1. Geological and Petrophysical Analysis Of Reservoir Cores
Upper Spraberry Formation
Claudio J. Saleta
New Mexico Petroleum Recovery Research Center
New Mexico Institute of Mining and Technology

2. Outline
1. Introduction
2. Petrography and Diagenesis
3. Petrophysics: Rock-Fluid Model
4. Conclusions

3. 1. Introduction
The objective of this study is to develop a detailed geological characterization of reservoir and non-reservoir rocks.
This investigation provides the framework for further studies:
Log Analysis
Cut Off values and Net Pay Determination
Reserve Calculation
Fluid Transfer Studies
Rock-Fluid Parameters for Modeling and Simulation

4. Introduction (cont.)
The outcome of this study is a rock-fluid model which, in conjunction with the fracture model found in a parallel investigation, provides a much- improved characterization of the Spraberry reservoir.
Parameters under study:
Matrix Composition Grain Density
Cements Sw
Rock-matrix porosity Wettability
Permeability Capillary pressure

5. 2. Petrography and Diagenesis

6. SMALL SCALE LITHOFACIES
Six Rock Types were observed in thin sections from Spraberry Formation core samples.
Petrographic data are related to petrophysical measurements of core plugs to build a rock-fluid model.
Each Rock Type possesses different:
pore geometry
mineralogical composition
fluid flow characteristics

7. Six Spraberry Rock Types
Very Fine Sandstone and Coarse Siltstones, Reservoir Rock : Rock Type “A”
V.F. Sandstones and Siltstones Slightly Shaly and/or Dolomitic : Rock Type “B”
Dolomite Mudstone or “Dolostone”: Rock Type “C”
Very Patchy Dolomitic Siltstones: Rock Type “D”
Shales and Very Shaly Siltstones: Rock Type “E”
Highly Laminated Siltstones: Rock Type “F”

8. THE SPRABERRY RESERVOIR ROCKS
Very fine grained sandstones and coarse siltstones
Well sorted
Very well consolidated
Composition:

9. Five factors control porosity in Spraberry Reservoir Rocks:
Original rock texture: grain size and sorting
Compactional effects: grain packing, deformation of ductile grains
Cementation: decreases overall porosity, increases tortuosity
Dissolution: produces secondary porosity, improves permeability
Fabric Rigidity: quartz rich lithologies resist compaction

10. CLAYS AFFECT POROSITY AND PERMEABILITY
Depositional clay occurs as dispersed clay particles or as laminae.
0.125mm
Shale
Laminae
Authigenic clays occur as pore linings, pore bridgings or discrete particles.
CLAYS AFFECT POROSITY AND PERMEABILITY

11. Authigenic Cements
Destroy Pore Space D P
Quartz
Quartz
Dolomite

12. Due to Dissolution of Grains and Cements
Secondary Porosity
Due to Dissolution of Grains and Cements DP
0.05 mm
Depth: ft
Grain Size: 55 mm
Rock Type “A”
Porosity: 12 %
E.T. O'Daniel 37
5U unit

13. UPPER SPRABERRY FORMATIONC LG P
UPPER SPRABERRY FORMATION
PORE PORE
TYPE SIZE
PT m Relatively Large
PT m
PT m
PT4 Much less than 5 m
PT5 Oversized up to 50 m

14. Depositional Matrix Includes:
Laminar clays
Dispersed clays
Organics
Depositional carbonate
Total Cement Includes :
Quartz overgrowths
Calcite
Dolomite
Pyrite

15. 3. Petrophysics: Rock-Fluid Model

16. Better correlation of porosity and permeability between depth 7195-7245 ft.
Pay zone (5U unit) and associated rock types.
More scattered points at shallower depth in same core well
( ft).
Rocks are shales and very shaly laminated lithofacies.

18. Similar units,however, petrophysical properties show important variations between fluorescing pay zone and non-pay zones richer in clay content.
Shift in correlation
for Sw and Porosity

21. Correlation for Porosity-Permeability
and Pore Throat Radius

22. Pore Throat Distribution for Rock Types A, C and D:
RT-A shows one dominant pore throat size at 0.66 mm.

23. Patchy dolomitic siltstone (“D”) is a rock type that falls between “B” and “F”. This category shows slightly higher grain density range and lower porosity (8.0 %) than “B” due to the higher amounts of dolomite cement present.

24. 4. CONCLUSIONS
1. Six (6) small-scale lithofacies have been
defined based on thin section, SEM, XRD, and petrophysical measurements.
2. Diagenetic processes have overprinted
original depositional characteristics. Original
rock composition exerts the most important
control on reservoir quality.

25. 3. Controls that affect reservoir quality: Quality damaging controls:
CONCLUSIONS (cont.)
3. Controls that affect reservoir quality:
Quality damaging controls:
Authigenic illite.
Argillaceous laminae.
Quartz cement as overgrowths and pressure solution.
Carbonate cements.
Initial very fine grain size.
Quality ehancing controls
Quartz rich composition (arkosic to subarkosic) make reservoir rocks relatively more resistant to compression forces and chemical wearing.
Dissolution of unstable grains and cements.

26. CONCLUSIONS (cont.)
4. Water and oil saturation data shows a close relationship between water saturation, porosity and lithology.
5. The relationship of water saturation and lithology suggests that rock type may control reservoir wettability, however this question is still unresolved.
6. Lithological variability exerts control upon the different petrophysical parameters: porosity, permeability, capillary pressure, pore throat size, and water saturation.
7. The knowledge obtained from the geological study is integrated with subsequent investigations to improve log interpretations, to understand the mechanical state of the rocks and to understand wettability of the rock matrix.