Eric Potter

Sequence-stratigraphic controls on complex reservoir architecture of highstand fluvial-dominated deltaic and lowstand valley-fill deposits in the Upper Cretaceous (Cenomanian) Woodbine Group, East Texas field: Regional and local perspectives

An analysis of 31 whole cores (1600 ft, 490 m) and closely spaced wireline logs (500 wells) penetrating the Lower Cretaceous (Cenomanian) lower Woodbine Group in the mature East Texas field and adjacent areas indicates that depositional origins and complexity of the sandstone-body architecture in the field vary from those inferred from previous studies. Heterogeneity in the lower Woodbine Group is controlled by highstand, fluvial-dominated deltaic depositional architecture, with dip-elongate distributary-channel sandstones pinching out over short distances (typically 500 ft [150 m]) into delta-plain and interdistributary-bay siltstones and mudstones. This highstand section is truncated in the north and west parts of the field by a thick (maximum of 140 ft [43 m]) lowstand, incised-valley-fill succession composed of multistoried, coarse-gravel conglomerate and coarse sandstone beds of bed-load fluvial systems. In some areas of the field, this valley fill directly overlies distal-delta-front deposits, recording a fall in relative sea level of at least 215 ft (65 m). Correlation with the Woodbine succession in the East Texas Basin indicates that these highstand and lowstand deposits occur in the basal three fourth-order sequences of the unit, which comprises a maximum of 14 such cycles. Previous studies of the Woodbine Group have inferred meanderbelt sandstones flanked by coeval flood-plain mudstones and well-connected, laterally continuous sheet sandstones of wave-dominated deltaic and barrier-strand-plain settings. This model is inappropriate, and a full assessment of reservoir compartmentalization, fluid flow, and unswept mobile oil in East Texas field should include the highstand, fluvial-dominated deltaic and lowstand valley-fill sandstone-body architecture.

The sagatu ridge dike swarm, ethiopian rift margin

Abstract A swarm of dikes forms the core of the Sagatu Ridge, a 70 km long topographic feature elevated to more than 4000 m above sea level and 1500 m above the level of the Eastern (Somalian) plateau. The ridge trends NNE and lies about 50 km east of the northeasterly trending rift-valley margin. Intrusion of the dikes and buildup of the flood-lava pile, largely hawaiitic but with trachyte preponderant in the final stages, occurred during the late Pliocene-early Pleistocene and may have been contemporaneous with downwarping of the protorift trough to the west. The ensuing faulting that formed the present rift margin, however, bypassed the ridge. The peculiar situation and orientation of the Sagatu Ridge, and its temporary existence as a line of crustal extension and voluminous magmatism, are considered related to a powerful structural control by a major line of Precambrian crustal weakness, well exposed further south. Transverse rift structures of unknown type appear to have limited the development of the ridge to north and south.

Dallas-Fort Worth earthquakes coincident with activity associated with natural gas production

On 31 October 2008 and the following day, numerous Dallas-Fort Worth (DFW) residents called 911 to report experiencing several small earthquakes, accompanied by loud booming noises and the shaking of walls and furniture. Using data recorded by regional seismic stations, the USGS National Earthquake Information Center (NEIC) located nine earthquakes with magnitudes between 2.5 and 3.0. On 16 May 2009, this scenario repeated itself, as local residents felt three earthquakes and the NEIC located four (largest = magnitude 3.3). A third sequence of felt events began on 2 June 2009, approximately 65 km southwest near the city of Cleburne, Texas, but has not yet been studied in detail (Figure 1).

Log-derived thickness and porosity of the Barnett Shale, Fort Worth basin, Texas: Implications for assessment of gas shale resources

This study estimates reservoir quality and free-gas storage capacity of the Barnett Shale in the main natural-gas producing area of the Fort Worth basin by mapping log-derived thickness, porosity, and porosity-feet. In the Barnett Shale, the density porosity (DPHI) log curve is a very useful tool to quantitatively assess shale gas resources, and gamma-ray (GR) and neutron porosity log curves are important factors in identifying the shale gas reservoir. The key data were digital logs from 146 wells selected based on the availability of GR and density log curves, log quality, and good spatial distribution. The Barnett Shale pay zone was determined on the basis of (1) DPHI >5%, (2) high GR values (commonly >∼90 API units), (3) no significant intercalated carbonate-rich beds, and (4) individual pay zones being thick enough to be commercially successful for the current design of horizontal wells. In the study area, the Barnett Shale pay zone varies from about 165 ft (50 m) to 420 ft (128 m) in thickness (H). Average DPHI values of individual wells for the pay zone vary from 8.5 to 14.0%. Porosity-feet maps of the pay zone show that areas of high DPHI-H values coincide with areas of high natural gas production, indicating that log-derived porosity-feet maps are a good method for evaluating reservoir quality and assessing natural gas resource in the Barnett Shale play. A limitation to this method is shown in the northwestern corner of the study area, which is located in the liquids-rich window with lower thermal maturity.

Regional assessment of the Eagle Ford Group of South Texas, USA: Insights from lithology, pore volume, water saturation, organic richness, and productivity correlations

AbstractA comprehensive regional investigation of the Eagle Ford Shale linking productivity to porosity-thickness (PHIH), lithology (Vclay), pore volume (PHIT), organic matter (TOC), and water-saturation (SW) variations has not been presented to date. Therefore, isopach maps across the Eagle Ford Shale play west of the San Marcos Arch were constructed using thickness and log-calculated attributes such as TOC, Vclay, SW, and porosity to identify sweet spots and spatial distribution of these geologic characteristics that influence productivity in shale plays. The Upper Cretaceous Eagle Ford Shale in South Texas is an organic-rich, calcareous mudrock deposited during a second-order transgression of global sea level on a carbonate-dominated shelf updip from the older Sligo and Edwards (Stuart City) reef margins. Lithology and organic-matter deposition were controlled by fluvial input from the Woodbine delta in the northeast, upwelling along the Cretaceous shelf edge, and volcanic and clastic input from distan...

Log-derived thickness and porosity of the Barnett Shale, Fort Worth basin, Texas

This study estimates reservoir quality and free-gas storage capacity of the Barnett Shale in the main natural-gas producing area of the Fort Worth basin by mapping log-derived thickness, porosity, and porosity-feet. In the Barnett Shale, the density porosity (DPHI) log curve is a very useful tool to quantitatively assess shale gas resources, and gamma-ray (GR) and neutron porosity log curves are important factors in identifying the shale gas reservoir. The key data were digital logs from 146 wells selected based on the availability of GR and density log curves, log quality, and good spatial distribution. The Barnett Shale pay zone was determined on the basis of (1) DPHI >5%, (2) high GR values (commonly >∼90 API units), (3) no significant intercalated carbonate-rich beds, and (4) individual pay zones being thick enough to be commercially successful for the current design of horizontal wells. In the study area, the Barnett Shale pay zone varies from about 165 ft (50 m) to 420 ft (128 m) in thickness (H). Average DPHI values of individual wells for the pay zone vary from 8.5 to 14.0%. Porosity-feet maps of the pay zone show that areas of high DPHI-H values coincide with areas of high natural gas production, indicating that log-derived porosity-feet maps are a good method for evaluating reservoir quality and assessing natural gas resource in the Barnett Shale play. A limitation to this method is shown in the northwestern corner of the study area, which is located in the liquids-rich window with lower thermal maturity.

Chapter 6: What Further Research Could Teach Us about “Close Encounters of the Third Kind”: Intraplate Earthquakes Associated with Fluid Injection

Abstract We propose five hypothesis concerning small intraplate earthquakes and the possibility that they are triggered by fluid injection. The proposed hypotheses are based on empirical observations but are consistent with the generally accepted ideas that small intraplate earthquakes are ubiquitous and occur on preexisting faults in response to regional tectonic stress and that injected fluids can induce seismic slip by reducing normal stress and hence fault strength. Although these hypotheses are not yet proven, they serve as a template for additional research. They also provide a basis for making decisions that reduce the likelihood of triggering earthquakes and for mitigating potential seismic hazard associated with injection activities.