1. Horizontal & Multi-Fractured Wells
Tony Martin
Director, Offshore Stimulation
Baker Hughes
Royal School of Mines, Imperial College
30 April 2012
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2. Fracturing Basics
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3. Pressure is Stored Energy
What is Pressure?
Pressure is Stored Energy
(per unit volume)
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4. Basic Concept Pressure, Rate, Proppant Concentration Time BHTP STP
Prop Conc
Time
BHTP = Bottom Hole Treating Pressure
STP = Surface Treating Pressure
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5. pnet = BHTP - Dpnwf - pclosure
Net Pressure
Net Pressure
given that
pnet = BHTP - Dpnwf - pclosure
BHTP = STP + HH - Dpf
BHTP = Bottom Hole Treating Pressure
Dpnwf = pressure loss due to near wellbore friction
pclosure = closure pressure
STP = Surface Treating Pressure
HH = Hydrostatic Head
Dpf = pressure loss due to friction in the wellbore
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6. Basic Fracture Characteristics
Length, xf
Width, w
Height, hf
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7. What Does Fracturing Do?
High Permeability Formations
Conductive path through skin damage
Re-stressing of weak formations
Reduction in turbulence in gas formations
Increased effective wellbore radius
Low Permeability Formations
Increased inflow area/reservoir contact
Change from radial flow to linear flow within reservoir
Massive reduction in drawdown
Increased drainage
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8. Permeability Drives Everything
High k
Medium k
Low k
In high permeability formations, fractures are designed to be short and highly conductive
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9. Permeability Drives Everything
Very Low k
Ultra Low k
In low permeability formations, fractures are designed to maximise reservoir contact
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10. Permeability Drives Everything
Example inflow areas:-
100 m, OH vertical well, 8.5” diameter = 67.8 m2
3000 m, OH horizontal well, 6” diameter = 1,436 m2
Single 50 m radial hydraulic fracture = 15,708 m2
For ultra low permeability formations (e.g. shale gas) planar fractures do not provide sufficient inflow area
Hydraulic fractures designed to exploit natural fracture networks
Stimulated reservoir volume (SRV)
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11. Permeability Drives Everything
As permeability decreases, fracture conductivity becomes less important and inflow area becomes more important
In the permeability drops by a factor of 10, then the inflow area has to increase by a factor of 10, for the same production rate
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12. The Importance of Fracture Conductivity
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13. Fracture Conductivity, Cf
Fracture Conductivity is a Measure of How Conductive the Fracture is
It is Analogous to the kh Derived by Well Testing
Fracture Conductivity Defines How Much can be Produced by the Fracture
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14. Fracture Conductivity, Cf
Proppant Fracturing:-
Cf = wave kp
Where wave = average propped width
kp = proppant permeability
Remember that kp is Not Constant
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15. Dimensionless Fracture Conductivity, CfD
Also called Relative Fracture Conductivity
Previously known as FCD
CfD is a Measure of How Conductive A Fracture is Compared to the Formation
In Order to get the Maximum Possible Production Increase, the Optimum Value for CfD must be Obtained
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16. Dimensionless Fracture Conductivity, CfD
wave kp
CfD = =
xf k
xf k
Where xf = fracture half length
k = formation permeability
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17. Dimensionless Fracture Conductivity, CfD
The Ability of the Fracture to
Deliver Fluid/Gas to the Wellbore
CfD =
The Ability of the Formation to
Deliver Fluid/Gas to the Fracture
In Order to Achieve the Maximum Possible
Production Increase, the Optimum Balance
Between Fracture and Formation Deliverability
Must be Found
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18. Fracturing Horizontal Wellbores
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19. Vertical, Deviated or Horizontal?
Vertical Wells
Cheap to Drill
Easiest to Fracture
Requires lots of wellbores and lots of locations
Deviated Wells
Significant Fracturing Problems
Increased Costs
Reduced number of locations
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20. Vertical, Deviated or Horizontal?
Deviated Wells (continued)
Usually very complex connection between fracture and wellbore
Affects both treatment placement and production
Solution is to plan well correctly
Azimuth of deviated section parallel to maximum horizontal stress, or
Drill S-shaped wells to penetrate reservoir with vertical wellbore
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21. Vertical, Deviated or Horizontal?
Deviated Wells (continued)
Uncontrolled Wellbore
Azimuth
Wellbore Azimuth Parallel
To Fracture Azimuth
S-Shaped Wellbore
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22. Cased and Cemented or Open Hole?
Open Hole Fracturing
Easier Connection Between Fracture and Wellbore
Cost Savings
Liner, Cementing, Rig Time
Specialised Systems Required to Isolate Individual Sections to Control Fracture Initiation
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23. Cased and Cemented or Open Hole?
Cased Hole Fracturing
Increased Cost
Liner, Cementing, Rig Time
Requires Complex Completion Systems
Precise Control of Fracturing Process
Traditionally, Most Horizontal Wells that are Planned to be Fractured are Cased and Cemented
New Technology is Changing This
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24. Horizontal Wellbores sh,min sh,max sh,max sh,min Longitudinal Fracs
Transverse Fracs
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25. Longitudinal or Transverse?
Longitudinal fracs are easiest to pump and have the simplest connection to the wellbore
Post-fracture production is not “choked” at the contact between fracture and wellbore
Easiest to predict post-fracture production
Wellbore must be drilled within +/- 15 ° of maximum horizontal stress azimuth.
Anything else behaves like a transverse fracture
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26. Longitudinal Fractures
Approximately Equivalent
Post-Frac Behaviour when
A ≈ B B
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27. Longitudinal Fractures
Designing Longitudinal Fractures
Start with “equivalent” single fracture on vertical wellbore
Use Unified Frac Design to design geometry of single fracture
Place multiple fractures along horizontal wellbore
Sufficient number to provide complete coverage
Maintain UFD length to width ratio
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28. Longitudinal Fractures
Unified Frac Design*:
Proppant number, Np
2 kfwave
2 kfwave
Np = =
rek√p
xek
radial
drainage
square
drainage
area = xe2
* Economides et al, 2001
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29. Longitudinal Fractures
Unified Frac Design:
Optimum dimensionless fracture conductivity, CfD,opt
CfD,opt = 1.6
For Np < 0.1
ln Np
ln Np
CfD,opt = e
For 0.1 < Np < 10
CfD,opt = Np
For Np > 10
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30. Longitudinal Fractures
Unified Frac Design:
Optimum length, xf,opt, and width, wopt
Adjust Np for Dietz* shape factor (CA):
wopt k
= CfD,opt
xf,opt kf CA
Np,e = Np
30.88
* Dietz, 1965
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31. Longitudinal Fractures
Calculate maximum dimensionless productivity index, JD,max: 1
JD,max =
For Np,e ≤ 0.1
0.99 – 0.5 ln Np,e
0.423 – 0.311Np,e – 0.089Np,e2 6 p
Np,e Np,e2
JD,max = e
For Np,e > 0.1
Economides & Martin, 2007
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32. Transverse Fractures Angle of Fracture from Wellbore
15°
15°
LONGITUDINAL
LONGITUDINAL
15°
15°
TRANSVERSE
Most Wellbores, Drilled Without Knowledge of (or Planning
for) Fracture Azimuth, will Produce Transverse Fracs
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33. Transverse Fractures
Transverse fractures have a very poor connection to the wellbore.
This makes frac jobs hard to pump due to tortuosity
This chokes production and dramatically reduces fracture effectiveness
Open hole fractures have a much cleaner connection between the fracture and the wellbore than cased and perforated fractures
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34. Transverse Fractures ye xe kf wave xe xf Np = Ix2 where Ix = 2 xf k ye
Drainage Area
xf k ye xe
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35. Transverse Fractures Productivity per Frac No of Fractures
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36. Transverse Fractures How Many Fractures?
Dependent upon xf, k, kf, xe, and wave
Complex iterative process
Useful to fix a value of xf based on height growth
Zone height, water or gas contacts
Find Np and CfD,opt for fixed proppant volume
Calculate JD per frac for optimum geometry
Calculate total JD against number of fracs
NPV analysis to get optimum number of fracs
Repeat for different proppant volumes, to get plot of optimum NPV against proppant volume per frac, for various numbers of fracs
Repeat process for different values of xf
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37. Transverse Fractures Gas Wells – Important
Near well bore choking effect
Caused by the very limited area of contact between fracture and wellbore
Can seriously affect productivity in medium and high permeability gas wells kh
kfw h
2rw p 2
sc = ln 1
JDTH =
(1/JDV) + sc
Economides & Martin, 2007, 2010
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38. Transverse Fractures Gas Wells – Important
Turbulent flow effects are also significant
The combined effect of choking and turbulence can reduce the flow by 80 to 90% in high permeability gas formations kf
kf,g =
1 + NRe
Economides & Martin, 2007, 2010
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39. Transverse Fractures
Consider which type of completion is best for your gas well
Permeability Range, md
Best Technical Solution
Comments
> 5
Horizontal Wellbore, Longitudinal Fractures
In all cases
0.5 to 5
Horizontal Wellbore, Longitudinal Fracture OR
Vertical Well with Fracture
Dependent upon relative costs of vertical and horizontal wells
0.1 to 0.5
Horizontal Wellbore, Transverse Fractures
Above 0.5 md, the choked connection means that transverse fractures are relatively inefficient
< 0.1
Economides & Martin, 2007, 2010
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40. Fracturing Multiple Intervals
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41. Completion Options Open Hole Cased Hole
Sliding side doors separated by open hole packers
Cased Hole
Sliding side door systems
Liner-conveyed
Completion-conveyed
“Plug and Perf” systems
Various different systems available
Coiled tubing-based systems
Fracturing through CT
Annular
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42. Open Hole Systems
Multizone open hole completion systems use a series of sliding side doors, separated by open hole packers
SSDs are initially closed and are opened by a ball landing on a seat
Seats have progressively larger diameters moving upwards
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43. Open Hole Systems Up to 40 zones per completion
3 different types of packer available
Inflatable, swellable, squeeze
Typically run as a liner
Liner hanger set conventionally
First ball sets the packers and opens the lowest interval
Swellables have to be left 24 to 48 hours
Subsequent balls open successive intervals and close off the previous interval
All zones flowed back together after fracturing operations have finished
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44. Open Hole Systems Applications Advantages Disadvantages
Horizontal or vertical wellbores
Cased or open hole
Acid or proppant stimulation treatments
Advantages
One-trip installations
Reduction in completion time
Disadvantages
Control of fracture initiation
Fluid recovery
Lack of flexibility
Ball recovery
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45. Open Hole Systems Disintegrating Frac Balls New technology
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46. Cased Hole Systems
In general, cased hole systems offer greater flexibility and better control of fracture initiation
Most systems allow perforations to be designed zone by zone
The point of fracture initiation is tightly controlled
However, in general cased hole systems are more expensive and require significantly more rig time
In addition to the time and expense of cementing a horizontal liner in place
In spite of this, there are still more cased and cemented horizontal multizone wells being completed than open hole wells
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47. Cased Hole Systems Casing-Conveyed SSDs
SSD run on casing or liner and cemented into place
SSDs can be opened in several different ways
Coiled tubing, with a packer positioned below the SSD to provide isolation
Balls, similar to open hole systems
Darts or “frac bombs”
Fluid pressure is used to break cement behind SSD
Acid soluble cement systems are also used
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48. Cased Hole Systems Completion-conveyed SSDs
A series of SSDs separated by squeeze packers are RIH on a tubing string.
Liner is perforated prior to completion running
SSDs manipulated by coiled tubing between zones
Technically the best system for zonal isolation, controlling fracture initiation and post-treatment fluid recovery
Very heavy on rig time
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49. Cased Hole Systems “Plug and Perf” systems
Perforate, stimulate, isolate
Move from the bottom of the well to the top
Perforate the lowest interval
Perform the treatment
Recover the frac fluid, if desired
Isolate the interval
Wireline/CT conveyed plugs
Sand plugs
Repeat as often as required
Go back in with CT and remove isolation systems
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50. Cased Hole Systems Coiled Tubing Methods Fracturing through CT
All intervals perforated before frac operations
Straddle packer placed on the end of the CT
Treatments pumped down CT into perforations
Treating pressure “energises” packer elements
Circulating and reversing possible
Multiple zones treated consecutively using a single CT run
Much greater pressure can be placed on the CT than is normal
Static vs dynamic
Large diameter CT required
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51. Cased Hole Systems Coiled Tubing Methods Annular CT Fracturing
No pre-perforating
Perforations either cut using jetting tool or shot via selective perforating guns on the CT
Zonal isolation
Packer placed below jetting tool or perforation guns
Sand plugs pumped down the CT/completion annulus
Treatment is pumped down the CT/completion annulus.
CT string used to monitor BH pressure
Multiple zones treated consecutively using a single CT run
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52. Summary Transverse or Longitudinal? How many fracs?
Formation stresses
Wellbore azimuth
Gas?
How many fracs?
Cased or Open Hole?
Fluid recovery
Rig time
Operational flexibility
Would a Vertical Well be Better?
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53. Horizontal & Multi-Fractured Wells
Thank you.
Any Questions?
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