00051181Applying Technical Limit Methodology For

Applying Technical Limit Methodology forStep Change in Understanding and

PerformanceD.F. Bond, SPE, P.W. Scott, SPE, P.E. Page, SPE, and T.M. Windham,* Woodside Offshore Petroleum Pty. Ltd.

SummaryThis paper presents an alternative planning approach to the drillingand completion process, technical limit, which has resulted in a stepchange in Woodsides performance. Three new wells and sixsubsea completions were finished 20% under budget with this tooland with a simple philosophy characterized by the following questions.

What is current performance? What is possible? What is needed to get there?The target was to drill a directional well in 20 days when the

previous best time was 42 days. A target of 12 days was set onsubsea completions, although a conventional approach had previ-ously been 201 days.

The methodology was to ask what would be possible if every-thing went perfectly on every operation making up the well time.This is not the usual trouble free time but a well time built up ofindividual components, with each component representing its the-oretical best performance.

Details of how the approach was used to plan, and operationaldata that confirm that the technical limit can be approached arepresented. As a result, the well construction performance deliveredstep change improvement when managed against the technical limit.

IntroductionDrilling performance offshore on the North West Shelf of Australiafrom 1968 to 1992 was erratic. A simple plot of time vs. total depth(Fig. 1) showed unacceptable scatter and a high average drillingtime, particularly when benchmarked against published data (No-erager et al.1). The conclusion was the well construction processwas not in control. The company developed a plan to remedy thiswhen faced with an upcoming development project (Wanaea andCossack subsea development).

An aggressive target setting and planning methodology wasdeveloped on the basis of question, What is possible? ratherthan the question, What can be improved? to get the desiredperformance.

The approach was greatly influenced by achievements in otherparts of the world. Some new drilling operations standards were setin the North Sea during the late 1970s and early 1980s, asdocumented by Shute et al.2. A major factor claimed in the successof this work came from time analysis, which rigorously pursued theidentification and removal of drilling problems. Work by Huber etal.3 in the North Sea took a similar approach, which also producedexcellent results.

The high level objective for the Wanaea and Cossack projectswas the requirement for highly productive wells and low construc-tion cost. Work carried out to maximize well productivity had thehighest priority because of the potential pay back and has beendocumented by Walters.4 The focus of this paper was the reductionof well costs.

With time as the predominant cost driver for well cost (70% ofthe well cost was time sensitive), time reduction took priority overunit cost reduction. Application of the What is possible? question

to every component of well construction resulted in aggregatedrilling and completion time, which was called the technical limit.

Technical limit was a term used to describe a level of perfor-mance defined as the best possible for a given set of designparameters. Such performance can be approached but requires aperfect set of conditions, tools, and people. A close analogy of thetechnical limit is a world record in athletics.

The Philosophy of Targeting Technical LimitThe decision to target technical limit was a profoundly significantone. As with a decision to pursue a world record in athletics, pursuitof technical limit required extraordinary effort and commitment andwould probably not be achieved. This is contrary to the commonlyheld belief that targets must be achievable. Implications includeda need for highly competent people, team work, and effectiveleadership.

In meeting the challenge, many deficiencies were exposed (anddealt with) that had not been exposed in the past, thereby invitingcriticism and invoking the blame culture, not uncommon in the oilindustry. A key success factor was to stay committed to thetechnical limit strategy, not to image.

Determining the Technical LimitThe Theoretical Well. The first stage in the development of atechnical limit well time was the construction of a theoretical well.The theoretical well assumed a flawless operation on the basis ofcurrent knowledge and design technology. It was made up ofactivities and durations that were derived from collective experi-ence. Assumptions included, for example, no midsection tripsrequired to change bit or bottomhole assembly (BHA), no reaming(stable hole), no waiting on equipment, no wiper trips,2,3 and nosignificant circulating time. This diverged from the assumptionsmade by Kadaster5 for a normal well. We concluded that to includesuch times would have included technical shortcomings in the plan.The goal was to highlight technical shortcomings as the focus foraction and change, rather than accept, them.

The well construction was broken into easily definable sectionsto calculate a theoretical well, such as drilling a 1712-in. hole,running and cementing 1338-in. casing, and drilling a 1214-in. hole.This produced about 9 to 16 sections depending on the design detailof the particular well. The sections were then broken into subac-tivities as shown in the following example.

Section: 1712-in. Hole. Lay down 26-in. BHA; pick up 1712-in.BHA; run in hole; drill shoe; perform leak-off test; drill 1712-in.hole; circulate bottoms up; and, pull out of hole.

The aim of breaking each section down was to define sufficientdesign detail to enable estimating of actual durations; too muchdetail became cumbersome to work with. Durations were thenestimated for each subgroup. Drilling time assumed a 10 minuteconnection time3 and rate of penetration (ROP) from the best bitruns in the area. A well time produced by this method often resultedin disbelief of the short duration calculated (see Table 1).

By developing the theoretical wells technical limit in a groupsession, it was possible to bring about a shift in paradigms aboutwhat was, and is possible.

Removable Time. The difference between actual well time andtheoretical well time was called removable time. It included con-

Copyright 1998 Society of Petroleum Engineers

This paper (SPE 51181) was revised for publication from paper SPE 35077, firstpresented at the 1996 IADC/SPE Drilling Conference held in New Orleans, 1215March. Original manuscript received for review 12 July 1996. Revised manuscriptreceived 30 April 1997. Paper peer approved 17 April 1998.*Now with Chevron Overseas Petroleum Inc.

197SPE Drilling & Completion, September 1998

ventional lost time and down time and also another componenttermed invisible lost time. Invisible lost time was the name givento the time taken to perform those activities included in a normalwell but excluded in the theoretical well. It was called invisiblebecause, before development of this method, it had not been recog-nized or reported as lost time. Fig. 2 shows the relationship betweentheoretical well, invisible lost time, and conventional lost time.5

The times being generated by the theoretical well were indicatingthat reductions of 40 to 60% were possible, so quantifying theamount of removable time was important.

Identification of the removable time (invisible lost time andnormal lost time3) was achieved manually by use of daily reportsfrom offset wells and application of the assumptions made for thetheoretical well. The exercise of extracting removable time analysiswas very time consuming (up to 2 man months for the eight wellsreviewed) and required a high level of drilling/completion knowl-

edge. The study provided quantification of the missing invisible losttime and a list of all the problems and technical limitations thatprevented best performance on those wells.

The result was significantly greater after subtracting removabletime from actual time than the time predicted by the theoreticalwell. This indicated that either the theoretical well was overlyoptimistic or that further removable time was hidden in the reports.To deal with this discrepancy, another term was introduced, effec-tive time (shown in Table 2).

It was concluded that there must be a component of invisible losttime associated with such things as efficiency improvements in rigcrew activities and drilling optimization (e.g., bit type and bitweight). It would require cross comparison of inefficiencies ondifferent wells to identify the best.

The data set of the eight immediate offset wells was checked foreffective time for each section to investigate these inefficienciesfurther. Table 3 shows the effective time for each section of thewells. The highlighted times represented the best sections, and,when combined, they added up to 19 days. This compared veryclosely with, in fact a little lower than, the theoretical well timesestimated, although design parameters had changed somewhat forthe new wells. The conclusion was that the theoretical well timeswere valid as the starting point for the technical limit.

The theoretical well time developed for the completions (as withdrilling) also appeared too low. A similar exercise of removabletime analysis was performed on a comparable North Sea subseacompletion campaign. The results from the study confirmed thetheoretical durations.

An opportunity to reduce well times by up to 60% was revealedby objectively assessing the removable time with this method.

Use of the Technical Limit MethodPlanning. The planning process used the technical limit concept toidentify the problems that prevented the technical limit being

Fig. 1Days to total depth (TD) for wells drilled on the North West Shelf between 1968and 1992.

TABLE 1ACTUAL VS. THEORETICAL DURATIONS

Offset Directional WellsTheoretical Time

(Days)Actual Time

(Days)

Cossack 2 22.0 42.3

Cossack 3 22.0 51.5

Fig. 2Diagrammatic representation of the relationship be-tween the theoretical well, invisible lost time, technical limit, andconventional lost time.

TABLE 2AN EXAMPLE OF EFFECTIVE TIME WITHCOSSACK 2 AND 3 DURATIONS

Offset WellsTheoretical

WellActualTimes

RemovableTime

EffectiveTime

Cossack 2 22.0 42.3 13.6 28.7

Cossack 3 22.0 51.5 22.3 29.2

198 SPE Drilling & Completion, September 1998

reached and then planned their removal. The time taken to drill andcomplete wells would be the indication of the ability to understandand manage the variables.

Approximately 9 months were spent planning the startup ofoperations. The planning process used the theoretical well andoffset well analysis to develop an engineering workscope anddetermine the resources needed. Execution of the engineeringworkscope involved getting engineers and contractors to under-stand potential obstacles to achieving the technical limit and thenmanage them.

Approximately 175 days were identified as removable time froma total of 435 days on the eight offset wells. The problems identifiedby analysis are shown in Fig. 3 as a Pareto chart. Significantly, theinvisible lost time was categorized as bit/BHA, 47%; mud, 23%;

waiting on weather (WOW), 13%; and other, 15%. Clearly, if thebit/BHA and mud problems were addressed, then 72% of theremovable time would be eliminated. Drilling and completingoutside cyclone season would potentially remove another 13%because of WOW.

The development of the theoretical well activities and timesprovided a baseline for further analysis of the sequences required.Program evaluation review technique charts were constructed,typically listing 300 tasks/well, and used to undertake critical pathanalysis. A number of activities were removed from the critical pathby introducing new tools and/or techniques.

The engineering planning work had a big impact on the speci-fication of the drilling rig needed for the project. The cost of thehigher rig specification was easily justified against the potential

TABLE 3EFFECTIVE TIME IN HOURS FROM WANAEA AND COSSACK REMOVAL TIME STUDY

Section

Wanaea CossackTechnical

LimitNo. 1 No. 2 No. 3 No. 4 No. 5 No. 1 No. 2 No. 3

Run TGB 2.25 2.00 3.00 2.50 1.50 6.50 2.50 2.50 1.50

Drill 36-in. hole 9.50 8.50 11.00 19.50 7.50 18.00 9.00 15.50 7.50

Run 30-in. casing 10.50 7.00 6.00 6.75 4.60 9.50 10.25 8.50 4.60

Drill 26-in. hole 28.25 33.00 23.00 27.25 27.75 28.50 30.50 25.75 23.00

Run 20-in. casing 10.25* 11.50 13.50 13.50 13.50 11.50 13.50 15.00 10.25

Run Bop 13.25 13.50 13.00 10.00 16.25 17.00 9.00 10.75 9.00

Drill 17 12-in. hole 133.25 110.00 118.00 117.50 114.75 155.50 172.75 174.00 110.00

Run 13 38-in. casing 32.50 23.50 36.25 21.75 25.00 22.50 22.75 23.00 21.76

Drill 12 14-in. hole 270.25 201.50 119.50 105.50 106.50 319.00 122.75 193.75 106.60

Run 9 58-in. casing 44.00 25.00 27.50 24.25 44.75 24.50 42.25 23.75 23.76

Drill 8 12-in. hole 130.25 53.00 72.00 90.75 71.25 61.00 98.50 111.25 53.00

Log 49.00 71.00 54.00 36.50 43.00 22.75 62.0m 36.50

Run liner 59.50 25.00 37.50 41.25 23.50 42.50 42.50 23.50

Clean out 44.00 37.50 26.50 45.00 69.50 26.60

Total hours 684.5 640.00 576.25 227.25 511.00 785.00 668.50 715.25 466.26

Total days 28.5 26.70 24.00 23.20 21.30 32.70 27.90 29.80 19.00

* The highlighted cells identify previous best (Technical Limit) times.

Fig. 3Results of the removable time study performed on eight offset wells. Categorized by bit/BHA, mud, WOW,and other.


efficiencies indicated by the theoretical well time. The result allowedfit for purpose rig selection and, ultimately, sole source negotiation ofthe selected rig rather than a low bid tendering process.

A number of other factors were addressed during the planningstage and were influential in the overall success of the project.These included identification and management of risk; communi-cation of the plan to all involved, to gain ownership and sharedgoals; and, preoffshore review of procedures, sequence of events,and equipment.

Operations. Invisible lost time was made very visible in theoperational phase of the project. Any activity time deviation fromthe technical limit schedule was reported on the daily report. If thedeviation was negative (i.e., time reduced), the time expected onfuture wells was adjusted downward and a new technical limit wasdefined. If the deviation was positive (i.e., extra time taken), it wasanalyzed for cause. If the extra time taken was unavoidable (i.e., the

technical limit time had been underestimated), a new time wasdefined for the next well. If it was removable, solutions weredeveloped that would prevent reoccurrence of the event.

Similar to the approach taken by Kadaster,5 the use of a totalquality management (TQM) approach was found to be very effec-tive (see the TQM feedback loop in Fig. 4). The feedback systemwas very broad in its application and became very efficient withproper resourcing from either company or contractor.

Initially, offshore personnel were uncomfortable reportingagainst the technical limit because every nonconformance, large orsmall, was exposed. It was important that management encouragedand supported the offshore team in pursuit of the ideal standardsthat had been set. A no-blame environment was essential andpracticed with vigor.

The measurement of operations against the technical limit sched-ule was extremely powerful. No better way was found to highlightand pursue maximum opportunity for improvement.

Fig. 4Diagrammatic representation of the management model developed tosupport the technical limit approach.

Fig. 5Days to total depth (TD) for wells drilled on the North West Shelf between 1968 and1992. Results from Wanaea and Cossack have been included to show the improvement made.


ResultsDrilling Performance. Typical historical drilling times for direc-tional appraisal wells on these fields were 42 to 52 days. Antici-pating some improvement in performance, 50/50 budget estimates(a budget estimate based on time, considered as equally likely to beexceeded than beaten) had been prepared with 34 days for a typicalmoderately deviated well and 46 days for a horizontal section well.Technical limit determination was carried out with the methodol-ogy described, arriving at durations of 19.8 days and 27.5 days,respectively.

A comparison between the technical limit, actual, and effectivetimes on Well 1 is presented in Table 4. The fifth column showswhere a new technical limit had been set.

Furthermore, Well 1 took 22.1 effective days. This was animprovement of 6.6 days compared with effective times of 28.7 and29.2 days of the previous offset wells; however, Well 1 had 26.2days of removable time. Table 5 shows the causes of the removabletime and the actions taken to prevent recurrence. Most of theremovable times were new problems not seen on the offset wells,an indication that the drilling process was still not in control.

TABLE 4POST-WELL ANALYSIS FROM WELL 1

Section

StartingTechnical

LimitActualTime

RemovableTime

EffectiveTime

NewTechnical

Limit

Drill 36-in. 9.0 11.0 0 11.0 10.0

Run 30-in. 11.0 9.0 2.0 7.0 7.0

Drill 26-in. 21.0 27.0 0 27.0 21.0

Run 20-in. 25.0 67.0 42.0 25.0 25.0

Run BOP 20.0 30.0 0 30.0 20.0

Drill 17 12-in. 107.0 380.0 249.0 131.0 107.0

Run 13 38-in. 36.0 43.0 2.0 41.0 36.0

Drill 12 14-in. 77.0 142.0 48.0 94.0 77.0

Run 9 58-in. 44.0 42.0 0 42.0 42.0

Drill 6 12-in. 65.0 104.0 39.0 65.0 65.0

TD logging 6.0 14.0 5.0 8.0 6.0

4 12-in. liner 57.0 292.0 241.0 51.0 51.0

Total hours 476.0 1158.0 626.75 531.0 467.0

Total days 19.8 48.2 26.1 22.1 19.5

TABLE 5POST WELL REMOVABLE TIME ANALYSIS FOR WELL 1

Number Problem

RemovableTime

(hours) Cause Action and Solution

1 Back-off in 17 12-in. hole 187.25 High drilling torque as aresult of formation andaggressive drilling.

Reduce drilling parameters. Eliminatestring weak-points, review drillingprocedures.

2 Twist off 2 38-in. drillpipe in liner 97.00 Excess weight on pipe. Procedures. Source stronger pipe.Minimize use.

3 Cleanout of cement in liner 71.00 Plug not bumped, no shearindication.

Reviewed procedures. Developed innerstring method.

4 Dropped junk basket and nut 64.00 Nut backed off downhole. Weld nut to shank. Review toolprocedures.

5 Correction run in 12 14-in. hole 44.00 Right hand bit walk and droptoo high.

Review bit and BHA selection. Allow lefthand lead.

6 No cement in 9 58-in. shoe 29.00 Mud syphoning through topdrive when changing over torelease dart.

Reviewed cement head design. Increasedshoe track to 3 joints. Plan to bump plugand pressure test casing.

7 Dropped 20-in. casing 24.00 Backup tong slipped. Review top drive and casing procedures.

8 Rig downtime (total) 22.00 Various equipment problems,critical path maintenance.

Review maintenance planning.

9 Problem landing CGB 18.00 Incorrect bolts-qualitycontrol. Cuttings build up atwellhead.

Use correct bolts. Review procedures.

10 Washout in Monel DC 14.00 Stress corrosion cracking. Inspect all monels internal (boroscope).Review quality assurance/quality controlprocedures.

11 Trip in 17 12-in. slow ROP 11.00 Bit balling. Use PDC bit. Review mud system.

12 Logging failure 4.00 Intermittent short in toolconnection.

Tool returned for repair. Calibrate backupbefore use.

13 Miscellaneous 42.50 Small events. As available resources allow.


Fig. 6Comparison of the effective time and removable time wells drilledbefore the start of the project and Wells 1 and 3. The inefficiency shown isa result of advancing the technical limit and taking a backward view.

Fig. 7Comparison of the effective time and removable time for thecomparable portions of the completions. Again inefficiency can be shownby taking a backward view from the final technical limit.

TABLE 6POST WELL ANALYSIS FOR WELL 3

SectionStarting Technical

LimitActualTime

RemovableTime

EffectiveTime

New TechnicalLimit

Drill 36-in. 10.0 7.5 0 7.5 7.5

Run 30-in. 7.5 6.5 0 6.5 6.5

Drill 26-in. 21.0 24.5 1.5 23.0 21.0

Run 20-in. 25.0 24.0 4.0 20.0 20.0

Run BOP 16.5 19.8 0 19.8 16.5

Drill 17 12-in. 111.0 117.0 1.8 115.3 111.0

Run 13 38-in. 36.0 40.0 7.5 32.5 32.5

Drill 12 14-in. 77.0 103.8 16.3 87.5 77.0

Run 9 58-in. 42.0 41.3 3.0 38.3 38.3

Drill 6 12-in. 63.0 59.8 4.8 55.0 55.0

TD logging 6.0 9.3 1.8 7.5 6.0

4 12-in. liner 51.0 205.3 155.0 50.3 50.3

Total hours 466.0 658.5 195.5 463.0 441.5

Total days 19.4 27.4 8.1 19.3 18.4


Well 3 was almost identical to the first well (Well 2 had thehorizontal section) and makes a good comparison. The drillingperformance for Well 3 is presented in Table 6. Overall perfor-mance had improved by 2.8 days, as indicated by the effective time;also, the offshore team was more efficient in many areas, includingrunning blowout preventer and casing. Again, new events happenedthat had not been anticipated. Only 8.2 days were identified asremovable time, 85% of which was accounted for by just twoevents. An indication that process control was quickly improving.

The analysis for Well 2 (with 808 m of horizontal section) wasdrilled in 40.4 days with 9.4 days of removable time. Adding allwells together, the drilling part of the project took 116.1 dayscompared to the budget base time of 114 days. Although drillingperformance still contained significant removable time, it was amarked improvement on the past (see Fig. 5).

A learning curve is evident by comparing effective time andremovable time for each of the three wells (Fig. 6). Indeed, it wouldappear that the operational efficiency had approached the technicallimit in just three wells. Such a performance has been described byBrett et al.6 and termed as excellent. Good is the adjective used forapproaching the learning curve asymptote in five wells.

Completion Performance. Subsea completions technical limits of10.5 days (new well) and 14.0 days (predrilled well) had beenestablished based on the planning phase described. These comparedwith 50/50 budget estimates of 16.5 days and 21.5 days, respec-tively. All these times included production testing.

The actual durations achieved averaged 11.3 days for new wellsand 15.9 days for existing wells on the six well campaign.

The process of refining the technical limit continued as wellswere completed. The six completion times are shown in Table 7.The technical limit for a new well had changed from 10.5 days to8.5 days at the end of the six well campaign. The best new wellcompletion was 9.1 days, which includes all forms of removabletime. The subsea completions were finished 33 days ahead of the50/50 budget times.

The completions, by their more mechanically controllable na-ture, started further along the learning curve than drilling did. Thefirst completion took 25% less time than the 50/50 budget time. Fig.7 shows the technical limit after the final completion compared witheffective time and removable time for each core completion ac-tivity. The completions learning curve is still evident in Fig. 7,although less pronounced than with drilling.

The drilling and completion campaign not only delivered sig-nificant cost savings against the budget, but also delivered subseawells with productivity 30% greater than expected.

ConclusionsThe results presented here could be considered lucky with such asmall data set; this is not disputed. The important conclusion withthe methodology outlined lies with a focus on the theoretical well

and a technical limit. These concepts were quantified and used inan aggressive method to target the What is possible? question.Technical limit was applied to planning and operations. The fol-lowing points have been concluded from this approach.

1. Drilling and completion performances can be usefully mod-eled with the technical limit.

2. The invisible lost time component of this model offers insightinto operational inefficiencies that conventional industry lost timesystems ignore.

3. Technical limit was used to set the highest performancestandards possible.

4. Quantifying and addressing removable lost time provided themaximum opportunity to improve.

5. The technical limit model led to a step change in understandingand performance when applied to three new directional wells andsix subsea completions.

6. Adoption of this technique requires courage because it revealsevery deviation from the ideal. A no-blame culture was essential toits acceptance.

AcknowledgmentsWe thank Woodside Offshore Petroleum and its joint ventureparticipants [BHP Petroleum, BP Developments Australia, Chev-ron Asiatic, Japan Australia LNG (MIMI), and Shell DevelopmentAustralia] for support throughout this project. Additional thanks toSedco Forex, Baker I.S., and all personnel that contributed to thedevelopment and application of the technical limit method. Per-sonal thanks to Phillis Harley for tireless support from the begin-ning of the project and through the preparation of this paper.References1. Noerager, J.A., White, J.P., and Floetia, A.: Drilling Time Predictions

From Statistical Analysis paper SPE/IADC 16164 presented at the 1987SPE/IADC Drilling Conference, New Orleans, Louisiana, 1518 March.

2. Shute, J. and Alldredge, G.: Conoco Cuts North Sea Drilling Time by40%. World Oil (July 1982).

3. Huber, D.D. and Walton, H.: A Realistic Goal From a Semi: Drill to10,000 ft in 10 Days, World Oil (September 1983).

4. Walters, N.S.: Maximizing Well Potential: An Integrated Approach,paper SPE 36997 presented at the 1996 SPE Asia Pacific Oil and GasConference, Adelaide, Australia, 2831 October.

5. Kadaster, A.G., Townsend, C.W., and Albaugh, E.K.: Drilling TimeAnalysis: A Total Quality Management Tool for Drilling in the 1990s,paper SPE 24559 presented at the 1992 SPE Annual Technical Confer-ence and Exhibition, Washington, D.C., 47 October.

6. Brett, J.F. and Millhiem, K.K.: The Drilling Performance Curve: AYardstick for Judging Drilling Performance, paper SPE 15362 presentedat the 1996 SPE Annual Technical Conference and Exhibition, NewOrleans, Louisiana, 58 October.

SI Metric Conversion Factorsft 3 3.048* E201 5 m

in. 3 2.54 E100 5 cm*Conversion factors are exact. SPEDC

David F. Bond is a principal drilling engineer for WoodsideEnergy Ltd. in Perth, Australia, responsible for technical integrityand performance of all Woodside drilling activities. He holds aBS degree in mechanical engineering from the U. of Leeds, U.K.Phil W. Scott is an implementation manager for new systemsbeing developed by Woodside Energy Ltd. in Perth, Australia.His recent focus has been on human elements in well construc-tion. He holds a BS degree in civil engineering from the U. ofWestern Australia. Peter E. Page is a senior completions engi-neer for Woodside Energy Ltd. in Perth, Australia. Previously,Peter worked for Shell Intl. He has worked for Shell in the U.K. andin Norway before moving to Australia in 1992. Tom M. Windhamis a drilling superintendent with Chevron Overseas PetroleumInc., in Escravos, Nigeria. He was seconded to Woodside fromNovember 1993 to December 1996. He holds a BS degree inpetroleum engineering from West Virginia U.

TABLE 7FULL COMPLETION TIMES

Completion

TechnicalLimit(days)

ActualTime(days)

RemovableTime(days)

EffectiveTime(days)

1 11.4 12.5 1.4 11.1

2 10.7 12.8 2.3 10.5

3 10.9 10.8 1.2 9.6

4 8.9 9.1 1.2 7.9

5 14.9* 19.3 4.7 14.6

6 13.2* 14.2 2.0 12.4

* Include running additional equipment.


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00051181Applying Technical Limit Methodology For