Bit Technology- Cutting Structures - Tungsten Carbide Cutting Structures

Tungsten Carbide Cutting Structures


Since most of the basic design features of the mill tooth cuttings structures
have been incorporated into insert bits, the main variations occur in insert
shape (Figure 3-5).



Figure 3-5: Tungsten Carbide Tooth Shapes
Historical shapes of milled teeth have built up a mystique about insert tooth
shape. Many people in the oil field thought that chisel shaped teeth
significantly affected the drill rate in all formations. This was because early
drilling practices used light bit weights, causing the relatively sharp chisel
shaped inserts to have a higher unit loading on the formation, hence faster
drill rates. When heavier bit weights are used, it tends to nullify the
advantage of the chisel shape. Even the steel milled teeth break down under
heavy weights. In fact, most bits drill 75% of the hole in a 1/2 to 3/4 dull
condition. With this in mind, many “blunt” insert tooth designs were made,
and seem to drill efficiently. Nowadays, most insert teeth have this blunt,
conical shape.

Bit Technology- Circulation Systems

Circulation Systems


The first hydraulic features incorporated into drilling tools dated back to
the original use of hollow drillpipe with direct circulation of drilling fluids.
As the first fishtail bits became popular, around the turn of the century,
circulation though water courses was used for the first time. The first
rolling cutter rock bits of 1909 introduced a central water course system
which directed fluid discharge towards the cutters.
In 1942, rock bits with jet nozzles were introduced to the oil industry. The
“jet bit” concept is considered to be the major hydraulic design
improvement in drill bits and remains state-of-the-art.
Further improvements in the circulation systems include extended nozzle
bits, seven to twelve nozzles in PDC bits, and the various water courses in
diamond bits.

Swab And Surge Pressures

Swab And Surge Pressures

Both swab and surge pressures are caused by moving the drillstring axially, and can be calculated using a method similar for calculating annular pressure losses. The greatest difficulty is determining the fluid flow velocity in the annulus when the pipe is opened-ended, because the
distribution of flow between the drillstring and annulus cannot be determined by a simple method.
Two approaches have been proposed.

The first assumes that fluid levels in the annulus and drillstring remain equal at all times. Annular fluid velocity then becomes:


where: Va = Average velocity (ft/min)
Vp = Drillstring velocity (ft/min)
D = Borehole Diameter (inches)
d = Drillstring Outside Diameter (inches)
di = Drillstring Inside Diameter (inches)

The minus sign is in the equation because the drillstring velocity is in the opposite direction to the fluid velocity.

This average velocity equation remains valid even when hole geometry changes. This method is easy to apply and is in widespread use in the oilfield. Its basic premise, that fluid levels in the drillstring and annulus
remain equal, is rarely justified. Because of the greater restrictions to flow, caused by the bit nozzles and pipe bore, actual flow in the annulus will nearly always exceed that calculated by this method. Calculated swab and surge pressures are therefore usually too low.


An alternative procedure considers the drillstring and the annulus as a “UTube”, as shown in the following figure.
 It is clear that the sum of hydrostatic and frictional pressures in the pipe bore and through the bit should equal the sum of hydrostatic and frictional pressures in the annulus. Both sums represent the pressure prevailing immediately below the bit.
There is only one flow distribution that will fulfill this criterion, and it can
be found by trial and error through the use of the pressure loss equations.

Figure 1-3: Equal Level Displacement

When tripping out of the hole, it may be assumed that both drillstring and annulus are kept full of fluid. The required distribution of flow is that which gives equal frictional losses in the pipe bore and annulus. When tripping into the hole, the fluid level inside the drillstring can drop well below that in the annulus, if small bit nozzles are present. This effect is usually seen as a pit volume being higher than expected, string weight lower than expected, and a considerable volume being pumped before standpipe pressure builds up while breaking circulation.

When the fluid level in the drillstring is below that of the annulus, a greater hydrostatic pressure will exist in the annulus, and fluid will tend to flow from the annulus up the drillstring. In this case, calculating flow distribution by equating frictional losses gives a calculated annular flow and surge pressure slightly higher than actually exists. Because this error is small and conservative, and because at present there is no reliable way of measuring the fluid level within the pipe, the practice of calculating flow distribution by equating internal and external pressure losses is generally accepted.

If the pipe is closed, or contains a float sub, it is easy to calculate flow in the annulus, because all of the fluid displaced by the drillstring passes up the annulus.

Calculating the pressure drop in the annulus is complicated by the motion of the inner wall of the drillstring. This motion is in the opposite direction to the displaced fluid, so the pressure drop will be greater than that for the same flowrate in a stationary annulus . Equations describing the system can be formulated, but solutions are usually too complicated for wellsite use.
Figure
 

Bit Hydraulics And Optimization - Diamond Bit Flow Patterns

Diamond Bit Flow Patterns

There are two main flow patterns in diamond bits:

1. Cross Pad Flow System (feeder/collector system)

a) the fluid travels along the high pressure “primary fluid courses” (those which connect to the crowfoot), to a point where “low pressure collectors” draw the fluid across the diamond pad

b) this ensures that the diamonds towards the outside diameter are cleaned and cooled

c) The HSI should be between 1.5 and 2.5.

2. Radial Flow System

a) provides a “high pressure primary fluid course” for each diamond row

b) permits fluid to travel in front of, and behind each diamond pad to facilitate cuttings removal and cooling

c) maintains uniform horizontal fluid velocity by tapering fluid course depth as they approach the outside diameter

d) The HSI should be between 2.0 to 3.0.

Bit Hydraulics And Optimization - Diamond Bit Hydraulics

Diamond Bit Hydraulics

The horizontal fluid velocity is the key element in diamond bit life and bit performance. It can be determined using:

The fluid courses assist this by directing the drilling fluid across the bit to cool the diamonds and to remove the cuttings.

 The diamond bit “Total Flow Area” consists of two components:

1. Fluid Course Area - is the area of all fluid courses on the bit. They are cast into the bit body.

2. Diamond Exposure Area - is the area between the bit face and formation, produced by the diamond exposure.

The desired TFA is calculated and designed into the bit by varying the diamond exposure, and the width and depth of the fluid courses. Another phenomenon which occurs with natural diamond bits is called hydraulic pump-off. The hydrodynamic pressure of the mud at the bit acts over the bit face area (between the cutting face of the bit and the formation) and tends to lift the bit off the bottom of the hole. For example, the pumpoff force on a 8-1/2 inch radial flow diamond bit (having a pressure drop of 900 psi) would be approximately 8600 pounds. It will require at least this much bit weight to keep the face of the bit in contact with the bottom of the hole.

Bit Hydraulics And Optimization - PDC Bit Hydraulics

PDC Bit Hydraulics

Since PDC bits are formation specific (best used in plastic formations), the formation characteristics will determine the hydraulic energy required. The drilling fluid will dictate the HSI, for water-based drilling fluids it will be between 2.5 and 4.5, while for oil-based drilling fluids it will be between 1.5 and 3.0.

The HSI, calculated at the jet nozzle orifices, will have several characteristics which will directly affect hydraulic energy:

1. the fluid velocity decreases rapidly once it leaves the nozzles
2. high vertical velocity and low horizontal velocities are achieved across the bit face
3. for higher volumes of fluid pumped, horizontal velocities will increase, but not necessarily HSI

The increased horizontal velocities provide better cuttings removal, better cooling, and possibly better drill rates.

Nozzle velocity is calculated in the same manner as with rollercone bits.

Bit Hydraulics And Optimization-Fixed Cutter Bit Hydraulics

Fixed Cutter Bit Hydraulics
The hydraulics for fixed cutter bits is based on the drilling fluids ability to remove cuttings beneath the cutters and to cool the bit. Fluid volume is critical to PDC bit performance. Fluid volume and fluid velocity is critical to diamond bit performance.

The major components of fixed cutter bit hydraulics are:

1. flow rate - Q (gal/min) and V (ft/min)
2. drilling fluid characteristics - MD (lb/gal), YP (lbs/100ft2) and PV (cps)
3. pressure loss - across the bit face (diamond bit) or through the jet nozzles (PDC bit)
4. the Total Flow Area (TFA) - instead of nozzle sizes

A very important parameter in fixed cutter bits is “Hydraulic Power Per Square Inch” or HSI. It is calculated using Hhp (hydraulic horsepower):

where: Hhp = Hydraulic Horsepower
A = Bit Area (square inches)*
* If the area of the bit is not given, it can be calculated using:

where: d = bit diameter (inches)
The hydraulic horsepower equation is the same (Pb x Q/1714), however in fixed cutter bits, resistance to fluid flow is created by the diamonds, nozzles, flow area restrictions, cuttings and the uneven hole pattern. Pressure losses at the bit are calculated using:

Bit Hydraulics And Optimization - Hydraulic Impact Force

Hydraulic Impact Force
Hydraulic (Jet) Impact Force is based on the theory that cuttings are best removed from beneath the bit when the force of the fluid leaving the jet nozzles and striking the bottom of the hole is the greatest. Impact Force is determined by:




where: MD = Mud Density (lb/gal)
Q = Flow Rate (gal/min)
Vn = Nozzle Velocity (ft/sec)
As can be seen, Impact Force depends on maximizing flow rate and nozzle velocity rather than pressure. Therefore, higher flow rates are required. The emphasis is on a large volume of fluid impacting with moderate force, rather than a small volume impacting at a high pressure.
This condition is optimized when circulating rates and bit nozzle sizes are chosen which will cause 48% of the pump pressure to be used to force fluid through the jet nozzles.

Bit Hydraulics And Optimization - Hydraulic Horsepower

Hydraulic Horsepower

Hydraulic horsepower is based on the theory that cuttings are best removed from beneath the bit by delivering the most power to the bottom of the hole. 

The amount of pressure lost at the bit, or bit pressure drop, is essential in determining the hydraulic horsepower. Bit pressure drop is determined by:

where: MD = Mud Density (lb/gal)

Vn = Nozzle Velocity (ft/sec)

From the bit pressure loss, hydraulic horsepower can be calculated:

To optimize Bottom Hole Cleaning and Bit Hydraulic Horsepower, it is necessary to select a circulation rate and nozzle sizes which will cause 65% of the pump pressure to be expended forcing the fluid through the jet nozzles of the bit.   

Bit Hydraulics And Optimization - Bottom Hole Horsepower

Bottom Hole Horsepower

Determination of the amount of Bottom Hole Cleaning necessary to maximize the drill rate is based upon:

1. Hydraulic (Jet) Impact Force

2. Hydraulic Horsepower

Maximizing Hpb involves minimizing Hpc, or in other words, the lowest flow rate and the highest pump pressure will result in the highest Hpb. However, the “lowest flow rate” will usually result in inadequate bottom hole cleaning. To compensate for this, bottom hole pressure can be increased by using smaller jet nozzles.

Bit Hydraulics And Optimization - Surface Horsepower

Bit Hydraulics And Optimization- Surface Horsepower

In order to maximize a hydraulics program, all aspects concerning drilling fluids and the associated equipment must be considered. The first component in any hydraulic design is the surface equipment and the hydraulic horsepower available from them. There are two limiting factors on the surface hydraulic horsepower.

The first is the flow rate range. As discussed earlier, the flow pattern in the annulus should be laminar, therefore the upper limit for the flow rate is a Reynolds Number of 2000. The highest velocity in the annulus will be around the collars, and this velocity can be determined by calculating the “critical velocity” over that section. In addition, running the pumps at that upper range is not always advisable because there will be more wear and tear on the pumps and much more fuel consumption.

The lower limit is a range where there is sufficient hole cleaning. This is determined by using the velocity around the drillpipe and the largest annular section (normally the upper hole section or drillpipe/riser section). 

A normal range is around 50 ft/min.

The second factor is the operating pressure of the mud pumps. Most mud pumps can produce the required pressure with little problem. However, because of the various components associated with the surface system (standpipe, rotary hose, pulsation dampener, etc.) the maximum surface pressure is usually limited to some value less than the maximum rated pump pressure.

The available “surface horsepower” is then determined by:

where: Hps = Surface Horsepower

P = Pump Pressure (psi)

Q = Pump Flow Rate (gal/min)

Once the surface horsepower has been determined, the horsepower distributions can be made:

where: Hpc = Circulation Horsepower

Hpb = Bit Horsepower

Bit Hydraulics And Optimization- Jet Nozzles

Bit Hydraulics And Optimization
Jet Nozzles

Jet Nozzles were introduced into the oilfield in 1948. These were necessary to increase bottom hole cleaning in deep wells. Prior to jet nozzles, the fluid course in bits was a hole bored into the center of the bit and the drilling fluid went from the drillstring directly into the annulus.
These “conventional water courses” did not have the power necessary to lift the cuttings and assist in the drilling process.

Both roller cone bits and PDC bits have recesses to install different size jet nozzles in order to obtain proper hydraulics. Most roller cone bits use three or four jet nozzles, while PDC bits usually contain six to nine. The flow area of all jets must be determined separately, then added together. For example, suppose four size 9 jets were being used:



There are four jets so the total flow area is 0.0621 x 4 or 0.2486 in2. Jet nozzles increase the speed of the drilling leaving the bit to around 225 ft/sec, and on many occasions the velocity is much greater. Because nozzle velocity is so important in hydraulic optimization, it should be calculated when the jets are installed in a bit. The formula is:



As mentioned in the previous section, the rate of penetration can be improved if the cuttings are removed from beneath the bit. In soft formations, the hole is generated by the jetting action of the drilling fluid, and the drill rate is limited by connection time, undesirable deviations, and the loading of the annulus with cuttings. In hard formations, the drill rate should be proportional to the weight-on-bit, if hole cleaning is adequate.

Dual string completion brief explanation.

Huge waves crash against a swaying oil rig

Directional drilling

Directional drilling (or slant drilling) is the practice of drilling non-vertical wells. It can be broken down into three main groups: oilfielddirectional drilling, utility installation directional drilling (horizontal directional drilling), directional boring, and surface in seam (SIS), which horizontally intersects a vertical well target to extract coal bed methane.

deep water horizon's blowout preventer

deep water horizon's blowout preventer

During the Deepwater Horizon drilling rig explosion incident on April 20, 2010, the blowout preventer should have been activated automatically, cutting the drillstring and sealing the well to preclude a blowout and subsequent oil spill in the Gulf of Mexico, but it failed to fully engage. Underwater robots (ROVs) later were used to manually trigger the blind shear ram preventer, to no avail.

As of May 2010 it was unknown why the blowout preventer failed. Chief surveyor John David Forsyth of the American Bureau of Shipping testified in hearings before the Joint Investigation of the Minerals Management Service and the U.S. Coast Guard investigating the causes of the explosion that his agency last inspected the rig's blowout preventer in 2005. BP representatives suggested that the preventer could have suffered a hydraulic leak. Gamma-ray imaging of the preventer conducted on May 12 and May 13, 2010 showed that the preventer's internal valves were partially closed and were restricting the flow of oil. Whether the valves closed automatically during the explosion or were shut manually by remotely operated vehicle work is unknown. A statement released by Congressman Bart Stupak revealed that, among other issues, the emergency disconnect system (EDS) did not function as intended and may have malfunctioned due to the explosion on the Deepwater Horizon.[9]

The permit for the Macondo Prospect by the Minerals Management Service in 2009 did not require redundant acoustic control means. Inasmuch as the BOPs could not be closed successfully by underwater manipulation (ROV Intervention), pending results of a complete investigation, it is uncertain whether this omission was a factor in the blowout.

Documents discussed during congressional hearings June 17, 2010, suggested that a battery in the device's control pod was flat and that the rig's owner, Transocean, may have "modified" Cameron's equipment for the Macondo site (including incorrectly routing hydraulic pressure to a stack test valve instead of a pipe ram BOP) which increased the risk of BOP failure, in spite of warnings from their contractor to that effect. Another hypothesis was that a junction in the drilling pipe may have been positioned in the BOP stack in such way that its shear rams had an insurmountable thickness of material to cut through.

It was later discovered that a second piece of tubing got into the BOP stack at some point during the Macondo incident, potentially explaining the failure of the BOP shearing mechanism. As of July 2010 it was unknown whether the tubing might have been casing that shot up through the well or perhaps broken drill pipe that dropped into the well. The DNV final report indicated that the second tube was the segment of the drill string that was ejected after being cut by the blow out preventer shears.

On July 10, 2010 BP began operations to install a sealing cap, also known as a capping stack, atop the failed blowout preventer stack. Based on BP's video feeds of the operation the sealing cap assembly, called Top Hat 10, included a stack of three blind shear ram BOPs manufactured by Hydril (a GE Oil & Gas company), one of Cameron's chief competitors. By July 15 the 3 ram capping stack had sealed the Macondo well, if only temporarily, for the first time in 87 days.

The U.S. government wanted the failed blowout preventer to be replaced in case of any pressure change that occurs when the relief well intersected with the well. On September 3 at 1:20 p.m. CDT the 300 ton failed blowout preventer was removed from the well and began being slowly lifted to the surface. Later that day a replacement blowout preventer was placed on the well. On September 4 at 6:54 p.m. CDT the failed blowout preventer reached the surface of the water and at 9:16 p.m. CDT it was placed in a special container on board the vessel Helix Q4000. The failed blowout preventer was taken to a NASA facility in Louisiana for examination by Det Norske Veritas (DNV).

On 20 March 2011, DNV presented their report to the US Department of Energy. Their primary conclusion was that while the rams succeeded in partly shearing through the drill pipe they failed to seal the bore because the drill pipe had buckled out of the intended line of action of the rams (because the drill string was caught at a tool joint in the upper annular BOP valve), jamming the shears and leaving the drill string shear actuator unable to deliver enough force to complete its stroke and fold the cut pipe over and seal the well. They did not suggest any failure of actuation as would be caused by faulty batteries. The upper section of the blow out preventer failed to separate as designed due to numerous oil leaks compromising hydraulic actuator operation, and this had to be cut free during recovery.

view of oil field rig

Crude Oil Distillation Process Part 2

Crude Oil Distillation Process Part 1