What is Well Stimulation and the Typical Methods?

What is Well Stimulation and the Typical Methods?

Well Stimulation is a technique oil companies use to maximize the volume of oil and gas that can be retrieved from a drilled well.

What Are the Most Common Methods of Well Stimulation?

The most common methods of well stimulation are

  • acid injection
  • hydraulic fracturing, and
  • explosives.

All forms of well stimulation help to open channels in the formation, so that oil and gas can flow to the wellbore more easily.

Acid Injection Well Stimulation

Acid injection is the oldest form of well stimulation from more than 100 years ago.

Acid stimulation is where an acid is pumped down hole under pressure.

The acid dissolves minerals and calcareous deposits that would otherwise impede hydrocarbon flow.

The porosity within the formation is enlarged, allowing for increased fluid passage.

The most common type of acid used is hydrochloric acid (HCl).

Careful consideration must be taken to not damage the steel casing and well equipment when using acid. After the acid job is complete, it is removed from the well by a process called backflush.

Hydraulic Fracturing Well Stimulation

Hydraulic fracturing well stimulation requires a fluid to be pumped down hole at extremely high pressures.

The fluid pressure forces the producing formation to fracture, crack, and break.

These fractures allow hydrocarbons to easily pass to the wellbore.

When a well is “fracked”, and the hydraulic fluid pressure is reduced, the cracks tend to close and return to their original state.

To maximize oil production a proppant or sand is pumped down hole while the well is being fracked.

The proppant makes its way into these tiny fractures within the formation.

As the pressure is reduced, the fractures are held open by the proppant, which is now within the fractures.

The hydrocarbons now have a much easier path to the wellbore.

Some research shows that production can increase 30 times when hydraulic fracturing has been used.

Retired wells can be fracked to revitalize and increase production, giving them a second life before they are decommissioned.

What is Hydraulic Fracturing Well Stimulation

What is Hydraulic Fracturing Well Stimulation

Explosive Well Stimulation

Explosive well stimulation requires the use of chemical explosives.

This is commonly known as well shooting.

Explosives detonated downhole create an energized pressure wave which travels through the fluid in the well.

The fluid moves into and breaks up the formation.

Explosive is the simplest form but has been proven the be the least accurate and effective of all methods.

It can also cause localized damage to the well if not executed properly.

It’s Time to Run Canadian, Eh?

Trendon Bit Service can save you time and money through,

  • – Faster ROP,
  • Bits that last, and
  • Our experience on your team.

Call us at: +1 403 536 2770,

Email us at: sales@trendon.ca, to save time and money on your project.

Trendon Bit Service

Performance. Durability. Control.

Improving Drilling Performance – Sliding vs. Rotating

Improving Drilling Performance – Sliding vs. Rotating

When it comes to improving drilling performance, saving the operator time is important. Time equals money and every minute, and every hour saved helps you succeed.

There are other metrics to consider when judging a successful drill and how to improve drilling performance.

Drill bits have a unit cost, whether it’s a purchase price or rental rate.

The larger cost to the operator is the time it takes to drill a well. As the operator is paying for the rig, the services, products, and people to be on location to take care of the entire drilling operation.

Drill bits that can drill faster and longer are what operators are continually seeking. An hour saved is big money.

The formations being drilled, depths of drilling wells, the size of the hole and locations where these wells are drilled are ever changing.

Therefore, not one bit type will serve as an all-encompassing solution.

Drill bit providers are continually improving their designs with the latest diamond cutter technology, tweaking how many cutters are utilized, where the cutters are placed in a bit and improving the matrix body material that holds the cutters in place.

Different bit profiles and gage lengths will also help the bit’s ability to be steered when drilling a directional well. All these available characteristics of a drill bit are considered when selecting the best drill bit for the job.

The speed at which a drill bit can drill at is highly sought after, along with the ability to steer the drill.

Improving Drilling Performance: Sliding vs. Rotating

When directional steering is required, a drill bit must “slide” to build angle or change direction in a well when using a conventional mud motor.

The mud motor will have a small bend between 1.5-2.5 degrees.

When the well direction needs to change the drill pipe will be held static whilst the mud motor will continue to power the drill bit. The small bend in the motor will force the drill bit to drill to one side of the hole and change direction.

In lateral and vertical sections, the drill bit can creep off trajectory, due to formation push or tendencies induced by the bottom hole assembly (BHA).

The drill bit will need to be corrected via a correction slide to stay within target.

The rate of penetration (ROP) during sliding is usually 50% or less than “rotating” (when the drill pipe is rotating, and the motor is powering the bit).

Drilling whilst the drill pipe is rotating is the most efficient drilling mode. Weight from the drill string can be easily and consistently be transferred to the drill bit. Rotating the drill string is powered from the surface by a rotary table or top drive.

If we can reduce the amount of sliding a drill bit has to do, the overall average rate of penetration (ROP) will improve. This saves time and money.

This is an important consideration that gets overlooked.

Improving Drilling Performance: Worked Example

If a drill bit can drill 10 m/hr rotating and 4 m/hr while sliding, the sliding ROP is 40% of rotating. If that drill bit slides 100 m out of 1000 m lateral the entire lateral would take 115 hours to drill with an average ROP of 8.7 m/hr.

Breaking this down by hours, sliding would take 25 hours and rotating would take 90 hours. 10% of the well drilled by sliding would take 28% of the total time drill the lateral. That is time wasted to drill the well.

That is why reducing sliding saves money.

Improving Drilling Performance: Drill Bit Design

In a build section, a drill bit can be designed to build angle as best as possible, whilst having a low reactive torque. This will help to quickly achieve the required build.

Note that coupling a properly designed build bit with an adequate directional bottom hole assembly (BHA) is paramount to success. Drilling a slow build section or using a drill bit that is difficult to control directionally will cost the operator time. Chances are the operator will not use that drill bit again.

In a horizontal section, a drill bit may tend to drift off target.

This can be costly as many corrections slides will be needed to stay within the payzone for the duration of the horizontal section.

A drill bit designed to track straight or resist walking will reduce the total number slides. Less sliding means a faster overall rate of penetration (ROP) and therefore less time spent drilling. Sometimes using a very aggressive drill bit may not actually equate to a faster section drilled.

Aggressive drill bits tend to not be as stable and more likely to wonder. Engineers spend a lot of time using field data and computer simulation software to design drill bits specific to the needs of an operator.

Designing aggressive drill bits that are stable is key.

The total meters slid can be adjusted by either building angle smoothly and rapidly as possible or tracking straight to reduce wandering or walking.

The operator will then benefit from a faster overall rate of penetration (ROP). A well drilled faster means money saved on not having to pay for hourly/daily services.

Saving hours of drilling can mean saving over tens of thousands of dollars which is big savings anyway you look at it.

It’s Time to Run Canadian, Eh?

Trendon Bit Service can save you time and money through,

– Faster ROP,

– Bits that last, and

– Our experience on your team.

Call us at: +1 403 536 2770,

Email us at: sales@trendon.ca, to save time and money on your project.

Trendon Bit Service

Performance. Durability. Control.

Rollercone vs Fixed Cutter Bits

Rollercone vs Fixed Cutter Drill Bits

This article talks about the key differences between Rollercone and Fixed Cutter Drill Bits. 

Generally speaking, there are two different categories of drill bits, Rollercones and Fixed cutter bits.

  • Rollercone bits have rollers rotating around bearings. Rollercone bits use steel teeth or tungsten carbide inserts as cutting elements.
  • Fixed cutter bits use diamond cutting elements to fragment the rock. Most types of fixed cutter bits are polycrystalline diamond compact (PDC), natural diamond (mills), and diamond impregnated bits.

Types of Drill Bits - Rollercone vs Fixed Cutter Bits - Trendon Bit Service

A fixed cutter bit’s life depends mainly on the wear of the diamond cutters while rollercone bits life is generally limited by bearing life rather than cutter wear.

When properly selected for the formation to be drilled, a fixed cutter bit usually will have a longer life than a rollercone bit, and in general PDC bits drill faster.

PDC bits remove the rock mainly by shearing, whereas natural diamond and impreg bits drill mainly by plowing and grinding the rock. A rollercone bit removes rock by crushing, gouging and scraping.

Rollercone bits are made up of three legs welded together.

Each leg holds a rolling cone fitted with teeth or inserts. Teeth are milled directly in the cone where tungsten carbide inserts are pushed in holes that are drilled in the cone.

Rollercones that have teeth milled into them are called tooth bits. These steel teeth are brazed over with a protective hard facing which substantially increases the life of the bit. Steel tooth bits are mainly used for fast soft rock applications like surface bits or shallow wells. When the cutters are made from tungsten carbide inserts, the bit is called a TCI (tungsten carbide insert) bit. TCI bits are more durable but are not as aggressive as a steel tooth bit. TCIs are used in harder more abrasive applications.

Steel Tooth vs. TCI

Since each rollercone contains bearings that allow the rollercone to rotate, lubrication or grease is required to keep the bearings moving smoothly. A pressure regulating system and grease reservoir is required to keep the grease in the bit and to ensure the seals are not squeezed out of their housing when the bit is subjected to extremely high pressures down hole.

When drilling, the weight on the bit and rotation from the drill pipe and or downhole motor makes the cones rotate and interact with the rock. The inserts or teeth penetrate the rock which fractures and break is up. The drilling fluid from the bit cleans and removes these fragments from the bottom of the hole so that new formation is revealed and the process continues uninterrupted.

Fixed cutter drill bits use natural or synthetic diamond cutters to fragment the rock. They are sometimes called a shear bit because it removes the rock by shearing it instead of gouging and crushing the rock like a rollercone bit. A diamond bit has three main parts: the cutters, the body, and the shank. Instead of having three independently moving cones, a diamond bit has a stationary head that rotates as one piece with the drill string. Because of the increased hardness and lower impact strength of diamond cutters compared with steel teeth or tungsten carbide inserts, the design of a diamond bit is quite different from a roller cone bit. Fixed cutter drill bits use various diamond cutters (PDC, thermally stable polycrystalline TSP, natural diamond, impregnated) to fragment the rock.

Steel and Matrix Drill Bits

Steel and matrix are the commonly used materials for drilling bit bodies.

Matrix bit bodies are manufactured using a cast mold by bonding tungsten carbide powder with an alloy binder. The mold is placed in a furnace to allow the binder to melt and infiltrate the matrix powder. As the binder infiltrates the matrix powder, a solid metal casting is formed. The two types of matrix body bits incorporate PDC cutters for cutting elements or incorporate natural diamonds mechanically or impregnated. The matrix bit body remains the predominant body type used in the industry. 

Matrix PDC bits utilize PDC cutters that are brazed in place. Depending on the magnitude of wear or damage to the matrix body, the PDC cutters and be removed and replaced with new cutters allowing the PDC bit to be reused multiple times.

PDC Cutters, Trendon Bit Service, Drilling Corner, Oil and Gas Drilling, Geothermal Drilling

Steel bit bodies are made of machined steel that is precisely milled. The PDC cutters (click here to read our article on how PDC Cutters are made) are brazed in each pocket. On steel bits, hardfacing reinforces the critical areas subject to erosion such as gauge areas, the front and back blade areas and nozzle exit areas. PDC bits make up more than 90% of all drill bits used in the oil and gas industry. This number is only getting larger.

Natural Diamond Bits

On a natural diamond bit, the cutters have natural industrial diamonds arranged in rows. On the bit, the diamonds are embedded on the surface of the bit which touches the bottom of the hole. The body is the main section and holds the diamonds. The shank is a steel base for the body that gives structural strength and provides a place for the threads to make up the bit on the drill string

Natural diamond bits were used from the early days in the petroleum industry, and some are still used for specific applications. Designers were always trying to solve natural diamond bit hydraulic problems caused by overheating and degradation of the diamond. These days natural diamond bits have nearly disappeared due to the limitations of short life and cost.

Impregnated Diamond Bits

Impregnated diamond bits are similar in theory to a natural diamond bit however they utilize smaller synthetic and natural diamond particles that are infiltrated in the supporting matrix throughout the blade (not just on the surface) . As the diamonds wear and fall out the matrix is worn and new sharp diamonds are exposed. In order generate and economical rate of rock removal a high speed motor or turbine is required to spin the bit any where from 1000 to 4000 RPM.

Call us at: +1 403 536 2770,
Email us at: sales@trendon.ca,
to save time and money on your project.

Trendon Bit Service
Performance. Durability. Control.

How Are PDC Cutters Made?

How Are PDC Cutters Made?

Understanding how PDC cutters are made is a great way to increase your drill bit knowledge. 

For some of us in the oil industry the term PDC may be a daily acronym used in the office or in the field but what does PDC really stand for?

It stands for Polycrystalline Diamond Compact.

A PDC cutter is the heart and sole of a PDC drill bit. It makes up more than 90% of all drill bits used today for mining, geothermal, oil and gas drilling.

PDC Cutters, Trendon Bit Service, Drilling Corner, Oil and Gas Drilling, Geothermal Drilling

What are PDC cutters made from?

PDC cutters come in many sizes, shapes and forms.

The most common are the cylindrical planar type in the image above.

A PDC cutter consists of two parts, the diamond table and the substrate. 
The thin disc at the top is the  diamond responsible for removing rock.

Diamond is one of the hardest materials on earth.
The larger portion below is the metal tungsten carbide alloy that is responsible for securing the cutter to the drill bit.

Natural diamonds can be found in the earth’s crust and require high pressure, heat and time to form.

For the last 125 years methods have been discovered to create synthetic diamond.
The first commercially successful synthetic  diamonds were created in 1954 by Tracy Hall of General Electric.
Since then, the manufacture of synthetic diamond has been vastly improved for uses in many different industries including mining, automotive machining, jewelry, and lasers for medical procedures.  

In order to make a PDC cutter, diamond grit is placed in a small cannister placed in a press.

The most common press machine is called a cubic press standing 9 feet tall and weighing 40 tons.
The cubic press uses 6 anvils which converge to create pressures higher than 1,000,000 PSI, but this pressure alone is not enough to create diamond.
As the diamond is pressed, it is also heated to 2300 degrees Celsius. A catalyst is added before pressing to help speed up the process.

The catalyst is usually cobalt.

The diamond will sit in this heated and pressed state for several minutes,  whilst diamond to diamond bonds are created.

How Are PDC Cutters Made

Diamond is known as a non-wettable material. This means that you cannot weld or braze to it.

The diamond is secured to the metal substrate during the pressing process. Before the grit is pressed it is put into a refractory metal can along with the tungsten carbide and cobalt.

What’s inside a PDC Cutter?

How are PDC Cutters Made?

Cobalt, which helps to catalyze the diamond sintering process, also helps to “glue” the diamond to the substate through molecular joining of the diamond and the substate.

Below are images showing loose diamond particles and joined diamond grains after the pressing process.
Cobalt can be seen as white specks between the black visible diamond grains.

This method of creating diamond gives the PDC cutter greater toughness (impact resistance) than a single diamond crystal.

The grains and boundary lines of each individual crystal is randomly oriented.
We see more uniform wear than a single diamond crystal but thermal conductivity and hardness is near that of single crystal values.

This multigranular diamond structure is extremely wear resistant but also gives it a significant boost in crack resistance.

After the cutter is pressed it is removed from the cube assembly.

A raw PDC cutter, which is very crude, is then sent for machining. Since diamond is the hardest stable material on earth, diamond tools are required to grind and machine the PDC cutter into tolerance. It’s like cutting a piece of lumber with a wood saw.

It’s a long arduous process.

Raw Unfinished PDC Cutter

Machined and Final PDC Cutter

There are various steps and changes that can be made to alter the properties of the PDC cutter in order to increase or decrease the cutters ability to withstand impact, wear, heat and corrosion.

Some of these include altering the diamond grain size, diamond table thickness, metallurgy of the tungsten carbide substrate, press pressure, press time, press temperature as well as many others.

The most important step that can vastly affect the performance of the cutter is the amount of cobalt left in between the diamond grains.
Cobalt when heated expands at a rate 13 times greater than diamond.

As a cutter begins to heat up while drilling the cobalt will expand, pushing and pressing between each diamond grain.

If the pressure becomes too great the diamond-to-diamond bonds will be severed leading to rapid wear and failure of the cutter.

One technique to increase cutter life and durability is to remove the cobalt from the diamond itself. Since the cobalt successfully completed its job during the manufacturing process its no longer needed when drilling takes place.

The cobalt is removed through a leaching process where it is placed in an acid bath. The vulnerable substrate is carefully protected with an acid resistant paint to stop rapid corrosion of the metal beneath the diamond.

The cutter can sit in an acid bath up to 4 weeks before being removed. The amount of time the cutter sits in the acid is dependent on how much or how deep into the diamond table the cobalt is to be removed.

In most cases the cobalt is removed 600 to 900 microns down. You can think of leaching as aging a fine wine. All good things take time.

Leached PDC Cutter Cross Section

After leaching, the PDC cutter is inspected for defects. Some PDC cutters are cut in half and viewed under scanning electron microscopes in order to ensure that the leach depths are correct.

Once the cutters pass inspection they are shipped to the drill bit supplier and are brazed into a PDC bit.

Call us at: +1 403 536 2770,
Email us at: sales@trendon.ca,
to save time and money on your project.

Trendon Bit Service
Performance. Durability. Control.

What is Depth of Cut?

What is Depth of cut and how do you calculate it?

Depth of Cut (DOC) is one of many important factors to consider in Polycrystaline Diamond Compact (PDC) drill bit design.

The depth at which the cutter penetrates the formation is Depth of Cut (DOC), as the image below describes.

Depth of Cut Cutter View
Coupled to the rotation of the PDC drill bit, Depth of Cut (DOC) is usually measured in millimeters and is .

It is more versatile and easier to back calculate from historical or live outputs at the rig site if we use the units DOC/revolution or mm/REV.

DOC/REV is related to the Rate of Penetration (ROP) of the PDC drill bit, usually measured in meters per hour.

Depth of Cut Equation

DOC/mm can be easily calculated using the following formula:

Depth of Cut Equation

*For all you engineers, drilling superintendents and directional hands out there keep this formula handy.

The Depth of Cut (DOC) formula is a generalization of how fast the PDC drill bit penetrates the formation in one revolution.

The bit is made up of multiple PDC cutters that are coupled to the blades.

The PDC drill bit cutters are the elements responsible for removing the formation and thus generating Rate of Penetration (ROP).

This Rate of Penetration (ROP) per revolution can be translated to the cutters via DOC/mm.

PDC Drill Bit Wear Grooves

If a PDC Drill Bit  is designed without considering its target ROP and revolutions per minute (RPM) serious performance limitations can be inadvertently placed on the bit.

If the DOC is too high the PDC blades may end up riding on the formation,

which hinders performance and wears the blades down.

PDC Drill Bit Depth of Cut

PDC Cutter Exposure

Once blade contact has been established the PDC drill bit simply cannot drill any faster without further damaging the blade.

One method to maximize DOC is to increase the cutters’ exposure from the supporting blade material.

An example of a PDC drill bit with a high and low exposure are depicted below.

PDC Drill bit Cutter Exposure

PDC drill bit Cutters that are largely exposed will have the ability to drill faster however there is a downside.

The PDC dill bit cutters have less surface area and pocket to be brazed to.

The mechanical lock between the cutter and pocket is largely reduced.

The PDC drill bit cutters will be more susceptible to complete pull out from the pocket during an impact event.

A lost PDC drill bit cutter will certainly mean reduced performance from the bit.

If the bit continues to drill for much longer, a severely damaged bit that cannot be repaired is a near certainty.

It is important that PDC drill bit cutter exposure is determined for optimum DOC and ROP while also considering cutter retention by not carelessly over exposing them.

As a rule of thumb most PDC drill bit cutters are not exposed more than half of their diameter, although this may not always be the case.

For instance a 16 mm cutter will not have an exposure of more than 8 mm.

An example whether or not a PDC drill bit with a cutter exposure of 6 mm will have blade contact is as follows.
Instantaneous ROP of the bit: 120 m/hr
Downhole RPM of the PDC: 200 RPM

PDC Drill Bits Canada - Depth of Cut

In this case since the cutter is exposed 6 mm from the blade and the depth of cut (DOC) is 10 mm there is a good possibility that the bit blades will rub on the formation.

Note:

Most PDC bits are designed such that each cutter is in a unique position along the profile of the bit.

In other words, most PDC drill bits do not have plurality in their cutter positions.

In the image below each cutter is located in a unique position along the bits profile also know as a single set design.

The depth of cut (DOC) formula can be used to generalize this bit.

If for instance a bit is designed where 2 cutters are in the same radial position or a plural set then this formula cannot be used.

However, if the plural cutters are 180 degrees away then dividing the depth of cut (DOC) formula by 2 will give you a more accurate generalization.

Single Set Cutter Layout

Depth of Cut Single Set Cutter Layout

Depth of Cut (DOC) is one of many important factors that must be considered when designing a PDC drill bit.

Selecting the cutter exposure correctly based on how the bit is expected to perform will ensure that blade contact will not impede high performance drilling that our customers expect.

Call us at: +1 403 536 2770,
Email us at: sales@trendon.ca,
to save time and money on your project.

Trendon Bit Service
Performance. Durability. Control.

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