Formation Damage Mechanisms

Transcription

1 Formation Damage Mechanisms FARUK CIVAN, Ph.D. Alumni Chair Professor Mewbourne School of Petroleum and Geological Engineering The University of Oklahoma 1

2 Presentation Outline How is formation damage defined? What does formation damage do? How does formation damage occur? What are the common formation damage mechanisms? How can we control formation damage? 2

3 Formation Damage An expensive headache (Amaefule et al. 1988) Requires interdisciplinary knowledge and expertise 3

4 Damage Mechanisms (Butler et al., 2000) Formation damage: Impairment of reservoir permeability by adverse processes Completion damage: Hinderence of well productivity by deposition and flow modification at and around well bore 4

5 Mechanical Skin (Formation Damage (Yildiz, 2003) Porosity and permeability variation by Fines migration and deposition Mud filtrate and fines invasion Rock compression Scales Acidizing 5

6 Near Wellbore Damage Damaged Region Non-damaged Region 6

7 Effect of Anisotropy and Stress on Damage Zone K H > K V K H < K V Well Invasion Zone 7

8 Formation Damage Indicators Permeability impairment Skin damage Decrease of well performance. 8

9 Pressure Profile and Skin P P w t > 0, s < 0 t > 0, s > 0 t = 0, s = 0 P wo P w r w r r o 9

10 Formation Damage Measure- Skin Factor w apparent s ( r ) = e ( r ) w actual r e Damaged Region r w r d Non- Damaged Region 10

11 Consequence of Formation Damage Reduction of reservoir productivity Non-economic operations 11

12 Formation Damage Not necessarily reversible (Porter, 1989) What gets into porous media does not necessarily come out (Porter, 1989) Avoid formation damage than to restore it 12

13 Potential Sources of Formation Damage During History of Well 1. Drilling (emulsion block, wettability change, mud damage, mechanical damage) 2. Cementing (ph change, scale formation) 3. Perforating 4. Completion 13

14 Potential Sources of Formation Damage During the History of the Well 5. Workover 6. Gravel packing 7. Production 8. Stimulation 9. Fluid injection 14

15 Common Formation Damage Mechanisms (Bennion, 1999, Bennion and Thomas, 1991, Bishop, 1997) 1. Fluid-fluid incompatibility (emulsion generation, etc.) 2. Rock-fluid incompatibility (clay swelling, etc.) 3. Fines invasion and migration (particles, etc.) 15

16 Common Formation Damage Mechanisms (Bennion, 1999, Bennion and Thomas, 1991, Bishop, 1997) 4. Phase trapping and blocking (water entrapment in gas reservoirs) 5. Adsorption and wettability alteration 6. Biological activity (bacteria, slime production). 16

17 What do Rocks contain? (Bucke & Markin,1971, Ezzat,1990, Mancini,1991) 1. Mineral oxides (SiO 2, Al 2 O 3, etc.) 2. Swelling and non-swelling clays (detrital and authigenic) 3. Other substances (mud, cement, and debris) 17

18 Clay Minerals Crystalline minerals described as hydrous aluminum silicates 1. Kaolinite group (breaks apart into fine particles) 2. Smectite or montmorillonite group (water sensitive and expandable) 18

19 Clay Minerals 3.Illite group (plugs pore throats) 4.Mixed-layer clay minerals (breaks apart in clumps and form bridges across pores) 19

20 Extraneous Materials Foreign materials introduced during: Drilling and completion of wells Workover operations Enhanced recovery processes 20

21 Externally Introduced Particles Fluid loss control materials Bentonite Clays Mud weighting materials Calcium carbonate Barite Hematite 21

22 Externally Introduced Particles Pore bridging materials Fibers Resins Silica Calcium carbonate Injection water materials Bacteria Sand, clay, silt, asphaltene, wax, polymers Materials produced by corrosion of tubing Particulate matter produced by drilling 22

23 Porous Media Realization Network Model Leaky-tube Model (Civan, 2003) 23

24 Bundle-of-Leaky-Capillary- Tubes Model of Porous Media 24

25 Porosity-Permeability Alteration 1.0E E-12 Permeability, K, md 1.0E E E E E E Porosity, φ, fraction 25

26 Formation Damage Causing Rock-Fluid Interactions (Bennion and Thomas, 1994) 1. Mobilization, migration, and deposition of fine particles (internal or external) 2. Alteration of porous media and particle surface (absorption, adsorption, wettability change, and swelling) 26

27 Formation Damage Causing Rock-Fluid Interactions (Bennion and Thomas, 1994) 3. Other processes (mud fluid imbibition, grinding and mashing of solids, surface glazing) 27

28 Deposition Within Porous Formation DEPOSITION ENTRAINMENT FLOW TYPICAL HYDRAULIC TUBE 28

29 Shock Phenomena Causing Particle Detachment and Mobilization Three Important Criteria: Critical salt concentration Critical interstitial fluid velocity Critical temperature 29

30 Salinity Shock CSC : Critical salt concentration (Khilar( and Fogler,, 1983) Basal Spacing Civan (2000, 2001) Salt Concentration 30

31 Particle swelling 31

32 Critical Mobilization Velocity Gruesbeck and Collins (1982) 32

33 Particles experience more fluid shear in tortuous paths (Civan, 2006) 33

34 Temperature Shock Gupta and Civan (1994) 34

35 Small Particles Deep-bed Filtration Fluid velocity decreases with radial distance Reservoir region of well influence Well Hydraulic fracture Critical velocity Tortuous flow path Suspended particles Immobile particles 35

36 Particle Deposition Mechanisms Surface deposition Pore throat plugging Pore filling and internal cake formation 36

37 Valve effect of pore throats Chang and Civan (1997) and Ochi and Vernoux (1998) 37

38 Pore Throat Plugging Deposition D p D t ( BRe ) 1 β = β = A e p + C cr D D t p 0 Non-bridging Bridging Re p = c p ud p ( µφ ) 38

39 Dislodgement/deposition at Pore Throats Flow Reversal 39

40 Particle aggregation kinetics Diffusion-limited Reaction-limited 40

41 Medium to Large Particles External Cake Formation Large particles (Screening) Medium particles (Bridging) 41

42 Filter Cake Distribution r, radial direction Vertical Well Radial filter cake Homogeneous thick 42

43 Filter Cake Distribution Horizontal Well Rotation effect Gravity effect Non-uniform thick Gravity direction 43

44 Perforated Wells y Uninvaded Zone Filter Cake Invaded Zone Wellbore Perforation x 44

45 Hydraulically-Fractured Wells y Uninvaded Zone Invaded Zone Wellbore Perforation x Filter cake 45

46 Conditions Favorable for Sand Production (Hayatdavoudi, 1999) 1. Lack of cementation and loss of mechanical integrity 2. Small grain size 3. Weak consolidation and compaction 46

47 Conditions Favorable for Sand Production (Hayatdavoudi, 1999) 4. Rising water table Higher water cut Petrophysical alteration 5. Grain buoyancy effect 6. High flow rate and low pore fluid pressure 47

48 Sand Liquefaction Criterion (Hayatdavoudi, 1999) Friction shear-stress > Critical-shear-stress y τ θ x 48

49 Massive Sand Production (Geilikman and Dusseault, 1994, 1997) Yielded Zone Intact Zone r w R(t) r e 49

50 Practical Results q s 0 0 Sand Production Rate t q q f o t Fluid Production Improvement q o = flow rate without sand production q f = flow rate with sand production 50

51 Sand Control Methods (JPT, 1995) 1. Sand control is necessary for weak formations and high water influx. 2. Hydraulic fracturing reduces the flow rate and pressure gradient to prevent sanding. 51

52 Sand Control Methods (JPT, 1995) 3. Zone perforation and fracpacking (gel or water packing) 4. Resin injection for chemical consolidation 5. Gravel packs, screens, and slotted liners to filter sand. 52

53 Sand Control Methods (JPT, 1995) 6. Dropping the water level by special completion techniques (Hayatdavoudi, 1999): a) Horizontal wells b) Water production from below the oil/water contact c) Reducing water-coning. 53

54 Wettability Definition: 1. Preferential affinity of solid to fluid phases 2. Tendency of fluids to spread over solid surface 54

55 Contact Angle θ < 90 o, strong wettability θ > 90 o, weak wettability θ 90 o, intermediate wettability θ 55

56 Wettability Effect (Durand and Rosenberg, 1988) Water-wet (Clay/Oil) Oil-wet (Clay/Oil) 56

57 Wettability Alteration Oil-wet Site Oil adsorbed Water-wet Site Water adsorbed Pore Space WI Oil Adsorption (mg/g) 57

58 Wettability Wettability alteration can be detected by capillary pressure measurement P c o F 100 o F 58

59 Particle Migration in Multi-phase Flow 59

60 Formation Damage Causing Fluid-Fluid Interactions (Amaefule, 1988, and Masikewich and Bennion, 1999) Emulsion blocking Inorganic deposition Organic deposition 60

61 Liquid Phase Entrapment Filtrates Water based Oil based Condensates Water Hydrocarbon 61

62 Phase Entrapment (Bennion, 2003) Wetting phase Wetting phase Wetting phase Non-wetting phase 62

63 Relative Permeability Alteration and Liquid Block (Keelan and Koepf, 1977) Before damage Kr vs. Sw After damage Kr vs. Sw Shrinking of mobile fluid saturation range 63

64 Natural and Induced Scale Damage (Shaughnessy and Kline, 1983) 2+ 2HCO CaCO CO H 0 3 3( s) 2( g ) 2 ( l) Ca Add incompatible fluid Dissolved HCO - 3 mol/lt Natural Induced 0 Dissolved Ca 2+ 64

65 Calcite solubility in water (Segnit et al., 1962) 2+ Ca + 2HCO3 CaCO3( s) + H 2O + CO2( g ) Calcite Solubility g/kg solution 150 o C 200 o C p CO2 65

66 Saturation Index (Schneider, 1997) SI = log10 K K ap sp SI > 0 SI = 0 SI < 0 Supersaturated Saturated C, Concentration of aqueous solution, mol/l Undersaturated 66

67 Organic Deposition 1. Paraffins (dissolved in oil) 2. Asphaltenes (undissolved, but suspended as a colloid in oil) 3. Resins (peptizing agent, dissolved in oil, help suspend asphaltene in oil) 67

68 Organic Deposition 4. Wax: A combined deposit of paraffins, asphaltenes, resins, mixed with clays, sand, and debris (dissolved in oil) 68

69 Asphaltene and Wax Phase Behavior (Leontaritis, 1996) Liquid+Solid Region (Mostly pressure dependant) Upper deposition boundary Liquid Saturation Bubble-Point Line Liquid+Solid+Vapor Region (Pressure and Composition dependant) Pressure Lower deposition boundary Liquid + Vapor Temperature 69

70 Electrokinetic Effect (Mansoori, 1997) Pipe or Capillary Tube Negative Charge Streaming Potential Difference Asphaltene deposits Positive Charge Asphaltene is positively charged Oil phase is negatively charged 70

71 Evaluation of Common Formation Damage Problems (Keelan and Koepf, 1977) Pore blocking by drilling, completion, workover, and injection fluids Clay hydration, swelling, dispersion, and pore blocking resulting from clay-water reactions 71

72 Evaluation of Common Formation Damage Problems (Keelan and Koepf, 1977) Liquid block resulting from extraneous water introduction during drilling, completion, and workover Caving and sand production 72

73 Analysis of Core Damage Data Permeability L K u L = µ P 73

74 Constant-Pressure Difference Test 1.0 Permeability ratio, K/K o 0 0 P-large PV-injected P-small 74

75 Core Plugs Wafers (Acid soak Experiments) 1-inch diameter 0.25-inch thick 75

76 A Simple Linear Core Flow Testing Set-up (Doane et al., 1999) Pressure Transducer Fluid Reservoir Core Holder Core Effluent Displacement Pump Annulus Pump Fluid collector 76

77 Annular Flow Tester (Saleh et al., 1997) Effluent Fluid Reservoir Radial Outward Flow Fluid collector Pump 77

78 Drilling of Wells (Yao and Holditch, 1993) Mud In Mud Out Mud Invasion Uninvaded Zone 78

79 Depth of Filtrate Invasion Water mud Depth of Invasion Low-colloid oil mud Oil mud Time 79

80 Saturation Profiles for Mud Filtrate Invasion (Yao and Holditch, 1993) Wellbore Mud Cake Filtrate S w = S wc t 1 t 2 t 3 S w = 1- S or r w Radial Distance r e 80

81 Dynamic Mud Tester Pump Mud Reservoir Mud Filtrate Core Linear Flow Effluent Fluid collector 81

82 Hydraulic Fracturing Fluids (Keelan and Koepf, 1977) Water-block Solids invasion Leak-off and spurt loss Clay hydration 82

83 Fracture Flow Tester (Doane et al., 1999) Fracture Flow 83

84 Mitigation Methods (Masikewich and Bennion, 1999) Emulsion blocking: Apply demulsifier Precipitates: Apply wax, scale, and alkaline control Migrating clays: Apply cation Swelling clays: Apply cation or polymer 84

85 Mitigation Methods (Masikewich and Bennion, 1999) Phase trapping and blocking: Apply alcohol, oil, and interfacial surface tension (IFT) reducer Wettability alteration: Apply surfactant Solid invasion: Apply cake inducing agent 85

86 Treatment Fluids (Thomas et al., 1998) Major Proper Additives Treatment = Treating + to control Fluid Chemical further damage 86

87 Treatment Fluids (Thomas et al., 1998) Additives can control: Corrosion Sludge formation Emulsion formation Organic and inorganic precipitation 87

88 Treatment Fluids (Thomas et al., 1998) Additives can control Homogeneity Clay stabilization Interfacial tension 88

89 Fracture Stimulation (Keelan and Koepf, 1977) Hydraulic fracturing Bypass damaged region 89

90 Bypassing Damage by Hydraulic Fracturing z y x 90

91 Completion Techniques Open-hole completions Cavity completions Hydraulic fracturing Frac-and-packs Horizontal wells 91

92 Reservoir Fluid Pattern- Open Hole vs. Perforated Cased Hole Well Perforation Invasion Zone Fluid goes through damaged zone Fluid bypasses damaged zone 92

93 Perforated Well Flow Efficiency (Chen and Atkinson, 2001, Yildiz, 2002) Wellbore radius Shut density Shut angle Perforation depth Perforation diameter Crushed zone thickness Damaged zone thickness Reservoir anisotropy Crushed zone 93

94 Partial Completion and Deviation (Al Qahtani and Al Shehri, 2003) Perforated Zone h c H z c Elevation to mid point L 94

95 Horizontally Fractured Well 95

96 Vertically Fractured Well 96

97 Frac-and-Pack Completion 97

98 Multi-lateral Wells Completion 98

99 Damage Tolerance of Completion Techniques from Most to Least (Jahediesfanjani and Civan, 2005) Long horizontal wells Short horizontal wells Horizontally fractured wells Cavity completions Vertical wells Frac-and-Pack completions Fractured wells Vertical wells 99

100 Final Remarks Formation damage mechanisms vary depending on the well operation types and reservoir and fluid conditions. Oil and gas recovery can be enhanced by minimizing and controlling of formation damage. 100

101 Thank you for your attention Questions? Discussions? Comments? 101