Apples and Oranges

How unconventionals stack up against conventionals

In a preliminary conference day ahead of the main days of the European Unconventional Gas Summit Paris 2011, Adrian Topham, Product Line Manager for Reservoir Development Services at Baker Hughes spoke of the essentials of shale gas in Europe, asking questions like: What is shale gas? How does it compare with conventional gas plays? What technologies make shale gas viable? And, how to make shale gas commercially successful?

First, Topham asked that everyone in the room categorize themselves, adding a tally to several categories on a drawing board. The final chart showed that most people in attendance were operators or service providers.

He asked: “What’s at the front of your mind: the viability, the environmental concerns, or something I haven’t thought of?”

He showed a slide of North American shale gas resource estimates from the Barnett, Marcellus, Antrim and Eagle Ford shales. “The size of these makes them pretty viable compared to any conventional play,” he said.

In terms of resource estimates for unconventionals, Topham looked at thousands of cubic feet (TCF) from the year 2000 to 2010.

“The EIA predicted there to be over 1 TCF/year, and we’re up by 4 TCF. Predictions have been problematic,” he commented. “Resource estimates are changing as we move forward.”

Topham presented a map of the key shale gas basins in Europe. It listed countries in terms of activity: Poland’s Silurian and Ordovician black shales; Germany’s carboniferous and Jurassic; then France, Austria, Netherlands, Sweden, UK, Bulgaria, Romania and Hungary.

Then, he offered four types of unconventional gas: gas hydrates, tight gas, CBM, and shale gas, which he said was produced from high TOC shales through the use of horizontal drilling and stimulation methods.

“We believe the other three are less significant,” he commented.

“For shale gas, the plays do not require a conventional structural trap,” said Topham. “Use of a stimulation technique is always needed to produce gas from shales. Estimates are in the thousands of TCF of technically recoverable resource in the US/Canada shale gas plays.”

Shale, he said, was the earth’s most common sedimentary rock and the keys to developing it were horizontal drilling and fracture stimulation.

Topham said success could depend on the size of the prize, that large regional plays contained minimal structural risk.

Topham harkened back to conventionals in which gas molecules were stored under pressure within rock pores and showed a slide of a conventional petroleum system, pointing to a “shaley” generation layer which migrates to an upper layer where entrapment takes place.

“Shale gas deposits don’t need trapping mechanisms,” he contrasted, “but are stored in voids of natural fractures. The hydrocarbons found in these shales are self sourced - gas shales must be fractured.”

According to core data, he said shale was the most common sedimentary rock and was normally rich in organic material.

A schematic shown contained one band depicting gas-rich shale, which prompted Topham to comment: “Whereas tight gas needs some kind of trapping mechanism shale gas does not.”

Absorption, he said, generally accounted for over 50% of the total stored gas volume.

He laid out the main characteristics of conventional exploration and production versus that for shale gas. “For shale you avoid lateral/vertical migration pathways & measure shale brittleness,” said Topham.

He listed a shale’s key parameters including gas in place, and sufficiently high TOCs.

Topham explained, “The rock needs to be brittle so that it will crack. The stress regime depends on the direction. Over pressure might require high strength proppants.”

In terms of shale gas production basics, he spoke about the typical steep decline of well production. In connection with that he showed a comparison of the various shales in the US. “Making it work in North America, we’ve got these huge numbers of rigs (like 60-70 at Barnett) to keep them productive,” he explained.

“The advances in order to make them commercial have largely been in horizontal drilling and hydraulic stimulation (fracking).”

Further advancements, said Topham, included the increased use of dual laterals and low pressure, among others.

To “stay on target” he mentioned Baker Hughes tools like AutoTrak and G3/OnTrak.

He gave mention to drilling bit performance. “If you want faster rates, diamond bits are the way to go,” said Topham. “Their rate of penetration has almost doubled with the introduction of geosciences technologies.”

He reported that average days per well could be reduced by nearly half, from 31 days to 15.

“Actual operations,” said Topham, “involved dozen of trucks, and silos of water. Contrast that to actual operations in Europe: a smaller pad, which is more compact, but from the air it’s still a fairly big site. We re-use about one third of the water.”

“In order to keep the footprint down,” he continued, “having a drill pad with multiple horizontal wells can be drilled - it’s the way to keep it down.”

In conclusion of the session, Topham said shale gas plays were very different. “There’s lower geologic risk but you need to find a basin that has high TOCs. Production from shale is possible due to tech breakthroughs, and unit production costs are decreasing.”