What's new in exploration

During most oil price-induced, mid-term industry-wide recessions, we often retreat to what others started doing, during the early reaction to the downward price change. Sadly, we follow the dust of those blowing “retreat.” Safety is found in the herd. We hope that the wolf won’t pick on me this time. As I predicted last year, this is going to be a buyer’s market for M&A.

Upturns usually result, when some brave soul[s] do something that others have not done, ever. Others will attempt innovations not universally accepted, or find an idea not applied previously to a new or emerging situation. The world has seen this over and over, yet our behavior in the face of adversity is overly predictable. “If you only base your decisions on empirical data, you can only repeat [the success and mistakes] what somebody else already did,” said TD Jakes during a Fox interview on his book discussing intellect vs instinct. For you older U.S. football fans, Vince Lombardi said, “the best defense is a good offense.” I think he was paraphrasing from Gen. George Patton or Attila the Hun.

The Macondo disaster’s impact on ultra-deepwater exploration activity was enormous. However, in dollars, it was rather minor, compared to the impact of U.S. shale oil capitalization on deepwater exploration. Let’s face it, a 200-MMbbl oil field in 11,000 ft of water that needs at least $6 billion in front-end investment does not sound as appealing as 1 MMbbl of oil under a 70-acre strip in North Dakota or South Texas. The math: for 1 MMbbl of oil, there will be $200,000 in leases, plus $8 million in drilling and completion costs, with 25% to owners and 20% to government. At $70/bbl of oil, that is $70 million minus, say, an extra $9 million of G&G and $31.5 million in tax and title, to net about $21.3 million. Am I missing something here, or is OPEC? Repeat this per well, times 200, with minimal environmental or litigation concerns, and you can see the risk/reward factor. Does $70 oil sound good to you today?

The next breakout will not be from technology, alone. Sorry Shell [E&P magazine, October 2014], but folks will not let you use their smart phones to collect geophysical data. Besides, you would have to cut a deal with the current data collectors—Google and Facebook. The next big breakout will come from where that technology is used to save money. Not too long ago, the leap from 2D seismic to 3D was heralded as the breakout of the century. The “however,” here, is where did we go to shoot the first 3D? Right over where we had shot 2D. There was a significant time gap before we spent money on 3D in new areas with no seismic. The Ramform Explorer is now a worn-down ship, but not the 3D idea it evoked; e.g., look up the new PGS Titan class.

What’s new? As the industry looks under the carpet and between the seat cushions for nickels, please turn your attention to the ROZ and CO₂ efforts that those poor folks in Midland, Texas, have been conducting. Many would argue that they are not using any exploration technology. CO₂ engineers will point out that explorationists, first producers, secondary producers, and tertiary producers still left behind most of the reservoir oil. Our research at RPSEA would agree. What better place to retreat to, and find low-risk oil in a recession than looking in oil fields.

What’s needed this year for “new” in technology? Answer: Concentration on interpretation while throwing off some of the old rules-of-thumb. I recall finding C₁₂/C₁₄ in water in the Mississippian formation of the Powder River basin. From outcrop to well, that meant rainwater had moved at 2–4 ft/year to trap oil in very old rock. I recall an oilco that I worked for, which had data showing that no oil they owned was more than 1 million years old. I also recall a discussion one night in 1976, with a Texaco hand, that they observed oil moving through water in reservoirs. I can prove that all oil is dynamic and not static, especially over geologic time. How difficult then, today, to visualize CO₂ carrying oil across water to your production system? Today Big Oil researchers struggle on how to get a methane molecule out of a near-solid rock with nano-Darcy perm.

Some rules to break: 1) Sw at 65% is the oil water leg. At most temps and pressures, there is probably not a defined water-oil interface, so throw out that cartoon of a trap with gas/oil/water. The ROZ folks are already ahead of you. In fact, have you ever seen Sw =0 ? Archie was right in 1942. 2) The reservoir is water drive. We freely use bubble-point thinking in development, but not in exploration. Have coffee with a flow assurance engineer, and learn about supercritical fluids and their behavior. 3) Low-frequency seismic, inverted, will resolve geological horizons, as seen on logs. Logging today still has issues with mud invasion, but it remains a good tool, somewhat limited to inches past mud over a few feet vertical. Most reservoirs shown on logs are well under the resolution of 5-hz seismic at rock velocities of 7,000 fps and above. 4) Color improves frequency. 5) Peter Vail was right, that seismic follows depositional interfaces. Okay, he was right a lot, and it took years to convince us. But it is also true that most of the seismic we use cannot resolve depositional interfaces to the detail that the lacustrine or fluvial geologists would want. More than one drilled paleo-volcano has shown perfect seismic off lap, but was not a hydrocarbon accumulation.