Impact of Source Rock on Basin-centered Gas Accumulation; Example from Bossier Sand Shale of Cotton Valley FM. in East Texas

Ahmed Chaouche
Anadarko Petroleum Corporation, The Woodlands, TX

Basin-centered gas systems (BGCS) have been defined by Law (2002) based on four main criteria of the gas reservoir: low permeability, abnormal pressure, gas saturation and no downdip water leg. These valid observations need to be completed by the fundamental role of source rocks and the impact of hydrocarbon generation on the adjacent reservoirs. This paper defines BCGS as any self-sourced, self-sealed, and self-overpressured system, and thus places more emphasis on the role of the source rocks and surrounding seals than on the nature of the reservoir rock.

BCGS can only form within closed petroleum systems. Highly generative source rocks and primary migration are critical. Hydrocarbon migration is perceived as a pervasive fluid percolating or permeating from the source rock to the surrounding pore space of the reservoir, instead of draining along preferential migration paths (carrier beds or faults). Kerogen type is not critical. However, kerogen abundance is critical and the generated fluids must be locked within the petroleum system.

For a given thermal stress, the timing of hydrocarbon generation may vary with the kerogen type. Early oil generation is expected from sulfur-rich kerogen compared to normal marine and lacustrine organic matter. Such difference in time for fluid generation is related to kerogen types (I, II, and III) and has been well documented (e.g., Espitalié et al.1977, and Hunt, 1984).

BSGS accumulations can be either overpressured or underpressured. Overpressure develops when the basin undergoes continuous burial. Organic-rich source rocks interbedded, or in contact with BCGS reservoirs, generate hydrocarbons that cause a pressure build-up in the reservoir pore space. Low quality source rocks or leaks in the system may cause an underpressured BCGS. Lean source rocks are incapable of creating overpressure because their low generative capacity results in insufficient amounts of gas (or oil) to completely fill the system and build up pressure.

Any major basin uplift events that postdate hydrocarbon generation (such as in many Rocky Mountain basins) cause fluid leakage due to a change in the integrity (reduced ductility) of the top seal as a result of cooling. Reservoir fluid shrinkage upon cooling and fluid losses through brittle seals or breached reservoirs is the major cause of the drawdown in pressure. In this case, the source-rock maturation and generation process is interrupted.

If a basin is uplifted and the hydrocarbon generation cycle is interrupted during oil generation the cooling and fluid shrinkage may induce massive precipitation of high carbon number organic compounds, most of which are asphaltenes. These asphaltenes or “bitumen” may crack to oil and gas upon sufficient heating during a new episode of burial.

Absence of a downdip water contact in BCGS is attributed to gas generation within the system that pushes formation water updip or to the edges of the basin reducing water saturation and increasing residual salt content within the formation.

In BCGS, accumulation of gas crosses over structural and stratigraphic traps. Gas is distributed independently of the porosity and permeability of the system, and sand bodies and diagenetic cells are filled according to their capillary-pressure seal capacities. These units ultimately leak if the filling pressure overcomes their seals.

Basin-centered gas accumulations are self-sealed. Water that has been expelled upward and to the edges of the basin has its own chemical composition and concentration that reacts with the water above. If a significant difference in chemical concentration exists between these waters, a sudden mineral precipitation cementing the pore space can occur all along the displaced front of water creating a basin-scale seal. If the difference in chemical concentration is not as significant, pervasive plugging of the system will occur after a large volume of fluid flow.

These mineral precipitates, such as quartz and carbonate, occur horizontally in the sandstones, siltstones, and carbonates along the thermocline, creating diagenetic seals that act as barriers for fluid expansion. Top seals that appear planar and cut across time and lithostratigraphic units may not be uniform boundary; variations can be induced by lithologic component such as shale, anhydrite beds across the basin.

Multiple top seals may be created through time within a BCGS. Continuous fluid generation and expulsion may form a series of top seals documenting periods of gas expansion in the system. In such systems, pressure/depth profiles commonly exhibit stair-step changes in pressure at the individual top seal boundaries that is characteristic of multiple stacked-pressure compartments. Generation of hydrocarbons drives fracture formation by increasing the pore fluid pressure in the first compartment, enabling hydrocarbons to leak and accumulate in the overlaying compartments. Seals between compartments act as valves, retaining and releasing gas accordingly to the leak-off point of the rock and to the healing process of the fracture network created by the gas expansion.

Overpressured BCGS are composed of fine-grained quartz, carbonates and shale. Sediments are often normally compacted until they reach the overpressure zone (OPZ) which typically occurs between 11,000 and 15,000 feet in the onshore gulf coast. Below the OPZ, compaction disequilibrium is no longer the driving mechanism in low permeability sandstones typical of most BCGS accumulations. Indeed, the lithostatic pressure created by the overburden is not supported by the matrix, in which grain to grain contact leads ultimately to pressure dissolution, but by the pressure of the fluid in the pore space. The notable absence of stylolites in the Bossier Sandstone and elsewhere supports the idea of fluid expansion and system inflation where fluid generation is one of the driving mechanisms. Intermittent compaction may occur for a short time when fluid pressure is released at the leak-off point of the seals.

Fluid overpressure rather than compaction disequilibrium seems to be the driving mechanism for reservoir diagenesis. Pore cementation occurs as water escapes out of the system. The first pulses of water travel along the most porous and permeable pathways. The largest pore throats are occluded first; followed by smaller pore throats as the fluids are diverted to lesser permeability pathways. Oil, then gas migration occurs in very tight sand fabric. Porosity distribution in the overpressured zone is unpredictable because of carbonate cementation, quartz overgrowth and other diagenetic products.

In this proposed BCGS model, kerogen type is less a factor than kerogen abundance. The surrounding reservoir, if homogenous, will receive pulses of hydrocarbons that equate with the source-rock richness inducing differences in gas saturation. The idea of “sweet spots” within otherwise widespread poor productive areas may be primarily related to variations in source-rock quality and distribution. Source-rock variability may impart variations in hydrocarbon and water saturation, porosity, permeability, and ultimately well productivity. Existing exploration models need to be updated to fully integrate the nature and role of the enveloping source and seal shale components of the BCGS.