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

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

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

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

2. Petrography and Diagenesis

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

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”

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

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

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

Authigenic Cements Destroy Pore Space D P Quartz Quartz Dolomite

Due to Dissolution of Grains and Cements Secondary Porosity Due to Dissolution of Grains and Cements DP 0.05 mm Depth: 7230.3 ft Grain Size: 55 mm Rock Type “A” Porosity: 12 % E.T. O'Daniel 37 5U unit

UPPER SPRABERRY FORMATION C LG P UPPER SPRABERRY FORMATION PORE PORE TYPE SIZE PT1 30-40 m Relatively Large PT2 15-30 m PT3 5-15 m PT4 Much less than 5 m PT5 Oversized up to 50 m

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

3. Petrophysics: Rock-Fluid Model

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 (7080-7195 ft). Rocks are shales and very shaly laminated lithofacies.

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

Correlation for Porosity-Permeability and Pore Throat Radius

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

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.

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.

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.

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.