As I understand it , the fracking fluid will flow to the surface dependant upon a number of factors. More importantly is the quantity of proppant which remains within the frack, ie the volume of sand grains held in suspension in the fracture which probably will have been bonded together with gum or resin in the fluid. Getting the fluids out is one thing, but to have successfully fracked and successfully inserted vast quantities of proppant which remain in situ is more important. The liquid will either flow to the surface or may have leaked elsewhere such as into a watersystem, unlikely at these depths. It may however be that the pressure at that depth causes the frack to completely close, no gas comes to the surface. The vertical wells will have told the design engineers all that they needed to know. Type and depth of the shale and surrounding rocks and gas flowed to the surface from the vertical from a narrow well. For every foot of horizontal successfully fracked, that is equivalent to a foot width of vertical well bore. We have successfully fracked 1500 feet length. Imagine the gas from a 1500 foot wide vertical well bore hole. That is what this will produce, and there is no maybe about that.IMHO. Expect the flowback to take several weeks at least. The flowback must be measured to report to environmental agencies regarding volumes of water needing treatment (if not reused in another frack) and to know the amount of chemical required to treat the flowed back water. Proppant in suspension, and corrosive chemicals etc, must be removed before the water can be safely dumped. The recovered proppant from the well is an indication too of how much sand remained within the well, holding open the frack. The fact we used sand tells me that ceramic proppant was not needed, no very high pressure or temperatures encountered. Everything seems to be good news, relax and wait for a few weeks. I suggest you ignore this site for a while and read a long book.
August 20, 2014 11:59 pm Shale is winning out over conventional wells From Mr Mike Stoddart. Sir, Martin Gooch’s letter (August 13) about the “crippling problems of shale oil and gas” is wide of the mark in a number of respects. While he is correct to highlight that depletion rates for shale oil wells are higher than for “conventional” wells, operators know about this before they drill the well but are happy to do so. Companies assess the prospective economics of an oilfield by calculating the net present value of the cash flows and the internal rate of return on their investment. The fact that depletion rates are higher makes shale oil drilling much lower risk than conventional wells because a high proportion of the estimated ultimate recovery of a well is produced in a short period after the well is completed. Using the language of the bond market, the income stream is of low duration (ie low risk) compared with a high duration (or high risk) for a conventional well. When drilled in known formations in the main US basins, shale oil also benefits versus conventional oil in that there is little (or no) exploration risk. The geology is often “layer cake” and the companies are not hunting for conventional oil traps (anticlines, tilted fault blocks and the like), many of which will have been breached at some time resulting in “dusters” once drilled. Once discovered and appraised, offshore conventional oil and gasfields require huge upfront investment before they can be brought on stream and often see substantial cost escalation between project approval and completion date. They are also usually late. These are factors that have plagued developments such as the Kashagan field in the Caspian Sea and, most recently, the Alma/Galia development of EnQuest. Shale oil drillers in the US, by contrast, have been raising their productivity by increasing the proportion of their wells that are horizontal (increasing the amount of formation exposed to the well-bore) and doing more frack-stages in each well. They are also lowering their drilling costs. EOG Resources, now the biggest oil producer onshore in Texas, is targeting completed well costs in the Eagle Ford of just $5.7m for 2014 – a tiny fraction of what it would cost to drill a conventional well offshore. With estimated ultimate recovery for each well of about 450,000 barrels – worth nearly $44m at current prices – this is expected to give the company a rate of return of over 60 per cent on its investment. The company’s recent interim results showed the company with operating margins of nearly 27 per cent – hardly the “crippling problem” Mr Gooch’s letter suggests. Mike Stoddart, Investment Analyst, Brown Shipley, Manchester, UK
Sold its Slovakian subsidiary, Aurelian Oil & Gas Slovakia ("AOGS") s.r.o to Discovery Polska LLP, a private Texas based company. AOGS holds a fifty percent interest in the Svidnik, Snina and Medzilaborce Concessions. San Leon received back €153,054 in relation to costs incurred and
"an overriding royalty interest equal to 3.5% of all hydrocarbons produced in the concessions."
Discovery Geo plan to drill two wells on these concessions targeting shallow oil for early production.
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