Geologic Evaluation of Regional Production Trends in the Upper Cretaceous Austin Chalk

摘要

The Upper Cretaceous Austin Chalk, which extends across Texas and Louisiana, is characterized by reservoirs that produce oil,gas, and in some cases, anomalously large amounts of water. Reservoirs typically have low matrix permeability and contain natural fractures. Horizontal drilling has been used to enhance and connect these fracture systems to drain the reservoir more effectively. Although the formation contains continuous (unconventional) reservoirs, it behaves as a hybrid system, wherein varied geologic settings yield both continuous and conventional accumulations. Well data indicate that the primary Austin Chalk production trend is parallel to and just updip of the underlying Lower Cretaceous shelf edge. This trend includes Giddings and Pearsall fields, and smaller geologically similar fields. Recent drilling has expanded this belt eastward into Louisiana, as well as downdip of the paleoshelf edge; this new region of production has proved successful and includes significant fields such as Brookeland and Masters Creek. The Austin Chalk is classified as a biomicrite according to Folk (1959); it is comprised primarily of coccoliths (Dravis, 1979). This low-permeability, low-porosity rock requires large connected fracture systems to store and produce hydrocarbons. Most of the large-scale fractures are parallel to regional strike with few dip-oriented fractures (Haymond, 1991). This one-dimensional fracture network requires many smaller,localized fractures to maintain fluid flow in the reservoir. The clay component of the formation also affects fracture intensity and connectivity (Corbet et aL, 1987; Haymond, 1991). The Austin Chalk is a low-porosity, low-permeability carbonate with a dual pore system comprised of a microporous matrix and a moderately interconnected fracture system (Dawson et al., 1995). Micropores range in size from 5 to 7 μm and matrix porosity commonly ranges from 3 to 10% (Dawson et al., 1995), generally decreasing with depth (Dravis, 1979). Permeability also decreases with depth and typically ranges from 0.1 to 0.5 mD (Dawson et al., 1995). The Upper Cretaceous (Cenomanian to Turonian) Eagle Ford Formation (also termed the Eagle Ford Shale or Group) underlies the Austin Chalk and is the main source of Austin Chalk hydrocarbons. The Eagle Ford Shale possesses good to excellent source rock properties and probably generated large quantities of hydrocarbons (Liro et aL,1994). The most productive inteiyals are transgressive and condensed-interval marine shales that were deposited in oxygen-depleted environments (Dawson, 2000). Kerogen type is dominantly oil-prone, and source rock quality varies both laterally and vertically (Dawson, 2000). Total organic carbon (TOC) ranges from 1 to almost 10 wt.% (Robison, 1997). The Eagle Ford Shale entered the oil generation window sometime in the early Paleogene to early Neogene (J. Pitman, 2012,written communication), and is still generating oil in the updip part of the trend. This is critical, as this time frame postdates the creation of the fractured reservoirs in the historic trend, allowing for the emplacement of oil into these reservoirs immediately after generation. Salt movement likely began in the Late Jurassic, soon after deposition, and continued through the Late Cretaceous in the East Texas region (Pearson et al., 2010), creating salt-related structures and fractures in conventional reservoirs. Salt movement also predated Eagle Ford oil generation. Fracture density and connectivity in the Austin Chalk are highly variable,depending on proximity to faults, mineralogical variations (such as an increase in clay content), bed thickness, and the distribution of post-fracture cements (Dawson et al., 1995). Most fractures in the formation were created in response to the downwarping of the Gulf Coast basin,paired with associated faults and localized uplifts that tend to parallel regional strike of the strata (Haymond, 1991).