First Automated MPD in Mexico GoM - Weatherford International

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D R I L L I N G & C O M P L E T I O NFirst automated MPDin Mexico GoM cuts drilling daysLuis GiralGerman CastiblancoWeatherford International Ltd.Risk, safety enhancements improve performance in carbonate drillingA footprint of only 5 x 5 m was required forthe deck components of the automatic MPDpackage, including choke manifold, Microfluxcontrol system, and the separator added tohandle the anticipated gas influxes.Drilling in the fractured carbonate formationsof the Gulf of Mexico typicallyposes many challenges to riskmanagement, safety, and drilling efficiency.Significant nonproductivetime(NPT) is generated by lost circulationand/or gas influxes in the high-pressureformations, and a host of related problems.In some cases, the conditions are so overwhelmingthat the hole is undrillable usingconventional means and must be abandoned.These difficult issues have been successfullyaddressed in the first use of automated managedpressure drilling (MPD) in the GoM. Bymeasuring and managing bottomhole wellborepressures in real time, the MPD system enableda proactive response to downhole influxesand losses that greatly reduced hole problemsand improved safety. The performanceenhancements resulted in successfully drillingthe designed hole size to target depth 12 daysfaster than the best offset.Land and offshore drilling operationsalong Mexico’s Tabasco coast face majordifficulties posed by variations in pore pressuresand fracture gradients, depleted reservoirs,and highly fractured carbonates.The fractured carbonate formations presentnegative drilling windows where pore pressureand fracture pressure overlap, resultingin entire sections experiencing completecirculation losses.The offshore development well selectedfor application of Weatherford’s MPDmonitoring, analysis, and managementsystem is about 27 m (89 ft) of water. Offsetwells had experienced considerablecost-increasing NPT due to a variety ofoperational problems, including lost circulationand gas influxes (sometimessimultaneously), difficulty identifyingwashout and ballooning events, differentialsticking, the presence of hydrogensulfide (H 2S) gas, low penetration rates, andformation damage.MPD objectivesThe primary objective of using the automatedMPD system was to reach the target depthwith the planned 8½-in. hole while incurringas little NPT as possible through the reservoirsection. The operational strategy was based onthree key MPD capabilities: using a lower mudweight, real-time monitoring of small variationsin bottomhole pressure, and proactive managementof those pressure changes to preventthem from escalating into well control events.Mud weight was reduced to enhance therate of penetration (ROP). Conventional drillingoperations typically use a heavier mud weightas a necessary safety margin because they dependon estimates of pore pressure rather thanactual data acquired while drilling. Real-timemonitoring and management of losses and influxesfacilitate the use of a mud weight closerto optimal weight without compromising safety.A lower-density mud also allows for easiercontrol or elimination of fluid losses when enteringweak formations. And when drilling in thereservoir, a lighter mud reduces skin damagethat can limit the well’s production potential.Improved drilling operationsResults from the MPD well compared to twooffset wells clearly show the success of the application.With MPD, the 8½-in. hole sectionReprinted with revisions to format, from the May 2011 edition of OFFSHORECopyright 2011 by PennWell Corporationwas drilled in 26 days versus 38 and 59 daysfor the offsets, saving 12 and 33 days respectively.ROP averaged 5-6 m/hr while the offsetsmanaged only 1-2 m/hr. The MPD well also requiredfewer bits (three) that the offsets whichrequired six and eight bits.MPD operations began with a lowerdensitymud than the offsets and averageda lower weight throughout the drilling. Theinverse emulsion mud weight ranged from1.58 to 1.96 gr/cc in the first offset well andfrom 1.05 to 1.96 gr/cc in the second. In theMPD well, it averaged 1.49 to 1.68 gr/cc.Kick and loss mitigation benefited fromreal-time detection and management of verysmall volume influxes.Operational highlightsThe MPD operation began with a pressuretest of all of the MPD surface equipment. Thebottomhole assembly (BHA) – consisting ofan 8½-in. polycrystalline diamond compactdrill bit, 6 ¾-in. x 8 ½-in. stabilizers, 6½-in. drillcollars, a 5-in. heavyweight drill pipe and a 5-in.drill pipe – was lowered into the well.Once the assembly was 50 m above theshale, the automated system was tested insidethe casing before lowering the accessories.The objective of this procedure was to calibratethe response of the system to influxes,losses, equivalent circulating density (ECD)control, swabbing, and surging. The casingshoe was drilled out when the calibration wascomplete.Drilling of the 8½-in. section began at4,375 m with a mud density of 1.65 gr/ccand a flow rate of 330 gpm, for an ECD of1.70 gr/cc. The mud density selected forthe MPD operation was 0.15 gr/cc lowerthan the conventional figure of 1.80 gr/cc.The automated system began in standardmode, with the chokes fully open,monitoring the entrance and exit flow torespond to any unexpected event. Essentially,the strategy was to wait until thewell “spoke” before making decisions inaccordance with the density and bottomholecirculating pressure (BHCP).One of the events that demonstratedthe significant benefit of the automatedsystem was the early identification of a

D R I L L I N G & C O M P L E T I O NThe system identifies a gas influx while drilling at 4,426 m. Because of the earlykick detection capabilities of the system, the pit gain was only 1.5 bbl.very small influx. At a measured depth of about 4,400 m, the automatedsystem detected an influx of only 1.5 bbl. The influx wascontrolled in less than 2 min.The Microflux system detected an increase in outflow comparedto inflow. Based on internal algorithms, the system indicated to theMPD choke to adjust automatically. The application of back pressureequalized the inflow and outflow.The influx that had been incorporated into the mud system was thencirculated out by applying 650 psi back pressure. Drilling continued whileback pressure was increased to 750 psi, which addressed the safety factorrequired by the operating company.This response contrasts with the inevitable NPT resulting fromconventional well control procedures and maneuvers that are the onlyavailable response when a high-pressure formation is conventionallydrilled.Conventionally, an influx is typically confirmed after a gain of manybarrels (typically 10 to 20 bbl). With the constant bottomhole pressuremethod of MPD, downhole influxes are detected typically at afew barrels and managed quickly before they escalate into a well controlevent.After evaluating the situation, it was determined that the optionswere to continue drilling with this back pressure or to increase thedrilling fluid density to reduce it. Considering the risk of finding a newinterval with higher pore pressure, it was decided to increase the mudweight from 1.65 gr/cc to 1.68 gr/cc. Back pressure was reduced by500 psi to continue drilling.The MPD connection was made at 4,435 m MD to keep the bottomholepressure constant and to replace the friction losses withback pressure. Drilling continued with a density of 1.68 gr/cc and ata depth of 4,480 m MD, total circulation losses were detected.In the lower part of the section, the outflow curve moved to theleft, indicating total losses. The behavior of the system once gas wasdetected on the surface is seen in the accompanying illustration. Anerroneous reading was seen in the exit flow, which is typical of gaspassing through the system. The system generated an alert, signifyingthe presence of gas on the surface.Both monitoring and management capabilities are based on thebehavior of the incompressible drilling fluid contained within a pressurizedclosed-loop system. In this environment, a changein bottomhole pressure due to an influx or loss is detectedin seconds by surface instruments monitoring the flow andpressure.Conversely, a change in annular pressure (back pressure)effected by closing an MPD choke or adding fluid via a pumpis quickly felt at the bottom of the hole. Small, fast changesin ECD are made easily without changing the mud system ordelaying drilling.In automatic mode, the MPD systems detects rapid fluctuationsin downhole pressure, algorithmically processesthem and immediately translates the data into changes in annularback pressure necessary to maintain a balance withinthe drilling window. In this manner, the MPD system managesbottomhole pressure even when the pumps are off whilemaking pipe connections.MPD technology also reduces the risk of hazardous gas production.Gas influxes are limited by MPD procedures, along withthe risk of sour gas release. Any gas getting into the system issmall and easily circulated in a controlled manner. The closedloopsystem also contains the gas and directs it away from therig floor.The MPD equipment spread chosen for the GoM wellconsisted of several relatively common rig equipment componentsintegrated by the Microflux control system.A 13 5 ⁄8-in. rotating control device (RCD) with a double sealing elementwas specified for the well. An RCD is the defining componentof an MPD operation. Installed on top of the BOP in land or offshoresurface applications, the RCD effectively encloses the circulation loopwith an elastomeric seal that closes the annulus and redirects the mudsystem returns. This creates a pressurized closed-loop system that ishighly sensitive to pressure changes initiated either downhole or at thesurface.Within this closed-loop system, pressure is managed accuratelythrough application of annular back pressure.On the GoM well, this back pressure was provided two ways – anautomated MPD choke system located downstream from the RCD andahead of the mud handling system, and an auxiliary annular pump (inthis case achieved by connecting the cementing pump already on theplatform).The choke package also includes metering to measure mass flowand pressure. This data helps inform the control system, which appliesproprietary algorithms to monitor, analyze, and manage downholepressure.The data is used for conventional well control as well as manual andautomatic MPD applications. Automation speeds the time from informationreceipt to action being taken. In difficult wellbore environments,this enhances the ability to proactively manage influxes and losses beforethey become well control events.The flowline used in the GoM application was carbon steel pipingwith 4-in. connections and 5,000-psi maximum allowable workingpressure. It was tested at the maximum static working pressure ofthe rotating head.The particular formation characteristics and the confirmed presenceof large volumes of gas in kick-loss situations necessitateduse of a higher-capacity fluid separator independent from the drillingequipment separator. A vertical, two-phase atmospheric separatorwas used to manage possible influxes. The separator had sufficientcapacity and residence time to ensure the complete releaseof gases returning from the well. The objective was to minimizethe possibility of these gases being released into the shale shakeror mud tanks. •