The Philippines – Paving the way forward in the South China Sea

The Philippines – Paving the way forward in the South China Sea

China and the Philippines are reportedly on the cusp of reaching an historic agreement that is expected to re-open the hotly disputed and prospective South China Sea region for oil and gas exploration.

The South China Sea, covering approximately 3.5 million sq km, has always been an area of international focus due to its strategic importance. One source, the United Nations Conference on Trade and Development (UNCTAD), has estimated that shipping contributes to roughly 80% of global trade by volume and 70% by value, a significant portion of which (approximately 60% in volume) is estimated to pass through Asia with the South China Sea accounting for one-third of the global total. Besides being the main maritime crossroad for countries like China, India, Brazil, Japan and the UK (ChinaPower, 2017), it has been touted to also contain potentially substantial oil and gas resources beneath its seabed with the U.S. Energy Information Administration (EIA) estimating the region to contain up to 11 Bbo and 190 Tcfg of potential resources (EIA, 2013). The topic of potential resource volumes in the South China Sea is the subject of heated debate and will not be examined in this blog due to space restrictions. An internet search will amply illustrate this point.

In a submission to the United Nations (UN) on 7 May 2009, China declared that it had “indisputable sovereignty over the islands in the South China Sea and the adjacent waters and enjoys sovereign rights and jurisdictions over the relevant waters as well as the seabed and subsoil thereof. The above position is consistently held by the Chinese Government and is widely known by the international community.” This claim by China is represented by the infamous “nine-dash-line” as illustrated in image 1 where it is superimposed with the currently active blocks in the region. The countries affected by China’s claim comprise the Philippines, Malaysia, Brunei, Indonesia and Vietnam.

 

 

China’s nine-dash-line claim in the South China Sea.

China’s nine-dash-line claim in the South China Sea.

China and the Philippines have already been embroiled in a lengthy maritime stand-off. In January 2013, the Philippines formally initiated arbitration proceedings against China’s claim, which it said is unlawful under the United Nations Convention on the Law of the Sea (UNCLOS), following escalating tensions due to mutual accusations of intrusions into the Scarborough Shoal area in early 2012 (BBC, 2016). On 12 July 2016, the Permanent Court of Arbitration in The Hague ruled in favour of the Philippines against China with regard to the latter’s claim to rights over the waters of the South China Sea and associated resources. The ruling, announced by an arbitration tribunal under UNCLOS, declared that there was no evidence that China had previously exercised control over the South China Sea. The tribunal also ruled that China had violated the sovereign rights of the Philippines and had caused “severe harm to the coral reef environment” with the construction of man-made islands. Although the ruling is binding, the Permanent Court of Arbitration does not have any powers of enforcement. The ruling was welcomed by the Philippines but China firmly rejected the outcome of the arbitration saying that its territorial rights over the sea would not be affected by the ruling in any way and that its armed forces will continue to defend its maritime interests and sovereignty in the area. (The South China Sea Arbitration – The Republic of the Philippines v. The People’s Republic of China, 2016)

In more recent times, the Philippines seems to have reconsidered its stance with regard to China’s claim. On 9 April 2018, it was reported that both countries had indicated that a potential deal for joint development in the disputed areas could be reached as early as 3Q-4Q 2018. Both governments initiated negotiations to ensure fair terms with regard to exploring for oil and gas in the area. Previously, on 14 February 2018, it was reported that the Philippines and China had set up a special panel to establish how joint exploration and development of oil and gas in their disputed zone could proceed without having to address the explosive issue of sovereignty. Leaders from both sides gathered for the second time under a bilateral mechanism aimed at resolving sovereignty disputes. As a result of the meeting, it was reported on 2 March 2018 that the Philippines and China have earmarked two areas where joint exploration may be considered. These comprise the 7,115.5 sq km North West Palawan Basin SC 57 and the hotly contested 8,823.5 sq km Recto Bank Basin SC 72 (Recto Bank being the renamed former Reed Bank). SC 57 is operated by CNOOC International with partners PNOC Exploration Corp and Jadestone Energy. On 2 March 2015, the Department of Energy of the Philippines had enforced Force Majeure in SC 72 suspending all exploration activity in the block effective 15 December 2014. Forum (GSEC 101) Ltd had previously cancelled plans to acquire a planned survey of the sea floor to determine possible well locations due to prior encounters with Chinese naval vessels. Forum is the operator of SC 72 with partner Monte Oro Resources & Energy Inc.

SC 57 and SC 72 within the nine-dash-line claim

SC 57 and SC 72 within the nine-dash-line claim

Although this is a step in the right direction, analysts claim that resolving future disputes, if they arise, may be extremely complex if sovereignty in the region is not first addressed. Nonetheless, this is an exciting and positive new development in the ongoing saga of the South China Sea with the potential for a precedent to be set in dealing with future disputes with China.

Salta Province offers opportunities in 12 bid-blocks

Salta Province offers opportunities in 12 bid-blocks

Argentina’s Salta Province government presented to the Houston oil & gas community the Salta Province Bid Round 2018 offering 12 blocks for exploration and eventual development. An additional three blocks will also be tendered later this year.  A small group attended the event but among the companies were majors ExxonMobil and Chevron. Neither company has been involved in the area before signaling that Salta could become a hot area for exploration in South America. The offered areas to be included in the current launch are: 9790 sq km Algarrobal, 7,676 sq km Guayacan, 184 sq km Ipaguazu, 1,766 sq km Las Canitas, , 9,810 sq km Ojo de Agua, 4,052 sq km Pichanal, 1,176 sq km Pocoy, 7,232 sq km San Ignacio, 381 sq km San Telmo, 6,444 sq km Santa Rosa, 8,546 sq km Tolar Grande and 245 sq km Yariguarenda. The areas to be offered in July are 2,884 sq km San Carlos, 6.3 sq km Cuchuma and 2 sq km Lumbrera.

Salta bid blocks and licensed acreage

Salta bid blocks and licensed acreage

With more than 80 years of oil and gas activity, the northwestern province of Salta was for decades the second highest producer in Argentina but natural reservoir declines from long-term production and also low natural gas prices the absence of wellhead gas pricing policies have slowly led to Salta losing its position.

 

A recent analysis of daily production shows Salta production at about 5,000 bo/d and 233 MMcg/d from 65 wells. Total proven reserves were published in 2016 as 28.21 MMbo and 714.51 Bcfg. The main producing prospects and horizons in Salta are the Silurian-Devonian Huamampampa, Icla and Santa Rosa formations as well as interesting future possible shale prospects for the Los Monos Formation, seen previously as a source rock but where interesting results have been recorded on the Yacuy 1001 and Ramos 1004 wells. The San Telmo, Las Penas, Tarija, Tupambi and Cretaceous Yacoraite formations are among the recognized productive horizons and targets in the province and Paleozoic prospects are deep but hold high productive potential for both oil and natural gas. The top four producing fields in the province are Ramos, Acambuco, Aguarague and San Antonio Sur.

Icla fm type production curve

Yacoraite fm type curve

Since 2015 the provincial government has started an initiative to improve conditions for exploration and production in Salta.  A new law was invoked for a special promotional regime to stimulate investments, including tax exemptions on equipment acquisition and possible reductions in royalties, especially for high risk projects were addressed by the law. Provincial hydrocarbon data has been catalogued and organized to accommodate the exploratory plan of Salta created in 2016. The main objective was to make the data accessible to better identify, qualify and quantify resources to promote future investments in the province.  Detailed technical data on historical exploration wells, hundreds of seismic lines and additional is now accessible for potential bidders to analyze available blocks.

The most interesting areas to be offered in the upcoming round may be the ones with existing discoveries and possibly high potential. This includes the Guayacan, Ipaguazu, Yariguarenda and Las Canitas blocks. This blog will take a quick look at a couple of these.

Ipaguazu block

Ipaguazu block

This 183 sq km license It is in the prolific Tarija Basin, between the Campo Duran-Madrejones area currently operated by Tecpetrol, and the Santa Victoria block (Madalena Energy). Tecpetrol in 2017 presented an US$ 30 million investment plan for Sierra de Aguarague. The license was awarded in 1990 and the partners have since been granted a 10 year extension of the contract which now expires in 2025. Geological targets are the Carboniferous Tupambi Formation at depths of around 3,800m and the Devonian.

The Ipaguazu anticline is separated from the Madrejones by a deep syncline which leads to hydrodynamic pressures on both sides. The Tupambi Formation seems to draw the most geological interest in the area. Six wells have been drilled on the block with the most notable being the Ipaguazu x-1 which tested in 1981 about 918 bo/d and 10 MMcfg/d from the Tupambi Formation. The sweet spot is projected to be about 3,000m deep with the observation of paleo channels in available 2D seismic lines.

The Devonian play is represented by the Huamampampa and Santa Rosa formations. These formations were not reached by the Ipaguazu x-1 but the play has been highly productive in the neighboring Aguaragua, San Pedrito and Ramos fields.

Future exploration work like reprocessing 2D lines, surface geochemistry, additional seismic acquisition and new drilling plans are expected to be worthwhile exploration investments for the  block.

Yariguarenda block

Yariguarenda block

This block is also in the Tarija basin, close to Bolivia and adjacent to the west with the Acambuco I Block operated by Pan American Energy and to the east of Madalena Energy’s Santa Victoria Block.  Chinese operator, JHP operates south of this license with the Tartagal Oriental Block. Six wells have been drilled historically in this area with two of them being successful. The Nacatimbay x-1001 and the Tartagal Oriental x-1001 tested oil and gas from the Las Penas and Tupambi Mississipian sandstones. The approximate depth of the objectives was 3,800m. The Nacatimbay well was drilled in the southern portion of the structural alignment of the Campo Duran, Madrejones and Icua fields. The Nacatimbay x-1001 tested gas and condensate in 1995 with a TD of 4,159m. The southern part of the area structures shows emergent faults from the Los Monos Formation (source rock and potential unconventional target).

The exploration challenges include assessing the Devonian Huamampampa and Santa Rosa formations, which produce oil and gas in neighboring Madrejones and Campo Duran.

The Tertiary Complejo Petrolifero Rio Pescado is also an interesting target to investigate, as well as the Carboniferous San Telmo Formation.

The expected work programs in Yariguarenda includes reprocessing existing 2D seismic, perform surface geochemistry and acquisition of some new 3D seismic to delineate the Tupambi reservoir in the southern area of the block. Deeper structural assessment and additional drilling is also expected if justified by these studies.

 

General exploration overview

 

Although there are some discoveries with interesting results, the Salta bidding blocks require extensive and intensive additional exploration work to determine profitability of oil and gas development. Further analysis is needed of existing technical information to use for exploration of deeper horizons also. The Tarija and Oran-Olmedo Basin in Argentina need further exploration and analysis of the petroleum systems and play definition in order to better identify possible sweet spots. The gas window, especially in the Carboniferous and Devonian plays is a great opportunity to invest in these blocks.

Additionally, the Los Monos Formation in its sandstone facies has been mentioned as an interesting unconventional tight gas play especially for the Aguarague-Ramos anticline. Porosity is low but gas saturation very high in its psamitic intercalations. The Salta province prospects in the Tarija basin are very linked to Bolivia gas fields in that basin with the reasonable hopes that some of the high producing wells and multi-Tcf fields can also be found on the Argentine sine of the border in Salta.

However, drilling and operating costs in Salta are currently higher than those in Neuquen for example due to more difficult drilling conditions, as well as the deeper objectives averaging between 3,800-4,200m and lack of economies of scale that now exist in Neuquen. The higher costs can be compensated by much higher volumes per well though especially with natural gas.

Improvements in government pricing and tax policy to promote industry activity in recent years, like an agreement being discussed with the Federal Government to apply to Salta the special gas pricing promotion plan now active for the Neuquen and Austral basin could provide the missing piece to help to revive the Salta Province to reach its full potential in hydrocarbons.

Major offshore Bahrain discovery 80 Bb oil in-place plus 13 Tcf gas in place

Major offshore Bahrain discovery 80 Bb oil in-place plus 13 Tcf gas in place

At a press conference on 4 April, chaired by Oil Minister Sheikh Mohammed bin Khalifa al-Khalifa supported by Bapco Exploration Manager Yahya Alansari, and with representatives of Degolyer and McNaughton, Schlumberger and Halliburton in attendance, more details were given of the major discovery first flagged on 1 April.

 Bahrain’s Higher Committee for Natural Resources and Economic Security, chaired by Crown Prince Salman Bin Hamad Al Khalifa, had announced 1 April 2018 that there had been a “highly significant” offshore discovery of tight oil and deep gas in the Khaleej Al Bahrain Basin, which extends off the west and south-west coast. The exact location has so far not been revealed; however in 2016 operating company BAPCO let a turnkey contract to Schlumberger for drilling and testing 2 exploratory wells, and was operating the “Key Hawaii” jack up in the extreme south of the Bahraini sector in the period from mid-March to mid-October 2017 when it moved off location. The rig was subsequently operating to the east of Bahrain, close to the Qatar border.

Figure 1 - Khaleej al Bahrain basin location

Figure 1 – Khaleej al Bahrain basin location

Figure 2 - Bahrain Stratigraphy & Petroleum Systems. Source: Bapco

Figure 2 – Bahrain Stratigraphy & Petroleum Systems. Source: Bapco

The Minister said that the discovery was of tight oil, amounting to 80 Bb in-place (with associated gas of 13.7 Tcf), and also with deeper gas amounting to 10-20 Tcf in-place. DeGolyer and MacNaughton Senior Vice president, Dr John Hornbrook, added that the 80 Bb figure was a P50 estimate. No well-name has been given, but the generic name is the 2000 sq km “Khaleej al Bahrain” basin, which extends around the west and south of the island. It is thought that the 80 Bbo figure applies to the entire resource play.

Bapco Exploration Manager, Mr Yahya Alansari, added that “the presence of a layer with moderate conventional reservoir properties on top of an organic-rich source rock creates a unique self-sourcing and trapping system, enhancing production and economic viability. The confirmation of this significant resource highlights the vast E&P potential and opportunities in Bahrain.”

Earlier Bapco technical documents suggest the oil may be reservoired in Hanifa-Tuwaiq Mountain Formations (Jurassic). In 2012, light oil (43 deg API) was recovered from the Hanifa-Tuwaiq Mountain Formation source rock interval, establishing the potential for unconventional plays.

The source rock for the Pre-Khuff gas is the Silurian Qusaiba Formation – which is geographically extensive. Thermal history modelling suggests gas generation in the Oligocene-Miocene. Deep (Pre-Khuff) gas has long been an identified target under the onshore Bahrain Field, and it is possible the figures for the current find conflate the offshore with the onshore potential. In 2016, NOGA was seeking international partners for onshore exploration, to replace Oxy and Mubadala, which pulled out.

Next steps

The Minister said that two appraisal wells had been agreed for 2018, which will be operated by Halliburton. No mention has been made of blanket 3D seismic coverage. Operating company Bapco is already in discussions with IOCs and major service companies on partnerships to exploit the resources. To date, worldwide, no unconventional resources have been exploited offshore. However, an optimistic production start date of 2022-2023 has been touted. The Minister added that one could expect the resources to support oil production of 200,000 b/d and gas of 1 Bcf/d.

Bid Round

At the ADIPEC Conference in 2016, Bapco announced an acreage offer for 2017-2018, offering four offshore areas CA 1, CA 2, CA 3 and CA 4 for Joint Study Agreements. The extent of the resource play coincides roughly with CA 2 (2228 sq km) to the west of the island and CA 4 (1478 sq km) to the south of the island. In CA 3, 9 wells have been drilled, with 3 TDing in the Khuff; in CA 4 (described as “the unconventional hot-spot”), seven wells have been drilled to date with oil shows, with one penetrating the Khuff.

Figure 3 Bahrain future Offshore Licensing Round

Figure 3 Bahrain future Offshore Licensing Round

 

 

 

 

© Drilling Info, Inc. This report is the exclusive property of Drillinginfo It may be used only in accordance with a current agreement between the user and Drillinginfo.  No part of this report may be reproduced, used, copied, modified, propagated, or distributed except in accordance with that agreement. Unauthorized use of all or any part of this report may violate copyright, trademark, trade secret, and/or other laws and is subject to civil as well as criminal sanctions.

 

THIS REPORT IS PROVIDED “AS-IS” AND ALL WARRANTIES ARE EXPRESSLY DISCLAIMED. THIS REPORT IS A SUPPLEMENT TO, NOT A SUBSTITUTE FOR, THE KNOWLEDGE, EXPERTISE, SKILL, AND JUDGMENT OF PROFESSIONALS. THE USER ACCEPTS ALL RISKS IN USE OF THIS REPORT INCLUDING BUT NOT LIMITED TO ANY INVESTMENT, ACQUISITION, DRILLING, WELL TREATMENT, PRODUCTION OR FINANCIAL DECISIONS. THIS REPORT IS NOT TRADING ADVICE, A TRADING RECOMMENDATION, OR TRADING INFORMATION. IN NO EVENT SHALL DRILLINGINFO OR ANY OF ITS AFFILIATES BE LIABLE UNDER ANY LEGAL THEORY, WHETHER IN TORT (INCLUDING NEGLIGENCE), CONTRACT, STRICT LIABILITY, STATUTORY OR OTHERWISE, FOR ANY DAMAGES EXCEEDING $1,000 OR ANY SPECIAL, INCIDENTAL, CONSEQUENTIAL, EXEMPLARY, PUNITIVE OR INDIRECT DAMAGE OF ANY KIND, EVEN IF APPRISED OF THE POSSIBILITY OF SUCH DAMAGES IN ADVANCE.

Less is more – North West Europe’s ‘lesser’ bid rounds

Less is more – North West Europe’s ‘lesser’ bid rounds

Norway and the UK tend to dominate the headlines for North West Europe E&P. Those not taking a detailed look at the region may have missed some of the lower profile bid rounds that took place last year. So, here’s an opportunity to recap on recent, ongoing and upcoming ‘lesser’ bid rounds.

Lesser Rounds

The Isle of Man held its 2nd Hydrocarbons Licensing Round from 11 September to 10 December 2017. All acreage was available at just under 4,000 sq km, the same as in the first Round in 1995. Three dry wells have been drilled in IoM waters, although 112/25- 1 (1982, BP, 2,780m) did encounter gas shows in the Permian. An unspecified number of applications are currently being assessed, with a decision expected by in April 2018.

Figure 1 - Isle of Man 2nd Hydrocarbons Licensing Round

Figure 1 – Isle of Man 2nd Hydrocarbons Licensing Round

The Faroe Islands 4th Exploration Round launched on 17 May 2017, with bidding closing on 17 February 2018. The round covered the Northwestern part of the Faroe-Shetland Basin to the South & Southeast of the Islands, and nearly 50,000 sq km was available. The Faroese government reports that only one application was received. Three licenses covering 6,500 sq km were awarded in the previous Third Round in 2007/8 but all three have since been relinquished, and there are no active Faroese licences. The regulator Jarðfeingi plans to offer further acreage to the Northeast, North and West of the islands in future rounds.

Figure 2 - Faroe Islands 4th Exploration Round

Figure 2 – Faroe Islands 4th Exploration Round

If ever less was more, then it would be in Greenland. Over 100,000 sq km is available in the 2018 Davis Strait round. But Greenland made similar offers for 85,000 sq km in Baffin Bay and 13,000 sq km onshore Disko-Nuussuaq in 2017 and 2016 respectively but receive no bids. Currently Western Greenland is effectively unlicensed for E&P although an out of round application for 10,000 sq km offshore Southwest Greenland is currently being reviewed.

Figure 3 – Greenland Davis Strait round

Figure 3 – Greenland Davis Strait round

Energistyrelsen, the Danish Energy Agency, plans to launch the 8th Licensing Round during H1 2018, offering Southeastern North Sea acreage. Denmark has softened its fiscal terms during 2017 to 2025 to facilitate redevelopment of Tyra Field, and this may attract increased interest. Energistyrelsen intends to hold biennial rounds; the last was the 7th Licensing Round held in 2014 with results announced in 2016 after much delay, with 16 awards to 11 companies.

Figure 4 – Denmark 8th Licensing Round

Figure 4 – Denmark 8th Licensing Round

Big fish & little fish

The UK and Norway continue to lead the North West Europe E&P scene. Norway’s APA2017 saw 75 licences awarded in mature acreage, and results are awaited from the 24th Round (Exploration acreage). The UK’s 30th Seaward Licensing Round received 96 applications for 239 blocks in mature acreage, with awards expected in Q2 2018, to be followed by an offer for exploration acreage in the 31st Round later this year.

Figure 5 – North Atlantic Margin acreage by operator

Figure 5 – North Atlantic Margin acreage by operator

But explorers have also shown an interest in the region’s lesser petroleum provinces. Ireland’s 2015 Atlantic Round was a rousing success and – as confidence in a stable oil price recovers – one might expect that Northern Atlantic Margin players will be interested in other under-explored basins. Statoil, ExxonMobil, and CNOOC/Nexen have already signalled intent with big acreage claims in Ireland. BP is also likely to be more aggressive following solid 2017 profits and with the Macondo issue largely settled, and it remains to be seen if Husky and Chevron will follow across the Atlantic. But one thing is clear – as industry confidence returns, both major and emerging players have established a strong presence in the region. Spending continues to be cautious, but we can reasonably expect a boost of exploration activity. Perhaps soon, less will really be more.

 

 

© Drilling Info, Inc. This report is the exclusive property of Drillinginfo It may be used only in accordance with a current agreement between the user and Drillinginfo.  No part of this report may be reproduced, used, copied, modified, propagated, or distributed except in accordance with that agreement. Unauthorized use of all or any part of this report may violate copyright, trademark, trade secret, and/or other laws and is subject to civil as well as criminal sanctions.

 

THIS REPORT IS PROVIDED “AS-IS” AND ALL WARRANTIES ARE EXPRESSLY DISCLAIMED. THIS REPORT IS A SUPPLEMENT TO, NOT A SUBSTITUTE FOR, THE KNOWLEDGE, EXPERTISE, SKILL, AND JUDGMENT OF PROFESSIONALS. THE USER ACCEPTS ALL RISKS IN USE OF THIS REPORT INCLUDING BUT NOT LIMITED TO ANY INVESTMENT, ACQUISITION, DRILLING, WELL TREATMENT, PRODUCTION OR FINANCIAL DECISIONS. THIS REPORT IS NOT TRADING ADVICE, A TRADING RECOMMENDATION, OR TRADING INFORMATION. IN NO EVENT SHALL DRILLINGINFO OR ANY OF ITS AFFILIATES BE LIABLE UNDER ANY LEGAL THEORY, WHETHER IN TORT (INCLUDING NEGLIGENCE), CONTRACT, STRICT LIABILITY, STATUTORY OR OTHERWISE, FOR ANY DAMAGES EXCEEDING $1,000 OR ANY SPECIAL, INCIDENTAL, CONSEQUENTIAL, EXEMPLARY, PUNITIVE OR INDIRECT DAMAGE OF ANY KIND, EVEN IF APPRISED OF THE POSSIBILITY OF SUCH DAMAGES IN ADVANCE.

 

 

 

 

 

Offshore Mexico Bid Round 3.1 – Results are in!

Offshore Mexico Bid Round 3.1 – Results are in!

On 27 March 2018, the Comision Nacional de Hidrocarburos (CNH) took bids for 35 exploration and extraction blocks in Mexico’s Round 3.1 (CNH-R03-L01/2017 over 2 areas: Burgos Basin, Tampico-Misantla-Veracruz Basin & Sureste (Southeast) Basin.   There were 30 companies representing 6 continents that participated in the Bid Round (20 pre-qualified as operators and 10 non-operators) including BP, Shell, Chevron, & Total who just won blocks in the GOM 250 Lease Sale last week.  Other participants include ENI, Pemex, Repsol, Lukoil & Premier Oil.  In total, 16 areas were awarded in today’s Bid Round.  Pemex came out the winner with the most areas awarded (4) totaling 2,935 sq km, plus they partnered up with 4 companies, including Shell & Total adding another 3 areas to their portfolio as a non-operator.  Total is making a big push to be a leader in the GOM as they came out strong in the US GOM 250 lease sale last week winning 9 blocks, plus were awarded 3 areas today totaling 2,356 sq km.

Overall the Mexican government was excited about the results from the sale and the positive impact it will have on the country especially the competitive bidding on the Sureste (Southeast Basin).

Pre-3.1 Sale Overview

Prior to the 3.1 sale, Pemex had the most blocks (116) & acreage (~45,000 sq km).  With Shell having the next highest block count (9) & acreage (~19,000 sq km) making them the boss in the GOM from the American and Mexican side (Figure 1).

Figure 1: Pre-Mexico 3.1 Offshore Round operator by block count and acreage. *Not shown: Pemex who has 116 blocks and over 45,000 sq km of acres they are the current operator making them the dominant operator in Mexico.

Figure 1: Pre-Mexico 3.1 Offshore Round operator by block count and acreage. *Not shown: Pemex who has 116 blocks and over 45,000 sq km of acres they are the current operator making them the dominant operator in Mexico.

3.1 Results

Bidding kicked off slow in Mexico City, with only four out of the 14 Burgos Basin blocks on offer getting snapped up. Repsol of Spain and UK-based Premier led the effort for this tranche of offshore shallow water blocks, separately picking up two tracks each. The Spanish company’s Repsol Exploración México secured rights to the 823 sq km Area 5 block with an additional royalty rate of 56.27%. That beat out state-run Pemex’s bid of 23.89%. Neither company offered additional investment factor. Meanwhile for Area 11, Premier Oil Exploration and Production Mexico scooped up the tract with its additional royalty bid of 29.43%. Premier was the sole bidder for the 396 sq m block. Repsol bid once more, scooping up Area 12. The company won the area with its 48.17% bid. The last block to be awarded, Area 13, went to Premier with its additional royalty payment bid of 34.73% The Burgos Basin blocks encompassed 8,424 sq km, with an estimated 579 MMboe in prospective resources.

Bidding for the second tranche of blocks in the Tampico-Misantla-Veracruz Basin was modest, with only four blocks out of 13 of the blocks on offer receiving any bids. Capricorn Energy with Citla Energy E&P won Area 15 (971 sq km in the Tampico-Misantla Basin) with an additional royalty bid of 27.88%. State-run Pemex Exploración y Producción with Deutsche Erdoel México and Compañía Española de Petróleos won Area 16 with their 24.23% bid. The trio followed up that win by offering an additional royalty if 35.51% for Area 17. Pemex, in a separate partnership with Spanish Compañía Española, bid an additional royalty of 40.51%, thus winning Area 18.

Bidding finally picked up the pace with the Sureste (Southeast) Basin with lots of partnerships and contested bidding for these 8 coveted areas.  As the bids were announced you could feel the excitement transmitted from the Mexican government about the competitiveness & desire from companies to win awards in this hydrocarbon rich basin.  In Area 28Eni of Italy and Russian Lukoil came on strong with an aggressive bid of 65% with an investment factor of 1.5, and a tie-breaker cash bonus of US$ 59.823 million. That beat out the second highest bid from Deutsche with Premier.  As for Area 29, Pemex submitted a winning bid of 65% with an additional investment factor of 1.5 and a US$ 13.07 million-plus bonus. In second place, Deutsche Erdoel México & partners lost out again offering 65% with an additional investment factor of 1.   Bidding intensified for Area 30. Deutsche, Premier, and Sapura won this tract with their bid of 65%, an additional investment factor of 1.5, and a US$ 51 million-plus cash bonus.  They won out over 6 other bids on this area making it the most competitive in the 3.1 Bid Round.  Area 31 went to Pan American Energy, which bid an additional royalty of 65% with an additional investment factor of 1 while Total & Pemex won Area 32 with 40.49%.  Area 34 was awarded to Total, BP and Pan American Energy with a bid of 50.49% and an investment factor of 1, and Area 35 closed out the awards going to Shell and Pemex with the winning bid of 34.86% for this block.

Figure 2 shows the results of the 3.1 Bid Round by award count and area (sq km).  Pemex came out the top winner followed by Total.  Premier Oil made a great showing walking away with 3 awards.

Figure 2: Mexico 3.1 Bid Round Results. Pemex was the top winner followed by Total and Premier.

Figure 2: Mexico 3.1 Bid Round Results. Pemex was the top winner followed by Total and Premier.

 

Interested in learning more?

Please contact the DrillingInfo GOM Team:

Tom Liskey, Regional Mgr – Americas Tom.Liskey@drillinginfo.com

Robyn Marchand, Technical Advisor – DrillingInfo  Robyn.Marchand@drillinginfo.com

© Drilling Info, Inc. This report is the exclusive property of Drillinginfo It may be used only in accordance with a current agreement between the user and Drillinginfo.  No part of this report may be reproduced, used, copied, modified, propagated, or distributed except in accordance with that agreement. Unauthorized use of all or any part of this report may violate copyright, trademark, trade secret, and/or other laws and is subject to civil as well as criminal sanctions.

 

THIS REPORT IS PROVIDED “AS-IS” AND ALL WARRANTIES ARE EXPRESSLY DISCLAIMED. THIS REPORT IS A SUPPLEMENT TO, NOT A SUBSTITUTE FOR, THE KNOWLEDGE, EXPERTISE, SKILL, AND JUDGMENT OF PROFESSIONALS. THE USER ACCEPTS ALL RISKS IN USE OF THIS REPORT INCLUDING BUT NOT LIMITED TO ANY INVESTMENT, ACQUISITION, DRILLING, WELL TREATMENT, PRODUCTION OR FINANCIAL DECISIONS. THIS REPORT IS NOT TRADING ADVICE, A TRADING RECOMMENDATION, OR TRADING INFORMATION. IN NO EVENT SHALL DRILLINGINFO OR ANY OF ITS AFFILIATES BE LIABLE UNDER ANY LEGAL THEORY, WHETHER IN TORT (INCLUDING NEGLIGENCE), CONTRACT, STRICT LIABILITY, STATUTORY OR OTHERWISE, FOR ANY DAMAGES EXCEEDING $1,000 OR ANY SPECIAL, INCIDENTAL, CONSEQUENTIAL, EXEMPLARY, PUNITIVE OR INDIRECT DAMAGE OF ANY KIND, EVEN IF APPRISED OF THE POSSIBILITY OF SUCH DAMAGES IN ADVANCE.

Is Egypt a regional gas hub in the making?

Is Egypt a regional gas hub in the making?

The Zohr Field – a Game Changer

On 20 December 2017, first commercial gas was achieved from the super-giant Zohr Field, located in the Egyptian Mediterranean deepwater (WD ~1,500m). From drilling to production took just 28 months; a record time for a deepwater project. The discovery and subsequent fast-tracking of Zohr, which is located 190km offshore and over 100km away from the nearest gas pipeline, has been heralded as a game-changer for Egypt. Since the late-2000s, a lack of investment, coupled with a growing population (2% average annual growth since 2010) had swung domestic energy supply and demand into the red. The political upheavals between 2011-13 only added to the problem, with the gas supply/demand slipping into the red in 2014. A 7% growth in consumption was coupled with a 5.7% fall in production 2015. The Government finally admitted defeat and started LNG imports in 2015. All this came less than 10 years after the launch of the two LNG export terminals at Idku and Damietta in 2005.

Then the discovery of Zohr was made. On 1 September 2015, operator Eni announced that the Zohr 1X NFW (TD 4,131m) had encountered a 430m net gas pay, in what was subsequently revealed to be a Cretaceous-Miocene carbonate build-up. The play-opening 30 Tcf GIIP discovery set in motion a scrabble amongst petroleum geoscientists to re-assess current thinking about the evolution of the Eastern Mediterranean region, and to see whether any more “Zohr-like” discoveries could be found.

Figure 1: Zohr Field

Figure 1: Zohr Field

But is that the long and short of the story? Just a stroke of luck (and some very enterprising people from Eni), resolving Egypt’s gas crisis? No, of course not. When peak output is achieved (expected in 2019) Zohr is planned to produce 2.6 Bcfg/d. But it alone will not suffice to move Egypt into a significant gas surplus, with in-country demand continuing to increase. It is the push from the current Sisi-led administration to accelerate (alongside Zohr) other recent, old and stalled projects. Couple this with the investment might of the oil majors, the shortfall could be relieved, and in the process convert Egypt into a gas-exporting country. Some of these other major projects that are and could contribute, are detailed below.

Figure 2: Egypt gas balance 2006 - 2016

Figure 2: Egypt gas balance 2006 – 2016

Deepwater Nile Delta Clastic Plays Continue to Prove Their Worth
In the Mediterranean, BP and DEA are working on Phase two of their West Nile Delta (WND) project. Phase one was brought onstream in March 2017, eight months ahead of schedule and just two years after development approval. It is currently producing 700 MMcfg/d and 1,000 bc/d. When Phase two is completed (by 2019) peak output from WND is expected to reach 1.5 Bcfg/d. The project has 5 Tcfg and 55 MMbc of untapped resource. The project is a long time in the making however; the discoveries were made in the early-2000s.

In contrast, in February 2018, BP also completed Phase one of its fast-tracked Atoll development, seven months ahead of schedule. The field was discovered in May 2015. Over 350 MMcfg/d and 10,000 bc/d are currently being produced, with an estimated in-place resource of 1.5 Tcfg and 31 MMbc.

Eni’s Nearshore Discovery Coming in Under the Radar
Whilst the oil industry has been waxing lyrical about Zohr, another record-breaking field was tied-in by Eni (in partnership with BP). In September 2015, the same month the Zohr discovery was announced, the nearshore Nooros Field was brought onstream. Discovery to first gas had taken just two months. Nooros lies to the north of, and on trend with, the giant Abu Madi Field. It was discovered by the Nidoco North West 2 NFW (TD 4,106m) in the Messinian Abu Madi sandstones. The field is now producing over 1.1 Bcfg/d, with 14 deviated wells drilled from just two onshore locations. Estimated in-place resources are 2 Tcfg.

Mediterranean discoveries slow down in 2016-17
In mid-2016, a further Abu Madi wet gas discovery (Baltim South West) was made by the same Eni/BP partnership, this time outboard of Nooros. Baltim South West, together with the nearby undeveloped 1995 Baltim South discovery, is estimated to hold a combined 1 Tcfg in-place. Neither are developed to-date. Baltim South West was the only confirmed Mediterranean discovery of 2016. The same story continued in 2017, with BP’s Pliocene Qattameya Shallow 1 gas discovery (TD 1,961m) being the sole success, aside from Abu Qir Petroleum finding a new producing horizon on its Abu Qir North Field.

The Western Desert contributes
Like the Mediterranean, the Western Desert continues to surprise. In the Abu Gharadig Basin, Shell and Apache’s 2015-16 tight gas pilot project has proven up an under-explored play in the Eocene Apollonia carbonate. Estimated in-place resources have been cited at ~440 Bcfg. On the adjacent concession, Shell also made a ~500 Bcfg discovery in the Cretaceous Kharita Formation in 2016, with the deep (TD 5,966m) BTE 2 NFW. Further west, Apache and Eni could also be eyeing up exploration of the deeper Jurassic and Palaeozoic.

Gas hub at the ready?
At first glance, all evidence seems to point towards Egypt becoming a regional gas hub in the near-term future. The recent (February 2018) announcement of a gas sales contract between Noble Energy and private-firm Dolphinus Holdings Ltd, to export Israeli gas from the Leviathan (22 Tcf) and Tamar (7 Tcf) fields into Egypt, confirmed an agreement that had already been signed in early 2015. The proposed Eastern Mediterranean gas pipeline project is continuing to progress, with ongoing discussions and agreements between Egypt, Israel, Cyprus and Greece. The two moth-balled LNG export terminals on the Mediterranean coast (Damietta and Idku), could serve as a staging-post for Egyptian-Cypriot-Israeli gas exports to Europe. This scenario assumes that sufficient gas has been found, or will be found, to make the project viable. Egypt’s gas deficit is indeed decreasing, as more projects are brought onstream and ramped up. But the country’s demand for gas is also increasing.

In addition, EGAS has not held licensing rounds since 2015, which could result in a drop-off in the size and number, of significant gas discoveries in the near-future. Add in the political squabbling, particularly in relation to Turkey flexing its muscles over the status of the waters around Cyprus, then the simple “gas hub-export to Europe” plan doesn’t seem as clear-cut.

The energy geopolitics of the Eastern Mediterranean have heated up over the past few years, with the temperature set to continue to rise. Egypt’s dream of becoming a gas hub is well within its grasp, but is dependent on the regional political dynamics; this may prove more complex than finding the gas in the first place.

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