표제지

제출문

요약문

목차

제1장 연구개발과제의 개요 14

제1절 연구의 목적 14

제2절 연구의 필요성 15

제3절 연구의 목표 16

제4절 연구의 내용 및 범위 17

제2장 국내외 기술개발 현황 18

제1절 국외 현황 18

제2절 국내 현황 19

제3장 연구개발 수행 내용 및 결과 20

제1절 서론 20

제2절 이질사암 저류층의 암석물리 21

제3절 근원암 유기물 분석 45

제4절 한계저류층 탄성파 속성 분석 기법 52

제5절 한계저류층 물성 특성화 기술 77

제6절 코어링 및 코어분석 기법 99

제7절 결론 145

제4장 목표달성도 및 관련분야에의 기여도 146

제5장 연구개발결과의 활용계획 147

제6장 연구개발과정에서 수집한 해외과학기술정보 148

제7장 참고문헌 149

Table 3-2-1. Average mineralogy of shale from hydrocarbon producing basins 23

Table 3-2-2. Chemical and physical characteristics of clay mineral. 29

Table 3-2-3. Habit of authigenic clays in sands. 30

Table 3-2-4. Effect of interlayer cations and humidity on smectite swelling. 33

Table 3-2-5. Radio activity in several minerals (Modified from Edmundson and Raymer, 1979). 39

Table 3-3-1. TOC, TN, δ13C and δ15N contents(이미지참조). 48

Table 3-5-1. Well thickness data. 87

Table 3-5-2. Permeability from well testing. 93

Table 3-6-1. Trouble-shooting guide for coring operations (modified from Baker Hughes INTEQ) 107

Table 3-6-2. Liner and disposable inner barrel temperature limitations. 114

Table 3-6-3. lists some conventional inner barrel coring systems and their characteristics. 114

Table 3-6-4. Core bit selection guide. 116

Table 3-6-5. The relative hardness of some core bit materials. 118

Table 3-6-6. Trask sorting coefficients and classifications. 141

Fig. 1-4-1. Annual project work plan. 17

Fig. 3-2-1a. Clean sand reservoir (porosity ＝ 38 %, Permeability ＝ 5,500 mD). 21

Fig. 3-2-1b. Shaly sand reservoir (Porosity ＝ 29%, Permeability＝500mD). 22

Fig. 3-2-2. Understanding of shale in petroleum industry. 22

Fig. 3-2-3. Authigenic shale in sandstone reservoirs (S＝smectite, D＝dolomite). 23

Fig. 3-2-4. Tetrahedral and octahedral units of clay minerals. 24

Fig. 3-2-5. Variation in ionic radius. 25

Fig. 3-2-6. Structural unit of clay minerals. 26

Fig. 3-2-7. Microphoto of kaolinite. 26

Fig. 3-2-8. SEM photos of pore-lining or -bridging illite (I) in the pore throat (PT) and adjacent pore (P) of a sandstone reservoir. 27

Fig. 3-2-9. Authigenic crystals of chlorite in a sandstone pore : microporous chlorite Rosettes. 28

Fig. 3-2-10. Glauconite grains. 29

Fig. 3-2-11. Cations concentrated on clay surface. 31

Fig. 3-2-12. Diffuse or Gouy layer of clay mineral 31

Fig. 3-2-13. Thickness of Sb layer. 32

Fig. 3-2-14. Effect of water salinity on smectite swelling. 33

Fig. 3-2-15. Usual contractor method for laboratory determination of CEC. 34

Fig. 3-2-16. Alternative method for CEC: "Multiple Salinity." 35

Fig. 3-2-17. Relation of CEC to surface area. 35

Fig. 3-2-18. Gamma Ray Log for several kinds of rock. 37

Fig. 3-2-19. Spectral Gamma Ray in Texas. 41

Fig. 3-2-20. Interval A is a single reservoir High GR streaks at 9100' and 9140' are "hot" sands: they have high U, low K and Th. 42

Fig. 3-2-21. Log-based clay mineral identification from K-Th response. 42

Fig. 3-2-22. SP log for the calculation of shale volume. 44

Fig. 3-2-23. Several reaction of SP log. 44

Fig. 3-3-1. Relationship between TOC and total nitrogen contents. 49

Fig. 3-3-2. Relationship between TOC and δ13C contents.(이미지참조) 49

Fig. 3-3-3. Relationship between δ13C and total nitrogen contents.(이미지참조) 50

Fig. 3-3-4. Relationship between δ13C and δ15N contents. 50

Fig. 3-3-5. Origin of organic matter various regions on the basis of δ13C-TOC/TN diagram. 51

Fig. 3-4-1. Seismic section and interpretation. Regional unconformity (continuous, high-amplitude reflector), fault, and channel-fill complex are defined in the section. 53

Fig. 3-4-2. Seismic facies and potential geologic fills, calibrated by well log interpretation (West et al., 2002). Typical deewater seismic facies can be interpreted to represent the stacking pattern. 54

Fig. 3-4-3. (A) A high-amplitude reflector is automatically traced. (B) The reflector is manually picked on the hanging-wall block of a NE-trending fault. 55

Fig. 3-4-4. Gridded surfaces with different grid size and algorithm. (A) Input data. (B) Gridded surface calculated from minimum curvature method. (C) and (D) Gridded surface calculated from convergent interpolation method. Note that contour is relatively smooth in the surface... 58

Fig. 3-4-5. NE-trending faults are well recognized in different attribute map: (a) time structure, (b) time slice, (c) variance, (d) azimuth, (e) local dip, (f) chaos, (g) envelope (normalized amplitude), (h) instantaneous frequency, and (i) instantaneous phase. Subordinary fault are locally... 59

Fig. 3-4-6. Small-scaled faults detecting from seismic section and variance map. (A) Faults with slight displacement is recognized in the section, but poorly traceable for a short distance. (B) NE-trending lineament is visible in variance map and used as a guide to the fault detection. 61

Fig. 3-4-7. (A) Seismic amplitude image. (B) Co-rendered amplitude and coherence image (Modified from Posamentier et al., 2007). The images well display deep-water turbidite channels and related depositional elements. ACH ＝ abandoned channel; CH ＝ channel; FL ＝ flood plain; PBA ＝... 62

Fig. 3-4-8. Generalized concept of sequence stratigraphy (After http://egeology.blogfa.com/post-100.aspx#Scene_1) 63

Fig. 3-4-9. Vertical stacking of systems tract and depositional environments (After http://www.uga.edu/strata/sequence/tracts.html). 64

Fig. 3-4-10. Velocity model for multi-layer depth conversion. (A) Average velocity. (B) Interval velocity assigned to each layer. (C) A separate velocity model is built for each layer, including velocity versus depth function. 65

Fig. 3-4-11. Example of horizon-based attributes illustrating deepwater depositional environments (After Posamentier et al., 2007). 66

Fig. 3-4-12. Displays of various seismic attributes: (A) reflectivity, (B) azimuth, (C) dip, (D) instantaneous phase, (E) variance, (F) chaos, and (G) flatness, and (H) instantaneous frequency. 67

Fig. 3-4-13. Time slices through (A) a seismic and (B) coherence data volumes (After Chopra and Marfurt, 2005). Note intense fractures to the right. 68

Fig. 3-4-14. Example of interpretation of lineations corresponding to subtle faults carried out on the curvature horizon slice. The lineation interpretation is carried out on three separate compartments as distinguished by the two main fault (After Chopra et al., 2007). 69

Fig. 3-4-15. Example of textural attributes and conventional seismic attributes in map view at the same stratigraphic level (After Chopra, 2008). 70

Fig. 3-4-16. Distribution of sand (blue) and shale (green and yellow) resulting from different simulation method. For location of the section, see Fig. 3-4-17. (A) 3D grids and upscaled lithofacies logs overlaid with gamma-ray curves. Facies distribution is generated from (B) Sequential... 75

Fig. 3-4-17. Horizontal slice of facies model created from (A) Sequential Indicator Simulation (SIS), (B) kriging(krigging), (C) truncated Gaussian simulation, and (D) object-based simulation methods. Note sinuous channel bodies in object-based simulation. 76

Fig. 3-5-1. Variogram calculation in one dimension with regular space. 78

Fig. 3-5-2. General spherical function model. 79

Fig. 3-5-3. Spatial relationship in point kriging calculation. 81

Fig. 3-5-4. Spatial relationship in block kriging calculation. 82

Fig. 3-5-5. Well location map. 84

Fig. 3-5-6. Well location with reservoir top. 85

Fig. 3-5-7. Variogram plot for grid top map, (a) before fitting, (b) after fitting. 86

Fig. 3-5-8. Map for top of the reservoir using ordinary kriging. 86

Fig. 3-5-9. Variogram plot for grid thickness map, (a) before fitting, (b) after fitting. 88

Fig. 3-5-10. Map for thickness of the reservoir using ordinary kriging. 88

Fig. 3-5-11. Thickness map with simulation grid defined, (a) 2D, (b) 3D. 89

Fig. 3-5-12. Logging chart of well 01-12. 90

Fig. 3-5-13. Pre-matched variogram plot for porosity, (a) horizontal, (b) vertical. 90

Fig. 3-5-14. Post-matched variogram plot for porosity, (a) horizontal, (b) vertical. 91

Fig. 3-5-15. 2-dimensional porosity map using SGS. 91

Fig. 3-5-16. 3-dimensional porosity map using SGS. 92

Fig. 3-5-17. Post-matched variogram plot for permeability(permebility), (a) horizontal, (b) vertical. 93

Fig. 3-5-18. 2-dimensional permeability map by porosity correlation and well test permeability. 94

Fig. 3-5-19. 2-dimensional permeability map by only porosity correlation. 94

Fig. 3-5-20. Pressure variation map. 96

Fig. 3-5-21. Oil saturation variation map. 97

Fig. 3-6-1. The petrophysical life cycle 101

Fig. 3-6-2. A typical organization chart showing the necessary members for planning a successful coring job. 102

Fig. 3-6-3. Sampling schemes for coring fluid invasion / tracer studies. 109

Fig. 3-6-4. A conventional bottomhole coring assembly. 110

Fig. 3-6-5. Operation of a conventional core barrel. 111

Fig. 3-6-6. Core bit nomenclature (modified from Baker Hughes INTEQ). 115

Fig. 3-6-7. Core invasion mechanisms (after Rathmell et al., 1990). 118

Fig. 3-6-8. Comparison of face (conventional) versus low-invasion coring fluid discharge characteristics (after Rathmell et al., 1990). 119

Fig. 3-6-9. Some conventional core catchers (modified after Security DBS). 121

Fig. 3-6-10. A full-closure core catcher activation assembly. 122

Fig. 3-6-11. A full-closure core catcher. 123

Fig. 3-6-12. A wireline-retrievable core barrel : (a) drilling mode, and (b) coring mode. 124

Fig. 3-6-13. The pressure-retained core barrel : (a) coring mode, and (b) activation of ball valve for pilling out of the borehole. 125

Fig. 3-6-14. The sponge core barrel (courtesy of Security DBS). 126

Fig. 3-6-15. The gel coring and preservation assembly : (a) prior to coring, inner barrel closed before core encapsulation, (b) gel release valve opens, and (c) gel encapsulation and core preservation. 127

Fig. 3-6-16. A general medium-radius wellbore path. 128

Fig. 3-6-17. The high angle/horizontal core head assembly. 128

Fig. 3-6-18. A stabilized coring assembly with a survey tool and non-magnetic drill collars. 129

Fig. 3-6-19. Orientation tool and borehole axes for a horizontal wellbore. 130

Fig. 3-6-20. Core section with scribes and a Master Operation Line (MOL) marked to assist in accounting for inner core barrel rotation. 130

Fig. 3-6-21. An electronic survey instrument at surface. 131

Fig. 3-6-22. The percussion sidewall coring tool and schematic of the gun and core barrel. 134

Fig. 3-6-23. The rotary or mechanically-drilled sidewall coring tool. 135

Fig. 3-6-24. The high-temperature sidewall core retort. 138

Fig. 3-6-25. The Summation-of-Fluids (SOF) material balance method related to fluid and rock components. 139