Shale Billionaire Hamm Tackles ‘Generation 3’ Rock, Continental Resources chairman is seeking ways to pull crude from sites passed over during the boom he helped start by David Wethe with assistance from Kevin Orland and Sarah Chen, November 8, 2023, Bloomberg
Welcome to Energy Daily, our guide to the energy and commodities markets powering the global economy. Today, reporter David Wethe outlines Harold Hamm’s plans for the future of US shale.
As the aging US shale industry frets about the depletion of top-tier drilling sites and turns to megamergers to lock up more inventory, one of its pioneers is already on to the next phase.
Harold Hamm — the US wildcatter who used sideways drilling to unlock North Dakota’s Bakken formation — is now seeking ways to pull crude from rocks passed over during the shale boom he helped start more than a decade ago.
“What we’ll need in the future is what I’ll say is Generation 3,” Hamm, 77, said Tuesday at an energy conference hosted by the Federal Reserve Bank of Kansas City and its sister bank from Dallas. “That’s to deal with the tough rock that contains a lot of things that heretofore we weren’t able to produce, and also to get more out of the Generation 1 and 2 rock.”
Hamm’s endeavor is a sign of the optimism oil executives have that new technology can again be harnessed to wring crude from currently marginal sites. It also illustrates the industry’s confidence that fossil-fuel production will be around for a long time.
Where horizontal drilling was key to unlocking shale — which Hamm dubs Generation 2 rock — a new wave of inventions will be needed to make Generation 3 rock productive, Hamm said. That includes drilling out the so-called tier 2 and tier 3 shale deposits, which are more expensive and require higher oil prices to be economical.
It also includes capturing carbon and pumping it back into the ground to make more oil flow, he said.
Those advances won’t be easy.
Rising inflation gets built into the US oil industry so that it needs $75 to $80 a barrel to produce oil and gas, Hamm said. That’s a big difference after getting used to $60 oil.
BloombergNEF said last month that oil companies need to clear $86 a barrel to profit from their costliest wells, up 50% since March of last year.
Still, the self-described optimist Hamm didn’t seem worried.
“We’ve had good examples in Oklahoma working with Gen 3 rock,” Hamm told the audience at the Petroleum Club in Oklahoma City. “And there’s going to be a lot of other examples we talk about as technology unlocks those.”
Refer also to:
2006 May: The Role of the Upper Geosphere in Mitigating CO2 Surface Releases in Wellbore Leakage Scenarios
2006 June: Possible indicators for CO 2 leakage along wells by Bachu and Watson, 8th International Conference on Greenhouse Gas Control Technologies, Trondheim, Norway
… Storage safety refers to the potential harm to other resources, equity and life that a CO2 leak may entail.
The probability and effects of leakage from CO2 storage sites need assessment by both the operator and regulatory agency during the application and permitting process, during the operational phase and after site abandonment [3]. Any fluid in the subsurface, especially a buoyant one like CO2 , will migrate laterally within the injection unit and may leak upwards across formations through faults and fractures and/or defective wells [1, 4]. The potential for CO2 leakage through fractures and faults can be well managed through proper geological characterization and selection of the storage site, and through proper operating procedures. Managing the potential for CO2 leakage through wells is more difficult. Exploration and production wells have been drilled, completed and abandoned since the middle of the 19th century, with variable technology and materials, and with no or under variable regulatory regimes. Well materials (cements, steel, elastomers, etc.) will or may degrade over time, particularly in the presence of corrosive agents such as saline formation water and CO2 [5, 6]. Thus, the potential for leakage through existing wells needs to be assessed for site selection and remediation. New wells will also be subjected to the same in-situ conditions as the existing wells.Dr Tony Ingraffea subsequently found new wells to be worse leakers than older ones, which makes sense given the oil and gas industry’s relentless greed, lies, and demanding degegulation which has been consistently granted by our deregulators, notably Alberta’s “No Duty of Care” legally immune AER. …
2007: Presentation on above 2006 paper Factors Affecting or Indicating Potential Wellbore Leakage by Watson and Bachu at the Alberta regulator, AER (when it was EUB), no less!
2008: Bachu, S., Buschkuehle, B.E., Haug, K. and Michael, K. (2008): Subsurface characterization of the Edmonton-area acid-gas injection operations; Energy Resources Conservation Board, ERCBNow AER/AGS Special Report 92, 134 p.
… From Page 88:
Figure 59 shows the extent of the Acheson original Blairmore T and subsequent St. Albert-Big Lake Ostracod A pools, and of the Strathfield (undefined) gas reservoir in the context of lithofacies changes in the Lower Mannville Basal Quartz and Ellerslie formations. When approval was granted for acid gas injection at Acheson, the regulatory agency required the operator to file annually with EUB and each other operator in the Acheson Blairmore T and St. Albert-Big Lake Ostracod A pools progress reports that “shall include the impact of acid gas injection on the performance of offsetting producing wells”. In March 2004 the operator at Acheson reported that CO2 was detected in 2003 in well 10-22-53-26W4 in the St. Albert-Big Lake Ostracod A pool, located at 3,625 m north from the acid-gas injection well. No H2S has been detected in the produced gas. Since at Acheson the average composition of the acid gas is 87% CO2 and 11% H2S (Table 14), with H2S being denser and more viscous than CO2, it is expected that CO2 would show first at a producing well. In addition, diagenetic processes within the reservoir could have reduced the H2S concentration in the injected acid gas as a result of pyrite precipitation, if an iron source was available. The issue was brought to EUB’s attention andwas heading to a hearing, but the operator at Acheson has indicated to the regulatory agency that it has initiated an Appropriate Dispute Resolution process with the operator of the offset producing well to address the issue of CO2 breakthrough, and that this situation “will be addressed pursuant to the terms of the Mediated Settlement Agreement”.
This case shows that, after 13 years of injection, CO2 has migrated northward a distance of [nearly 4 km] mostly under the combined drive of injection and production. The drive into the St. Albert-Big Lake Ostracod A gas pool has increased lately with the large spike in gas production from this pool (Figure 57b). There are five producing wells much closer to the acid-gas injection well (Figure 59) that did not report CO2 breakthrough, but these wells are owned by the same operator that operated until recently the Acheson acid-gas injection site. If acid gas broke through at any of these wells, it is most likely that the operator just stripped the acid gas from the sour reservoir gas and re-injected it, as the produced gas in this area is sour to begin with. Understanding the migration path and fate of the injected acid gas at Acheson requires a separate study that is beyond the scope of this report. …
2012: CO2 in Stream, Dead Ducks Prompt Wyo. DEQ Citation against Anadarko
2012: Earthquake risk for carbon capture and storage schemes
Move over fracking: carbon capture and storage schemes (CCS) are more likely to trigger earthquakes, warns the US National Research Council (NRC). Meanwhile, a separate study warns that quake-fractured rocks could undermine CCS efforts by allowing the trapped gas to leak back into the atmosphere.
Carbon sequestration involves pumping CO2 at high pressure below ground and trapping it in porous rocks at depths of 1 to 4 kilometres. ….carbon capture and storage could see billions of cubic metres of fluid injected below ground – potentially enough to trigger more and larger quakes, the report concludes.
Even if those quakes do not damage property or put lives at risk, they could undermine carbon capture schemes, says Mark Zoback, a geophysicist at Stanford University in California. “If you trigger an earthquake, you are threatening the seal of the repository,” he says. “CO2 is buoyant and it wants to rise and get out.” …
2012: Peer reviewed PNAS paper: Earthquake triggering and large-scale geologic storage of carbon dioxide
Despite its enormous cost, large-scale carbon capture and storage (CCS) is considered a viable strategy for significantly reducing CO2 emissions associated with coal-based electrical power generation and other industrial sources of CO2. … We argue here that there is a high probability that earthquakes will be triggered by injection of large volumes of CO2 into the brittle rocks commonly found in continental interiors. Because even small- to moderate-sized earthquakes threaten the seal integrity of CO2 repositories, in this context, large-scale CCS is a risky, and likely unsuccessful, strategy for significantly reducing greenhouse gas emissions
2018 US Geological Survey: Induced Seismicity Associated with Carbon Dioxide Geologic Storage
LEFT: The CO2 pipeline rupture. RIGHT: Vehicles pass over the pipeline explosion site in Satartia in July. Yazoo County Emergency Management Agency/Rory Doyle for HuffPost