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

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

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

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

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 © 2012 Baker Hughes Incorporated. All Rights Reserved.

Basic Fracture Characteristics Length, xf Width, w Height, hf © 2012 Baker Hughes Incorporated. All Rights Reserved.

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.

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

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

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) © 2012 Baker Hughes Incorporated. All Rights Reserved.

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.

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

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 © 2012 Baker Hughes Incorporated. All Rights Reserved.

Fracture Conductivity, Cf Proppant Fracturing:- Cf = wave kp Where wave = average propped width kp = proppant permeability Remember that kp is Not Constant © 2012 Baker Hughes Incorporated. All Rights Reserved.

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 © 2012 Baker Hughes Incorporated. All Rights Reserved.

Dimensionless Fracture Conductivity, CfD wave kp CfD = = xf k xf k Where xf = fracture half length k = formation permeability © 2012 Baker Hughes Incorporated. All Rights Reserved.

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 © 2012 Baker Hughes Incorporated. All Rights Reserved.

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

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.

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.

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

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.

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.

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

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 © 2012 Baker Hughes Incorporated. All Rights Reserved.

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

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.

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 © 2012 Baker Hughes Incorporated. All Rights Reserved.

Longitudinal Fractures Unified Frac Design: Optimum dimensionless fracture conductivity, CfD,opt CfD,opt = 1.6 For Np < 0.1 -0.583 + 1.48 ln Np 1 + 0.142 ln Np CfD,opt = 1.6 + e For 0.1 < Np < 10 CfD,opt = Np For Np > 10 © 2012 Baker Hughes Incorporated. All Rights Reserved.

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 © 2012 Baker Hughes Incorporated. All Rights Reserved.

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 1 + 0.667Np,e + 0.015Np,e2 JD,max = - e For Np,e > 0.1 Economides & Martin, 2007 © 2012 Baker Hughes Incorporated. All Rights Reserved.

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 © 2012 Baker Hughes Incorporated. All Rights Reserved.

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.

Transverse Fractures ye xe kf wave xe xf Np = Ix2 where Ix = 2 xf k ye Drainage Area xf k ye xe © 2012 Baker Hughes Incorporated. All Rights Reserved.

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

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 © 2012 Baker Hughes Incorporated. All Rights Reserved.

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 © 2012 Baker Hughes Incorporated. All Rights Reserved.

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 © 2012 Baker Hughes Incorporated. All Rights Reserved.

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 © 2012 Baker Hughes Incorporated. All Rights Reserved.

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

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 © 2012 Baker Hughes Incorporated. All Rights Reserved.

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.

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 © 2012 Baker Hughes Incorporated. All Rights Reserved.

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 © 2012 Baker Hughes Incorporated. All Rights Reserved.

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

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 © 2012 Baker Hughes Incorporated. All Rights Reserved.

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.

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.

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.

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.

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.

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? © 2012 Baker Hughes Incorporated. All Rights Reserved.

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