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Rotary BHA

• The rotary BHA consists of a bit, drill collars, stabilizers, reamers, subs and other special tools run below the drill pipe
• Motors were used to put the wellbore on course and rotary BHA’s were used to drill the majority of the well
• Even though rotary assemblies are used only occasionally, we will still look at them
• Steerable motor assemblies in the rotating mode are still rotary BHA’s subject to the same influences as the rotary BHA
• A slick assembly is simply a bit and drill collars

 

• The deviation tendency is caused by the bending of the drill collars
• The point at which the collars touch the wall of the hole is the tangency point
• The resultant force applied to the formation is not in the direction of the hole axis but in the direction of the drill collar axis

• The resultant force can be broken up into its components FB and FP

 

• FB is the side force caused by the bending of the collars or building force
• FP is the force due to gravity or pendulum force
• Ideally, if

1.        FP > FB, the hole inclination will drop
2.        FP < FB, the hole inclination will increase
3.       FP = FB, the hole inclination will remain constant

• The building force can be increased by increasing bit weight, which drives the tangency point down
• The building force is also affected by the stiffness of the collars
• Stiffer collars will bend less
• As the diameter of the collar increases, the stiffness of the collar increases

• The pendulum force can be increased by reducing bit weight and using larger diameter collars
• ØSome inclination is required to have a pendulum force
• ØFor a slick assembly, the building and pendulum force will balance at relatively low inclinations; therefore, they are not expected to build much inclination

• So why does the inclination exceed 1 to 2o in some areas while it does not in other areas?
• If the bed dip is relatively flat, we seldom have any deviation problems
• When bed dip is encountered, we can experience deviation problems in harder rock

• Deviation problems are associated with formation dip
• The anisotropy of the formation causes deviation

 

• If the formation deviation tendency can be defined as a force FF, the resultant force at the bit would be
  -FB + FP + FF   
•  The wellbore will continue to build angle until the sum of the forces is equal to zero 
•  Unfortunately it is difficult to define FF and it changes with depth     

Rule of thumb

• If the bed dip is less than 45 degrees, the bit will have a tendency to deviate perpendicular to the bed dip (up dip)   
• If bed dip is above 65 degrees, the bit will have a tendency to deviate along the bed dip 
• Between 45 and 65 degrees, the bit can do either
• In directional drilling, it is the difference between the bit angle and the formation dip 
• The formation may want the bit to drop inclination when the wellbore is at an inclination greater than bed dip 
• The two forces associated with a rotary assembly are the building force (FB) and the dropping force (FP) 
• If we want to make a building assembly, the building force must be maximized 
  Stabilizers are used as fulcrums in order to increase the side force at the bit
   

Building assembly

A building assembly is constructed by placing a stabilizer near the bit
Bending of the drill collars above the stabilizer causes the building force at the bit to increase substantially

• At low inclinations, the drill collars are bent by increasing bit weight

• At higher inclinations, gravity will bend the collars and the build tendency is less affected by bit weight   
• In order to make a dropping assembly, the pendulum force is maximized by placing a stabilizer at least 30 to 90 feet above the bit

 

•     If the collars touch the wall of the hole between the stabilizer and the bit, the tangency point becomes the place where the collars first touch the wall of the hole
•     If the stabilizer is too far above the bit, the collars will touch the wall and the pendulum force will be reduced  

-A holding assembly is constructed by placing stabilizers closer together so that the collars are more rigid
-Bit side force is minimized

• Holding inclination is the most difficult with a rotary assembly

• Analysis by Amoco indicated that

1. -Assembly A proved to be the most successful even though it maintained inclination only 60 percent of the time
2. -Assembly B maintained inclination less than 50 percent of the time
3. -Assembly C held inclination less than 50% of the time 

To better understand the forces on a rotary BHA, lets look at a single stabilizer assembly with the stabilizer positioned at various distances from the bit

• Rotary BHA’s were not very efficient as it was difficult to predict the actual performance of any rotary BHA
• Frequent trips were required to change stabilizer placement and size

• The build, hold or drop tendency of the rotary BHA could be adjusted but the walk tendency could not be changed substantially

• A pure rotary assembly is used only occasionally today
• Derivatives of the rotary assembly are used frequently
• Steerable motor assembly 
• Rotary steerable assembly

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METHODS OF DEFLECTING A WELLBORE

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Jetting

Jetting was used as an alternative to whipstocks 

• Jetting was only effective in softer rocks since formations have to be eroded to change the trajectory of the wellbore 
• A bit with a larger diameter nozzle facing the side of the hole was used to erode the formation to one side of the bit                       

• The larger nozzle was oriented in the desired direction
• The formation was washed as the assembly was lowered into the hole 

•  If the rocks were too soft, the entire bottom of the hole may wash out without substantially altering the hole trajectory
• In harder formations, the bit often had to be turned slightly left and right to erode the side of the hole 
• Penetration rate while jetting, was very slow 
• Once a portion of the hole had been jetted and the bit worked to bottom, the assembly was rotated to continue drilling ahead   
• Jetting created a high dogleg severity in a short interval even though surveys may not indicate it   

• The jet deflection bit was actually the first steerable assembly 

1.   While jetting, the drill string was not rotated in order to effect a trajectory change (slide drilling) 
2.   After jetting, the drill string was rotated to drill ahead

 

METHODS OF DEFLECTING A WELLBORE

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METHODS OF DEFLECTING A WELLBORE

Any number of directional tools can be used to deflect a wellbore or make the wellbore go where we want it to go

Methods of Deflection

• Whipstocks
• Jetting
• Rotary BHA
•  Rotary BHA with adjustable stabilizer
• Motor
•       Steerable motor
• Rotary steerable assembly

• Over time, the tools we have used to deviate a wellbore in the desired direction have changed

• Newer and more efficient tools have been developed and will be developed in the future

Significant advances in directional drilling technology

 Whipstock

•      One of the earliest tools used in the industry was the whipstock
•  The whipstock is a metal wedge placed in the wellbore that causes the bit to deviate
•     In the early years of the petroleum industry, they were used to sidetrack wells if a portion of the drill string became stuck
•      As directional drilling started in the 1930’s, whipstocks were oriented and used to change the inclination and azimuth of the wellbore Whipstocks were not very efficient
•      In order to use a whipstock, the drill string was pulled from the hole and a whipstock was run into the well
•      On a retrievable whipstock, a pin was sheared and the bit drilled off the whipstock
•  

  Retrievable whipstock

•      Because the bit had to be run in with the whipstock, it was a smaller diameter than the hole
•      A second trip was made to open the hole to full gage 
•   In harder rock, a reaming trip may have been required
•   Using the whipstock required a minimum of three trips, which was not cost effective
•   Permanent whipstocks were no better even though a full sized bit could be used to drill off it
•      Today, whipstocks are used frequently to sidetrack out of casing
•      The majority of casing sidetracks are now performed with a whipstock 

 

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Directional drilling

Directional drilling is the art and science involving the intentional deflection of a wellbore in a specific direction in order to reach a predetermined objective below the surface of the earth

• At one time it was thought that all wells were vertical
• Methods to measure deviation were developed in the 1920’s (initially acid bottle)
• Directional drilling developed after 1929 when new survey instruments were available (inclination and direction)
• The first controlled directionally drilled well was drilled in the Huntington Beach Field in 1930 to tap offshore reserves from land locations
• Directional drilling became more widely accepted after a relief well was drilled near Conroe, Texas in 1934

• Today, directional drilling is an integral part of the petroleum industry
• It enables oil companies to produce reserves that would not be possible without directional drilling
• One of the primary uses of directional drilling was to sidetrack a well even if it was to go around a stuck BHA

 

• Sometimes multiple sidetracks are used to better understand geology or to place the wellbore in a more favorable portion of the reservoir
• Straight hole drilling is a special application of directional drilling

1. To keep from crossing lease lines
2. To stay within the specifications of a drilling contract
3. To stay within the well spacing requirements of a developed field

 

• Drilling multiple wells from a single structure or pad
• Most offshore development would not be possible without directional drilling
• Inaccessible surface location
• Drilling in towns, from land to offshore and under production facilities

• Drilling around salt domes
• Salt can cause significant drilling problems and directional drilling can be used to drill under the overhanging cap
• Steeply dipping sands can be drilled with a single wellbore
• Fault drilling
• In hard rock, deviation can be a problem
• Sometimes the bit can track a fault
• Drilling at a higher incident angle minimizes the potential for deflection of the bit
•  Relief well drilling
• Directional drilling into the blowout when the surface location is no longer accessible
• Very small target and takes specialized equipment
•  Horizontal drilling
• Increasing exposure of the reservoir to increase productivity
•  Multilateral drilling
• Drilling more than one wellbore from a single parent wellbore

•        Extended reach drilling wells are characterized by high inclinations and large departures in the horizontal plane

• Extended reach wells are wellbores where the horizontal departure is significantly higher than the true vertical depth of the well, which is the horizontal departure – TVD ratio (HD/TVD)
• Extended reach wells have been drilled with HD/TVD ratios greater the 6/1.
  BP drilled a well at Wytch Farm with a measured depth of 34,967’ (10,658 m), a TVD of 5,266’ (1,605 m) and horizontal departure of 33,181’ (10,114 m) 
  
  

  
  

  
  

  
  

  •    There are four basic hole patterns
  •      Not all wells conform to the basic hole patterns and may be a combination of patterns
  •     For simplicity, the basic hole patterns are defined as:
  • 
  • 

Liner

•What is a Liner?

–Any string of casing whose top is located below the surface.  Set by drill pipe,which is subsequently retrieved.

 

 

Any string of casing whose top is located below the surface, hung inside the previous casing and is run to its setting depth by drill pipe.

Why Liners ?

-Prime reason:

–Save $$

–(Cost of 1 Joint of Casing can be $3,000!)

-Cover Corroded/Damaged Casing

-Cover:

–Lost Circulation Zones.

–Shales or Plastic Formations

–Salt Zones

-Deep Wells:

Rig Unable to Lift Long String of Casing

Types of Liners

-Production:

–Most common

–Save $$

–Slotted liner

-Intermediate/drilling:

–Cover problem zone in order to be able to continue drilling

-Tie-back/liner complement:

–From top of existing liner to surface, or further up casing to cover corroded or damaged zone.

Tie-Back (Liner Complement)

Procedure for Setting Liner

-RIH with drillpipe

-At liner hanger depth, condition mud

–(Reciprocation / Rotation)

-Release slips (liner hanger)

–(Rotation - mechanical pressure - hydraulic)

-Set slips, release liner weight, check to see if running tool is free

-Pump mud - to ensure free circulation

-Cement / Displace / Bump plug / Bleed off

-Release setting tool

-POOH above TOC and circulate

–NOTE: A liner swivel can be run below the hanger to ensure that the tool can be rotated even if the liner is stuck or set.

  Job Procedure Liner

 

 

 

 

 

 

-Pressure test lines.

-Pump wash/spacer.

-Pump slurry.

-Drop "Pump Down" plug (or drill pipe wiper dart).

-Displace 

–To running tool 

–Shear "Wiper Plug”

–Displace to Float Collar

-Bump plug/check for returns.

-Release tool.

-Pull up to T.O.C. and circulate.

Liner Overlap 

-Cementing the liner “lap” is critical .

-Too much cement above the liner hanger is not recommended

-So make sure that “uncontaminated” cement is present at the liner lap - washes and spacers / WELLCLEAN II

-If not, there is communication from the annulus to the formation

 

 Recommendations for Liner Cementing

 

 

-Ensure rheology of cement system is adequate for 100% mud removal

-Turbulent flow, if possible

-Consider 5 - 10 min. “contact time” at liner lap

-Batch mix cement

-Minimize U-tubing effect

-Rotation of liner during cementing (special bearing in tool)

-Adequate mud conditioning prior to cementing

Example Calculation - Liner

-Well Information: 

–9-5/8" 47 lb/ft intermediate casing from surface to 6500 feet

–7" 29 lb/ft intermediate liner from 6200 ft to 10,500 feet

–6" open hole to TD at 14,500 feet

–Drill pipe 3-1/2" 13.30 lb/ft 

–4-1/2" 16.60 lb/ft liner required from 14,400 ft to 400 ft inside 7" liner.

–Float collar 80 feet above shoe.

-Cement required to top of liner with 20% excess in open hole

*Calculate:

–Slurry Volume and Displacement 

 

  Liner Example Calculations - Results

 

 

 

 

 Conclusion

 

 

 

-Liners have many applications

-The main feature is that normally you have small volumes of slurry and high pressures during the job.

-Liner overlap is the most critical part to cement correctly

-Even though most of the times we are not at charge of the hardware (liner hanger, cement head, etc.), we must have knowledge of what has been run in the hole, and the way it works.

-It is important to slow down the displacement to avoid excessive pressures (shear pins, end of displacement)

 

 

•Case history

•Critical water zones in a North African field required isolation with an intermediate casing 

 

cemented in two stages. This operation increased rig time, cost and potential trouble for this

 

casing operation. Because the stage tool created a potential future weakness in the 

 

intermediate casing string, the production casing had to be run to surface to cover the stage

 

tool and protect it from future production operations.

 

•The casing program was redesigned using LiteCRETE technology to replace the two-stage 

 

intermediate casing with a single-stage casing requiring only one cement slurry. This saved 

 

stage-tool-running time, associated rig costs and eliminated the risk associated with a stage 

 

tool. Instead of a full production string, a production liner was then run back into the 

 

intermediate casing, saving additional time and expense in well construction.

 

•LiteCRETE technology offers a well-construction solution with low permeability and low 

 

density. Superior-quality cement columns can be pumped higher in the annulus so 

 

multiple-stage cementing becomes unnecessary.