Field Notes

The toe is the part of the lateral nobody can see

In the Hartshorne coal, gravity decided where the trouble collected. In a toe-up lateral, water and produced solids drain back toward the heel, where a cleanout is easy. In a toe-down lateral they settle at the toe, the hardest and most expensive place to reach. Our updip wells outperformed the downdip ones and cost less to keep clean.

Years later, evaluating non-operated interests in new Bakken drills, I haircut the unrisked recoverable by 20% to cover interventions I couldn't see. To test whether that was defensible, I built the Tail & Toe Workbench. On an illustrative 10,000 ft lateral, the risked EUR comes out about 20% lower.

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We fought H2S with bugs, and the bugs won

In a historic high-H2S Smackover field in south Arkansas, we tested microbe-based treatments using a strain that consumes H2S and also digests paraffin. Results were good enough that the operator moved to a purely microbial schedule and dropped production chemicals, saving roughly $250,000 a year.

The surprise was flow: several rod-pumped wells began flowing on their own. Lessons: treat the injection side as well as producers, watch wellhead integrity as pressures rise, look for value in the cost line, and gather downhole data so a good result can be explained and repeated.

The reserves audit is won in March, not December

The forecasts that draw an auditor's hardest questions usually aren't the wild ones. They're the ones that look fine: a curve that ties to the last data point but carries a b-factor above 1 and no terminal decline, so on paper the well never reaches its economic limit.

What draws questions: declines that don't honor the last 12 to 24 months, LOE and differentials not tied to lease operating statements, PUDs without an approved and funded plan inside five years, and interests that don't tie to land records. Check them against actuals all year and the audit becomes a review instead of a negotiation.

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Drilling some of China's first horizontal coalbed methane wells

Shortly after founding Source Rock, we took a consulting contract with a U.S. company holding large coalbed methane concessions in Shanxi and Yunnan provinces. Our field hands rotated 28 days on, 28 off, for about a year.

In Shanxi we kept it simple: a single updip lateral so water drained to the heel. In Yunnan we drilled a vertical well into the coal, moved about 2,500 ft away and drilled a downdip horizontal that intersected it in the seam. The pump sits in the vertical, the horizontal does the draining, and gravity carries the water to the pump.

Book proved. Manage to 3P.

PDP is what the bank lends on and what gets audited, but on paper every PDP-only company is in decline. Tracking proved, probable and possible reserves internally keeps the real inventory, recompletions, workovers and undeveloped locations, in the database with forecasts and economics.

It shows where new production came from, lets you rank a recompletion against a new drill on the same price deck, documents the upside buyers pay for, and forces the useful question: what would it take to move this from possible to probable?

What horizontal coalbed methane taught me about shale

In 2005 I presented a paper to the Oklahoma Geological Survey on horizontal completion practices in the Arkoma Basin's Hartshorne coal. Four things separated the good wells from the bad: drill updip, orient the lateral across the face cleats, protect the coal with native or KCl water instead of gels, and stay in zone.

On the wells I designed, with medium-radius builds of about 700 ft, we kept the lateral in the seam 98% of the time. Shale development runs on the same principles today.

Chevron's first Gulf of Mexico horizontal sidetrack

In 1995 I recommended, and helped drill and complete, Chevron's first horizontal sidetrack in the Gulf of Mexico, at a time when plenty of people doubted horizontals would pay offshore.

What made it work wasn't the technology. It was knowing the reservoir well enough to show where the remaining oil was and why a horizontal would reach it better than a vertical. The best wells still come from understanding the rock before spending the capital.

Why short-history wells overstate EUR

Early in a horizontal well's life, transient linear flow dominates. Fit an unconstrained Arps curve to those months and the b-factor often lands above 2, the curve flattens and the 30-year EUR balloons; in this illustrative case by 72%.

The fix: cap b or anchor to analog type curves until boundary-dominated flow appears, flag short-history wells in any acquisition screen, and re-forecast as history builds. A disciplined b-factor is one of the cheapest risk controls in an evaluation.

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