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Coastal & Marine Geology Program >Subsidence and Fault Activation . . . > Open File Reoprt 01-274

Shallow Stratigraphic Evidence of Subsidence and Faulting Induced by Hydrocarbon Production in Coastal Southeast Texas

USGS Open File Report 01-274

Robert A. Morton, Noreen A. Purcell, and Russell L. Peterson

Contents:
Summary
Introduction
Geology & Production Histories
Sediment Surface Profiles
Sediment Cores
Results
Coastal Environmental Implications
References
Appendix A
Appendix B
Project Contact:
Bob Morton

Subsurface Geology and Production Histories

Chilingarian et al. (1995) reported that young, shallow, thick, laterally extensive, uncemented, argillaceous, and highly porous geological formations are the most susceptible to subsidence induced by subsurface fluid withdrawal. These criteria apply to most of the oil and gas fields producing in the Gulf Coast region. Other important criteria involve fluid production histories for each field, the associated reduction in reservoir pore pressures, and eventually the cumulative temporal reductions in subsurface pressures over large areas. The last phenomenon is known as regional depressurization. Because formation pore pressures and horizontal stresses at the reservoir level are closely linked, decreases in pore pressure translate to increases in effective stress. The increased effective stress causes compaction of the reservoir and can reactivate faults that are critically stressed and at the threshold of failure (Wiprut and Zoback, 2000).

Kreitler et al. (1988) evaluated thousands of reservoir pressures from the Frio producing trend in Texas and demonstrated that the initial pressure gradients for many wells were far below those expected for hydrostatic (normal) conditions because of prior hydrocarbon production. Contour maps of the southeast Texas coast constructed by Kreitler et al. (1988) show the broad regional influence of subsurface depressurization that extends far beyond the limits of oil and gas production. These regional aggregated pressure-gradient observations were later confirmed by Sharp and Hill (1995), who constructed pressure-depth plots for the Big Hill and Fannett Fields within the Frio fairway of southeast Texas.

Detailed pressure histories and depletion curves are not readily available for the primary reservoirs of any of the fields included in this study. To provide a basis for comparing subsurface stress perturbations with surficial wetland changes, aggregated cumulative oil and gas production from the NRG Associates database (Table 1) was used as a gross substitute for reductions in reservoir pressure.

Table 1. Summary of field characteristics.
Field Port Neches Clam Lake Caplen
Discovery Date 1929 1937 1939
Number of Wells 110 55 (approx.) 57
Reservoir Age Oligocene Miocene, U. Oligocene Miocene
Number of Prod. Zones 21 31 32
Production Depth Range 2350-2715 m 700-2045 m 1220-2350 m
Ave. depth of max. prod. 2440 m 1980 m 2200 m
cumulative oil prod. 34.1 million bbls 21.4 million bbls 19.4 million bbls
Cumulative condensate prod. 12.5 million bbls 00.1 million bbls 00.7 million bbls
Cumulative gas prod. 575 Bcf 10 Bcf 55 Bcf
Initial pressure gradients Most are normal Normal Normal
General Field reference Kiatta, 1986 Williams, 1962 Musolff, 1962

Port Neches Field

The Port Neches Field, also known as the Bessie Heights Field, has produced more than 46 million bbls of liquid hydrocarbons and 575 Bcf of gas during a period of 70+ years. The cumulative volumes of hydrocarbon production assigned to Port Neches (Table 1) include contributions from the Port Neches Field proper, as well as from North, South, and West extensions. The North extension is an area principally of gas production. Hydrocarbon production is mostly from the Oligocene lower Hackberry sands of the middle Frio stratigraphic interval at depths ranging from 2350 to 2715 m.

Oil production at Port Neches peaked in the early 1950s, remained relatively constant through the 1970s, and then gradually declined in the 1980s. In contrast, gas production accelerated rapidly during the mid to late 1950s and then rapidly declined. Wetland losses began during the late 1950s, shortly after the high rates of fluid production and by 1978 more than 3400 hectares of wetlands had been converted to open water (White and Tremblay, 1995). The area of wetland loss encompassed the entire east side of the Neches River valley in a circular pattern that included the entire field and extended far beyond the limits of production. Wetland losses on the south side of the field coincided with a reactivated fault that was not visible on aerial photographs until the mid 1960s (White and Morton, 1997).

Clam Lake Field

Since 1937, the Clam Lake Field has produced more than 21 million bbls of oil and 10 Bcf of gas (Table 1). Hydrocarbon reservoirs in the field, which are Miocene to upper Oligocene, range in depth from 700 to 2045 m. Although hydrocarbons are encountered over a broad range of depths, most of the production is from the lower Miocene section at depths of about 1800 m. Oil production gradually increased from the time Clam Lake Field was discovered until the late 1950s. Between the late 1950s and early 1960s, oil production rapidly increased and then went into gradual decline. Gas production at Clam Lake was not significant until the late 1960s when it showed a substantial increase that lasted for about 5 years. The onset of wetland loss at Clam Lake closely corresponds to the period of accelerated hydrocarbon production. Aerial photographs show that wetlands were continuous east of the field through the mid-1950s but by the mid-1960s, surface elevations had changed and wetlands were being converted to water east and northeast of the field (White and Tremblay, 1995).

Wetland loss at the Clam Lake Field is clearly controlled by reactivation of a deep fault that is one of the principal hydrocarbon traps at the reservoir level. Fault projections by White and Morton (1997) show a close correlation between the surface expression and reservoir location of the fault plane. Open water in the form of coalesced ponds has replaced wetlands on the downthrown side of the fault (White and Tremblay, 1995). At the surface the fault is represented by a sharp boundary that reflects the change in elevation, surface water, and species and density of vegetation. During the field investigation, offset along the fault was not visible because the plant density during the growing season obscured the fault plane.

Caplen Field

The Caplen Field, discovered in 1939, has produced more than 20 million bbls of oil and condensate and 55 Bcf of gas. Oil and gas reservoirs range in depth from 1220 to 2350 m with most of the production coming from lower Miocene sandstones at depths of about 2200 m. Oil production at Caplen peaked in the mid-1950s but gas production was relatively insignificant until the late 1950s when it rapidly accelerated (White and Morton, 1997). High rates of gas production were sustained until the mid-1980s when they rapidly declined. Only a few wells are currently producing.

Like at the Clam Lake Field, the wetland losses at Caplen are controlled by two faults that were reactivated about 20 years after the field began producing. The intersecting surficial fault traces have the same shapes and orientations as the major subsurface faults mapped at the reservoir level (Ewing, 1985). Marshes were submerged and converted to open water along the fault traces and the loss of wetlands later extended away from the faults. The timing of wetland losses coincided with the periods of accelerated hydrocarbon production at Caplen. In the mid-1950s the faults were faintly visible on aerial photographs, but later the conversion of wetlands to open water was well defined and abrupt along the fault plane (White and Tremblay, 1995).

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Coastal & Marine Geology Program >Subsidence and Fault Activation . . . > Open File Report 01-274


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