SPE-112662-MPD_GoM.pdf

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Copyright 2008, IADC/SPE Drilling Conference

This paper was prepared for presentation at the 2008 IADC/SPE Drilling Conference held inOrlando, Florida, U.S.A., 4–6 March 2008 . This paper was selected for presentation by an IADC/SPE program committee following reviewof information contained in an abstract submitted by the author(s). Contents of the paper havenot been reviewed by the International Association of Drilling Contractors or the Society ofPetroleum Engineers and are subject to correction by the author(s). The material does notnecessarily reflect any position of the International Association of Drilling Contractors or theSociety of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, orstorage of any part of this paper without the written consent of the International Association ofDrilling Contractors or the Society of Petroleum Engineers is prohibited. Permission to reproducein 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.

Abst ractShell Exploration & Production Company continues toexecute redevelopment slim hole sidetracks using ManagedPressure Drilling (MPD) on the Auger TLP in Deepwater Gulfof Mexico. Four sidetracks have been successfully drilledutilizing a Dynamic Annular Pressure Control (DAPC) systemto eliminate lost circulation and borehole instability events.

Execution of MPD continues to improve, resulting inoperational efficiency gains and allowing access to previouslyunattainable reservoir targets. Intervals previously consideredimpossible to drill due to depletion induced frac gradient

reduction are being drilled and cased trouble free with MPD.

Recent MPD well designs have incorporated reduced staticmud weights below pore pressure to manage the availabledrilling margin. Bottom hole pressure variation from thedefined set point has been reduced and excursions outside ofthe target pressure window are being eliminated duringsubsequent MPD well operations.

Auger’s field redevelopment history, well designs andManaged Pressure Drilling designs will be reviewed.Execution of MPD operations will be addressed in detailfocusing on engineering and operational improvements

throughout the four MPD sidetrack campaign.

IntroductionThe Auger Tension Leg Platform (TLP) is Shell’s firstdeepwater development located in the Gulf of Mexico (GOM).The TLP is moored in 2860 feet of water on Garden Banks

block 426 and began production in 1994. Production hassurpassed five hundred million barrels equivalent from fivemain reservoirs, yielding reservoir pressure depletion inexcess of 5000 psi from initial conditions.

Common in mature fields, drilling challenges change with theintroduction of reservoir pressure depletion. Rock mechanicsanalysis has concluded that the depletion at Auger results infracture gradient (FG) reduction due to redistribution ofstresses in both the sands and shale overburden. The depletioninduced fracture gradient reduction becomes a key componentin narrowing the available drilling margin.

Borehole stability must be maintained for the shaleoverburden and virgin pressure sands. In conventionaldrilling, borehole stability is achieved solely with thehydrostatic pressure of mud density. The challenge of areduced fracture gradient is further compounded inredevelopment sidetracks when the existing well geometryyields higher annular friction pressure, or equivalentcirculating density (ECD), than during original developmentdrilling. Increased ECD in conjunction with original muddensity requires the need to have a larger drilling margin, thusconflicting with the tighter margins created from depletion

The opportunity of redevelopment drilling is maintaining production rates from normal decline while adding reserves

from unique drainage points. Previous redevelopmentsidetrack campaigns at Auger conducted between 1999 and2002 resulted in a success rate less than 30%. Only 2 of 7sidetrack attempts on three well slots were successfullydrilled, cased and completed. The resultant trouble time andcost necessitated an in-depth review and ceasing of futuresidetrack drilling.

Figure 1 illustrates the days versus depth curves of the previous redevelopment sidetrack campaign. Post wellreviews conclude lost circulation events as the root cause tothe failed sidetracks. Common operational events noted onthe sidetracks include ballooning, control drilling, tight spots,

pack offs and mud weight reduction. These events reaffirmthe tight drilling margin challenge in which the combination ofmud weight and resulting drilling ECD is larger than theavailable drilling margin.

Managed Pressure Drilling was identified as the technology tomitigate the challenges of the tight drilling marginenvironment. The MPD system utilized on Auger providesautomated control of surface applied backpressure enablingreduction of surface mud weight to control the ECDmagnitude and maintaining a constant bottom hole pressurethroughout the drilling process.

IADC/SPE 112662

Managed Pressure Drilling Success Continues on Auger TLPMark J. Chustz, Shell E&P; Larry D. Smith, Signa Engineering Corporation; and Dwayne Dell, At Balance Americas LLC

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MPD SolutionA proactive application of MPD was taken on Auger toimprove execution of redevelopment drilling by eliminating

borehole trouble events and ultimately enabling access to previously unattainable reservoir targets. The MPD approachof constant bottom hole pressure (CBHP) seeks to maintainthe same pressure on the borehole during all phases of the

drilling process, including pumps on, pumps off or whiletripping. When one variable of the drilling system causes theBHP to increase or decrease, other variables have to becontrolled to offset that change.

The Auger MPD solution enables reduction of surface mudweight based on resulting ECD while at drilling flow rate.The MPD method of CBHP is executed with additionalsurface equipment used to convert the wellbore into a closedsystem for the drilling process. Application of surface

backpressure is performed to compensate for the reduction of bottom hole pressure from mud weight reduction and anyoperation during the drilling process. Formation flow, orinflux, is avoided in the offshore MPD operations due to lackof surface equipment to handle any flow.

Various components of the drilling system must be understoodand managed to accomplish CBHP. Key components includeannular surface pressure, drilling fluid density and rheology,cuttings loading, annular friction, hole geometry, drill piperotation speed and tripping speed. While variables such ascuttings loading (rate of penetration, ROP), drill pipe rotation(revolution per minute, RPM) and mud rheology can beadjusted to make small changes in bottom hole pressure,application of annular pressure using DAPC to replace loss ofannular friction is the most significant and the most importantkey to a successful MPD operation.

Figure 2 illustrates the breakdown of the bottom hole pressurecomponents while drilling and when executing a MPDconnection. Surface mud weight is adjusted to obtain thedesired ECD in drilling mode, and the MPD set point isaccomplished with surface backpressure on the boreholeduring a connection. The MPD connection set point is slightlyless than the drilling ECD to provide a safe tolerance forvariation in applied backpressure.

The operational risks introduced with MPD are either over pressure or under pressure events. Over pressure eventswould exceed the fracture gradient and induce ballooning or

lost circulation. Under pressure events include those whereBHP reduces below borehole stability or pore pressureresulting in hole collapse or an influx. Hazard identification isthe critical planning component of the MPD system design todevelop reaction plans for safely avoiding and securing thewell in these type events.

Analysis of the additional cost of MPD operations faroutweighs the recovery cost of lost circulation, a possibleredrill, and the associated deferred production from boreholetrouble events.

MPD Well DesignWell design starts with the definition of the pressure regimefor the section to be drilled. Formation pore pressure, fracture

pressure and borehole stability data are developed by the assettechnical team based on previously acquired data in the fieldincluding drilling offset data, reservoir pressure data,

petrophysical data and geophysical data. This data is

reviewed and agreed on, after which it is used by the drillingengineers to design the drilling bottom hole pressure windowfor each interval. At Auger, because of field reservoir

pressure depletion, this drilling window becomes narrow,which is the driver for using the CBHP technique of MPD.

In order to successfully drill the Auger slim hole sidetracks,the interval design must maintain the bottom hole pressurewithin a 0.5-0.8 ppg window as defined by the minimum BHPrequired to maintain stability and prevent hole collapse whilestaying less than the BHP required to be below fracture

pressure and mud losses. However, circulating ECD in theslim hole sidetrack geometry ranges from 1.0-1.4 ppg greaterthan the static surface mud weight, largely depending on drill

pipe design. Static mud weight must therefore be reduced toor slightly below maximum pore pressure and belowminimum stability pressure to drill the intervals.

By using DAPC to add annular pressure equivalent to theannular friction component of the BHP, or 500-600 psi, whichis lost when pumps are shut down for connections, BHP can

be held near constant and maintained within the narrowoperating pressure window.

Hydraulics modeling is critical for the MPD well design.Multiple cases are modeled during the design phase todetermine optimum circulation rate, standpipe pressure andannular velocity. Whereas the primary objective is tominimize ECD, there are trade offs in order to stay withinstandpipe pressure limitations and to ensure adequate cuttingsremoval from the wellbore. Multiple sensitivities are run inorder to clearly understand the impact of ROP, RPM andcirculation rate at different values and how they affect ECD.

Hydraulics analysis continues during drilling operations predicting BHP results prior to making changes in drilling parameters. Adjustments are often made based on real timedrilling data in order to safely maintain BHP within thedesired operating window.

Mud rheology is an important element in the design and, sinceit is impractical to significantly change rheology duringexecution, the issue must be accurately addressed during

planning. Due to the slim hole geometry, mud rheology has avery significant impact on annular friction and, ultimately, thedecision on required surface mud weight to provide a drillingECD within the available drilling margin.

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Low shear rate viscosity measurements are morerepresentative of drilling annular velocities and greatly effectannular friction losses. Trade offs on mud rheology controlmust be managed to minimize annular friction while still

providing for adequate wellbore cleaning and baritesuspension. Previously used weighted synthetic based mudsystems typically had 3-6 RPM readings ranging from 18-22.

These levels address hole cleaning and barite sag, but also leadto significant annular friction losses in slim well geometries.

To address the higher than desired annular friction losses, anew synthetic mud system was selected at Auger with lowshear viscosity ranging from 10-12. This system was uniquein that it used a specific barite particle size allowing rheologyalteration to reduce ECD by 0.4-0.6 ppg and standpipe

pressure by 500-800 psi, yet still adequately addressing holecleaning and barite sag.

The previous discussion addresses BHP design during drilling;however, and equally as critical, is maintaining the same BHPduring tripping. First, the open hole must be conditioned andadequately cleaned prior to tripping. For holes with anglesgreater than 35 degrees, which is generally the case at Auger,several circulations are made with pipe rotation to remove thecuttings bed layers from the hole. After the hole is adequatelycleaned, a higher mud density must be placed in the hole toaccount for the reduced mud weight plus a trip margin. Thiscan be done in a single stage or in multiple stages dependingon the particular BHP window.

The bottom hole pressure is held constant during thecirculation of higher density mud by adjusting circulation rateand pipe rotation speed as the heavier density mud moves upthe annulus and replaces the lighter density fluid that wasoriginally in the hole. A circulation rate schedule is preparedwhich factors in the differing annulus fluid gradients, thelowering of ECD as circulating rates are reduced and changesin wellbore geometry. By following an accurately preparedschedule, the increased mud density can be placed and the

bottom hole pressure held constant.

When designing the trip mud densities, swab modeling isconducted and mud density increased accordingly tocompensate for BHP reduction from drill pipe swab effects.Recorded pressure while drilling (PWD) data is used fromeach drilling assembly trip to validate swab models and

provide valuable learning to subsequent wells. For multiple

stage weight ups, the MPD system is used to hold backpressure for pulling out of open hole to compensate forswab and any additional hydrostatic required on the secondincrease, typical performed once back in the cased hole.

It becomes significantly more difficult to manage the BHP if backreaming and pumping is required to trip out. Pack offscan occur resulting in the loss of ECD above the pack off,which can lead to BHP loss across unstable formations andhole collapse. Losses can occur, which when initiated,

preclude the use of MPD techniques due to the loss of ECD.

MPD System DesignFor slim hole sidetracks conducted inside the existing

production casing, Auger utilizes a surface BOP stackinstalled on top of a dual barrier production riserconfiguration. Even though TLP movement is minimal, a slip

joint and ball joint are required below the rotary table to tie therotary housing to the BOP stack. Doing so provides alignment

over the stack and addresses environmental concerns bydiverting any rotating control device (RCD) element mudleakage into the existing return mud flowline.

To meet the above design requirements, an internal bearinghigh pressure RCD was modified to provide a sealed topflange to which the bottom receiver of the slip joint could beconnected providing the transition to the slip joint overshot,

ball joint and rotary housing assembly. The RCD element isinstalled and retrieved through the assembly and the standardrig mud return system used in the event of element leakage orwhen the element is not installed.

The Dynamic Annular Pressure Control (DAPC) system isautomated and operates to maintain a constant bottom hole

pressure at a programmed BHP set point. It is designed tomanage pressure whether drilling, making a connection, ortripping. For Auger the system was programmed to maintainconstant BHP during connections and tripping. Backpressurewas not held while drilling ahead as the designed flow rate

provided adequate ECD for borehole stability.

The DAPC system utilized on Auger consisted of three major pieces of equipment: a choke manifold, a backpressure pump,and an Integrated Pressure Manager (IPM). Under the controlof the IPM the choke manifold makes continuous

backpressure adjustments to maintain the BHP at the programmed set point. Precise BHP control is accomplishedusing continuous flow into the choke manifold from the

backpressure pump while the rig pumps are off.

The DAPC choke manifold consisted of two primary 4”hydraulic choke legs and one 2” secondary hydraulic chokeleg. Under normal operation only one primary choke is active,with the other acting as backup. The backup 4” choke leg was

programmed for static high-level pressure relief to protect thewellbore against over pressure events. Figure 3 shows theMPD flow schematic for while drilling.

All three chokes are hydraulically gear driven position chokes

activated by a hydraulic power unit (HPU) mounted on themanifold. Another redundant feature of the manifold allowsthe HPU to be powered from multiple sources in case ofmalfunction or failure. Primary power is supplied by anelectric motor and secondary power by the rig air supply. Inthe unlikely event both fail, then manual power is available byrecharging the designated accumulators while still maintainingthe programmed BHP set point under automated control.

The second component of the DAPC system is the backpressure pump. Similar to the choke manifold, operationis under full control of the IPM. The pump provides adedicated, on-demand supply of backpressure whenever the

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rig pump drilling flow rate drops below a defined threshold.This is accomplished by delivery of a steady flow of mud intothe choke manifold providing the ability to actively stabilizeBHP during connection transitions, from rig pumps-on to rig

pumps-off and back. BHP can also be increased or decreasedduring a connection by simply changing the set point in theIPM. Figure 4 shows the MPD flow schematic during a

connection.

Measurement, monitoring, analysis, and control are allintegrated into the third component of the DAPC system, theIntegrated Pressure Manager. The IPM consists of a controlcomputer, a programmable logic control system, a real-timehydraulics model, and data communications network.Together these provide the automated software control anddata acquisition necessary to maintain constant bottom hole

pressure through the DAPC choke manifold. A humanmachine interface (HMI) provides the means for a controlsystem technician to configure and adjust the operation of theIPM and the entire DAPC system.

Accurate BHP control requires a steady stream of accuratedata. The IPM relies on this stream of data to maintain itsaccurate control of the BHP throughout the drilling interval.Regularly updated drilling parameters and real-time data fromthe PWD tool are transmitted over a data communicationsnetwork to the IPM. Of particular importance is the rig pumpstroke counter, which is a crucial parameter for the operationof the DAPC system.

The Integrated Pressure Manager uses the pump strokes as its primary indicator that the pumps are working, mud is flowing,and that there is annular friction in the wellbore. Twoindependent rig pump stroke counters are used to reduce thechance of data interruption or mechanical failure and ensurean uninterrupted supply of data. The IPM is programmed toalert the system technician if one of the stroke counters wentdown or showed erratic flow allowing a manual switch to thealternate sensor.

As a contingency, in the event that all rig data beingtransmitted was severed the control system technician couldmanually enter the stroke rate. The hydraulics model runscontinuously to provide the IPM with the necessary calculateddata to maintain the set point. Using the model and themanually entered stroke rate, the IPM will still generate therequired DAPC system configuration and continuously control

the BHP.

Installed downstream of the DAPC choke manifold is a massflow and density meter providing measurements of all flowgoing through the system. The meter is installed in a manifolddesigned for quick change out in the event of plugging ormalfunction. Continuous flow out measurement is graphicallycompared with rig pump flow in to detect formation influx ordownhole losses. The density measurement monitors gaslevels in returns and provides quick detection of return muddensity when weighting up or cutting back the mud system.

Engineering ImprovementsDownhole pressure fluctuations will occur in every MPD well.In order to maintain a constant BHP set point, the IPM is

programmed to control fluctuations within a specified safeoperating tolerance spread. Initially the BHP allowabletolerance was required at +/-0.3 ppg but as improvementswere made to the system the variability was reduced down to

+/-0.2 ppg of the set point.

A significant improvement made to the DAPC systeminvolved BHP control directly through the active primarychoke. In the original IPM version, mud return from the wellflowed through one of the primary choke legs while the

backpressure pump flowed through the secondary choke leg.This early IPM version used the secondary choke to manage

backpressure during a connection while the primary chokelegs were closed and inactive. While effective and reliable,the rig pump transition during a connection required anextended transition from primary to secondary choke control.The process requires dynamic equalization of line pressure

between the primary and secondary legs prior to transferring backpressure control. Each connection requires the DAPCsystem to perform numerous simultaneous control operationswhich include starting the backpressure pump, dynamicallyclosing the 4” choke and adjusting the 2” choke as rig pumpflow rate is altered, and then opening the isolation valve

between the legs once pressures were equalized. This processincreases connection time due to the steps necessary to makethe transition. The change to backpressure control through theactive primary choke resulted in MPD connection time equalthat of a conventional drilling operation and improvedaccuracy in BHP control.

The modification of backpressure control solely through the primary choke also enabled the secondary choke to be utilizedfor protection against over pressure events. This newcapability allowed the DAPC system to manage the pressurerelief operation and eliminate potentially damaging pressurespikes caused by standard open or close type relief valves.The new IPM control function for the secondary choke

provides the ability to track the increase and decrease ofsurface backpressure during a connection while providing avariable relief mechanism.

On the first two wells at Auger, the mass flow meter returnmeasurements were often times inconsistent and erratic.Possible causes identified included improper meter sizing,

upstream surging through the DAPC choke, deck vibration,upstream piping configuration and meter installationorientation. Subsequently, the flow meter manifold wasredesigned to address many of the issues. Meter orientationwas changed from vertical to a horizontal position. Inlet

piping was straightened and hoses replaced steel lines tominimize vibration transmitted from the upstream anddownstream systems. The meter size was reduced from 4” to3” and the meter was positioned further from the DAPCchokes. Deck vibration was also addressed by modificationsto the bottom of the meter skid. Ultimately, meteringaccuracy was improved to within 2-3% of downhole

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circulation rate resulting in improved monitoring of the MPDoperation.

Previously discussed in the well design section was thedisplacement of heavier density mud in the hole prior totripping. Essentially only two parameters are available tomanage the BHP, mud density and circulation rate. As

heavier mud is being displaced, the annular friction is adjusted by reducing downhole pump flow rate to maintain a constantBHP. Constant BHP is easily maintained when using adownhole PWD tool to measure real time BHP; however,MWD signals are lost at reduced circulation rates.

On the initial Auger wells, approximate calculations weremade and downhole circulation rates were reducedaccordingly once the PWD signal was lost. Analysis of therecorded PWD data concluded that BHP was maintainedwithin 0.2 ppg. Unfortunately the 0.2 ppg was above theminimum fracture gradient and seepage losses did occur.Improvement was required and was accomplished by

proactively preparing a circulation rate schedule accountingfor hole geometry changes and annular friction losses based onactual hydraulics modeling. Results from recorded PWD ofthe latter weight ups revealed that constant BHP wasaccomplished with a 0.1 ppg fluctuation within the pressurewindow.

Written MPD procedures are necessary to ensure a properlyexecuted plan. Initially, procedures were prepared forcalibration of MPD equipment, MPD operations equipmenttesting inside casing, making connections, calibrating rig

pumps, and changing out RCD elements. As the drilling program progressed, these procedures were refined for eachwell based on operational experience and understanding of theMPD system.

Of significant importance was the refinement of the RCDelement change out procedure and the addition of a detailedwell control shut in procedure. Unplanned events wereoccurring when changing out elements leading to excursionsof BHP both on the high side and low side. It was determinedthat the root cause of these mishaps was a lack of sufficientdetail in the element change out procedure. Without thisdetail, each change out was being performed using differentapproaches for holding surface pressure during the operation.This inconsistent approach led to confusion for the operational

personnel responsible for performing the operation. Detailed

discussions led to the preparation of a standard detailed procedure that was consistently followed. In turn, theunacceptable BHP excursions were completely eliminated.

Addressing well control procedures, MPD provides the abilityto almost instantly increase bottomhole pressure to stopadditional influx from occurring. Upon detecting an influx,annular pressure can quickly be added to a level ranging up toa safe margin below anticipated minimum fracture gradient.BHP pressure can be immediately increased with the DAPCsystem to stop the influx. This can be done either whiledrilling at full circulation rate or when ramping down the

pump to zero by adding the same incremental pressure to

pressures used during the connection pump ramp downsequence. Shut in procedures were prepared reflecting theability to add pressure while ramping down the downhole

pumps prior to shutting the BOP. Since an influx can quickly be eliminated prior to shutting in of the BOP stack, animprovement exists in comparison to taking additional influxduring a shut in on conventional drilling operations.

Execution ImprovementsUnderstanding MPD fundamentals and how to react tounplanned events form the foundation MPD training fordrilling personnel. An initial orientation was provided thedrilling crews in a classroom setting to provide a basicunderstanding of MPD concepts and how they specificallyapplied to Auger slim hole drilling.

The most difficult aspect of MPD training is ensuring the wellsite drilling personnel develop a high confidence level thatthey, without hesitation, can accurately respond to unplanneddrilling events. A real time operational approach to providethis training was taken. MPD engineers provided 24 hour perday rig floor coverage to supervise the operation, but evenmore important, to continuously discuss the “what if”

possibilities with each crew. As different situations aroseduring drilling operations, actual or potential reactions tounplanned events were discussed in a real time operationalsetting. These discussions repeated themselves on a daily

basis and MPD quickly became second nature to the well sitedrilling personnel. Unplanned events were minimal for theAuger program, but when there was an occurrence, the correctreaction was taken to safely secure the well. This is anoutstanding achievement for the drilling team and supports thetraining philosophy.

MPD equipment rig up time was significantly reduced afterthe initial well. Due to deck space and load limitations, eachwell required rig up and rig down of all of MPD equipment.Approximately 600 feet of 2” and 4” steel piping was requiredfor the rig up. Prior to rigging down from the first well, all ofthe piping was coded and photographs taken of the equipmentlayout. On subsequent wells the configuration was thenreinstalled accordingly, resulting in only a fraction of the rigup time.

RCD installation was performed off line while the BOP stackwas on the stump then set on the well as one unit. Doing so

eliminated use of critical path time for the RCD installation.Additionally, the piping layout was improved to enable testingof the on deck MPD equipment without the RCD. Thisreduced testing once the RCD element was installed.

The DAPC system is calibrated at the beginning of every joband prior to the commencement of MPD operations. Thisoperation tunes the DAPC chokes for optimum performance atzero and max flow rates as well as defines the connectionramp up and down sequence. On the initial well a dedicatedcalibration trip was made in casing prior to exposing openhole. Training of the well site drilling personnel was also

performed during this trip to provide the critical knowledge of

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all the MPD operations. Due to the improvements made in thecalibration procedure, the DAPC system calibration wascombined with the milling trip in subsequent wells. Inaddition, by eliminating the calibration trip the time requiredfor calibration and training was significantly reduced.

A backup to the DAPC backpressure pump was incorporated

for risk mitigation and system reliability. The drilling flowrates of the Auger slim hole sidetracks only required one ofthe three rig pumps. On the initial well, a dedicated rig pumpwas used as backup but required manual valve manipulation

before it could be routed into the DAPC manifold inlet. Anautomated valve was incorporated and programmed into theIPM allowing immediate use of the rig pump to provide thecontinuous flow into the choke manifold. Several connectionswere successfully made using the backup rig pump when theDAPC backpressure pump was out of service.

Without the proactive involvement of the drilling rig personnel, success at Auger would not have been possible.MPD drilling requires a mindset that is willing to adapt. Newapproaches to performing old tasks have to be accepted. TheAuger rig personnel not only were willing to adapt, theyembraced the new technology and took ownership.

Continuity of the drilling team was vital for success on theAuger MPD wells. Crews that started the first well finishedthe last well. MPD drilling evolved from being confusing to

being normal. MPD operations were seamless and fullyintegrated with support and involvement from management,engineering, rig supervision, rig crews and service providers.Auger MPD was truly a TEAM effort.

ResultsThe proactive application of MPD on Auger achieved constant

bottom hole pressure control throughout the drilling process tomanage the tight drilling margins created from redevelopmentdrilling challenges of:

• Depletion induced fracture gradient reduction within producing intervals and shale overburden.

• Adequate bottom hole pressure required for boreholestability & well control of virgin formations.

• Increased annular friction pressure of drill pipe by casinggeometry yielding excessive equivalent circulatingdensity (ECD) over surface mud density.

To date on Auger, over 10,000 ft has been successfully drilledon four sidetracks without lost circulation or formation influxutilizing an automated MPD system. In total, this representsover 140 pump cycles in which 99% of the automated cycleswere performed within the set point tolerance. The majorityof the over and under pressure events outside of the set pointrange were during manual BHP control operations when usingthe blow out prevention equipment, such as RCD elementchange out.

Table 1 summarizes the four redevelopment sidetracks drilledwith MPD on Auger, including description of the available

pressure window, actual mud weights, MPD set point, footagedrilled, number of MPD pump cycles and weight up method.

The A-18 ST3 well was the first Auger MPD well in theredevelopment campaign. The target was an up-dip location

in a virgin pressure reservoir fault block. The requiredsidetrack depth, however, was above a known depletedreservoir, thus presenting the risk of lost circulation if drilledwith conventional mud weights and the expected drillingECD. The sidetrack was drilled with surface mud weightreduction of 0.4 ppg effectively reducing the drilling ECDsafely below the minimum fracture gradient. The mud weightutilized still provided primary well control but was less thanthat required for borehole stability. MPD was successfullyused to mitigate lost circulation risk and to further prove upthe system for additional surface mud weight reduction to

below pore pressure for tighter drilling margin wells.

The second Auger MPD well, A-8 ST1, targeted atticlocations of two depleted reservoirs. Previously determinedun-drillable due to the available drilling margin of 0.8 ppg andexpected ECD of 1.0 ppg over surface mud weight, the MPDsystem allowed surface mud weight reduction of 0.5 ppg forthe sidetrack. The surface mud weight was 0.2 ppg below

pore pressure for the deeper half of the interval. This well wassuccessfully drilled, weighted up and cased without either alost circulation or influx event by maintaining a constant

bottom hole pressure with the MPD system.

The third sidetrack, Auger A-13 ST3, was added to thecampaign after successful execution of A-8 ST1. It alsotargeted a severely depleted up-dip target while also having to

penetrate three additional depleted zones in the interval. Thiswell comprised of the tightest available drilling margin of 0.6

ppg at TD through the target. The surface mud weightapproach varied from the previous wells such that mud weightwas reduced by 0.3 ppg while drilling the section. This wasrequired due to the trip mud weight needed at the kick offdepth after the window milling operation. The TD mudweight was equal to known pore pressure at the sidetrack kickoff point. The zone was uneconomical and the hole wasweighted up and plugged for an immediate geologicalsidetrack.

The fourth Auger MPD sidetrack, A-13 ST4, had the same

available drilling margin as ST3. Again, the mud weight wassuccessfully reduced by 0.4 ppg while drilling the interval andreached TD with surface mud weight 0.1 ppg less than pore

pressure. Commercial pay was encountered and the well wasweighted up and cased for completion.

Borehole trouble events caused from lost circulation orstability were completely avoided in the four MPD sidetracks.The latter two wells added otherwise unattainable reserves and

production by utilizing the DAPC system.

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Consistency of personnel was the key to improvements madewith the MPD system and to the success of each subsequentsidetrack. Specific operational improvements are summarizedas follows from the first to last well:

• MPD equipment rig up time became 100% offline afterthe first well

• Online pressure testing of the MPD system reduced toonly 1 test after the RCD element was installed

• Cased hole calibration of the MPD system reduced byover 50% to less than 6 hours

• Incorporated MPD contingency training with systemcalibration after the first well

• MPD connection time improved by over 40% to theequivalent of a conventional drilling connection

• Critical backup systems were incorporated to achieve100% uptime of the MPD system

• Flow meter accuracy improvements made to enhanceconnection gas and kick detection monitoring

• RCD element change outs improved to less than 1 hourand eliminated under & over pressure variations

• Weight ups of 0.5 ppg were done without lostcirculation by maintaining bottom hole pressure

The proactive approach to MPD enabled proper planning andtraining time, in addition to focus on continuous improvementof the system and its operability.

AcknowledgementsThe entire Auger well site rig team deserves special thanks fortheir positive attitude and focus on continuous improvement ofMPD. The authors also thank Shell for permission to publishthis paper.

References1. Chustz, M., et al (2007): “ Managed Pressure Drilling withDynamic Annular Pressure Control System ProvesSuccessful in Redevelopment Program on Auger TLP inDeepwater Gulf of Mexico” SPE 108348 presented atIADC/SPE Managed Pressure Drilling and UnderbalancedOperations Conference held in Galveston, Texas, 28-29March 2007

2. Roes, V., et al (2006): “First Deepwater Application ofDynamic Annular Pressure Control Succeeds” SPE 98077

presented at SPE/IADC Drilling Conference held inMiami, Florida, 21-23 February 2006

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Figure 1 – Historical Auger Sidetracks: Days vs. Depth Curve

Figure 2 – Bottom Hole Pressure Components

15000

16000

17000

18000

19000

20000

21000

0 10 20 30 40 50 60 70 80 90Day

D e p t h

A-05 ST-01

A-04 ST-01

A-19-ST01

A19 ST-01

A05 ST-01 BP00

A04 ST 1 / 2 / 3

A05 ST-01 BP02 A05 ST-01 BP01

ECD Breakdown of CBHP Method of MPD3-1/2" DP in 7" Csg x 6.5" OH

0.1

0.1

0.6 0.2

0.1

0.1

0.6

13.5 13.7 13.9 14.1 14.3 14.5

Drilling

Connection

PPG

compressiblity flowrate rotary cuttings Back PSI

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Figure 3 – DAPC Flow Schematic: Drilling

Figure 4 – DAPC Flow Schematic: Connection

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Table 1 – Summary Table of Auger MPD Wells

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