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

			Figure 1. Three modes of fluid saturation.
			Figure 2. Primary vs. secondary porosity.
			Figure 3. Quantification of microporosity using thin section and SEM/BSE.
			Figure 4. Mercury Injection Capillary Pressure tests (MICP) are used to link pore-throat size distribution, petrographic analysis, and potential maximum hydrocarbon pore volume.
			Figure 5. Tight Gas Resource Map. Detailed reservoir characterization using core, logs, and production data confirmed the primary controls on reservoir quality. This information was then used to create a map which differentiates Conventional vs. Tight-Gas resources to optimize field development.