18 Oileld Review

Drilling Automation

In pursuit of increased quality and protability, many in the manufacturing industry

have found success in automating processes. The oil and gas industry is looking for

ways to replicate this strategy for drilling. Drilling automation may hold the key to

efciently performing intricate and high-speed tasks and thus make complex wells

technically and economically feasible. When a drilling project involves large

numbers of wells drilled through well-documented lithologies and pressure regimes,

operators can capitalize on the repetitive nature of automated drilling to eliminate

costs associated with the performance variability typically exhibited from one well to

the next within a drilling program.

Walt Aldred Cambridge, England

Jacques Bourque Mike ManneringGatwick, England

Clinton Chapman Bertrand du CastelRandy Hansen Sugar Land, Texas, USA

Geoff Downton Richard HarmerStonehouse, England

Ian FalconerHouston, Texas

Fred FlorenceNational Oilwell VarcoCedar Park, Texas

Elizabeth Godinez ZuritaVillahermosa, Mexico

Claudio NietoPetrleos Mexicanos (PEMEX)Villahermosa, Mexico

Rob StauderHelmerich & Payne, Inc.Tulsa, Oklahoma, USA

Mario ZamoraM-I SWACOHouston, Texas

Oileld Review Summer 2012: 24, no. 2. Copyright 2012 Schlumberger.For help in preparation of this article, thanks to Jonathan Dunlop, Cambridge, England; Jean-Paul LeCann, Roissy-en-France, France; Eric Maidla, Houston; and Jose Luis Sanchez Flores, Sugar Land, Texas.Factory Drilling, PowerDrive, PowerV, ROPO and Slider are marks of Schlumberger.FBRM is a registered trademark of Mettler-Toledo Autochem, Inc.IntelliServ is a registered trademark of National Oilwell Varco.

Engineers have long viewed drilling as nearly equal parts art and science. Today, as autono-mous computer-controlled drilling operationsdrilling automationapproach reality, the view of engineers is leaning decidedly toward science. The ultimate objective of drilling auto-mation, as with most upstream innovations, is to deliver nancial benets to the operator. Drilling automation seeks to accomplish this through pro-cess improvements, optimized rates of penetra-tion (ROPs), consistent hole quality and overall drilling performance, all of which allow operators to reach their objectives in the shortest time. Bringing together rig oor and downhole automa-tion also promises to improve environmental pro-tection and worker health and safety while helping operators to economically exploit reserves that are out of reach using todays tech-nologies. As large numbers of upstream industry experts prepare to retire, automation may offer a way to codify best practices and knowledge and thereby preserve expertise.

On the manufacturing assembly line, automa-tion has become ubiquitous, typically taking the form of computer-guided robots performing repetitive tasks. The machines are tireless, pre-cise and do not suffer from the boredom or lapses in attention that their human counterparts do. They are able to attain a level of autonomy

because there are few decisions to make and there is little uncertainty or variability in their environment and tasks. This is the concept behind the Factory Drilling approach for eld development in which a large number of wellsfor which conditions are well-understoodare to be drilled and completed.

The drilling industry has lagged other indus-tries in adopting automation, but some advances have been made; high-end drilling units have been equipped with remotely operated iron roughnecks and pipe handling machines. However, while equipment mechanization repli-cates repetitive rig tasks on the drill oor and removes humans from potentially dangerous environments, it is not the same as drilling auto-mation. An automated drilling process provides operators with a way of accessing reservoirs at lower costs while safely and consistently outper-forming manual operations.

Automation of the drilling process requires a system that has the ability to deal with changing and uncertain environments. Fed directly by downhole and surface data, these systems must react to changes such as lithology in a manner that maintains optimal performance, thus increasing uptime and efciency. Reduction of personnel on the rig oor and the systems ability

Summer 2012 19Suummmerer 220101122 19191919

to perform some tasks remotely would be only by-products of this effort, not objectives.1 In prac-tice, automated systems will more likely leverage the knowledge and experience of rig personnel than do away with them.

The drilling culture is part of the reason for the upstream industrys delay in adopting auto-mation. Drilling personnel often make opera-tional decisions based on their overall experience and knowledge of the local geology and drilling conditions. As a consequence, many are suspi-cious of systems that seem a threat to their skill set, require them to relinquish some portion of control of the drilling operation or move techni-cal limits away from traditionally conservative drilling practices.2 From an organizational point of view, the major components of an automated

system require close cooperation over long peri-ods of time, but the systems employed in the drill-ing process are often owned by a variety of companies and may have different drivers, mak-ing automated cooperation difcult.

The current challenge of creating an auto-mated drilling system that is capable of drilling a well or section autonomously lies in the many uncertainties associated with making a hole deep in the Earth. In manufacturing industries, dra-matic events encountered during the process are the exception, whereas in drilling, they are the rule. Downhole pressures, temperatures and rock characteristics often change rapidly as the bit progresses toward TD. Therefore, it is difcult to replicate an experienced drillers response to any of the many possible scenarios.

1. Pink T, Bruce A, Kverneland H and Applewhite B: Building an Automated Drilling System Where Surface Machines Are Controlled by Downhole and Surface Data to Optimize the Well Construction Process, paper IADC/SPE 150973, presented at the IADC/SPE Drilling Conference and Exhibition, San Diego, California, USA, March 68, 2012.

2. The technical limit is the best possible drilling performance for a given set of parameters. It is an ideal standard, which requires a perfect set of conditions, tools and people.

Automating the drilling process hinges on not only availability and interoperability of com-puter-controlled machinery but also on informa-tion management: gathering the right information at the right time and coupling it with the experi-ence necessary to make optimal decisions. The industry has long used software that assists drill-ers in making decisions on the rig oor. These systems require human intervention to interpret

Summer 2012

20 Oileld Review

data and carry out the appropriate actions, pro-viding drilling guidance rather than automation.

An automated drilling process requires a sys-tems engineering approacha loop that inte-grates real-time downhole and surface data with predrill models. Adjusting to changing condi-tions, this system modies operational settings, such as pump rates, hook load and rotary speed.3 In addition, an automated system updates the model using real-time data, essentially simulat-ing the decisions of an experienced driller adapt-ing to the results of imperfect predictions. The level of integration between surface and down-hole systems varies considerably and is limited by sensor availability near the bit and along the drillstring and by bandwidth to send measure-ments and commands to and from downhole. This means the character of drilling automation is likely to vary from well to well. However, results show that higher frequency data from more sensors improve operator ability to drill to the technical limit.

The path to drilling automation may be described in terms of three tiers. The rst tier is a system that offers guidance to drillers, the sec-ond makes decisions with driller approval and the third moves toward an autonomous system in which the drillerwho may be located off siteacts as the monitor, to intervene only when required (below).

The drilling industry has taken hesitant steps toward automation. Built and tested around 1980, the National Automated Drilling Machine was an early attempt to build an automated drill-ing rig.4 Because manufacturers could not over-come the failure of fragile sensors in a drilling environment, the machine was never commer-cialized. In the 1990s, many rigs were built with mechanized pipe handling equipment, and engi-neers developed closed loop control, using data gathered while drilling, to adjust rotary steerable drilling systems.

Only recently, driven by Norwegian operators and regulators concerned with safety and health issues, has the industry made a sustained effort toward drilling automation. In 2007, the SPE cre-ated a technical section devoted to drilling sys-tems automation; those involved in the section are working toward automation in all areas, including completion and production. This arti-cle examines the state of those ongoing efforts to bring to the industry a level of drilling automa-tion as a means to more efcient, safer and higher quality drilling operations in the future. Case studies from Mexico and the US illustrate various drilling automation applications.

Controlling the BrakeHistorically, in an imitation of manual drilling operations, automated drilling has centered on using the drilling line brake to control weight on bit (WOB). Autodrillers, which mimic human operators by using pneumatic controls to maintain constant WOB or constant ROP, have consistently outperformed humans when drilling conditionsformation geology, pressures and temperaturesare well-known and vary gradu-ally. However, autodrillers performed poorly when these conditions changed abruptly.5

The introduction of disk brakes gave rise to electronic autodrillers that used computer control algorithms to maintain a constant WOB or ROP.6 Improvements to autodrillers drove engineers to develop increasingly complex software that simplified control and adjusted drilling parameters in response to changing formation characteristics as the bit drilled ahead (next page).

Autodrillers are in the second tier of automa-tion because they rely on driller approval. Although dependent on local rig equipment auto-mation and mechanization, drilling automation seeks to build on those systems by integrating the drilling machine with downhole systems and mea-surements. The objectives are to improve and lower the cost of reservoir access and to outper-form manual operations safely and consistently.

Automating the drilling process is complex. Engineers at Schlumberger have segmented the process into manageable modules that may be used either independently or in combination to eventually deliver an intelligent system able to drill a hole section autonomously. The modules are the following:sRIGANDDOWNHOLESYSTEMSINTEGRATIONs2/0OPTIMIZATION abnormal event detection and mitigation shock and vibration monitoring and

mitigationsWELLBORESTEERINGsWELLBOREINTEGRITYsOPERATIONSSEQUENCEMANAGEMENT

Integrating automation modules, which use downhole and surface information, with the rig control system requires drillers to exchange their role of overarching supervisor for that of a criti-cal component within a process. The integrated system must be designed so that the driller inter-acts with it intuitively and is in a position to take control of the rig at any time. To achieve this, the driller must understand what the automation sys-tem is doing as it handles its many tasks, and the

> The path to automation. Systems and industries move from manual to automated control systems in a predictable manner. Initially, in the rst tier (bottom), the systems perform a limited analyze-and-advise function by suggesting an optimal course of action for the human operator to perform. In the second tier (middle), the semiautonomous automated system chooses the action and performs it, but only after receiving approval from the driller. In the third tier (top), the automated system is autonomous and informs the driller of its actions as it takes them.

Decides everything and acts autonomously.

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Summer 2012 21

driller must anticipate what the system is going to do next. Therefore, counter to preconceptions held in the industry, human involvement in drill-ing operations may be increased rather than decreased by automation.

Faster Engineers are applying these requisite computer control algorithms to various aspects of the drill-ing process; the algorithms fall in each of the

tiers on the path to full automation. Most pro-grams based on these algorithms act in an advi-sory capacity and require human intervention to initiate action. Others are, or are nearly, autono-mous systems, which take action without seeking permission from or notifying the driller and might be best described as supervised autonomy. One such algorithm helps optimize ROP and has been used in programs that have both advisory and full-control capacities.

Automated ROP optimization relies on the fact that while the bit is on bottom, the driller can control only three things: WOB, drillstring rotation speed in revolutions per minute (rpm) and mud ow rate. An automated ROP optimiza-tion system can therefore be created in which the set points of WOB and rpm are fed directly to the controls of the drilling rig.7 Building on this idea, engineers at Schlumberger developed the ROPO rate of penetration optimization module.

3. The driller adjusts the block position to keep the weight on bit within a desired range. The weight on bit is calculated as the difference between the measured hook load, which is a measure of the amount of pipe suspended below the block, and a datum taken by measuring hook load when off-bottom.

4. de Wardt JP and Rogers J: Drilling Systems AutomationA Technology that Is at a Tipping Point,

>Modern autodrillers. Whereas WOB was the only parameter considered by early autodrillers as input for controlling the drilling process, later autodrillers used multiple parameters. In this example of multiparameter autodriller output, the multicolor horizontal bar at the top indicates by color which parameter is controlling the brake at that point. The solid curves at the bottom represent parameter data and the dashed lines are the parameter set points. The horizontal black line across the middle of the graph shows the status of the autodriller. When the line is at the low value, the autodriller is off; the upper value signies it is on. As the 90-ft (27-m) long stand is drilled through a fairly homogenous formation, the ROP function (red) controls when the autodriller is turned on and the bit is above bottom. When ROP reaches its set point, WOB and torque (dark blue and green, respectively) rise as the bit automatically nds bottom. Torque takes control as ROP and WOB level off. When torque is recognized as the limiting factor, the autodriller raises the torque limit and drilling continues on P (light blue)the standpipe pressure when drilling with a mud motor minus standpipe drilling pressure when just off bottomthrough most of the stand, although ROP experiences brief intermittent control throughout the primary P control period. Toward the end of the stand, WOB takes over as the bit encounters harder rock. (Adapted from Florence et al, reference 5.)

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paper IPTC 14717, presented at the International Petroleum Technology Conference, Bangkok, Thailand, February 79, 2012.

5. Florence F, Porche M, Thomas R and Fox R: Multiparameter Autodrilling Capabilities Provide Drilling/Economic Benets, paper SPE/IADC 119965, presented at the SPE/IADC Drilling Conference and Exhibition, Amsterdam, March 1719, 2009.

6. For more on autodrillers: Aldred W, Belaskie J, Isangulov R, Crockett B, Edmondson B, Florence F and Srinivasan S: Changing the Way We Drill, Oileld Review 17, no. 1 (Spring 2005): 4249.

7. Dunlop J, Isangulov R, Aldred WD, Arismendi Sanchez H, Sanchez Flores JL, Alarcon Herdoiza J, Belaskie J and Luppens JC: Increased Rate of Penetration Through Automation, paper SPE/IADC 139897, presented at the SPE/IADC Drilling Conference and Exhibition, Amsterdam, March 13, 2011.

22 Oileld Review

The ROPO algorithm is based on a model of PDC bitformation interaction and a data pro-cessing technique that detects changes in bit response. The PDC bit model assumes that bit-formation interaction is broken into three linear phases based on the depth of cut (below). During the rst phase, when the bit is just starting to turn on bottom and before reaching critical depth, increasing WOB causes little increase in depth of cut and, consequently, low ROP. During the second phase, higher WOB results in an increased depth of cut. Phase three begins when this increased efciency has led to the founder pointthe time at which the uid system is no longer able to adequately clean the face of the bit, and cutting efciency is reduced.8

The ROPO module characterizes the bit response in real time and determines optimal val-ues of rpm and WOBwithin a set of complex lim-its that includes WOB, torque, surface rpm, ROP and motor limitsto achieve maximum ROP.9

In 150,000 m [492,000 ft] drilled through a range of environments, wells drilled in the ROPO advisory mode have shown an average 32% ROP improvement compared with the ROP in offset wells drilled manually or with an autodriller sys-tem (above). When the ROPO algorithm was used in closed loop automation, or control mode, dur-ing which it sent commands directly to the rig control system, ROP improvements were even greater, with the control mode wells experienc-ing a 53.1% ROP gain over the ROP in wells drilled in advisory mode.10

For operators involved in multiple-well projects, saving rig time consistently, without sacricing wellbore quality, is a strong incentive to improve ROP. In the Burgos basin in Mexico, PEMEX planned to drill 400 wells, many of which are in the Comitas eld where the lithology is well known. Typical drilling trouble spots included an 81/2-in. section through mostly shale and a 61/8-in. section that is characterized by interbedded formations of shale and sand.

In their evaluations of the many wells already drilled in the Comitas eld, engineers found that ROP averaged 23 m/h [75 ft/h] through the 81/2-in. section and 16.15 m/h [52.98 ft/h] through the 61/8-in. section. Both rates are well below the technical limit. Engineers determined that reducing drilling time by increasing ROP represented a singular opportunity to improve project economics.

Engineers rst selected wells that appeared to be good candidates for ROPO applications and then gathered relevant offset well data. Wells were then drilled in ROPO mode and the results evaluated against offset well results. Two com-parisons were made with results from offset wells: rotating ROP and total ROP for the section. When the ROPO algorithm was used through the 81/2-in. section, the rotating ROP increased to 55.40 m/h [181.8 ft/h]. In the 61/8-in. section, ROPO use increased average ROP to 25.2 m/h [82.6 ft/h]. Time savings in the 81/2-in. and 61/8-in. sections were 37% and 39%, respectively.

SmootherIn high-angle wells, especially extended-reach wells with targets that may have a horizontal displacement of several miles from the surface location, some engineers view high ROP as a secondary objective to well path accuracy. To plan an accurate trajectory, the directional driller must locate the wellbore in three dimen-sions and precisely execute holds and turns. The objective is a trajectory that is the most efcient path to a distant target or one that keeps the wellbore within often narrow depth ranges to maximize formation exposure.

> Automated ROP algorithm. Depth of cut per revolution is estimated by dividing ROP by rpm so that real-time drilling data can be plotted in three dimensions of WOB, bit torque and depth of cut. WOB can be described as the sum of two components: friction and cutting. The drilling response of a PDC bit is modeled as three distinct operating regimes. During the rst phase (blue), frictional and cutting components both increase during low WOB as interaction is dominated by friction at wear ats of the bit cutters. The second regime (tan) begins when WOB is beyond the critical point and friction is optimal, thus increasing WOB translates into pure cutting action. The third regime (green) occurs when the bit is past the founder point when cuttings are building up around the bit, causing cutting efciency to decrease. As the bit drills into a new formation, the responses will change abruptly and the data points will fall on new lines.

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> ROPO algorithm advantage. When eight wells were drilled from the same pad, four using the ROPO module (blue) showed signicantly faster drill rates on the nal tangent section than those drilled conventionally (red). Furthermore, each of the ROPO wells exhibited consistent drilling time results. Time to drill the section in wells drilled without the ROPO technique varied from 6.8 to 8.3 days. In wells drilled with the ROPO approach, time to drill a section varied from 5.3 to 5.8 days. (Adapted from Chapman et al, reference 10.)

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Summer 2012 23

8. Detournay E, Richard T and Shepherd M: Drilling Response of Drag Bits: Theory and Experiment, International Journal of Rock Mechanics and Mining Sciences 45, no. 8 (December 2008): 13471360.

9. Though rpm and WOB are set by the system, they can also limit the system. For example, a PDC bit design may include maximum allowed WOB or rpm recommendations to prevent bit damage.

In directional drilling, certain processes have already been automated. For directional drilling with a bent housing downhole motor, engineers at PathFinder, a Schlumberger company, have developed the Slider automated surface rotation control system. The system is designed to increase drilling efciency of a bent housing motor when in sliding mode by repetitively rotat-ing the drillpipe clockwise at surface, then coun-terclockwise without disturbing the toolface orientation of the BHA. The Slider system uses surface torque readings as feedback to an auto-mated system that controls the rocking move-ment of the drillstring to minimize the sliding

friction along the toolstring. At the same time, the system reduces the need to pull the bit off bottom to reset the toolface.

When using bent housing mud motors to change BHA direction, directional drillers must often halt drilling. The Slider control system, however, allows BHA directional change without halting drilling and as a consequence may enhance overall ROP, a secondary objective. For example, when engineers used the Slider system in the build section of a well in Wood County, Oklahoma, USA, they increased sliding ROP by 118% compared with results from manual opera-tions (below).

In contrast to mud motors, rotary steerable systems (RSSs) do not involve sliding sections so they generally deliver faster ROP and smoother wellbores. Additionally, because the drillstring rotates while drilling, hole cleaning is more efficient than when sliding.11 Therefore the well may be drilled with a lower pump pressure, which reduces the equivalent circu-lating density and reduces the threat of frac-turing the formation.12

For most rotary steerable systems, trans-mitting steering commands from surface to the RSS tool is accomplished using manually

>Marked ROP improvements. An operator used slide drilling in two sections of a well drilled in the Marcellus Shale. In the upper section, the well was drilled manually and had an average ROP of 5.8 ft/h. In the lower section, using the Slider system, ROP was raised to 16.1 ft/h (Track 1). WOB (gold) and hook load (purple) were essentially equal through both sections (Track 2). The Slider system kept topdrive torque (blue) low by adjusting rotary speed (red) through the lower sections (Track 3).

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10. Chapman CD, Sanchez Flores JL, De Leon Perez R and Yu H: Automated Closed-Loop Drilling with ROP Optimization Algorithm Signicantly Reduces Drilling Time and Improves Downhole Tool Reliability, paper IADC/SPE 151736, presented at the IADC/SPE Drilling Conference, San Diego, California, March 68, 2012.

11. Melgares H, Grace W, Gonzalez F, Alric C, Palacio J and Akinniranye G: Remote Automated Directional Drilling Through Rotary Steerable Systems, paper SPE/IADC

119761, presented at the SPE/IADC Drilling Conference and Exhibition, Amsterdam, March 1719, 2009.

12. Equivalent circulating density, or ECD, is the effective density exerted by a circulating uid against the formation. The ECD is calculated as: ECD = d + P/ (0.052*D), where d is the mud weight in pounds per gallon (lbm/galUS). P is the pressure drop in the annulus between depth D and surface (psi), and D is the true vertical depth (ft).

24 Oileld Review

controlled timed variation in mud ow; the driller manipulates the mud pumps to change tool settings. By allowing the steering command to be sent directly to the mud pump controller via a digital signal, directional drillers are able to control the well trajectory remotely.

Many rotary steerable systems today are equipped with a degree of autonomy. For example,

hold inclination and azimuth commands, sent from the surface to the PowerDrive RSS, compel the BHA to maintain a constant course without further intervention from the surface. The PowerV vertical drilling system maintains a vertical tra-jectory, without human intervention, by sensing forces acting on the BHA that may cause it to devi-ate and then steering back to vertical.

Such a remote automated steering operation was performed in the 121/4-in. section of the Jacinto 1002 well located about 150 km [93 mi] from Villahermosa in southern Mexico. The only offset well, the Jacinto 1001, encountered very hard sands that caused low ROP. The formation in this section consists of intercalated zones with unconned compressive strengths ranging from 41 to 83 MPa [6,000 to 12,000 psi], which cause high BHA vibrations and abnormal bit wear.

To address these challenges, drilling engi-neers used a directional drilling system that com-bined RSS tools with a mud motor power section. This system, which delivers more energy to the bit, mechanically decouples the bit from the drill-string, thus dampening vibrations above the motor because the drillstring rotates at a lower rpm than the bit and RSS. Engineers sent 21 automated downlinks to the RSS tool from a remotely located control center to build the curve, keeping the well tangent to the next casing point and drilling the 121/4-in. section with a sin-gle bit (above left).13

Schlumberger engineers are developing an automated trajectory control system that receives real-time survey data to characterize the steering behavior of a BHA. The system uses that real-time downhole information to create more-accurate projections and determine the appropriate steer-ing command to keep the drilling tool along the planned trajectory. Currently, the system is used in an advisory capacity, but an updated version in eld tests will be able to act autonomously, issu-ing downlink commands to the tool to make it a fully automated trajectory control system.14

Changing or unexpected formation character-istics may cause bit or BHA dysfunction, requiring continuous adjustments to the WOB and rpm in response. Using surface measurements, an engi-neer may have difculty recognizing a change or its cause at the time it is encountered. Usually, there is a signicant time lag between the time an event occurs and when the driller recognizes it and takes the proper corrective action. Given the lag and the many factors inuencing surface read-outs, it is not surprising when a driller makes an incorrect decisionone that is at best ineffectual and at worst detrimental.

A new automation array has the potential to overcome this shortcoming. The array consists of two elements: newly developed downhole sensors capable of high-frequency sampling and wired drillpipe capable of transmitting the resulting high volumes of data to the surface. By interpret-ing large volumes of data quickly, these auto-mated systems alert drillers in real time to

> Downlinking enhancement. Engineers used automated downlinking on the Jacinto 1002 well (blue) to drill a 121/4-in. section in 172 fewer hours than were required for the same section in the offset Jacinto 1001 well (red). The Jacinto 1002 required only one bit on a mud motor and RSS-equipped BHA compared with the need for four bits in the Jacinto 1001 well drilled using an RSS controlled conventionally by the directional driller. (Adapted from Melgares et al, reference 11).

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Summer 2012 25

threatening BHA phenomena such as stick-slip, whirl, axial shock and bit bounce.15

Wired drillpipe makes it possible to gather annular pressure and temperature measure-ments along the drillstring, which allows opera-tors to monitor the entire wellbore. Algorithms quickly condense these data and convert them into ags and control signals for the automation

system (above). Other algorithms sort the data, recognize an event and bypass the driller to initi-ate proper corrective actions if necessary.

Automatic Fluids MeasurementsOne of the most important factors inuencing the success of drilling operations is the operators ability to maintain drilling uids properties within

a prescribed range of values. Automation of the well construction uids (WCF) domain addresses four major systems. In addition to the uids, the WCF domain also encompasses ow conduits, tanks and process equipment. These four systems in turn fall into four areas: uids treatment and pumping, downhole, solids control and waste management (previous page, bottom).16

13. Melgares et al, reference 11.14. Pirovolou D, Chapman CD, Chau M, Arismendi H,

Ahorukomeye M and Penaranda J: Drilling Automation: An Automatic Trajectory Control System, paper SPE 143899, presented at the SPE Digital Energy Conference and Exhibition, The Woodlands, Texas, USA, April 1921, 2011.

> Automated drilling mechanics. High-frequency downhole measurements taken by a downhole sensor placed in the BHA can be processed to detect a drillstring state. This diagnostic information is sent uphole in real time and processed by an automated surface system that makes the appropriate modications to the drilling parameters or to the procedures on surface. In this case, high levels of axial acceleration (top left) indicate the presence of bit bounce (top right), which can reduce drilling efciency and potentially damage the bit cutting structure or components within the BHA. A spectral plot (center) identies BHA and drillstring resonant frequencies and illustrates the energy present within the axial vibrations as a function of frequency. Red corresponds to high energy generated by vibrations while green indicates low energy has been generated. The higher the energy, the more damaging the vibrations are likely to be. The three intervals (bottom) correspond to different levels of risk. High-risk bit bounce (left) triggers a red light alarm on the surface. Normal drilling conditions, or low-risk drilling conditions (center), display as a green light on the surface to indicate it is safe to drill ahead. The presence of moderate risk of bit bounce presents a cautionary yellow light (right) to the driller.

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15. For more on these drilling phenomena: Centala P, Challa V, Durairajan B, Meehan R, Paez L, Partin U, Segal S, Wu S, Garrett I, Teggart B and Tetley N: Bit DesignTop to Bottom, Oileld Review 23, no. 2 (Summer 2011): 417.

16. Geehan T and Zamora M: Automation of Well-Construction Fluids Domain, paper IADC/SPE 128903, presented at the IADC/SPE Drilling Conference and Exhibition, New Orleans, February 24, 2010.

26 Oileld Review

The emergence of managed pressure drilling (MPD), in which engineers use a choke to regu-late backpressure on the well to preserve a con-stant bottomhole pressure (BHP), has been instrumental in the drive to automate the WCF domain.17 The set point for the choke is deter-mined using a hydraulic model. The hydraulic model is built and updated continuously during drilling operations using rig-supplied data such as ow rate, bit depth, rpm, torque and mud density, temperature and rheological parameters. Because uids parameters are measured manually and because there is often a time lag between when a sample is collected and analyzed and when it is input into the model, the measurements may rep-resent a source of error in the model.18

Recently, two Norwegian operators asked M-I SWACO, a Schlumberger company, to develop automated drilling uid sensors. In response, a team of M-I SWACO engineers, working with reg-ulators and supported by the operators, devel-oped several sensors, most of which were custom developed or adapted from other industries. Engineers for this uids measurement automa-tion project began by determining that while most uids measurement tasks could be executed

remotely, uid analysis must be performed on site and monitored remotely. Engineers identi-ed existing sensors that allow uids measure-ments to be accomplished remotely and determined which additional sensors required development.

Traditionally, engineers determine particle size distribution (PSD) using a series of sieves. Recently developed techniques rely instead on image analysis and require sample dilution in opaque uids. One such technique uses an auto-mated FBRM focused beam reectance measure-ment instrument. The sensor is installed directly in a 5-cm [2-in.] ow loop leading from the active ow pit or the owline where it measures the PSD of the uids entering the well or exiting the annulus at one-second intervals (above).19

Engineers designed an automated elemental analysis and solids content instrument to replace conventional retorting procedures and manual chemical titrations. The new analysis tool uses a 500-eV source and a sensor that can be moved along three axes and is capable of monitoring any element with an atomic weight greater than that of magnesium. It can also measure high- and low-gravity solids content. Analysis may be displayed in

existing graphical interfaces as concentrations of the various additives used in the uid formulation.

To create an automated rheometer, the team focused on exploiting existing software and expanding instrument temperature range capa-bilities. To do so, they based the rheometer design on the Couette bob and sleeve API speci-ed layout and the 10-second and 10-minute gel strength measurements.20 The primary change to the standard equipment was an electronic load cell to replace the spring attached to the bob that measured torque. The load cell is designed to improve accuracy by reducing the effects of tem-perature on measurements.

The data from the automated rheometer are exported directly to software that updates ow and pressure simulations for comparison with real-time downhole data reported from the rig. The software also prepares and reports test data directly in wellsite information transfer standard markup language (WITSML) to be displayed on graphical user interfaces (GUIs).

An automated electrical stability (AES) instrument was built and designed for the project to change the high-frequency electrical stability test from a single-point to a trend analysis. Trends may then be displayed beside other measure-ments such as oil/water ratios and viscosity. Each test sequence includes seven measurements; the software excludes the extremes and the remain-ing ve are averaged, recorded and displayed as a trend on a GUI. The AES meter includes real-time capacitance measurements of oil-base drilling u-ids and is installed directly on the rig owline. Engineers are thus able to identify instantaneous trends in water content variation.

17. For more on MPD: Elliott D, Montilva J, Francis P, Reitsma D, Shelton J and Roes V: Managed Pressure Drilling Erases the Lines, Oileld Review 23, no. 1 (Spring 2011): 1423.

18. Stock T, Ronaes E, Fossdal T and Bjerkaas J: The Development and Successful Application of an Automated Real-Time Drilling Fluids Measurement System, paper SPE 150439, presented at the SPE Intelligent Energy International, Utrecht, The Netherlands, March 2729, 2012.

19. Stock et al, reference 18.20. Mud shear stress is measured after a mud has set

quiescently for a period of time. The times called for by the American Petroleum Institute procedure are for 10 seconds and 10 minutes, although measurements after 30 minutes or 16 hours may also be made.

21. Stock et al, reference 18.22. Sadlier A, Laing M and Shields J: Data Aggregation and

Drilling Automation: Connecting the Interoperability Bridge between Acquisition, Monitoring, Evaluation, and Control, paper IADC/SPE 151412, presented at the IADC/SPE Drilling Conference and Exhibition, San Diego, California, March 68, 2012.

23. Sadlier A and Laing M: Interoperability: An Enabler for Drilling Automation and a Driver for Innovation, paper SPE/IADC 140114, presented at the SPE/IADC Drilling Conference and Exhibition, Amsterdam, March 13, 2011.

> Determining particle size distribution with FBRM focused beam reectance measurement. During the drilling of a 121/4-in. section, engineers grouped particles by size to reect materials added for formation strengthening. To test FBRM sensors, engineers equipped shakers with weak screens that were intended to fail quickly. When the rst screen failed, at about 3:30 a.m., rig personnel observed a sharp increase in the concentration of coarse-size particles ranging from 185 to 1,002 m (black, brown and blue). The installation of a new screen one hour later was followed by a decrease in the concentration of those coarse particles until that screen failed at about 10 a.m. The ner particles of 19 to 63 m and 54 to 100 m (green and red, respectively) showed steady increase in concentration over the entire period. (Adapted from Stock et al, reference 18.)

HighPa

rticl

e co

ncen

tratio

n

Low06:19:0403:00:00 05:00:0001:00:0009:00:00

Time

07:00:0005:00:0003:00:0001:19:04 11:00:00

370 to 632 m

185 to 317 m

542 to 1,002 m 54 to 100 m

19 to 63 m

Summer 2012 27

Density measurements using dual real-time sensors present analytical trends and represent a signicant change from standard API measure-ment techniques that use a conventional industry balance. Unlike the balance method, the new density sensor provides real-time updates of static and dynamic downhole pressures cor-rected for temperature variations.

Because the vibrating tube densitometer commonly used today is able to transfer temper-ature and density data from the sensors directly into the simulation software, engineers at M-I SWACO incorporated the densitometer into the project. As a consequence, data may be used in simulation software and shown on GUI displays located on rigs and in remote opera-tions centers.21

Interoperability: The Bridge to AutomationAs sensor and software capability expands and is further enabled by increased network capacity, the type and number of well construction tasks being moved from human control to machines continue to increase. New automation algorithms have provided substantial gains in reliability and tool performance, and operators wishing to take advantage of these algorithms will inevitably move the industry toward drilling automation. As part of that process, operators will also drive the creation of standards to facilitate deployment of these algorithms.

A fully automated drilling process depends ultimately on the ability of all the components to share information. This requires that many parts and processes sift, select and act upon an enor-mous amount of data autonomously and synchro-nously. LWD and mud logging illustrate why a data aggregator system that gathers and coordi-nates various data sources must be developed before true drilling automation will be possible. In most cases, LWD tools transmit their data to the surface via mud pulse, which must be then translated into usable data. This means the data are not available to the user in real time but in near real time. Similarly, drill cuttings used as a data source by mud logging systems are not avail-able until they are circulated to the surface, cap-tured and analyzed, which may be a matter of hours after they are created.22

To efciently use these data to automatically and appropriately respond to the drilling situa-tion requires systemwide interoperabilitythe linking of people, tools, equipment and informa-tion at the right time and in the context of the drilling operation (above). Complete interopera-bility is fundamental to automation. Limited interoperability results in islands of automation that must be pulled together by humans to assure proper system interaction. Alternatively, custom solutions incorporated onto a select number of rigs are costly and also require human interven-tion. Rig contractors may offer a fast path to interoperability by providing remote control sys-tems, but this approach may also be hampered by

systems that are congured for specic rigs, con-tractors or rig types.

Improvements in the movement of and access to real-time data are also needed. Engineers are now working to apply to the drilling industry a uni-ed architecture standard, which offers a unied data access technology stack that combines the lessons learned in process control with the auto-mation used in aircraft, automobile, space and other industries. Engineers working on drilling automation are particularly interested in how these industries use existing standards, security congurations and certications and real-time interoperability technologies to address redun-dancy and reliability. Of special interest for auto-mated drilling scenarios is how other industries have addressed the concepts of situational aware-ness, human interaction and planning and system contingencies in the face of unexpected events.

Drilling contractors, service companies, equipment manufacturers and operators use vari-ous standards for data portability. WITSML is used most commonly in the oil industry to standardize the interfaces between various well monitoring and control technologies and software programs.23 A new standard or extension of an existing stan-dard such as WITSML to describe rig and surface equipment is also needed but will require the combined efforts of operators, service companies, rig contractors and equipment suppliers.

For automation to occur on a wide scale, rig control standards must be applied industrywide. In addition to providing uniformity across all automated drilling units, contractor compliance with these standards will afford service providers a reliable platform upon which to integrate their solutions. Such a platform must allow a generic view of the rig from a programmatic standpoint. Once that is accomplished, conversion to specic rig platforms and specic rig contractor proto-cols will be necessary, requiring signicant cus-tom coding and rig time to assure each application is correct. Though early adopters of automation will pay for its development internally, they will reap the nancial benets of automation early, and standardization will help reduce overall costs and engineering time. RvF

> Information for action. Inputs required by a drilling automation system are at once related and distinct, making it difcult to consider which should be a priority. (Adapted from Sadlier et al, reference 22.)

Drilling pressureRheologyHole cleaning

Hydraulic

DrillingAutomation

Formation pressureWellbore qualityFormation evaluation

Geologic

ControlSurface measurementsDownhole measurementsMaintenance

Mechanical

Reduction ofnonproductive timeInvisible lost timemanagementData analyticsDownhole dynamics

Drilling Process