In-situ Stress and Pore Pressure in the South Eugene Island Field, Gulf of Mexico

Analysis of minifiacs and pore pressure suweys from sand reservoirs in a Gulf of Mexico oil field show effective stress ratios, K, that scatter significantly and do not correlate with previously published fracture gradient models for this area. The lower-bound value of K is 0.33, which corresponds to the expected value for Coulomb failure for a coefficient of tiiction of 0.6 in normal faulting environments. However, in some sands K approaches unity, thus indicating an essentially isotropic stress field. Hence, the data indicate a highly variable state of stress that cannot be simply related to depth or pore pressure, but appears to reflect an interaction between reformational processes and material properties. Borehole breakout analysis in vertical wells reveals stress orientations that are predominantly perpendicular to normal faults and, hence, consistent with an extensional stress regime. Analysis of breakouts in inclined wells in two sand reservoirs allows to constrain the magnitude of the maximum horizontal principal stress, S~ax, and fiu-ther indicates an active normal faulting environment with a clear, but small degree of horizontal stress anisotropy (i.e., Sv > SHmax > s~i~. Introduction Determination of the full stress tensor in oil fields is critical for addressing engineering issues such as borehole stability and sand production as well as understanding dynamic constraints on hydrocarbon migration and fracture permeability. In this study we use data ftom miniffacs, pore pressure surveys, and dipmeter caliper logs to constrain the full in-situ stress tensor (i.e., the magnitude and orientation of all three principal stresses) in reservoirs sands from the South Eugene Island (SEI). This field is located in the Gulf of Mexico on the outer continental shelf about 100 miles offshore Louisiana. Geologically, this field is a “classical” Plio-Pleistocene Gulf of Mexico salt-withdrawal minibasin that is bounded to the north and east by a regional (down to the south) fault system and to the south by an antithetic fault system]. Over 25 unconsolidated sands layers are separated by massive shale packages and normal faults into at least 100 structurally or stratigraphically distinct reservoirs. The field is one of the largest oil and gas producing fields in the US2’3. As the hydrocarbons trapped within the reservoirs of SEI field are much older than the young sediments, they are believed to have mi rated vertically over significant distances relatively $ recently . Fig. 1 displays a schematic N-s trending crosssection through the field showing the main basin bounding growth fault system in the middle as it offsets sand reservoirs in the footwall (to the right) from those in the hanging wall (to the left). Note, that the structural relief across the fault system increases significantly with depth while individual sand reservoirs become less continuous. The availability of minifrac data fi-om fracture completions and pore pressure history data fi-om pressure surveys from the SEI field provides an unique opportunity to accurately characterize in-situ least principal stresses and pore pressures in the hydrocarbon producing sand reservoirs. Integrating these least principal stress measurements with carefully analyzed pore pressure data and borehole breakouts from dipmeter caliper data in vertical and inclined wells allows us to constrain the fill stress tensor in these reservoir sands and to compare with published estimates of the least principal stress derived from fracture gradients. There are three clear advantages of this study over previous stmdies of this type in the Gulf coast region: (1) We can use least principal stress data from minifracs conducted in sands whereas previous studies derived stress data from low quality leak-off tests that were predominantly measured in shales. (2) Our stress measurements were taken in the same reservoir sands in which pore pressures were measured whereas previous compilations often compare stress data from shales with pore pressure data from sands. (3) All of our data come from the same field (and ofien even the same well) whereas previous publications reflect regional compilations. Pore pressure history data tlom numerous production wells also allow us to quantifi production related pore pressure