depth-derived, Oil & Gas Glossary

What Is Depth-Derived?

A depth-derived measurement in well logging and drilling engineering is any quantity computed from measured depth (MD) along the wellbore trajectory using directional survey data, including true vertical depth (TVD), true vertical thickness (TVT), true stratigraphic thickness (TST), and depth-converted log curves, all of which correct the raw measured depth along the deviated wellbore to the actual vertical or stratigraphic dimension needed for reservoir characterisation and volumetric calculations.

Key Takeaways

Measured depth (MD) follows the wellbore trajectory; true vertical depth (TVD) is the vertical component below the reference datum.
For vertical wells TVD equals MD (corrected for Kelly bushing elevation); for deviated wells TVD is always less than MD.
True stratigraphic thickness (TST) corrects for both wellbore deviation and formation dip to give the actual layer thickness perpendicular to bedding.
All depth-derived quantities require accurate directional survey data (inclination and azimuth at every survey station).
Errors in directional survey data propagate into all depth-derived quantities and can cause well placement errors of tens of metres at depth.

How Depth-Derived Values Are Computed

When a directional well is drilled, the wellbore follows a curved path from vertical at surface to the planned angle and azimuth at the target. The length measured along this path is the measured depth, recorded from the drill floor or rotary table reference (the Kelly bushing or rotary table elevation above sea level). To convert measured depth to true vertical depth, directional survey data is used: at regular intervals (typically every 30-90 metres), the inclination (angle from vertical) and azimuth (compass direction) of the wellbore are measured by a magnetic or gyroscopic directional tool. These survey measurements define the wellbore trajectory in three-dimensional space and allow the vertical component of each depth increment to be computed as TVD increment = MD increment × cos(inclination).

The minimum curvature method is the industry-standard algorithm for computing TVD from directional survey stations. It assumes the wellbore follows a smooth circular arc between consecutive survey stations and computes the spatial coordinates of each station by integrating the directional data using the average of the inclination and azimuth vectors at the two endpoints of each interval. The minimum curvature method is more accurate than simpler averaging methods (such as the tangential or balanced tangential methods) for typical wellbore curvature rates and is used in all commercial directional drilling software for positional uncertainty analysis and TVD computation.

Depth-Derived Applications Across International Jurisdictions

In Canada, depth-derived TVD values are required in AER well submissions for all deviated and horizontal wells. AER Directive 059 (Well Drilling and Completion Data Filing Requirements) specifies that directional surveys must be submitted with sufficient station density to characterise the wellbore trajectory, and that pay interval tops and bases must be reported in both MD and TVD. Horizontal Montney wells commonly have TVD values 800-2,500 metres less than total MD at the toe of the lateral, reflecting the 2,000-4,000 metre horizontal extension drilled at ~90° inclination. Pool fluid contact depths (oil-water contact, gas-oil contact) are always reported in TVD so that contacts defined at one well can be mapped across the pool to other wells with different deviations.

In the United States, BSEE OCS well completion submissions require TVD depths for all reported formation tops and completion intervals. In the Gulf of Mexico where extended-reach drilling from centralized platforms may place the wellbore 10+ km from surface with significant TVD-to-MD differences, accurate depth-derived TVD is essential for reservoir correlation between wells on the same structure. The SEC reserve reporting rules require reserve volumes to be defined by depth contours in TVD, not MD, to ensure geologically consistent reservoir boundary definition across multiple wells. In Norway, Sodir NPD Diskos well data submissions require directional surveys and TVD profiles for all directional wells; Norwegian well naming conventions include the TVD of the reservoir penetration in the field nomenclature for some fields. In the Middle East, Saudi Aramco's maximum reservoir contact (MRC) wells — with lateral lengths of 7-12 km and complex 3D wellbore trajectories — require extremely precise depth-derived TVD and TST calculations to place perforations and completions within the thin horizontal oil column above the aquifer contact.

Fast Facts

In a horizontal well drilled at 90° inclination through a 15-metre thick reservoir with 10° formation dip, the measured depth of the pay interval can be 20-100 metres while the true stratigraphic thickness of that interval is still only 15 metres. Without the TST correction, a log analyst would compute porosity-feet and water saturation across the apparent 20-100 metre pay, dramatically overstating net pay volume. The TST correction divides the apparent (MD-based) thickness by a factor of cos(wellbore angle from normal to bedding) to recover the true layer thickness — a correction that can change net pay estimates by factors of 5-10 in near-horizontal wells through dipping formations.

True Stratigraphic Thickness Corrections

True stratigraphic thickness (TST) is the thickness of a formation layer measured perpendicular to the original depositional surface (the bedding plane). In a vertical well drilled through horizontal beds, MD increment equals TVT (true vertical thickness) which equals TST when bedding is horizontal. When bedding dips at an angle to horizontal, TVT and TST differ: TVT is the vertical thickness of the bed, TST is the perpendicular-to-bedding thickness. In a horizontal well drilled at high inclination, the wellbore may traverse the formation nearly parallel to bedding, greatly exaggerating the apparent MD-based thickness over the true bed thickness. The general formula for TST from MD in a deviated well through a dipping formation is TST = MD increment × sin(90° - |inclination - dip|), where inclination and dip are both measured from vertical. This correction is critical for accurate net pay calculation, volumetric reserve estimation, and log response corrections in horizontal wells.

Tip: When correlating formation tops between a vertical and a horizontal well in the same field, always convert both wells' formation tops to TVD relative to the same reference (typically mean sea level, TVDSS) before comparing. A formation top at MD 3,200 m in a vertical well and MD 5,800 m in a horizontal well may both correspond to the same TVDSS of -2,750 m (2,750 m below sea level), confirming structural correlation. If you compare the two MD values directly, the 2,600-metre difference is meaningless — it reflects wellbore path length, not formation depth difference. All structural maps and reservoir correlations must be built in TVD or TVDSS space, never in MD space.

Depth-derived is also referenced as:

TVD-converted — used when log curves measured in MD have been interpolated to TVD sampling intervals for use in reservoir models; "TVD-converted sonic log" means the sonic log depth track has been resampled from MD to TVD
Depth-corrected — used when the depth-derived calculation is specifically removing a bias from the raw MD measurement; for example, "depth-corrected net pay" means net pay has been corrected for wellbore deviation and formation dip
TVDSS — true vertical depth subsea (below sea level); the most common reference datum for depth-derived quantities in offshore wells; replaces the Kelly bushing datum (TVDKB) for inter-well correlation where different rigs may have different KB elevations

Frequently Asked Questions

What reference datum is used for TVDSS in a well?

TVDSS (true vertical depth subsea) is referenced to mean sea level as zero, with depths below sea level being positive numbers and elevations above sea level being negative. The conversion from MD to TVDSS requires knowledge of the Kelly bushing (KB) or rotary table (RT) elevation above mean sea level, which is surveyed at well construction. TVDSS = TVD (from KB) - KB elevation. For example, if the KB is 30 metres above sea level and a formation top is at TVD of 3,000 m from KB, then TVDSS = 3,000 - 30 = 2,970 m. For offshore wells where the rig floor may be 20-30 metres above mean sea level on a jackup or 100+ metres on a drillship or semisubmersible, the KB elevation correction is significant and must be applied consistently across all wells in a field to ensure that structural contour maps are geologically valid.

Why do LWD logs differ in depth from wireline logs in the same well?

LWD logs are depth-referenced to drill pipe measured depth at the time of drilling; wireline logs are depth-referenced to the wireline cable depth at the time of logging. These two measurements differ because drill pipe stretches under tension differently than wireline cable, and the mechanical stretch of the string changes with well geometry, mud weight, and temperature. Additionally, bit depth errors accumulate differently in LWD versus wireline due to differences in how depth is measured. Typical depth offsets between LWD and wireline logs in the same well are 0.5-3 metres per 1,000 metres of depth, but can exceed 5-10 metres in deep deviated wells. When integrating LWD and wireline data in a composite log, a depth-matching (depth shift) correction must be applied by correlating distinctive marker beds (radioactive shales, tight limestone markers) visible on both log suites to bring them into alignment before using the combined log data for formation evaluation.

Why Depth-Derived Measurements Matter in Oil and Gas

The entire value chain from wellbore drilling to reservoir characterisation to production optimisation depends on knowing accurately where the wellbore is, what formation it is in, and what the true thickness and depth of reservoir intervals are. An error in TVD calculation that places a wellbore 15 metres above its actual position can mean the difference between landing in the productive oil column and landing in the nonproductive water leg, making the difference between a commercial well and a dry hole. In complex extended-reach and MRC wells where multiple lateral branches must be steered to stay within a 10-20 metre oil column above the aquifer contact, the accuracy of real-time depth-derived TVD from LWD measurements directly determines how much of the reservoir is contacted and how much water-free production the well delivers. Depth-derived calculations are therefore not bookkeeping details but fundamental measurements that determine whether wells succeed or fail in their reservoir objectives.