Broussard, Robin (Shell Upstream Americas) | Jimenez, Juan (Shell Upstream Americas) | Leenaarts, Elise (Shell Upstream Americas) | Lyell, Sharon (Shell Upstream Americas) | Stammeijer, Jan (Shell Upstream Americas)
Connectivity between reservoir compartments in the Brutus Field is difficult to predict despite extensive availability of conventional 3D seismic, and historic production and pressure data, resulting in risk and uncertainty in planning future late-life development wells. It is because of this that more sophisticated tools are needed to unravel the complex structural and stratigraphic framework in this mature field, leading to an integrated approach to field development using both qualitative legacy 4D seismic data and geochemical fingerprinting data obtained as part of the reservoir surveillance activities. The 4D signals observed on the time lapse analysis of a 2012 ocean bottom node (OBN) dataset compared to a pre-production, 1999 narrow azimuth (NAZ) streamer dataset appear consistent with production, pressure and geochemical data. This integrated interpretation approach supports the probability of several remaining undrained reservoir compartments that are being targeted in the upcoming Brutus drilling campaign. One of these compartments, the J2 Reservoir U2 fault block, will be the focus of this paper.
The integrated results of the legacy 4D, production, pressure, and geochemical data support the interpretation that the J2-RU2 block is an undrained/poorly drained compartment, thus lowering the subsurface risk of drilling a development well here.
Brutus Field, located in Green Canyon blocks 158 and 202 in the Gulf of Mexico, is a mature oilfield producing since 2001 from Pliocene and Pleistocene reservoirs. The field is located along the eastern flank of a northwest-southeast trending salt ridge that formed during Late Pliocene to Early Pleistocene times in direct response to sediment loading and associated faulting. The sediments that accumulated within the resulting Brutus mini-basin have been strongly influenced by episodic salt withdrawal and syn-sedimentary faulting. Brutus’s most prolific and deepest reservoir is the Late Pliocene J Sand, which accounts for about two-thirds of the field’s production. The location map is shown on Figure 1.
Pool, Wilfred (NAM) | Geluk, Mark (Shell Int. E&P) | Abels, Janneke (Shell International E&P) | Tiley, Graham John (Shell International E&P) | Idiz, Erdem (Shell Global Solutions International) | Leenaarts, Elise
In 2008 Shell obtained two licenses for unconventional gas exploration in the Skåne region of southern Sweden, with a total size of 2500 km2 (600,000 ac). The objective was the Cambro-Ordovician Alum Shale, one of the thickest and richest marine source rocks in onshore northern Europe.
The licenses covered the Höllviken Graben and the Colonus Shale Trough. In both areas the Alum Shale had been encountered in older wells, with a thickness of up to 90 m and TOC values up to 15%. Maturities of up to 2% Vre were considered encouraging for a shale gas play. Relative high quartz contents suggested good fraccability of the shales. All data was obtained through public sources. Identified risks were the uncertain timing of hydrocarbon generation and the position of the licenses adjacent to the Trans-European Suture Zone where several phases of fault movement have a risk for actually retaining the hydrocarbons.
The derisking strategy for this opportunity was based on both technical and non-technical aspects. Aim was to collect geological and geophysical data to constrain depth and thickness of the shale and to identify potential dolerite dykes. In addition, well data were needed to establish rock properties and gas content. The external environment, especially concerns from the people in Skåne regarding the visual impact of activities and potential impact of drilling activities on the aquifers and on the tourism industry have resulted in extensive engagements with stakeholders and specific requirements around seismic acquisition (low impact), site preparation and operations (e.g. small rig, different lighting).
80 km of 2D seismic was acquired in 2008 and three wells, with a final depth of around 1000 m, were drilled in 2009 to mid 2010. The Alum shale was fully cored and the well sites have been restored. Thickness, richness and maturity of the Alum were as predicted although the basin was shallower than previously anticipated. Canister desorption tests, however, indicated that the shales have only low gas saturation. This significantly increased the risk for a viable shale gas play and therefore the licenses were not renewed after the initial 3 year period.