I guess he must have lost track of the score while waiting in line for hot dogs because production growth in U. Oil companies have to make a big deal about shale plays because that is all that is left in the world. It is completely unreasonable to expect better performance from bad reservoirs than from better reservoirs.
The majors have shown that they cannot replace reserves. They talk about return on capital employed ROCE these days instead of reserve replacement and production growth because there is nothing to talk about there. Shale plays are part of the ROCE story—shale wells can be drilled and brought on production fairly quickly and this masks or smoothes out the non-productive capital languishing in big projects around the world like Kashagan and Gorgon, which are going sideways whilst eating up billions of dollars.
None of this is meant to be negative.
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Arthur Berman: The shale gas boom is not sustainable except at higher gas prices in the US. There is lots of gas—just not that much that is commercial at current prices. If Walmart were evaluated solely on the difference between wholesale and retail prices, they would look fantastic.
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But they need stores, employees, gas and electricity, advertising and distribution. So do gas producers. A business must be commercial to be successful over the long term, although many public companies in the US seem to challenge that concept. Investors are starting to ask questions, such as: Where are the earnings and the free cash flow.
Shale companies are spending a lot more than they are earning, and that has not changed. They are claiming all sorts of efficiency gains on the drilling side that has distracted inquiring investors for a while. I was looking through some investor presentations from and and the same companies were making the same efficiency claims then as they are now.
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The problem is that these impressive gains never show up in the balance sheets, so I guess they must not be very important after all. The reason that the shale gas boom is not sustainable at current prices is that shale gas is not the whole story. Taken together, the US needs to replace 19 billion cubic feet per day each year to maintain production at flat levels.
So you can see how hard it will be to sustain gas production. Then there are all the efforts to use it up faster—natural gas vehicles, exports to Mexico, LNG exports, closing coal and nuclear plants—so it only gets harder. This winter, things have begun to unravel. Comparative gas storage inventories are near their low. The simple truth is that supply has not been able to adequately meet winter demand this year, period.
Resource estimates can be hugely misleading because they are guesses and have nothing to do with economics. OP: Do you foresee any new technology on the shelf in the next years that would shape another boom, whether it be fossil fuels or renewables? Arthur Berman: I get asked about new technology that could make things different all the time. OP: In Europe, where do you see the most potential for shale gas exploitation, with Ukraine engulfed in political chaos, companies withdrawing from Poland, and a flurry of shale activity in the UK?
Arthur Berman: Shale plays will eventually spread to Europe but it will take a longer time than it did in North America. The biggest reason is the lack of private mineral ownership in most of Europe so there is no incentive for local people to get on board. In fact, there are only the negative factors of industrial development for them to look forward to with no pay check. There are a few promising shale plays on the international horizon: the Bazherov in Russia, the Vaca Muerte in Argentina and the Duvernay in Canada look best to me because they are liquid-prone and in countries where acceptable fiscal terms and necessary infrastructure are feasible.
At the same time, we have learned that not all plays work even though they look good on paper, and that the potentially commercial areas are always quite small compared to the total resource. Also, we know that these plays do not last forever and that once the drilling treadmill starts, it never ends. Skip main navigation Press Enter.
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Posted by. Back to discussions. Expand all Collapse all. Oklahoma Shale. A family member just inherited several royalty interests in Pottawatomie County, Oklahoma. In look We have known about the shale beds forever. The new development is always a combination of existing knowledge applie Cary: Not being specifically acquainted with your area of interest, I'll defer to others more fami Please give me a call. I would appreciate the opportunity to discuss this with you further.
Gas injection for shale gas recovery
Cary Jones. Posted Reply Reply Privately Options Dropdown. In looking at the maps it appears that there are shale plays in surrounding counties, but Pottawatomie is out of luck. This brings up a question that I have wondered about.
When we hear that there is a new shale formation to be drilled, is that discovery due to new exploration or is it due to new technology being applied to an already known shale formation. How is it that these new finds in old oil producing areas were not known before? Bringing it back to Pottawatomie County, could there possibly be anything new to be discovered there or is the geological mapping already maxed out in that location.
This fluid which remains in the formation lowers the fracture conductivity, reducing or impeding the flow of oil and gas. Very often in water based hydraulic fracturing fluids, the majority of the water is never recovered from unconventional reservoirs and the water that is recovered is contaminated. Gelled fracturing fluids must be flushed from the formation to clean out as much residue as possible from the proppant pack and may result in significant fines from over-flushing.
However, creating the required extraction fluid formulation involves significant aqueous chemistry costs and is associated with the use of massive amounts of water, whereby a single stage or reservoir interval can require the equivalent of two or more Olympic size swimming pools of water being pumped down the hole into the reservoir. But water life cycle costs have risen significantly.
This is especially true in areas now experiencing water shortages and droughts, as well as those areas with fewer regional disposal well options. At the same time, public awareness and subsequent negative perception of the sheer amount of water required for each well — typically between 2. Energised solutions for extraction When it comes to hydraulic fracturing, there is significant room for improvement in productivity and also to reduce costs.
Pumping more sand and fluid into longer laterals is not necessarily the most strategic approach. While bigger may sometimes make better, in this case it does not result in optimal wells. The use of nitrogen and carbon dioxide N2 and CO2 overcomes and mitigates many of the challenges associated with traditional water based hydraulic fracturing fluids by reducing the high volumes of water, chemicals and even proppant.
CO2 serving to displace water in hydraulic fracturing continues to be a proven method used in well stimulation of reservoirs from Saudi Arabia to South Texas. Energising solutions, using CO2 or N2, provide a better approach for operating companies to increase oil and gas production from tight or water sensitive formations as well as unconventional reservoirs such as shale, tight sands and coalbed methane. N2, an alternative to CO2 for well stimulation, has also been proven effective for well stimulation of shallower reservoir environments.
Fracturing treatments energised with CO2 or N2 are increasingly being recognised for maximising long term well productivity as a result of minimising environmental damage with a smaller well site footprint without the requirement for large water retention ponds.
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It also reduces the overall costs of water transport, treatment and disposal.