We have results on the YPx-1 but unless I read this wrong how about the CHx-1? Below is from current presentation
Well logs and tests on two key wells
- CH.x-1 – Lower Agrio Oil test
3,000 – 3,200 m
- YP.x-1 – Mulchinco gas and liquids test
I liked the comments on the need for a very heavy drilling mud. Would be nice to see a little more detail on what was found pressure wise in each zone
I would say the situation with well inventory at record levels and frack stages hitting 90 per well could mean a very bright future but only after the price of oil turns
Good for Rockpile in long term
Surprised the market did not respond to the news. This is a solid step to increasing the asset value of the company and ultimately the takeover price.
Canada has alternative pipeline projects in the works. The looser is the American worker
Another Enbridge project, the proposed Northern Gateway Pipeline would take 500,000 barrels per day of tar sands oil 731 miles in a different direction — to Kitimat, B.C., on Canada’s West Coast, from Edmonton. The pipeline, at a cost of $6.5 billion, is expected to open up Asian markets for Alberta crude and is controversial for its possible environmental impact as it crosses the Canadian Rocky Mountains. Northern Gateway received government approval last year with 209 environmental conditions to meet.
First Nations tribes are mounting legal fights to stop the Northern Gateway from being built, saying it violates aboriginal land rights as fears about the impacts of possible oil spills from the pipeline galvanize more opposition. The project has lost momentum in recent months because of rising opposition and costs related to meeting the environmental conditions the Canadian government imposed on the project.
Trans Mountain Pipeline
The Pacific Coast is also the destination for U.S.-based Kinder Morgan’s Trans Mountain Pipeline expansion, which would nearly triple the 300,000 barrel-per-day capacity of the existing 710-mile pipeline stretching from near Edmonton to Vancouver. Expected to carry 890,000 barrels per day of tar sands oil to port en route to Chinese refineries, the $5.4 billion Trans Mountain Pipeline is currently being reviewed by Canadian regulators, who are likely to decide whether to approve the project sometime next year. Kinder Morgan wants to finish construction on the project in 2017.
TransCanada is envisioning a $9 billion alternative to Keystone XL called Energy East that, if completed, will carry more than 1 million barrels of oil per day to Canada’s East Coast. Much of the proposed 2,858-mile Energy East is already built, stretching from Saskatchewan to Quebec. TransCanada plans to extend the pipeline from near Montreal to refineries in St. John, New Brunswick, where the oil could be refined locally or loaded on tankers en route to other refineries along the Texas Gulf Coast or ports beyond.
Energy East, opposed by many environmental groups and First Nations people along its route, is slated for completion in 2018 and is under environmental and regulatory review by the Canadian government.
Old standard was 3.5 million lbs, latest have been 5.2 million and new test well which is doing outstanding is 7 million. That is a doubling of sand per well. That would be good news indeed for the sand suppliers.
The cost is more than just sand as it also means increased stages but still for the added production a small price to pay
These new "high intensity" wells are delivering big results. Below is from Motley fool article on OAS web site
" Whiting Petroleum (NYSE:WLL), for one, has noted that wells completed with its enhanced completions in the Bakken during the third quarter, which had average sand volumes of 5.2 million pounds, delivered an average 30-day production rate of 1,102 BOE/d. That's a 44% increase in productivity over wells drilled in the second quarter using 3.5 million pounds of sand. Even more impressive were two monster wells Whiting Petroleum reported that delivered an average initial production rate of 5,224 BOE/d per well after being competed with a hybrid-style completion using 7 million pounds of sand per well. Clearly, these companies are finding that increasing proppant intensity is the key to unlocking more oil out of the Bakken."
HIGHLIGHTS on some great news, now we need well results which will be coming soon
Company Best Estimate Risked Contingent Resources attributed to the Vaca Muerta Shale at Coiron Amargo are 91.5 MMBOE (152.4 MMBOE Unrisked) up 374% from the December 2012 estimate of 19.3 MMBOE;
517 (181 net) Horizontal Multi Frac Vaca Muerta Shale locations at Coiron Amargo associated with the Best Estimate Contingent Resources;
On the Valle Morado block the Company has conventional deep gas Best Estimate Contingent Resources of 75.3 Bcf (Unrisked 117.1 Bcf);
On the Curamhuele block, Lower Agrio Shale Best Estimate Risked Prospective Resources 99.4 MMBOE (Unrisked 365.4 MMBOE);
570 (517 net) Horizontal Multi Frac Lower Agrio Shale locations at Curamhuele associated with the Best Estimate Prospective Resources;
In addition to the Lower Agrio Shale at Curamhuele, a Vaca Muerta Shale at Curamhuele Best Estimate Risked Prospective Resources 92.6 MMBOE(Unrisked 1,157.1 MMBOE);
Madalena's Total Risked Contingent Resources are 105.2 MMBOE (172.7 MMBOE Unrisked); and
Madalena's Total Risked Prospective Resources are 192.0 MMBOE (1,522.5 MMBOE Unrisked).
rtmac, for the most part the driller does know what they will get before its fracked. Particularly when they are doing infill wells. Shale is very consistent across a given area
Boys, think about this. It is BIG oils big projects that are all being put on hold and flat out canceled, Restarting those big projects cannot and will not happen quickly.
Shale on the other had has not risk. Drill the hole and you know very closely what the results will be. Further shale can ramp up production virtually overnight. That ability to ramp up quickly is what will put the Saudis into serious financial trouble. They need $100 plus oil to meet their budget obligations and keep their socialist economy running.
Shale will be cranking big time long before oil gets back to $100.
Big U.S. oil companies are starting to think small.
A stubborn 16-month crude rout with no end in sight is driving the largest U.S. oil producers away from costly, high-risk megaprojects long touted as the industry’s future and toward safer shale operations that generate the cash needed to satisfy anxious investors.
Exxon Mobil Corp., Royal Dutch Shell Plc, Chevron Corp., ConocoPhillips and Hess Corp. have all either delayed or abandoned projects that range from the deep seas of the Gulf of Mexico to Canada’s oil sands and the U.S. Arctic. At the same time, Exxon and Chevron both announced plans to substantially increase U.S. crude production, largely as a result of their shale operations.
“What makes more sense in this environment: drill a $100 million well in the deepwater Gulf that might come up empty, or poke lots of holes in west Texas where you already know there’s oil for a few million apiece?”
The shale drilling boom led to a supply glut that deflated prices by more than half since 2014 and shale remains one of the most economic options for producers. For Exxon and Chevron, that’s meant rededicating their spending to a region they’d mostly ignored for the half century before the shale boom while they pursued giant overseas discoveries.
Exxon has more than tripled the number of rigs it has drilling shale formations around the U.S. since buying XTO Energy for $35 billion in June 2010, Jack Williams, the senior vice president in charge of Exxon’s wells, said during a March meeting with analysts in New York. Exxon plans to double U.S. shale production in the next three years.
For Chevron, shale wells are forecast to contribute the equivalent of 160,000 barrels of daily oil output in the next two years, the company said in a March presentation to analysts. Despite the fall in crude markets, Chevron Chairman and CEO John Watson has so far stuck to his goal of boosting worldwide output 20 percent to 3.1 million barrels a day by the end of 2017, in large part because of shale.
Only 10 percent of non-shale discoveries this year will be profitable, down from 40 percent in 2010, said Julie Wilson, a senior exploration analyst at Wood Mackenzie. Cost overruns have afflicted 64 percent of oil and gas megaprojects and 73 percent of them have faced delays, according to an Ernst & Young LLP survey of 365 developments.
“Projects are getting bigger and bigger and they are failing more often,”
The Saudis quite simply can't continue with this for much over a year. Contrary to what you say the Saudis are burning thru cash in a very big way. One they need oil over $100 per barrel to support the budget. Second cash reserves are being moved out of Saudi Arabia by the wealthy to protect their cash.
Further if they cut back on their social programs they risk serious domestic unrest. To make matters worse if oil hits $65 buck a barrel the shale boys can open the spigot back up very very quickly keeping the Saudi domestic budget in a deficit.
No Change to $3.5 Billion of Credit Commitments
In October, the lenders under Whiting’s revolving credit agreement completed their semi-annual redetermination of the borrowing base. Under their current price deck, lenders set a $4.0 billion borrowing base. There was no change to the $3.5 billion in aggregate commitments. There were no changes to the interest rates, fees or repayment terms of the credit line, which matures in December 2019. Whiting and its lenders also agreed to extend the 2.5 to 1.0 senior secured debt to EBITDAX covenant and institute a 2.25 to 1.0 EBITDAX to consolidated cash interest charges covenant. Both remain in effect through March 31, 2018. Whiting is well within both these covenants. No funds were drawn on the credit facility as of September 30, 2015.