rotating Marine Diverter Insert
Fig 7 PMCD-RCD 7800 Rig Up on the Jack-up Rig WillBoss
Fig 8 PMCD-RCD 7800 Rig Up on a Semi-Submersible in Vietnam
