Rheinland Revival

A private Canadian company is front and centre in Germany's post-reunification oil rebirth.

This article appears in the July issue of Oilweek 

By Peter McKenzie-Brown

“The guys who founded the company began their exploration program by driving around what had been East Germany looking for Communist-era oil and gas relics.” The speaker was Alicia Groeneweg, a geology major working as a co-op student for Calgary-based Central European Petroleum; we were having dinner with others in a small Thai restaurant. Already unusual, the story got better when she reached the punch line. “They didn’t hit pay dirt until they found a decaying museum glorifying the achievements of socialist oil production.”

Intrigued, I asked her to put me in touch with her CEO, Peter Putnam. As Putnam talked about his company, the narrative became compelling. “As a general rule, petroleum people don’t approach things from historical context,” he said. “But I see this story as a combination of 20^th century history and geopolitics and (21^st century) regional geological analysis and economic analysis. If you don’t understand what was going on during the Cold War, you actually miss the story.”

Who Knew?

A PhD in geology, Putnam wears many hats. “I’m the chairman and chief executive of Central European Petroleum (CEP), an executive officer of OSUM Oil Sands Corp. and the non-executive chairman of Petrel Robertson Consulting Ltd. I was also a founding shareholder of Laricina.”

The key to these connections is Petrel Robertson, which he describes as a “unique entity in the Canadian consulting firmament. It has created a number of well-known companies. Others include OSUM Oil Sands and the asset base within Laricina Energy. Those two companies (plus CEP) all have one common originating location. Petrel Robertson put together their original theoretical premise, asset base and technical base. In various forms, Petrel Robertson actually created their land positions, conducted negotiations with governments, raised the money and staffed the organization. Then we let them go on as autonomous businesses.”

CEP is the most recent in a long line of companies formed in this way, although that fact is not well known; “we’ve always been very quiet about these things.” Even though CEP is the largest resource landowner in Germany, the company is virtually invisible in Canada. “This is the first media interview we’ve ever had in North America,” according to Putnam. “It’s funny that Alicia, our co-op student, was the one who finally connected us with the media in this country. But we are a big deal in Germany. There have been nearly a thousand reports about us there, in German. (They’ve been) in newspapers and on television and so on. We are big news in that country.”

Germany produces 145,000 barrels of oil per day, but consumes around 2.5 million. The seventh largest oil importer in the world, it is beholden to Russia for supply – especially because of the recent embargoes on Syrian and Iranian imports. Since the federation has only 276 million barrels of proved reserves, anything that inspires hope for a decline in imports is newsworthy. “So what we are doing there is of much interest to the Germans. We’re doing it in the poorest part of Germany. There was oil and gas production in that area under the Communist regime, but no interest in it until we got there. No one has done any development (in former East Germany) since reunification.”

The Prize

“We’re just a small company but we were able to do that because of the way the table was set when we entered Germany,” said Putnam. CEP was able to develop its enormous land position in Eastern Germany “because of the way the rules are set up and because as a private entity we were able to fly under the radar.”

“We have been in Germany since 2006, and we started our drilling campaign last year. We have raised about $134 million and we do have a partnership with Gaz de France, and we would always consider working with other partners. We have an enormous position, more than 3.4 million acres of land, and we’re just a small team so we are going to need partners. We need to optimize what we see as the value here.” What, exactly, does he see? Near term, “a substantial light oil opportunity.”

“The reservoirs we’re chasing are an oil story.” The target is in the Zechstein formation in Europe’s Permian Basin, which stretches from the east coast of England to northern Poland. The Zechstein has yielded much of the North Sea’s oil, and in many places it also serves as the main cap rock for gas fields in the Rotliegend – one of the world’s giant gas-producing formations.

The Rotliegend “is the zone just below our main target. It’s the Zechstein that interests us just now. We think it offers a combination of conventional but also somewhat unconventional (light oil) targets.” Looking at the bigger picture of the company’s holdings, Putnam said its large land position includes “old producing fields, high-risk green-field prospects and land in the Baltic Sea. We have sealed off the entire trend between Denmark and Poland. Try to do something like that in Canada!”

Last year CEP drilled Germany’s first-ever horizontal well, and it showed a little oil – the first new oil production since reunification. “We want to do a fracture stimulation of the well before we release any information on it,” he said. Since then, the company has drilled another, conventional hole. What success did they have? “We are in a blackout period, so I can’t give you well results.”

Those holes represented the beginning of CEP’s exploration push. “This year, next year and the year following are the ones in which we are really going to explore our lands. It is an expensive area to work, but the prize is commensurate with the cost or you just wouldn’t do it.”

Exploration in Europe is expensive because, while drilling and well servicing contractors exist, the services they provide are scarce. There are no issues related to quality in terms of either equipment or skill levels – after all, Germans invented seismic geophysics and they have been doing sophisticated fracture operations since the 1970s – but there are issues with respect to availability. “They have a sophisticated service industry,” Putnam said, “but they aren’t used to drilling more than a handful of wells a year.”

To appreciate the importance of history and geopolitics on CEP’s holdings, consider Guhlen, which Putnam described as the company’s best onshore prospect. Several hundred kilometres square, the property is southeast of Berlin. “That area has been out of bounds (for exploration) since 1914 because it was a military base during World War I and during World War II – that’s where Rommel learned desert warfare,” according to Putnam. “And after the fall of Berlin it became (the Soviet Union’s) biggest onshore military base outside of Russia. Today it is right in the heart of one of our exploration licenses. (During the Communist era,) it was surrounded by productive fields. We actually had to do an unexploded ordnance survey of the property, and we identified 4½ tonnes of unexploded ordnance. Within that area is our biggest onshore opportunity. It sat under everybody’s nose forever because it was a no-go area.”

Azerbaijan, Kazakhstan, Uzbekistan and…East Germany?

The Guhlen prospect is a small-scale example of the opportunities there for the plucking when the Soviet Union collapsed. Think Azerbaijan, Kazakhstan and Uzbekistan, all of which were insignificant producers until they got access to western know-how and capital.

East Germany was only different in that its land-mass was small enough for an entrepreneurial start-up from Canada to pick up all the goodies. According to Putnam, “we targeted East Germany because it was post-communist, and we could see that nobody had looked at it since the regime fell.” To understand the system in Germany, Petrel Robertson hired Germany’s honourary counsel in Alberta, consultant Jaap Baumann, to open the doors to Germany’s bureaucrats. “He’s Dutch by birth, but he lived in Germany most of his adult life. He’s now our country manager in Germany. He opened all the doors for us. It was through him that we met all these government agencies and found out all the rules.”

“Germany is the easiest place in the world to get acreage,” according to Putnam. “Everything is done in secret. There are no size limits, no shape limits. By law, as long as you are working on the land they have to extend your ownership.” What this means in practice is that CEP will have rights to all the oil and gas resources in its license areas, as long as the company wants them. “One of the benefits of being in Germany is that you never have to worry about land expiries. You don’t have to worry about doing rapid development. Under this system you have all the time you need.”

He later learned that the communist government’s oil company – its acronym was EEG – had been the world leader in ultra-deep drilling in the 1960s to 1970s, drilling as deep as 8,500 metres. In its search for oil the workers’ oil company drilled hundreds of wells and, in the 1980s, shot thousands of miles of seismic. “The funny thing is that 99% of the wells they drilled predated the seismic. East Germany went bankrupt in 1987-88, so they were not able to optimize or maximize what they found in those seismic data. Even so, the biggest oil field they found produced over 10 million barrels, and they found it without seismic.”

The reason an outside company could achieve so much success in Germany, according to Putnam, is that its bureaucrats really don’t have a culture of dealing with smaller entrepreneurial companies like CEP. “Being Canadian was a good brand; we were quite welcome when we first showed up. There is a sense in Germany that we are a major hydrocarbon power, that we have global reach. That helped, but the main thing is that we asked the right questions.”

Communist-era Legacies

It seemed like the right time to ask about the oil and gas museum – the odd story that inspired Oilweek’s enquiries into CEP. Clearly, Putnam relished telling the story. “There is no public information about the German oil industry,” he began. “It is a black hole of information. There are very few oil and gas companies in Germany, about ten. They produce about two billion cubic feet of gas and 60,000 barrels of oil a day, so (Germany) is not an inconsequential producer. But you can’t find out about the industry – it’s very difficult.” There are no relinquishment rules on technical information in the country because of the way German mining law developed.

“Nobody finds anything by sitting in their desk,” he continued. “If you want to find something you better get off your butt and go see it.” So Putnam and Alula Damte – Ethiopian by birth, he is a PhD in structural geology, a VP of Petrel Robertson and now president of CEP – went on a week-long trip from the Brenner Pass in the Alps to the Baltic Sea, looking for evidence of oil and gas activity.

During the first three days they found no evidence of old seismic lines or pump jacks, according to Putnam. “Then we saw (a pump jack) through our binoculars. When we drove up, we found that it was strictly decorative. We were in a fossilized petroleum equipment yard from the Communist era. It turned out we were on the grounds of a museum built to the glorification of the oil industry in East Germany. We went inside and – lo and behold! – on the walls was all this information about the history of the oil industry in that part of the world, and thus suggested that there was real opportunity. We captured everything by taking digital photographs of the exhibits and taking notes.”

Between them, Putnam and Damte had to pay three euro for admission. The value of what they learned? Priceless.

As they began securing land – the company acquired seven leases between 2007 and 2011 and is seeking more – Putnam and his team began seeking more legacy data. They learned, for example, about a multi-government, Communist-era consortium named Petro-Baltic. Since government had funded the data, it was there for the asking. No one else had asked.

Gaz de France, a French utility, bought out East German’s EEG in 1994 and now owns its data. After CEP brought them in as a partner in an exploration license, the French firm released data relevant to three of the Canadian company’s exploration licenses. The wells the company is drilling this year are based entirely on that legacy information.

Is there a simple way to sum up this narrative? “It’s a bit like one of those shaggy-dog stories,” said Putnam. “A Canadian, a Dutchman and an Ethiopian go into a bar and come out with Germany’s biggest oil and gas landholdings. It was almost just like that. I love the historical and geopolitical part of it. What we added was technical and economic thinking.”

Where it All Began

Equipment in the Underground Test Facility proved the effectiveness of  SAGD 

A quarter-century after the first Canadian horizontal well was drilled, the technology is the cornerstone of today's industry.

This article appears in the June issue of Oilweek

By Peter McKenzie-Brown
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 29^th, 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 13^o 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.