February 2018
Special Focus

Healthy boost in activity projected for international drilling communities

Outside of the U.S., a global recovery is on the horizon for the upstream oil and gas industry.
Craig Fleming / World Oil Emily Querubin / World Oil

The year 2017 was lackluster for the international upstream community, but there’s reason to believe that 2018 will be an improvement. Brent crude prices have trended between $60 and $70/bbl in the past month, up from about $53/bbl a year ago. If oil prices stay above $60, increased E&P development should follow worldwide. Still, during the years of the downturn, operators have scrapped many high-cost activities to focus on the most economically-developable basins, and have improved long-term projects by standardizing and simplifying operations. Thus, as companies begin to allocate more capital to upstream activities, the industry’s recovery will continue on a subdued incline.  

World Oil forecasts a 4.5% annual increase in international drilling activity, from 41,598 wells drilled in 2017 to 43,476 wells in 2018, Table 1. With the exclusion of the U.S., North America is the only major continent with a probable decline, down 2.6%, due to slightly lower activity in Canada. Otherwise, gains are expected across every major basin. In spite of the steep decline in offshore drilling, some deepwater plays are still economically attractive. Companies are now exploring for high-quality formations with natural porosity and permeability at relatively shallow depths, or exceptional reservoirs at unexceptional depths. This year, World Oil is expecting operators to spud about 2,375 offshore well an increase of roughly 9.4%, Table 2. Reflecting the effects of OPEC’s quota deal with Russia, global oil production remained nearly flat last year, at 80.84 MMbpd, Table 3. 


Canada. The Canadian Association of Oilwell Drilling Contractors predicts drilling will edge higher 1.8%, to 6,138 wells, compared to 6,031 in 2017. World Oil forecasts 7,000 wells in 2018, a drop of 2.8% compared to the 7,200 drilled in 2017. In any case, the biggest hurdles in Canada are the lack of market access and regulatory stability, with three major infrastructure projects cancelled or delayed in the past six months. The lack of key energy infrastructure sends a message to potential investors that Canada’s rules and regulations around these projects are subject to continuous change. While the drilling and service rig market may have bottomed out, meaningful upward movement of day rates remains a struggle. For more information on Canada, see the article on page 51.

Mexico. The Mexican government’s initiative to bolster its sagging production, by amending its constitution to allow private companies to lease drilling rights, is starting to pay dividends. Wildcat discoveries in Zama and Ixachi, combined with smaller finds, added approximately 1 Bboe of recoverable reserves in 2017. The giant Zama discovery by Talos Energy, in only 546 ft of water, was the first offshore exploration well drilled by a private company in Mexico’s history. After the initial discovery, the Zama-1 well was drilled to 13,478 ft to test a deeper target. However, no additional hydrocarbons were found. An appraisal program is expected to begin in second-half 2018. We expect drilling nationwide to increase 12% to 84 wells. In 2016, operators drilled 149 wells. 


Regional drilling activity is improving, with seven major countries projected to increase activity. During 2017, drilling in South American countries declined, with wells down 5.2%, at 2,347. This year, a moderate rebound to 2,390 wells is forecast. Meanwhile, regional oil output fell 2.9% last year, to 6.93 MMbpd.

Brazil. After reaching a record in 2016, Brazil’s overall production rate (oil and gas, combined) is now on track to surpass that of Norway. Accordingly, World Oil forecasts that the number of wells drilled will increase from 198 to 223 in 2018, demonstrating a 12.6% jump. The country’s pre-salt layer continues to garner the attention of E&P companies, worldwide. Brazil held its third production sharing bidding round in 2017, drawing bids from majors, including Shell, Statoil and ExxonMobil, for four blocks in the Santos and Campos basins. In November, the Libra field consortium announced that the field had gone onstream in the Santos basin. The first large-scale development phase of the project, involving an FPSO unit with a production capacity of 150,000 bopd and 17 wells, was launched soon thereafter. According to Total (20%), the next step will be to bring Mero field onstream in 2021. The field, in the northwestern portion of the Libra block, is said to hold an estimated 3.3 Bbbl of oil.

Guyana’s deepwater sector is gaining traction after ExxonMobil announced its sixth oil discovery early this month. The sizeable finds have been concentrated in the Stabroek Block, which is spread out over about 6.6 million offshore acres. The recent discoveries have put the country on the oil market map, as it has not been an active producer until now. Analysts have reported that roughly 350,000 to 400,000 bopd are anticipated by 2026. At this rate, Guyana is on track to become one of the top oil producers in Latin America.

Argentina’s largely undeveloped Vaca Muerta shale, which is said to hold approximately 16 Bbbl of oil and 308 Tcf of technically recoverable gas, is still straining to get the fiscal commitment necessary to begin full-scale development. Thus far, high well costs and logistical constraints have prevented pilot projects from reaching the development phase. In addition to the Vaca Muerta, the EIA’s 2015 assessment shows that the country’s untested unconventional prospects could hold a cumulative 801.5 Tcf of technically recoverable wet gas and 27 Bbbl of tight oil. In August, GeoPark (50%) and Wintershall (50%) reported the discovery of a new oil field in the CN-V block of the Neuquen basin, in Argentina’s Mendoza Province, where a significant percentage of the country’s oil is produced.  


Despite gains made in 2016, regional oil output slipped 0.8%, to average 2.91 MMbpd. Drilling was off 7.2%, to 386 wells, including 315 offshore. This year, drilling is forecast to improve 7.5%, to 456 wells, of which 357 will be offshore.

Fig. 1. Statoil’s Gina Krog, offshore Norway. Photo: Statoil.
Fig. 1. Statoil’s Gina Krog, offshore Norway. Photo: Statoil.

Norway. Gas production on the Norwegian Continental Shelf reached a record high in 2017, Fig. 1. Although crude production was down slightly, overall output was up for the fourth straight year. According to the Norwegian Petroleum Directorate, five new fields went onstream on the Norwegian shelf in 2017. In 2018, the NPD expects investments to be approximately NOK 122 billion, about the same level as last year. In 2019, investments are expected to rise to just under NOK 140 billion. Plans for development were submitted for ten new projects, while nine are undergoing development. In 2017, 34 exploration wells were completed, three fewer than the previous year. Half of the wells were drilled in the Barents Sea, 12 in the North Sea and five in the Norwegian Sea. Eleven discoveries were made, compared with 18 in 2016. WO predicts Norwegian drilling will be up 2.4%, to 210 wells. 

United Kingdom. In Sept. 2017, the UK’s Oil and Gas Authority reported that the economic recovery of the country’s offshore oil and gas sector was making progress. According to the OGA, offshore exploratory drilling in 2017, through September, tallied 21 wells, just one less than in 2016. Offshore development wells totaled 63 in 2017, 24 less than in 2016, but 50% less than in 2014 (126). Despite the dramatic reduction in offshore activity, the OGA conducted its 30th Offshore Licensing Round, offering 820 blocks for bidding. World Oil predicts British drilling should improve 7.3%, to 103 total wells. 


Due to the fact that Russian operators (particularly Rosneft) again boosted their drilling, regional wells drilled were up a rousing 11.3% in 2017, at 10,186. This year, operators will again push activity upward, with a healthy 6.9% increase to 10,889 wells. With Russian producers pushing the limits of their capacities, oil production across the area rose another 1.5%, to 14.02 MMbpd. 

Russia. An average $34.1 billion per year will be expended on 1,673 oil and gas fields in Russia between 2018 and 2020, according to GlobalData. Spending on traditional Russian oil projects will add up to $55 billion over the three-year period, while heavy oil fields will require $7.1 billion over the same time period. Onshore projects will be responsible for over 85% of the $102.6 billion of upstream capital expenditure, or $88 billion by 2020. Russian shallow-water projects will require $14.6 billion over the timespan. Russia’s natural gas production rose to its highest level ever last year, driven by increasing sales to Europe and rising domestic demand. Government data showed that output jumped 7.9% to beat a 2011 record. With plans to expand into China and new LNG plants, Russia may close the gap on the U.S., which surpassed Russia to claim the top spot in global natural gas production nine years ago. Russian crude output hovered around 10.97 MMbpd during 2017 and averaged 10.88 MMbpd in 2016.

Azerbaijan. In 2017, SOCAR completed 66 new wells that went into operation after wellbore construction, with most in Bulla-Daniz, Garadagh and Seadan fields. A production-sharing agreement for the Azeri-Chirag-Gunashli fields (Caspian Sea) was signed in September 2017 by SOCAR and operator BP. The PSA will now be in force through 2049. The large offshore complex has eight platforms, six for production and two for processing natural gas. Production at ACG averaged 585,000 boed during the first half of 2017. Up to $40 billion could be invested to further develop ACG over the next
30 years. 

Kazakhstan officials are talking to a major oil company in an attempt to increase output at Kashagan field. The Kashagan development, which cost $55 billion, is expected to produce 260,000 bopd in 2018. Output from other fields in the region will be lowered to keep the country from exceeding its OPEC production limit. The field was put into operation in 2013, but production was suspended because of gas leaks in the 200-km pipeline, caused by high-sulfur content. It took three years and cost $2 billion to repair the micro-cracks. Production resumed in late 2016. 


As drilling fell 2.2% in 2017 to a seven-year low, E&P activity remained at a relatively low ebb throughout Africa. However, some countries did rebound moderately from severely low drilling levels in 2016. This year, activity will rise 6.3% to 833 wells. Somewhat counterintuitive, regional oil production rose 3.9%, to 7.76 MMbopd.

Nigeria. As it endures continued militant attacks, protests and underinvestment, Nigeria continues to struggle after a dramatic drop in production back in 2016. Despite its troubles, the Nigerian government set a new production target of 2.5 MMbopd last year, and hopes to reach it by 2020. Because of the recent push to boost production, World Oil anticipates the well count in Nigeria will climb from 76 to 85, representing an 11.8% increase in 2018. In August, Shell started production at Gbaran-Ubie Phase 2, a key project in the Niger Delta region, where the lion’s share of Nigeria’s oil is produced. According to Shell, peak production of approximately 175,000 boed is anticipated for 2019.

Angola was hit hard by the slump in oil prices, as it relies on its crude shipments for most of its export revenue. Early last year, however, Eni started producing through the Armada Olombendo FPSO vessel on the East Hub Development Project, in the deep waters of Block 15/06. Production was added to that of the existing West Hub Project in Sangos, Cinguvu and Mpungi fields, which started producing back in January 2016. Accordingly, the block was expected to hit peak production of about 150,000 bopd last year. Likewise, Chevron started producing from the main production facility of the Mafumeira Sul Project, in Block 0. The facility, which is about 15 mi off the coast of Cabinda Province, has a capacity of approximately 150,000 bpd of liquids and 350 MMcfgd. According to Chevron, ramp-up to full production is expected to continue throughout this year. With numerous start-ups of key projects, Angola will likely see an increase in drilling during 2018. World Oil has forecast a 15.9% boost, from 44 wells in 2017 to 51 this year.

Libya continues to withstand a copious amount of disruption to its energy sector in recent years, and was exempt from OPEC’s deal to cut back production last year. Consequently, the nation’s output climbed to 1 MMbpd by year-end 2017, after it had dropped to a low of about 550,000 bpd in April. Its present production level is the highest it has seen in about four years, but still not the 1.25-MMbpd mark that its National Oil Corp. was aiming for. It has been reported that Sharara, the country’s largest field, is now holding a steady output of approximately 290,000 bpd.

Kenya. Rapidly emerging as one of Africa’s chief oil provinces, Kenya has seen numerous discoveries of late. Following Tullow Oil’s successful E&P year in 2016, Africa Oil Corp. concluded its 2017 exploration and appraisal drilling campaign in November, reporting two more new discoveries. The Erut-1 well proved that oil has migrated to the northern limit of the South Lokichar basin, a Cenozoic sedimentary basin within the East African Rift. Correspondingly, the Emekuya-1 well encountered significant oil sands in the Greater Etom structure, further de-risking the northern part of the basin.

In Mozambique, Area 4 partners secured project financing for the Coral South FLNG project in December. The project, situated in the Rovuma basin and operated by Eni, will see the development of gas resources in the southern part of the Coral gas reservoir. The FLNG facility will be constructed with six subsea wells and a liquefaction capacity of approximately 5 Bcm. Similarly, Anadarko Petroleum received the government go-ahead needed for the design and construction of marine facilities for its two-train LNG project in northern Mozambique. The company is developing the country’s first onshore LNG plant made up of two initial LNG trains, with a capacity of 12 MMtpa, which will support Golfinho/Atum field in Offshore Area 1.

Ghana. Approximately 37 mi off the western coast of Ghana, Eni started production from the Offshore Cape Three Points Block last year. It was a major achievement, as the project was brought onstream in just two-and-a-half years. The development contains three fields, which hold 500 MMbbl of oil and 40 Bcm of non-associated gas. The John Agyekum Kufuor FPSO unit is producing up to 85,000 boed through 18 underwater wells.


A consistent source for upstream work during the downturn has been in the Middle East, even though there was a loss of 9.5% last year, to 3,005 wells. For 2018, we forecast a 2.9% uptick, yielding a 3,091-well total. Due to OPEC’s production quota agreement with Russia, regional oil output declined 1.3%, to 26.98 MMbpd. That performance may or may not be repeated this year, given renewal of the production quota agreement in December.

Saudi Arabia and Russia unexpectedly joined forces in late 2016 to counter the booming U.S. shale plays. But before the new Saudi oil minister Khalid Al-Falih could rein in production, the Kingdom’s output reached an all-time high of 10.72 MMbopd in November 2016. In accordance with the OPEC agreement, Saudi Arabia reduced its crude output 6.9% to 9.978 MMbpd. During 2017, drilling in the Kingdom has remained resilient with about 100 rigs working onshore, with another 19 posted at offshore locations. Saudi Arabia is seeking to sell as much as 5% of Aramco in a public offering to establish a sovereign wealth fund and reduce the economy’s reliance on hydrocarbons. We expect drilling activity to increase 1%, to 599 wells. 

Iraq’s oil production was 36% higher in 2017 compared to 2014, according to an Iraqi cabinet official. Associated gas production increased 50%, and the country has exported more than 2.3 MMbbl of condensate and 40 tons of LNG. The country has been reluctant to cut production, citing its terrorism-battered economy, but pledged to reduce output starting January 2017 in accordance with the OPEC deal. In March, Iraq’s petroleum exporting company, SOMO, said the country had reduced crude flow by 300,000 bpd to 4.46 MMbpd. In the last quarter of 2017, Iraq averaged 4.41 MMbopd according to the IEA.  

Iran. Now that Iran is no longer under sanctions, the country’s E&P community has joined forces to share knowledge and encourage outside investments. It is the first time in the history of Iran’s petroleum industry that Iranian companies are cleared for E&P activities. A gathering in Tehran examined methods of financing for implementing oil projects and reducing risk. Leaders want to launch an investment fund to provide capital. Development is underway in Azar field, which started producing crude in March 2017 at an initial rate of 15,000 bopd. The country is OPEC’s third largest producer, at 4.2 MMbopd. 

Fig. 2. Drillship in Zohr field, offshore Egypt. Photo: BP.
Fig. 2. Drillship in Zohr field, offshore Egypt. Photo: BP.

Eastern Mediterranean. Egypt’s Nooros and Zohr mega-fields reportedly will double the country’s natural gas output by 2020, Fig. 2. In 2018, the country is on track to end natural gas imports and become a completely self-reliant producer. During 2017, Egypt’s production increased to 5.1 Bcfd, from about 4.4 Bcfd the year prior. Production at Nooros field hit record levels early in the year. Eni reported that the field’s seven operating wells were producing 170,000 boed. In December, Eni’s giant Zohr field was brought onstream less than two-and-a-half years after discovery. The field has reserves of 30 Tcf of gas-in-place. According to Eni, 20 wells are expected to be drilled at Zohr by the end of 2019. BP has actively explored the region in recent years and the company’s West Nile Delta offshore development has been a key contributor to continued growth of Egyptian E&P. According to BP, production from all five fields is expected to reach up to 1.3 Bcfd.  

While activity continues in Israel’s Tamar and Leviathan natural gas fields, development of Karish and Tanin fields is quickly becoming a focal point. After acquiring the fields in 2016, Energean Oil & Gas plans to develop the fields, which are estimated to hold 2.4 Tcf, plus 33 MMbbl of hydrocarbons liquids. Development of Tanin includes six wells, which will be connected to the same FPSO that hosts Karish production. First gas is expected in 2020. In December, Energean was awarded five additional exploration licenses in the area. The company now holds 13 exploration licenses. In June, Zion Oil & Gas spud the Megiddo-Jezreel #1 (onshore) to evaluate four different geologic strata with hydrocarbon potential. In September, Zion announced the discovery of hydrocarbon-bearing zones above 9,000 ft. At Leviathan, Noble Energy’s initial development will involve four subsea wells, each capable of flowing more than 300 MMcfd. The field, is estimated to contain 22 Tcf of gross recoverable resources and is expected to produce first gas by the end of 2019. 

In Turkey, Condor Petroleum said that its Poyraz West 2 appraisal encountered 465 ft of net pay, of which 197 ft are in a newly discovered reservoir. After drilling five wells and completing a processing facility and pipeline system, Condor announced first gas in December. 


China accounts for about 88% of all regional drilling, and last year was no exception. Overall, the region saw 17,357 wells drilled, up 11.3% from 2016’s level. In 2018, we project a 6.6% increase for the region, with operators drilling nearly 18,500 new wells Precipitated mainly by a reduction in Chinese output, the area’s oil production declined 3.1%, to 6.52 MMbpd. Output was down in most major countries, except for India and Pakistan.  

China began 2018 with the opening of its second Sino-Russian oil pipeline. The second line runs parallel to the first, spanning about 585 mi between Mohe and Daqing. Now, with the ability to import about 600,000 bpd (double its previous amount) from Russia, the countries have seemingly solidified a firm energy cooperation. Already the world’s largest energy user, China’s LNG imports soared to a record amid peak winter demand in November. The spike in demand is a direct result of President Xi Jinping’s effort to reduce smog, and transition the country from coal to gas. In 2018, the number of wells drilled is expected to rise to 16,388, up from 15,315 in 2017. This represents a 7% increase. CNOOC announced in November that production had begun at the Weizhou 12-2 phase II project in the Beibu Gulf, in the South China Sea. Seven wells produce about 6,400 bpd. It is expected to reach peak production of approximately 11,800 bpd this year.

Indonesia. In pursuit of a comeback after a recent decline in energy investments, Indonesia saw some E&P progress last year. In August, CNOOC reported first gas at BD field in the Madura Strait, offshore East Java. At that time, the company said two of four wells were producing and peak production of 25,500 boed was anticipated for this year. The production facilities also include an unmanned wellhead platform and an FPSO. The country suffered a blow in July, however, when ExxonMobil withdrew from the East Natuna project. The giant gas field, on the southern edge of the South China Sea, will likely see further delay in development. With 46 Tcf of recoverable gas resources, the field holds some of the world’s largest untapped gas reserves.

Malaysia. International Petroleum Corp. recently began drilling the first two infill wells planned for Bertam field, 108 mi offshore Peninsular Malaysia. Bertam field includes an unmanned wellhead platform and 12 horizontal wells, which produce to a moored FPSO. As of year-end 2016, the field has net 2P reserves of 9.5 MMboe remaining. According to IPC, the infill wells are targeting gross resources of about 2.3 MMboe. The drilling is scheduled to conclude by the end of February 2018. 


This region has been particularly sensitive to oil prices, and its activity took a significant hit in 2016. New Zealand and Papua New Guinea remain very minor players, with Australia taking the lead role in the area. Drilling rebounded during 2017, and wells across the region totaled 200, up 64%. This year, a reasonable 8% gain to 216 wells is predicted. Meanwhile, regional oil production lost more ground, declining 8.1% to 412,200 bpd. Every country lost ground, with East Timor experiencing the largest percentage drop.

Fig. 3. Chevron’s Wheatstone facility, offshore Australia. Photo: Chevron.
Fig. 3. Chevron’s Wheatstone facility, offshore Australia. Photo: Chevron.

Australia’s energy sector has seen significant progress of late, with the start-up of two major projects. In October, Chevron reported that LNG production had begun at the Wheatstone Project in Australia’s western Pilbara region, about 7.4 mi west of Onslow, Fig. 3. It is the country’s first natural gas hub. The project consists of two LNG trains, with a combined capacity of 8.9 million metric tons per annum, and a domestic gas plant. It processes natural gas from Chevron’s Wheatstone and Iago fields. 

In August, BP announced the start-up of the Persephone project, off of Australia’s western coast. As part of the North West Shelf Project, the development is made up of two subsea wells, which are tied back to the existing North Rankin complex. According to BP, the project’s peak production is expected to reach approximately 48 MMscfd, net. Exploration activity continues to progress, as well. Companies that have reported discoveries in Australia within the last year include Beach Energy and Northwest Energy. wo-box_blue.gif

About the Authors
Craig Fleming
World Oil
Craig Fleming Craig.Fleming@WorldOil.com
Emily Querubin
World Oil
Emily Querubin Emily.Querubin@worldoil.com
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