United States by WORLD OIL STAFF; Canada by ROBERT CURRAN, Calgary, Alberta; Mexico by DR. DANIEL ROMO RICO, Mexico City
No one is chanting “Drill, baby, drill,” but US operators are doing just that, extending their strong run in 2010 to 2011 as they take advantage of sustained high oil prices. Drilling activity is booming in liquids-rich shale plays such as the Bakken and the Eagle Ford, as well as in conventional oil and gas regions like the Permian basin in West Texas and Oklahoma’s Anadarko basin. Offshore drilling activity is returning to the Gulf of Mexico, though not at the pre-Macondo levels in either the shallow or deepwater blocks. Canadian drilling activity is also expected to increase. The Petroleum Services Association of Canada (PSAC) has predicted that 12,950 wells will be drilled in 2011, representing a 5.7% increase from 2010. In Mexico, where the economics of drilling activity are intertwined with government policy, drilling activity is down so far in 2011, but with an increased emphasis on exploration.
UNITED STATES
In 2010, US operators drilled 40,182 wells with a total footage of 288,100 ft. As a result of this strong activity, combined end-of-year US oil reserves for the 50 largest public oil and gas companies grew 11% in 2010 and their US gas reserves grew 12%, the strongest combined annual growth in at least five years, according to a benchmark study released by Ernst & Young in June. In continuation of this strong activity, World Oil’s midyear forecast revision estimates that 23,565 wells were drilled in the first half of 2011. A 6.7% increase is forecast for the second half, for a 2011 total of 48,714 wells, Table 1. This forecast, slightly lower than the 50,392 wells we predicted in February, nevertheless represents an impressive 21% jump from 2010. Well depth is also forecast to increase by about 780 ft/well compared to 2010, for a 2011 average of 7,949 ft/well. This deepening is being driven by the proliferation of horizontal wells with long laterals in the shale plays, and to tap bypassed reserves in mature oil fields.
Our second-half forecast reflects the upward direction of rig counts and our midyear operator survey. The Baker Hughes rig count was 1,908 on July 29, up from 1,700 at the beginning of the year and a first-half average of 1,773, and RigData’s count has seen similar movement. The nine majors and large independents that responded to our survey expect to increase drilling by 29% in the second half of 2011, whereas 65 smaller independents reported that they will drill 4.5% fewer wells in the second half than in the first. This is a reversal of the usual pattern, in which the smaller companies tend to be more optimistic than the major operators.
Our current estimate of the number of US wells drilled in 2010 is 5,435 fewer than we estimated in February, based primarily on downward revisions in Texas, California and Pennsylvania.
Area highlights. Texas continues to be the brightest spot in the US for drilling. Even with the downward revision of our 2010 number, that state saw drilling increase by some 50% over 2009 levels, and another 39% jump is expected this year, to 20,893 wells. The Lone Star state provides a striking illustration of the nationwide shift in E&P budgets from gas to oil. Year-on-year, the biggest increases are forecast for Permian basin-centered District 8 (3,502 wells, or 96%) and District 1 in the Eagle Ford (1,104 wells, or 120%). Meanwhile, activity is slowing in Districts 5, 6 and 7B, which contain the Barnett shale and Texas’ portion of the Haynesville. Similar trends are seen from the first half to the second half, except in District 1, where feverish first-half drilling in the Eagle Ford (already exceeding 2010’s total) will slow by some 30%.
The northern district of Louisiana, which holds the rest of the Haynesville shale, will also see drilling decrease, by 31% compared with 2010. The southern district will be slightly up, bringing the onshore state total to 1,064 wells.
After Texas, the biggest expected increases for 2011 are in Colorado (1,037 wells), California (848 wells) and North Dakota (847 wells). In each of these states, the boom seems to be driven primarily by interest in oil-rich shale formations: the Bakken in North Dakota and the up-and-coming Niobrara and Monterey in Colorado and California, respectively. The delineation of the latter two plays is proceeding much more rapidly than was seen in older plays such as the Barnett and Marcellus, thanks to improved technology and greater industry confidence in the economics of shale resources. Though a good portion of the Bakken formation lies within Montana and the first horizontal well into the shale was drilled there, that state continues to trail behind North Dakota in drilling activity, with only a 28-well increase expected this year, to 274 wells.
The expected slowdown in Marcellus shale gas drilling, staved off throughout 2009 and early 2010 by lease requirements, finally arrived in response to stagnant gas prices, resulting in a 2010 total of 2,682 wells in the core state of Pennsylvania. Only 1,134 wells were drilled in the state during the first half of this year, and, despite a 15% increase expected in the second half, the 2011 total is forecast to be 9% lower than last year’s, at 2,438 wells. Because of its proximity to large gas markets, the Marcellus still has favorable economics compared with other gas shales, and this is reflected in the drilling forecast for West Virginia. That state, which is still in a much earlier stage of Marcellus shale development compared with Pennsylvania, should see a 12% increase in wells drilled this year, to 463.
In the Gulf of Mexico, operators drilled 204 wells in 2010, most of them in the first half of the year before the deepwater moratorium went into effect. In 2011, we expect the well count to rise from 89 in the first half to 132 in the second half, for a total of 221 wells. GOM drilling remains anemic with a fleet utilization rate of only 53.4% as of July 27, according to World Oil’s RigStar service.
What can go wrong? As an industry accustomed to boom-and-bust cycles, even when the rigs are running hot the question always looms: When will the drilling downturn begin? As always, economics is the key factor. If the Europeans are unable to solve their debt crisis and if the US falters in raising its debt ceiling and stimulating the national economy, we may enter a double-dip recession. Consequently, oil and gas demand will suffer and prices will trend downward. Instinctively, operators will cut back on E&P expenditures wherever possible. Another potential hurdle is the effort among state and federal lawmakers to regulate the hydraulic fracturing technology that makes shale drilling economic.
About these statistics. World Oil’s drilling tables and forecasts are based on a variety of sources, including American Petroleum Institute (API) drilling and completion reports, Baker Hughes and RigData rig counts, and reports from the state regulatory agencies. Also, 74 operators with drilling programs in the US responded to this year’s survey. Please note the credits and explanations in the table footnotes. We thank all the contributors for their time and effort in providing data and analysis for this report.
World Oil editors try to be as objective as possible in the estimating process to present what they believe is the most current data available. Sound forecasting can only be as reliable as the base data. In this respect, please note that well data reporting is a dynamic process and most historical data will be continually updated over a period of several years before “the books are closed” on any given year.
| Table 1. Midyear revision, 2011 US drilling forecast |
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CANADA
At the halfway point of 2011, Canada’s oil and gas industry finds itself firmly ensconced in a strange, bipolar state, with a veritable oil boom on one side and a natural gas bust on the other. On the oil side, the news has been dominated by pipelines and oil sands, while reports on the gas side have focused on pricing.
This dichotomy has created a certain degree of instability as producers try to determine if the situation is transitory or if a permanent shift has occurred in the North American gas market. Meanwhile, spending has surged this year even as it has moved increasingly to oil, and the continued strength of the Canadian dollar vs. the American greenback has dampened revenues from exports. On top of that, add in the usual mix of economic issues, political posturing and unpredictable international factors, and 2011 could turn out to be one of the better years on record. But it also has the potential to become one of the most challenging years the Canadian industry has ever faced.
Government involvement. Most recently on the political side, provincial energy ministers met in Alberta in July, emerging from a one-day meeting with at least a partial consensus to pursue diversification of target energy markets for the country’s enormous oil and gas resources. Analysts have echoed that sentiment recently, stating outright that more energy customers are needed for Canada to take full advantage of high oil prices. Meanwhile, work continues among Canada’s western provinces (British Columbia, Alberta and Saskatchewan) to better align their provincial regulatory frameworks.
But perhaps the most significant development politically was the majority election victory scored by Prime Minister Stephen Harper’s Conservative party in early May, providing some of the political stability that has been long-desired by the business community at the federal level.
There have also been increasing calls from industry, oil and gas analysts and politicians to craft some sort of national energy strategy. However, the shape of that strategy differs among the various parties. Some believe enhancing Canada’s competitiveness internationally is key, while others advocate a more streamlined and seamless regulatory regime within Canadian borders.
On the publicity front, as the industry and the Alberta government have pushed back against negative, often misleading, information from environmental groups about oil sands extraction, activists have shifted their attention to the pipelines used to ship the upgraded crude from Alberta—in particular, TransCanada’s proposed 1,700-mile Keystone XL project (which would ship crude from Alberta to the south-central US) and Enbridge’s proposed Northern Gateway project (which would transport crude oil from Alberta to the West Coast and imported diluent back to Alberta). Both projects face opposition from a wide variety of opponents.
Mergers and acquisitions. Notwithstanding the cautionary notes, spending is up and it is driving all sorts of activity, including M&A, drilling and land sales. Daily Oil Bulletin records from earlier this year projected a spending increase of 21% in 2011 to C$54.1 billion, but a spate of recently announced increases in capex budgets could push that number much higher. Globally, Barclays Capital is projecting that spending in 2011 will top the US$500 billion mark for the first time.
On the M&A front, early forecasts predicted increased activity. Through the first-half, there have been several significant announcements, but the largest deal was the one that got away. In February, Encana announced it had sold a 50% stake in its Cutbank Ridge gas prospect, which crosses the British Columbia/Alberta border, to PetroChina for C$5.4 billion. But in June, the deal fell through.
On the oil sands front, China National Offshore Oil Corp. in July offered US$2.1 billion for Opti Canada, which recently filed for creditor protection. Opti is partnered with Nexen on the Long Lake steam-assisted gravity drainage (SAGD) project. In June, Malaysia’s national oil company, Petronas, picked up 50% of Progress Energy Resources’ British Columbia Montney shale gas prospects for C$1.1 billion.
Meanwhile, Shell intends to sell off its portion of the McKenzie gas project, including the 950-Bcf Niglintak field and the company’s stake in the associated C$7 billion pipeline.
Production. Canadian producers reversed the downward trend in reserves additions in 2010, particularly on the gas side. Even with a reduction of almost 600 Bcf due to economic factors, producers replaced 116% of production, according to the Daily Oil Bulletin, achieving the best level since 2005. On the liquids side (not including oil sands), positive revisions, improved recovery bookings, and proved reserve additions bolstered overall reserves by more than 200 million bbl. Oil sands reserves remain around 169 billion bbl, according to Alberta’s energy regulator.
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| Fig. 1. Historical drilling activity in Western Canada. |
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As activity has increased, costs have also risen. The Canadian Energy Research Institute (CERI) estimates that although capital costs have declined 3.6%, operating costs have increased 5.8%. CERI also forecasts that more than C$2 trillion of investment in new oil sands projects will occur by 2035.
Of the individual oil sands projects, the one capturing the most attention this year has been Imperial Oil’s Kearl mine, the initial phase of which is now estimated to cost C$10.9 billion, with a total cost of $23 billion and ultimate expected production of 345,000 bpd. The company has faced problems in its efforts to ship 33 modules destined for the Kearl project from South Korea to Alberta. The government of Missoula County, Montana, and a number of environmental groups have succeeded in having shipment of a portion of the modules blocked. Nonetheless, the company remains confident that the current delays will not significantly affect Kearl’s work schedules. Imperial says it will continue to seek the needed permits from the governments of Montana and Idaho.
Land sales and drilling. Just as land sales signaled that last year’s burgeoning turnaround was for real, the continued strength of land sale revenues collected by Canadian governments in 2011 augurs well for the remainder of this year and further into the future. Leases and licenses acquired in these sales form the basis for future drilling plans and are viewed as an indicator of future activity.
Through the first six months, land sales brought in C$2.1 billion, the third-highest six-month total on record and an 18.8% increase over the $1.73 billion brought in at the halfway point last year. The highest six-month total was in 2006, when governments took in $2.7 billion.
Alberta once again led the way, taking in 87% of the total amount, or $1.86 billion, including a sale in June that brought in a record $843 million. Shale gas and conventional oil prospects were cited as the twin forces behind the record sale.
British Columbia did not fare as well, as land sale revenues plummeted almost 90%, to $66.4 million, versus the $609 million collected in first-half 2010. It would appear that the prolonged slump in gas prices has caught up to the province and its predominantly gas-prone reserves. Saskatchewan also saw its revenue dip, to $193 million, down 30% from $276 million during the first half of last year.
Drilling numbers are also looking up at the halfway point of 2011. A total of 6,884 wells were drilled, up 28% from the 5,367 wells drilled through the first six months of 2010. Of the 2011 wells, 3,988 were drilled for oil, 58% of the total.
In response to the increase, the Canadian Association of Oilwell Drilling Contractors has revised its 2011 Western Canadian forecast upward to 13,128 wells drilled, vs. its previous forecast of 11,811. The Petroleum Services Association of Canada has made a more modest revision (Fig. 1), predicting 12,950 wells drilled this year, up just 700 from the forecast made late in 2010.
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| Fig. 2. Historical Mexican crude oil production and proved reserves replacement rate. |
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MEXICO
During 2010, Mexican national oil company Pemex reviewed its main E&P objectives, setting new goals to increase reserves, stabilize oil and gas production levels and improve the use of gas. The exploration strategy is mainly aimed at increasing crude oil reserves in shallow waters and onshore; enlarging the portfolio of exploratory opportunities in non-associated gas fields; improving the probability of commercial success in deepwater projects; and accelerating delineation activities to increase reserves. Meanwhile, the production strategy is focused on updating exploitation schemes for development and mature fields; increasing the efficiency of development in complex projects like the onshore Chicontepec field; reactivating marginal, abandoned and soon-to-be-abandoned fields; and speeding the development of recently discovered fields.
Pemex investment grew 9.7% in 2010 to $20.4 billion, of which 90% was channelized into E&P. The main projects, which accounted 72.4% of total E&P investment, were Cantarell, Ku-Maloop-Zaap (KMZ), the Strategic Gas Program, the Burgos gas field and the Tertiary Gulf area (Chicontepec). Exploration investment exceeded $2 billion for the third consecutive year. During 2011, Pemex expects to invest about $22 billion and to increase the resources in KMZ and the Strategic Gas Program while reducing investment in Burgos and Chicontepec.
Exploration and drilling. Unlike in previous years, in 2010 Pemex strengthened its exploration program by including subsoil seismic studies and incorporating wide-azimuth 3D seismic in the Gulf of Mexico. Last year, the company acquired 24,778 sq km of 3D seismic, of which 68% was in the deepwater Tamil and Yoka Butub areas, in the southwest, and Centauro area, in the north. The rest was mainly carried out in new prospects in Burgos and the Southeast basin. 2D seismic studies were drastically reduced, with only 2,356 sq km acquired, mainly in Burgos and the Sabinas and Veracruz basins, vs. 18,287 sq km in 2009. However, during the first quarter of 2011, the rates of 2D and 3D seismic acquisition have increased by 69.5% and 45%, basically in the same areas studied last year.
During the first five months of this year, the total number of wells drilled by Pemex was about 360, just 36% of the 994 wells drilled during 2010, pointing to a likely decrease in activity for the year. However, an increased portion of Mexican drilling was for exploration. The 39 exploratory wells completed in 2010 marked the lowest number since 2001. In contrast, from January through May of this year, 18 exploratory wells were completed, three more than in the same period of 2010. In the last two years, about 55% of drilling has been concentrated in northern non-associated gas fields, especially Burgos. Most of the remainder has been in the Southeast basin, which mainly contains oil and associated gas. In deep water, two exploratory wells were completed last year: Labay-1 and Lackach-2DL. Both are non-associated gas producers.
Development drilling has increased over the last several years, from 610 in 2007 to 1,264 last year. However, in the first five months of 2011 this activity has been down, with 384 wells drilled vs. 613 in the same period of last year. The percentage of successful development wells completed reached 95.3% in 2010, the highest level since 1992.
The number of recognized fields increased by 11 last year to 405, which contained 7,476 operating wells (4,390 producing oil and associated gas, and 3,086 non-associated gas). Furthermore, Pemex reported 233 offshore platforms and 192 injection wells.
As of Jan. 1, proved oil and gas reserves stood at 13.8 billion boe. Based on the results of exploratory and development activities, Pemex achieved a proved reserves replacement rate of 85.8%, the highest since the adoption of the criteria defined by the US Securities and Exchange Commission in the late 1990s, but still below the 100% that has been set as goal for 2012. Offshore areas, primarily Cantarell and KMZ, hold 60% of these reserves, of which 74% is crude oil, 9% is condensate and plant liquids, and the remaining 17% is dry gas. The reserves-to-production ratio declined again in 2010 to 10 years from 10.2 years in 2009.
Production. Crude oil production has declined since 2004, reaching 2.6 million bpd during the first half of 2011, Fig. 2. Cantarell maintained its reduction trend, but this performance was offset by increases in Maloop and Sihil fields as well as other fields in the south. In Chicontepec, crude oil production continues to be far below Pemex’s objectives.
Last year, gas production was 0.2% less than in 2009 at 6.3 Bcfd (excluding 683 MMcfd of nitrogen), halting the growth trend seen since 2002. In the first half of 2011, the rate fell further, to 6.0 Bcfd. This decline is driven by decreased non-associated gas production, especially from Burgos, while associated gas production continues to grow, driven by additions from the Litoral Tabasco and Samaria-Luna assets.
Based on the large number of wells in operation and low output, Mexico’s per-well productivity in 2010 reached its lowest level since the early 1980s, at 507,000 boepd. Pemex doesn’t expect additional declines in oil production until at least 2015, supported by activity in Cantarell, KMZ and some southern fields. In particular, there is great hope for increases in the recovery factor in mature fields through the recently introduced E&P integrated contracts, which offer cash compensation to contractors. The first round in three southern areas, Santuario, Carrizo and Magallanes, will be completed in the third quarter of the year, and the second round will begin before the end of the year. The objective is to contract at least 20 areas by the end 2012. Pemex is considering extending the integrated-contracts model to Chicontepec and deepwater fields.
Politics. Despite President Felipe Calderón’s announcement that he will send Congress additional oil industry reforms in September, the political environment is unlikely to permit such reforms. The presidential campaign process has begun, and no party will want to pay the political cost of major reforms, especially not the Institutional Revolutionary Party (PRI), which is widely expected regain the presidency. Also, the reforms adopted in 2008 have not been fully implemented, and those that were implemented have not yielded sufficient results to support a drive for further reforms. 
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