Attitude: Definition, Strike and Dip, and Geological Orientation in Well Planning

Key Takeaways

• Strike and dip convention and the right-hand rule: Strike is the compass bearing of the horizontal line on a dipping plane, measured in degrees clockwise from north (azimuth convention) or as a compass quadrant (e.g., N45E). Dip is the maximum angle of inclination of the plane below horizontal, measured perpendicular to strike in the steepest descent direction. The right-hand rule is a mnemonic for recording strike and dip consistently: when the right hand is held flat with fingers pointing along the strike direction and the thumb pointing in the dip direction, the recorded strike should be such that the dip direction is 90 degrees clockwise from it. Alternatively, the dip direction (the azimuth of the downslope direction) can be recorded directly as the dip quadrant: a bed striking N45E (045 degrees azimuth) and dipping 30 degrees toward the southeast (135 degrees azimuth) is written 045/30SE or 045/30/135. In the WCSB foothills, where beds in thrust-fault anticlines rotate from near-horizontal in the core of the structure to steeply dipping on the limbs, accurate bedding attitude data from outcrop measurements, dipmeter logs, and FMI image logs are essential for constructing the structural cross-sections used to locate reservoir crests and fault-bounded traps in plays such as the Foothills Gas fairway in the Front Ranges of Alberta and British Columbia.
• Formation attitude from dipmeter and FMI image logs in the borehole: In the subsurface, formation attitude is measured using wireline dipmeter tools and borehole image logs such as the Schlumberger Formation MicroScanner (FMI), Halliburton EMI, and Baker Hughes STAR. These tools record the resistivity of the borehole wall at high resolution (1 to 5 millimetre button spacing on FMI) as the tool is pulled up the borehole. Dipping formations intersect the cylindrical borehole wall as sinusoidal curves rather than horizontal lines; the dipmeter algorithm (or the geologist's manual pick on FMI images) fits a sinusoid to correlated resistivity events across the multiple pads, extracting the dip magnitude and dip azimuth (dip vector) of each formation boundary at the depth of the correlation. A software package such as the Schlumberger Techlog FMI analysis module or Halliburton WellboreXplorer displays these dip vectors as tadpole plots (dip magnitude on the x-axis, dip direction as the tail direction) showing how formation attitude varies with depth. In structural wells at the WCSB foothills, FMI dip data resolve the change from backlimb to forelimb attitude across a thrust-fault anticline core within meters, providing information that would otherwise require a full seismic reflection survey to approximate.
• True vertical thickness, true stratigraphic thickness, and directional well corrections: In a deviated or horizontal well, the measured depth (MD) from the surface to any formation top is greater than the true vertical depth (TVD) to that horizon, and the apparent thickness of any bed intersected by the wellbore differs from its true stratigraphic thickness (TST) or true vertical thickness (TVT) depending on the wellbore and formation attitudes. The relationship between apparent thickness (intersected along the wellbore), TVT (thickness measured vertically), and TST (thickness measured perpendicular to bedding) depends on both the wellbore attitude (inclination and azimuth) and the formation attitude (dip magnitude and dip azimuth). In a horizontal Montney well drilled at 90-degree inclination through a formation dipping 2.5 degrees southward, the wellbore may traverse 4,500 metres of measured depth within the formation but the TST of the Montney target window may be only 22 metres: the well is travelling along the formation rather than through it. Accurate TST and TVT calculations from wellbore survey data plus formation dip are required for reservoir volumetric calculations (net pay thickness per well), for comparing formation tops between deviated wells in the same pool, and for designing the wellbore trajectory to maximize in-zone residence time in horizontal drilling programs. AER Directive 065 requires TVD-corrected formation top picks in all pool delineation applications in Alberta.
• Structural attitude in fold-and-thrust belt interpretation and trap definition: In the WCSB foothills fold-and-thrust belt from the Front Ranges of BC through the Alberta Foothills, the attitude of reservoir beds changes systematically across thrust-fault anticlines and synclines. Correctly defining the attitude of each structural domain (backlimb, forelimb, hinge zone, fault plane) from dipmeter logs, seismic reflections, and outcrop data is fundamental to defining the structural trap geometry (the three-dimensional closure that prevents buoyantly ascending hydrocarbons from escaping laterally or updip) and to calculating trap size, column height, and spillpoint. In the Foothills Gas play, structural attitude data from dipmeter logs in vertical exploration wells define the limb dips used to construct balanced cross-sections of the thrust geometry, which in turn provide the geometric constraints needed to extrapolate the subsurface structure between well control points and estimate the prospective area of the hydrocarbon trap. Attitude inconsistencies between adjacent wells or between wells and seismic may indicate unresolved faulting, folding, or poor seismic imaging quality, triggering reinterpretation before drilling a development well.
• Fracture attitude from image logs and natural fracture characterization: Open natural fractures in tight carbonate and unconventional shale reservoirs are planar features whose attitude (dip and strike) is critical for characterizing reservoir connectivity, predicting hydraulic fracture propagation azimuth, and designing well trajectories to maximize natural fracture intersection in formations such as the Duvernay, Nisku, and Leduc carbonates. Borehole image logs (FMI, STAR) resolve individual fractures as sinusoidal traces on the borehole wall image; the sinusoid amplitude gives the fracture dip magnitude and the sinusoid azimuth gives the fracture dip direction, from which the fracture strike and orientation relative to the maximum horizontal stress (Shmax) can be determined. Open fractures aligned with Shmax (NE-SW trending in most of the Alberta Deep Basin and NW-trending in some foothills areas) are hydraulically conductive and produce the Stoneley wave attenuation signature on array sonic logs; closed or mineralized fractures intersecting the wellbore at a high angle to Shmax are seismically visible but not hydraulically conductive. The attitude of natural fractures relative to the planned hydraulic fracture propagation direction (which tracks Shmax) determines whether natural fractures will be stimulated by or shielded from the hydraulic fracture treatment, directly influencing estimated ultimate recovery (EUR) per stage.