About

Welcome! There has been a great deal of interest in the Horn River Basin located in the northeast of British Columbia, Canada where massive reserves of unconventional shale gas have been discovered.

Shale gas across North America have changed the way we view the resources available to meeting long term energy needs while reducing carbon emissions. Some estimate the Horn River basin could contain over 600 trillion cubic feet of natural gas. The most recent public report* by the National Energy Board (“NEB”) pegs Horn River volumes at 78 trillion cubic feet of shale gas in the northeastern corner of B.C. (this does not include the Montney basin or others in BC). This is enough natural gas to cover all of Canada’s growing needs for 26 years according to NEB.

Billions of dollars are being invested into the area and positioning the Horn River basin as a major producer of shale gas in North America, and contributing to building a bridge to a cleaner energy future.

The purpose of Horn River News is to consolidate news on the Horn River Basin; shale gas; the companies participating in the exploration of the area; and insight into the potential of unconventional shale gas as a clean alternative to other fossil fuels.

Your comments are encouraged and welcome. Thank you.

Horn River News

hornrivernews(a)gmail(dot)com

*NEB News Release: First time study doubles the estimate of BC gas resources

15 responses to “About

  1. Nice to have a spot where all of the news is about Horn River.

    Nothing happening until Gas price goes up – as a contractor for Encana they have cut back spending huge up there, I have had to lay off an employee.

    Encana plans on spending some mad cash up there though. Plans of a 600 man Camp & huge laydown yard. 2 new Trinidad rigs drilling right now for ECA – new gas plant should be online sometime in the first or second quarter 09.

  2. Your participation and comments are both welcome and encouraged. Thank you for your post.

  3. Frédérick Chabot

    Private investor. Passionate of Shale Gas and regular reader of your blog. This company could reshuffle the cards at Hamburg with a contrarian approach ( unconventional ) to the play. Muskwa in Alberta, who knew!

  4. As a directional driller with no Horn River experience; any reading or research I do on the technology used there concentrates on Frac technics. Can anyone tell me if Horn River wells are drilled either under-balanced or with managed pressure?
    Previous Shale gas experience in the Marcellus Shale field in Pennsylvania was conventional, however I wondered if there were significant differances at Horn River.

  5. The Horn River Basin

    The Horn River play is one of the latest grand resource plays to emerge in the Western Canadian Sedimentary Basin. Following in the footsteps of such shale gas plays as the Barnett, Antrim and Caney Shale, the Horn River discovery lead to a surge in land sales in remote north-eastern British Columbia. Mineral rights for more than a million acres were secured by oil and gas companies in the last few years.
    Horizontal Section Chart

    While the presence of natural gas in this stratigraphical unit was known for decades, it took recent technological advances to make this play economical, allowing operators to extract hydrocarbons from the shale. Horizontal drilling allows boreholes to open up more reservoir; multi well pad drilling minimizes the environmental impact; invert mud keeps open holes under control. Multi-stage fracturing, a process that cracks up the rock by shooting high pressure water and sand into the formation, opens new permeable conduits in the otherwise tight formation. The thickness of the shale stack makes this an ideal candidate for multi-stage fracturing.
    Build Section Chart

    Large quantities of natural gas are present in various horizons of the Horn River Formation. Commercial quantities of gas can be extracted from the Muskwa shale, Otterpark Member or Evie Member. Natural gas reserve estimates vary from 100 to 600 trillion cubic feet, twice to ten times higher than reserves of the Montney Play, which is successfully drilled south of the Horn River Basin. Ten to twenty percent of the gas can be recovered with current technology.

    Chinook Consulting assists oil and gas companies with field and office geological supervision of operations pertaining to all areas of the Horn River Basin. Several of our wellsite geologists are specialized in this particular play. Well positioned since the discovery of this play, our company amassed solid expertise and detailed knowledge related to the challenging geology and complex drilling process of the Horn River Shale.

  6. The Case for Remote Geo-Steering – Cutting Costs in Horn River

    The Western Canadian Sedimentary Basin is a mature oil and gas area, where most of the easy reservoirs have already been discovered, and in many cases already drained. Most new plays are linked to the deployment of new technologies in reservoirs previously deemed un-economic.

    Where is remote geo-steering applicable?

    Not every play is suitable for remote geo-steering. Most conventional plays aren’t, due to the fact that the best borehole follows the best quality reservoir, and cuttings sample observation is crucial in determining the optimal wellpath. A few of the largest resource plays drilled nowadays are prime candidates, however. Contributing factors are good well control of resource plays and existing in-depth knowledge of reservoir characteristic from previously drilled stratigraphic wells.

    Most new gas wells use horizontal drilling to open up more reservoir. The same is true for heavy oil in-situ wells. Gamma markers are used for landing the build section for most horizontal wells. Not sample description, but continuously supervision and communication are the key for optimal landing.

    When hydraulic fracturing jobs create large permeable conduits around the well-bore, the hole can be drilled at some distance from the best natural porosity and still tap the entire hydrocarbon potential of the reservoir. The prime objective when penetrating low permeability reservoirs with thick layers of monotonous shale or siltstone is not so much rock quality, but drilling efficiency. MWD and drilling parameters are sufficient to choose the optimal drill path in such horizontal wells. Remote geo-steering can be used to drill wells in the Horn River shale gas play or in the Montney Formation in the southern Peace River Country.

    When drilling horizontal wells in thin sand beds, penetration rate is the first alarm when the bit hits roof or bottom of the reservoir. Gamma or other LWD signatures are most often used to decide steering direction. Fast decisions are crucial to maximize the exposure to hydrocarbon rich rock. Steering based on cuttings samples is ineffective in this kind of play (high penetration rates produce contaminated samples, and the lag time delays the process further). Lithology within a monotonous formation gives little to no information regarding the position of the wellbore within the uniform rock unit. Remote geo-steering can be applied in heavy oil wells drilled in the Clearwater and McMurray Formations in the Athabasca area, in the Bluesky Formation of the Peace River area, or in the Bakken light oil play in South-Eastern Saskatchewan.

    What does remote geo-steering offer?
    Horizontal Section Striplog

    * Continuous supervision of drilling operations
    * Continuous assessment of stratigraphic location of the drill bit in real time.
    * Correlation of drilling, MWD and mud gas parameters throughout the wellbore and to offsetting wells.
    * Use offset well information to optimally land the build section, by employing TVD logs with cross plot of offset data.
    * Continuous monitoring and critical evaluation of the wellpath inclination and azimuth in relation to stratigraphic markers and porosity windows.
    * Continuous communication with directional driller, proactive adjustments to ensure wellpath placement remains within the acceptable stratigraphic window.
    * Proactively evaluate wellpath position in relation to existing and planned wellbores.
    * Assess hole condition by monitoring drilling parameters and mud properties, paying particular attention to any indications of overpressure zones, sticky hole or lost circulation.
    * Establish estimated timelines for events such as encountering critical Formation tops, casing points, entering reservoir, and reaching total depth.
    * Estimate how long current bit is expected to drill, and when the next trip is expected.
    * Generate detailed daily reports, to be distributed within the company and to partners as needed.
    * Generate exhaustive final reports and striplogs.

    Why should remote geo-steering be considered?

    There are two main arguments to be made in favour of remote geo-steering: one is the lower cost and the second is the added safety.

    Savings occur due to the fact that geologists work close to home, transportation and accommodation costs are eliminated. Day rates are typically lower for people working in town as compared to on-site personnel.

    Safety is always a big concern for oil and gas companies. With fewer people at the wellsite, there is less exposure to hazards. Fewer vehicles on the road and a smaller ammount of logged driving hours also lower the risk of accidents.

    Having a focused group of geologists following a project also increases the quality of the job, with better response and more accurate data acquisition. Better flow of information is another success factor of the remote geo-steering procedure.

    How does remote geo-steering work?
    Operations Room

    Real-time data relay from the wellsite is a day to day reality and has become very robust and reliable in the past few years. Geologists can acquire continuous drilling and MWD parameters to decide the optimal steering direction in real time at any distance. Decisions can be instantly relayed to directional drillers. Geologists with extensive wellsite experience are key to the efficiency of a remote procedure system.

    Cuttings samples can be collected at the wellsite using semi-automated sample catching systems that require minimal supervision; they can be prepared and described at a later time in a laboratory environment. For in-depth analyses, critical samples can be collected and preserved in geo-jars and gas samples can be harvested in iso-tubes and preserved for subsequent analyses in a specialized laboratory.

    Chinook Consulting offers remote geo-steering services tailored for specific projects. Continuous remote geological supervision is offered in house (in the offices of our clients) or from our dedicated operations room.

    If cuttings samples are required, our company can arrange sample preparation from wet samples and petrographic description.

  7. Please include TAQA NORTH in your list of companies (Blogroll)

  8. Could someone explain to me potential limitations with a thin shale, say under 40m?

  9. Gazprom wants 10% of US Natural Gas market in 5 years

    BUENOS AIRES, Oct 8 (Reuters) – Russia’s Gazprom (GAZP.MM) aims to take a 10 percent share of the U.S. natural gas market within five years, Deputy Chief Executive Alexander Medvedev said on Thursday.

    The company plans to expand into the United States as it did in Britain in recent years, Medvedev told reporters.

    “We are taking into account different opportunities, but Gazprom marketing operated on the organic growth route in the United Kingdom,” he said.

    “We are now following the same method in the United States. We know how to work in fully liberalized markets,” Medvedev said at a press conference at the World Gas Conference.

    The Russian giant plans to use liquefied natural gas from its Sakhalin-2 project to supply U.S. customers and is also looking at swapping pipeline gas in Europe to obtain supplies for the United States.

    In the longer term, Gazprom could send LNG from its giant Shtokman field to the United States. The field, which is being developed with France’s Total (TOTF.PA) and Norway’s StatoilHydro (STL.OL) should begin production in 2015, Medvedev said.

    Gazprom’s European customers, which sharply cut back gas purchases earlier in the year as the world economy swooned due to the global financial crisis, have been stepping up their purchases in recent months.

    “Starting from July … we see that the daily offtake of gas is substantially higher,” Medvedev said, adding shipments were up by as much as 30 million cubic meters per day from the low point earlier in the year.

    UKRAINE PAYS

    Gazprom has received payment from Ukraine for the gas consumed in September and Medvedev said that if contractual payments continue there will be no problems for European gas supplies this winter.

    “We do hope that political factors will not negatively influence (the situation) especially in view of the (Ukrainian) election campaign … we know that Ukraine has enough hard currency reserves to pay for its gas,” Medvedev said.

    Disputes between Russia and its neighbors, like Ukraine that host the giant pipelines that connect Gazprom with its western European customers, have led to significant disruptions of gas supplies in recent years, pushing the issue of gas supply security up the agenda for European energy importers.
    Medvedev said Gazprom had enough gas reserves to meet future European needs as well as those of emerging Asian consumers like China.

    Gazprom aims to eventually hold a 25 percent share of the world LNG market by 2020 with supplies coming from Sakhalin in the Pacific, fields off the Yamal peninsula in northern Russia and the giant Shtokman field in the Arctic.

    The company is also urging Russia to liberalize the domestic gas market, in part to spur on energy efficiency. Russian industrial users are ready to operate in a liberalized market, Medvedev said although the lingering effects of the economic crisis may deter the government from moving quickly, he admitted.

    Medvedev said talks with ExxonMobil (XOM.N) over the gas at the Sakhalin-1 project were progressing and he hoped to wrap up a deal to have the gas sold into the domestic Russian network completed soon.

  10. Please include PetroBakken Energy Ltd. in your list of companies (Blogroll)

  11. All knotted up

    As Canadian gas production slips, exports to the United States are

    by R.P. Stastny

    Western Canadian natural gas production enjoyed historic highs throughout the early years of the last decade and, not surprisingly, gross export volumes to the United States followed in kind. Exports peaked in 2007 at just over 10.4 billion cubic feet (bcf) a day, but then followed production declines. Analysts now expect that downward trajectory to continue even if gas production makes a comeback. The reasons are anything but simple.

    At one time, natural gas forecasters would look to weather, storage levels, and North American production levels for clues. Today, a host of other significant factors need to be considered: the pace of the U.S. economic recovery, the rate of shale gas declines, the extent of the U.S. gas drilling slowdown, how much Canadian natural gas is diverted to the oilsands, the price of liquefied natural gas (LNG) imports versus Canadian gas prices, and the fluctuations of currency exchange rates.

    Other considerations will also impact Canadian gas exports: TransCanada PipeLines´ pending mainline toll increase, the impact of additional volumes of natural gas to the U.S. Midwest through the newly completed Rockies Express pipeline from Montana to Ohio, the extent of power switching from coal to natural gas in both the United States and Canada, further royalty adjustments or drilling incentives in Alberta or British Columbia, the effect of service cost deflation on drilling activity levels, and how aggressively major players step up development in the Montney and Horn River shale plays. (Devon recently traded its international plays in favour of North American gas, while ExxonMobil and Imperial Oil increased their respective land holdings in those two northeast B.C. areas.)

    There remain still more long-term variables driving Canada´s gas exports: the timing of Arctic pipeline approvals; the emergence of new technologies with potentially step-changing impacts such as multi-stage fracing of horizontal wells or the unlocking of methane hydrates; the ultimate accuracy of shale gas reserves estimates; and a host of potential-but unpredictable-environmental, legislative, or geopolitical changes.

    Forecasting today is like navigating through a fog, fraught with uncertainty, even humbling to many who make it their life´s work.

    “There was a time when I thought I understood all this,” says Dave Russum, vice-president of geoscience for AJM Petroleum Consultants. “When I was younger, I felt like I could read the trends and predict what was going to happen. But as it becomes more and more complex, I think it´s the unexpected factors that´ll have the biggest impact.”

    By this, he means the hurricane that wipes out a portion of production in the Gulf of Mexico, or a financial meltdown that slams the world into a recession. So rather than pulling numbers, Russum simply says that natural gas exports are likely to decline in coming years.

    “The biggest factor right now,” he says, “is how quickly the U.S. comes out of recession, boosting industrial demand.”

    Russum also puts a lot of stock in the environmental factor. Large-scale switching from highly polluting coal to natural gas power generation has the potential to make a real impact on natural gas demand in North America.

    As for whether stronger natural gas prices will improve Canadian gas exports, he isn´t so sure. This is because the United States, in his estimation, has a greater capacity to ramp up its natural gas production than Canada. So any increases in commodity prices will be met by an uptick in U.S. drilling, quickly depressing prices again.

    “So logically [Canadian gas exports] will be coming down,” he says. “The volume of gas we´re producing in Canada and certainly in Alberta is going to slip. I think even the growth in B.C. will be inadequate to make up the slide in Alberta gas production. The consumption in the oilsands and the conversion to natural gas power generation within Canada will increase demand, so that also means that there will be less to export.”

    Bill Gwozd, vice-president of gas services at Ziff Energy Group, shows more faith in the ability of his company´s forecasting models to generate hard numbers.

    “We had about 10 bcf per day exported in 2005 and, in 2010, that´s down about 20 per cent,” Gwozd says. Production growth in the Montney and Horn River, he adds, will likely be offset by the growth of natural gas demand in the oilsands and possibly by the Ontario shift to more natural gas power generation. “So by 2015, exports are expected to still be in that 7 to 8 bcf per day range.”

    By 2020, Ziff Energy forecast models include Mackenzie Delta gas and a whisper of Alaska gas production, but starting in 2015 it also factors in growing volumes of liquefied natural gas imports to the United States. The net effect is that by 2020, Canadian gas exports to the United States are still about 7 bcf to 8 bcf per day. And that actually is optimistic.

    “Realistically optimistic,” Gwozd says. “But there are a number of grey clouds on the horizon. If Alaska is delayed or Mackenzie is delayed by five years, or LNG is delayed by a few years, or the oilsands development is accelerated because of demand, then you could have the stars aligning so that gas exports are down even more.”

    Oilsands producers are forecasting that 6 bcf per day will be needed for projects by 2020 if all of them go ahead. Ziff, however, sees oilsands gas consumption more conservatively: 3 bcf per day by 2020, or 20 per cent of Canada´s production. (The oilsands currently consume about 1.1 bcf per day.)

    “The shift from a coal-fired power generating strategy to a natural gas-fired strategy will also vacuum away incremental gas from our cousins in Boston,” Gwozd says. “By 2020, 30 bcf a day is how much all of North America will consume for natural gas-fired power generation. That´s up from 20 bcf per day currently for gas power generation. So a 50 per cent jump from today.”

    Another variable that comes into play in the long term is where Canadian exports are destined. The United States will always be Canada´s biggest market, but Asia will become a customer as well if the Kitimat LNG project proceeds. By most accounts, this would be a win for Canada. Not so for the United States, because of the uncertainties around Arctic pipeline approvals and the resistance to LNG imports in some parts of the United States.

    “Our models actually have Mackenzie and Alaska eventually proceeding,” Gwozd explains. “But in the interim, until we have LNG in the Maritimes coming on, it would be a prudent strategy for our cousins in Boston, and maybe even in New York, to look into some long-term strategies such as learning how to knit or read by Braille just so they have a backup strategy for those folks who are so adamant to keep LNG off their coast.”

    Perhaps a more realistic backup strategy is the promise of the shale gas plays in the Lower 48. Huge initial production and massive long-life reserves have inspired much confidence in the burgeoning natural gas economy in the United States.

    But these shale plays had better be as prolific as touted in light of declining Canadian exports because a controversy is now brewing over the estimated ultimate recovery (EUR) of shale gas wells in the United States. The firing of World Oil editor Perry Fischer by the publication´s parent company president and chief executive officer, John Royall, has landed this debate on the radar for many.

    Fischer´s dismissal was given no formal reason, but it followed the last-minute withdrawal of a column written by geologist/consultant Arthur E. Berman questioning the EUR numbers promoted by major shale gas producers.

    His doubts are shared by many in the petroleum industry, from scientists and financial analysts. The crux of the issue is that when reserves are calculated on the actual decline trends in the Barnett shales-which are now well-developed by thousands of wells-rather than on some future, model-driven expectation of flattening decline rates, these shale wells show much lower EURs than producers claim.

    If it turns out that years from now the average Fayetteville shale well, for example, has a EUR of 0.59 bcf to 1.04 bcf, as calculated by the likes of Berman, rather than the 2.2 bcf to 3.3 bcf, as claimed by major operators, this could become the biggest wild card yet in the Canadian export game, especially if by then natural gas-fired power switching is already well underway in North America.

    Read more: http://www.oilweek.com/articles.asp?ID=711#ixzz0eRsFxwvY

    • Thanks for the post Marius. We are preparing a brief article “Does the U.S. need Canadian natural gas?” to be posted soon.

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