Thomas Finkbeiner

Stress, pore pressure, and dynamically constrained hydrocarbon columns in the South Eugene Island 330 field, northern Gulf of Mexico

Hydrocarbon phase pressures at the peak of two severely overpressured reservoirs in the South Eugene Island 330 field, Gulf of Mexico, converge on the minimum principal stress of the top seal. We interpret that the system is dynamically constrained by the stress field present through either fault slip or hydraulic fracturing. In two fault blocks of a shallower, moderately overpressured reservoir sand, hydrocarbon phase pressures are within a range of critical pore pressure values for slip to occur on the bounding growth faults. We interpret that pore pressures in this system are also dynamically controlled. We introduce a dynamic capacity model to describe a critical reservoir pore pressure value that corresponds to either the sealing capacity of the fault against which the sand abuts or the pressure required to hydraulically fracture the overlying shale or fault. This critical pore pressure is a function of the state of stress in the overlying shale and the pore pressure in the sand. We require that the reservoir pore pressure at the top of the structure be greater than in the overlying shale. The four remaining reservoirs studied in the field exhibit reservoir pressures well below critical values for dynamic failure and are, therefore, considered static. All reservoirs that are dynamically constrained are characterized by short oil columns, whereas the reservoirs having static conditions have very long gas and oil columns.

Relationships among in-situ stress, fractures and faults, and fluid flow; Monterey Formation, Santa Maria Basin, California

We used borehole televiewer (BHTV) data from four wells within the onshore and offshore Santa Maria basin, California, to investigate the relationships among fracture distribution, orientation, and variation with depth and in-situ stress. Our analysis of stress-induced well-bore breakouts shows a uniform northeast maximum horizontal stress (SH max) orientation in each well. This direction is consistent with the SH max direction determined from well-bore breakouts in other wells in this region, the northwest trend of active fold axes, and kinematic inversion of nearby earthquake focal plane mechanisms. In contrast to the uniformity of the stress field, fracture orientation, dip, and frequency vary considerably from well to well and within each well. With depth, fractures can be divided into distinct subsets on the basis of fracture frequency and orientation, which correlate with changes of lithology and physical properties. Although factors such as tectonic history, diagenesis, and structural variations obviously have influenced fracture distribution, integration of the in-situ stress and fracture data sets indicates that many of the fractures, faults, and bedding planes are active, small-scale strike-slip and reverse faults in the current northeast-trending transpressive stress field. In fact, we observed local breakout rotations in the wells, providing kinematic evidence for recent shear motion along fracture ©Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Manuscript received April 15, 1996; revised manuscript received December 27, 1996; final acceptance July 15, 1997. 2Department of Geophysics, Stanford University, Stanford, California 94305-2215. We wish to thank Tom Zalan of the Chevron U.S.A. Production Company for providing the offshore well data, Unocal Corporation for providing the data on the onshore well, and Marcia McLaren from Pacific Gas and Electric Company for providing the earthquake focal mechanisms used in the stress inversion analysis. The data used as background seismicity in Figure 1 were extracted from the World Wide Web of the Southern California Seismic Network (SCSN) catalog operated jointly by the Seismological Laboratory at Caltech and the U.S. Geological Survey, both in Pasadena, California. We appreciate the comments and helpful discussions from Daniel Moos, Steve Graham, and Lev Vernik.

Comprehensive wellbore stability analysis utilizing Quantitative Risk Assessment

Abstract A comprehensive geomechanical approach to wellbore stability requires knowledge of rock strength, pore pressure and the magnitude and orientation of the three principal stresses. These parameters are often uncertain, making confidence in deterministic predictions of the risks associated with instabilities during drilling and production difficult to assess. This paper demonstrates the use of Quantitative Risk Assessment (QRA) to formally account for the uncertainty in each input parameter to assess the probability of achieving a desired degree of wellbore stability at a given mud weight. We also utilize QRA to assess how the uncertainty in each parameter affects the mud weight calculated to maintain stability. In one case study, we illustrate how this approach allows us to compute optimal mud weight windows and casing set points at a deep-water site. In another case study, we demonstrate how to assess the feasibility of underbalanced drilling and open-hole completion of horizontal wells utilizing a comprehensive stability analysis that includes application of QRA.

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

Determination of stress orientation and magnitude in deep wells

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