My last post on geosteering took a high-level look at wellbore placement across unconventional basins. In closing I promised to next look at some problematic areas—places where out-of-zone wellbore placement occurred at a higher rate than in well-controlled areas, like the Central Basin Platform, Mid-Continent, or the Midland Basin.
Let’s start by asking the question a few questions: Does being out of zone matter? Is production impaired by landing less lateral than planned in your target zone?
Since I called the DJ Basin problematic, and I received several comments from folks who are actively placing wells in the DJ, and who reinforced the idea that structural complexity causes the out-of-zone problems, I thought we’d start there.
Of the wells in our Play Assessments app that have targeted the Niobrara B as a landing zone, and for which we have directional surveys, nearly 28% have been characterized as having less than 75% of the wellbore in zone.
Compare the map below—colored by Peak Oil rates—of the wells in the Niobrara B that have 75% or more of the lateral in zone …
… with this map of the Niobrara B of wells with less than 75% of the lateral in zone.
Note that in the map of <75% in zone, there are fewer wells with higher peak oil rates.
Zooming in we can see that the distribution of “good wells”—using the assumption that high peak oil rates are a proxy for more favorable EUR values—is much higher in the “in-zone” map:
The following montage shows that wrench and other faulting with appreciable throw/heave occurs in the Wattenberg area and appears to persist to the northeast (for reference, red and pink boxes refer to the map and the well cross section in the montage below).
So, no mystery here. Faulting offset in the DJ through the Niobrara section requires out-of-zone wellbore path manipulation to stay on track to place the majority of the lateral in the upcoming downthrown fault block.
Interestingly, First 12 oil rates in the Niobrara B are counterintuitive. You’d think that the more wellbore in zone (100%), the higher median First 12 oil volume would be compared with wells with less wellbore in zone.
That’s not the case. The following graph hints that the opposite may be true.
Median proppant values are relatively consistent across all ranges of in-zone percentages, and as the graph below shows (for wells with less than 60% in zone) variations in proppant per perforated foot don’t correlate well with First 12 oil.
Perhaps, being more out-of-zone in the DJ implies greater faulting, and with greater faulting, chances are that natural fractures improve flow rates.
This kind of first cut evaluation will at some point need to be normalized for other important variables such as lateral length, frac job size, etc.
However, even when normalization is performed, there is still meaningful variability in results, as shown below (Niobrara—from DI Engineering Explorer).
We can conclude that using DI Play Assessments out-of-zone metrics can be used to high-grade basins, or areas within basins, that are likely to have higher percentages of wells with 75% or more of lateral in zone, but we should be careful about assuming that in-zone percentage correlates with better production values in faulted plays. In areas known to be faulted like the DJ, out-of-zone wells hint at faulting complexity and the enhancement to reservoir flow that natural fractures confers.
Naturally there are some outliers, so in the last part of the series I’ll look at some of these and then dig into production metrics.
If you’ve got perspectives on using in-zone, out-of zone percentages as drivers (or not) of production response please email me at email@example.com.
Latest posts by Mark Nibbelink (see all)
- The Rewards of Staying in Zone?—Geosteering Part III - July 12, 2019
- The Future Evolution of Demand - July 11, 2019
- Geosteering—Are We There Yet? Part 2 - June 21, 2019