First Break - Volume 29, Issue 10, 2011

Kurtis Wikel argues that a geomechanics approach to tracking the stresses in the subsurface caused by drilling and hydraulic fracture operations in the production of unconventional tight gas and oil and gas shale reservoirs pays major dividends and should be more seriously considered by the geoscience community.

Ibrahim Mustafayev and Thomas. L. Davis discuss lithology and fluid discrimination issues in the Delhi Field in Louisiana and find that the geology of the reservoir dictates that fluid changes can only be distinguished if shear impedance is incorporated into the analysis.

In this study of an unconventional reservoir, Jared Atkinson and Thomas Davis conclude that more work is needed to account for the different response to fluid injection in unconventional, low permeability reservoirs compared with more permeable conventional reservoirs. They also suggest that hydraulic fracture monitoring using converted wave data shows promise as a viable option to conventional microseismic analysis.

Jonathan S. Abel, Sean Coffin, Yoomi Hur and Scott Taylor offer a framework for studying issues with microseismic source location estimation accuracy and provide new geometric intuitions and quantitative relationships that aid in the understanding of this problem.

Giles Watts, Ian Jack and Mark Thompson comment on the results of a questionnaire among geoscientists and engineers regarding the current use of 4D seismic and likely future developments. The results are both fascinating and salutary in their exposure of how 4D technology is perceived by experts and the implications for industry R&D investment going forward.

Fluid inclusions have been used to identify oil charge and migration into the Ungumayo anticline, located in the Marañon Basin, Peru. Sandstone samples recovered from an exploration well drilled into the west flank of the trap (Ungumayo-1X) and from a well in the nearest producing oilfield, the Chambira Este Field, were sent for fluid inclusion analyses. The samples containing fluid inclusions were compared using petrography and fluid inclusion geothermometry to identify the local geological controls on the formation of the different fluid inclusion types identified in the wells. The bulk chemical composition of the volatiles inside the fluid inclusions was obtained using mass spectrometry, with ions being identified from inorganic gases, dry organic gases, water-soluble hydrocarbons, C1 to C13 petroleum compounds, and sulphur compounds. The fluid inclusion mass spectrometry results were interpreted by comparing the abundances of specific hydrocarbon-related compounds and mass spectra between samples from the exploration well and the oilfield. The combination of petrography and fluid inclusion techniques confirms the migration of liquid hydrocarbons into the Ungumayo structure. The fluid inclusion mass spectrometry analysis suggests that the Ungumayo structure still contains a non-biodegraded oil accumulation.

The Llanos Basin of Colombia, a foreland basin of the Eastern Andean Cordillera, is a petroleum-rich province in which the water/oil ratio found in the reservoirs is anomalously large, with up to 80% water and only 20% hydrocarbons. This formation water has low salinity. Within foreland basins, flow of fresh water has generally been explained by basin-scale circulation of meteoric water percolating from adjacent topographic highs. An alternative origin is tested here by 3D modelling: the low salinity water is released by smectite-illite transformation. Since 50% of the sediments within the Llanos Basin are mudrocks, the modelling results show that a significant volume of water has been added by diagenetic reactions in the northern and western parts of the basin. The peak of low salinity water generation by diagenesis occurs at a depth of about 4 km, where compaction is almost complete. Results show that neglecting the mineral dehydration reactions can lead to misinterpretation of overall mass balance and fluid transfer operating at the basin scale.

The Guyana Basin contains a world-class source rock of Late Cretaceous age, but no hydrocarbon fields have yet been discovered offshore. In order to evaluate source rock maturity, we used basin modelling software to model a grid of interpreted 2D seismic sections and combined the 2D modelling results to build a basin-wide model. The burial depth, temperature, and transformation ratio of the Cretaceous source rocks were calculated from the end of the Cretaceous to the present, and mapped over the entire basin. The modelling results show that regional uplift during Late Cretaceous–middle Miocene time slowed the maturation of the Cretaceous source rock in the basin except in the south-eastern depocentre. In this depocentre, the oil window was reached during the Palaeogene, by which time few reservoir and seal rocks had been deposited. For the rest of the basin, uplift of the Waini arch and the middle Miocene regional uplift slowed maturation of the source rock. Possible reservoirs that could have received hydrocarbons from the south-eastern depocentre include Cretaceous-middle Miocene clastic rocks that pinch out against the southern flank of the Waini arch and stratigraphic traps along the shelf.