COPYRIGHT. Hydraulic Fracturing Core. Why This Module Is Important

Transcription

1 Hydraulic Fracturing Core Why This Module Is Important The oil and gas industry utilizes stimulations to improve the productivity of producing wells in both the conventional and unconventional realms If a well is understimulated, then it will not produce to its full potential Why This Module Is Important On the other hand, an over-stimulated well will result in spending more on the completion than is necessary and poorer economics Hydraulic fracturing is the method most commonly used to stimulate wells industrywide 1

2 Why This Module Is Important In order to optimize the stimulation, one must understand how the rock will perform under stress The rock properties of the reservoir rock are studied to determine how they will react to the stimulation fluids and pressures to which they will be exposed during a hydraulic fracture treatment This module will expose the participant to the relationship between rock properties and fracture behavior Why This Module Is Important The module also explains the four stages of a hydraulic fracture and the purpose of each stage There are numerous design criteria to consider when designing a fracture stimulation The various options for these criteria are discussed as well as the application of each 2

3 Why This Module Is Important Lastly, two additional stimulation methods are covered which are used more in conventional reservoirs: frac packs and acid fracturing Why This Module Is Important Frack packs are a combination of sand control and stimulation Lastly, two additional stimulation methods are covered which are used more in conventional reservoirs: frac packs and acid fracturing Frack packs are a combination of sand control and stimulation Acid fracs are normally used to stimulate tight carbonate rock 3

4 Why This Module Is Important It is important that the Petroleum Engineer understand the applications of the various stimulation methods at our disposal Furthermore, one must understand when to utilize a particular type, size, and concentration of proppant versus another, or why slickwater gels are pumped in some wells and linear or cross-linked gels in others This module will help one to understand the various choices in stimulation design and the applications of each option Crushed Proppant 4

5 Learning Objectives Hydraulic Fracturing Core Well Stimulation Methods By This the section end of will this cover lesson, the you following will be learning able to: objectives: Understand the differences between chemical and non-chemical stimulation methods Recognize the different applications of chemical stimulation and non-chemical stimulation methods Describe the more common non-chemical stimulation methods used in our industry 5

6 Why Do We Stimulate our Wells? Attempt to increase the productivity of the well to improve the economics Reasons for substandard performance: Formation damage Attempt to chemically dissolve the damage usually with acid Matrix Acid Treatments covered in another section Fracture past damage that we cannot chemically dissolve or remove (i.e. Water Blocks, Bacteria, etc.) Low permeability reservoir rock Requires fracturing to expose the well to more reservoir surface area and to create a highly conductive flow path back to the wellbore Well Stimulation Methods Different Stimulation Methods to Overcome Different Circumstances Chemical Methods of Stimulation Acid Can dissolve some damage and dissolves rock Solvents/Surfactants Dissolve paraffin and asphaltenes, break emulsions, clean up water block, etc. 6

7 Well Stimulation Methods Different Stimulation Methods to Overcome Different Circumstances Non-chemical Methods (i.e. Mechanical Methods) of Stimulation Often results in an increase of well drainage radius, r w Underreaming Cavitation Hydraulic Fracturing Frac Packing Mechanical Stimulation Methods Under-reaming Start with base hole Under-ream with a specialty bit to create a larger hole (i.e. an increased r w ) Applying Heat (Steam) Application in conventional reservoirs with sand production where a wire-wrapped screen and/or gravel pack is planned 7

8 Mechanical Stimulation Methods Cavitation Original hole New hole Start with base hole Cavitate produce sand intentionally to create a large cavity in the open hole effectively a much larger rw Application in shallow oil sands (Canada - CHOPS) with sand production; the cavity eventually gets so large that the velocities and pressure drop get so low that sand production is minimized Mechanical Stimulation Methods Hydraulic Fractures The most common stimulation method used in the industry Creates two propped wings out into the reservoir increases the r w Applications are reservoirs with sufficient hydrocarbons in place to make drilling viable but not enough perm to drain the reservoir 8

9 Mechanical Stimulation Methods Frac Pack Creates two propped wings out into the reservoir increases the r w Added benefit of providing sand control Applications are reservoirs with high porosity and perm that exhibit sand production The most common stimulation method used in Gulf of Mexico Summary of Chemical vs Mechanical Stimulation Chemical Stimulation Dissolves formation or damaging material in the rock Examples Acid Solvents Surfactants Non-Chemical Stimulation Increases the wellbore radius r w, and thus, increases the productivity of the well, the drainage radius, and the reserves Alternatively, uses heat to alter the viscosity in heavy oil reservoirs Examples Under-reaming Cavitation Hydraulic Fracturing Frac Packing Steam 9

10 Back to Work Suggestions Hydraulic Fracturing Core Well Stimulation Methods Leverage the skills you ve learned by discussing the skill module objectives with your supervisor to develop a personalized plan to implement on the job. Some suggestions are provided. Learning Objectives Contact a completion engineer in your group and review a recent stimulation on a well in your area. Was that stimulation a chemical or non-chemical stimulation? Discuss with the engineer why this particular method was selected as the stimulation method versus another possibility. You This should section now: has covered the following learning objectives: Understand the differences between chemical and non-chemical stimulation methods Recognize the different applications of chemical stimulation and non-chemical stimulation methods Describe the more common non-chemical stimulation methods used in our industry 10

11 Learning Objectives Rock Mechanics By This the section end of will this cover lesson, the you following will be learning able to: objectives: Recognize the importance of Rock Mechanics and its impact on hydraulic fracturing Understand how rock mechanics can impact an effective well spacing pattern 11

12 Rock Stress/Strain Relationship Linear Elastic Materials Stress Force divided by the area across which the force acts Stress is expressed as force per square inch, dynes per square centimeter, etc. Strain The change in the size or shape of a body relative to its original size or shape Strain is non-dimensional but is frequently expressed in inches per inch, centimeters per centimeter, etc. Strain occurs when stress is applied to an object like rock Rock Stress/Strain Relationship Linear Elastic Materials Young s Modulus (modulus of elasticity) The ratio of stress to strain for all values of stress not exceeding the proportional limit Elastic deformation is non-permanent deformation Young s Modulus is the slope of stress-strain curve in elastic deformation region Young s Modulus 12

13 Rock Stress/Strain Relationship Linear Elastic Materials P1 Young s Modulus Rock Stress/Strain Relationship Linear Elastic Materials Poisson s Ratio The ratio of transverse strain to axial strain within the elastic limit of the material Most materials have Poisson s ratio values ranging between 0 (cork) and 0.5 (rubber) 13

14 Measurement of Poisson s Ratio Poisson s Ratio = Lateral Strain Longitudinal Strain Rock Mechanics Linear Elastic Materials Reservoir rock will perform/deform elastically until the force reaches the point of failure When the rock fails, it fractures If fluids are pumped into that fracture at high enough rate and at high enough pressure, that fracture will be extended well out into the reservoir If proppant is added to the frac slurry, it will provide a means to prop the fracture and keep it open after the pumps are stopped 14

15 Rock Mechanics Linear Elastic Materials Fracture Boundaries Reservoirs are often bounded by shales Shales are more ductile than sandstones and carbonates so normally require a higher stress in order to fracture them This quality makes shales excellent boundary rocks for our conventional reservoirs as it helps to keep our fracture stimulation jobs confined to the pay zone Rock Fracture Mechanics Triaxial Loading of Rocks Overburden v Normally the highest stress Max H Min h Studies show that rock will always fail perpendicular to the minimal stress 15

16 How Does the Rock Fracture? This is the result of a properly planned and executed fracture job Fracture models are used to design frac length, width and height Theoretically, this is what frac models predict Fracture Orientation Frac wings The direction of the fracture can be critical to well spacing True for Vertical Wells True for Horizontal Wells (covered in unconventional section) We need to understand the fracture orientation before we drill! 16

17 Various Well & Injection Patterns & Frac Orientations (a) Good Drainage (A) Good Areal Sweep Injector Wells Producing Wells How to Determine Fracture Orientation? Hole Ovality Strain Relaxation / Reconstruction Impression Packers Tiltmeters Geophones / Micro Seismic (b) Incomplete Drainage (B) Poor Areal Sweep How do we determine the fracture orientation prior to drilling? Cored Fractures Others 17

18 How to Determine Fracture Orientation? Hole Ovality Strain Relaxation / Reconstruction Cored Fractures Impression Packers Tiltmeters Geophones / Micro Seismic Others How to Determine Fracture Orientation? Hole Ovality Strain Relaxation / Reconstruction Cored Fractures Impression Packers Tiltmeters Geophones / Micro Seismic Others 18

19 How to Determine Fracture Orientation? Hole Ovality Strain Relaxation / Reconstruction Cored Fractures Impression Packers Tiltmeters Geophones / Micro Seismic Others How to Determine Fracture Orientation? Hole Ovality Strain Relaxation / Reconstruction Cored Fractures Impression Packers Tiltmeters Geophones / Micro Seismic Others Mandrel Cured Rubber Impression Material Impression Interval 9 ft (2.7 m) 19

20 How to Determine Fracture Orientation? Hole Ovality Strain Relaxation / Reconstruction Cored Fractures Impression Packers Tiltmeters Geophones / Micro Seismic Others Fracture-Induced Surface Trough Depth Fracture How to Determine Fracture Orientation? Hole Ovality Strain Relaxation / Reconstruction Cored Fractures Impression Packers Tiltmeters Geophones / Micro Seismic Others Microseism Fracture Surface Tiltmeters Downhole Tiltmeters in Offset Well Receivers Reservoir 20

21 How to Determine Fracture Orientation? Hole Ovality Strain Relaxation / Reconstruction Cored Fractures Impression Packers Tiltmeters Geophones / Micro Seismic Others Well Fracture Program Plan 7000 psi (48 MPa) 6500 psi (45 MPa) Well Designed Proppant Filled Fracture Downhole Fracture Viewed from Borehole Camera Shale Sand Reservoir 7100 psi (49 MPa) Shale Water 21

22 Back to Work Suggestions Hydraulic Fracturing Core Rock Mechanics Leverage the skills you ve learned by discussing the skill module objectives with your supervisor to develop a personalized plan to implement on the job. Some suggestions are provided. Learning Objectives Consult a reservoir engineer in your group and review a fracture stimulation on a well in one of your fields. Review what efforts, if any, were taken to determine the orientation of the fracture created when the well was stimulated. You This should section now: has covered the following learning objectives: Recognize the importance of Rock Mechanics and its impact on hydraulic fracturing Understand how rock mechanics can impact an effective well spacing pattern 22

23 Learning Objectives Hydraulic Fracturing Core Propped Hydraulic Fracturing By This the section end of will this cover lesson, the you following will be learning able to: objectives: Describe the principles of hydraulic fracturing and how it impacts production in conventional wells Identify fracture stimulation candidates Describe the different stages in a hydraulic fracture and the purpose of each stage 23

24 Why Do We Frac? It is usually an economic decision and applied to a reservoir that has sufficient hydrocarbons in place but too low of permeability to produce at a high rate unstimulated Post-frac conventional wells normally decline hyperbolically MCFD (m 3 /h) 100,000 (118,000) 10,000 (11,800) 1,000 (1,180) 100 (118) 10 (11.8) Gas Well Rate vs Time Production Curve Time Conventional and Unconventional Fracturing There are multiple ways to classify the conventional and unconventional in the energy business, including: Resource Completion 24

25 Conventional and Unconventional Fracturing Conventional Resources Traps of oil and/or gas that are trapped in sandstone or carbonate reservoirs with high enough permeability that they can be exploited economically via conventional means with vertical wells Unconventional Resources Difficult to define That which is not conventional Resources that need assistance to produce economically either by increasing the permeability (i.e., multiple fractures) or a reduction in viscosity (i.e., heating heavy oil) Permeability cut off of < md Conventional vs. Unconventional Well/Completion Generally speaking, the industry classifies a vertical well as a conventional completion and a horizontal well with multiple fractures as an unconventional completion Frac Detail Pilot Hole Horizontal Well Frac Vertical Well Frac 25

26 History of Hydraulic Fracturing Nearly 70 Years History of Hydraulic Fracturing Early attempts to hydraulically fracture an oilfield producing zone occurred in Hugoton, Kansas, USA in 1947 by Pan Am Oil Co. The first well to successfully be hydraulically fractured to increase production was the Klepper Gas Unit No. 1 well in Hugoton The first commercial hydraulic fracturing treatment (March 1949) 26

27 Frac Models Frac models play an important role in hydraulic fracture design The predictive capabilities of the models are a function of the quality of input data Input: Rock Mechanics Data both pay zone and boundary formations Frac Fluid Properties Formation Leak-off Proppant type and concentration Reservoir and fluid properties Maximum treating pressure A View of a Hydraulic Fracture This diagram depicts some of that which a frac model will predict It will project the height, width, and fracture half length as well as the fracture s conductivity Rock Fracture Perfs Output: Pump rate Frac height, length, and width Frac conductivity Anticipated flow rate, flow history, and reserves Casing Cement sheath ρ h ρ h ρ h Envelope of compressive stress perpendicular to fracture 27

28 Frac Stages Vertical Wells Stage 1: Mini-frac or DFIT Small frac pumped prior to the main frac for data mining purposes Provides: Frac gradient Fluid leak-off Net frac pressure Perforation pressure drop Stage 2: Pad Initiates the fracture in the rock Establishes frac width Controls fluid leak-off Extends fracture Frac Progression Stage 3: Slurry Extends the fracture length Transports proppant from the surface into the fracture Suspends the proppant while fracture closes Stage 4: Flush Displaces slurry down to the top perforation Pad - Create Frac Proppant Follows Proppant Continues Flushed - Job Done 28

29 Back to Work Suggestions Hydraulic Fracturing Core Propped Hydraulic Fracturing Leverage the skills you ve learned by discussing the skill module objectives with your supervisor to develop a personalized plan to implement on the job. Some suggestions are provided. Learning Objectives Consult a completion engineer in your group and review a recent conventional well fracture stimulation in which a DFIT Mini-frac was conducted prior to the stimulation. Discuss with the completion engineer what type of data was mined from this stage, and how the results altered the design of the main frac job which followed. You This should section now: has covered the following learning objectives: Describe the principles of hydraulic fracturing and how it impacts production in conventional wells Identify fracture stimulation candidates Describe the different stages in a hydraulic fracture and the purpose of each stage 29

30 Hydraulic Fracture Design Learning Objectives By This the section end of will this cover lesson, the you following will be learning able to: objectives: Develop an understanding of the concepts of folds of increase, fracture conductivity, and optimum fracture half length as a function of economic return Understand the fracture design to be considered and the application of such with regard to proppant, fluids, and pump rate 30

31 Frac Design Frac Design Options Frac Design Frac fluid type and volume Proppant type and concentration Pump rate Leak-off (fluid loss) control The design option decisions will affect the frac properties of: Frac length Frac height Frac width Frac conductivity These frac properties in combination with the reservoir rock and fluid properties will determine the well productivity 31

32 Frac Design Productivity Ratio = Productivity of the well post-frac Productivity of the well pre-frac Also known as J/Jo NOTE: Another way to think of this is the folds of increase in production, such as a 5-fold increase in a stimulated well vs. an unstimulated well McGuire-Sikora Method to Predict Productivity Increase Post Frac Productivity Index Ratio Vs Relative Capacity 32

33 McGuire-Sikora Method Definition of fracture conductivity = w * k f The fracture width X fracture permeability RCF is the relative conductivity factor the ratio between the fracture conductivity and the formation permeability RCF = w * k f / k The greater this value, the better the results i.e., yields higher J/Jo Calculate the ratio of L/r e L is the fracture half-length r e is the drainage radius McGuire-Sikora Method to Predict Productivity Increase Post Frac Productivity Index Ratio Vs Relative Capacity 33

34 McGuire-Sikora Method to Predict Productivity Increase Post Frac Productivity Index Ratio Vs Relative Capacity 50,000 McGuire-Sikora Method to Predict Productivity Increase Post Frac Productivity Index Ratio Vs Relative Capacity J/J o = ,000 34

35 McGuire-Sikora Method to Predict Productivity Increase Post Frac Productivity Index Ratio Vs Relative Capacity J/J o = ,000 McGuire-Sikora Method to Predict Productivity Increase Post Frac Productivity Index Ratio Vs Relative Capacity J/J o = 7.4 The larger we can make the ratio of L/r e, the better the results The larger we make the RCF, the better the results 50,000 35

36 McGuire-Sikora Method McGuire-Sikora factors we can control with frac design? Frac width, w Frac permeability, k f Frac Length, L The greater we make any of these factors, the better the results because they will increase either the L/r e or the RCF, and thus, the J/Jo Furthermore, the lower the formation permeability k the greater the J/J o for a given fracture conductivity A lower fracture conductivity can yield a comparable RCF if the formation permeability is lower Fracture Variables AVERAGE WIDTH, in. (mm) LENGTH ft (m) HEIGHT ft (m) 36

37 Fracture Design Frac Half-Length, L The longer the frac length, the better the productivity Control frac length by: Frac volume Frac width Controlling Leak-off Confining frac in-zone Polymers as Carrying Fluid Range of water based fluids Non or minimal damaging Brines ideal to control formation pressure Viscosity Higher viscosity - wider fracture Proppant transport Leak-off control Polymer material Linear Cross linked gels Frac Width, w The wider the propped frac (w), the higher the productivity Control propped frac width by: Frac fluid viscosity Frac pump rate Slurry Proppant concentration 37

38 Polymers Used in Fracturing (and Other Applications) Guar inexpensive but high residue Hydroxypropyl Guar (HPG) used in cross-linked gels Carboxymethylhydroxypropyl Guar (CMHPG) Hydroxyethyl cellulose (HEC) Carboxymethyl cellulose (CMC) Carboxymethylhydroxyethyl cellulose (CMHEC) Polyacrylamide (PAM) inexpensive, slickwater fracs Xanthan (XC) and other biopolymers Guar is a long chain sugar, a polysacharride Polymers Used in Fracturing (and Other Applications) Guar inexpensive but high residue Hydroxypropyl Guar (HPG) used in cross-linked gels Carboxymethylhydroxypropyl Guar (CMHPG) Hydroxyethyl cellulose (HEC) Carboxymethyl cellulose (CMC) Carboxymethylhydroxyethyl cellulose (CMHEC) Polyacrylamide (PAM) inexpensive, slickwater fracs Xanthan (XC) and other biopolymers Guar is a long chain sugar, a polysacharride Conventional Stimulations Unconventional Stimulations 38

39 Polymer Chemistry in Oilfield Fracturing Semi Solid Gel Structure Linear Polymers Coiled spring uncoiling is called hydration or the ability to take up water Crosslinked Polymers 39

40 Crosslinked Polymers High Viscosity and Proppant Transport Polymer Degradation by Micro-organisms Enzyme Microorganism/ Bacteria Biocides Polymer Sugar A biocide may be required to mitigate microorganism metabolism / growth 40

41 Population Growth of Micro-organisms Population Bactericides or Biocides Time Growth of microorganisms negatively affects polymer frac fluid viscosity, and thus, the proppant transport 41

42 Frac Design Breakers If the gel remains in high viscosity state, it will damage the reservoir Breakers are added to chemically break the polymer down to smaller chains to reduce the viscosity Different polymers require different chemical breakers (enzymes and oxidizers) Ideal breaker has a delayed reaction so that it doesn t start breaking down the polymer too early Encapsulated breakers have a shell which dissolves and provides the time release properties that are desired Gel Breakers Once gel viscosity is engineered, created, and used, then there is the requirement to break the gel viscosity - once gel is made and used, destroy it Gelled Oils Breaker interferes with association polymer, normally acid or base Gelled Water Breaker will chemically degrade polymer 42

43 Fracture Design Leak-off Frac fluid will leak out of the fracture and into the formation if not controlled The more frac fluid that leaks-off, the less frac length created Tighter rock will experience less leak-off than permeable rock Fracture Design Factors effecting leak off: More viscous frac fluids will leak-off less than low viscosity fluids Leak-off Determination Methods Cores and Porosity Logs porosity/ permeability relationships Natural fractures will affect leak-off Experience and Familiarity with the Formation Can control leak-off with higher viscosity and particulate fluid loss additives (FLA) Silica Flour, 100 mesh sand, starch, etc. Mini-frac (DFIT) 43

44 Fracture Design - Fluids Gelled Water is Most Widely Used HSE friendly Can be relatively inexpensive Can be non-reactive with formation Lower treating pressures Emulsified Oil HSE issues Expensive Fracture Design - Proppant Gelled Diesel HSE issues Different additives depending on season and source Foams (Nitrogen or CO 2 ) used in depleted reservoirs Less water trapped in pores via capillary pressure Lower density Low leak off Limited transport capabilities Frac permeability The higher the permeability of the propped frac (kf), the better Control frac permeability by Proppant concentration Proppant size - 20/40 is the most common sized used Proppant quality/strength Proppant Cost/Economics play a major role in proppant selection Transportation costs can add substantially to proppant expense 44

45 Proppant Concentration in Fracture X X Multi-Layer Mono-Layer Partial Mono-Layer Proppant Packing Proppant In-Situ Permeability, k f 45

46 Fracture Design - Conductivity Fracture Conductivity (C f ) Measure of the flow capacity of the propped frac Definition - C f = k f * W f Units are md-ft or md-in It is the numerator in the McGuire-Sikora Relative Conductivity Ratio where: RCF = Relative conductivity ratio k f = Proppant permeability w f = Fracture width Proppant Conductivity C f = k f * w f K f Proppant permeability w f Fracture width C f Fracture conductivity, indicates the fracture s ability to flow fluids Proppant is selected to withstand the fracture closing pressure C f /k k = Formation permeability C f = Fracture conductivity w f k f 46

47 Proppant Concentration More Permeable Rock Requires a Wider Propped Frac and Larger Proppant than Low Permeable Reservoirs in order to get sufficient Conductivity Ratio To Achieve a Wider Propped Frac: Proppant Conductivity PERMEABILITY - DARCIES Increase Frac Fluid Viscosity And/or Pump at Higher Rate Increase Proppant Concentration PERMEABILITY VS. CLOSURE STRESS (14 MPa) (28 MPa) (41 MPa) (55 MPa) (69 MPa) (83 MPa) CLOSURE STRESS - PSI 2.0lb/ft 2 (9.8 kg/m 2 ) 20/40Jordan250 o F (121 o C) 2.0lb/ft 2 (9.8 kg/m 2 ) 20/40 PRB250 o F (121 o C) 2.0lb/ft 2 (9.8 kg/m 2 ) 20/40 C-Lite250 o F (121 o C) 2.0lb/ft 2 (9.8 kg/m 2 ) 20/40SIN BAUX250 o F (121 o C) 47

48 Proppant Strength Conductivity Various Proppant Types: Proppant Strength and Crushing Use Industry Proppant Conductivity Data and compare to your formation closure stresses to determine the correct proppant to use Too weak a proppant will result in crushing of the proppant and a severe reduction in fracture conductivity as seen at the right Crushed Proppant 48

49 Proppants - Permeability and Conductivity Proppant In-Situ Permeability, k f Measured in laboratory Can be reduced by crushing, gel residue and some fluid loss additives Average Propped Fracture Width, w f Mainly a function of proppant concentration Can be reduced by crushing and embedment Proppants - Permeability and Conductivity Proppant In-Situ Permeability, k f Measured in laboratory with Cooke Conductivity Cell 49

50 Proppant Selection Proppant selection greatly influenced by cost / economics $ $ Fracture Design Pump Rate 20/40 the most common proppant size in conventional well fracturing Frac width created Proppant transport How many zones get fracced in a multi-zone stimulation Limited by tubular pressure limitations and friction Impacts cost of frac 50

51 Fracture Design - Limitations Limitations: The tubing or casing through which the frac job is being pumped will have pressure limitations These pressure limitations will limit the rate at which the frac can be pumped Friction reducers (e.g., polyacrylamide) will reduce the treating pressure, and thus, increase the rate which can be pumped The Service Company stimulation expense is partially based upon hydraulic horsepower (HHP) expended on the job and. Post Frac, Get the Fluid Off the Formation Obviously, for a given pump rate (Q), the lower the treating pressure (Pw), the less HHP expended and the lower the cost Post job, frac fluid retention must be addressed as quick as is practical Treating fluid removal from fracture is critical 51

52 Surfactants Aid Frac Fluid Recovery Reduce surface tension Reduce interfacial tension Surfactant Benefits in Fracture Fluids Fracture Optimization Methodology Cum. Production Time L f = 500 ft (152 m) L f = 300 ft (91 m) L f = 100 ft (30 m) Un-treated Treatment Cost Prevent or break emulsions Fracture Length 1 2 NPV Increase recovery of treatment fluids Optimal Fracture Length 3 52

53 Back to Work Suggestions Hydraulic Fracturing Core Hydraulic Fracture Design Leverage the skills you ve learned by discussing the skill module objectives with your supervisor to develop a personalized plan to implement on the job. Some suggestions are provided. Learning Objectives Consult a completion engineer in your group and discuss a recent conventional well fracture stimulation. What steps were taken in the stimulation design phase to optimize the fracture stimulation? You This should section now: has covered the following learning objectives: Understand the concepts of folds of increase, fracture conductivity, and optimum fracture half length as a function of economic return Understand the fracture design considerations available and the application of such, with regard to proppant, fluids, and pump rate 53

54 Learning Objectives Hydraulic Fracturing Core Frac Packing By This the section end of will this cover lesson, the you following will be learning able to: objective: Develop an understanding of the basic concepts and applications of frac packing 54

55 Frac Pack Stimulation or Sand Control? Frac Packs are actually a combination of Sand Control and Stimulation Application Highly permeable sandstones with sand production problems (i.e., weak to poor sand consolidation) Benefit It is the only means of sand control that can yield a negative skin (i.e., a stimulated condition) The #1 completion method in the Gulf of Mexico Frac Pack Well Completion Principles 1. Achieved by causing an intentional tip screen out to pack the fracture with gravel 2. Method is to pump less pad volume and with less emphasis on fluid loss control Pad pumped down tube Gravel pack screen 1 55

56 Frac Pack Well Completion Principles 1. Pad (yellow) extending the fracture into the reservoir 2. High degree of fluid leakoff 2 Fracture extended into the reservoir Frac Pack Well Completion Principles 1. Fracture is fully extended 2. Gravel slurry is being pumped behind the pad 3 56

57 Frac Pack Well Completion Principles 1. Gravel is now entering the fracture 2. Fracture has stopped growing Frac Pack Well Completion Principles 1. Gravel is in place and packed off 2. Well is ready to produce

58 Frac Pack Design Basics Design Steps A sand grain distribution analysis is performed on a core sample The optimal gravel size is selected based upon this data Frac Pack Design Basics Operational Procedure The proper size screen is selected based upon the gravel size The screen is run in the hole and the frac pack job is pumped first filling the fracture with gravel, then packing gravel in the annulus between the screen and the casing (or open hole) Once the job is pumped in place, the well is ready to be brought on to production slowly 58

59 Fracpacking Sand Control with Well Stimulation Conventional cased-hole gravel packs often result in low well productivity, i.e., a high skin The frac pack completion technique was developed to place short, wide fractures in cased holes, followed by a gravel pack in the screen / casing annular space Typical frac wing lengths are from ft (10-50 m) Typical fracture widths at the wellbore are 2-3 in. (5-8 cm) The fracture creates the stimulation aspect of the completion and the correctly sized gravel provides the sand control to keep the formation sand in place Back to Work Suggestions Hydraulic Fracturing Core Frac Packing Leverage the skills you ve learned by discussing the skill module objectives with your supervisor to develop a personalized plan to implement on the job. Some suggestions are provided. If your company is active in an area where frac packs are utilized, consult a completion engineer that works in this area, and review a recent frac pack completion. Ask the completion engineer to explain the method used to determine the gravel size to use. What skin factor resulted from the frac pack completion? 59

60 Learning Objectives You This should section now: has covered the following learning objective: Develop an understanding of the basic concepts and applications of frac packing 60

61 Learning Objectives Hydraulic Fracturing Core Fracture Acidizing By This the section end of will this cover lesson, the you following will be learning able to: objectives: Develop an understanding of the basic concepts of acid fracturing and their applications Recognize the differences between acid fracturing and propped hydraulic fracturing 61

62 Fracture Acidizing with HCl Acid Fracture Acidizing Carbonates Only Primary Purpose: To stimulate natural carbonate reservoir capacity Factors in Carbonate Fracture Acidizing: Carbonate mineralogy Fracture geometry Fracture conductivity Acid Reaction Rate Conductivity Depends Upon: Etching the rock face to create channels, not upon total rock removal 62

63 Heterogeneous Limestone Rock Before and After Lab Test HCl Etching AFTER ETCHING BEFORE ETCHING Fracture Acidizing Description Liquids are pumped at relatively high rate and pressure until the reservoir rock fails and a fracture is created Acid is then pumped into the fracture to dissolve some of the carbonate rock and etch the face of the fracture creating a very uneven surface on the fracture face When the pumping stops, the fracture closes The uneven nature of the fracture face does not allow the fracture to heal cleanly leaving a highly conductive fracture back to the wellbore 63

64 Fracture Acidizing vs. Propped Hydraulic Fracturing Fracture Acidizing Relies on a chemical reaction to create the uneven surface and maintain an open fracture Normally ft (15-50 m) in length Pumped in carbonates Stages of Fracture Acid Job Pad or Pre-flush usually gelled water Establishes fracture, creates fracture width, controls leakoff, and cools formation Acid Stage Usually HCl but not always Acid is often gelled to yield more viscous fluid, greater frac width, less leak-off, and a longer effective frac length Etches the fracture face to provide an uneven face and fracture conductivity Propped Hydraulic Fracturing Does not utilize a chemical reaction but relies on proppant to maintain an open fracture Generally ft ( m) in length Pumped in sandstones Flush Usually brine water Displaces the acid down to the perforations 64

65 Acid Fracturing Job Operations Acid Fracture Conductivity Effect of etched fracture face creating a conductive fracture after the fracture closes 65

66 Laboratory Flow Test of Multi Stage Acid Job Channels Sub-channels Induced fracture etching Channels which stay open and good fracture conductivity Alternative Closed Fracture Acidizing (CFA) As the name implies, fractures earlier created are re-entered with acid at low treatment pressure A technique for development of highly conductive channels (worm holes) using natural fractures or previously induced fractures to direct the acid path After the frac closes at the conclusion of the acid frac job, acid is further pumped into the closed fracture, further etching the frac channel network Pump overflush equal to acid volume pumped 66

67 Comparison Laboratory Flow Testing Acid Etched Fracture Flow Capacity Tests 120 F (49 C) Closed Fracture Acidizing Closed Standard Fracture Acidizing Open 0.05 Summary of Stimulation Options Conventional Wells If damage does not exist Matrix stimulation is probably not a viable option Sandstones: hydraulic fracturing should be considered Carbonates: fracture acidizing should be considered If damage exists and permeability is low Sandstones: 1) hydraulic fracturing should be considered; 2) Skin bypass fracturing (skin frac) may be a secondary option Carbonates: 1) fracture acidizing 2) matrix acid If deep damage exists and permeability is high Sandstones: matrix stimulation may not be effective Damage bypass treatments may be considered Carbonates: high rate acidizing If near-wellbore damage exists and permeability is not low Matrix stimulation 67

68 Summary of Stimulation Options Conventional Wells What is the mineralogy? (i.e. Is it a carbonate or sandstone?) What is the permeability of the reservoir? Is the formation damaged? Summary of Stimulation Options Conventional Wells If damage does not exist Matrix stimulation is probably not a viable option Sandstones: hydraulic fracturing should be considered Carbonates: fracture acidizing should be considered If damage exists and permeability is low Sandstones: 1) hydraulic fracturing should be considered; 2) Skin bypass fracturing (skin frac) may be a secondary option Carbonates: 1) fracture acidizing 2) matrix acid If deep damage exists and permeability is high Sandstones: matrix stimulation may not be effective Damage bypass treatments may be considered Carbonates: high rate acidizing If near-wellbore damage exists and permeability is not low Matrix stimulation 68

69 Back to Work Suggestions Hydraulic Fracturing Core Fracture Acidizing Leverage the skills you ve learned by discussing the skill module objectives with your supervisor to develop a personalized plan to implement on the job. Some suggestions are provided. Learning Objectives Locate a completion engineer in a group within your company with carbonate reservoirs and discuss a well where an acid frac was utilized to stimulate the well. Ask the completion engineer to explain why an acid frac was employed versus a matrix acid job or propped hydraulic fracture. You This should section now: has covered the following learning objectives: Develop an understanding of the basic concepts of acid fracturing and their applications Recognize the differences between acid fracturing and propped hydraulic fracturing 69

70 Learning Objectives Hydraulic Fracturing Core Unconventional Hydraulic Fracturing: Introduction By This the section end of will this cover lesson, the you following will be learning able to: objectives: Understand the differences between conventional and unconventional resources Identify fracture candidates for unconventional resources Describe the proppant theories for microfractures in shale resources Understand why slickwater fracs work in shale resources 70

71 Recall Conventional and Unconventional Fracturing There are multiple ways to classify the conventional and unconventional in the energy business Resources Completions Recall Conventional and Unconventional Fracturing Conventional Resources Traps of oil and/or gas that are trapped in sandstone or carbonate reservoirs with high enough permeability that they can be exploited economically via conventional means with vertical wells 71

72 Recall Conventional and Unconventional Fracturing Conventional Resources Traps of oil and/or gas that are trapped in sandstone or carbonate reservoirs with high enough permeability that they can be exploited economically via conventional means with vertical wells Unconventional Resources difficult to define That which is not conventional Resources that need assistance to produce economically either by increasing the permeability (i.e., multiple fractures) or a reduction in viscosity (i.e., heating heavy oil) Permeability cut off of < md Unconventional Resources - Occurrence & Examples Examples of unconventional resources are: Shale gas Shale oil Tight gas Tight oil Coalbed methane (CBM) Heavy oil Oil sands Methane hydrates Usually require a horizontal type well to exploit Only about a third of worldwide oil and gas reserves are conventional; the remainder are in unconventional resources 72

73 Unconventional Hydraulic Fracturing Recall from the earlier slide, we said that generally speaking a conventional completion utilizes a vertical well and an unconventional completion utilizes a horizontal well Pilot Hole Horizontal Well Frac Shale Resource Plays Shale resource plays are not truly shale reservoirs Desire a shale content < 40% More accurately described as either: Frac Detail Vertical Well Frac Shaly Sandstone Shaly Carbonate 73

74 Mineralogical Distribution Regarding Shales Unconventional Completions - Early Shale Wells Vertical shale wells have been drilled and completed on a very limited scale for nearly 200 years First successful large scale shale drilling/completion program was proven by Mitchell Energy in the Barnett Shale in the Fort Worth Basin Vertical wells initially Pioneered the use of slickwater as the fracturing fluid Slickwater is freshwater with low concentrations of polyacrilomide (PAM) Higher viscosity than fresh water but less friction Lower viscosity than other gelled polymers used as fracture fluids Typically use smaller proppant at lower concentrations Much cheaper than conventional hydraulic fracturing 74

75 Shale Reservoirs Natural gas stored in tight shales Adsorbed onto insoluble organic matter; kerogen that forms a molecular film Trapped in the pore spaces of the fine grained sediments interbedded with shale much like conventional reservoirs Confined in fractures within the shale itself Shale Reservoirs Require unconventional development Multi-staged fractured horizontal completions Gas and/or oil in shale May be 2,000-14,000 ft (600-4,300 m) deep Very low permeability 75

76 Shale Reservoirs Complex combination of natural fractures, low permeability, and ultra-low permeability (nano-darcy) rock Best results come from most complete stimulation of this complex reservoir; the goal is to create a complex fracture network which is a combination of: Micro-fractures within the shale Stimulated/disturbed natural fractures not necessarily propped Newly created fractures with proppant Multiple stimulation conducted along the lateral from the toe to heel Why Did Slickwater Fractures Work in the Barnett? Comparing parameters to the Conventional Wells and the McGuire-Sikora Method Slickwater reduced the stimulation cost significantly The reservoir drainage radius, r e is comparable to the frac length, L, giving a high L/r e value High conductivity ratio (CR) achievable with low proppant concentrations because the reservoir permeability is so low and is in the denominator Once the CR reaches 1X10 5 the MS curves are fairly flat Micro-fractures and natural fractures occur in varying degrees in the shale reservoirs and many are opened/disturbed with the slickwater but not propped Conventional fractures are created and propped 76

77 Why Did Slickwater Fractures Work in the Barnett? Recall McGuire-Sikora Chart k f w RCF ( f ) = RC Unconventional Completions Advances Followed Quickly k f Industry developed methods to pump multiple propped fractures along a single lateral Added tremendous exposure to reservoir Propped fractures gave excellent permeability contrast Stimulated natural fracture system along the entire lateral of 2,000-4,500 ft (600-1,400 m) in length expanding the SRV Early External Casing Packer (ECP) Systems placed 6-10 fractures in a lateral Improved designs led to stages then 30 stages and now can pump 100+ fracture stages in a single lateral 77

78 Back to Work Suggestions Hydraulic Fracturing Core Unconventional Hydraulic Fracturing Leverage the skills you ve learned by discussing the skill module objectives with your supervisor to develop a personalized plan to implement on the job. Some suggestions are provided. Learning Objectives Consult a completion engineer in an unconventional resource group (your group if you are working in UR s). Ask them to show you where your UR falls in the Clay, Carbonate, Quartz Ternary Diagram, and how the placement affects the stimulation design. You This should section now: has covered the following learning objectives: Understand the differences between conventional and unconventional resources Identify fracture candidates for unconventional resources Describe the proppant theories for microfractures in shale resources Understand why slickwater fracs work in shale resources 78

79 Completion Methods Learning Objectives By This the section end of will this cover lesson, the you following will be learning able to: objectives: Recognize the importance of lateral orientation with regard to the formation stress profile in an unconventional resource Outline the two most common completion techniques for unconventional shale plays 79

80 Unconventionals Variables in Well Design Lateral direction Completion methodology Lateral spacing The stimulated reservoir volume (SRV) Timing and effects on offsets Lateral length Spacing of frac stages Number of perf clusters per stage Frac fluids Proppant (size, type, and concentration) Clean out methods Lateral Direction This section will focus on lateral direction and completion methodology Must drill the well in the direction of minimum horizontal stress so that fractures will be perpendicular to the lateral 80

81 Lateral Direction Predominant Completion Methods External Casing Packers No Cement Used ECP s set along liner in the open hole with a shifting sleeve inbetween each pair of ECP s Ball dropped one at a time to shift sleeve open between ECP s Single fracture stimulation pumped between each ECP Used in approximately 20% of the unconventional horizontal wells Packers Plus, Frac Point, Zone Guard, Zone Select, etc. 81

82 Predominant Completion Methods Plug and Perf Production casing is cemented in place 4-10 sets of perforations (perf clusters) are made in the casing That set of perf clusters is fracture stimulated A plug is set in front of the stimulated perforations to isolate them from the rest of the lateral and a new set of perf clusters is perforated These perf clusters are fracture stimulated with a single frac stage Another plug is set and another set of perf clusters is perforated and the process repeated frac stages per lateral are common Used in approximately 80% of the unconventional horizontal wells Ball and Sleeve Method ECP's Advantages Faster than Perf and Plug method reduces service company expenses Can be less expensive Can pump up to 60 frac stages in a single lateral but at what expense? Disadvantages Some operators believe the results are not as good as Plug and Perf Does each frac stage create a new frac or do some stages refrac existing fractures? Drill out of the balls, seats, and plugs is necessary New Developments Dissolvable balls and seats 82

83 Plug and Perf Completion Method Advantages Many operators believe they experience superior production results Flexibility in location of perf clusters Can frac multiple perf clusters with each stage (multiplying effect) New Developments Dissolvable plugs Perf Cluster design - Length, density, spacing Back to Work Suggestions Hydraulic Fracturing Core Completion Methods Leverage the skills you ve learned by discussing the skill module objectives with your supervisor to develop a personalized plan to implement on the job. Some suggestions are provided. Disadvantages More expensive than ECP with shifting sleeves Not all perf clusters get fractured (50-67% get stimulated) Drill out of the plugs necessary prior to production Consult a reservoir or completion engineer in one of your unconventional resource plays, and discuss the methodology used by your company to determine the natural fracture orientation of the reservoir rock. 83

84 Learning Objectives You This should section now: has covered the following learning objectives: Recognize the importance of lateral orientation with regard to the formation stress profile in an unconventional resource Outline the two most common completion techniques for unconventional shale plays 84

85 Unconventional Hydraulic Fracturing: Well Spacing, Lateral Length, Effects on Offsets, and Perf Cluster Spacing Learning Objectives By This the section end of will this cover lesson, the you following will be learning able to: objectives: Describe stimulated reservoir volume as it applies to unconventional horizontal wells Understand the concept of optimal lateral spacing as it applies to shale plays Recognize that lateral length and perf cluster spacing vary from play to play and are not a constant variable in well and stimulation design 85

86 Unconventionals Variables in Well Design Lateral Direction Completion Methodology Lateral spacing and stimulated reservoir volume (SRV) Timing and effects on offsets Lateral Length Spacing of frac stages and number of perf clusters per stage Frac Fluids Proppant Size, type, and concentration Clean out methods Unconventional Well Spacing Optimum distance between laterals: Too far apart reserves are left behind Too close stimulations and drainage patterns overlap Optimum distance varies depending on rock properties, pay thickness, frac design, well costs, and product prices 86

87 Unconventional Well Spacing The rock properties and frac design determine the Stimulated Reservoir Volume (SRV) Most NA Unconventional Resource Plays are being developed on ft ( m) spacing between laterals Industry utilization of Pad Drilling increasing: Multiple wells spaced a few feet apart on a single pad Smaller environmental footprint Cheaper drilling expense Optimize facilities and infrastructure Unconventional Well Spacing 87

88 Unconventional Well Spacing Overlapping Stimulation Unconventional Well Spacing Understimulated, Undrained Reservoir 88

89 Unconventional Well Spacing Optimum Lateral Spacing Stimulated Reservoir Volume SRV 89

90 Stimulated Reservoir Volume SRV Stimulated Reservoir Volume SRV 90

91 Stimulated Reservoir Volume SRV Stimulated Reservoir Volume SRV 91

92 Stimulated Reservoir Volume SRV Stimulated Reservoir Volume SRV 92

93 Stimulated Reservoir Volume SRV Stimulated Reservoir Volume SRV Industry uses microseismic techniques to listen to the reservoir rock parting and grinding as the frac pressures cause the rock to fail Process the data and generate maps of the fractures that were created during the stimulation including location, direction, length, and height Industry calls the total affected area the SRV Stimulated Reservoir Volume Helpful for optimizing the lateral direction and spacing 93

94 SRV from Microseismic Data Multiple Fracture Stages Timing and Placement of the Offsets Unstimulated Reservoir Many shale plays in the U.S. were initially developed with only one well per section, with the understanding that the operator would need to return and drill more wells to fully deplete the hydrocarbons in place Therefore, the first offsets were often drilled several years after the first well Industry quickly learned that they needed to shut in the producing wells for a few days prior to the offset frac to prevent the producing well from being overwhelmed with frac water from the new well Various completion methods have been tried to minimize damage to offsets including zipper frac, modified zipper frac, high intensity fracs, diverters, etc. 94

95 Simultaneous Operations, Zipper and Modified Zipper Hydraulic Fracturing A) Sime-Ops Frac B) Zipper Frac C) Modified Zipper Frac Fully Developed Shale Section Horizontal Wells Staggered Perf Clusters 95

96 Unconventional Hydraulic Fracture Variables Lateral Length Early wells were ft ( m) in length Grew to 4500 ft (1400 m) (limited by 640 acre unit size) Many states now allow 2-section units Extended Reach wells with ~ 10,000 ft (3000 m) laterals Experimentation with 15,000 ft (4600 m) laterals in some areas Longer lateral exposes wellbore to more reservoir Increases SRV Increases initial producing rate Increases reserves Unconventional Hydraulic Fracture Variables Must make economic sense Spacing of frac stages and number of perf clusters per stage Early wells designed with ft ( m) per frac stages Spacing has shrunk with time and now runs ft ( m) per frac stage Now perforate 4-10 perf clusters per stage If every perf cluster took a frac, that would translate into a propped fracture every ft (15-30 m) Production logs, tracers, and fiber optics tell us that actual perf cluster efficiency only runs 50-67% 96

97 Learning Objectives You This should section now: has covered the following learning objectives: Be able to describe stimulated reservoir volume as it applies to unconventional horizontal wells Understand the concept of optimal lateral spacing as it applies to shale plays Recognize that lateral length and perf cluster spacing vary from play to play and are not a constant variable in well and stimulation design 97

98 Unconventional Hydraulic Fracturing: Frac Fluids, Proppant, and Clean Outs Learning Objectives By This the section end of will this cover lesson, the you following will be learning able to: objectives: State the requirements and objectives in multi-stage fracture treatments Identify the typical fluids, proppants, concentrations, and pump rates for multi-stage fracture treatments Explain the rationale behind and process of the post-stimulation drill out of the lateral 98

99 Unconventionals Variables in Well Design Lateral Direction Completion Methodology Lateral spacing and stimulated reservoir volume (SRV) Timing and effects on offsets Lateral Length Spacing of frac stages and number of perf clusters per stage Frac Fluids Proppant Size, type, and concentration Clean out methods Unconventional Hydraulic Fracture Variables Slickwater polyacrylamide (PAM) friction reducer added to water Cheaper than other polymer fluids Low viscosity means fractures are more narrow Used extensively in shale plays Can stimulate natural fractures even though W f may not be wide enough to accept proppant Linear gel guar polymer added to water Cheapest of the non-pam polymers but has high residue More viscous than PAM but less than X-linked More proppant transport capability than PAM X-linked gel chemicals used to x- link linear gels More expensive than linear gels More viscous than linear gels More proppant transport capability than linear gel More difficult to break than linear gel Hybrids Combinations of the three fluids above Utilized in many shale plays with the slickwater segment used with small grain sand proppant and the X-linked fluid to carry the larger grain size and higher concentration proppant 99

100 Unconventional Hydraulic Fracture Variables Proppant Material Manufactured in various grain sizes, strength, and density Common Grain Sizes 100 mesh the smallest, then 40/70, 30/50, and 20/40 Material Sand, resin coated sand, ceramic, and bauxite Increased strength of proppant usually accompanied by an increase in density and increased cost of the proppant Natural sand is used primarily in shale wells due to low cost Many wells today pump over 10,000,000 lb (4,500,000 kg) of proppant into their lateral completions so a difference of $0.05/lb ($0.11/kg) can add $500,000 to the stimulation cost Use predominantly smaller size proppant (i.e. 100 mesh, 40/70 and 30/50) at relatively low concentrations (1-2 ppg) than conventional well hydraulic fracturing due to the low perm of the reservoir. Unconventional Hydraulic Fracture Variables Exploitation/Development Early Thought Avoid intersection of offset well s fractures (called hits ) with well spacing Current Thinking Intersection of stimulations may be good if done effectively 100

101 Unconventional Hydraulic Fracture Variables Exploitation/Development Many offset existing horizontal wells experience a bump in production following the stimulation of an offset well Consequently, operators are moving wellbores closer and closer Unlike conventional well fracturing, the goal is not so much to create very long fractures as it is to thoroughly stimulate the SRV creating a complex stimulated network and drain more of the hydrocarbons in place Consequently, the volume of proppant used has gone up significantly over time - in many areas companies are pumping pounds ( kg) of proppant per lateral foot This translates to million pounds (7-9 million kg) of sand in an extended length lateral of 10,000 ft (3048 m) Unconventional Hydraulic Fracture Variables Clean Out Methods The Perf and Plug and the ECP methods of completion both require a drill out of the lateral prior to it being produced Run in hole with a bit and a mud motor on either coil tubing or stick tubing and drill out all of the plugs, balls, seats, proppant, etc. left behind Operation is risky and expensive Often rate limited which reduces the fluid velocity and thus the carrying capacity of the completion fluid Pump viscous pills to help carry debris out of the lateral Take small bites and make multiple wiper trips Selling point of the method which utilizes shifting sleeves in a cemented liner 101

102 Results of Unconventional Hydraulic Fracturing in U.S. Graph showing the growth % of hydrocarbons in U.S. that come from unconventionals (trillion cubic meters) (12.7) (11.3) Results of Unconventional Hydraulic Fracturing in U.S. (9.9) (8.5) (7.1) (5.7) (4.2) (2.8) (1.4) 102