Geologic Characterization of Low-Permeability Gas Reservoirs, Travis Peak Formation, East Texas

RI0204. Geologic Characterization of Low-Permeability Gas Reservoirs, Travis Peak Formation, East Texas, by S. P. Dutton, S. E. Laubach, R. S. Tye, R. W. Baumgardner, Jr., and K. L. Herrington. 84 p., 71 figs., 5 tables, 1991. Print.


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ABSTRACT
The Lower Cretaceous Travis Peak Formation contains an estimated 6.4 trillion cubic feet (Tcf) of gas in place in East Texas and North Louisiana. Advanced technology will be needed to maximize recovery from this low-permeability ("tight") gas sandstone. This report focuses on the contribution of geology to understanding and efficiently developing the complex gas reservoirs in the Travis Peak Formation in East Texas. Geologic characterization of the Travis Peak Formation included three major areas of study: (1) interpretation of stratigraphy and depositional systems, (2) evaluation of reservoir sandstone diagenesis, and (3) analysis of the structural history and current structural setting.

Depositional systems of the Travis Peak Formation in this region include (1) a braided to meandering fluvial system that composes most of the section, (2) a deltaic system that is interbedded with and encases the distal part of the fluvial system, (3) a paralic system that overlies and interfingers with the deltaic and fluvial systems near the top of the Travis Peak, and (4) a shelf system that is present at the downdip extent of the Travis Peak. Reservoir geometry and quality in the systems vary because of differences in depositional processes that controlled sediment lithology, texture, and stratification, in addition to the degree of diagenesis. Thin sandstones separated by mudstones in the upper part of the formation were deposited in paralic and meandering fluvial environments. Best quality reservoirs in the upper Travis Peak occur in tidal-channel, tidal-flat, and meandering fluvial channel sandstones. In most of the lower part of the Travis Peak, sandstones are dominantly braided fluvial. Best quality reservoirs in the braided fluvial deposits exist in wide channel belts oriented parallel to depositional dip. Reservoir quality decreases at channel margins (levees), at channel tops (abandoned-channel deposits), and in interchannel areas where sediments are poorly sorted.

Petrographic studies indicate that the Travis Peak Formation contains mainly fine- to very fine grained sandstone, muddy sandstone, silty sandstone, and sandy mudstone. True claystones that could provide stress barriers to hydraulic fracture growth are rare. The sandstones are mineralogically mature, consisting of quartzarenites and subarkoses. Well-sorted sandstones had high porosity and permeability at the time of deposition, but their reservoir quality has been reduced by compaction and cementation. Cementation by quartz, dolomite, ankerite, illite, and chlorite and introduction of reservoir bitumen by deasphalting have reduced porosity to less than 8 percent and permeability to less than 0.1 md in much of the formation. Structurally deeper Travis Peak sandstones are more intensely quartz cemented than are shallower sandstones. This variability in cementation results in differences in mechanical properties, porosity, and permeability between upper and lower parts of the Travis Peak. Furthermore, differences in grain size and cementation history of fluvial and paralic sandstones have resulted in fluvial sandstones having an order of magnitude higher permeability than paralic sandstones at all depths.

Because a correspondence exists between extensive quartz cementation and fracture occurrence, abundant, open natural fractures should be expected in highly cemented sandstones. Natural fractures may contribute to production in lower Travis Peak sandstones that have very low matrix permeability. Predicting the propagation direction of hydraulically induced fractures is a key part of completion strategy, and geologic studies of core showed that borehole breakouts and drilling-induced fractures in core can be used as inexpensive and reliable methods of predicting horizontal stress directions and the direction of hydraulic fracture propagation. Hydraulic fractures propagate in directions subparallel to the east-northeast strike of the natural fractures. Thus, hydraulically induced fractures may not intersect many natural fractures. Among the effects that natural fractures can have on well treatments are increased leakoff, fracture branching, and curvature. Branching could cause high treatment pressures and detrimentally affect treatment results if not accounted for in treatment design. Geologic models indicate that natural fractures are not likely to be common in the upper Travis Peak sandstones and that special precautions for treating naturally fractured rock are not required in the upper zone. In the lower Travis Peak, however, natural fractures are common and locally are extensively developed.

Keywords: borehole ellipticity, coring-induced fractures, depositional systems, East Texas, Hosston Formation, microfractures, natural fractures, reservoir quality, sandstone diagenesis, stratigraphy, stress, tight gas sandstones, Travis Peak Formation, Texas

CONTENTS

Abstract

Introduction

Geologic Setting

Travis Peak Stratigraphy and Depositional Systems

   Methods
   Stratigraphy

   Depositional Systems

     Braided to Meandering Fluvial Depositional System

         Fluvial-channel fill

         Abandoned-charnel fill

         Floodplain

         Lacustrine

         Overbank

     Deltaic Depositional System

     Paralic Depositional System

         Coastal plain

         Marginal marine

   Shelf Depositional System

Travis Peak Paleogeographic Evolution

   Paleogeography: Time 1

   Paleogeography: Time 2
   Paleogeography: Time 3

   Paleogeography: Time 4

   Paleogeography: Time 5

   Early Travis Peak Deposition (Times 1-3)

   Late Travis Peak Deposition (Times 4-5)

Hydrocarbon Production

Diagenesis

   Methods
   Travis Peak Composition

     Framework Grains

     Matrix

   Cements

           Quartz

           Authigenic clay minerals

           Carbonate cements
           Solid hydrocarbons

           Other authigenic minerals
   Porosity

Organic Geochemistry

Burial and Thermal History

Diagenetic History

Reservoir Quality

   Methods

Porosity Distribution

   Permeability Distribution

   Controls on Porosity and Permeability

     Compaction

     Cement

     Secondary porosity

     Overburden pressure

     Depositional environment

   Conclusions

Natural Fractures
   Methods

   Fracture Abundance

   Fracture Attitudes

   Fracture Morphology and Dimensions

   Characterization of Fractures with Borehole-Imaging Logs

   Contrasts and Similarities between Travis Peak and Cotton Valley Fractures

   Petrology of Travis Peak Fracture-Filling Minerals

   Fluid-Inclusion Microthermometry

   Relationship between Fracture Development and Diagenesis

   Microfractures

   Significance of Microfractures.

   Interpretations of Fracture Origins

   Applications to Reservoir Studies

Stress Directions

   Regional Stress Patterns

   Borehole Breakouts

     Overview

     Wellbore Elongation Measurement.

  Interpretation of Wellbore Ellipticity

   Strain Measurements on Core

   Massive Hydraulic Fracture Treatments

   Fractures Created in Stress Tests

   Drilling-Induced Fractures

   Application to Reservoir Development
Engineering Implications
   Reservoir Characterization

   Reservoir Quality

   Structure

Conclusions

Acknowledgments

References

Figures

1. Location of study area and wells

2. Stratigraphic nomenclature, East Texas Basin

3. Structure-contour map, top of Travis Peak Formation

4. Isopach map of Travis Peak Formation in East Texas-West Louisiana study area

5. Location of East Texas counties and West Louisiana parishes included in study of stratigraphy and depositional systems
6. Representative log of Travis Peak Formation from eastern Panola County, Texas

7. Cored intervals plotted by depth below top of Travis Peak

8. Stratigraphic cross section A-A'

9. Stratigraphic cross section B-B'

10. Stratigraphic cross section C-C'

11. Percent-sandstone map, combined lithostratigraphic units 1 through 3

12. Percent-sandstone map, combined lithostratigraphic units 4 and 5

13. Core description of Prairie Mast No. 1-A well, Nacogdoches County, Texas

14. Clay-clast conglomerate developed at base of a fluvial charnel

15. Planar crossbedded fine- to medium-grained fluvial-channel-fill sandstone

16. Small-scale, current-ripple-laminated, fine-grained fluvial-channel-fill sandstone

17. Burrowed, muddy fine-grained abandoned-channel-fill sandstone

18. Densely rooted and burrowed floodplain sandy mudstone

19. Current-ripple-laminated, fine-grained sandstone sharply overlying a laminated and soft-sediment-deformed sandy mudstone

20. Slumped muddy fine-grained sandstone deposited in an overbank environment (levee or splay)
21. Wavy- and lenticular-bedded muddy fine-grained sandstone deposited in a lake or bay

22. Burrowed to bioturbated, wavy-bedded and ripple-laminated muddy sandstone

23. Core description of Clayton Williams Sam Hughes No. 1 well, Panola County, Texas

24. Hypothetical paleogeographic reconstructions of five time periods during Travis Peak deposition

25. Structure-contour map, top of Cotton Valley Formation, North Appleby field

26. Gamma-ray and resistivity logs and informal nomenclature, Travis Peak Formation, SFE No. 2 well, North Appleby field

27. Stratigraphic cross section D-D' illustrating the occurrence and geometry of channel-belt sandstones in lower Travis Peak, core zone 4, North Appleby field

28. Net-sandstone and log-pattern map, Sandstone X, lower Travis Peak, core zone 4, North Appleby field

29. Stratigraphic cross section D-D' illustrating the occurrence and geometry of channel-belt sandstones in upper Travis Peak, core zone 1, North Appleby field

30. Net-sandstone map, Sandstone B, upper Travis Peak, core zone 1, North Appleby field

31. Photomicrograph of quartz cement in a clean Travis Peak sandstone

32. Moderate amount of quartz cement in a sample that retains primary porosity

33. Quartz cement volume in clean sandstones as a function of present burial depth
34. SEM photograph of fibrous illite filling a secondary pore formed by the dissolution of a feldspar grain

35. SEM photograph of a rosette of authigenic chlorite from a depth of 7,383.6 ft (2.250.5 m) Mobil Cargill No. 15 well

36. SEM photograph of fibrous illite in a sample that was freeze dried to preserve the original morphology of the long, delicate fibers

37. SEM photograph of matted illite fibers in an extraction-dried sample taken immediately adjacent to the sample shown in figure 36

38. Rippled sandstone with reservoir bitumen highlighting ripple faces, from a depth of 8,240.0 ft (2,511.6 m), Stallworth Everett No. 2-B core

39. Plot of reservoir bitumen volume with depth below top of Travis Peak

40, Photomicrograph of reservoir bitumen in primary porosity at a depth of 8,386.7 ft (2,556.3 m), ARCO Phillips No. 1 core
41. Burial-history curves, tops of Travis Peak Formation, Cotton Valley Group, Bossier Shale, and Smackover Formation. Ashland SFOT No. 1 and Sun D. O. Caudle No. 2wells
42. Burial-history curve, Ashland SFOT No. 1 well, showing when major diagenetic events may have occurred

43. Plot of porosimeter porosity versus depth for 1. 687 Travis Peak sandstones

44. Plot of porosimeter porosity versus depth for 89 clean Travis Peak sandstones

45. Plot of secondary porosity measured in thin section versus depth in clean fluvial sandstones

46. Plot of stressed permeability versus depth for 649 Travis Peak sandstones
47. Plot of stressed permeability versus depth for 66 clean Travis Peak sandstones

48. Plot of unstressed permeability versus depth for 176 clean Travis Peak sandstones

49. Plot of porosimeter porosity versus stressed permeability for 649 Travis Peak sandstones

50. Comparison of sandstones from similar depositional environments at different present burial depths

51. Inverse relationship between total cement volume and unstressed permeability in clean sandstones

52. Inverse relationship between quartz cement volume and unstressed permeability in clean sandstones

53. Total cement volume in clean sandstones as a function of present burial depth

54. Core gamma-ray log, core profile, fracture distribution, and environmental interpretation, cores 1 through 3, Holditch SFE No. 2 well

55. Core gamma-ray log, core profile, fracture distribution, and environmental interpretation, cores 9 through 15, Holditch SFE No. 2 well

56. Strikes of natural fractures in Travis Peak sandstones

57. Two views of an open fracture in the Holditch SEE No. 2 core, from a depth of 9,842 ft (3,000 m)

58. Fractures in reservoir rocks imaged with Formation Microscanner and borehole televiewer logs

59. Photomicrograph showing superposition of infilling mineral phases in Travis Peak fracture
60. Photomicrographs of fluid inclusions in Travis Peak quartz-filled fractures

61. Homogenization temperatures from vein quartz and calcite

62. Homogenization temperature versus salinity and final melting temperature

63. Preferred orientation of closed microfractures in a single well

64. Sketch of a hydraulic fracture induced by open-hole stress test 2, Holditch SFE No. 2 well

65. Box plots of stress-direction indicators. Travis Peak Formation

66. Stress-direction indicators, Holditch Howell No. 5 well, drilling-induced fractures in the same core interval, and stereographic projection of fractures created during hydraulic fracture treatment

67. Map of seven wells with polar plots of H for wellbore ellipticity

68. Plan views and sections of ellipticity logs for in-gauge borehole, borehole breakout, and washout

69. Plot of wells showing intervals in Travis Peak Formation covered by ellipticity logs in this study

70. Plots of ellipticity ratio versus depth below Kelly bushing
71. Plots of ellipticity ratio versus elevation relative to top of Travis Peak Formation

Tables

1. Travis Peak cores used in this study

2. Linear regression correlation coefficients between log stressed permeability and various textural and mineralogic parameters in 66 clean Travis Peak sandstones

3. Distribution of average porosity and permeability by sedimentary structure

4. Differences in coring-induced and natural fracture strike in continuous core intervals

5. Isotopic composition of vein quartz and vein carbonate


Citation
Dutton, S. P., Laubach, S. E., Tye, R. S., Baumgardner, R. W., Jr., and Herrington, K. L., 1991, Geologic Characterization of Low-Permeability Gas Reservoirs, Travis Peak Formation, East Texas: The University of Texas at Austin, Bureau of Economic Geology, Report of Investigations No. 204, 84 p.