Greatest Hits

What makes for a top-producing well that garners significant industry attention? Must it be a discovery having one of the largest flow rates of the year on initial test? Or, is it a relatively smaller well that’s opened up an intriguing new producing area, even though the flow test may not be that great?

Maybe it’s the well that recorded big production from an existing pay zone, finally proving the true potential of an emerging play, such as a shale in Poland or in Ohio’s Utica play.

All of these criteria are valid and warrant consideration in a roundup of some of the top oil and natural gas wells reported in 2012, both onshore and offshore.

All of the wells listed here provided encouragement that new producing provinces continue to be found everywhere in the world (think Mozambique, for example). And, they remind us that older provinces like the Permian Basin in West Texas can be refreshed with the application of new technologies. Finally, they remind us that ingenuity is still the No. 1 reason new oil and gas resources are found.

INTERNATIONAL

Explorers enjoyed a good year in 2012. Successes were realized in deep water in several major offshore provinces, and emerging onshore resource plays made bold steps forward in other countries. Here’s a wrap-up of the progress made in the world’s most notable plays.

Angola

Like Ghana, Angola’s pre-salt formation has a common origin with offshore South America. But unlike Brazil’s Campos and Santos basins, Angola’s pre-salt region is found both offshore and onshore. The country’s onshore pre-salt is about 13,000 feet deep, while the offshore pre-salt is even deeper.

Angola is one of the two largest oil exporters in Africa and looks to surpass the current leader, Nigeria, thanks to its newly discovered pre-salt reserves. In the spring of 2012, Sonangol’s #1-Azul flowed about 3,000 barrels of oil per day. And, during a drillstem test in March, a Cobalt International well, #1-Cameia, flowed at an unstimulated, sustained rate of 5,010 barrels of 44-degree-gravity API oil and 14.3 million cubic feet of associated gas per day.

In the fall, Maersk Oil’s #1-Caporolo flowed 3,000 barrels of oil per day from the offshore pre-salt.

Argentina

The potential for greater domestic oil and gas production is a tantalizing prospect in Ar- gentina, which has suffered escalating energy shortages since the country fell into recession in 1999 and the government defaulted on a $100-billion debt. Rising imports of LNG at prices that are several multiples of regulated domestic prices have saddled the government with a hefty bill for energy subsidies. Any homegrown resources will help the country’s economic situation. Shales may be the answer. According to a 2011 Energy Information Administration report, Argentina boasts the world’s third-largest unconventional gas resource potential; roughly half this 774 trillion cubic feet worth of natural gas is in the Neuquén Basin.

Exploration successes in 2012 provided encouragement that new producing provinces continue to be found everywhere in the world

Although recent enthusiasm in Argentina regarding unconventional fossil fuel resources has focused on gas, Repsol-YPF announced a large discovery of Vaca Muerte shale oil in 2012 in Loma La Lata Field in the Neuquén province. The estimated size has increased to 741 million barrels of recoverable shale oil.

In the winter of 2012 in Argentina’s Mendoza Province, Repsol-YPF reported a significant conventional oil find. The unnamed wells are in the Chachahuen Block in the Neuquén Basin and the company estimates the reservoir contains at least 40 million barrels of recoverable resources. In the spring, the company reported that a Mendoza Province prospect could contain up to 1 billion barrels of oil equivalent, based on results from two exploration wells in the Payun Oeste and Valle del Rio Grande blocks. The two exploration wells confirm the extension of Vaca Muerta shale in the Mendoza structure.

And near year-end, Petrobras reported an oil and gas strike at #1-x Estancia Campos in Santa Cruz Province. The #1-x Estancia Campos is in the Puesto Peter concession and encountered approximately 11 million barrrels of oil equivalent pay in Springhill. In the Estancia Agua Fresca Block, preliminary results from #1-x La Cancha Austra indicate 52-degree-gravity oil with estimated reserves of approximately 6 million barrels of oil equivalent.

Ghana

Success in Brazil’s pre-salt basin has led operators to look at analogous basins across the Atlantic along the West Coast of Africa, including in Ghana, where numerous discoveries have been made in the Tano Basin. The pre-salt formations’ common origin began about 120 million years ago, when the ancient Gondwana supercontinent split into what is now South America and Africa.

The finds in West Africa are multiplying quickly. Tullow Oil Plc, based in London, turned in additional results from its Tano Basin appraisal well in 2012. The #2A-Ntomme hit approximately 128 net feet of light-oil pay in excellent quality sandstone reservoirs. Fluid samples recovered from the well indicate oil of approximately 35-degree-gravity API.

According to Tullow Oil partner Anadarko Petroleum Corp., the pressure data collected from the #2A-Ntomme and #3-Tweneboa sidetrack wells indicates the potential for an oil column of more than 400 feet below the gas-condensate accumulation encountered in the #3-Tweneboa sidetrack. Paul Dailly, senior vice president of exploration for Kosmos Energy, whose company is an 18% partner in the two discoveries, called the find a “great result” because Ntomme was originally identified as a gas-condensate discovery. “However, this well confirms the majority of resources to be oil,” he said in a statement.

Tullow operates the Deepwater Tano Block with a 49.95% working interest. Kosmos and Anadarko Petroleum each own an 18% stake, with Sabre Oil & Gas Holdings holding 4.05% and Ghana National Petroleum Corp. a 10% carried interest.

Kosmos also announced completion of sidetrack operations at its Jubilee project’s #7-J, which was drilled to test a new completion design resulting from near-wellbore productivity issues. The sidetrack was flow tested at a rate of up to 15,000 barrels of oil per day.

In the spring of 2012, another of Tullow’s appraisal wells in the Tano Block, #4AEnyenra, hit 105 feet of net oil pay. And in the fall, the company released deepwater wildcat results from its #1-Wawa, which struck 65 feet of gas-condensate pay and 42 feet of oil pay in turbidite sands. Samples show the oil to be good quality (38- to 44-degree-gravity API).

In the fall, Eni reported the first oil discovery in the Offshore Cape Three Points (OCTP) Block, also in the Tano Basin. The #1XSankofa East encountered 92 feet of pay with gas and condensate and 249 feet of gross oil pay in Cretaceous sandstones. During the production test, the well produced about 5,000 barrels per day of high-quality oil, with flow rates constrained by surface infrastructure.

Mexico

Pemex struck oil in the deep water, its first success after years of exploration in the deeper reaches of the Gulf of Mexico. Production from Pemex’s Gulf of Mexico fields had slipped from 3.4 million barrels per day in 2004 to about 2.5 million barrels per day in 2012.

In March, Pemex announced its first discovery, #1-Puskon. It was drilled in 2,122 feet of water and encountered two intervals between 23,294 feet and 24,426 feet. The company also identified a 2,598-foot zone of Paleocene rocks with good porosities.

In an announcement in August, a deepwater gas discovery at Pemex’s #1-Kunah exploration well indicated nearly 2 billion cubic feet of gas in five stacked wet reservoirs at depths between 9,333 and 13,461 feet. Production tests showed 34 million cubic feet per day of wet gas and 110 barrels per day of liquids.

In November, Pemex reported a new oil discovery at exploration well #1-Supremus. After analyzing production tests, the company concluded the Perdido Prospect could hold up to 125 million barrels of oil.

Mozambique, Tanzania

The Anadarko and Eni discoveries in areas 1 and 4 offshore Mozambique could hold more than 100 trillion cubic feet—or a potential value 30 to 40 times the current gross domestic product of the country, according to an Ernst & Young report. Operators and the Mozambique government are looking at building onshore processing facilities (including liquefied natural gas facilities) that could employ an estimated 7,000 new workers.

In the spring, Eni reported that its #1-Mamba North had a potential of up to 7.5 trillion cubic feet of gas, and an Anadarko appraisal well hit 525 net feet of gas pay at #4-Barquentine. In the fall of 2012, #2 Mamba North East added at least 10 trillion cubic feet of gas in place to Area 4 and confirmed at least 62 trillion cubic feet of gas in place. It encountered 656 feet of gas pay in stacked multiple high-quality Oligocene, Eocene, and Paleocene sands.

In Tanzania, Statoil is working on similar LNG processing plant plans with the government. LNG products from either country could easily be shipped to Asia.

Statoil’s discovery at #1-Zafarani hit 394 feet of high-quality reservoir with high porosity and permeability. The results indicated that the area holds up to 5 trillion cubic feet of gas in place. Meanwhile, BG Group’s #1-Jodari hit 370 feet (Miocene) and 36 feet (Tertiary) of gross pay. The net-to-gross ratio indicates a mean recoverable resource estimate of 3.4 trillion cubic feet of gas.

Poland

Russia’s Gazprom has a monopoly on European gas supplies, and the majority of Russian exports (78%) are destined for European markets, particularly Germany, The Netherlands and Poland. The development of any non-Gazprom resource could play a strategic role in loosening Gazprom’s grip on Europe’s supply of natural gas and aid its still anemic economic recovery.

As U.S. shale development flourished in recent years, operators began transferring shale oil and gas recovery technologies to international arenas. Poland was an early target because of its significant resource base. Early estimates of the country’s reserves were perhaps optimistic; in March 2012 Poland pared estimates for its recoverable shale-gas reserves to between 12 trillion and 27 trillion cubic feet—still an important resource base.

In 2011, U.K.-based 3 Legs Resources Plc fast-forwarded shale exploration when it drilled and shut in the country’s first two horizontal shale-gas exploration wells, #2H-Lebien LE and #1H-Warblino LE.

In early January 2012, it carried out further tests, with impressive results.

“Following a period of shut-in we were able to achieve significantly better results on the two wells,” said the company in a press release, “particularly #2H-Lebien LE, which flowed unassisted at an average rate of 550,000 cubic feet per day for a 21-day natural flow test, before being shut in.”

At year-end 2012, 3 Legs added more detail: “The well is now in a planned shut-in period to record pressure buildup using surface and downhole pressure gauges; this pressure buildup data will further enhance understanding of the longer-term flow potential of the Ordovician interval.”

More exciting developments for Polish shale exploration continued through the year, with London-based San Leon Energy Plc’s announcement that its #1G-2 Lewino, in the Gdansk concession, encountered continuous gas shows of more than 3,200 feet. At midyear, the company’s #2 Siciny encountered continuous dry-gas shows throughout and found almost 500 feet of net oil pay in the first zone.

In the second zone, with a 787-foot gross interval, more than 105 feet of net pay was reported. Zones three to five also revealed potentially prospective, highly fractured, organic-rich shale intervals with a total gross thickness of 1,410 feet between 6,774 and 8,562 feet.

U.S.

In the U.S., the unconventional revolution is maturing. Operators have identified the major resource plays, and work is now focused on identifying attractive new opportunities within these broader petroleum systems. Here is a summary of significant 2012 developments in domestic exploration.

Bakken, Three Forks

Bakken and Three Folks drilling and production were robust again and production pushed North Dakota into the No. 2 spot among producing states in the U.S. in 2012. Interesting new expansion into Montana included leases acquired in McCone County, which hasn’t seen drilling since 2006.

North Dakota On the North Dakota side of the play, Bakken activity continued to expand. In the spring, a Burlington Resources Oil & Gas Co. venture in McKenzie County, #11-1TF-2SH Sunline, initially flowed 1,464 barrels of 43.4-degree-gravity oil and 2.76 million cubic feet of gas in the previously untapped second bench of Three Forks (Middle Three Forks).

Two important discoveries were reported by Continental Resources from tests in McKenzie County. The #2-22H Charlotte initially flowed 1,140 gross barrels of oil equivalent per day on completion from a deeper bench of Three Forks. Production is from a fractured two-section lateral in the second bench, approximately 50 feet below a typical first bench Three Forks well.

A second Continental test at #3-22H Charlotte, the first horizontal well to test the third bench (TF3) of the Three Forks zone in the Williston Basin’s Bakken play, flowed 953 barrels of oil equivalent per day.

With the addition of oil found in the lower Three Forks benches, including TF2, TF3 and TF4, the company now estimates the Bakken has 903 billion barrels of original oil in place, a 57% increase from a 2010 estimate of 577 billion barrels.

According to Continental Resources’ president Harold Hamm, “This could be a real game-changer. The #3-22H Charlotte is the first well in a 14-well program that we plan to complete by year-end 2013 to test productivity of the second, third and fourth benches of the Three Forks over a broad area of the play.”

A Middle Bakken discovery in September by Burlington Resources Oil & Gas Co.’s #34-34H Llano in McKenzie County initially flowed a whopping 6,800 barrels of 47-degreegravity oil and 1.28 million cubic feet of gas from Charlson Field.

Montana In Montana’s Roosevelt County, new exploration seemed to open up the area. In spring 2012, an Oasis Petroleum well, #15-22H Susie, flowed 1,227 barrels of oil and 892,000 cubic feet of gas per day from a fractured Middle Bakken lateral.

In May, a Whiting Oil & Gas Corp. wildcat in Roosevelt County (#34-24TFH Schnitzler) produced 2,148 barrels of oil and 1.95 million cubic feet of gas from Three Forks in its first month of reported production.

In Richland County, Montana, Slawson Exploration opened a new Williston Basin pay zone with four Upper Middle Bakken completions: #1-32H Culverin initially flowed 476 barrels of oil per day; #1-30H Cleaver initially flowed 296 barrels per day; #1-26H Arrowhead-Federal initially pumped 316 barrels daily; and #1-30H Dart-Federal initially pumped 312 barrels of oil per day.

Additionally, Apache Corp. announced plans to drill six horizontal Bakken/Three Forks wildcats in Daniels County, Montana. According to IHS Inc., the six proposed units are two to eight miles northwest, north and northeast of the two-well, abandoned Four Buttes Field.

Niobrara

The Niobrara play in Colorado and Wyo - ming continued to expand in 2012, with permits issued as far south as Colorado Springs, Colorado, as far north as the Power River Basin in Wyoming and as far west as Colorado’s Garfield County.

The core area of Wattenberg Field and its environs in the Denver-Julesburg Basin continued to host the steadiest activity and results, with Anadarko Petroleum Corp. and Noble Energy Corp. leading the charge. However, during the summer, Continental Resources Inc. announced a producer flowing 910 barrels of oil equivalent per day, #1-2 Buchner, in Weld County, Colorado.

In the fall, a Chesapeake Operating Inc. well in Converse County, Wyoming, #29-33-70 1H Combs Ranch Unit, flowed at an initial rate of 854 barrels of 50.1-degree-gravity oil, with 4.9 million cubic feet of gas per day. And late in the year, a Denver-Julesburg Basin well by Whiting Oil & Gas Corp., #04-0414H (Wild-horse), initially flowed 1,170 barrels of oil equivalent per day from an undisclosed horizontal Niobrara B zone interval.

Permian Basin

The Permian Basin is one of the leading tight-oil provinces in the U.S. and a primary driver behind the growth in U.S. onshore production. As natural gas prices sagged in 2012, activity in the oil-rich Permian Basin flourished. In particular, the horizontal Bone Spring play sparked activity across southeastern New Mexico and West Texas.

In the spring of 2012, Cimarex Energy Co.’s #2 Tres Equis State flowed 1,120 barrels of 39.7-degree-gravity oil, 251,000 cubic feet of gas and 282 barrels of water per day from Bone Spring. The Delaware Basin producer is in Lea County, New Mexico. The well produces from fracture-stimulated perforations at 10,901-15,386 feet. According to IHS Inc., after drilling an 11,300-foot vertical hole, Cimarex drilled a horizontal leg to the south. Measured depth was 15,523 feet and true vertical depth was 11,184 feet. The well confirmed Triple X West Field, which was discovered in 1997.

COG Operating completed #1H Red Sauce State in the summer producing 1,118 barrels of crude and 2.06 million cubic feet of gas. The horizontal Eddy County, New Mexico, well produces from acid- and fracture-stimulated Bone Spring perforations at 8,200-10,869 feet. The Delaware Basin venture was drilled to 10,930 feet and the lateral bottomed to the west at a true vertical depth of 7,930 feet.

Additionally, Cimarex announced a significant Wolfcamp well in its Ford West Field development in Culberson County (RRC Dist. 8), Texas. The #1H Macbeth 22 Fee produced 4.34 million cubic feet of gas and 364 barrels of 57.7-degree-gravity condensate per day. Production is from fracture-treated perforations at 9,845-14,255 feet. IHS Inc. reported that the Delaware Basin horizontal well was drilled to a total depth of 14,405 feet in Section 22, Block 59, T1S, T&P RR Co. Survey, A-6990. The true vertical depth in the south-trending lateral was 9,781 feet.

The Permian’s bounty will continue to unfold because it is a stacked play. Says Bernstein Research in a report on the basin, “The targets of today don’t represent the last set of opportunities, so technology, ingenuity and price signals will continue to open up new formations.”

Utica

In October of last year, the U.S. Geological Survey released estimated reserves of the Ordovician-age Utica shale and related Point Pleasant formations throughout Appalachia of 940 million barrels of oil, 38 trillion cubic feet of gas and 208 million barrels of natural gas liquids. According to estimates by the Ohio Department of Natural Resources, the state has 1.3 billion to 5.5 billion barrels of oil recoverable potential, and 3.8 trillion to 15.7 trillion cubic feet of natural gas. In 2012, the shale became one of the most interesting plays in the U.S.

Operators began to crack the play’s code in 2011. Chesapeake Operating Inc. announced a Utica shale discovery in Harrison County, Ohio, in late 2011, #8H Buell, which had a peak flow rate of 9.5 million cubic feet of gas and 1,425 barrels of oil and natural gas liquids per day.

In May 2012, a Gulfport Energy Corp. producer in Harrison County, #1H Wagner Unit, flowed 3,282 barrels of oil equivalent per day. And in August, Gulfport’s #1-1H Shugert in Belmont County, Ohio, topped the list of producing wells with an initial rate of 5,050 barrels of oil equivalent per day.