+ All Categories
Home > Documents > Shale Gas & Oil Shale

Shale Gas & Oil Shale

Date post: 08-Nov-2014
Category:
Upload: norfolking
View: 192 times
Download: 2 times
Share this document with a friend
Description:
JPT Special Section
Popular Tags:
17
Europe Gears Up for the Shale Gale Shale Gas: Beyond the US and Europe Shale Oil: The Trend Toward Liquids Oil Shale: The Rock That Burns Cuadrilla’s drilling site in Singleton, Fylde, UK Photo courtesy of Cuadrilla Resources. SHALE SPECIAL SECTION
Transcript
Page 1: Shale Gas & Oil Shale

Europe Gears Up for the Shale Gale

Shale Gas: Beyond theUS and Europe

Shale Oil: The Trend Toward Liquids

Oil Shale: The Rock That Burns

Cuadrilla’s drilling site in Singleton, Fylde, UK

Photo courtesy of Cuadrilla Resources.

SHALESPECIAL SECTION

Page 2: Shale Gas & Oil Shale

T he European shale gas revolution is still in its infancy and though its commercial potential could rival that of

North America, significant challenges lie ahead. France has put a moratorium on shale gas activity while a compre-hensive study into its environmental impact is being car-ried out, and its National Assembly has voted in favor of a ban on hydraulic fracturing.

The potential for shale gas production in Europe is undoubted, as consultancy IHS CERA estimates that Eu-rope’s total shale gas in place could be 6,115 Tcf. Among the key challenges that will determine the ultimate produc-tivity in Europe is a regulatory environment that is currently ill-suited to unconventional gas, the company said. “Regu-lations designed for traditional exploration and production

have not been adapted to reflect the character of uncon-ventional gas,” said Jonathan Parry, global gas director at IHS CERA. “There are significant challenges ahead, includ-ing uncertainties over length of tenure, permitting regimes and norms, and water management, among others.”

However, a host of major and smaller operators are lin-ing up to take acreage in a number of European countries where the shale gale is beginning to blow. “Europe is just starting down the path of unconventional production, but we have some activities in the US we would like to leverage in order to move Europe forward on a more accelerated path,” Linda DuCharme, director of Europe, Russia, and the Caspian at ExxonMobil, told the recent Gastech conference

Europe Gears Up for the Shale GaleJohn Sheehan, JPT Contributing Editor

in Amsterdam. “We expect Europe to be a significant part of future activity.”

Poland Leads the WayPoland plays host to Europe’s largest known reserves of shale gas. Leasing activity in the country’s three main ba-sins—the Baltic Basin, the Podlasie Basin in the east, and the Lublin Basin to the south—is well under way. The country is keen to push forward with shale gas production as it looks to break away from its reliance on Russian gas supplies.

The US Energy Information Administration (EIA) esti-mates that Poland has 792 Tcf of risked shale gas in place, with 514 Tcf in the Baltic Basin, 222 Tcf in the Lublin Basin, and the remainder in the Podlasie Basin. Chevron and Exx-onMobil have been joined by a large number of smaller players such as DPV Service, Cuadrilla, EUR Energy, and Mazovia Energy in securing acreage across the country.

Talisman is carrying out seismic acquisition on con-cessions in the Baltic Basin and it is on track to spud its fi rst two shale gas wells in the fourth quarter of this year, the company said. It moved into the Polish plays through a farm-in arrangement with San Leon Energy for a 60% interest in San Leon’s three concessions. Talisman is committed to drill-ing a minimum of three wells—Gdansk-W, Braniewo-S, and Szczawno—which cover 600,000 acres. Three optional wells with horizontal sections will be drilled after a successful fi rst phase of testing. San Leon is also engaged in a fi ve-year ex-ploration and development program on its two concessions, Nowa Sol and Wschowa in the Permian Basin South. Both concessions are on trend with prolifi c Rotliegendes gas and Zechstein oil production.

Nexen recently entered into an agreement with Mara-thon to jointly explore 10 concessions in Poland’s Paleozo-ic shale play and it says it will pump USD 100 million into shale-related activities. Nexen will acquire a 40% working interest in the concessions, which encompass more than 2 million acres. Marathon is acquiring 2D seismic this year and plans to drill one or two wells in the fourth quarter and potentially seven or eight wells during 2012.

Another company that has snapped up acreage in Poland is Realm Energy, which holds three licenses in the country. The largest license, Gniew, is located in the Baltic Basin and covers 294,296 acres. Two other licenses, Ilawa, also located in the Baltic Basin, and Wegrow, in the Podlasie Basin, cover 161,109 acres and 180,136 acres, respectively, with Realm holding a 50% position.

Realm’s primary targets in Poland are the multiple shale formations within the lower Silurian, Ordovician, and Cambrian geological periods. The company is designing

3 Legs Resources Lebian drillsite in Poland.

32 JPT SPECIAL SECTION: SHALE

Page 3: Shale Gas & Oil Shale

WWW.MICROSEISMIC.COM

You Can’t Manage What You Don’t Monitor

Knowing where you’re producing in your

reservoir is important. Understanding

where you aren’t is invaluable.

With field-wide, near-surface monitoring

from MicroSeismic, you can track changes

in your reservoir in real-time. Optimizing

your well spacing, well design and

completions. Managing to get the most

from your reservoir.

Page 4: Shale Gas & Oil Shale

seismic programs on its lands and expects to shoot an ag-gregate 150 sq km of 2D seismic once the necessary per-mits have been granted and locations have been scouted. In addition, it is currently reprocessing 470 km of existing seismic data. Realm said it intends to move forward with drilling programs on its substantial acreage positions once seismic surveys have been completed and well loca-tions determined.

3Legs Resources holds six hydrocarbon exploration and prospection licenses in the Baltic covering a total area of approximately 1.03 million acres (held through subsid-iary company Lane Energy Poland). “We are commencing our own exploration program in the heart of Poland’s Baltic Silurian shale play,” said Mike Mullen, the company’s chief operating officer. “With all the drilling activity that is occur-ring around our license areas in Poland, it is the ideal time for us to move up our development schedule and begin our seismic acquisition program that will help us select drilling locations in preparation for the drilling of our first well.”

3Legs also has two permits covering 620,000 acres in the Krakow region. The work program obligations require one exploration well to be drilled and a certain amount of 3D seismic to be acquired within the first two years. The company is exploring for unconventional gas potential in the Silurian and Ordovician shales and, in partnership with ConocoPhillips, drilled its first two shale gas exploration wells, the Lebien LE1 and Legowo LE1a. The first well on the Lebork concession (Lebien LE1) underwent a single-stage fracture stimulation in November 2010 followed by a period of testing. Further evaluation is ongoing.

Poland’s national gas company, PGNiG, also holds substantial acreage in the region and has 13 of the roughly 60 shale gas licenses issued by the Environment Ministry.

BNK Spins the BitBNK Petroleum has an interest in six total concessions in Poland that total 1.6 million gross acres (1.1 million net acres). The concessions in Saponis, Starogard, Slupsk, and Slawno are located in northern Poland and total about 730,000 gross acres. BNK’s plan is to test multiple targets in the Silurian, Ordovician, and Cambrian shales that are located at depths ranging from 7,000 ft to 12,500 ft. The first well, Wytowno 1, began drilling in December 2010 and was completed in the first quarter this year. “The well encountered encouraging gas shows and log responses,” the company said. “Currently BNK is awaiting the results of the core analysis so that the logs that were run can be properly calibrated.”

In May, BNK said its Lebork S-1 well has been drilled, cased, and cemented to its total depth of 11,779 ft. It said that during drilling, numerous gas shows were recorded over 935 ft of the Lower Silurian, Ordovician, and Cam-brian shales. The gas shows consisted mainly of methane gas. The strongest gas shows were in the Cambrian shale though gas shows in the other intervals may have been diminished because of hole coring of the other intervals.

“Consistent with projections, the two primary shale target intervals were thicker in the Lebork S-1 well than in the Wytowno 1 well. The Ordovician shale interval in the Leb-ork S-1 well is approximately 299 ft thick, which is slightly thicker than the 272 ft found in the Wytowno 1 well,” the company said.

The Cambrian shale also thickened to 49 ft from the 29.5 ft found in the Wytowno 1 well. BNK said this provides further support for its hypothesis about an increasing thick-ness trend that may continue into deeper portions of the basin. The company anticipates receiving all core analysis back by the third quarter.

The log suite in the Lebork S-1 well calculates the high-est gas and best properties in the Cambrian shale interval followed by the Ordovician shale interval. BNK said the un-calibrated log suites of both wells indicate higher gas calcu-lations in the Ordovician interval in the Lebork S-1 than in the Wytowno 1, which may change after the logs are calibrated.

During the third quarter, the completion will be de-signed and the first intervals in each well will be fracture stimulated. The company is also planning to drill its first well on the Starogard concession in July.

Supermajors Take AimLarger operators are also getting involved in Poland. ExxonMobil has built a large acreage position in the Pod-lasie and Lublin Basins of eastern Poland, the location of a potential new shale gas play. The company has total hold-ings of more than 1.6 million acres.

France’s Total has just announced an agreement with ExxonMobil to farm into the Chelm and Werbkowice explo-ration concessions with a 49% interest. The work program for each of the concessions involves acquisition of seismic data, drilling of an exploratory well, and a production test if drilling results are encouraging. ExxonMobil has already acquired seismic and drilled an exploratory well on the Chelm con-cession, the results of which are being evaluated.

Aurelian Oil and Gas also has acreage in the south-ern Permian Basin and in the Carpathian Thrust Fold Belt in southern Poland, Slovakia, and central Romania. Activ-ity is less advanced in the Lublin Basin, where Halliburton completed the Markowola-1 exploration well in the Pionki-Kazimierz license for PGNiG last year. Results were mixed, and further tests are being carried out. Halliburton said significant production of shale gas could begin in Poland within three to four years if economic production of the res-ervoir is proved.

Eastern Europe Eagerly AwaitsOutside of Poland in Eastern Europe, the search for shale gas is ramping up, but geological challenges are causing headaches for explorers. In Hungary, disappointing results from drilling in the Mako Trough led to ExxonMobil and MOL withdrawing from an exploration project there. Part-ner Falcon Oil, which holds 247,000 acres in Hungary, is looking for new partners.

34 JPT SPECIAL SECTION: SHALE

Page 5: Shale Gas & Oil Shale

The three companies had teamed up to drill the Foldeak-1 well, which was completed at a depth of approxi-mately 12,632 ft (3,850m) within the Szolnok formation but was later abandoned.

In Bulgaria, six licenses have been awarded to five companies, including BNK Petroleum, TransAtlantic Petro-leum, Chevron, and Integrity Towers. In the Ukraine, the Dnieper-Donets Basin is being targeted for shale gas po-tential. It is estimated by the EIA to contain 48 Tcf of shale gas resources. Total and Eurogas have teamed up to hunt for shale gas in that basin.

The Ukraine’s state-run energy firm, Naftogaz, and ExxonMobil signed a memorandum to cooperate on searching for shale gas deposits in the country. The Ukrai-nian government is also in talks with Chevron and Shell about shale operations, as it looks to lessen its reliance on Russia for its energy needs.

In Romania, East West Petroleum has acquired acre-age in the Pannonian Basin, which has been the site of ex-tensive successful oil and gas exploration. East West said unconventional hydrocarbon resource plays have been rec-ognized on the acreage and it plans an extensive study and evaluation of these potentially large, untapped resources.

TransAtlantic Petroleum is planning to drill a well to test the Silurian-age shale on its Sud Craiova Block E III-7, onshore western Romania. And Chevron picked up three shale gas exploration blocks in the Carpathian-Balkanian Basin in the country.

French Shale MoratoriumWestern Europe plays host to a significant number of shale gas basins, which are made up of Carboniferous, Permian, Jurassic, and Ordovician-age shales. The EIA estimates risked

gas in place of western European shales at 1,505 Tcf of which 372 Tcf is estimated as technically recoverable (Table 1).

Environmental concerns are likely to play a big part in whether the shale gale takes off in western Europe. In France, shale gas is contained in the Paris Basin and the Southeast Basin, and exploration has sparked a major po-litical row. French Prime Minister Francois Fillon extended a moratorium on research and drilling for shale oil and gas, pending reports commissioned by the government to es-tablish the impact of drilling on the environment. The coun-try’s National Assembly has voted in favor of a ban on frac-turing. The bill now needs to be approved by the Senate. If the bill is approved, it will revoke the permits of companies carrying out fracturing there, although it does not outlaw the extraction of shale gas itself.

Companies that rushed to grab land in France now have a nervous wait to see what will happen next. In the Paris Ba-sin, which has similar traits to the Bakken formation in the US, companies such as Toreador Resources, Vermilion Energy, Realm, Hess, and Elixir Petroleum have all taken acreage.

Vermilion said that it remains in discussion with regu-latory authorities regarding the evaluation of resource play potential in France, including the Lias Shale oil play in the Paris Basin. The proposed drilling of two vertical wells through the shale and recompletion of the shale in a num-ber of existing wellbores has been deferred as a result of the recent government pronouncements, and a timeline and framework for further activities have yet to be established.

Paris-based independent Toreador Resources is lead-ing the way in the search for French shale after securing more than half of the exploration permits in the Paris Basin. However, it is delaying its “proof of concept” exploration program. The program is aimed at determining the type of petroleum resources contained in the tight rock within the Liassic Shale at a depth of between 7,546 ft and 9,843 ft as well as their economic potential.

Last year, France granted three exploration permits: one to oil major Total and two to US-based energy explora-tion company Schuepbach Energy for periods of between three and five years to explore in the southeast part of the country. GDF Suez has since entered partnership talks with Schuepbach. Total announced in January that it was plan-ning to farm out up to a 50% interest in its 100% operated South East Basin, Montelimar Permit acreage in southeast France. This significant shale gas opportunity could hold up to 85 Tcf of initial gas in place. Total’s Montelimar Permit, which was granted for a five-year period, covers a surface of 4,327 sq km that spans from the south of Valence to the Montpellier region in southern France. Operations in the South East Basin remain on hold until a decision on further activity is taken by the government.

ExxonMobil at Forefront in GermanyIn Germany, the search for unconventional gas is being spearheaded by ExxonMobil. Over the next five years the company could spend up to USD 1 billion exploring

Table 1. Shale Gas Resources

Country Technically recoverable shale gas resources (Tcf)

France 180

Germany 8

Netherlands 17

Norway 83

U.K. 20

Denmark 23

Sweden 41

Poland 187

Turkey 15

Ukraine 42

Lithuania 4

Others (3) 19

Source: US Energy Information Administration.

JPT • JULY 2011 35

Page 6: Shale Gas & Oil Shale

for shale gas in North Rhine-Westphalia and Lower Sax-ony where it holds six exploration licenses. The licenses cover 3.2 million acres of the Lower Saxony, Ibbenburen, and Ruhr Basins, and include potential shale gas and coal-bed methane exploration plays. ExxonMobil operates all these licenses, with a 67% interest in five of them, and a 100% interest in the sixth. Exploration drilling will continue this year to evaluate a number of unconventional play con-cepts. The company has drilled five exploratory wells in shale sediments in the country.

Other companies that have secured exploration per-mits in Germany include BASF’s oil and gas arm Winter-shall, Gaz de France, BNK Petroleum, BEB, and Canada’s Realm Energy. Realm has announced plans to explore for oil and gas potential in the Posidonia and Weald shales. Realm was awarded a wholly owned shale exploration concession in Germany in May 2010. The Aschen concession lies in the Weser-Ems region in the Lower Saxony Basin and covers an area of 15,888 acres. It contains two mature, organically rich shale formations and several partially appraised oil and gas fi elds.

3Legs Resources has a 630,000 acre exploration per-mit and will be testing Permian-Carboniferous horizons in the Bodensee trough. The license areas are located in south-ern Germany around and to the northeast of Lake Konstanz and contain obligations to acquire 2D or 3D seismic and drill one exploration well during the fi rst three years.

BNK Petroleum has leased 3,745 sq km of land for gas exploration, including shale opportunities in west and central Germany. The company has two concessions in North Rhine-Westphalia and a 300,000 acre concession in Lower Saxony. It also has three concessions in Thuringia totaling 770,000 acres and in March 2010, BNK was awarded a concession that totaled 840,000 acres, bringing BNK’s total holdings in Ger-many to about 2.4 million acres. All of BNK’s concessions were acquired for their potential for shale gas. Across its acreage BNK is primarily targeting three shales. Some concessions also have the potential for “Bakken-like” unconventional oil, coalbed methane, and tight gas sands, the company said.

UK Activity Picks UpShale gas drilling in the UK was given the go-ahead in May by the government in a new report looking at the impact it could have on water supplies, energy security, and green-house gas emissions. The inquiry found no evidence that the hydraulic fracturing process involved in shale gas ex-traction poses a direct risk to underground water aquifers provided the drilling well is constructed properly. It con-cluded that, on balance, a moratorium in the UK is not justi-fied or necessary at present.

Members of Parliament nevertheless urged the De-partment of Energy and Climate Change to monitor drill-ing activity extremely closely in its early stages to assess its impact on air and water quality. Tim Yeo, chairman of the committee that looked into fracturing, said: “There has

been a lot of hot air recently about the dangers of shale gas drilling, but our inquiry found no evidence to support the main concern, that UK water supplies would be put at risk.

“There appears to be nothing inherently dangerous about the process of fraccing (sic) itself,” Yeo said, “and as long as the integrity of the well is maintained, shale gas ex-traction should be safe. The government’s regulatory agen-cies must of course be vigilant and monitor drilling closely to ensure that air and water quality is not being affected.”

However, a week after the inquiry, Cuadrilla Resourc-es halted drilling for shale gas in England after scientists said two small earthquakes might be linked to hydraulic fracturing. The British Geological Survey recorded a 1.5 magnitude quake near Blackpool in northwest England, within 1.2 miles of the gas well. A 2.3 magnitude quake was recorded nearby in April.

Cuadrilla Resources has been actively exploring Cheshire’s Bowland Shale. Cuadrilla began drilling for natural gas at its first location, Preese Hall 1, located ap-proximately five miles east of Blackpool, in August 2010. The company completed its first phase of exploration in December 2010, which involved drilling a vertical explor-atory well with total depth of around 9,000 ft.

The second phase of the exploration program began in March. This phase involves stimulating rocks surround-ing parts of the vertical well using hydraulic fracturing. Cuadrilla said that once this phase is completed, it will be able to determine whether there are commercial quantities of natural gas present at the drilling site.

Celtique Energie holds licenses in three areas of the UK: the Cheshire Basin, East Midlands, and the Weald Basin. In the Weald Basin, Celtique has a 50% share in licenses covering 1,000 sq km. It says these have conventional Trias-sic potential and unconventional oil and gas potential in the Jurassic Liassic shales.

IGas has operations across northwest England and the North Wales coast and has license interests in Stafford-shire and Yorkshire. In total it has interests in licenses cov-ering 1,756 sq km.

IGas says that at its Point of Ayr acreage, initial indi-cations are that the shale extends over the whole acreage and has an expected average thickness of more than 800 ft. The company said a significant proportion of its acreage in the northwest England—from Ellesmere Port in the west in PEDL 190 to the Trafford Centre in the east within PEDL 193—is considered to have shale that has a high potential to be hydrocarbon bearing.

However, UK Energy Minister Charles Hendry has made it clear that shale gas developers will face challenges. He told a House of Commons committee: “Some of it is un-der very heavily populated areas of the country [and] there has to be approval given from people whose land is being drilled underneath and this could make things much more complicated. Approval from landowners is not required in the United States.”

36 JPT SPECIAL SECTION: SHALE

Page 7: Shale Gas & Oil Shale

Hendry said he did not anticipate the govern-ment offering any special support to encourage the development of shale gas. “I can’t see any reason for changing the support that is offered to the industry,” he said. “I think it would be a market-driven exer-cise, but subject to very strict safety and environ-mental protections.”

Elsewhere in northern Europe, Cuadrilla Re-sources and DSM Energie bought permits in the Neth-erlands, while BG also has a large exploration tract on the east Netherlands border with Germany. Cuadrilla plans to drill the Netherlands’ first unconventional gas well in Boxtel in North Brabant province later this year.

Cuadrilla is partnering with Energie Beheer Netherlands, a natural gas exploration, production, transportation, and sales company owned by the Dutch government. Plans are to drill three wells.

The Dutch Energy Council, the highest advisory body of the Dutch government in energy affairs, has come out strongly in favor of the development of un-conventional gas in the Netherlands.

The council has recommended a number of poli-cies that should stimulate the exploitation of shale gas and coalbed methane in the Netherlands.

In Scandinavia, shale gas potential is mostly to be found in the Cambrian/Ordovician Alum Shale, but results so far have been mixed.

In Sweden, Shell took a position in the Alum Shale and acquired 400 square miles of acreage. The com-pany has drilled three wells, but results have proved disappointing. Shell said recently that it is not going to renew its exploration licenses in Scania (southern Sweden) after the analysis of the three wells drilled showed that no gas could be produced from the Alum Shale there.

Meanwhile, Gripen Gas has picked up five ex-ploration permits in Östergötland in central Sweden. The five exploration licenses (Ekeby, Hov, Eneby, Or-lunda and Skedet) establish Gripen Gas as the prin-cipal acreage holder in the Cambro-Ordivician basin of Östergötland. The basin contains over 50 recorded gas seeps. The exploration licenses have been award-ed for an initial period of three years, which may be extended for a further three years. The licenses lie close to the industrial complex of Linköping where a growing energy demand exists.

In southern Europe, BNK Petroleum has ac-quired new exploration acreage in Spain to pursue a shale gas opportunity. BNK’s subsidiary Trofagas Hidrocarburos won a new 61,470 acre oil and gas ex-ploration concession in the autonomous community of Cantabria onshore Spain with work commitments that include geological studies in the first year, and drilling up to four vertical wells in each of four sub-sequent years. JPT

Shale gas is everywhere. China’s estimated technically recoverable shale gas resources, at 1,275 Tcf, are al-

most 50% greater than those touted in the US. Argentina, with 774 Tcf, contains 150 Tcf more than all of Europe. These numbers were spelled out in “World Shale Gas Resources: An Initial Assessment,” a study released April 2011 under the auspices of the US Energy Information Administration (EIA), which commissioned the study from Advanced Re-sources International (ARI).

China, in fact, ranks first in shale gas resources, fol-lowed by the US, Argentina, Europe, Mexico, South Africa, Australia, and Canada. Although the study is preliminary and excludes areas like Russia and the Middle East, there is no doubt shale gas resources exist in abundance world-wide. The numbers ARI arrived at are rough. With more extensive data and more time to assess it, ARI stated, the amounts would be higher.

However, Donald L. Gautier, chief of the US Geological Survey (USGS) World Petroleum Project, introduced a note of caution regarding the EIA study’s fi gures. The USGS is in the midst of its own assessment of global continuous accumula-

Shale Gas: Promising Prospects Worldwide Robin Beckwith, Staff Writer JPT/JPT Online

Concurrent shale gas completions operations at c-34-L Apache Horn River in northeast British Columbia, Canada. Photo courtesy: Apache Corporation; Ben Affleck, photographer.

JPT • JULY 2011 37

Page 8: Shale Gas & Oil Shale

tions, including technically recoverable gas from source rock systems such as gas shales. Initial results from the fi rst basins assessed will be released within the next few months. Ac-cording to Gautier, the USGS approach, which is geologically based, probabilistic, and emphasizes application of well per-formance data from analog shale plays in North America, is quite different from that of ARI. “I wouldn’t be at all surprised if the results are as different as the methodology,” he said.

Shale Gas Economic RequisitesWhile shale yields approximately 20% (4.8 Tcf in 2010, according to the EIA) of US natural gas consumption, this resource has yet to contribute more than negligibly in re-gions elsewhere. Yet many countries, buoyed by and in some cases participating in US shale gas exploitation, ap-pear poised to initiate shale gas development within their borders. However, with a lack of shale drilling and comple-tion services, as well as gas production and transportation infrastructure, promising shale gas reservoirs need at least five to 10 years before production would be economic.

“The shale gas story in North America has been an overnight revolution that has taken 30 years to develop,” ARI president Vello Kuuskraa said in an email statement. It has often been said that this “revolution” is the result of devel-opments in hydraulic fracturing and horizontal drilling. But it is no easy matter to apply these technologies successfully on any given well. As Apache global technology consultant George E. King pointed out in paper SPE 133456, “No two shales are alike…Understanding and predicting shale well performance requires identifi cation of a critical data set that must be collected to enable optimization of the completion and stimulation design. There are no optimum, one-size-fi ts-all completion or stimulation designs for shale wells.” So, while the EIA study helps locate possible “sweet spot” areas within worldwide shale gas plays, these cover huge extents of land whose specifi c geophysical characteristics will need to be discovered and delineated well by well, fi eld by fi eld.

For shale gas extraction anywhere in the world to become economic, a host of factors, pulled by demand, need to gather momentum. These include the presence of technically experienced, well-supplied and -equipped drilling and completions service companies with a low cost base and the critical mass necessary to learn and respond quickly to new developments in modeling, planning, fluids, and proppants technology.

A good measure of transparency or knowledge transfer is also critical—similar to requirements in most areas throughout North America to reveal fracturing and production-performance data within six months following execution, which competitors can then plun-der for insight.

Some form of government support is a likely ingredi-ent for shale gas’s ultimate economic success. For example, the US benefi ted from a tax incentive created in the 1980s, which, along with high gas prices, jump-started US tight gas

exploitation. By 1992, when the incentive ended, the result-ing infrastructure, critical mass, and expertise were in place to continue economically without incentives.

China: Drilling, Learning“America’s shale gas production alone has exceeded that of total Chinese gas output. That gives us a lot of confi-dence,” Zhang Dawei, deputy director of the Strategic Re-search Center for Oil and Gas in China’s Ministry of Land and Resources (MLR), said in an April news report.

According to the Chinese government’s “12th Five-Year Plan (2011–2015),” that country aims to double natural gas consumption from 4% of its total energy mix to 8% in 2015 (in comparison, coal consumption is targeted to de-crease from 70% to 63%). The EIA estimates China’s 2009 natural gas consumption at 3.075 Tcf, driven by the needs of a vast population approaching 1.4 billion, 47% of whom live in cities spread out over a land area of close to 9.57 mil-lion sq km. In the “International Energy Outlook 2010,” how-ever, the EIA projects that China fails to achieve its targeted natural gas share, due to continuing reliance on coal. Ac-cording to the EIA, natural gas will provide 5% of China’s energy mix in 2020.

China began importing liquefied natural gas (LNG) in 2006. A shift toward reliance on its shale gas resources might undercut demand for LNG imports. However, Wood-side Petroleum chief executive Don Voelte (quoted before he stepped down 30 May 2011) indicated China has more regasification terminals scheduled to start up in 2011, with LNG demand set to grow by about 17% annually to 24 mil-lion tonnes in 2016.

China’s MLR will soon hold an auction for eight shale gas exploration blocks covering 18,000 sq km in southwest Sichuan, central Hubei, Guizhou, and direct-controlled mu-nicipality Chongqing. The auction, originally scheduled for November 2010, was delayed reportedly to open the bidding for increased competition with the goal of quickening the pace of shale development. Six domestic companies have been short-listed by the MLR to bid on the blocks: Petro-China, China Petroleum & Chemical, China National Offshore Oil Company (CNOOC), Shaanxi Yanchang Petroleum Group, China United Coal Bed Methane, and Henan Provincial Coal Seam Gas Development and Utilization.

Shale gas drilling in China is just beginning. Petro-China, which produces nearly 80% of China’s total gas output, completed drilling China’s first horizontal shale gas well late March 2011 in Sichuan province. Following December 2010 drilling of a vertical shale gas test well in Yuanba, a district about 500 km from Sichuan province cap-ital Chengdu, Sinopec plans to drill its first horizontal shale gas well mid-2011 in Fuling, not far from Yuanba and in the same prolific geological Sichuan Basin.

In December Shell and Petrochina, 13 months after inking a joint exploration agreement, spudded the Yang 101 evaluation well on the Fushun-Yongchuan shale gas block

38 JPT SPECIAL SECTION: SHALE

Page 9: Shale Gas & Oil Shale

in southwestern Sichuan province. According to reports, Shell will spend as much as USD 1 billion a year over the next five years on shale gas in China, drilling a possible to-tal of 17 wells, some of which will be for shale gas. Industry sources said Shell in mid-March 2011 spudded two more shale gas exploration wells on the Fushun Block.

Spurred by identification in the five-year plan as one of China’s top targets for technological breakthroughs, shale gas research could receive significant government funding. China’s National Energy Administration is set-ting up a shale gas laboratory in Langfang, near Beijing, financed mostly by PetroChina, which will reportedly be-come China’s national shale gas research center.

Chinese firms are also learning firsthand about tech-nically sound and economical shale gas well development through positions outside its borders—for example, spend-ing well over USD 6 billion on North American shale gas assets in first-quarter 2011. PetroChina announced early February 2011 it paid USD 5.5 billion for a 50% interest in EnCana’s Cutbank Ridge business assets, representing current production of about 255 MMcfe/d; proved reserves of about 1.0 Tcfe, as of yearend 2010; and about 635,000 net acres of land straddling the British Columbia and Alberta boundary. This is, to date, the largest Chinese investment in a foreign natural gas asset. The price tag represents 3.8% of EnCana’s 2010 estimated production for 24% of its market capitalization—indicative of PetroChina’s eagerness to buy.

In addition, in first-quarter 2011, CNOOC won ap-proval from Australia’s Treasurer to invest in a coal seam gas and shale gas exploration prospect in Queensland. CNOOC Gas & Power Group’s farm-in agreement commits it to spend at least AUD 50 million for a 50% stake in Exo-ma’s five exploration permits in the Galilee Basin and gives it options to buy 173.2 million shares in Exoma, amounting to a 35% stake based on Exoma’s current share base.

Some joint ventures are forming between service com-panies within and outside China. For example, the Weir Group and Shengli Oilfi eld Highland Petroleum Equipment an-nounced in November 2010 the formation of a joint venture to provide high-pressure well service pumps and related fl ow control equipment to China’s developing shale gas industry. The joint venture will be owned 60% by Weir and 40% by Highland and will be based in Dongying, Shandong province.

Argentina’s Shale Gas SurpriseWithin Argentina—the world’s eighth-largest country, whose total area is 2.78 million sq km—15.33% of its vehicles run on natural gas. These 1.9 million vehicles—approximately 15% of the world’s total number of natural gas-fueled cars, according to the International Association for Natural Gas Vehicles—power a continuing demand for natural gas, as do the electricity needs of its 46.8 million people.

This looks promising for companies like YPF, which last December reported discovering an estimated 4.5 Tcf of shale natural gas reserves south of Loma La Lata in Ar-

gentina’s Neuquén Basin. According to the EIA, this basin— Argentina’s largest shale prospect—is estimated to contain up to 408 Tcf of technically recoverable shale gas resources.

There are caveats, however. The deposits are not yet proven and will be more expensive to extract than conven-tional natural gas. In addition, there are stringent govern-ment controls on prices companies like YPF can charge for gas to Argentine customers. With YPF’s announcement in May 2011 of the country’s largest oil find in two decades—approximately 150 million bbl of crude oil equivalent in potential shale reserves in the same Loma La Lata field—Miguel Martinez, chief operating officer at YPF’s parent Repsol, has publicly expressed doubts the company would put a priority on developing its shale gas.

However, a government incentive program, called Gas Plus, is in place that allows companies extracting un-conventional gas to charge higher prices. For example, Apache said it has drilled more than 70 unconventional wells in four Neuquén fields since 2008. In April, its pro-duction under the Gas Plus program reached 75 MMcf/d with an average price of USD 4.93/Mcf. The company said it is evaluating the potential of unconventional resources in the low-permeability Precuyo formation and Los Molles and Vaca Muerta shales in Argentina’s Neuquén Basin.

Results from Apache’s well ACS-15h, in the Anticlinal Campamento field, southern Neuquén province, were re-leased in May. ACS-15h tested at a rate of 7 MMcf/d after multistage hydraulic fracturing. The well has a 2,800 ft hori-zontal section at 12,800 ft true vertical depth. Apache has an 85% interest, and Pampa Energia, Argentina’s largest power generator, 15%.

While Apache has identified further locations to drill near ACS-15h in AC field, it will study the longer-term per-formance of the first well before drilling others.

According to King, Apache’s Argentine shale gas de-velopment trials have required gathering of pumping re-sources from all over the country and pulling engineering talent from both North and South America.

Heading back from the drilling camp to Ensign Rig 16 on Beach Energy’s fi rst shale gas exploration well, Encounter-1, near Innamincka in South Australia. Photo courtesy: Beach Energy Limited.

JPT • JULY 2011 39

Page 10: Shale Gas & Oil Shale

Present in Argentina since 1978, Total, through its subsidiary Total Austral, operates 28% of the country’s gas production. Mid-January, Total acquired interests in four exploration licenses in Argentina in partnership with YPF to appraise their shale gas potential. Located in the Neuquén Basin, the licenses were awarded by the provin-cial authorities for a six-year period. Total has additional significant shale gas positions in Argentina, including 85% stakes in the La Escalonada and Rincón La Ceniza blocks in the same shale gas play, acquired early 2010. As operator, the company is currently conducting geological, seismic, and petrophysical studies in these blocks. Total is execut-ing plans to drill exploration wells in 2011 to evaluate the play’s potential.

Mexico’s TreasureWhile the EIA estimates the presence of 681 Tcf of shale gas in Mexico, and despite the close proximity of success-ful shale gas plays in the US, such as the Eagle Ford Shale in South Texas, no shale gas exploration drilling has yet oc-curred in Mexico. Pemex plans to drill the country’s first shale gas test well sometime later this year, very likely tar-geting the Eagle Ford Shale in Coahuila state.

South Africa: At a StandstillSouth Africa’s estimated 480 Tcf in technically recoverable shale gas resources are a possible boon to its population of 49 million, which relies heavily on coal. According to the EIA study, South Africa has one major sedimentary basin that contains thick, organic-rich shales—the Karoo Basin in central and southern South Africa. The Karoo Basin is large (236,000 sq miles), extending across nearly two-thirds of the country, with the southern portion of the basin potentially favorable for shale gas. However, the ba-sin contains significant areas of volcanic (sill) intrusions that may impact the quality of the shale gas resources, limit the use of seismic imaging, and increase the risks of shale gas exploration.

The Karoo is also an ecologically sensitive region, home to rare species such as the mountain zebra and riv-erine rabbit. In addition, it contains valuable farmland.

On 21 April 2011, South Africa’s cabinet placed a moratorium on oil and gas exploration licenses in the Ka-roo region. “Cabinet has endorsed the decision by the de-partment of minerals to invoke a moratorium on licenses in the Karoo, where fracking (sic) is proposed,” the govern-ment said in a statement.

Several companies are eyeing shale gas in the region. A Sasol/Chesapeake/Statoil joint venture has a Techni-cal Cooperation Permit (TCP) for 34,000 sq miles; Anglo American, a TCP for 19,300 sq miles; Falcon Oil and Gas, a TCP for 11,600 sq miles; and the leader, Royal Dutch Shell, a TCP for 71,400 sq miles.

A cabinet spokesman said the department of miner-als and resources would lead a task team to explore the implications of hydraulic fracturing, which would include

the departments of trade and industry as well as science and technology. No deadline for the moratorium’s end was given. All drilling applications in the Karoo—including those already submitted—will not be approved “until the research is carried out, concluded, and pronounced on,” the spokesman said.

Riches “Down Under”The EIA identified major shale gas in four main Australian assessed basins. It stated that further potential might ex-ist in other basins, not assessed due to budget and data constraints. With geologic and industry conditions resem-bling those of the US and Canada, according to the EIA, the country appears poised to commercialize its gas shale resources on a large scale. The Cooper Basin, Australia’s main onshore gas-producing basin, could be the first to de-velop, although its Permian-age shales have a nonmarine (lacustrine) depositional origin and the gas has elevated CO

2 concentrations. Beach Energy started drilling its first

two shale gas exploration wells in March—the Encounter-1 and Holdfast-1—both in the Cooper Basin. Encounter-1’s shale target zone was about 395 m thick. Flow stimulation of both wells began in June. A pilot production program, primarily driven by equipment availability, is targeted to begin early 2012.

Beach has a memorandum of understanding with Japa-nese company Itochu, whereby Itochu is considering the con-struction of an LNG facility that could be supplied by Beach’s shale gas, should it be produced in commercial quantities.

Other prospective shale basins in Australia include the small, scarcely explored Maryborough Basin in coastal Queensland, which contains prospective Cretaceous-age marine shales that are over-pressured and appear gas sat-urated. The Perth Basin in Western Australia, undergoing initial testing by AWE and Norwest Energy, has prospective marine shale targets of Triassic and Permian age. Finally, the large Canning Basin in Western Australia has deep, Or-dovician-age marine shale that is roughly correlative with the Bakken, Michigan, and Baltic basins.

The cost of drilling a well in Australia is estimated at USD 7 million to USD 10 million, considerably higher than the USD 3 million to USD 6 million typically encountered in the US. The size of the resource appears to be driving activ-ity, with operators willing to pay higher prices while learn-ing, with the prospect of future lower costs and plenty of resources remaining to extract.

In addition, an Australian fi rm has made a bold move into a US shale gas play, with the intention to gain more than fi nancially. In fi rst-quarter 2011, BHP Billiton acquired all of Chesapeake Energy’s interests in the Fayetteville Shale, in-cluding the midstream pipeline system, for USD 4.75 billion. The shale assets include 487,000 acres of leasehold and producing natural gas properties located in Arkansas, USA. In a press release, BHP Billiton chief executive J. Michael Yeager said, “Longer term, the expertise we gain here will be usable elsewhere.” JPT

40 JPT SPECIAL SECTION: SHALE

Page 11: Shale Gas & Oil Shale

©2011. Micro Motion, Inc. All rights reserved. The Emerson and Micro Motion logos are respective trademarks and service marks of Emerson Electric Co. and Micro Motion, Inc.

Emerson’s expanded range of Micro Motion® ELITE® High Capacity Coriolis meters have no moving internal parts, delivering you exceptionally accurate, repeatable and reliable fiscal measurement - day in, day out. With more than 600,000 Coriolis flow and density

meters installed worldwide and over 30 years of application expertise, Micro Motion keeps your process moving. Learn more at www.MicroMotion.com

With high flow, large pipeline measurement devices,just one moving part can spell trouble.

Who needs moving parts anyway?

Page 12: Shale Gas & Oil Shale

T he “shale gale” is not all about natural gas. While US shale gas drilling continues, it now is primarily to hold

acreage and build gas reserves. As illustrated in Fig. 1, there is a definite trend in the US away from natural gas to crude oil. Many companies have pulled rigs from de-velopment drilling in gas shales to explore wet gas and oil-bearing shale plays. Lured by the prospect of high-val-ue oil, whose margins promise a much higher return than those for natural gas, shale oil in US plays like the Bakken, Eagle Ford, Niobrara, Leonard (or Avalon), and Monterey is being extracted from low-permeability rock in increas-ing  quantities.

For example, while 33 permits were issued in 2008 for drilling in the Eagle Ford Shale, for the first 11 months of 2010, 1,018 permits were issued. Oil and condensate pro-duction has also sharply increased in the Eagle Ford, from a combined 0.8 million bbl in 2009 to roughly 3.9 million bbl in the first 10 months of 2010. A recent study—“The Economic Impact of the Eagle Ford Shale,” prepared by the Center for Community and Business Research, University of Texas at San Antonio—forecasts annual Eagle Ford oil production at 15 million bbl for this year, rising consistently until 2020, when it is projected to reach 111.5 million bbl.

In 2008, the US Geological Survey estimated that the US portion of the Bakken formation contains between 3  billion and 4.3 billion bbl (a mean of 3.63 billion bbl) of undiscovered, recoverable oil, ranking it among the larg-est US oil plays ever. Production in 2009 reached nearly 8  million bbl per month from roughly 4,500 producing wells. Oil production in North Dakota—in the heart of the Bakken—increased from 35 million bbl in 2005 to nearly 80 million bbl in 2009.

Technology Is the Enabler“The technology drivers that lifted gas recovery from 1% to 50% in the Barnett,” stated Apache global technology consultant George E. King, “will ultimately be the spring-board that drives oil recovery from the initial 1% to 1.5% in the Bakken and Eagle Ford oil-producing shales to much higher values.”

Continental Resources, the number one driller and lease holder in the Bakken as of November 2010, with 864,559 net acres, has been driving its production upward with advances in technology. For example, in 2009, it per-formed the first 24-hour continuous hydraulic fracture in the North Dakota portion of the play. In 2010, Continental developed a drilling concept it calls the Eco-Pad, whereby the company drills multiple horizontal wells from a single

The Trend Toward Shale OilRobin Beckwith, Staff Writer JPT/JPT Online

pad with zero boundary-line setbacks. This concept is ex-pected to reduce drilling and completion costs per well by approximately 10%, with about 70% less surface footprint area than four conventional drilling pads and only one ac-cess road.

The US National Energy Technology Laboratory cited the following as key to the Bakken’s oil-rich future:

• Further deployment of microseismic fracture monitor-ing is necessary to enable increased understanding of frac-ture propagation and extent in the Bakken system, resulting in better hydraulic fractures and enhanced production.

• With laterals now extending beyond 10,000 ft, pre-cise well placement control is crucial, as is the ability to deliver a smooth wellbore that enables single-trip fractur-ing and completion equipment installation.

• Single-well fracture programs of 30 stages or more are vital—and have been proven possible. For example, in 2010, Brigham Exploration completed a 35-stage fracturing program on its Figaro 29-32 horizontal well (20,673 ft total depth) that used 3.1 million lbs of proppant. Increasing the ability to pump ever larger multistage hydraulic fracturing jobs will improve economics in the Bakken play.

• Resolving water issues is a requirement in the Bakken, where typical water use for hydraulic fracturing is 1.5 mil-lion to 4.0 million gallons per well. Surface water in the Wil-liston Basin is in short supply. The cost of acquiring hydraulic

Fig. 1—In the US, capital investment in drilling for crude oil is climbing, while it is declining for natural gas. Courtesy: Aperio Energy Research.

42 JPT SPECIAL SECTION: SHALE

Page 13: Shale Gas & Oil Shale

fracturing water, and for disposal of fl owback and produced water, can range from USD 2 to USD 11.75 per bbl.

Global Response to Shale OilThe following are some examples of worldwide shale oil activity:

China National Offshore Oil Company will pay USD 570 million for a 33.3% stake in Chesapeake’s oil-rich shale leasehold acres in northeast Colorado and southeast Wyoming. It has also agreed to fund 66.7% of Chesapeake’s share of drilling and completion costs until an additional USD 697 million is paid, anticipated by year-end 2014.

In May, YPF announced it had made a large shale oil discovery at Loma La Lata in Neuquén province, Argen-tina. Estimated at 150 million bbl, it is equivalent to 6% of that country’s reserves, which in 2009, according to the US Energy Information Administration, totaled 2.62 billion bbl. This follows on the heels of another discovery—an esti-mated 4.5 Tcf of shale natural gas reserves—made last December in the same Loma La Lata area. When Repsol (YPF’s parent company) chief operation officer Miguel Martinez was asked by Dow Jones Newswires about the potential of shale resources to boost Repsol’s reserves, he said generally speaking, “my bet would always be against shale gas.”

Apache announced plans mid-May to explore for oil in shale formations in Egypt’s Western Desert. Thomas Voy-tovich, head of the company’s Egyptian unit, said that shale formations in the East Bahariya Block, where the company holds 74,000 acres, could hold 700 million to 2.2 billion bbl of crude oil. Egyptian offi cials have approved the drilling of two shale wells, likely to be spudded in the second half of 2011.

Two Japanese fi rms have bought into US oil shale acre-age. Mid-October 2010, Itochu agreed to buy a 25% stake in an oil shale project in Wyoming from Fidelity Exploration & Production, a unit of MDU Resources Group. Itochu is buying a share of about 88,000 acres in the Niobrara in southeast-ern Wyoming. Terms of the sale were not disclosed. Maru-beni will buy a stake in a US shale oil project from Marathon Oil for about USD 270 million. Under terms of the deal, an-nounced in early April 2011, Marubeni will receive a 30% working interest in Marathon’s 180,000 acres in the Niobrara in Wyoming and Colorado for USD 5,000 per acre. Marathon will be operator of the jointly owned acreage.

Australian junior Petsec plans to sell its minority stake in the WZ6-12 and WZ12-8 West oil fields in China’s Beibu Gulf to fund its push into US shale oil operations, chairman Terry Fern said at the company’s annual general meeting

18 May 2011. “We take the view that gas is unlikely to move much above the USD 4 to USD 5/Mcf price range within the next three years, so we are directing our attention more to oil,” he said. “We believe the quickest and least risky acquisition of sizable oil reserve additions is through shale oil, onshore Louisiana and Texas. Our strategy is to be an ‘early mover’ in areas where the shale source rocks are liquid-rich and to acquire high-quality acreage before it becomes extremely competitive and costly to lease.” Pet-sec has set itself a target of adding net reserves of more than 35 million barrels of oil from its shale oil plays in Loui-siana and Texas over the period from 2011 to 2013. JPT

Chesapeake Energy drilling rig located in the Barnett Shale (Tarrant County, Texas). Photo courtesy: Gary Wilson.

JPT • JULY 2011 43

Page 14: Shale Gas & Oil Shale

Oil Shale: The Rock That BurnsRobin Beckwith, Staff Writer JPT/JPT Online

T he term “oil shale” refers generally to fine-grained sed-imentary rock that contains solid bituminous materials,

called kerogen, which can be converted into liquid and gaseous hydrocarbons (petroleum liquids, natural gas liq-uids, and methane) when the rock is heated in the chemi-cal process of destructive distillation known as pyrolysis. Oil shale is found in a variety of depositional environments, including fresh water to highly saline lakes, epicontinen-tal marine basins and subtidal shelves, and in limnic and coastal swamps, commonly in association with deposits of coal. Unlike crude oil or even tar sands, oil shale has not been subject to high enough heat over a long enough peri-od of time to break the complex solid hydrocarbons down into lighter, liquid and gaseous compounds. One of its de-fining characteristics, however, is that it contains enough oil to burn without further processing, giving rise to its Ute Indian name, “the rock that burns.”

According to Jeremy Boak, director of the Center for Oil Shale Technology and Research, “oil shale” is not a misnomer, as is commonly held. “If oil shale is not shale,” he said, “then neither is the Barnett, the Haynesville, the Niobrara, or the Eagle Ford.” The difference is that shale oil, as currently used for plays like the Bakken and Eagle Ford, refers to rock that contains liquid hydrocarbons, and oil shale refers to rock that yields hydrocarbons upon heat-ing under appropriate conditions. Many names have been used for oil shale over the centuries, such as albertite, algal coal, alum shale, bituminite, boghead coal, cannel coal, gas coal, kerosene shale, kukersite, schistes bitumineux, stella-rite, tasmanite, torbanite, and wollongongite. Some of these names are still in use.

The organic matter in oil shale—composed chiefly of carbon, hydrogen, oxygen, and small amounts of sufur and nitrogen—is predominantly kerogen, which by definition is an organic material that is typically insoluble in ordinary organic solvents. The mineral and elemental content of oil shale differs distinctly from coal. The ash (or mineral) con-tent of coal is generally less than 40 weight percent (wt%), whereas oil shale commonly has an ash content greater than 60 wt%. The organic matter of oil shale typically has a higher hydrogen and lower oxygen content than that of lignite and bituminous coal.

Oil Shale Production TechniquesOil shale can be mined and processed to generate oil that is similar to oil pumped from conventional oil wells, although its API gravity is generally lower. Extracting oil from oil shale is more complex and expensive than con-ventional or even unconventional oil extraction. Because of

its insolubility, once it is mined, the organic matter must be retorted at temperatures of 900°F to 950°F to decompose it into shale oil and gas. Mined byproducts—such as urani-um, vanadium, zinc, alumina, phosphate, sodium carbonate minerals, ammonium sulfate, and sulfur—can add consider-able value to some oil shale deposits. However, the mineral byproduct could be uneconomic to produce. For example, on some US Federal oil shale lands, deposits of nahcolite (a naturally occurring form of sodium bicarbonate, or baking soda) are intermixed with the oil shale. Relative to oil and other petroleum products, nahcolite is a low-value com-modity, and its price would likely fall even further if its pro-duction increased significantly.

Only a limited portion of the resource occurs at depths accessible to open-pit or underground mining operations. Accessing and recovering a large percentage of existing oil shale will likely require the development of in-situ technolo-gies for processing oil shale underground. In-situ solutions obviate problems associated with mining, handling, and

Typical oil shale rocks.

44 JPT SPECIAL SECTION: SHALE

Page 15: Shale Gas & Oil Shale

Slickwater GreenCustomizable Powdered BlendEngineered using the latest green chemistrySlickwater Green is one of the most environmentally responsible stimulation solutions ever created. In addition to being engineered according to the principles of green chemistry, this revolutionary powdered blend is premixed based on job site specifications and delivered in dry form – simplifying logistics and eliminated the risk of freezing. Slickwater Green’s powdered form also may eliminate the need for chemical totes and help reduce the operational footprint. Best of all, application of Slickwater Green produces environmentally responsible results that simplify slickwater stimulation treatments.

Slickwater Green Blend includes:+ Friction Reducer+ Biocide+ Oxygen Scavenger+ Clay Control+ Scale Inhibitor

Slickwater Green Blend

+ Eco-friendly • Designed using principles of green chemistry • More environmentally friendly • No harmful by-products • Transported to job site in inert, dry form • No solvents or auxiliary chemicals required • No leftover chemicals or totes to dispose of • Requires fewer chemical units, reducing operational and carbon footprint

+ Enhanced productivity • Faster/easier application • Powder eliminates chemical freezing concerns

+ Flexible treatment designs • Premixed to client or location specifications

Stage After Stagewww.fractech.netToll Free 866.850.1008

To put Slickwater Green to work in your wells, contact your Frac Tech representative today.

A member of the ECO-Green Family: Innovative, Environmentally Responsible Solutions

1000 (-2 hrs) 4000 (0 hrs) 4000 (24 hrs) 4000(50 hrs) 4000 postgas Stress - psi

10,000

1,000

100

10

md-

ft

45/50 Texas Gold Baseline - 2% KCl

45/50 Texas Gold Regain - Slickwater Green

Conductivity Comparison: 2% KCl vs. Slickwater Green @2lbs/ft2, 121 0C (250 0F), Ohio Sandstone

Page 16: Shale Gas & Oil Shale

Table 1. World Oil Shale Resources of Signifi cant Interest

Country Oil ShaleReserves (Million Tonnes)

Oil ShaleReserves (BillionBbls)

Global Rank

Annual Oil Shale Produc-tion 2005 (Thousand Tonnes)

USA 301,556 2,085.3 1

Russia 3,5470 247.8 2

Zaire 14,310 100 3

Brazil 11,734 82 4 159

Italy 10,446 73 5

Morocco 8,167 53.4 6

Jordan 5,242 34.2 6

Australia 4,531 31.7 8

Estonia 24,944 16.3 9 345

China 2,290 16 10 180

Canada 2,192 15.2 11

France 1,000 7 12

Egypt 816 5.7 13

Israel 550 4 14

Others (13) 7,804 54.5

Total Known 408,602 2,826.1 684

disposing of large quantities of crushed rock. In addition to potentially recovering a greater amount of the total sec-tion of oil shale, using underground slow heating methods, with lower temperature requirements (650°F to 700°F) than surface retorting, has the added advantage of producing a superior quality shale oil, reducing some of the upgrading needed before delivery to refineries can occur.

Boak notes a third alternative, called in-capsule pro-cessing, pioneered by Red Leaf Resources. “This approach involves mining the oil shale,” he said, “then placing it in a structured cell or capsule resembling a landfill or heap leach mineral recovery cell, heating it with hot gases in-jected into the lower part of the cell, and recovering the products through pipes in the upper part of the cell.” Ac-cording to Boak, the completed retort is designed to be left in place.

Uses for Spent ShaleNotably in Germany and China, the heat energy obtained by the combustion of the organic matter in oil shale has been used in the cement-making process. According to the US Geological Survey (USGS), other products that can be made from spent oil shale include specialty carbon fibers,

adsorbent carbons, carbon black, bricks, construction and decorative blocks, soil additives, fertilizers, rock wool in-sulating material, and glass. Most of these are produced in small quantities or are in the experimental stage.

Some uses backfired. For example, Sweden’s alum shale was burned with limestone to manufacture “breeze blocks,” a lightweight porous building block used widely in the country’s construction industry. Production stopped when it was recognized the blocks were radioactive and emitted unacceptably large amounts of radon.

World Oil Shale ResourcesThe largest known deposit is in the Green River formation in the western US, containing an estimated 213 billion tons of shale oil (1.5 trillion bbl). Overall US reserves are estimated at 2 trillion bbl (301 billion tons). For many reasons—pre-dominant among them lack of infrastructure, reliable recov-ery technologies, and adequate water resources—shale oil in today’s world market is not competitive with petroleum, natural gas, or coal. However, it is produced in three coun-tries that possess easily exploitable deposits of oil shale but lack enough comparable fossil fuel resources ( Table  1). Estonia, with an estimated resource of 16.3 billion bbl, pro-duces 345,000 tonnes annually; Brazil, with 82  billion bbl, produces 159,000 tonnes annually; and China, with 16 bil-lion bbl, produces 180,000 tonnes annually. According to the World Energy Council, oil shale resources of approximately 2.8 trillion bbl or 408.6 billion tonnes, exist worldwide. A new USGS assessment has revised these numbers upward, but the fi gures are incomplete, as those for Wyoming have yet to be published. The estimated world total is likely to exceed 4.1 trillion bbl. To put this in perspective, 2009 glob-al crude oil proved reserves totaled an estimated 1.3  tril-lion bbl, and 2008 worldwide coal reserves totaled an esti-mated 948 billion short tons.

Oil shales range widely in organic content and oil yield. Commercial grade quantities of oil shale, as deter-mined by their yield of shale oil, range from about 100  liters to 200 liters per tonne. The USGS uses a lower limit of about 40 liters per tonne for classification of US Federal oil shale lands. Elsewhere, a limit of 25 liters per tonne has been  suggested.

Deposits range from Cambrian to Teriary age, occur-ring in minor, uneconomical accumulations to huge depos-its occupying thousands of square kilometers and reaching thicknesses of 700 m or more.

Centuries of HistoryThe promise of oil shale has tantalized humankind through-out the world since long before 1912 when the US—whose awareness of the strategic signficance of its huge oil shale resources was dawning along with the country’s nascent dependence on petroleum—established the Office of Naval Petroleum and Oil Shale Reserves. For centuries, people have been fascinated by what happens when oil shale is heated. Apothecaries and physicians in Austria used oil from shale for medicinal purposes as early as 1350. In

Source: Dyni, World Energy Council, 2007.

46 JPT SPECIAL SECTION: SHALE

Page 17: Shale Gas & Oil Shale

Fig. 1— Oil shale mined from deposits in Brazil, China, Estonia, Germany, Russia, and Scotland, 1880–2010. Graph copyright: Schlumberger. Used with permission.

England, the first known patent for “a way to extract and make great quantities of pitch tarr and oyle out of a sort of stone” was issued in 1694. According to paper SPE 116570 (Crawford et al.), oil shale was used in Sweden, Scotland, and France as early as 1637 as a source of fuel. Before, during, and following World War II, Sweden produced oil from alum shales, until 1966 when other fuels became more readily available. During this period, Sweden mined about 50 million tons of oil shale. In North America, the first small processing facility for oil shale was opened in Alberta, Can-ada, in 1815. By the eve of the US Civil War, more than 50 companies in Canada and the US were retorting shale to distill oil from rock—although in small quantities—whose uses included kerosene and lamp oil, paraffin, fuel oil, lu-bricating oil and grease, naphtha, illuminating gas, and am-monium sulfate fertilizer.

With the rise in the more easily extracted crude oil beginning in 1859, interest in oil shale generally waned. However, awareness of oil shale’s vast potential produced an investment boom in the US between 1917 and the late 1920s, and sporadic development from the early 1970s onward. Oil shale has been mined commercially in Ger-many, China, Scotland, Russia, Brazil, and Estonia (Fig. 1). World oil shale production peaked in 1980 when 47 million tons were mined, two-thirds of it in Estonia where it was used mainly for fuel in several large electric power plants. Several other countries have attempted or currently have an oil shale mining industry, including Australia, Sweden, Canada, Israel, Jordan, and Morocco.

Estonia’s Problematic ExampleOil shale serves as the main fuel for power generation only in Estonia, where the oil shale-fired Narva power plants ac-

counted for 95% of the country’s electrical generation in 2005. According to I. Opik, in “The Future of the Estonian Oil Shale Energy Sector,” 22 million tons of oil shale were produced in 1997 from six room-and-pillar underground mines and three open-pit mines. Of this amount 81% was used to fuel electric power plants, 16% was processed into petrochemicals, and the remainder was used to manufac-ture cement as well as other minor products. E. Reinsalu, in “Criteria and Size of Estonian Shale Reserves,” said state subsidies for oil shale companies in 1997 amounted to USD 9.7 million. More recent figures are forthcoming that could paint a somewhat different picture.

Interest in oil shale has grown since 2000, with a rise in studies, conferences, symposiums, and associations devoted to exploring its potential. Yet challenges abound. John R. Dyni’s summation of Estonia’s oil shale situation, which appears in the USGS report, “Geology and Resourc-es of Some World Oil-Shale Deposits,” dated June 2006, points to problems emblematic of those facing the industry as a whole:

“The future of oil shale mining in Estonia faces a num-ber of problems, including competition from natural gas, petroleum, and coal. The present open-pit mines in the kukersite deposits will eventually need to be converted to more expensive underground operations as the deep-er oil shale is mined. Serious air and groundwater pollu-tion have resulted from burning oil shale and leaching of trace metals and organic compounds from spoil piles left from many years of mining and processing the oil shales. Reclamation of mined-out areas and their associated piles of spent shale, and studies to ameliorate the environmental degradation of the mined lands by the oil shale industry are under way.” JPT

JPT • JULY 2011 47


Recommended