Sam Green

Producing pore pressure profiles based on theoretical models in undrilled, deepwater frontier basins

A working petroleum system was established on the shelf in offshore Labrador with the Bjarni H-81 discovery in 1973 in the Hopedale Basin. The same reservoirs as those targeted on the shelf are present in the deep water, which is currently receiving attention as the result of newly acquired seismic data. To date, only a very small number of wells have been drilled in the deep water, i.e., Blue H-28, Orphan Basin, and none off mainland Labrador. The wells that were drilled in the deep water had encountered significant overpressure, e.g., kicks that indicated overpressures of 26,850 kPa in the Mid-Cretaceous. Therefore, it was reasonable to assume that pore pressures be similarly high for any new deepwater prospects identified. To help reduce the risk in unexplored environments, we developed an approach that can be adopted to model pore pressure in deepwater settings, with Labrador as the main case study area featured, but also we discussed other global examples such as the Voring Basin, Mid-Norway. Our results indicated, as a first approximation, that seismic velocity-based pore pressures in shale-rich intervals were similar to the geologic model down to the Lower Tertiary. Deep lithologies were, by regional analogue, likely affected by cementation that will act to preserve overpressure generated by disequilibrium compaction by reducing permeability but will not generate additional pore pressure. The cements (and any carbonate or volcanic lithologies) will, however, result in faster shales and will underpredict pore pressure by mimicking low porosity. A theoretical or “geologic modeling” approach can be used to sense-check any pore pressure interpretation from seismic velocity. The geologic approach also can be used to assess the risk for mechanical seal failure by allowing for estimates of the pore pressure, and related fracture pressure, to be made without the effects of cementation that affect the logs and seismic velocity data.

The Importance of Recognizing Hydrodynamics for Understanding Reservoir Volumetrics, Field Development and Well Placement

By recognizing and quantifying the regional distribution of overpressure a better understanding of hydrocarbon distribution can be built. Changes in aquifer overpressure represent fluid potential driving hydrodynamic flow. When hydrocarbons are trapped above a dynamic aquifer the hydrocarbon-water contact becomes tilted; the magnitude of the tilt is controlled by the differences in overpressure and the relative fluid densities. Structural closure may no longer be the key control on fluid distribution which is now being controlled by the hydrodynamic spill point. If the distribution of hydrocarbons is no longer controlled by structure then the placement of exploration or appraisal wells requires careful consideration. If a fluid contact can be shown to tilt down to the West then a well drilled on the East will encounter a shallower contact, or possibly water if the tilt is significant, and the decision may be made to abandon a prospect. However, a well drilled on the West may have a deeper than expected contact leading to an interpretation of a significant discovery. Furthermore, if the fluid contact is tilted then the volumetrics of the trapped hydrocarbons changes, either positively or negatively, but must be assessed. In all cases the impact for future exploration, development and appraisal are important. The Miocene reservoir system has been shown to be laterally drained (Hauser et al., 2013), i.e. low overpressure reservoirs sandwiched between high overpressure shales in the K2 (Sanford et al., 2006) and Knotty Head (Williams et al., 2008) Fields. Systematic changes in reservoir overpressure have been identified in the location of the Mad Dog Field as well as a tilted hydrocarbon-water contact (Dias et al., 2010). The work presented in this discusses in more detail the likely impact on hydrocarbon distribution for the Miocene reservoirs. Furthermore, the paper will extend the understanding of the geological-pressure controls on fluid distribution to the Lower Tertiary Wilcox play and comment on the likely impact for that system. The major implications of hydrodynamics are; a) Identification of regional overpressure gradients dictating natural aquifer flow and regional extent of sub-salt hydrodynamic reservoirs (natural pressure drive/support to a field), b) Identification of tilted fluid contacts and the impact on hydrocarbon distributions and volumetrics, and c) Description of the impact for other reservoir systems in the Gulf of Mexico, e.g. the Wilcox.

A hydrodynamic model and associated spill-point map for the Huntington Field, UK Central North Sea

Abstract The Huntington Field is located in Block UK 22/14b in the UK Central North Sea. The reservoir is the Tertiary Forties Formation (a deep-sea fan interval), which has been produced since 2013. Pre-production well data indicate that hydrocarbons (oil) are present outside structural closure as recorded by direct pressure data and wireline-derived fluid contacts, and indicated by seismic attribute data. These observations in other parts of the world (e.g. Mad Dog Field, Miocene Gulf of Mexico) have been attributed to the presence of a hydrodynamic reservoir. This paper aims to reconcile these observations from seismic data, logs and pressure data with competing models to explain the hydrocarbon distribution. Combining the interpretations above with the additional observations that (a) there are no sedimentological barriers or identifiable faulting between wells, (b) the surrounding fields (Everest and Forties) have been actively producing for decades, but that calculated flow rates in the Huntington Field agree with published data for other virgin hydrodynamic systems, and (c) measured regional and local overpressure gradients indicate fluid flow to the NW where hydrocarbons are present outside the structure indicates that a hydrodynamic model is the most probable solution to explain the fluids and their present distribution.

The Shelf to Deep-Water Transition - Using Analogues to understand the Pressure Regime in Un-Drilled Labrador Basins

The future of exploration in Labrador is focussed on transitioning from the shelf in to the deep-water region following the progress of exploration in other similar settings. Understanding the pressure history in such a frontier area must be built on robust use of analogues, i.e. Mid-Norway which has shown that significant discoveries can be made in such deep-water settings as in the deep-sea Nise Formation Fan reservoirs Mud-weights in many of the Labrador Shelf wells are low; however Pothurst P-19 took a very high kicks taken, implying under-balanced drilling and mis-understanding of the pore pressure regime in these Basins. Moreover in the Saglek and Hopedale Basins, the wells are shelfal to upper slope in terms of structural position and with the focus to move in to deeper water targets in the future. Following the announcement on September 13, 2011 to shoot large-scale multi-client 2D seismic survey of offshore Labrador into the deep water, understanding the shelf-to-deep water transition becomes even more crucial.