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Advances in Reservoir
Quality Assessment of Tight-Gas Sands - Links to Producibility*
Robert Klimentidis1 and Joann E. Welton1
Search and Discovery Article #40395
Posted March 16, 2009
*Adapted from extended abstract prepared for presentation at AAPG Annual Convention, San Antonio, Texas, April 20-23, 2008
1ExxonMobil Research, Houston, TX ([email protected]; [email protected])
Abstract
Quantification of porosity
types and sizes coupled with in-situ
reservoir
capillary pressure data allows one to estimate potential hydrocarbon pore volume in a hydrocarbon transition zone. Integration of this data with economic gas rate production and
reservoir
quality data (such as
sandstone
compositional and textural trends on a field or basin scale) can provide a tool to evaluate Conventional vs. Tight-Gas zones in a prospect.
Three modes of porosity
volumes can be described in sandstones: 1) movable or maximum potential hydrocarbon pore volume usually associated with intergranular
porosity
; 2) clay-bound water volume associated with detrital and diagenetic clays; and 3) other bound-water typically located in secondary pores within partially dissolved minerals (i.e., feldspars) and in detrital lithics sedimentary, volcanic, metamorphic) (Figure 1
).
The two main porosity
types found in sandstones are primary intergranular
porosity
and
secondary microporosity. Primary intergranular
porosity
occurs between detrital grains. Secondary
porosity
is located in partially dissolved minerals,
microporous detrital grains and matrix, and various diagenetic mineral cements such as clay minerals (chlorite, kaolinite, illite/smectite, illite, etc.)
(Figure 2)
. Differentiation and quantification of the various
porosity
types is an essential step in understanding and
predicting
the producibility of
tight-gas reservoirs. MicroQuant is a SEM/BSE technique which has been developed to quantify secondary microporosity from petrographic thin sections
(Figure 3
).
Conventional gas reservoirs consist predominantly of primary intergranular porosity
with
large pore-throat sizes and varying amounts of secondary
porosity
(Figure 4). In contrast, tight-gas reservoirs (i.e., a
reservoir
which requires artificial
stimulation to produce at economic rates) consist predominantly of secondary
porosity
with pore-throat sizes below 1 micron in diameter (Figure 4
).
Pore-throat size distribution is a key control on properties such as permeability, water
saturation, producible pore volume, and producibility potential (e.g., hydrocarbon flow rates and cumulative production). The ability to characterize and
quantify pore types and sizes based on mineralogical trends in a stratigraphic framework within a basin allows one to build a predictive reservoir
quality
spatial model (Figure 5
). The integration of rock quality data, pore-throat size distribution, and economic gas rates can be mapped to differentiate
Conventional vs. Tight-Gas reservoirs in a basin or field. This protocol can also be used to locate better
reservoir
quality intervals (“sweet-spots”) for optimized field development.
Figure Captions
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Figure 2. Primary vs. secondary |
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Figure 3. Quantification of microporosity using thin section and SEM/BSE. |
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Figure 5. Tight Gas Resource Map. Detailed |