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Horizontal & Multi-Fractured Wells Tony Martin Director, Offshore Stimulation Baker Hughes 30 April 2012 Royal School of Mines, Imperial College © 2012.

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Presentation on theme: "Horizontal & Multi-Fractured Wells Tony Martin Director, Offshore Stimulation Baker Hughes 30 April 2012 Royal School of Mines, Imperial College © 2012."— Presentation transcript:

1 Horizontal & Multi-Fractured Wells Tony Martin Director, Offshore Stimulation Baker Hughes 30 April 2012 Royal School of Mines, Imperial College © 2012 Baker Hughes Incorporated. All Rights Reserved.

2 Fracturing Basics © 2012 Baker Hughes Incorporated. All Rights Reserved. 2

3 What is Pressure? Pressure is Stored Energy (per unit volume) Pressure © 2012 Baker Hughes Incorporated. All Rights Reserved. 3

4 Basic Concept Pressure, Rate, Proppant Concentration Time BHTP STP Rate Prop Conc © 2012 Baker Hughes Incorporated. All Rights Reserved. 4 BHTP = Bottom Hole Treating Pressure STP = Surface Treating Pressure

5 Net Pressure given that p net = BHTP -  p nwf - p closure Net Pressure © 2012 Baker Hughes Incorporated. All Rights Reserved. 5 BHTP = STP + HH -  p f BHTP = Bottom Hole Treating Pressure  p nwf = pressure loss due to near wellbore friction p closure = closure pressure STP = Surface Treating Pressure HH = Hydrostatic Head  p f = pressure loss due to friction in the wellbore

6 Basic Fracture Characteristics Height, h f Length, x f Width, w © 2012 Baker Hughes Incorporated. All Rights Reserved. 6

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 © 2012 Baker Hughes Incorporated. All Rights Reserved. 7

8 Permeability Drives Everything High k Medium kLow k In high permeability formations, fractures are designed to be short and highly conductive © 2012 Baker Hughes Incorporated. All Rights Reserved. 8

9 Permeability Drives Everything Very Low k In low permeability formations, fractures are designed to maximise reservoir contact Ultra Low k © 2012 Baker Hughes Incorporated. All Rights Reserved. 9

10 Permeability Drives Everything Example inflow areas:- –100 m, OH vertical well, 8.5” diameter = 67.8 m 2 –3000 m, OH horizontal well, 6” diameter = 1,436 m 2 –Single 50 m radial hydraulic fracture = 15,708 m 2 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) © 2012 Baker Hughes Incorporated. All Rights Reserved. 10

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 © 2012 Baker Hughes Incorporated. All Rights Reserved. 11

12 The Importance of Fracture Conductivity © 2012 Baker Hughes Incorporated. All Rights Reserved. 12

13 Fracture Conductivity, C f 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 © 2012 Baker Hughes Incorporated. All Rights Reserved. 13

14 Fracture Conductivity, C f C f = w ave k p Where w ave = average propped width k p = proppant permeability Remember that k p is Not Constant Proppant Fracturing:- © 2012 Baker Hughes Incorporated. All Rights Reserved. 14

15 Dimensionless Fracture Conductivity, C fD Also called Relative Fracture Conductivity –Previously known as F CD C fD 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 C fD must be Obtained © 2012 Baker Hughes Incorporated. All Rights Reserved. 15

16 Dimensionless Fracture Conductivity, C fD C fD = = CfCf xf kxf k w ave k p xf kxf k Where x f = fracture half length k = formation permeability © 2012 Baker Hughes Incorporated. All Rights Reserved. 16

17 Dimensionless Fracture Conductivity, C fD The Ability of the Formation to Deliver Fluid/Gas to the Fracture The Ability of the Fracture to Deliver Fluid/Gas to the Wellbore C fD = In Order to Achieve the Maximum Possible Production Increase, the Optimum Balance Between Fracture and Formation Deliverability Must be Found © 2012 Baker Hughes Incorporated. All Rights Reserved. 17

18 Fracturing Horizontal Wellbores © 2012 Baker Hughes Incorporated. All Rights Reserved. 18

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 © 2012 Baker Hughes Incorporated. All Rights Reserved. 19

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 © 2012 Baker Hughes Incorporated. All Rights Reserved. 20

21 Uncontrolled Wellbore Azimuth Wellbore Azimuth Parallel To Fracture Azimuth S-Shaped Wellbore Vertical, Deviated or Horizontal? Deviated Wells (continued) © 2012 Baker Hughes Incorporated. All Rights Reserved. 21

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 © 2012 Baker Hughes Incorporated. All Rights Reserved. 22

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 © 2012 Baker Hughes Incorporated. All Rights Reserved. 23

24 Horizontal Wellbores  h,max  h,min Transverse Fracs  h,max  h,min Longitudinal Fracs © 2012 Baker Hughes Incorporated. All Rights Reserved. 24

25 Longitudinal or Transverse? Longitudinal –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 © 2012 Baker Hughes Incorporated. All Rights Reserved. 25

26 Longitudinal Fractures Approximately Equivalent Post-Frac Behaviour when A ≈ B A B © 2012 Baker Hughes Incorporated. All Rights Reserved. 26

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 © 2012 Baker Hughes Incorporated. All Rights Reserved. 27

28 Longitudinal Fractures Unified Frac Design*: –Proppant number, N p N p = 2 k f w ave rek√rek√ xekxek = radial drainage square drainage area = x e 2 * Economides et al, 2001 © 2012 Baker Hughes Incorporated. All Rights Reserved. 28

29 Longitudinal Fractures Unified Frac Design: –Optimum dimensionless fracture conductivity, C fD,opt C fD,opt = 1.6 C fD,opt = N p C fD,opt = e ln N p ln N p For N p < 0.1 For 0.1 < N p < 10 For N p > 10 © 2012 Baker Hughes Incorporated. All Rights Reserved. 29

30 Longitudinal Fractures Unified Frac Design: –Optimum length, x f,opt, and width, w opt Adjust N p for Dietz* shape factor (C A ): = C fD,opt w opt x f,opt k kfkf N p,e = N p CACA * Dietz, 1965 © 2012 Baker Hughes Incorporated. All Rights Reserved. 30

31 Longitudinal Fractures Calculate maximum dimensionless productivity index, J D,max : J D,max = J D,max = - e – 0.311N p,e – 0.089N p,e N p,e N p,e 2 For N p,e ≤ 0.1 For N p,e > – 0.5 ln N p,e 6  Economides & Martin, 2007 © 2012 Baker Hughes Incorporated. All Rights Reserved. 31

32 Transverse Fractures Angle of Fracture from Wellbore Most Wellbores, Drilled Without Knowledge of (or Planning for) Fracture Azimuth, will Produce Transverse Fracs 15° LONGITUDINAL TRANSVERSE © 2012 Baker Hughes Incorporated. All Rights Reserved. 32

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 © 2012 Baker Hughes Incorporated. All Rights Reserved. 33

34 Transverse Fractures xexe yeye Drainage Area N p = I x 2 k f w ave x e x f k y e where I x = 2 xfxf xexe © 2012 Baker Hughes Incorporated. All Rights Reserved. 34

35 No of Fractures Productivity per Frac Transverse Fractures © 2012 Baker Hughes Incorporated. All Rights Reserved. 35

36 Transverse Fractures How Many Fractures? –Dependent upon x f, k, k f, x e, and w ave –Complex iterative process –Useful to fix a value of x f based on height growth Zone height, water or gas contacts Find N p and C fD,opt for fixed proppant volume Calculate J D per frac for optimum geometry Calculate total J D 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 x f © 2012 Baker Hughes Incorporated. All Rights Reserved. 36

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 © 2012 Baker Hughes Incorporated. All Rights Reserved. 37 J DTH = 1 (1/J DV ) + s c s c = ln -   h 2rw2rw kh kfwkfw Economides & Martin, 2007, 2010

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 k f,g = kfkf 1 + N Re Economides & Martin, 2007, 2010 © 2012 Baker Hughes Incorporated. All Rights Reserved. 38

39 Transverse Fractures Consider which type of completion is best for your gas well Economides & Martin, 2007, 2010 Permeability Range, md Best Technical Solution Comments > 5Horizontal Wellbore, Longitudinal Fractures In all cases 0.5 to 5Horizontal Wellbore, Longitudinal Fracture OR Vertical Well with Fracture Dependent upon relative costs of vertical and horizontal wells 0.1 to 0.5Horizontal Wellbore, Transverse Fractures Above 0.5 md, the choked connection means that transverse fractures are relatively inefficient < 0.1Horizontal Wellbore, Transverse Fractures OR Vertical Well with Fracture Dependent upon relative costs of vertical and horizontal wells © 2012 Baker Hughes Incorporated. All Rights Reserved. 39

40 Fracturing Multiple Intervals © 2012 Baker Hughes Incorporated. All Rights Reserved. 40

41 Completion Options Open 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 © 2012 Baker Hughes Incorporated. All Rights Reserved. 41

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 © 2012 Baker Hughes Incorporated. All Rights Reserved. 42

43 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 Open Hole Systems © 2012 Baker Hughes Incorporated. All Rights Reserved. 43

44 Applications –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 Open Hole Systems © 2012 Baker Hughes Incorporated. All Rights Reserved. 44

45 Disintegrating Frac Balls –New technology Open Hole Systems © 2012 Baker Hughes Incorporated. All Rights Reserved. 45

46 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 Cased Hole Systems © 2012 Baker Hughes Incorporated. All Rights Reserved. 46

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 © 2012 Baker Hughes Incorporated. All Rights Reserved. 47

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 © 2012 Baker Hughes Incorporated. All Rights Reserved. 48

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 © 2012 Baker Hughes Incorporated. All Rights Reserved. 49

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 © 2012 Baker Hughes Incorporated. All Rights Reserved. 50

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 © 2012 Baker Hughes Incorporated. All Rights Reserved. 51

52 Summary Transverse or Longitudinal? –Formation stresses –Wellbore azimuth –Gas? How many fracs? Cased or Open Hole? –Fluid recovery –Rig time –Operational flexibility Would a Vertical Well be Better? © 2012 Baker Hughes Incorporated. All Rights Reserved. 52

53 © 2012 Baker Hughes Incorporated. All Rights Reserved. 53 Horizontal & Multi-Fractured Wells Thank you. Any Questions?


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