Finding off-structure geopressured gas accumulations in the US Gulf

Charles Brewster
Texaco

Charles Sharpe, Sharon Landeche, Bob Klein
Amoco

Lori Hathon
Shell E&P

• Location of Matagorda Island 519 Field, offshore Texas. Axes of depositionally perpendicular shale ridges and Lower Miocene expansion faults are shown schematically. [166,424 bytes]
• Geochemical facies zonation formed along diagenetically altered migration pathway accumulations. [51,199 bytes]
• Geological and geophysical model of Matagorda Island 519 diagenetic trap. [80,424 bytes]

Compartmentalized traps hold new reserves

Studies of the Matagorda Island 519 field offshore Texas led to an exploration model to predict the existence of similar exploration targets in geopressured sandstone in flanking structural positions. The extensional tectonic setting includes coast-parallel, Lower Miocene expansion faults.

The deltaic depocenters, formed on the downthrown sides of these faults, deformed older, underlying shales into ridges. These ridges are oriented perpendicular to the strike of the expansion faults, and structures over the ridges are preferred areas for hydrocarbon accumulations.

An exception to this simplified setting is the Matagorda Island 519 field. This field is on the structural flank of a coast-perpendicular ridge, in geopressured sandstone, showing pressure and diagenetic compartmentalization. These compartmentalized reservoirs are thought to form as a result of a complicated secondary porosity diagenetic process related to fluid flow and pressure cell formation. Prediction of similar exploration targets can be enhanced through geochemical, pressure, and seismic interval velocity analyses.

Field characteristics

Matagorda Island 519 field produces from 4 wells in geopressured sandstones at depths from 14,200 ft to 17,300 ft downthrown to a lower Miocene expansion fault and flanking a diapiric shale ridge. An ultimate recoverable resource of 250+ Bcf of gas is attributable to this field. The deltaic sandstones have porosities of 0-23% and a high intergranular volume of 25-33%. The productive porosity is considered secondary porosity based on petrologic relationships and the result of ferroan-calcite cement dissolution.

Sandstone petrology suggests the following diagenetic evolution:

• Mechanical compaction
• Formation of clay grain coats on detrital grains
• Calcite cementation
• Partial dissolution of detrital feldspar and quartz
• Dissolution of calcite cement and calcite detrital grains and variable cementation by poly-crystalline quartz, ankerite, and pyrite.

Zoning of authigenic cements is observed with poly-crystalline quartz/pyrite cement predominate updip and most proximal to the expansion fault. This authigenic facies grades downdip into dolomite/Fe-ankerite and further downdip into Fe-calcite cemented facies.

The best secondary porosities and the hydrocarbon productive reservoirs are limited to the downdip dolomite/Fe-ankerite and Fe-calcite cemented facies. The spacing of approximately 2,000 ft between wells demonstrates a diagenetic overprinting rather than a facies change origin of these relationships.

Geopressured compartments

Geopressure cells are distinct and form a banded compartmentalization recognized in resistivity log patterns. Above geopressure, sandstones are highly resistive (1.5 to 4 ohms), in a classic caprock formed by calcite mineral precipitation from fluids periodically expelled from the pressurized zone. The geopressure zone is a sharp transition about 300 ft thick, where drilling mud weights increase from 13 lb/gal to 17 lb/gal. Corresponding shale resistivities drop from 1.5 ohms down to about 0.9-1 ohm in the geopressured interval.

The first pressure band interval is about 800 ft thick and overlies the second geopresssure zone. The second zone has an 18+ lb/gal environment with corresponding shale resistivities of 0.3 to 0.5 ohms. This zone is about 1,700 ft thick but shows increasing resistivity at the base. This is where the top of the reservoir becomes developed, and where the resistivity increases to 1-2 ohms.

Within the reservoir zone, the upper 200 ft is tightly ferroan-calcite-cemented sandstone with 20-23% cemented intergranular pore space occupied by calcite cements. Upon entering the productive reservoir, the 20-23% pore spaces are etched, interconnected voids filled with hydrocarbons. The reservoir pressure drops from the 18+ lb/gal in the overlying compartment, to 17 lb/gal in the reservoir.

Exploration model

The proposed geologic model is dynamic, involving several periods of pressure formation and includes diagenetic mineral assemblages consistent with hydrothermal fluid flow alterations. Updip, a non-economic sandstone assemblage shows poly-crystalline quartz and pyrite cemented sandstone with thin zones containing gas shows. The non-economic, cemented sandstone is seen beneath two banded geopressured shale compartments. Downdip, the sandstone grades into reservoir quality, with a Fe-ankerite and Fe-calcite residual overprint.

Detailed interval velocity analyses show two tiered, slower velocity zones (Compartments B and C) over the faster cemented sandstone, the tight facies. Within the reservoir interval, updip, fast cemented sandstone is non-economic. The velocities slow downdip, where secondary dissolution in porosity is hydrocarbon saturated. The mechanism forming these accumulations is thought to be interplay between geopressuring and diagenesis.

Exploration methodology

Exploring for such diagenetically controlled gas accumulations can be achieved through a combination of geological and geophysical techniques. First, electric logs can be screened for highly resistive sandstone with uneconomical gas shows. Cuttings from these wells can be obtained and analyzed for anomalous pyrite, ankerite, and quartz mineralization.

Samples showing such mineralization may be considered migration pathway indicators and thus high-grade areas for more sophisticated geophysical techniques. Detailed interval velocity models can illuminate the structure of the geopressured compartments. Subtle velocity analyses can detect the limits of tight, cemented facies by their characteristic high velocities. Slower velocities should indicate the areas where porous, gas-saturated rocks are located downdip.

An analysis of the Lower Miocene trend along the Gulf Coast suggests that at least 10 of these type of fields may be expected. With an average field size of 250+ Bcf, this may represent some 2.5 Tcf of potential resources. The two fields of this type discovered to date are Matagorda 519 field, offshore Texas, and the East Bayou Postillion field, Iberia Parish, south Louisiana. Some 300 miles of depositional strike separating these fields suggests plenty of running room to use this model in the Lower Miocene trend.

Additional potential exists in the Lower Miocene trend to the southwest of Matagorda Island in the offshore Mustang Island and North and South Padre Island OCS areas. Further calibration may also show applicability to the Frio and Wilcox trends of the Gulf Coast. These methods, and this exploration model, may allow for the addition of significant resources to be discovered along the strike of these prolific hydrocarbon-producing trends.

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