efficiency in pipe handling.pdf

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Copyright 2000, IADC/SPE Drilling Conference

This paper was prepared for presentation at the 2000 IADC/SPE Drilling Conference held inNew Orleans, Louisiana, 2325 February 2000.

This paper was selected for presentation by an IADC/SPE Program Committee followingreview of information contained in an abstract submitted by the author(s). Contents of thepaper, as presented, have not been reviewed by the International Association of Drilling

Contractors or the Society of Petroleum Engineers and are subject to correction by theauthor(s). The material, as presented, does not necessarily reflect any position of the IADC orSPE, their officers, or members. Papers presented at the IADC/SPE meetings are subject topublication review by Editorial Committees of the IADC and SPE. Electronic reproduction,distribution, or storage of any part of this paper for commercial purposes without the writtenconsent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is

restricted to an abstract of not more than 300 words; illustrations may not be copied. Theabstract must contain conspicuous acknowledgment of where and by whom the paper waspresented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax01-972-952-9435.

AbstractA drilling rig, either fixed or mobile, can be described as a

factory that digs a hole. The purpose of this paper is to

examine the fundamentals of the well bore construction

process and how this has traditionally influenced rig design.By using an economic justification analysis to evaluate the

tubular handling processes, a step change in performance and

a breakthrough in rig design will be achieved.

This paper will outline the developmental steps taken by

the rig designer, and in parallel, the technologicaldevelopment of tubular handling systems, that contribute to

this step change in performance. Actual field performance forthe pipe handling systems will be presented, including the

innovative process that allows casing to be assembled in

stands and racked back in doubles in preparation for casing the

well.

Additionally, the handling of single 80 or 90 joints ofcasing and/or drill pipe is considered under parameters such as

eliminating couplings and the subsequent reductions in make

up and break out time, tool joint maintenance, and casing wear

that can be attributed to tool joint hard banding.

The innovative use of both an automated vertical and

horizontal pipe racking system, potentially providing the rig

design with a smaller, lighter derrick structure and increasedefficiency, will be illustrated. An example of the computer

modeling system will be used to present an animation of the

tubular handling process.

The resultant benefits of this combined approach can yieldoverall performance advantages of up to 20%, with associated

up front economical benefits, over traditional jack up designs.

IntroductionA typical exploratory well drilled by a jack up unit in the Gulf

of Mexico usually involves various activities that are bes

described by a depth vs. time curve. Fundamental toenhancing performance in any given well is endeavoring to

shorten flat spots in this curve. Technological advancements in

pipe handling have done just that. Such advancements havetraditionally been determined by the rig geometry, which, in

turn was dictated by the lengths of drilling tubulars used to

drill and construct the well. This paper deviates from

traditional thinking by exploring the benefits of longer

tubulars and how they maximize the capability of an advanced

pipe handling & racking system.

Table 1 and Fig. 2 describe the base line well3 that this

paper uses. The graph represents actual footage against time

and is generated by the performance of a typical GOM jack upunit, equipped with a top drive drilling system. By

examination of the data that is used to construct this curveand specifically applying technology and automation to this

data, performance is enhanced accordingly.

This discussion also lends itself to the handling of longer

well bore casings, which are ordinarily transported to the rigand handled in approximately 40 lengths. JU2000 will now

accommodate 80 or 90 lengths of casing as doubles made up

and transported to the rig as such, or single joints. Similarly

the horizontal pipe handling (HPH) capabilities of JU2000

also permit the handling of single 90 joints of casing, drilpipe, tubing, or any other oil field tubular.

It can be shown that in addition to lowering overall well

bore construction costs, JU2000 also boasts capital equipmencost savings for the rig owner. These costs include, but are not

limited to the up front costs of the derrick, drill floor and

substructure, and the potential to eliminate couplings from the

various strings of pipe that are use to construct a well bore

The elimination of couplings not only results in a costreduction in terms of the couplings themselves, but can also

reduce associated maintenance expenditure.

IADC/SPE 59105

JU2000 - Efficiency by DesignHoward Day - Friede and Goldman Ltd.; Mike Williams - Varco International


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2 H.W.F. DAY, M. WILLIAMS IADC/SPE 59105

Pipe Handling BackgroundHistorically, the drilling industry has evolved such that a

contractor has been able to rack back drill string componentsin the derrick in longer lengths. It was originally laid out

completely in singles. The industry further evolved such that

a rig owner had the facility to rack back doubles, which are

two 30 joints of drill pipe connected together and stood back

in the derrick vertically. Then there were triples (three 30joints), and now "fourbles" of range 2 (four 30 joints), or

triples of range 3 drill pipe (40 joints), comprising a 120'"stand" of drill pipe.

Horizontal racking was developed as a requirement in the

design of early drillships. A horizontal racking system was

necessary to achieve the desired CG and motion

characteristics of the vessel. One of the first mechanizedhorizontal rackers was built for the Global Cuss 1. Although

it was simple, the system proved to be reliable and kept up

with the fastest tripping rates.

Mechanized vertical pipe racking was introduced on the

Humble Oil Rig 30 as the early BJ type V three arm vertical

pipe racking system. An era of mechanization had begun.

These early systems were robust and by most accounts, addedsome time savings to the tripping process. Such systems do

not offer the offline capabilities of stand building and BHA

handling, which modern Pipe Racking Systems (PRS) offer

today. These early machines required extensive modificationsto the derrick, requiring large windows in the derrick structure

to accommodate the racking arms.

These factors and industry growth contributed to a slow

but steady acceptance of these systems into the 80s. The

column pipe racking development addressed the need for more

robust designs and the drive toward semi-automation. Varco

introduced the first of these designs, the PHM in 1986. ACtechnology and modern control systems with encoding drove

this new era of vertical machine, allowing a single operator toprecisely manipulate pipe and collars. These machines brought

on additional time savings in BHA handling, providing a

significant advantage in safety and efficiency.Traditionally, conventional jack up design has dictated that

the drill string be laid down in order to facilitate a rig move, or

changed out per operational requirements. Due to extended

reach requirements, JU2000 now boasts cantilever pipe rack

geometry, which permits an operator to do this in 90' lengths.

These 90 lengths can comprise either doubles of range 3,

triples of range 2, or single 80 or 90 joints a smalldeparture from tradition, although a giant step forward in pipe

handling.

Ultimately, JU2000 offers operators and contractors theability to handle oil field tubulars in longer lengths. Indeed,

this has been fundamental to the way pipe handling hasevolved in the drilling industry. Quite simply, any time that a

length of pipe can be handled in a ninety-foot length instead of

the more traditional thirty or forty-foot lengths, pipe-handling

efficiency is dramatically improved.

Technological AdvancementsTo date, no jack-up or bottom supported Mobile Offshore

Drilling Unit (MODUs) incorporates all of the capabilities, as

described above, to the fullest. These capabilities are

described as follows, whilst simultaneously juxtaposing thelatest technology in automation against base case data (Table1).

Horizontal Pipe Handling. Historically, the machines thahave performed this function accommodate twenty or thirtythousand feet of drill pipe only, and have a substantial vertica

requirement, which is not readily available with modern jack

up designs. A horizontal pipe handling (HPH) capability is

permitted with JU2000 by virtue of the area available on the

cantilever pipe rack, due to the extended reach capability of

the unit. Additionally, robust conveyor technology today

allows HPH to be utilized on a jack up unit, in conjunctionwith an articulated crane being mounted centrally on the rigs

port side cantilever beam (Fig. 1). This feature permits the

following:1. The ability to change out entire strings of drill pipe or

other oil field tubular, off of the critical path, without lowering

a single joint of pipe into the mouse-hole or into the well bore

This is accomplished by laying it down or picking it uphorizontally in 90 sections. This feature will eliminate items

63 and 66 a time related saving of approximately 24hrs(Table 1)

2. The handling of triples of range 2, doubles of range 3, or

longer single joints of drill pipe, which can offer a reduction in

the number of tool joints in the drill string. This wil

significantly reduce casing wear. A large percentage of casing

wear can be attributed to tool joint hard banding. Obviouslythis can offer cost savings in tool joints and tool jointmaintenance for the owner of the drill string.

3. The handling of doubles of range 2, range 3, or longer

single joints of casing, tubing or other oilfield tubular. This

can offer significant capital equipment cost savings byreducing the number of couplings required in the string, and

significant time related costs in making up or breaking out a

string of any such tubular.

4. The handling of casing strings made up in doubles of

range 3 at a shore base, then transported to the rig as doubles,

and then handled to the rotary as doubles into the well bore, as

one component, as TLP riser joints are sometimes handledtoday. Indeed, subject to manufacturing capabilities, thehandling of single 90 joints of casing, drill pipe, tubing, orany other oil field tubular is also permitted by the geometry of

the extended reach cantilever.

5. Greater flexibility with the set back area, therefore

allowing the standing back of longer strings of casing, or

increasing the set back area for various (or all) bottom hole

assemblies, and/or a work string of tubing.

6. A horizontal pipe handling capability offers the

utilization of a smaller derrick footprint, which can offer

enhanced set back area efficiency over the larger, more costlyderrick arrangements. The setback area can be a directfunction of the derrick footprint. Benefits to the smaller

derrick footprint include a lighter derrick, drill floor andsubstructure, therefore potentially increasing the allowable


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IADC/SPE 59105 JU2000 - EFFICIENCY BY DESIGN 3

hook / setback / rotary loading combinations, when in the

extended reach mode, off of the longitudinal centerline of the

rig. Obviously, the smaller derrick footprint also reduceswindage.

Vertical Pipe Handling. Column type pipe racking machinesare common place with most newbuilds (floating and bottom

supported MODUs) today. However, when the functionalityof a vertical pipe handling system is augmented with that of a

horizontal system, this marriage of functionality has acomplimentary nature.

The Glomar Explorer is the first rig from the recent marine

build cycle to incorporate both horizontal and vertical

automated (mechanized) pipe handling systems. Jim Long,

Rig Manager for the Glomar Explorer stated:At Global Marine, we believe the combination of

horizontal and vertical racking systems offers many benefits.

Having both systems allows us to perform stand building of

casing, drill pipe and BHAs while drilling ahead. Keeping the

primary drill string off the floor also allows us to keep our

landing string or a production test string in the derrick,

reducing open hole time. A jack-up with both pipe handlingsystems should see similar offline benefits as we see on the

Explorer and our two new drillships.

As the use of vertical pipe racking systems has grown, so

has the space required to store the array of tubulars that isrequired to drill modern 20,000 foot wells. Both the first and

second generation rackers required the machine to sit between

the setback area, taking up valuable drill floor real estate. The

development of parallel racking, as illustrated perfig 1, allows

JU2000 to maximize setback flexibility utilizing an adjustable

fingerboard for all tubulars.

Offline Capability. As fig 2 illustrates, the key to real

productivity and step changes in performance is in parallel,simultaneous, or concurrent activities, reducing the non-

productive time of our factory. Many of the recent new builds

incorporate an auxiliary mouse hole that will allow standbuilding while drilling ahead. This patented technology1

allows for building of triples while drilling ahead. It can

facilitate the building of a BHA assembly, and with some

designs can allow casing to be built in doubles and racked

back in preparation for the casing run. JU2000 will allow for

all of these features resulting in significant time savings and

efficiencies due to parallel activities. In addition, the use oflonger tubulars will contribute to the overall benefits of

mechanization.

Table 1 demonstrates the offline capability of the marriage ofthe horizontal and vertical pipe handling systems, clearly

showing those operations which can be performed off of thecritical path.

AC Technology & AHS. The broad speed and torque range ofAC motor technology produces superior machinery

performance in both top drives and drawworks with single-

speed direct drive gear boxes. In addition to the simplicity ofthe mechanical components, the ability of AC motors and their

controls to act as servos, enables a greater level of control and

flexibility never before experienced in drilling controls. The

growing use of AC technology on modern drilling machineryhas greatly impacted the performance, reliability and weigh

savings of these devices. The use of AC motors is prevalen

with column pipe racking, top drives and now drawworks, or

hoists. The automated hoisting system development continues

in a trend of performance breakthroughs, and with bothsignificant performance enhancements via the electronic

driller feature, and a 45% weight savings in a typical threethousand horsepower class machine, this will have significan

impact on a cantilever jack up design.

The Electronic Driller2 is designed to provide a near

constant weight on bit. Computerized closed loop feedback

control of the disc brake allows exceptional fast line controlResults from a 76 well study in South Texas yielded a 37%

reduction in rotating hours when the Electronic Driller was

used.

Capital Equipment Cost and Weight SavingsIn addition to a substantial overall performance increase

significant equipment cost savings can be seen by both the rigowner and operator in terms of the up front costs of the unit

and the various tubular components required in the well bore

construction process. Some of these savings are listed as

follows:

Smaller Derrick Footprint and Lighter Equipment.1. When comparing a 30 x 35 footprint against a 40 x

40 footprint, a weight saving of up to 15% of the derrick

structure is possible, with little compromise in set back area

Cost saving in the derrick structure is estimated to be as much

as 10%.

2. Weight savings in newer drawworks designs can be asmuch as 80,000lbs. (3000hp class)

3. The weight of the drill floor and substructure ispredominately dictated by the weight of the equipment that i

supports. The smaller derrick footprint, resulting in shorter

spans, in combination with lighter equipment, is estimated toresult in weight savings to the drill floor and substructure that

approach 25%.

Longer Tubulars Less Couplings.JU2000, which can accommodate HPH, can ultimately handle

longer tubulars. Handling longer oilfield tubulars is

fundamental to pipe handling performance enhancement. Cos

savings can be derived as a result of this capability in terms oconsidering coupling elimination.

Although there are different schools of thought on the

practicality of using longer drilling tubulars, some capitaequipment cost considerations are listed as follows:

1. A cost saving of approximately 20% can be realizedwhen considering a new string of range 3 drill pipe against a

string of range 2.

2. Fewer tool joints will result in less tool joint

maintenance.

3. Fewer tool joints will reduce any casing wear that can

be attributed to tool joint hard banding.4. Departing from manufacturing considerations, longer


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lengths of either drill pipe or casing can be handled efficiently

with a jack up unit that has an HPH capability consider 80

foot or 90 joints.

ConclusionTraditionally, the geometry of the cantilever on a

conventional jack up has dictated that the drill string be laid

down in order to facilitate a rig move, or changed out peroperational requirements. JU2000 now allows an operator to

do this in 90' lengths. In conjunction with the horizontalhandling capability, vertical pipe handling functionality

reciprocally compliments the overall performance of the pipe

handling system. After all, that is what a drilling rig does in

a manner of speaking, handle pipes!

These enhancements are a direct result of the rig designerand handling equipment manufacturer jointly understanding

well bore construction processes. In terms of modern MODU

design and the design of the handling equipment that the rig is

outfitted with, a step change in the performance of the unit as

a whole is a derivative of designing the unit from the bottom

of the well up, instead of from the rotary table out.

In addition to performance enhancements, the overall costof a newbuild jack up unit can be lowered. These economical

benefits are a function of creative thought processes, which

should inherently endeavor to reduce size, and therefore

weight and subsequent costs, instead of the bigger, heavier,and therefore less overall cost effective approach, or

popularly throwing steel at the problem.

From the evolution of the cable tool rig to rotary drilling,

and on with the myriad of technical advancements, our

industry has challenged the traditional way we drill wells and

build rigs. If we are to continue to drive the cost of well

construction down, we must continue to embrace change. Thefirst jack up unit to not incorporate an independently powered

rotary table into its design was the Galaxy I in 1989. In

choosing a non conventional approach to the implementation

of a rotary table, as this particular contractor did, we have the

opportunity to think out of the box, and build a rig thatembodies the emerging tubular handling technology and

benefits that modern floating rigs use today.

The benefits of longer tubulars, both horizontal and

vertical pipe racking systems and the performance per

pound benefits of the AC hoist and other integrated drillingcontrols will continue to improve on well bore construction

curves. As we move into the future, we will expand the rigcapability envelope, and strengthen the momentum of change

and progress that our industry has embraced into the new

millennium.

AcknowledgmentsWe thank Jim Long (Global Marine) for an overview on

horizontal pipe handling philosophy; Tommy Welch

(Loadmaster Rig Services) for thoughts on derrick design in

way of drill floor arrangements; Doug Snapp (Grant Prideco)

for thoughts on tubular possibilities; Sid Truitt (Dallas Mavis

Trucking Services) for logistical opinion; Paul Geiger Jnr. &

Calvin V. Norton (Friede and Goldman Ltd.) for input on drillfloor, substructure and cantilever structural design

considerations, and general arrangements; Jay Cotaya, Pau

Rowlett, Phil Vollands, Brian Eidem (Varco Systems) for

various contributions.

Footnotes1Varco International is the owner of the Foxhole patenregistered in the following countries; USA, Japan, Denmark

Norway, France, UK and The Netherlands.2 Ref. Oil and Gas Journal article 12-14-98.3 Per GRI (Gas Research Institute)


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Fig 1: JU2000 Vertical PRS & HPH Systems: Plan and Elevation


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legend - Performance Enhanced By:

Horizontal Pipe Handling Capability (operated by 2 rig personnel)

Additional Offline Capability

AHS & ED

ID Description Duration Notes

26" Hole & 18 5/8" Conductor (1,500' MD) 1.83 days

1 Nipple up diverter and function test 2 hrs

2 Pickup BHA 1 hr Standing. back in derrick

3 Trip in 1 hr

4 Washout Drive Pipe Bit #1 1 hr

5 Run Gyro multishot 1 hr

6 Trip out 1 hr

7 Pick up 13 1/2" Directional BHA 2 hrs Standing back in derrick - tested

8 Trip in 1 hr

9 Drill hole section bit #2 4 hrs

10 Trip out 1 hr

11 Pick up 26" underreamer assembly 2 hrs Standing back in derrick

12 Trip in 1 hr

13 Underream hole section 5 hrs

14 Trip out 1 hr

15 Pick up hole opener assembly 1 hr 16 Wiper trip to TD 1 hr

17 Circulate bottoms up 1 hr Stand back 5" (for next hole section) in stands from horizontal storage(concurrently)

18 Trip out 1 hr

19 Rig up & run 18 5/8" Casing 6 hrs Run in doubles, from horizontal or vertical

20 Circulate (Annulus & Casing Volume) 2 hrs Stand back 5" (for next hole section) in stands from horizontal storage

(concurrently)

21 Cement 1 hr Stand back 5" (for next hole section) in stands from horizontal storage

(concurrently)

22 Set slips and cut 18 5/8" 1 hr Stand back 5" (for next hole section) in stands from horizontal storage(concurrently)

23 Nipple down 20" Diverter 1 hr Stand back doubles of 13 3/8" csg. (for next hole section) from horizontalstorage (concurrently)

24 Install wellhead and test to 300psi 2 hrs Stand back doubles of 13 3/8" csg. (for next hole section) from horizontalstorage (concurrently)

25 Nipple up diverter 3 hrs Stand back doubles of 13 3/8" csg. (for next hole section) from horizontalstorage (concurrently)

17 1/2" hole & 13 3/8" Surface casing (4,500' MD) 1.52 days

26 Pick up BHA 1 hr

27 Trip in 0.5 hrs

28 Pressure Test Casing & Function test diverter 0.5 hrs

TABLE 1 BASE CASE DATA

Note: The following data does not reflect any breakdown of timespent wire line logging each hole section. Clearly, additionaloffline activity would be conducted whilst logging, providing

that this concurrent operation did not interfere with the wire lineor the handling of the tool string on the catwalk.The logging program of the base case well is estimated to takeand additional 3 days.


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29 Drill out & perform leak off test 0.5 hrs

30 Drill Hole Section 13 hrs

31 Trip Out and lay down BHA 2 hrs Rack back BHA

32 Rig up & Run 13 3/8 in 5.5 hrs Run in doubles, from horizontal or vertical

33 Circulate 4 hrs Stand back 5" (for next hole section) in stands from horizontal storage

(concurrently)

34 Cementing 3 hrs Stand back 5" (for next hole section) in stands from horizontal storage

(concurrently)35 Set Slips and cut 13 3/8 casing 2 hrs Stand back 5" (for next hole section) in stands from horizontal storage

(concurrently)

36 Nipple Down 20 in Diverter 1.5 hrs Stand back doubles of 9 5/8" csg. (for next hole section) from horizontalstorage (concurrently)

37 Install 20in x 13 5/8 Spool and Test 1 hr Stand back doubles of 9 5/8" csg. (for next hole section) from horizontalstorage (concurrently)

38 Nipple Up 13 5/8 in BOP 2 hrs Stand back doubles of 9 5/8" csg. (for next hole section) from horizontalstorage (concurrently)

12 14 in Hole 9 5/8 in (16,500' MD) 15.98 days

39 Pick up BHA 0.5 hrs

40 Trip in & Test Casing 3 hrs

41 Drill out & perform leak off test 1.5 hrs

42 Drill Hole Section 65 hrs Enhanced performance with AHS & ED

43 Trip for Bit 6 hrs









52 Drill Hole Section 50 hrs Enhanced performance with AHS & ED53 Circulate and Condition Mud 4 hrs Pick up doubles of 9 5/8" casing from horizontal storage (concurrently)

54 Trip Out 8 hrs Lay down 5in DP in stands horizontally (concurrently)

55 Change Rams to 9 5/8 in Casing 1.5 hrs

56 Rig up and Run 9 5/8 in casing 14 hrs Run in doubles, from horizontal or vertical

57 Circulate 2 hrs Lay down 5in DP in stands horizontally (concurrently)

58 Cementing 3 hrs Lay down 5in DP in stands horizontally (concurrently)

59 Set Slips and Cut 9 5/8 in Casing 2 hrs Lay down 5in DP in stands horizontally (concurrently)

60 Nipple Down BOP 3 hrs Pick up BHA, 3 1/2 and 4 1/2 in DP (concurrently)

61 Install 13 5/8 in x 13 5/8 in Spool and Test 1 hr Pick up BHA, 3 1/2 and 4 1/2 in DP (concurrently)

62 Nipple up 13 5/8 in BOP 3 hrs Pick up BHA, 3 1/2 and 4 1/2 in DP (concurrently)

8 3/4 in Hole (19,340' MD) 9.5 days

63 Lay down 5in DP 11 hrs Activity simultaneous to items 57 - 62 or completed during items 64 & 65

64 Install variable rams 2 hrs

65 Test BOP 3 hrs

66 Pick up BHA, 3 1/2 and 4 1/2 in DP 14.5 hrs Activity simultaneous to items 57 - 62 or completed during items 64 & 65

67 Test Casing 0.5 hrs

68 Drill out & perform leak off test 3 hrs


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69 Drill Hole Section 35 hrs Enhanced performance with ED







76 Circulate and condition mud 4 hrs Stand back doubles of 7" csg. (for next hole section) from horizontal storage

77 Trip Out 8 hrs Lay down 3 1/2" and 4" DP in stands horizontally

78 Change Rams to 7 in casing 1.5 hrs

79 Rig up and Run 7 in Casing 14 hrs Run in doubles, from horizontal or vertical

80 Circulate 1.5 hrs Lay down 3 1/2" and 4" DP in stands horizontally

81 Cement 3 hrs Lay down 3 1/2" and 4" DP in stands horizontally

82 Set Slips and cut 7 in casing 2 hrs Lay down 3 1/2" and 4" DP in stands horizontally

83 Nipple Down BOP 2 hrs Lay down 3 1/2" and 4" DP in stands horizontally

84 Release Rig 0 days

Fig 2: GOM Automation and Mechanization Vs. Conventional Design

0

5000

10000

15000

20000

25000

0 5 10 15 20 25 30

Days

Depth

(ft)

Conventional

Automation andMechanization

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