A Quiet Revolution In The Oil And Gas Industry

There has been somewhat of a quiet revolution taking place in today's oil and gas industry.  Or perhaps a better description is that a slow, decades-long series of technological innovations is   enabling the production of oil and gas never before dreamed of.  For the most part, politicians, economists, planners, "social engineers"  (I hate that term) and the general public, have not caught on.  The importance of this revolution or evolution in where and how our energy comes from is enormous. 

The world's economy is at a crossroads.  Solar energy, wind energy, geothermal energy, bio-fuels, and all other current alternatives are clearly not the solution to our near term energy needs.  We must accept this, perhaps swallow a little pride, and accept the idea that we really need all the oil and gas we can find and produce.

Meanwhile, fortunately, the idea that the burning of fossil fuels and the consequent release of "fossil" carbon dioxide as the cause of global warming and/or climate change is being proven to be false (if not an outright fraud and hoax).  See here for more on global warming/climate change.

The following article is an excellent summary of the timeline of how this transformation of the oil and gas business has come about.  All geologists, geophysicists, engineers, and others, should take note.

The bottom line is, we have and can produce A LOT of oil and natural gas.  "Peak Oil" has been pushed ahead.  This is good for our economy; it is good for us; it might help us get on the road back to growth and prosperity.  It buys us time to develop the inevitable alternatives.  Parents, "teach your children well".
Peter

Here is a pertinent excerpt from the following article:

"Is horizontal drilling helping bring about any other changes? Perhaps it is even changing the way corporations work. “Companies that fail to adequately research the geology are putting themselves at considerable risk if they assume all resource plays are alike and that more and larger fracks are the solution to economic production,” according to Russum. Even so, engineers are increasingly replacing geologists in the executive suite.

Traditional geologists who spent entire careers looking for conventional reservoirs are now more interested in minor variations in rock properties, in stress regimes and in proximity to source rock. In terms of traditional petro-geology this is a difficult concept to grasp, but to a large extent it is a response to the revolution spawned by horizontal drilling."

source:

Where it All Began by Peter McKenzie-Brown - Language Instinct Published : May 30th, 2012 1996 words - Reading time : 4 - 7 minutes

The world of oil and gas was quite a different place a quarter century ago. Production mostly came straight up out of vertical holes. Though the Texans had drilled the first horizontal well in 1929, in Canada horizontal drilling was still mostly an esoteric, unproved and untested technology. In 1987, all that began to change – so much so that, during the last 25 years, it simultaneously emerged as a standard production technique and revolutionized production. One result is that many petroleum resources have become technology-driven plays. Another is that reserves are way, way up. In a sense, the most important uses of horizontal drilling technologies are reverse images of each other. “What makes horizontal drilling for nonconventional resources (like shale gas and tight oil) so attractive to the financial community is the very high initial rate of return. In the beginning, production rates are extremely high, although they quickly taper off. You have to remember that these applications enable you to get highly desirable hydrocarbons out of really poor reservoirs,” according to Dave Russum, who is director of geosciences at AJM Deloitte, a consultancy. The oilsands represent the mirror image of this situation. “You are drilling into tremendous reservoir rocks – highly porous and very permeable, so there’s plenty of oil in there. But until you process the stuff it isn’t a particularly attractive commodity.” The Bitumen Story It’s true that in April 1978 Imperial Oil drilled Canada’s first horizontal well into the Clearwater formation at Cold Lake – a storied well overseen by Dr. Roger Butler in an early test of a system of oilsands production now known as steam-assisted gravity drainage (SAGD). After that test and a less interesting effort by Texaco a couple of years later, in Canada the technique mostly languished until 1987. Then the advent of improved down-hole drilling motors and the invention of other necessary supporting equipment, materials, and technologies – particularly down-hole telemetry equipment, which enabled rigs to drill straight on target – led to an explosion of new applications for this technology. Producers and the drilling and service firms that support them found endless new uses for directional drilling – especially as it is used for horizontal wells. Appropriately, in Canada the first horizontal wells drilled after Imperial’s early test were part of the Underground Test Facility (UTF), which celebrated its official opening on June 29th, 1987. Developed by the Alberta Oil Sands Technology and Research Authority (AOSTRA), the UTF involved a pair of tunnels driven into limestone 15 metres below the reservoir. Within those tunnels, AOSTRA constructed large well chambers. “Pairs of injection and production wells were drilled upwards from the well chambers at a 170 slant,” according to the mining engineer behind the project, Gerry Stephenson, “and deflected horizontally into the base of the reservoir. The mobilized bitumen drained by gravity from the steam chamber in the reservoir to the well head in the tunnel and all of the production was pumped from a central location.” Those tests proved Butler’s theories about SAGD beyond any possible doubt. Over its 15-year life, the UTF also evaluated other recovery strategies, but nothing compared to its SAGD results. “AOSTRA’s staff had estimated that the recovery might be somewhere between 30 percent and 45 percent of the bitumen in place” during the Phase A tests, according to Stephenson. “We actually got 65 percent recovery. The steam chambers formed by mobilization of the bitumen spread way beyond the area we’d expected….Over the 10-year life of the well pairs, Phase B got a steam/oil ratio, the most critical figure of all, of 2.3 to one.” The tests at the UTF forever transformed Canada’s oilsands industry. Today, SAGD is responsible for more than half of Canada’s bitumen production. Ironically, Sceptre Resources drilled the first horizontal well in Saskatchewan to test a SAGD-like system at Tangleflags, just as the UTF began its definitive tests. Drilled into the shallow (450-metre) Lloydminster sandstone, this primitive application of a form of SAGD illustrated the kinds of problems horizontal drilling could overcome. With an active aquifer below and a gas cap above, the reservoir’s pay thickness was about 27 metres. The oil was heavy: about 13o API. Primary production from the field had been meagre (0.6% of the oil in place), and the use of cyclic steam stimulation, which uses vertical production wells, had flopped when they tapped the aquifer and started producing 99% water. That was when the company decided to try SAGD – not the technique we use today, but the primitive version Imperial had tried out nine years earlier. Sceptre injected steam through four vertical wells near the gas-oil contact, draining the mobilized oil through a horizontal well. At the industry’s leading edge, the company found itself with a technical and economic success. Fast Production from Tight Reservoirs More than any other series of innovations, the technology-intensive processes that now surround directional drilling have enabled the industry to get production out of otherwise unproductive rock. In August of that same transformational year, Alberta Energy drilled the first horizontal well into the Glauconitic formation at Suffield. This was the first time a Canadian operator drilled horizontally into a conventional oilfield. Things then quickly sped up. In February 1998 alone, three significant projects based on horizontal drilling took off. Amoco began a 10-well horizontal drilling program at Athabasca, into the Wabiskaw formation. Canadian Hunter drilled gas wells at Ansell (Alberta) into the Cardium formation and at Helmet (British Columbia) into the Jean Marie. A few months later, Shell Canada drilled for Mississippian oil in Saskatchewan, at Weyburn. This early application of the technology was meant to connect isolated small reservoirs or improving contact within heterogeneous rocks to enhance the sweep efficiency. “In the 1990s the big push was to explore conventional carbonate rocks, especially from the Mississippian in Saskatchewan,” according to AJM Deloitte’s Russum. “The idea was to develop known reservoirs where the rock quality was variable, using horizontal wells to extract more oil from those formations…. Many different companies hopped on to the horizontal drilling band wagon in Saskatchewan with more than 500 wells drilled into the Mississippian in 1997 alone. In that year more than 1300 horizontal oil wells were drilled across the basin – a tally that was not beaten until 2007.” Horizontal drilling also began to tap the heavier oils in Saskatchewan and southeastern Alberta in the 1990s, and there was a lot of experimentation in other reservoirs. Also, of course, in that decade SAGD began to be developed in its modern form. As horizontal drilling became more commonplace, the petroleum industry began combining it with innovations in both drilling and well completion technologies and ideas. The result has been like a snowball rolling downhill. Horizontal drilling has been enhanced by geo-steering, measurement-while-drilling, coil tubing, down-hole motors and new bit design, for example. Also, producers can now drill multilateral horizontal wells from a single drilling pad. Perhaps the important recent development on the drilling side is the monobore. Monobore drilling involves running a casing string, then forcing a steel cone down the well to expand it in the hole. This process is repeated with identical casing strings. Thus, monobore completions have the revolutionary characteristic of installing a string with the same interior diameter from top to bottom. “These are making a huge difference,” said Russum. “In the past you had to drill a vertical well, then run the casing to the bottom and wait for the casing to set before you could begin to drill the horizontal leg. Monobores help reduce those time-consuming steps.” Although technologies like microseismic are also making a difference, the most important developments on the completion side have involved the increasing power and sophistication of hydraulic fracturing. Better fracking has developed because of new packers, better pumping equipment and better treatment fluids and proppants. “It’s now easier to isolate horizontal wells and to put fractures into certain points of the formation,” according to Russum. “In the early days, each stage of multistage fracking would take a whole day. Each frack would have to be tested separately before you proceeded to the next one. Today it’s a continuous process.” These clusters of technological breakthroughs first created the shale gas revolution. Pioneered by an American, George Mitchell, in the Barnett shale in Texas, tight gas reservoirs began yielding highly economic volumes of natural gas – and, not incidentally, drove down the price of gas. Some observers now describe natural gas as a low-value by-product encountered in shale reservoirs in the quest for natural gas liquids. From a production perspective, the other great outcome from this cluster of technologies has been the development of tight oil from shale – what Russum prefers to call “conventional oil from more shaley, low-permeability reservoirs.” One outcome is that both western Canada and the US are experiencing growing light oil production for the first time in decades – much of it coming from the Bakken play in North Dakota and Montana. After decades of decline in Alberta, for example, light oil production has recently risen to ten year highs. An Explosion of Uses These new technologies are changing almost everything about Canada’s petroleum industry. For example, horizontal wells are now a huge part of gas storage. “You can store gas very quickly into those wells,” said Russum, “and you can extract it quickly, too. Then there is the whole area of trying to reduce surface impact. I think we’re going to see more and more of that. Surface owners are more and more reluctant to have pumpjacks and other surface equipment on their land, and horizontal wells are less likely to disturb natural habitat. There is also extended reach, so you can reach under lakes and towns and cities. You can use it to reduce water production in a thin reservoir located over an aquifer.” The economics of the horizontal well are also greatly improved, especially when you are planning production from a narrow reservoir – ten metres thick, for example. Horizontal wells provide much greater contact with the reservoir per dollar of drilling than do their vertical kin. And when they are drilled in search of unconventional resources like shale gas and tight oil, the producer gets a quick payback because initial production rates are so high. Still not convinced? Then let the numbers tell the tale. According to an AJM Deloitte study which is complete to late 2011, more than 30,000 horizontal wells have produced conventional oil or gas in Western Canada over the past twenty five years. Of that tally, 4,300 were completed in 2011. This set a record for horizontal oil drilling: nearly 3,500 wells (led by the Cardium, Viking and Bakken), and an additional 800 wells focused on gas – mainly attracted by the high liquids content in the Montney and Middle Mannville. Today, half of Western Canada’s wells are being drilled horizontally. Is horizontal drilling helping bring about any other changes? Perhaps it is even changing the way corporations work. “Companies that fail to adequately research the geology are putting themselves at considerable risk if they assume all resource plays are alike and that more and larger fracks are the solution to economic production,” according to Russum. Even so, engineers are increasingly replacing geologists in the executive suite. Traditional geologists who spent entire careers looking for conventional reservoirs are now more interested in minor variations in rock properties, in stress regimes and in proximity to source rock. In terms of traditional petro-geology this is a difficult concept to grasp, but to a large extent it is a response to the revolution spawned by horizontal drilling. Oilsands companies in particular, but also other companies involved in modern resource plays are basing their business plans on step-by-step, decades-long development of vast and well-defined resources. This means traditional wheeling-and-dealing is at least partly on the decline – to a large extent replaced by courting cash-rich foreign companies with deep pockets and the desire to support these capital-intensive activities. Peter McKenzie-Brown Language Instinct Peter McKenzie-Brown Peter McKenzie Brown is the vice president of a resource company. He has written several volumes of history, and has worked in the corporate and academic worlds. He is British by birth, American by upbringing and Canadian by choice. Disclaimer : Although the writer is a director and officer of Stratabound, the thoughts and views herein are his only and not those of Stratabound. He is not registered in any jurisdiction as a broker or investment adviser, so nothing herein should be construed as advice on whether to buy, sell or hold shares of Stratabound or any other company mentioned herein. Peter McKenzie-Brown Archive Website Contact author Subscribe to his services

Another New Shale Play: Newfoundland, Canada

It looks like a new oil exploration and development play might be taking shape in Canada's northeastern Province of Newfoundland.  The target appears to be the stratigraphic equivalent of the Utica Shale of the Ohio, and New York areas in the United States.  In the area of interest off the west coast of Newfoundland around Port au Port Bay, they call this the "Green Point Shale".

source: http://seekingalpha.com/article/412511-newfound-billions-of-barrels-of-shale-oil-in-newfoundland?source=email_macro_view&ifp=0



Source: Shoal Point Energy website.
Here is a link to a map showing all of the oil and gas activity in eastern Canada.

Oil exploration and production is well established in the offshore basins of eastern Newfoundland with fields such as Hibernia, Terra Nova, and White Rose producing around 300,00 barrels of light crude per day.  (One wonders why exploration and production off Canada's east coast has been allowed where geologically similar areas off the U.S. east coast are off limits.)  Newfoundland is also "friendly" to the oil and gas business, both environmentally and economically.  There is even a refinery in Newfoundland , a good infrastructure network, and a trained workforce in place, presumably eager to expand and grow.  Again this is a refreshing contrast to the U.S.

The Green Point Shale in Newfoundland apparently compares well with the south Texas Eagle Ford Shale that is attracting so much attention.  These factors include total organic content (TOC) of the shales and the thermal maturity of the shales, that is their ability to contain and produce both oil and gas.  One major difference is the Green Point Shale is far thicker in this area than the Eagle Ford Shale is in Texas.

Apparently the Green Point Shale is much thicker than the Eagle Ford Shale, (and many other shales) because it has been through at least one episode of comressional tectonics, or mountain-building.  This has taken the layers of shale, and compressed them, pushing them together like a deck of cards on a table would be pushed together to overlap into a single large deck of cards.  This is a positive aspect to this play.  The negative to this "mountain building" is the layers of rock are much more structurally complex than the shales in for example, the Eagle Ford Shale, Barnett Shale, Haynesville Shale, and the Bakken Formation.  This makes for more difficult drilling and development.  On the other hand, these shales probably compare more favorably with the successfully developing Marcellus Shale in the Pennsylvania area of the eastern U.S.

The exploration of the Green Point Shale is in its preliminary stages but there are some very positive initial results in the area.  However the claims of "Billions" of barrels of oil seem premature and a bit sensational to me, still this area is very much worth watching.

This activity is discussed in more detail here:

Peter

More On The Barnett Shale Gas Play, Devon Energy

Very interesting. New technology, horizontal drilling, geology, high stakes, big money, Texas. Stay tuned. Note: This article was written "way back" in 2005.
Peter

Devon Energy Marks Milestone in Barnett Shale Play
Aug. 8--OKLAHOMA CITY -- In the third week of July, Devon Energy of Oklahoma City lifted its one-trillionth cubic foot of natural gas from the Barnett Shale field near Fort Worth.

A "T," as energy people call it, is a milestone under any condition and more so in this case because it represents almost 70 percent of the 1.45 trillion cubic feet of natural gas taken from the Barnett Shale field since 1993. It puts Devon on track to repeat as the biggest gas producer in the Barnett Shale, Texas' largest gas field, and as the top natural gas producer in Texas.

It was also a payoff for Devon, the acquisitive company that has become both the pioneer and biggest player in drilling and production in the Barnett Shale field.

Today, the company has 18 rigs working in the Barnett Shale. Most significantly, five of them are in Johnson County, south of Fort Worth. For Devon, the expansion beyond its original base in Wise, Denton and northern Tarrant counties marks a significant turn in the investment it made in 2002 when it bought Mitchell Energy and its pioneering base in the Barnett Shale for $3.5 billion.

Since 2002, Devon has drilled almost 2,000 wells in the Barnett Shale, more than doubling Mitchell's 2002 production to the current 560 million cubic feet a day. Up to 1,000 more wells could be drilled on the company's leased acreage in western Wise County, as well as Johnson, Parker and Hood counties.

The Barnett Shale is merely the highest-profile field in which Devon operates. The company, through its 2002 purchase of Ocean Energy of Houston, was already a player in the Carthage Field in East Texas, the state's second-most productive field. Devon also has significant acreage in the Permian Basin in West Texas and in the old South Texas gas fields near the Mexican border, much of it acquired when it bought Pennzoil's exploration and production unit in 1999 (a purchase that had eluded Fort Worth-based Union Pacific Resources two years earlier).

In addition to the 20 offshore Gulf of Mexico wells Devon plans to drill this year, the company is a big player in Canada and the Caspian Sea region. It is also making inroads in China. Still, 88 percent of its production is in North America.

This year, Devon received permission from the Texas Railroad Commission to reduce the spacing between gas wells from 40 acres to 20. Although that hardly brings back the early 20th Century practice of drillers putting derricks literally against one another, Devon hopes that the closer spacing will add production.

Devon, too, is going back to some of its older wells and refracturing them. Fracturing involves injecting water mixed with fine sand at high pressure to create hairline cracks in the tight shale. More than any other technology, it has made the difficult Barnett Shale play possible.

A "frac" is done after the well is first drilled, and Devon thinks that it can reverse the inevitable production decline (of up to 50 percent) that sets in over the first two or three years of a well's life.

"We've done some refracs in Wise and Denton counties, and we find that we can take a well that originally produced 1.5 million cubic feet a day and had declined over a few years to about a third of that, and then bring the production back to the original level," said Brad Foster, who heads Devon's North Texas operations.

Devon has kept its head down in Texas, putting its Barnett Shale field offices in Bridgeport and Cleburne rather than in a higher-profile setting in Fort Worth. The company reflects the low-key style of Chairman Larry Nichols.

Nichols, 63, is not the kind of Oklahoman to throw his hat into the air and start singing about the wind whipping down the plain at the thought of a Sooner State company being Texas' biggest gas producer.

Nichols, who has a geology degree from Princeton University and a law degree from the University of Michigan, once clerked for the late Chief Justice Earl Warren. Nichols was working at the Justice Department as an assistant to William Rehnquist, who is now chief justice, when he returned home to join his father, John, in the family's energy-investment firm.

Nichols may come from a pioneering Oklahoma family, but he isn't one to proclaim an Oklahoman dominance over Texas, at least in gas production.

"It's a nice thing to be Texas' biggest producer because it means we're doing good work," he said. "But it doesn't go any farther than that."

Independent energy analyst Kurt Wolff is among Devon's boosters. He describes the firm as "an independent that is still being run by the chief executive who has built its great long-term record."

At the time Larry Nichols joined the family firm, John Nichols, an accountant by training, had run it for two decades.

"Dad thought this was a great time to begin raising money in Europe for energy investment in the U.S.," Larry Nichols said.

The newly named Devon Energy ("We didn't want to call it 'Nichols Energy,' " Larry Nichols recalled), did a nice -- although quiet -- business investing in various drilling and production projects, mostly in the Southwest, but also in West Virginia gas fields. The energy boom of the late '70s and early '80s benefited Devon Energy nicely. Along the way, John Nichols, 91, who remains a venerable presence in Oklahoma City, turned over the company reins to Larry.

The younger Nichols proved to be an aggressive acquirer of properties, but it was a decision to not do something that saved Devon. In 1982, the company was poised to join the so-called "Deep Anadarko" play in southwestern Oklahoma. The industry was abuzz about the play, which was 25,000 feet deep, and its supporters said it was going to be the next big thing.

But the Deep Anadarko didn't feel right to John and Larry Nichols. The industry bore all the signs of a boom about to go sour: overproduction, flagging demand and a vast oversupply of drillers. So the Nicholses decided to sell instead of going deep in the Anadarko.

The sale saved Devon when the price of a barrel of oil plunged from $34 to $10 over the next three years, taking three-quarters of the U.S. domestic energy industry with it. Devon Energy was still standing and able to go public in the late 1980s in order to make its mark as a pioneer in the coal-bed methane gas play in the San Juan Basin of New Mexico.

Devon's success in the San Juan Basin and other domestic fields gave it the capital to go after some of the goodies that were placed on the table as the energy industry consolidated during the 1990s doldrums: the venerable Kerr-McGee company of Oklahoma in 1996; Northstar Energy in 1998, which gave Devon a major foothold in Canada; Pennzenergy in 1999; Santa Fe Snyder (co-founded by Fort Worth oilman John Snyder) in 2000; and Anderson Exploration in 2001.

The San Juan Basin success also gave Devon the confidence that it could handle a new, unconventional natural gas play. It champed at the bit when Mitchell Energy of Houston began shopping itself in 1999.

"Mitchell was interesting because it had opened the Barnett Shale in North Texas, and we watched it closely," Larry Nichols said. "In 1999, when we first talked with them, we didn't think we were quite ready. Two years later, we were."

When Devon made the $3.5 billion deal to buy Mitchell, the Oklahomans made it clear that the Barnett Shale was, as Nichols said, "the prize of the transaction."

At the time of the purchase, Mitchell's aggressive beginning in Wise and Denton counties had resulted in 400 wells. By mid-2005, Devon had more than 2,000 wells in the Barnett Shale and had produced a trillion cubic feet of gas. Most important, as Wolff, the energy analyst notes, "Devon caused a lot of other producers to look hard at the Barnett Shale, and most of them eventually got into the play. But Devon was there early."

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