proposal of stinger bits

8/11/2019 Proposal of Stinger Bits

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A proposal for

DEVELOPMENT OF STINGER ELEMENTS

To

Directorate General of Hydrocarbons

OIDB Bhawan, Plot No 2, Sector 73, Noida

November 19, 2013

By

OLIVIA OIL CORPORATION

Head Office-AB-22, Alberta, Canada

GLOSSARY

Bit n : the cutting element at the bottom of the drillstring, used for boring through therock.

Bit record n : a report containing information relating to the operating parameters andperformance of the bits run in a well.

Bit sub n : a short length of pipe installed immediately above the bit. The threads on


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the bit sub accept the pin thread on the bit and the pin thread for the drillcollars.

Bottom hole assembly (BHA) n : the part of the drillstring which is just above thebit and below the drillpipe. It usually consists of drill collars, stabilisers and variousother components.Bottom hole pressure (bhp) n : the pressure,

1. at the bottom of the borehole, or2. at a point opposite the producing formation.

Cable tool drilling n : an earlier method of drilling used before the introduction of

modern rotary methods. The bit was not rotated but reciprocated by means of a strongwire rope.

Circulate v : to pump drilling fluid through the drillstring and wellbore, returning tothe mud pits. This operation is carried out during drilling and is also used to improvethe condition of the mud while drilling is suspended.

Core Bit (Core Head) n: A donut shaped drilling bit used just below the core barrel

to cut a cylindrical sample of rock.

Cuttings n : the fragments of rock dislodged by the bit and carried back to surface bythe drilling fluid.

Diamond bit n : a bit which has a steel body surfaced with diamonds to increase wearresistance.

Directional drilling : n the intentional deviation of a wellbore in order to reach acertain objective some distance from the rig.

Drag bit n : a drilling bit which has no cones or bearings but consists of a single unitwith a cutting structure and circulation passageways. The fishtail bit was an early

example of a drag bit, but is no longer in common use. Diamond bits are also dragbits.

Drilling fluid n : the fluid which is circulated through the drillstring and up the annulusback to surface under normal drilling operations. Usually referred to as mud.Drilling line n : the wire rope used to support the travelling block, swivel, kelly and

drillstring.

Formation fluid n : the gas, oil or water which exists in the pores of the formation.Formation pressure n : the pressure exerted by the formation fluids at a particular

point in the formation. Sometimes called "reservoir pressure" or "pore pressure".

Insert bit n : a type of roller cone bit where the cutting structure consists of speciallydesigned tungsten carbide cutters set into the cones.

Milled tooth bit n : a roller cone bit whose cutting surface consists of a number of steelteeth projecting from the surface of the cones.

Roller cone bit n : a drilling bit with 2 or more cones mounted on bearings. The cuttersconsist of rows of steel teeth or tungsten carbide inserts. Also called a rock bit. R.O.P. abbr : rate of penetration, normally measured in feet drilled per hour.


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W.O.B. abbr : Weight On Bit. The load put on the bit by the drill collars to improvepenetration rate.

Introduction:

When drilling with conventional PDC bit only a small portion of diamond cutting

element is used during a bit run. The percentage of cutter that contacts formation

will depend upon a number of factors including cutter size and amount of depth-

of-cut bearing surface. However in most cases only 10% to 40% of the cutter will

be used to actually shear the formation. The remaining 60 to 90% of the cutter is

locked into the bit body and remains unused during the run. This resulting wear

flats generate a high degree of frictional heat which breaks down the carbon

bond, the increased temperature causes more wear. A drillers effort is to reduce

this wear and generate more ROP (rate of penetration) and RPM (rotations per

minute).

Also with conventional drilling system the speed of bit at periphery is max and

quite sufficient to drill the formation but at the center it is nearly zero thus

exposing the drill string directly to solid formation. This can lead to vibrations and

thus drill string instability, therefore a danger to entire setup. And, the present

PDC bits cannot efficiently drill all range of formations especially the hardcarbonaceous rocks.

These problems have been together solved with solved with innovation of a

stinger element. This comprises of a conical diamond element that is placed at

center of bit with additional feature of ultra-thick diamond layer. The bit is

modified in design for these cutters to fit inside the bit. The cutters rely on

crushing unlike the previous concepts.

BACKGROUND -

The relatively poor performance of PDC bits in harder formations has been

discussed by various

authors since the inception of the PDC in the 1970s.

Despite the fact that PDC bits tend to start drilling at

higher ROP than roller cone or impreg bits, PDCs


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have been observed to reduce ROP quickly leading to

increased Weight On Bit (WOB) and ultimately the

pulling of the bit. Steady state testing of early drag

bits (Appl et.al, 1962) and PDC cutters (Langveld,

1992) showed that both cutters and bits should lastmuch longer than had been observed in the field.

The difficulty of obtaining long bit life in hard rock

was discussed by Feenstra (1988) where temperature

limitations and impact resistance of the PDCs were

highlighted as areas for improvement.

Glowka (1989) stated that wear flats on diamonds

require additional force to make a cut since the WOB

has to crush additional rock to achieve penetration.

The frictional energy generated by the higher WOB

on dulled cutters heats up the cutter. This leads to

thermal damage and delamination of the PDC and

ultimately limits bit performance.

Brett et.al,(1990), described bit whirl as the cause of

cutter chipping and failure, where chaotic bit motion,

due at least in part to unbalanced cutter forces

(Weaver and Clayton, 1993), leads to whirling of the

bit. Bit whirl resulted in off rotation axis motion and

cutters engaging the formation in directions other

than perpendicular to their intended direction.

Subsequent work by many manufacturers resulted in

Anti-Whirl bits with low friction gauge, as

described by Warren et.al, (1990) and Clegg (1992).

Once the bit balance and whirl issues appeared

solved, bit manufacturers set about improving the bit

longevity by increasing the diamond volume on a bit

through thicker diamond, increased cutter and blade

count, increased back-rake, and use of smaller cutters

(Sinor et.al, 1998; Mensa-Wilmot and Calhoun,

2000). This tactic, despite generally making the bits

drill slower, did appear to make the bits last longer.


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Discussion of drill string effects that include

vibration axially, laterally and torsionally by

Langveld (1992) and Warren and Sinor (1994)

showed that each of these modes of vibration could

significantly damage cutters and the bit as a whole.This work has led to the modeling of the bit and BHA

as a single system (Barton et.al 2007) in an effort to

fully understand the various forces that affect the

ROP and overall bit performance during the drilling

process.

Aim: Development of Stinger Element.

Objectives:

Development of optimized bit design.

Selection of appropriate technology.

Field Testing.

Modified drill string.

Statement of Purpose: To reduce the production costs by increasing the bit

durability.

LIMITATIONS

Despite their dominance in oil and gas applications, fixed PDC cutters have an

inherent limitation: because most of its cutting edge is fixed into the bit blade,

very little of the cutter contacts the formation. Accordingly, more than 60% of the

cutters circumferential edge is unused during a bit run.

Methodology: Variable declaration.

Development of optimized bit design


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i.

Bit shape.

ii.

Fluid vents on bit.

iii. Size of stinger element.

iv. Cutting angle.

v.

FEA (finite element analysis) modeling.

Selection of appropriate technology.

i. ONYX 360 rolling PDC cutter technology.

ii. SHARC PDC drill bits.

iii.

Vertical Turret Lathe.

Field Testing

i.

Quartz Granite Wash (GW).

ii.

Feldspar Granite Wash (GW).

iii.

Highly abrasive Granite Wash (GW).

Modified Drill String.

i. CERTIS isolation technology.

ii. Control with IRDV.

iii.

SCAR sampling technology.

EVALUATION OF RISK -

1) a common problem in drilling is that something breaks in fall or down during

drilling . for example , drill string twists off and fall to the bottom . a cone can

break off the tricone bit or tool such as pipe wrench falls from the the rig floor

into the well . This is called fish and cannot be drilled with a normal drill bit due to

which drilling has to be suspended .


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This risk can be mitigitated with the help of spear or overshoot by which the pipe

can be retrieved , a tapered mill reamer is also used for overcoming fishing .

2) The drill string can become stuck in the well due to either mechanical problems

or differential pipe stucking like adhering of drill pipe to the well walls due to

suction .

This is a mitigated risk as drill pipe can be cut with a string shot or chemical cutter

.

3) Sloughing shale is soft shale along the wellbore that absorbs water from thedrillng mud .

This is a mitigated risk as chemical such as potassium salts added to drilling mud

are used to avoid sloughing shale .

4) unexpected abnormal pressures are the common risks in the subsurface which

can't be mitigated .

5) While drilling a well with overbalance , part of the drilling mud liquid with some

fines called the mud filterate is forced into the permeable rock adjacent to the

wellbore . This is called Formation damage and can't be prevented so is a

unmitigated risk during drilling .

6) In some areas corrosive gases such as carbon dioxide and hydrogen sulphide

can flow out of the rocks and into he well as it is being drilled . This is is an

unmitigated risk .

PHASE WISE DISTRIBUTION OF THE WORK PLAN


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Infrastructure: Smith Bits, a Schlumberger company

Man Power: 2 HR manager

1 Project manager

3 Finance managers

2 bit designer

Time: 2 month

PHASE 3: Test run and evaluation of results

Description:

Confirming greater durability through comprehensive testing.

To determine how the new rolling cutter design compared with premium fixed

PDC cutters, drilling durability tests were conducted using a granite test formationwith an unconfined compressive strength of 30,000 psi.

After 90 passes on the test formation, the premium fixed cutters developed

extreme wear flats. The ONYX 360 rolling cutters showed virtually no sign of wear

after 480 passes, and little wear after 600 passes.

Requirements:

Tools - conductor casing, drill string, derrick including hoisting system, drill line

Materials - test formation

Transport: 2 trucks containing cantilevered masts, 1 tool truck transporter

Infrastructure: Test rig


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Tentative cost: $ 0.3 million

Timeline: 4 months

PHASE 5: Successful run

Description: After the modifications were adopted on basis of previous test runs,

the bit was brought for another run. This process of moving of bit between two

positions continues until bit registers a series of successful runs. This in our case

was observed as 15 successful runs on succession. After this final results and data

were tabulated. And, a factor of safety was introduced and bit was passed tested

OK.

Requirements:

Tools - conductor casing, drill string, derrick including hoisting system, drill line

Infrastructure: Test rig

Materials: Test formation

Manpower: 2 drilling engineer

1 tool pusher

1 company man

1 finance manager

1 supply manager

Transport: 2 tool transporter trucks

Tentative cost: $ 2.3 million

Timeline: 1 month


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S.

No.

Phase Requirement Description Unit

Price

(in $)

Quantity Total

1 I Manpower Formation

Evaluation

Engineer

116000 2 232000

2 I Manpower Well Logging

Engineer

85000 3 255000

3 I Manpower Drilling Fluid

Engineer

84000 2 168000

4 I Manpower Geologist 33000 1 33000

5 I Manpower Driller 28000 2 560006 II Manpower HR manager 13000 2 26000

7 II Manpower Project manager 12000 1 12000

8 II Manpower Finance manager 10000 3 30000

9 II Manpower Bit designer 9500 2 19000

10 III Manpower Drilling Engineer 10000 2 20000

11 III Manpower Tool pusher 6000 1 6000

12 III Manpower Company man 30000 1 30000

13 III Manpower Finance manager 5000 1 5000

14 III Manpower Supply manager 9000 1 900015 III Manpower Truck driver and

assistant

4000 6 24000

16 IV Manpower Formation

Evaluation

Engineer

38670 2 77340

17 IV Manpower Well Logging

Engineer

28330 3 84990

18 IV Manpower Drilling Fluid

Engineer

28000 2 56000

19 IV Manpower Geologist 11000 1 11000

20 IV Manpower Driller 9330 2 18660

21 IV Manpower Truck driver and

assistant

4000 2 8000

22 V Manpower Drilling Engineer 10000 2 20000


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23 V Manpower Tool pusher 6000 1 6000

24 V Manpower Company man 30000 1 30000

25 V Manpower Finance manager 5000 1 5000

26 V Manpower Supply manager 9000 1 9000

27 V Manpower Truck driver andassistant

4000 4 16000

28 I Infrastructure Test rig 110000 1 110000

29 III Infrastructure Test rig 110000 1 110000

30 II Materials Substrate 1200 5 6000

31 II Materials Thermally stable

poly crystalline

diamond

20000 10 200000

32 III Materials Test formation 12000 5 6000033 IV Materials Substrate 120 5 600

34 IV Materials Thermally stable

poly crystalline

diamond

200 10 2000

35 V Materials Test formation 12000 1 12000

36 III Transport Truck 82000 2 164000

37 III Transport Tool Truck

Transporter

107000 1 107000

38 IV Maintenance Tool Truck

Transporter

38000 1 38000

39 V Transport and

Maintenance

Tool Truck

Transporter

145000 1 145000

40 III Tools Cantilevered

Masts

34000 2 68000

41 III Tools Conductor

Casing

20000 1 20000

42 III Tools Drill String 500000 2 1000000

43 III Tools Derrick including

hoisting system

320000 2 640000

44 III Tools Drill line 100000 4 400000

45 V Tools Conductor

Casing

20000 1 20000


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46 V Tools Drill String 500000 2 1000000

47 V Tools Derrick including

hoisting system

320000 2 640000

48 V Tools Drill line 100000 4 400000

REJECTION RATIO

The rejection ratio is defined as the ratio of the number of products not fit for application or rejected to

the total number of products manufactured during a specific period of time.

During the manufacturing process, some of the bits were not found to be successfully produced due to

inefficiency of the production machines.

Also some of the bits were found to undergo abrasion due to their exposure to severe operating

conditions. Accumulating the reports, approximately 2 out of 100 bits were estimated to be incapable ofserving the drilling purpose.

Therefore, the rejection ratio,

Rejection Ratio = (No. of products rejected)/(Total no. of products manufactured)

= 2/100

= 0.02

Hence, Total Cost: $6537782

Cash Plan

PHASE 1:

Description: Technological advancements introduced

Total cost: $854000

Time: 1 year

PHASE 2:

Description: Designing and manufacturing of the bit

Total cost: $293000


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Time: 2 months

PHASE 3:

Description: Test run and evaluation of results

Total cost: $ 2663000

Time: 1 month

PHASE 4:

Description: Further modification of the bit according to the results


Time: 4 months

PHASE 5:

Description: Successful run


Time: 1 month

Timeline

First 3months: $683200 (Phase1)

Next 6months: $170800 (Phase1)

Next 2months: $293000 (Phase1 Followed by Phase 2)

Next 2months: $2692659 (Phase 2)

Next 2months: $497231 (Phase2 Followed by Phase 3)

Next 4months: $2072700 (Phase 4 and followed by phase 5)

Total Budget


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Total Cost: $6,409,590

1. Manpower: $1,266,990

2.

Infrastructure: $220,000

3.

Materials: $280,6004. Transport and Maintenance: $454,000

5. Tools: $4,188,000

TECHNICAL BENEFITS -

1) Revolutionary cutting technology extends PDC bit durability

2) Unique rolling cutter design ensures reliability

3) The rolling cutters orientation in thebit blade relative to its contact

with the formation, coupled with the bits drilling force, drives efficient rotation of

the

cutter. And because the entire diamond edge of the cutter is used,

wear is reduced for more sustained rates of penetration and fewer bit

replacement trips.

4) Minimizing loading force to drill more efficiently

5) Innovative diamond element increases drilling speed and improves stability


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6) Maintain high ROP in hard, abrasive formations

7) minimize vibration during drilling providing extra stability .

8) wireless logging introduced with shorter length of drill string needed and

advanced logging in the wellbore .

CONCLUSIONS AND RECOMMENDATIONS :-

Accelerated abrasion testing leads to the following conclusions:The Stinger cutter exhibits reduced vertical and drag forces compared to

conventional shear cutters when tested on the VTL. The Stinger cutter has

significantly improved abrasion resistance during extended wet testing on the

VTL.

The Stinger cutter shows far higher linear footage before burn out in dry/hot

testing compared to conventional PDC.

Laboratory testing at Terra Tek showed the Stinger bit to successfully cut hard

abrasive rocks with no observable wear. All this suggests that Stinger PDCs may

represent a significant step toward the goal of long-life bits for hard formations inhot environments. Obviously additional test-driven, iterative improvements to

Stinger bit design and understanding are needed to attain the longevity and

footage demanded for geothermal applications.

Corporate Profile

Knowledge, technical innovation and teamwork are at the center of who we are.

For more than 80 years, we have focused on leveraging these assets to deliver

solutions that improve customer performance.

Today, our real-time technology services and solutions enable customers to

translate acquired data into useful information, then transform this information


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into knowledge for improved decision making-anytime, anywhere. Harnessing

information technology in this way offers enormous opportunities to enhance

efficiency and productivity. This is a quantum leap from providing traditional 'just-

in-case' information to delivering 'just-in-time' knowledge that meets the

changing needs of our customers.

International teamwork

Reflecting our belief that diversity spurs creativity, collaboration, and

understanding of customers' needs, we employ approximately 120,000 people

representing over 140 nationalities and working in more than 85 countries. Our

employees are committed to working with our customers to create the highest

level of added value. Knowledge communities and special interest groups with

our organization enable teamwork and knowledge sharing unencumbered by

geographic boundaries.

Technology innovation

With 125 research and engineering facilities worldwide, we place strong emphasis

on developing innovative technology that adds value for our customers. In 2012,

we invested $1.2 billion in R&E.

Olivia Oil Corporation is the worlds leading supplier of technology, integrated

project management and information solutions to customers working in the oil

and gas industry worldwide.


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REFERENCE -

Appl, F.C. and Rowley, D.S.: Drilling Stresses on

Drag bit Cutting Edges, presented at the 5th

Rock Mechanics Symposium, School of Mines

and Metallurgy, University of Minnesota, May 3-5 1962.

Brett, J.F., Warren, T.M. and Behr, S.M.: Bit Whirl


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A New Theory of PDC Bit Failure, SPE

19571, SPEDE (Dec. 1990), 275-281.

Clayton, R., Chen, S. and Lefort, G.: New Bit

Design, Cutter Technology Extend PDC

Applications to Hard Rock Drilling, 2004.

SPE/IAD. 91840.

Clegg, J.M.: An Analysis or the Field Performance

of Antiwhirl PDC Bits, 1992. SP. 23868.

Feenstra, R.: Status of Polycrystalline-Diamond-

Compact Bits: Part 1Development, JPT (June

1988), 675-684.

Glowka, D.A.: Use of Single-Cutter Data in the

Analysis of PDC Bit Designs: Part 1-

Development of a PDC Cutting Force Model,

Journal of Petroleum Technology, August 1989.

Langeveld, C.J.: PDC Bit Dynamics, 1992. SPE

23867.


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Mensa-Wilmot, G. and Penrose, B.: Advanced

Cutting Structure Improves PDC Bit

Performance in Hard and Abrasive Drilling

Environments, 2003. SPE 81167.

Mensa-Wilmot, G, and Ramirez, J.: Unique

Polycrystalline Diamond Compact (PDC) Cutter

Improves Drilling Efficiency, 1999. SPE 53954.

Schell, E.J., Phillippi, D. and Fabian, R.T.; New,

Stable PDC Technology Significantly Reduces

Hard Rock Cost Per Foot, 2003. SPE/IADC

79797.

Sinor, L.A., Powers, J.R. and Warren, T.M.: The

Effect of PDC Cutter Density, Back Rake, Size

and Speed on Performance, 1998. SPE/IADC

39306

Warren, T. M., Brett, J.F. and Sinor, L.A.:

Development of a Whirl Resistant Bit, SPE

19572, SPEDE (Dec. 1990), 267-274.


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Warren, T.M. and Sinor, L.A.: PDC Bits: Whats

Needed to Meet Tomorrows Challenge, 1994.

SPE27978.

Weaver, G.E. and Clayton, R.I.: A New PDC

Cutting Structure Improves bit Stabilization and

Extends Application Into Harder Rock Types,

1993. SPE/IADC 2574.

proposal of stinger bits

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