drillbits-slb_04

DRILLING & MEASUREMENTS SUGAR LAND LEARNING CENTER

Drill Bits SELF - LEARNING PACKAGE

USEFUL PRE-REQUISITES Knowledge of the Drilling Process. Knowledge of the Rotary Rig and its Components.

Drill Bit Self- Learning Package

December 2001

DRILLING & MEASUREMENTS SUGAR LAND LEARNING CENTER DRILL BITS SELF-LEARNING PACAKAGE

Welcome to Drill Bit Self-Learning Package. This package is design to give you an introductory understanding of Drill Bits.

Introduction to Self-Learning Self-Learning enables you to learn at your pace, in your time, and in your way. This course book provides the content, structure, and organization of your learning, which would otherwise be managed by an instructor in a class. It also gives you some review questions to help you to confirm your understanding. Below is some information to help you get started. How To Use This Self-Learning Package - Try to do the course in a maximum of 2 sessions, close together: (For example: Work session - - Break - - Work session) - Set yourself up in a suitable learning environment: no noise, no interruptions, and no distractions. - Use the review questions to confirm that you have understood. They are for your benefit. They are not assessed or marked. If you get an answer wrong, just go back through the material. - It is useful, but not essential for you to have met the pre-course requirements stated on the course book cover. Everything you need to complete the Drill Bit Self-Learning Package is contained in these notes. To get started turn to the next page.

Sugar Land Learning Center

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December 2001

Table of Contents OBJECTIVES......................................................................................... 4 INTRODUCTION................................................................................... 5 DRILL BIT INDUSRTRY OVERVIEW................................................ 6 - Drill Bit Competitors…………………………..……………....…..10 - Drill Bit Market Past & Present…………………..…….........……12 - Drill Bit Competitors: Strengths & Weaknesses…….... ………….13 - Hughes Christensen…………..………..…………………....13 - Smith Geodiamond……………………...…………………..14 - Schlumberger Drill Bits………………..……..…………..... 15 - Security DBS…………………………..………….. .........…16 - Drill Bit Industry Summary……………....…..………….........…..17 ROLLER CONE BITS ......................................................................... 19 - Component Parts…………………………………..……………….19 - Exterior Parts…………………………………….…………...……20 - Interior Parts…….…………………………….…………... ………23 - Bearings…………..……………………..…………………..23 - Seals……………………………………….………………...26 - Grease System………………….………………...…...….…29 - Assembled Components……..………………….… .. .……..30 - Cutting Structure.…………………………………………..………31 - Insert Bits………..……………………..………………..… .31 - Tooth Bits……………………………………………….... ..34 - Hydraulic Configurations……….………………..…………...…...36 - Nozzles…….………………..………………………………..……38 - IADC Code…….……………………………………………..……40 - Schlumberger Nomenclature…………………..…………………..43 - Schlumberger Features…………………………..…… . ….………45 - Schlumberger Product Lines…………………….…………………54 FIXED CUTTER BITS......................................................................... 55 - PDC…………………………………..………..…………………. .55 - Natural Diamond & TSP……………………..……..………… ..…56 - Impregnated Diamonds……………………..…………………...…57


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FIXED CUTTER BITS......................................................................... 58 - PDC Components…………………..…………………..………. .. .58 - PDC Nozzles …………………………..……………………...….. 67 - PDC Designs…………………..…………………………..……….68 - PDC Cutters …………………………..…………………….......…69 - Schlumberger PDC Cutter Technology……………..……………..71 - NPI PDC Cutters ……………………..………………….…......…75 - TReX Cutters…………………..…………………..…………...….76 - Schlumberger Fixed Cutter Product Lines……….…………… ..…79 - Schlumberger Fixed Cutter Nomenclature……………………... ...82 - Schlumberger Fixed Cutter Features…………………………... ....83 DRILL BIT LINKS ON THE SCHLUMBERGER HUB ..................... 88 Objectives Upon completion of this Drill Bit Self-Learning Package, you should be able to do the following things: ?? ?? ?? ?? ?? ?? ?? ?? ?? ?? ?? ?? ?? ?? ?? ??

Describe the Drill Bit industry List the 4 major Drill Bit competitors and their strengths & weaknesses Identify the interior components of a roller cone bit Identify the exterior components of a roller cone bit Identify the component parts of a roller cone bit Describe the different roller cone hydraulic configurations Describe the roller cone IADC Code Demonstrate an understanding of Schlumberger’s roller cone nomenclature List and describe Schlumberger’s roller cone features List Schlumberger’s roller cone product lines Identify the major types of fixed cutter bits Identify the major components of PDC bits Describe Schlumberger’s PDC cutter technology List Schlumberger’s fixed cutter product lines Demonstrate an understanding of Schlumberger’s fixed cutter nomenclature List and describe Schlumberger’s fixed cutter features


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December 2001

Introduction Reed-Hycalog (Schlumberger Drill Bits) is the combination of two strong, technologically advanced leaders in the supply of drill bits and expertise to the petroleum drilling industry. The union of the two companies provides a totally integrated, full-service company dedicated to implementing drill bit solutions on a worldwide basis. The history behind the two companies is as diverse as the product lines they collectively distribute. Reed Tool Company was formed in 1915 when Clarence E. Reed formed a partnership with J.H. Giesey to manufacture drilling tools. Throughout the years, Reed has designed, manufactured, and sold thousands of different products to make drilling around the world more efficient. Today, Reed focuses its technical resources on developing premium roller cone drill bits with over 400 different sizes and types of bits in it’s product line. J.R. Frenchie Mayeaux and Dan Grady in Shreveport, Louisiana formed Hycalog (HYdroCArbon-LOGging) in 1946. This company was later combined with the US operations of Drilling and Service and the Rucker companies. Originally operating as a core bit company, Hycalog has now grown into the leading supplier of PDC and natural diamond drill bits worldwide with the number one market position in most drilling areas. The most recent chapter in this history was the acquisition of Reed-Hycalog (via Camco International) by Schlumberger. Reed-Hycalog is now an integral part of Drilling & Measurements, which is part of Schlumberger’s Reservoir Development Group. In 2001, Reed-Hycalog began the transition of changing the company’s name to Schlumberger Drill Bits. Schlumberger Drill Bits has four strategically located ISO 9001 certified manufacturing facilities with the most modern CNC manufacturing equipment in order to meet customers requirements. Roller Cone manufacturing plants are located in Houston, TX and in Singapore. The Fixed Cutter manufacturing plants are located in Houston, TX and in Stonehouse, England. The safety record within these facilities, and in the field, surpasses the industry standard defined by Drill Bits and by Schlumberger. In addition to ISO 9001, Schlumberger Drill Bits meets the API Q1 standard and the Schlumberger QHSE standards.


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Drill Bit Industry Overview Reservoir development starts with the drill bit. With today’s technology, to drill for oil and gas a drill bit is needed. Schlumberger (Reed-Hycalog) sells drill bits. There is a major difference between the Drill Bit segment of Schlumberger and all of the other segments. Drill Bits manufacture and sell tools (bits) that are supported by service. The other Schlumberger segments sells services that are supported by tools. This means that there is a major philosophical difference in the way that Drill Bits sells and conducts business from all of the other Schlumberger segments. Drill bits are often bought one at a time on the rig site. As they come out of the hole, the performance of the bit is evaluated. The other Schlumberger segments basically sell their services before the well starts and then support it with tools. This is the major difference between the Drill Bit segment of Schlumberger and all of the other segments of Schlumberger. There are two major drill bit types: Roller Cone and Fixed Cutter. Within the roller cones there are two types bits - insert bits and tooth bits. Roller Cone Bits:

Insert Bit


Tooth Bit

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Within the fixed cutters there are two types of bits: PDC bits (Polycrystalline Diamond Compact) and Natural Diamond/Impreg.

PDC Bit

Natural Diamond / Impreg Bit

Customer’s Expectations In order to sell drill bits, specific customer’s expectations must be met. There are several things that the customer might expect from a drill bit when they buy it: - they may expect the bit to drill an entire interval - they may expect the bit to drill the interval faster than on previous wells - they may want the bit to drill it at the lowest cost-per-foot - they may want a good dull condition from the drill bit once it comes out of the hole - they may be interested in directional accuracy - they may have some other criteria that they are interested in


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Which one of these customer’s expectations are the most important? From a drill bit aspect, bit cost-per-foot is going to be the best measure of performance. But, the customer is not always interested in cost-per-foot. Sometimes they are interested in making sure they can drill the interval in a specific amount of time irregardless of how much it costs them. Sometimes they have to drill the interval at a certain ROP (Rate Of Penetration) in order to meet the criteria that they have for a specific well. Another situation that customers might need is to have a good dull condition. This is important because sometimes customers rerun bits on multiple wells. Sometimes directional accuracy is the most important for a customer. This is extremely important if you are drilling horizontal or directional wells anywhere in the world. The directional accuracy could be far more important than how much it cost for the bit, or how much it cost to drill a specific interval of the well. If the customer cannot hit their targets, then they are not going to get the reservoir development that they expect. There could be some other things that customers expect out of bits; for example, hours. There are some customers in parts of the United States that if the bit does not drill a certain amount of hours then their expectations have not been met. So which one is most important? The answer is it depends. It depends on what that specific customer's expectations are out of the drill bit. It is the responsibility of the Drill Bit Engineers and Specialist to find out what are the customers' expectations. Once the customer’s expectations are identified, the proper bit to meet the proper application can be selected. Drill Bit Sales Drill bits are sold in a variety of different ways. One of the ways drill bits are sold is at the rig site. In this situation bits are loaded up in the back of a pickup truck and an Engineer or Specialist, in a geographically assigned area, will go out into the field and sell the bits at the drilling rigs. Contact is made with the people that are buying the bits. Then a decision is made on what bits are going to meet that customer's expectations on that specific location.


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Another way drill bits are sold is in the office. They are sold to operating companies, to drilling engineers, and to purchasing departments. Typically it is better not to sell bits to purchasing departments because they are only interested in price. Drill bits are not a commodity. They are a “performance tool”. Drill bits are also sold directly to directional drillers and drilling contractors. There are a lot of wells that are drilled, especially in the US and Canada, on a footage basis. Footage means that a drilling contractor has agreed with an oil company that they will drill a specific depth of a well for a certain price. In this case the contractors are responsible for purchasing the bits. The drill bits will be sold directly to the drilling contractor as opposed to the oil company. There are some situations where directional drillers are responsible for buying the bits. Directional companies will turnkey a directional well, or a section of a well. Being part of Drilling & Measurements, Schlumberger Drill Bits will need to take advantage of this situation when D & M has the directional job and is buying the bits. Drill bits are also sold by tender to national oil companies. Basically what this means is that a national oil company will put out a bid for bits. Sometimes this is for a 6-month supply, a year supply, or some other period of time that they will designate. All of the major drill bit companies get to bid on the tender. The bits are typically bought from whomever provides them with the lowest price. Another way drill bits are sold is by supply contracts to major oil companies. This is typically driven by management consultants and purchasing managers. When this happens the companies are trying to reduce their costs over a period of time by buying bits in bulk from one or more of the major drill bit suppliers. Many of the major oil companies do have some kind of supply contracts with one or more of the drill bit companies.


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Drill Bit Competitors There are 4 major drill bit competitors that control approximately 92% of the $1 billion dollar worldwide drill bit market. First is Hughes Christensen. Hughes Christensen is owned by Baker Hughes International. They are the #1 drill bit company in the world with approximately 30% market share. Hughes is the roller cone portion of the business and Christensen is the fixed cutter portion of the business. Second is Smith Geodiamond. Smith GeoDiamond is owned by Smith International. They are the #2 drill bit company in the world with approximately 27% market share. Smith is the roller cone portion of the business and Geodiamond is the fixed cutter portion of the business. Third is Reed-Hycalog which in 2001 were changing the name to Schlumberger Drill Bits. Reed-Hycalog is owned by Schlumberger and is part of Drilling & Measurements. They are the #3 drill bit company in the world with approximately 20% market share. Reed is the roller cone portion of the business and Hycalog is the fixed cutter portion of the business. Fourth is Security DBS. Security DBS is owned by Halliburton. They are the #4 drill bit company in the world with approximately 15% market share. Security is the roller cone portion of the business and DBS is the fixed cutter portion of the business. There are several other drill bit competitors around the world that collectively have approximately 8% market share. There are RBI, Varel, Walker-Macdonald and TSK which are all roller cone companies. There are also many regional and local PDC companies located around the world. The drill bit market is basically split out into the 2 major bit types - roller cone and fixed cutter. The roller cone is approximately 60% or $600 million, and the fixed cutter is about 40% or $400 million.


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Drill Bit Market – Past and Present To understand the drill bit market, it is necessary to look at the market in the past and then where it is today.

Past Drill Bit Market

Penetration Rate

PDC

Tooth Insert Impreg & N.D.

Formation Compressive Strength On the vertical axis is penetration rate, and on the horizontal axis is formation compressive strength. The chart shows the PDC, the tooth, the insert, and the impreg / natural diamond bits. As indicated, there is very little overlap between the PDC, the tooth bits, the insert bits, and the diamond / impreg. If a customer wanted to drill in a specific area it would be pretty easy to identify what type of bit they were going to need to run for the particular formation. Based on how fast they wanted to drill it, and the compressive strength of the rock, it would dictate which one of the four bit types would actually be used in that particular application.


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Today the bit market has changed quite a bit.

Present Drill Bit Market

Penetration Rate

PDC

Tooth Insert

Impreg & N.D.

Formation Compressive Strength On the vertical axis is penetration rate, and on the horizontal axis is formation compressive strength. With the evolution of PDC cutter technology, the evolution of tooth bits and of insert bits, and the improvements to the impreg and natural diamond bits, there is now quite a bit of overlap in the present bit market. If a customer wanted to drill in a specific formation, a decision would have to be made on which drill bit type would be the best to use. This was one of the major reasons why all 4 of the major roller cone drill bit companies and the major fixed cutter drill bit companies combined as one instead of operating as two separate companies.


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Drill Bit Competitors – Strength & Weaknesses Hughes Christensen The first strength of Hughes Christensen is that they were the first in Bit Optimization Service. Basically they were the first ones to put a drill bit engineer in a customer’s office, at no charge, to do all of the analytical and business requirements for the customer’s drill bit needs. In some cases they were given a bit contract to provide a certain number of bits. Hughes was first in this Bit Optimization service. Smith and Security quickly followed and Schlumberger Drill Bits were the last ones to offer that service. The second strength of Hughes Christensen is volume economics. They build twice as many bits as Schlumberger Drill Bits. Their volume economics allow them to have a lower cost per bit because they can absorb the overhead from their factories over a greater number of products. The third strength of Hughes Christensen is market strategy. They have done an excellent job over the years of marketing their product. Every innovation, every new feature, and every good performance are published in many of the oil & gas publications. The final major strength of Hughes Christensen is name recognition. Hughes was the first roller cone drill bit company. They are very well known throughout the industry. They have good competitive products. Hughes Christensen does have several weaknesses. First, they have an arrogant sales staff. This attitude has cost them some business in the past. Their second major weakness is sometimes they are slow to respond. Since they have such large volumes of product they cannot always get their bits out to the market in as a timely manner as they would like to. Also the actual drill bit market is not predictable. So if activity increases faster than planned, sometimes Hughes Christensen can be a little slow to get their products out to the market place.


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Smith Geodiamond The first strength of Smith Geodiamond is they have autonomy, which allows them to focus. Since they are not owned by one of the major oil service companies, they can spend more of their time focused specifically on the drill bit segment. The second strength of Smith Geodiamond is that they were second in the market with Bit Optimization Service. Soon after Hughes Christensen, they started putting their engineers in the offices to help make bit selections. The third strength of Smith Geodiamond is that they market new technology very well. Any time they come up with what new products or features, they have brochures coming out, they have covers on the major oil publications, and they do an excellent job of marketing their product. The third strength of Smith Geodiamond is the fact they acquired experienced personnel. A few years ago, Smith decided that they wanted to go full force into building fixed cutter bits and becoming a dominant force in the fixed cutter market. They decided to go after the #1 fixed cutter company in the world at that time - Hycalog. They hired Hycalog’s President, their Vice- Presidents, their design engineers, and they selected and hired the specific Hycalog salesmen that they wanted for specific geographical areas. Instead of developing their company and their personnel, they went out and bought them from Hycalog. This is one of the things that contributed to Hycalog falling from the #1 fixed cutter company in the world to #3, and has allowed Smith Geodiamond to become a viable fixed cutter competitor. The final major strength for Smith Geodiamond is customer relations. They spend a lot of money, time, and resources on making sure they take care of their customers. They give away jackets, shirts, cups, hats, etc. They also take their customers on expensive trips. They are the drill bit company that are the most committed to spending money on customer relations. Smith Geodiamond does have several weaknesses. The first weakness is a lack of corporate structure. They are not owned by of one of the major drilling service companies. This limits the amount of corporate support, financial & technical resources, and personnel resources. Sugar Land Learning Center

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Smith Geodiamond The second weakness of Smith Geodiamond is the lack of access to related drilling technologies. Schlumberger Drill Bits has Drilling & Measurements with the PowerDrive and PowerPak systems. Hughes Christensen has Baker Inteq with the AutoTrack system. Security DBS has Sperry Sun with the GeoPilot system. The lack of access to related drilling technologies does put Smith Geodiamond at a disadvantage. The final weakness of Smith Geodiamond is that they have limited packaging opportunities. If you are not owned by one of the major service companies, it is very difficult to package all the services in order to provide the drilling solutions that the customers may need. Schlumberger Drill Bits (Reed-Hycalog) The first strength of Schlumberger Drill Bits is the differentiated technologies. There are many developments that have been patented that differentiates Schlumberger from their competitors. The second strength of Schlumberger Drill Bits is fixed cutter market recognition. A few years ago Hycalog was the #1 fixed cutter company in the world. They are still recognized in several markets as being the #1 fixed cutter company. The third major strength of Schlumberger Drill Bits is the Schlumberger resources. Financial, technical, and personnel resources are now available. Schlumberger Drill Bits also have several weaknesses. First was the company’s focus on margin. While this may not be a bad strategy, if you are going to try to gain market share, margins may not be the primary focus. Currently under D & M, the focus is on market share first. The second weakness of Schlumberger Drill Bits is late to service delivery. It sometimes takes a lot longer to get products to the market place than it did for the competitors.


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To become the #1 drill bit company in the world, it will require better customer response and getting products on time to the market as quickly as possible. The last major weakness of Schlumberger Drill Bits is struggling to reorganize. There have been 3 reorganizations in the last 4 years. First, Schlumberger acquired Camco International. This made Reed and Hycalog part of Schlumberger. Second, was the reorganization of Reed Tool Company and Hycalog to combine to form one company, Reed-Hycalog. Finally, in January 2001, Reed-Hycalog reorganized into Drilling & Measurements. Almost any company would have had difficulty surviving three reorganizations in four years. Security DBS The first strength of Security DBS is their synergy with Sperry Sun. This gives them access to related drilling technologies and packaging opportunities. The second strength of Security DBS is the modernization of their manufacturing plant. Within the last two years they renovated their roller cone manufacturing plant. They put in new machinery and new technology to improve the speed and efficiency of building their roller cone bits. The third strength of Security DBS is that they were right behind Hughes and Smith with Bit Optimization Service. The last strength of Security DBS is their fixed cutter technology. In their fixed cutter bits, they have some excellent products and some excellent cutter technology. Security DBS also has several weaknesses. The first weakness is their roller cone technology. Most of their roller cone bits are not competitive with Hughes, Smith, and Schlumberger. However, they do make a few good products, especially in their bigger bits that have performed well in the Gulf of Mexico and in other offshore applications.


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The final weakness of Security DBS is that they tend to operate as 2 separate companies. Since they have such a strong fixed cutter side and such a weak roller cone side, most of the focus is on fixed cutter bits. Even though they are one company, they tend to operate as two. This prevents them from being a fully unified company. Drill Bit Industry – Summary Drill bits have unique technologies. There are different drilling demands. Almost anywhere in the world that drilling is done the drill bit application will be different. For example, in multiple places in the United States there will be different formations and different drilling applications. Drill bits have unique design concepts. There is a lot of design work that goes into fixed cutter and roller cone bits. There are materials issues, bearings, elastomers, grease, moving parts, and cutter development. Drill bits have manufacturing issues. One of the reasons why there are only 4 major drill bit companies that control approximately 92% of the worldwide market, is because roller cone manufacturing is a very capital-intense and complicated business. Not everybody can easily get into the roller cone manufacturing business. That is one of the reasons for the major oilfield service companies such as Schlumberger, Baker, and Halliburton aligning themselves with an established drill bit company. It would be very difficult for someone to start up a new roller cone company. Finally, patents are what are unique to drill bit technologies. There are many patents that are filed on drill bits that never get into bits. It is a very competitive market with only 4 major competitors in the market place. All of the drill bit companies are actively trying to patent everything they can to prevent the competitors from copying their designs or taking advantage of some of the concepts and innovations that have been developed.


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Drill Bit Industry Review Questions •

List the major Drill Bit types

•

List the 4 major Drill Bit competitors and their market shares

•

List Schlumberger Drill Bits’ strengths & weaknesses

•

Describe the Schlumberger Drill Bit plan for market share growth

•

List 4 Schlumberger Drill Bit Roller Cone differentiations

•

List 4 Schlumberger Drill Bit Fixed Cutter differentiations

•

List 6 things that are new for Schlumberger Drill Bits


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Roller Cone Bits – Component Parts There are two types of roller cone bits. There are tooth bits and there are insert bits. Sometimes roller cone bits are referred to as rock bits. Under tooth bits, these bits are sometimes referred to as steel tooth bits or mill tooth bits. On the insert side, these bits are sometimes referred to as carbide bits or button bits. The roller cone bits are basically made up of the 3 major things. There are: 1) lugs, 2) cutters, and 3) component parts. To make a roller cone bit there will be 3 lugs per bit. All 3 lugs will be exactly the same. There will also be 3 cutters per bit. All 3 cutters will have different cutting structures. Finally there will be a variety of component parts.

Lugs

Cutters

Component Parts

To make 1 roller cone bit, it takes: - 3 lugs - 3 cutters - 3 sets of component parts. The cutters are attached to the lugs. Then the 3 lug and cutter assemblies are welded together to make a drill bit.


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Roller Cone Exterior Parts

Nose Cutter #3 Gage Row Heel Row

Cutter #1 Inner Row Cutter #2

Shirttail

Lug

Bit Bowl Pin

Nozzle, Pod & Socket Bit Body

In this diagram, the first area to identify is the API pin. The purpose of the pin is to connect the bit to the drill string and to allow fluid to get through into the body of the bit and out through the nozzles. Next is the bit body. This is all the exterior part of the bit that is not the cutter. So it includes all 3 of the lugs, the nozzle pods, and the areas that are on the shirttail. The next area is the lug. As mentioned before, it takes 3 lugs to make up 1 bit. So the lug is the area of the bit where the shirttail is located and the bit body that goes down to the pin. It is the part of the bit that holds on the cutter. There are 3 cutters on each bit. There is Cutter #1, Cutter #2, and Cutter #3. Each one of these 3 cutters will have a different cutting structure design. The way to identify the 3 cutters is Cutter # 1 will have the insert or tooth that is the closest to the centerline of the middle of the bit.


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Shirttail

Lug

Bit Bowl Pin


Once the Cutter #1 is identified, count the cutters in a clockwise manner to find Cutter #2 and Cutter #3. The reason these cutter numbers are important is when dull grading the bits, the location of the dulling characteristics will be identified by the cutter numbers. When identifying whether the bearings/seals are effective or have failed, the cutter numbers are used if all 3 of the cutters do not have the same grading. The nose of the bit is the area of inserts or teeth that is the closest to the center of the middle of the bit. The inner row would be all of the rows that are not the gauge. The gauge row is the row of inserts that are the furthest on the outside of the cutting structure. The heel row are small, tungsten carbide or diamond inserts that are put on the back face of the cutter. The shirttail is the area of the lug where the grease reservoir cap, the hard metal that is applied to protect the shirttail, the cone retention loading hole, and the grease-loading hole is located. This is an important part of the bit because it will identify some of the areas that will need to be protected. Shirttail protection features that are added to the bits will be discussed later.


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Shirttail

Lug

Bit Bowl Pin


Then there is the nozzle pod and socket. This is the where the nozzles is located. There is an O-ring and a snap ring that holds the nozzles in. This whole assembly area where the nozzle goes in is called the nozzle pod and nozzle socket. Finally there is the bit bowl. This is all of the blank space, the void space that is inside, the interior of the bit beneath the cutters, and inside of the nozzle pod and nozzle sockets. In the bit bowl is where there may be drilled cuttings. A lot of flow has to get through there in order to keep the bit clean. This is also where your center jet would be installed if a center jet were to be added to any bit. Now that the external parts of the roller cone drill bit have been reviewed, it is time to take a look at what is on the inside. The focus will be on the bearings and seals. These are one of the most critical parts of a roller cone drill bit. If the bearings and seals fail prematurely, your bit life will be limited.


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Roller Cone Interior Parts Bearings In roller cone bits, there are generally 4 major bearings.

• Main Bearing • Retention Bearing • Thrust Bearing • Pin Bearing

There is the main bearing, the retention bearing, the thrust bearing, and the pin bearing. The main bearing, the thrust bearing, and the pin bearing are all load-bearing surfaces. The function of the retention bearing is to attach the cutter to the lug. However, through testing, and looking at the bits that have been cut down for dull analysis, the retention bearings also do take some load.


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There are 2 major types of main bearings in a roller cone bit. There are roller bearings and there are friction/journal bearings.

Roller

Friction / Journal

Roller bearings are long cylinders that roll in tracks or grooves that have been cut in the lug. Typically roller bearing bits will have two rows of roller bearings, or three rows for the larger bits. They roll freely between the cutter and the journal. The friction or journal bearing bits have a bushing that rotates between the lug and cutter. Schlumberger Drill Bits have a floating bushing that rotates freely between the cutter and the lug. In the past these bearings were called friction bearing. Today, most people in the drill bit industry call them journal bearings.


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There are two types of retention bearings. There are ball bearings and there are threaded rings.

Balls

Threaded Ring

On most all drill bits, the cones or cutters are held onto the lug using ball bearings. This is not a unique feature to Schlumberger. Ball bearings are used by all 4 major drill bit competitors as their cone retention bearings. Ball bearings roll in the track and keep the cutter from falling off of the lug. The threaded ring, however, is a unique and patented feature that can only be used by Schlumberger Drill Bits. It is attached by the threads in the cutter shell and the corresponding threads located on the threaded ring. The threaded ring rides in a groove on the lug, and allows the cutter to be attached to the lug. A retention tool holds the threaded ring in place while the cutter is screwed on. Once the cutter is on, the retention tool is taken out, and a peening tool is inserted. The peening tool will peen or deface the threads on the cutter to prevent the cutter from backing off. The advantages of having a threaded ring retention bearing over a ball bearing is: - the threaded ring will help reduce the lost cone rate by two-thirds - it becomes an integral part of the cutter, so it allows the cutter to have more freedom and be better tolerant of cutter movement - it has surface contact as opposed to point loading of the balls bearings Sugar Land Learning Center

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December 2001

With ball bearings there is point loading that can cause spalling, Spalling is little particles of metal that have flaked off of the lug surface. This makes the surface uneven and no longer will run smoothly. This affects the bearing performance. As soon as the bearing performance is negatively affected, then the bit life will be limited. Seals At Schlumberger there are 4 major types of seals that are used. The first is an O-ring seal. Years ago the O-ring seal was patented by Hughes and was not allowed to be used by any of the other major bit companies. What Hughes actually patented was the amount of squeeze on the O-ring to seal the bit to keep the drilling fluids out and keep the bearing grease in. HNBR Ribbed Texturized HNBR Texturized

O-Ring and HNBR Radial

Reed-Hycalog decided to use a HNBR radial seal to counteract the patent Hughes had on the O-ring. The HNBR radial seal is a patented feature that only Schlumberger uses. Smith and Security decided that they would go ahead and use the O-ring even though Hughes had a patent. Then several years later there were lawsuits. Hughes was paid hundreds of millions of dollars by Smith and Security for violation of their patent. The O-ring patent has expired and is now used by Schlumberger Drill Bits.


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The O-ring seal is used in Schlumberger’s 4-3/4" and smaller inch diameter bits. All of the bits larger than 4 3/4, use the HNBR radial seal. The radial seal provides several advantages. It runs cooler, it is recessed and is better protected, and it is more tolerant of cutter movement. A radial seal is flat and has more surface contact. The next seal used by Schlumberger is a HNBR texturized seal. HNBR stands for Hydrogenated Nitrile Butadiene Rubber. It is obvious why this seal is just called HNBR. The HNBR texturized seal was the seal that was developed for Schlumberger’s motor bit product line. This seal has a series of Xs cut into the inside surface of the seal. The purpose of these Xs is to trap grease in all of the little small pockets, as shown in this picture.

HNBR Texturized Seal

By trapping the grease into these little pockets, it allows the seal to run cooler. Typically motor bits are running at higher RPM (Revolutions Per Minute) so running cooler is important to extending bit life. The HNBR ribbed textured seal is a brand new seal that was recently developed to be put into Schlumberger’s new “Titan” bits. It is an upgrade from the HNBR texturized seal in that it has a rib in the middle that helps keep the grease on both sides of the seal. As shown in this picture, once the grease gets into the little pockets, it gets trapped and allows the seal to run cooler. A cool running seal is critical when running at high rotary speeds on motor bits.


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December 2001

Pilot Pin (Friction Pin)

Main Bearing

Insert Cutter Cutter Bore

Shirttail

Snag Seal Land Ball Retaining Plug

Ball Race (Bearing Race)

Ball Bearing Radial Seal

Seal Groove

Floating Bushing Thrust Washer

From this diagram, the bearing terms can be identified. Starting on the righthand side of the picture an insert bit cutter is shown. The ball race is where the ball bearings roll and allow the cutter to move around the lug. Moving from the right side of the diagram into the middle of the cutter is the cutter bore. The cutter bore has the internal bearing surfaces that match up with the corresponding parts on the lug. There is also a groove in which the seal is recessed. Moving on into the center part of the diagram is the thrust washer. The thrust washer is a washer that is silver-plated. The silver is used as a dry lubricant so as the thrust washer heats up, takes loads, becomes hot, and develops friction; the silver will melt and form a lubricant. Next there is the floating bushing. This is a copper beryllium bushing that is also silver-plated for dry lubricant. Next is the HNBR radial seal. This could be a texturized radial seal, a ribbed texturized radial seal, or an O-ring. This shows the order in which component parts and the cutter fit on the lug. Moving over to the journal part of the lug is the thrust pin bearing and the pilot/friction pin bearing. Next there is the main bearing surface, the ball bearing groove, the seal land, and the back face of the cutter. The ball retention plug is used to secure the cutter once it is connected to the lug. The ball bearings are loaded through this ball-loading hole on the backside of the journal. After the proper number of balls are loaded, the retaining plug is inserted and is welded with what is called a frogeye weld.


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December 2001

Grease System On sealed bearing roller cone bits there is a grease system. This diagram shows Schlumberger Drill Bits’ greasing system. The grease reservoir is where the extra grease for the bearings is located. The grease is pumped from the grease reservoir through a grease passage holes into all of the bearing surfaces. To ensure that grease gets to all the bearing surfaces, grease is painted on every bearing surface before the bit is assembled. A grease-compensating diaphragm is used. If too much pressure builds up in the reservoir or bearing system, the grease can vent or release through the diaphragm so it does not burst the seal. Once the seal is damaged or fails, the drilling fluid will flow in, compromise the bearing system, and will limit the bearing life. On top of the diaphragm is a reservoir cap that is held in place with a snap ring. A hex nut is screwed in with an Allen wrench that closes off the grease-loading hole.

Grease Reservoir Diaphragm Reservoir Cap

Snap Ring

Grease Passage Holes

Grease Loading Hole Plug Threaded Ring Access Hole Plug


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December 2001

Assembled Interior Components Earlier the ball-loading hole for a ball bearing retention system was discussed. If the bit has a threaded ring, the threaded ring access hole is where the tool to hold the threaded ring still is located. It also serves as the access hole for the peening tool used to deface the threads on the cutter side of the threaded ring assembly. A threaded ring access hole plug is then inserted and sealed off with a frogeye weld. Radial Seal

Main Bearing

Retention Bearing

Hole Wall Lug

Heel Row

Pin Bearing

Cutter Thrust Bearing

Gauge Row

Inner Row

This diagram shows a view of the cutter assembled to the journal on the lug. Starting on the left side is the borehole wall. Moving inward from the left side of the picture are the heel row inserts that are in contact with the borehole wall. Next are gauge row inserts. This diagram shows how much of the insert is actually in the cutter and how much of the insert is protruding out from the cutter shell. On the top of the picture is the radial seal and the groove where the radial seal is recessed. Next is the main bearing - in this case a journal bearing. On the bottom of the picture are the inner row inserts. Finally there is the thrust bearing, thrust washer, and the pin bearing.


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December 2001

Cutting Structure – Insert Bits The cutting structure is also important for the life of a drill bit. If the cutting structure fails the bit is finished. If the cutting structure wears out, the inserts break, or the cutting structure gets damaged, the bit will have to be pulled out of the hole because it will no longer be able drill the formations economically. Sometimes the cutting structure of a bit is called the “cone” or the “cutter”. These two terms can be used interchangeably. Gage Row

Interlock Row

Heel Row Insert Pad

Seal Flange

“Cone” or “Cutter”

“Teeth”

Spear Point (Spade)

Cone Shell Back Face

Cone Profile Heel Face (Gage Face)l Outer Rows

Cone Groove Inner Rows

Starting on the right side of this diagram is the cone profile. The cone profile identifies how aggressive the bit is going to be in terms of cutting formation. A more rounded cone profile would be for a more aggressive bit. A flatter cone profile will be used for a slower drilling, more durable cutting structure type bit, typically used in harder formations. Beginning on the right side of the picture and moving inward, the first insert is the spear point or the spade. This is also the nose insert. When identifying the nose insert on the cutter, this is the insert that is closest to the center of the middle of the bit.


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Gage Row

December 2001

Interlock Row

Heel Row Insert Pad

“Cone” or “Cutter”

“Teeth”

Seal Flange Spear Point (Spade)

Cone Shell Back Face

Cone Profile Heel Face (Gage Face)l Outer Rows

Cone Groove Inner Rows

Next are the insert pads. The insert pads are created as a result of the designed cone grooves. Since the bit has 3 cutters, each with a different cutting structure, the cutting elements have to intermesh with each other. The cone grooves are machined into the cutter to allow the inserts to intermesh. Another reason for the insert pad is to support the insert. If the insert is not protected, and the proper amount of the insert is not in the cutter shell, the insert will not be properly supported and will break. Next are the inner row inserts. These are all the inserts that are not the gauge row inserts and not the nose row inserts. The remaining row of inserts are called the interlock row. An interlock row means that part of the interlock insert is intersecting the line of the gauge row inserts. This does not mean that these inserts are on top of each other. It just means that they intersect the line of the gauge row inserts. Finally there is the heel row. The heel row inserts are on the back face of the cutter.


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December 2001

This picture gives a few examples of insert shapes by formation. Schlumberger has over 100 different insert shapes and types that are used on their roller cone drill bits. As illustrated, the inserts get shorter and more rounded when going from soft formations to harder formations. The first insert on the chart has a sharp tip and a lot of protrusion. The straight lines that go across the picture indicate the protrusion. Everything below that line represents the part of the insert that is buried in the cutter shell. Everything above that line represents the part of the insert that is protruding from the cutter shell and makes contact with the formation. The first insert has quite a long protrusion and the insert shape is quite sharp. Looking at the very last insert in this picture, that insert is much shorter and has a much rounder shape. Selecting the right insert for the right bit is most important to provide you the best bit performance in any given application.


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December 2001

Cutting Structure – Tooth Bits Mill tooth bits have their tooth shape milled out of steel. Once the teeth are milled, a hard metal is welded to each tooth to make the tooth more durable. There are 4 basic types of hard metal that are used on Schlumberger’s mill tooth bits.

Duraclad Hardmetal

Armorclad Hardmetal

First there is the standard Duraclad hard metal. This is a tungsten carbide matrix composite. The hard metal is welded onto the teeth in a manual process. Duraclad has a lot of porosity. It is a durable product but is typically use this in Schlumberger’s non-premium tooth bits. The next type of hard metal is called Armorclad. This is much more dense and much less porous type of material. It has a much higher concentrated mix of tungsten carbide pellets. Armorclad is typically use this in the premium mill tooth bits such as EHT, MHT, and the SL - Slim Line bits. Armorclad II is a new hardmetal that has just been introduced. This is a premium hard metal that is an upgrade from Armorclad. This hardmetal will be used on the new Titan tooth bit products.


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December 2001

Finally there is the “built-in” hard metal – PMC (Powdered Metal Cutter). Schlumberger has as patented process of using powdered metal to make a tooth cutter. Because of the patent protection, Schlumberger is the only drill bit company that can use this “built-in” hard metal. The PMC product technology has been in development for more than 12 years. In 2001 the first PMC products will be going standard. The first product lines will be FMJ (Full Metal Jacket) and CMC (Composite Matrix Cutter).

PMC “Built-In” Hardmetal PMC is a “built-in” hardmetal that is built using a mold. This hard metal is more durable, more abrasive-resistant, and provides a lot longer life for the tooth. PMC will also allow more flexibility in designing tooth shapes. For Schlumberger Drill Bits, the PMC process for making tooth bits may become the way tooth bits are made in the future. It will be more economical to manufacture once the process is fully developed. All of Schlumberger’s competitors use welded hard metal on their tooth bits.


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December 2001

Hydraulic Configurations Hydraulics are very important for a drill bit. The primary purposes of hydraulics for the drill bit are to keep the bit cool and to get the cuttings off the bottom of the hole and up the annulus. There are 3 basic Schlumberger hydraulics configurations: Conventional, Mudpick, and Mudpick II.

Conventional

Mudpick

Mudpick II

First is conventional hydraulics. This means that the drilling fluid comes out of the nozzle and goes straight to the bottom of the hole. There is no tooth cleaning and the fluid cleans the rock between the cutting zones. There is stagnant flow at the cutting zone where the inserts or teeth are in contact with the bottom of the hole. There is no cleaning where the cutters are actually in contact with the formation. All of the competitors use some form of conventional hydraulics. In the late 1970s, early 1980s, Reed started developing improved hydraulics. The objective was to find a way, given the same set of hydraulic conditions, that ROP could be improve by changing the direction of the hydraulic flow. In the early 1980s, Reed introduced the patented Mudpick hydraulics.


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Conventional

December 2001

Mudpick

Mudpick II

With Mudpick hydraulics, as you can see in this picture, the position of the nozzle is re-directed so that now the flow is cleaning the gauge row and interlock row inserts. The rock is being cleaned at the leading edge of the cutting zone. The stagnant flow has been shifted to the trailing side of the cutter. Now there is better cleaning on the bottom of the hole. With Mudpick there was an increase in rate of penetration given the same set of hydraulic conditions. Without changing nozzle diameter, the flow rates, and any of the variables for hydraulics, ROP was improved by changing to Mudpick hydraulics. We use Mudpick hydraulics on all of the Schlumberger product lines, except those that use the Mudpick II hydraulics. In the early 1990s, almost ten years after the development of Mudpick, Mudpick II hydraulics was introduced. Mudpick II cleans the gauge row and inner row of teeth. It cleans the rock at the cutting zone right at the corner as the inserts are coming around to make contact with the formation. It cleans the cuttings from the bottom of the hole and removes the stagnant flow completely from the cutting zone. The stagnant flow is shifted outside the area where the inserts are in contact with the formation. Mudpick II has shown that ROP was increases an average of 20% - 22% over the offset bit runs. Mudpick and Mudpick II hydraulics are patented features of Schlumberger. None of the other drill bit companies can use these hydraulic configurations.


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December 2001

Competition has developed various types of hydraulic configurations to combat Mudpick and Mudpick II hydraulics. Because of the improvements in ROP, the competitors will continue to try to meet or exceed Schlumberger’s performance. Schlumberger builds bits with both Mudpick and Mudpick II hydraulics. The reason for this is because there are both advantages and disadvantages to Mudpick II. Mudpick II will increase ROP, but it is limited to only the soft and soft-to-medium formations. The harder the formations become, the less effective the Mudpick II hydraulics. Also, because of the angle of the nozzle and the flow, there have been some cases of abnormal erosion in the gauge and interlock row insert where the fluid is hitting the cutting structure at high rates of speed. There has also been some backwash on the shirttail as a result of the Mudpick II configuration. Whether Mudpick or Mudpick II is the right hydraulic configuration for a specific bit will be determined by the application, the hydraulic conditions, and satisfying the customer's needs. Schlumberger’s Roller Cone Nozzles Schlumberger has a variety of different types of roller cone nozzles. The chart bellows shows the 2 basic types of Schlumberger nozzles: shrouded nozzle and standard nozzle. NOZZLES AVAILABILTY

BIT SIZE RANGE

SHROUDED TYPE

3-3/4” 5-7/8” 7-7/8” 9-1/2” 20”

SHROUDED TYPE

– – – – –

5-1/2” 6-3/4” 9” 18-1/2” 26”

STANDARD T YPE

SHROUDED TYPE

AAK AK CK DK EK

AACK ACK CCK DCK ECK

STANDARD TYPE

NOZZLES A VAILABILITY SIZE (32 ND) TFA in²

8 0.049

9 10 11 12 13 14 15 16 18 20 22 24 28 0.062 0.077 0.093 0.110 0.130 0.150 0.173 0.196 0.249 0.307 0.371 0.442 0.601

AAK AK CK DK EK

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AACK ACK CCK DCK ECK

?

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STANDARD TYPE

? ?

SHROUDED TYPE

STANDARD TYPE


NOZZLE TYPE NOZZLE OUTSIDE DIAMETER

IN

TFA WITHOUT NOZZLE

IN ²

AAK AACK

AK ACK

CK CCK

DK DCK

EK ECK

0.811 0.517

0.926 0.673

1.173 1.081

1.297 1.321

1.609 2.033

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December 2001

The standard type nozzle has got a flat surface on the top and the snap ring, which is what holds the nozzle in the bit. On the shrouded type nozzle, the snap ring is covered by a recessed groove. The purpose for shrouded nozzles is for use with highly abrasive fluids or if there are highly abrasive formations. The shroud protects the snap ring. All nozzles are measured in 32nds of an inch in terms of the diameter. In the picture on the previous page there is a 14 stenciled on top of the nozzle above the center hole. This means that this nozzle is a 14/32nd nozzle. Hughes Christensen also used the same types of roller cone nozzles as Schlumberger. In fact the nozzles are interchangeable. Smith Geodiamond uses a screw type nozzle. Security DBS uses a nozzle that is held in by a nail. The Smith and Security roller cone nozzles are not interchangeable with Schlumberger.

Roller Cone Components Review Questions • Identify the exterior components of a roller cone bit JOURNAL & ROLLER

• Identify all of the interior components of a roller cone bit • List the 2 Schlumberger Drill Bit main bearing types • List the 2 Schlumberger Drill Bit cone retention bearings

BALLS THREATED

• List the 3 Schlumberger Drill Bit seals • List the 3 Schlumberger Drill Bit hydraulic configurations CONVENTIONAL MUDPICK MUDPICK II


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December 2001

Roller Cone IADC Code

IADC Cutting Structure Code Formation

Series / Type

Cutting Element

Soft to Hard

11to 34-

Mill Tooth

Soft to Hard

41to 84-

Tungsten Carbide Insert

The IADC code, which stands for International Association of Drilling Contractors, was developed for roller cone bits in 1992. There is an IADC / SPE Paper 23937, that details this IADC roller cone bit classification system. In the IADC roller cone classification system the numbers are divided up into formation, series / types, and cutting elements. Within soft or hard formations, there will be a series and type. If the first two numbers of the IADC code are 11 through 34 the cutting element will be mill tooth. If the first two numbers of the IADC code are 41 to 84 the cutting element will be a tungsten carbide insert bit. The second digit of the IADC code tells the hardness of the bit within the series. So a 11 would be the softest of the mill tooth bits. A 12 would be the next hardest, and 13 would be the hardest. On inserts, for example, there may be a 41, 42, 43, 44, 45, etc. So within the series, the harder the bit, the higher the second number will be.


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December 2001

The IADC roller cone classification code basically looks like this:

IADC Roller Cone Cone Classification Code

4 1 7 Series Type

Bearing Special Gage Features

1 1 5 M If you look at this diagram, there are two examples. There is a 417 and a 115M. The first number represents the series. The 4 means it is an insert bit. The 1 means it is a mill tooth bit. The second number represents the type within that series. The third number in the IADC code represents the bearing and gauge package. Most of the time there will be three numbers in the IADC code. Occasionally, in the fourth position, there will be a letter. This letter represents special features. It is not used very often but sometimes the drill bit manufacturer wants to indicate that this bit has some kind of special feature. There are 7 different types of bearing and gauge configurations in the IADC code. They are: 1. Standard roller 2. Roller air cooled 3. Roller with gauge protection 4. Sealed roller 5. Sealed roller and gauge protection 6. Friction/Journal bearing 7. Friction/Journal bearing and gauge protection The codes that are used the most often are IADC code numbers 1, 5, 6, and 7. Sugar Land Learning Center

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December 2001

There are several letters used in IADC to represent these special features. They are not used very often. Most of the time the bit manufacturer will choose to identify the special feature in their nomenclature as opposed to the IADC code. Below is a list of these special features: A = air application B = special bearing /seal C = center jet D = deviation control E = extended jets G = gauge or body protection H = horizontal or steering application J = jet deflection L = lug pads M = motor application S = standard steel tooth model T = a two-cone bit W = enhanced cutting structure X = predominantly chisel tooth inserts Y = conical tooth insert Z = other shaped insert The M letter is used most often to designate a bit is designed for motor application. The IADC code for roller cone bits has several uses. It is a good starting place when trying to compare roller cone bits on offset bit records. In order to determine what bit is going to be run in a specific application, bit performance has to be evaluated. By looking at offset bit records, the IADC code of the offset bits can be identified. Why would the IADC code be only a starting place? If a customer says, “I need a 12-1/4” IADC code 517,” sure, which one do they want? Within the industry there are probably 60+ 12 ¼” 517 type bits. The IADC code gives a general indication of what kind of cutting structure is needed. The features, or combination of features, will then be selected for the specific application.


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December 2001

Schlumberger Drill Bits – Roller Cone Nomenclature Below is an example of two of Schlumberger’s roller cone bits: a 12-1/4” EHP51HDLK and a 17-1/2 EMS13GC.

12 ¼” Size

EHP Product Line

17 ½” EMS

51 H DLK IADC Design Added Cutting Variant Features Structure

13

GC

The first set of numbers, the 12-1/4 and the 17-1/2, represent the size in inches. The size is also indicated in metric on Schlumberger’s box labels for those that work in the metric system. The next set of prefixes in Schlumberger’s nomenclature represent the product line. In this case, EHP, Enhanced High Performance, and EMS, Enhanced Motor Series, are the product lines for these particular bits. The Schlumberger product lines will be discussed later. The next two numbers are the first two numbers of the bit’s IADC code. Schlumberger Drill Bits is the only company that uses the first two numbers of the IADC code, to identify their cutting structure. All the rest of the competitors use different sets of nomenclature and different sets of numbers to identify their bit types. In the top example, the 12-1/4" EHP51, the 51 indicates that the first two numbers of the IADC code for this bit is a 517. In the bottom example, the 17-1/2" EMS13, the IADC code for this bit is 135. So the first two numbers of the IADC code is represented in our nomenclature as 13. In 2001, Schlumberger launched three product lines which do not use the first 2 numbers of the IADC code in it’s nomenclature. The numbers used in the FMJ, DJ, and DR product lines are not associated with the IADC code.


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December 2001

The next letter, if there is one, would represent the design variant. There are three different design variants frequently used by Schlumberger. They are designated by A, H, and X. Below are the design variants: A = Chisel-Shaped Inserts. The application for this would be an aggressive insert shape typically for soft to medium formations. The downside to using the A variant is that an insert shape that is sharp chisel may not be durable enough. If the insert is not durable enough, the bit life could be limited. H = Chisel-Shaped Inserts in IADC code 41 to 51 with 3° cutter skew. Typically insert bits in 41 to 51 range have 5° cutter skew. The application for the H designate is that it is a durable skew angle for any application where you need more durability. A 5° skew is for a more aggressive bit but it is less durable. A 3° skew is a little less aggressive but it is more durable. Durability could be needed in situations like running high RPM (Revolutions Per Minute), a directional situation, motor bit runs, or any time there are streaky formations. The downside is that the more durable the bit, the slower the ROP. So a little bit of ROP is sacrificed in order to get durability. Schlumberger also builds bits that have faster ROP. So it depends on the customer's expectations, the application, and the objective for that bit run. X = is a special cutting structure that might vary from type to type. When an X is in the suffix of Schlumberger’s nomenclature, the special cutting structure will be different from a normal bit. The applications for this type bit are formations such as medium-hard carbonates that suit an aggressive gauge design but does not lead to gauge breakage. The downside is that if you put a little longer gauge row inserts in for aggressive gauge design, there could be a tendency for the inserts to break. Schlumberger Drill Bits has several options for added features. With the example of the 12-1/4", DLK stands for diamond lug pad and K shirttail protection, and in the case of the 17-1/2" EMS13, G stands for gage protection on the bit and C stands for center jet.


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December 2001

Schlumberger Drill Bits – Roller Cone Features Below are the Schlumberger Drill Bits roller cone features: C F G JA K KP KPR L M T

-

Center Jet Flame Spray cutter shell coating Heel Row Inserts on tooth bits Jet Air Drilling Shirttail Inserts Shirttail Inserts - Premium Coverage Shirttail Inserts Raised - Premium Coverage Lug Stabilizing Pad Mudpick II Hydraulics on HP Bits GageGuard - shorter inserts in between the gauge row Inserts

C = Center Jets. There are 2 types of center jets. There is a single-port center jet that is installed in the center of the bit to provide hydraulic fluid to the inner row and nose area. There is also a three-port center jet. The threeport center jet is fixed and is installed in the factory. For the single-port center jet, it is interchangeable and can be installed or changed in the field.

Single Port

Three Port

There are several benefits to running center jets. They reduce bit balling and help keep the nose and inner rows of the cutting structure clean. The major disadvantage of center jets is that they can reduce the outer cutter cleaning. If a bit has three nozzles, and then a center jet is added, there will be less fluid exiting out of the 3 outside nozzles.


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December 2001

Another disadvantage is the center jet can aggravate the nose area. With high flow rates through your center jet, there can be nose cone erosion in the center of the bit. The applications for center jets are basically in bits 12-1/4" and larger. It is available in 7-7/8" and larger, and on occasion, a center jet has been installed in a bit smaller than 7-7/8". Typically center jets are used in medium to very soft, very sticky, gumbo type formations, or where cleaning around the center of the bit is most important. Generally, no more than 18% of the TFA (Total Flow Area) should be going through the center jet. If the center jet is more than 18% TFA, the outside nozzles could be starved for fluid and will not keep the gauge row of inserts cleaned. D = Diamond PDC-coated inserts. PDC stands for Polycrystalline Diamond Compact. The purpose of using PDC-coated inserts is to eliminate thermal fatigue and to eliminate abrasive wear. Almost any of the cutting structure or shirttail inserts can be replaced with the diamond PDC-coated inserts. In the Schlumberger nomenclature, it is very simple to identify what features have diamond PDC-coated inserts and which ones do not. When looking at the suffixes of Schlumberger nomenclature, everything to the right side of the D represents diamond PDC-coated inserts. Everything to the left side of the D represents non-diamond PDC-coated inserts. The competition uses the D repetitive when they indicate their diamond coated inserts.

The benefits of PDC-coated inserts, the D feature, are that it does eliminate abrasive wear and thermal fatigue. There are some downsides, however. It is costly. Some of the PDC-coated inserts could cost $25, $50, or $100 per insert. The application must be right for using these inserts because it does increase the cost of the bit. Another downside is it will not solve fracture due to overload. If the inserts are breaking due to overload, using diamond PDC-coated will not solve the problem. It will only help if the bit is experiencing abrasive wear and thermal fatigue. Sugar Land Learning Center

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December 2001

The applications for the D feature would be any application where abrasive cutting structure wear or thermal fatigue limits bit life. It can also be used in directional applications where there would be excessive wear on the gauge row inserts. The diamond PDC-coated insert would be a good solution to that gauge wear problem. F = Flame Spray. This is a tungsten carbide coating that is applied to the finished cutter in a high-velocity oxygen-fuel environment. After the inserts are pressed into the cutter, the cutters are sent to an outside vendor for the Flame Spray to be applied. For Flame Spray, the steel cutter shell surface is bombarded with tungsten carbide pellets at high velocity and they are embedded into the cutter shell.

Flame Spray Cutter

The benefits of Flame Spray are that it reduces cutter shell erosion and eliminates cone wear. The downside is that the coating may flake due to differences in modulus of elasticity between the tungsten carbide pellets and the steel. The best applications for flame spray is directional, or any application where there is off-center rotation, gyration, or cutter wear limits bit life due to erosion. Sometimes this happens with poor solids control or high solids in the mud. Flame spraying has to be done in the before the bit is assembled. It is not something that can be done in the field. It has to be requested while the bits are being built. If there is a very abrasive formation, the abrasive formation will erode the steel. The problem with cutter shell erosion is that when the cutter shell is eroded, there is no longer support for the inserts. Once the inserts fall out, the bit will not drill at an adequate ROP. The bit will have to pull out of the hole and be replaced.


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December 2001

G = heel row inserts on a tooth bit. Not all of tooth bits come with heel row inserts. Typically it is included on the directional tooth bits and on the motor tooth bits. The G feature is standard on all insert bits, so it is not included as a part of the insert bit nomenclature.

“G” Feature The benefit of the G feature is that it helps maintain gauge. It is in contact with the borehole wall and it does help protect the gauge teeth on a mill tooth bit. It does have side cutting ability and it is diamond-compatible. The downside is that in some designs, it can reduce the total carbide on gauge. If the gauge row carbide were compromised in order to accommodate the hole for the G feature, it probably would not be added. The applications would be any application where gauge rounding results in an under gauged hole or premature bearing failure. This feature will be used in bits that are for directional applications, or any tooth bits that are run in a motor application. The next feature is TuffGage. There is no nomenclature for this feature at the present time. It is a different configuration of the heel pack inserts. Typically there is one row of large heel pack inserts going around the back face of the cutter. The TuffGage feature basically is two rows of inserts. Sometimes they line up one on top of each other. Sometimes they are staggered between each other. Sometimes they have skip spacing between the two rows of inserts. Generally these inserts are smaller.


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December 2001

TuffGage in this heel pack configuration, give somewhere in the range of 20% to 40% more carbide on the back face of the cutter. That increase improves durability. It helps protect the gauge row inserts and helps increase the bit life. The next features are shirttail and lug protection. There are 3 configurations of shirttail and lug protection used by Schlumberger Drill Bits: - K, KP, DK, and DKP - KPR and DKPR - L and DL

“K”, “KP”, “DK”, & “DKP”


“L” & “DL”

“KPR” & “DKPR”

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December 2001

K, KP, DK, and DKP are holes that are drilled into the shirttail where flattop tungsten carbide inserts are pressed into the drilled holes. There are standard patterns that are use for the K and KP shirttail protection. However, there is the flexibility to install any kind of design pattern as long as the pattern does not violate the specs in terms of the relationship of the inserts to each other, to the grease-loading hole, to the grease reservoir cap, and to the hard metal. This is an add-on feature. It can be done after the bit is built, either in the factory or at a machine shop that has been certified at a field location. The second type of protection is L, or DL, which stands for lug stabilizer pad. This is a piece of steel that is welded onto the shirttail and then machined. Once the piece of steel is machined to the proper diameter, holes are drilled and tungsten carbide inserts or diamond-coated inserts are pressed into the lug pad. The benefits of the lug pad are they stabilize the bit, they help to maintain gauge by reducing side loads, and they also reduce bit body wear. The downside is that sometimes the lug pads extend the gauge length of the bit. This can be a possible problem in a directional well with the overall length and steerability of the bit. So if the lug pads extend the gauge length and affect directional steerability, they will not be installed on the bit. The third type of shirttail protection is KPR and DKPR. This is shirttail protection that is premium. The R stands for raised inserts that are rounded and protruding from the shirttail. This feature was introduced in 2000 and has become a very effective shirttail feature. This feature can also be installed in both the factory and in the field. There is a new KPR insert that is just being introduced. It is called Mega KPR. This is an insert that is going to be used on the “Titan” product line. The difference between Mega KPR and the standard KPR, is that the standard KPR insert is 5/8" diameter and the Mega KPR inserts are 3/4" diameter. The applications for this is directional or any application where: 1) off-center wear or bit rotation is encountered, 2) bit stability could be a problem or be a limiting factor, or 3) in any application where a little more insurance is wanted. They can also be used in situations where a customer just wants to make sure that they do not have any shirttail damage or they just want a little extra protection.


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These shirttail features do not cost very much and is a very effective tool to help ensure that you have a longer bit life. In a directional or off-center wear application, these features are very important because they do help protect the shirttail and protect the gauge row. In a directional situation, the bit is laying on the low side of the hole the majority of the time. The shirttail and gauge row inserts are taking an abnormal amount of wear. Also, in a directional application, there are more opportunities for downhole vibrations, off-center wear, and gyrations. This shirttail protection, gives the bit added bit life when running in a directional application. T = GageGuard. This is the insert that is located in between the gauge row inserts as shown in the picture below.

GageGuard

This insert is typically a shorter, rounder protruding insert. It makes contact with the borehole wall which helps to protect the gauge inserts. This helps because it gives 3 points of contact with the borehole wall. There are the gauge row inserts, the GageGuard inserts, and the heel pack inserts, all in contact with the borehole at the same time. This transfers the load between the 3 inserts and helps protect the gauge row, which is the most vulnerable part of the bit. The benefits of the GageGuard feature are better gauge durability and better material selection. Diamond PDC-coated inserts can also be used with GageGuard. The downside is that there may be a reduction in gauge count on some designs.


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December 2001

In order to make the space to drill the hole and press in the GageGuard insert, some of the gauge row inserts would have to be moved or eliminated. In some designs, it is not worth sacrificing the gauge row inserts for the GageGuard feature. If the gauge row inserts are spread out too far, or the configuration is changed, the gauge row could be weakened. It is not beneficial to weaken the gauge row by adding GageGuard. If it does cause a reduction in the gauge count for some designs, GageGuard would not be added. GageGuard is a factory-installed feature. It is not an add-on feature. The bit has to be designed with GageGuard on it from the beginning. GageGuard does come standard on some Schlumberger products but is not available on all of the product lines. Most applications will see benefits of GageGuard unless there is a reduction in the gage count that limits the run. JA = Jet Air. It is design differences that are used for durable bit geometry for under-balanced drilling. It typically has a low offset, an open cutting structure, and has special nozzle ports. There are only two areas in the world that typically use jet air bits. They are used in the Northeast and in West Texas, U.S.A. The bit is only built in two sizes, 7-7/8" and 8-3/4". The applications are for under-balanced drilling using air, foam, or mist. M = in the suffix represents Mudpick II hydraulics on HP bits. Normally if a bit had Mudpick II hydraulics, it would be called EHP. In order for a bit to be an EHP, it had to have three things: 1) threaded ring, 2) Mudpick II hydraulics, and 3) enhanced shirttail protection. In the 7-7/8" product line ball bearing are used instead of threaded rings. Since these bits do not have threaded ring, they cannot be called EHP. The way the Mudpick II hydraulics are designated on the 7-7/8" product line is by the M. The benefits of Mudpick II hydraulics on HP bits are a faster ROP (Rate Of Penetration) and better cutter and bottom hole cleaning. Most importantly, it makes more efficient use of the available hydraulic energy. There are some downsides to using Mudpick II hydraulics. There may be some cutter shell erosion due to the high-energy zone directly at the corner. There have also been some cases of backwash on the shirttail. Mudpick II cannot be used effectively in all situations. It works well in most soft and medium formations, especially where there is a tendency for bit balling. Any time there is low hydraulic energy or more efficient use of the hydraulic energy is needed, Mudpick II hydraulics is an effective tool.


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Diamond Features With Schlumberger’s roller cone cutting structure and shirttail features, there is the opportunity to use diamond PDC-coated inserts. If a bit has diamond PDC-coated inserts, the following designations are used: DA

- Diamond Coating on All Inserts

DN

- Diamond Coating on Nose Row Inserts

DI

- Diamond Coating on Inner Row Inserts

DG

- Diamond Coating on Gage Row Inserts

DT

- Diamond Coating on GageGuard Inserts

DH

- Diamond Coating on Heel Row Inserts

DK

- Diamond Coating on Shirttail Inserts

DKP

- Diamond Coating on Premium Shirttail Inserts

DKPR - Diamond Coating on Premium Shirttail Raised Inserts DL

- Diamond Coating on Lug Pad Inserts

Nomenclature & Features Review Questions Describe the features in the suffixes on each of the following roller cone bits: - 07 7/8” HP51X-MKP - 12 1/4” EHT11GK - 08 1/2” EHP51ACDLK - 17 1/2” EMS11DHKPR - 05 7/8” SL51HFDGH - 08 1/2” DJ44HTKPRDH - 07 7/8” HP62JA Sugar Land Learning Center

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December 2001

Schlumberger’s Roller Cone Product Lines In Schlumberger Drill Bits there are 3 major roller cone product lines: 1) Roller Bearing Non-Sealed, 2) Journal Bearing Sealed, and 3) Roller Bearing Sealed. Below is a list of all the current Schlumberger roller cone product lines (red indicates new products Schlumberger launched in 2001):

Y HP EHP MHP EHT MHT JA SL DJ FMJ CMC MS ETS EMS T DR

Roller Bearing Non-Sealed

Journal Bearing Sealed

Roller Bearing Sealed

• Y

• • • • • • • • • •

• • • • •

HP EHP MHP EHT MHT JA SL DJ FMJ CMC

MS ETS EMS T DR

Non-sealed roller bearing High Performance Enhanced High Performance Motor High Performance Enhanced Hardmetal Tooth Motor Hardmetal Tooth Jet Air Slim Line (Marketed as “Sabre”) Driver Journal (directional product line) Full Metal Jacket (PMC product line) Composite Matrix Cutter (PMC product line) Motor Series Enhanced Turbine Series Enhanced Motor Series Titan Driver Roller (directional product line)


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Fixed Cutter Bits The 3 types of fixed cutter bits are 1) PDC bits, 2) Natural Diamond and TSP bits, and 3) Impregnated Diamond bits. PDC (Polycrystalline Diamond Compact) bits have PDC cutters as the primary cutting structure. The PDC bits are built with either a steel body or a matrix body. The polycrystalline diamond compact consists of a diamond layer attached to a tungsten carbide substrate to form the complete cutter. Shown in this picture are the diamond table and polycrystalline diamond compact mounted onto the carbide substrate.

Tungsten Carbide Support

Diamond Table Polycrystalline Diamond Compact

There are 5 basic cutter sizes that are used in the oilfield to make PDC drill bits. These PDC cutters range in size from 19 millimeter down to 8 millimeter.

Increase the allowable RPM, ROP. Decrease the abrasiveness of the rock.


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December 2001

The PDC cutters are inserted into the bit body at an angle away from normal. This is called the backrake angle. Depending the on this angle of orientation of the cutters, it determines how aggressive the bit's cutting structure will be. The lower the backrake angle, the more aggressive the bit. Typically the backrake angle of PDC bits will be between 18% and 40%.

BLADE PDC CUTTER

Backrake Angle

?

When finally assembled the soft formation PDC bit looks something like the picture below. Shown are the cutters, the blades, and the pin.

Cutters

Blade

Pin


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General PDC Terms BLADE NOZZLE

JUNK SLOT AREA

Natural diamond and TSP (Thermally Stable Polycrystalline) bits use exposed surface-set diamonds as the primary cutting structure. These generally range from 5 to 8 stones per carat up to 1 stone per carat. In a natural diamond bit, the diamonds are set on the blades very closely spaced, as shown below.

Natural Diamond Bit


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TSP bits use thermally stable polycrystalline diamonds as the cutting structure. Once again, these are quite small pieces, ranging from about 1 to 2 millimeters in size. These are set so that they actually shear the formation rather than the grinding mechanism used by the natural diamond bits. Shown below is the orientation of the TSP cutters along the blades or ribs.

TSP Bit Impregnated diamond bits use an even smaller diamond, basically a gritsized diamond, which is set into a matrix in the blades. This then wears away, continually exposing new diamond to do the cutting. By using very small grit size, obviously the potential for high rates of penetration is limited. These bits tend to drill in the range of 1 to 5 feet per hour on average. Pictured below is an impregnated diamond bit with grit that is so fine that the cutting structure on the blades of the bit cannot be seen.

Impregnated Diamond Bit Sugar Land Learning Center

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December 2001

The failure methods of the 3 fixed cutter bits are shown below: IMPREG DIAMOND BIT: Hard Formation GRINDING Soft formation SHEARING SHEARING

NATURAL DIAMOND BIT: PLOUGHING/GRINDING PLOUGHING/GRINDING

PDC BIT: SHEARING SHEARING

F The impregnated diamond bits predominately drills by grinding when in a hard formation, although it may convert to shearing in a softer formation. The natural diamond or a TSP bits predominately drills by ploughing and grinding. The PDC bits predominately drills by shearing the formation. The advantage of fixed cutter bits is they have no moving parts. Why is this an advantage? Primarily there is less risk of leaving any junk in the hole like the cones off of a roller cone bit. Losing cones is a disadvantage when drilling horizontal holes especially when fishing the cones is a big problem. In addition, there are no temperature concerns up until about 700 degrees centigrade with PDC bits. The grease and rubber products in roller cone bits are temperature-sensitive, which can be a problem when drilling hot wells. In terms of operating procedures for fixed cutter bits there are many different thoughts on this. Many people in the oilfield seem to think that the only thing needed is to put the pin up, connect it to the drill string, and then turn it to the right. It is not that simple. Fixed cutter bits, especially PDC bits, are very lithology-sensitive and drill more efficiently if drilling parameters are adjusted every time the rock type changes. This is difficult unless particular attention is paid to the fixed cutter bit while it is drilling.


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Fixed Cutter Bits – PDC Component Parts

Matrix Body Bit Terminology Terminology INTERCHANGEABLE NOZZLE

CONE

FIXED PORT

NOSE TAPER OR FLANK

STEEL BLANK

SHOULDER CUTTERS • FACE • GAUGE • UPREAMING DIAMOND GAGE PAD

WELD GROOVE BIT BREAKER SLOT

TUNGSTEN CARBIDE MATRIX

SHANK BORE BEVEL MAKE UP FACE API PIN CONNECTION

SHANK

Steel Body Bit Terminology INTERCHANGEABLE NOZZLE

CONE NOSE

CUTTERS • FACE • GAUGE

TAPER OR FLANK SHOULDER

FIXED PORT GAUGE GAUGE INSERTS BIT BREAKER SLOT SHANK BORE

STEEL BODY

BEVEL MAKE UP FACE

SHANK

API PIN CONNECTION


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The main components of PDC drill bits are: - synthetic diamond cutters - support structures for the cutters - bit body - blades - profiles - diamond impregnated studs ("impregs") - gauge protection inserts - nozzles The majority of steel and matrix body PDC bits use one of four diameter cutters: 8 mm, 13 mm, 16mm, or 19 mm. Some bit styles use more than one cutter size in a single bit. Schlumberger’s PDC cutters have a bevel or chamfer around the periphery of the cutting face to increase initial impact resistance. Posts (or studs) are used as the PDC support primarily in steel bodied bits. Schlumberger has the facility to bond the PDC onto a post. The posts are manufactured from cemented tungsten carbide to provide a strong, erosion resistant support for the diamond. The post diameter varies according to the compact diameter. In addition, posts for 13mm cutters are available in short and long versions to allow the bit designer to make trade-offs between cutter interference and retention requirements. The Schlumberger inclined post (trade named "SuperStud") is a stud that is angled backwards from the cutting edge to the base. It was designed by Reed-Hycalog to provide greater support for the PDC, especially when used in high bladed steel bits. Due to the geometry of the post, the diameter may be less than an upright post, while still providing sufficient support and bond face area. This means cutters on inclined posts provide additional design freedom and can be packed more closely along a blade, if desired. Reed-Hycalog holds a patent on the angled post design and is the only PDC bit company that offers bits with this type of component. Cylinder cutters are basically elongated PDC elements. The increased length serves 2 functions: 1) it gives the necessary support to the diamondcutting layer and 2) it provides additional surface area for brazing the cutter securely into the bit body.


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Longer components may be one piece or have a separate piece of tungsten carbide bonded onto the PDC. The PDC on a cylinder cutter used by Schlumberger has a peripheral bevel or chamfer to increase the cutter's impact resistance. Bit Body The 2 main PDC bit body types are matrix body and steel body. The functions of the bit body are: - to retain and support the cutters & nozzles - to strengthen the bit downhole - flow control - attachment to the drill string The factors dictating the bit body material are bit life, strength, accuracy, repairability, and bit length. Blades The functions of the blades are: - support cutters and hybrids - direct fluid flow - define waterway depth - act to resist axial and lateral loads Blades support PDC cutters and hybrids:

Support Cutters CYLINDERS

POSTS OR STUDS

Cutters Hybrids


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Blades direct fluid flow:

Direct Fluid Flow

Blades define the waterway depth:

BLADE HEIGHT


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Blades help resist axial and lateral loads:

Resist Loads

Profiles There are 3 major profiles used for PDC bits: 1) short, 2) medium, and 3) long.

Profiles

CONE

NO

TAP

SE

ER/

BREAKER SHRANK

GAGE

NK

MEDIUM

LONG

The largest profile the better axial and lateral forces resistance.


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SHOULD

ER

FLA

SHORT


December 2001

Bit Length PDC bit length is important when: - a short radius well path is needed - getting the motor closer to the bit is needed - near bit stabilization is needed - drilling directional or horizontal wells

Bit Length

Diamond Impregs Although Schlumberger’s steel and matrix Hybrid PDC drill bits can both have diamond impregnated studs (generally referred to as impregs), the impregs are of different construction. Matrix Hybrid bits have impregs cast in situ during the manufacturing stage. Steel bits utilize separate components that are manufactured from tungsten carbide. Both types contain many tiny natural diamonds in the end toward the formation. The impregs used in Reed-Hycalog's patented Hybrid PDC bits help ensure a uniform wear pattern for all PDC cutters across the face of the bit, which contributes to longer bit life. Additionally, the impregs are beneficial in protecting the PDC cutters from impact damage by stabilizing the bit downhole. In essence, the impregs serve as built-in protection against bit whirl. Because the impregs contain diamonds, they can continue to protect the PDC cutters from damage in hard or highly abrasive formations.


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Diamond Impregs

IMPREGS

Gauge Protection Schlumberger utilizes 2 types of gauge inserts in steel bodied bits. The first type consists of a cylindrical piece of hot pressed tungsten carbide with fluted sides to improve retention. The second type is like the first but also contains surface-set cube diamonds, orientated to their crystallographic optimum, to provided enhanced abrasion resistance. Reed-Hycalog holds a patent on using this technique for providing diamond gauge protection in a steel bodied bit. Schlumberger gauge inserts are manufactured with a radius on the outside face so when they are assembled in the bit gauge, they will be flush with the steel surface.

Gauge Protection Steel Bodied Bits

Conventional Gauge Pad


“G” Feature Gauge Pad

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Gauge Protection

Gauge Protection Matrix Bodied Bits

PDC Nozzles Schlumberger uses a variety of interchangeable nozzle types and sizes. The choice of nozzle type is based on many factors, including the size of the bit and the recommended hydraulic program. All nozzles are manufactured from tungsten carbide, which provides the necessary erosion resistance. They are screwed into the bit using custom nozzle wrenches and all have rubber "O" rings to hydraulically seal the threads. Because the nozzles are threaded, they may be removed from the bit body and changed should the hydraulics need to be adjusted.


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PDC Bit Designs The design of a PDC drill bit is largely a matter of compromise, as various factors, which may be in conflict, are considered against a tight framework of fundamental constraints. Features that prove extremely beneficial under one set of circumstances may be less than optimal under another. Consider that a PDC bit is a mechanical device designed to transmit energy for the purpose of drilling rock. Despite its small size, it must be designed to transfer more energy than is generated in a high performance race car engine. Cone The cone of the bit provides a degree of stability when the bit is drilling, due to the resultant cutting forces from the PDC set within the cone generally urging the bit to rotate about its central axes. The resulting central cone of rock further enhances this stabilizing effect, as it helps prevent the bit from shifting the location of the central axis. The cone of the bit is usually lighter set than elsewhere on the bit face as the rock cone is unconfined and consequently less force is required to remove it. Also less rock per revolution of the drill bit is removed towards the central region of the bit. Nose The nose of the bit is that region of the face that is the furthest from the pin end. It is, therefore, the first part of the bit to encounter any change in formation when drilling a vertical or near vertical hole. Because of this, it is desirable to have a relatively large number of cutters set on the nose to prevent overloading during the transition to a harder formation. Taper The taper (or flank) of the bit is the section between the nose and the gauge. It may provide a degree of stability and its length is usually governed by the cutter density requirement. A bit designed for tough applications, which needs a large number of cutters, would tend to have a more extended taper than a product for drilling a soft formation. However, an alternative way to achieve a higher cutter density without increasing the taper is to increase the number of blades.


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Outer Diameter Radius The Outer Diameter Radius (ODR) refers to that region of the bit profile where the radius at the end of the flank leads into the gauge of the bit. This region of a bit is extremely important, especially in motor or turbine applications where rotating speeds are high. The cutters must withstand the effects of high velocity due to their radial position on the face of the bit. Although the angular velocity of cutters at the bit gauge is identical to that of cutters within the cone, the tangential velocity is greater since it is a function of radial location. PDC Cutters The number of cutters used on a PDC bit is a primary determinant of how the bit performs. In an ideal situation, a PDC bit would be designed so it would: - drill a broad range of formations including hard and abrasive stringers - provide a consistently high rate of penetration - have a long bit life - can be built at a low cost Unfortunately, there are performance and cost tradeoffs in varying cutter count. Using more cutters allows a bit to drill harder, more abrasive formations and generally results in a longer bit life. However, a higher cutter count also makes a bit more costly (particularly since PDC components constitute a high percentage of the total bit cost) and, in general, causes the bit to drill at a slower rate of penetration. As the number of cutters is reduced, the direction of the tradeoff reverses. Cutters of 8 mm diameter have been used on products designed for harder formations. In fact, the first PDC manufactured was this size. 13 mm cutters are the industry standard size. They are most suitable for cutting medium to medium-hard formations as well as abrasive rock. Generally associated with fast drilling, 19 mm cutters are most suitable for drilling soft to medium formations when mounted in high bladed style bits. Because larger cutters produce large cuttings in the right application, they are extremely useful when drilling with oil based mud or water based mud in a hydratable formation.


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PDC cutters of up to 48 mm diameter have been used in soft formation bits. However, Reed-Hycalog's experience is that the incremental advantage does not outweigh the inherent problem of redundancy limitations. Space is limited on the bit face and by using such large cutters there is only sufficient room to mount the minimum number of cutters to cut a full bore hole. If one cutter were to fail, the bit would be unable to proceed. Additionally, as very large cutters wear, the very large wear flats produce considerable heat that can cause catastrophic damage to the diamond layer. Cutters are distributed across the bit face in such a way as to satisfy various requirements. Naturally the cutter layout must result in a full gauge hole being cut as the bit is rotated. As with most bits, satisfying one condition may well be at the cost of another. Judgments based on experience must be used to produce an optimized bit design. Cutter Wear It is desirable to get even wear across all the cutters of the bit. If one cutter wears appreciably more than the others, it could result in a weak spot. Additionally, even wear results in the efficient utilization of the PDC. Cutter Placement The cutters are arranged across the bit in such a way as to provide maximum bit life and to take into account expected rates of penetration and product cost. Cutter Balance The lateral imbalance force, resulting from the vectorial addition of all the cutting forces as the bit is drilling, is calculated at the design stage. Certain types of anti-whirl drill bits utilize this force in conjunction with a cutter devoid area and a low friction zone at the gauge to reduce the incidence of backward whirling, a detrimental motion of the bit which can occur under certain conditions. On most products, however, it is desirable to minimize this lateral force and the cutters are positioned accordingly.


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Cutter Redundancy Depending on the target formation, Schlumberger bits may have considerable cutter redundancy built into the design. This is especially true on the flank and Outer Diameter Radius. If the bit is designed for tough, abrasive formations, the work performed per cutter, in these expected high wear regions, is minimized. This reduced work per cutter results in longer product life and reduced risk of premature failure. Schlumberger PDC Cutter Technology There are performance steps that are followed in the development of cutter technology. First, the best performing cutters in the industry are identified. Currently, Schlumberger primarily utilizes in-house cutters but will also use five outside vendors as suppliers. Whenever a new cutter design is developed, it is tested to assure consistent quality and reliability. Currently, only between 10 and 15% of cutters evaluated actually meet the test criteria. Schlumberger continually evaluates it’s own standard cutters to make sure they are all up to the standards. Here are some interesting facts about diamond. Diamond is in fact 10 times harder than steel. It is also twice as hard as tungsten carbide. Remember, tungsten carbide is the substrate that is used in the PDC cutters. Diamond is 10 times more wear resistant than tungsten carbide. In compression, diamond is 20 times stronger than granite, which is probably one of the hardest rocks. Diamonds also have the lowest coefficient of friction of any known material. Friction of course creates heat. Convection cooling is not as efficient in maintaining low temperatures as reducing friction. Diamonds are one of the best thermal conductors known. This means if heat is transmitted to the cutter it will soon spread throughout the diamond layer. Diamond also turns to graphite at approximately 1,300 degrees Centigrade at ambient pressure, and in the presence of oxygen will burn at 800 degrees Celsius. Diamond is non-wettable which means it must be combined with another material in order to bond. What Schlumberger uses is cobalt to bond the diamond. Unfortunately at 700 degrees C, the cobalt will actually force the diamond apart. Therefore the challenge is to mix the diamond grit with the cobalt and the tungsten carbide to develop a superior PDC cutter.


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December 2001

In the manufacture of PDC cutters, Schlumberger uses a diamond press. This is a huge piece of equipment 12 feet high, 27 tons in weight, and all that is used just to compress a two-inch square cube. The pressures involved are 1 million psi and temperatures up to 1,400 degrees Celsius. The diamond press is used not only to manufacture the standard cutters but is also used to test out new designs for research and development. In the manufacturing process two cutters are manufactured at one press. Salt is used as an excellent thermal conductor and will not deform under the massive pressures. As the pressure and heat is applied the cobalt is driven down from the substrate by a concentration gradient into the diamond grit. Once it mergers with the diamond grit it then bonds it together, and also bonds the diamond layer to the tungsten carbide substrate.

Cobalt driven by concentration gradient Diamond Grit

1,400º C & 1,000,000 psi

Unfortunately, the tungsten carbide and diamond have different thermal expansion rates. As the cutter cools down the tungsten carbide is wishing to expand while the diamond is wishing to contract. This creates incredible stresses at the interface between the diamond layer and the tungsten carbide substrate. The thickness of diamond layer that can be manufactured is limited by several factors. Primarily, it is the cobalt diffusion. If diamond layer is too thick, not enough cobalt will actually get into the PDC cutter that will result in a very weak outer edge. Also there are stresses induced by differences in the thermal expansion coefficient. Unsintered diamond or high stress concentrations will result in the cutter flaking, delaminating, or even cracking which will all basically lead to a premature bit run failure. Sugar Land Learning Center

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December 2001

Historically, PDC cutter’s impact resistant against the abrasion resistance was measured. Basically there was a tradeoff. If a cutter had very high impact resistance it would have low abrasion resistance. Conversely, if it had high abrasion resistance it would have low impact resistance. When Hycalog first started developing PDC cutters, they referred to the impact resistance axis as R, S, T, U and V and the abrasion resistance axis as C, D, E, F, G, H, I.

V U Impact Resistance

T S R C D E F G H I Abrasion Resistance

Shown here is what historically has been the tradeoff. By using larger diamonds to give impact resistance a smaller diamond grit was needed to give abrasion resistance. It was soon realized that if larger and smaller diamond grit could be combined, there would be a more abrasion and impact resistance cutter. This would actually move away from that trade-off line.


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December 2001

Trade-off line

Impact Resistance

Abrasion Resistance

For several years now Schlumberger has been using both tri-modal and quadra-modal grits, which are grits with either 3 or 4 different sizes of diamond. After the diamond compact is manufactured it then needs to be set on to an additional tungsten carbide substrate. This substrate or support is what actually holds the cutter to the face of the bit. The attachment process for attaching the compact to the substrate is called LS bonding. LS bonding is quite a difficult process as the LS bond has to be heated up higher than the critical level for the diamond layer. So as the induction coil applies heat to the support the diamond layer is actually being continually cooled with a layer of cooling water being passed above it. LS Bonding is shown below:

Cooling Water Carbide Contact

Shim PDC

LS Bond

Induction Coil (Heat Supply)


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It is very important to have a good quality assurance in the manufacture of PDC cutters. Each PDC cutter is inspected several times during the manufacturing process. Each is given a dimensional check, a UV dye penetrant check, which is done to look for cracks in the diamond layer and the edge delamination, to check the LS bond integrity, and to see if there has been any thermal degradation. Finally, there is an ultrasonic test which is done for delamination, LS bond checks, and also for thermal degradation. NPI PDC Cutters Historically, the interface layer between the diamond and the tungsten carbide was planar. However in recent years Schlumberger has changed to non-planar interface (NPI) type cutters. The NPI cutters have several advantages: - they give reduced stresses of the interface of the diamond and the tungsten carbide substrate - they allow between 25% and 40% more diamond on the cutter - they have increased impact resistance

Non-Planar Interface (NPI) Geometry

Star (1)

Fan


Star (2)

Iris

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December 2001

Currently, most fixed cutter bits manufactured by Schlumberger use NPI cutters as standard. Different types of geometries have been tried and tested. Tests have been conducted trying to create a thicker rim of diamond on the outside layer that would give increased diamond where you need it the most. One of the problems with PDC cutters when used at very high back rake angles is that there has been a greater incidence of impact damage. This is due to the fact that there is less tungsten carbide support at a small depth of cut, as you can see in the diagram below. 15º Back 45° Rake

Backrake

45º Back 15° Rake

Backrake

Backrake Angles

To overcome this problem Schlumberger developed the TuffEdge™ cutter that is used with high backrake angles. Basically, this has a chamfered geometry and gives far better impact resistance than the old conventional design. A TuffEdge™ cutter is shown below:

TuffEdge™ Cutter


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December 2001

Another recent development has helped improve both abrasion resistance and impact resistance. This was the introduction of the encapsulated cutter where basically most of the cutter is surrounded by a tungsten carbide rim. Below is a picture of this substrate.

The PDC is not totally supported by the carbide rim. Basically it goes around about 300 degrees leaving the PDC only exposed at the actual cutting interface of the bit. It also is fitted around a conventional NPI (non-planar interface) substrate.

TReX Cutters The latest development in Schlumberger’s PDC cutter technology is the TReX cutters. TReX cutters give maximized abrasion resistance and improved impact resistance. Successful bit performance depends upon maintaining a sharp diamond edge on each individual cutter throughout the bit run. Although diamond is the hardest known material it will deteriorate due to abrasive wear and impact shocks which are common during the downhole drilling process. Abrasive wear is caused by continuous contact with the rock surface and the friction at the cutter edge causing thermal degradation of the diamond. As the diamond develops a larger wear flat then the cutting efficiency is decreased. Impact shocks cause a lot more damage. Commonly bit whirl and stick slip, two common types of downhole vibration, will cause shocks in the range of 20-30g. Minor normal vibration is commonly in the range of 1-2g.


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The picture below shows the effect of repetitive impact shocks and loads are to a PDC cutter.

Sharp

Microfracture

Chipped

Initially, it starts microfracturing and then will actually start to leave a jagged edge as the diamond layer peels off. The idea behind developing the TReX cutter was to try and get a cutter with very high abrasion or toughness and maximum wear life. The objective was to move up to the top right hand corner of the graph shown below.

Toughness

Wear Life

The consistent target has been the top right-hand corner of the graph.

The properties which influence the life of the PDC in the oilfield are its toughness and its wear life, or its impact resistance and abrasion resistance. If a coarse diamond grit is used the large grains tend to absorb the shock. However, the downside is that loss of an edge grain represents significant wear amount. Small grains on the other hand are less shock resistant. If a smaller grain is lost it is less significant than if a larger diamond grit grain is lost. Throughout the years small improvements have been made mainly by the introduction of thicker cutters and of non-planar interface (NPI) cutters.


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Old-style planar interface cutters with thicker diamond wafers improve the wear life of the bit but they did result in a weaker bit in terms of abrasion resistance or toughness. Thick diamond and NPI substrates did in fact give wear and toughness improvements, but these were not greatly significant. The new TReX cutter is a significant departure from existing technology. It uses a multi-modal diamond grit concept, and the cutting edge is ultra wear resistant and very, very tough. Currently, this technology is patent pending. It uses existing NPI substrates, the only difference being the composition of the diamond grit. For optimum performance benefits from the TReX cutters the selection of the application is crucial. The objective of the run must be defined and if possible the run should be supervised. This ensures that the correct drilling parameters are used at all times and also allows identification of anything strange happening during the run which may lead to premature failure of the bit. For TReX cutters it is important to have good offset data and to present a good case study following the run. Schlumberger Fixed Cutter Product Lines

SCHLUMBERGER DRILL BITS FIXED CUTTER PRODUCT LINES PDC • Hybrid-PDC™ • BiCentrix™ • SteeringWheel™ • Transformation™


NATURAL DIAMOND & IMPREG

• DuraDiamond™ • 300 SERIES • 400 SERIES • 500 SERIES • 600 SERIES

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RS prefix is used for Schlumberger’s bits that were designed for use specifically with rotary steerable drilling systems. These systems drill directional wells without the use of a motor and therefore will require specific bit designs.

Rotary Steerable Bit

SB is used for the Stable BiCentrix™ range of bits. These bits have drill-out capabilities and can be used on directional wells. Stable BiCentrix™ ?


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ST is used to designate SideTrack bits. These are bits specifically designed for use in sidetracking a well.

SideTrack Bit DS is a standard nomenclature used for full production designs. The most recent development of standard production bits within the DS product line are the SteeringWheel™ and TransFormation™ bits. SteeringWheel™ bits have greater stability which creates a smoother borehole and bottom hole pattern. These bits also improve directional response. The SteeringWheel™ bits helps to reduce bit vibration and bit whirl. This stability allows more even wear of the PDC cutters and improved condition of the PDC face.

SteeringWheel™ Bits


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TransFormation™ bits are designed to transform from a soft formation bit to a harder formation bit as the formations change. This is accomplished by a paired arrangement of blades for a broader range of formations. The primary blades (P) drill the majority of the softer formations and secondary blades (S) drill the formations when they become harder.

Transformation™ Bit

X prefix is added to the DS, RS or SB to designate that the bit has the new TReX cutters. Schlumberger Drill Bits Fixed Cutter Nomenclature Here examples of Schlumberger Fixed Cutter Bit nomenclature:

12 1/4 Size

17 1/2

DS 70 A4 HF+GLUV Product Design Design Added Line Number Variant Features

4XX


A1 GSU Page 82


DS 4XX X 70 A4 A1

December 2001

= represents standard production PDC bit = DuraDiamond™ series = TReX cutters = the design number - these have no significance in terms of of cutter count, blade count, cutter size, etc. = indicates this is the 4th variant of this bit = when a bit is first designed, it is designated A1 – subsequent changes will then be A2, A3, etc.

After the numbers that designate the variant, are the letters that designate the various features on the PDC bit. Schlumberger Fixed Cutter Features The features for Schlumberger’s fixed cutter bits are designated in the suffix of the nomenclature. Schlumberger’s major features are: D

= DiamondBacks – secondary cutters used to back-up the primary cutters. Used for extra protection in harder and abrasive formations.

DiamondBacks

Full DiamondBack


Partial DiamondBack

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F+

December 2001

= Hardfacing - the hard facing used on steel-bodied bits – it is applied to minimize erosion specifically adjacent to the nozzles.

Hardfacing

G

= Extra Gauge Protection - used in applications where gauge wear may be a problem, such as directional drilling or highly abrasive formations.

H

= Hybrid - means the bit has a hybrid or impreg backup cutters – these are diamond-impregnated studs located behind the PDC cutters. The primary functions of Hybrids are to: - enhance bit stability - reduce torque fluctuations - protect PDC cutters - create smoother cutting action - increase bit life Drilling Sequence Of Hybrid Bits Through Hard Stringers

STAGE 1 Sugar Land Learning Center

STAGE 2

STAGE 3 Page 84


H

December 2001

= Hybrid

Hybrid Bits

J

= Fixed Ports – fixed nozzles installed during manufacturing to provide extra hydraulic cleaning

L

= Long Gauge - means the bit has a longer gauge than standard, sometimes which is used when drilling tangent sections. The long gauge acts as an integral near bit stabilizer and assists in holding angle.


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December 2001

N

= NPI Cutters – the bit has Non Planar Interface cutters.

S

= Short Gauge – the bit has a gauge that is shorter than normal. Short gauge bits are generally used for their steerability in a directional or horizontal well.

U

= Upreaming Cutters - the PDC cutters located at the backend of the gauge pad. These are in contact with the formation whenever the bit is being pulled out of the hole and rotated, and they are used to wipe out any ledges or irregularities in the borehole.

Upreaming Cutters

Natural Diamond “upreamers” PDC “upreaming” cutters

V

= SwitchBlade™ hydraulics - refers to the hydraulics configuration of the Transformation™ bit.

Conventional Sugar Land Learning Center

SwitchBlade Page 86


December 2001

The SwitchBlade™ hydraulics concept is as follows: 1. drilling fluid exits the nozzle in front of the secondary blade, cools and cleans the cutters, and then flows inward 2. high velocity flow creates a venturi effect, drawing fluid through the reduce opening 3. high velocity flow from both nozzles is maximized to cool and clean the primary blade where most of the cuttings are generated

1

2

3

SwitchBlade™ Hydraulics


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Drill Bit Links on the Schlumberger Hub Drilling Services Hub http://www.hub.slb.com/index.cfm?id=id2617

Drill Bits - Products & Services http://www.hub.slb.com/index.cfm?id=id8417

Drill Bits – Best Practices http://www.hub.slb.com/index.cfm?id=id18241

Drill Bits – Bit Browser http://www.stonehouse.oilfield.slb.com/browser/Search.cfm

Sugar Land Learning Center (SLC) Web Site – Drill Bit Training http://slc.sugarland.anadrill.slb.com/SLCNewImage/Sugar%20Land%20Learning%20Cent er%202001.htm


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