The geopolitical composition of the Eastern Mediterranean region is complex, as it has only recently begun accepting recognition as its own entity. Comprised of Greece, Turkey, Syria, Lebanon, Israel, Egypt and Cyprus, the region has, by and large, been acknowledged as merely an extension of the Middle East, Southeastern Europe or Western Asia.
Nonetheless, the effects of low oil prices during the last two years have slowed activity in this conventionally prolific E&P hot spot. Yet, many operators are pressing on in pursuit of the next Zohr discovery.
E&P activity in Greece has been largely fixed on the development of Prinos field by Energean Oil & Gas, situated in the Prinos-Kavala basin of the Gulf of Kavala. According to Energean, which is the Hellenic Republic’s chief hydrocarbon producer, active oil fields in the Gulf of Kavala—Prinos, Epsilon and Prinos North—contain about 30 MMbbl of 2P reserves.
The company has identified additional exploration targets in the Prinos basin, which include Zeta, Alpha and Delta. Zeta reportedly has been identified as a separate accumulation from Prinos and Prinos North. The Alpha prospect is found north of Zeta and, based on 3D seismic data, it is believed to be in another fault block.
Nearly 5 mi northwest of the island of Thassos, and 11 mi south of North Greece, Prinos field covers an area of 4 km2. Energean completed the drilling of PA-35A in late December 2015. In April 2016, Energean’s drilling rig, Energean Force, commenced drilling of PA-36. In May 2016, the successful completion of PA-40 was reported, doubling the field’s total production. Following the completion of wells PA-35A, PA-40, PA-36 and PA-41, production rates have swelled to 4,500 bpd of medium grade sour oil, as well as associated gas. Prinos’ 2P reserves rest at 11.7 MMbbl, Fig. 1.
As part of the company’s $200-million investment program, 15 development wells were planned in Greece, as well as the installation of an unmanned platform at Epsilon field. The company’s initial objective was to exceed 10,000 bopd by year-end 2016. “Our view is that oil prices will stay low before rebounding to a healthier level, sometime in 2017,” Energean CEO Mathios Rigas said in an interview with Bloomberg in February 2016. “We aim to be at peak production in Prinos, when the price of oil rebounds.”
Presently, Energean has 14 producing wells at Prinos field, which is shaped by a low relief, faulted anticline. The reservoir produces under-saturated sour crude oil, with API gravity between 27 and 30 degrees, at depths between 8,169 ft and 9,087 ft, TVDSS.
Positioned about 11 mi southwest of eastern Macedonia in northern Greece, and 1.8 mi north of Prinos, Prinos North lies in the Kavala basin. Energean reportedly has invested more than $30 million in the field’s redevelopment since 2008, managing to resume oil production after an unsuccessful sidetrack suspended production in 2004.
Under its new investment program, the company plans to sidetrack the PNA-H3 well in 2017–2018, with the intent to boost production to 2,000 bopd. According to Energean, the cumulative oil production is 4.0 MMbbl, and 2P reserves total 3.3 MMbbl.
Developed alongside Prinos, South Kavala field is at the center of a new $1.5-million development plan that will see the installation of downhole pumps in two of the field’s existing wells through 2019, which will allow the field to produce continuously and increase condensate yields. Eventually, the plan is expected to bring the recovery rate up to 98.5%. According to Energean, remaining gas reserves at South Kavala are about 2.6 Bcf.
Epsilon field has a new development plan, as well. Energean’s development project consists of the design, fabrication, installation, commissioning and subsequent operation of a new wellhead jacket platform, Lamda. This facility will be situated about 2.1 mi northwest of Prinos’ existing platforms. Additionally, the Epsilon project will see the installation of three submarine pipelines that will connect Lamda to Prinos Delta, as well as the drilling of five to nine wells.
Additionally, in November, Energean secured a 25-year exploitation license for the West Katakolon Block, in western Greece. The block is a segment of the Katakolon Concession Area, covering an area of 60 km2 and holding about 10 MMbbl of recoverable oil. This is the third field to go into development in Greece, after Prinos and South Kavala.
The company reportedly will submit a field development plan to the Greek Ministry of Energy by the end of February 2017, and drilling is scheduled to begin in 2018. First oil is expected in 2018–2019, and it will be the first hydrocarbon production, ever, in the western part of Greece.
Centrally located between Europe and Asia, Turkey is ideally positioned to be a vital conduit of crude transport. According to data from the U.S. Energy Information Administration (EIA), approximately 2.9 MMbbl of oil passed through the Turkish Straits in 2013, alone. And that figure probably has increased considerably since then. E&P activity in the region, however, has progressed at a fairly slow rate.
In July 2016, an attempted coup took place, as Turkey’s army sought to take control. In addition to warplanes flying overhead, roads in Istanbul were blockaded by army tanks. A possible upsurge in oil prices was reported, as crude shipments through Turkish pipelines and waterways were compromised. In a matter of days, however, the threat was quelled by the forces of President Recep Tayyip Erdogan. Ultimately, there was little disruption to the country’s flow of oil.
In January 2016, Valeura Energy confirmed a natural gas discovery in Turkey’s Thrace basin, the country’s primary gas producing region. It is found on the Gallipoli Peninsula, of northwestern Turkey. The discovery was made with the company’s first exploration well, Bati Gurgen-1, on its Banarli license.
Bati Gurgen-1 was drilled to an MD of 8,973 ft, encountering 104 ft of aggregate net gas pay in multiple stacked sands, in the Danismen and Osmancik formations. Additionally, the well penetrated multiple over-pressured, thin and tight stacked sands in the Mezardere formation.
Through a 24-hr production test, an initial 3.448 MMcfg and 15 bbl of condensate were produced. Measured porosity and permeability were promising; however, net pay was too scant to warrant fracing. Consequently, the well was plugged to a depth of 8,333 ft.
Activity in the region has sparked interest from a few energy supermajors, as well. In May 2016, Statoil farmed into some onshore acreage in Turkey. The company procured a 50% interest in two exploration licenses in the Thrace region. Valeura Energy retains the remaining 50%, and continues to serve as operator. “We look forward to explore[ing] the licenses further, together with the operator Valeura, and we are optimistic with regards to the potential,” said Erling Vågnes, Statoil’s senior V.P. of exploration activities in the Northern Hemisphere.
More recently, in October, Condor Petroleum’s Poyraz-5 appraisal well encountered more than 459 ft of net gas pay in several stacked reservoirs of Miocene and Eocene age. The well was drilled in Poyraz Ridge field, situated in the Ortakoy Block in the Thrace basin.
Also in October, the same drilling rig that was used to drill Poyraz-5 was moved to Poyraz-3, on the same drilling pad, Fig. 2. By the end of the month, it was reported that the development well had encountered a minimum 442 ft of net gas pay. Don Streu, president and CEO of Condor Petroleum, said, “Borehole imaging of the Sogucak carbonate in Pyraz-3 confirms the presence of an extensive network of fractures within the pay column, which should serve to enhance flow performance.”
Although there is no production to date, E&P activity offshore Syria is promising. However, the country’s intensifying civil war has stifled all progress and wreaked havoc on its existing oil fields. Output, some of which is now controlled by ISIS, is down to a fraction of its pre-war level. Likewise, the political division has spilled over into the Lebanese Republic, causing activity in the country to go dormant for the last several years.
Lebanon has not, heretofore, been known as a key energy producer, but it could begin to catch up to its regional competitors with its first auction of offshore oil and gas rights. The auction was first scheduled for November 2013, but it was delayed by the Lebanese government’s failure to delineate energy blocks and institute necessary production sharing contracts, used to stipulate tender protocols.
When the auction was postponed in 2013, then-Energy Minister Gebran Bassil said that, based on a number of seismic surveys, Lebanon could hold at least 96 Tcf of gas and 850 MMbbl of oil.
Early this month, the country’s newly formed government passed the two decrees necessary to move forward with the auction, potentially putting it on the map as an Eastern Mediterranean E&P contender. Exploration rights are expected to go up for auction in the next six months.
Although E&P activity has proven slow-moving in recent years, the Republic of Cyprus houses a significant quantity of offshore natural gas, particularly in the Aphrodite area of its exclusive economic zone. In 2011, Noble Energy discovered Aphrodite field in Block 12 (Fig. 3), which is believed to hold approximately 4 Tcf. The company has been working with the Cypriot government to settle on a field development plan.
Following Eni’s discovery of Zohr field offshore Egypt, about 3.7 mi from Cyprus’ maritime border, the Cypriot energy ministry announced that the government would receive bids in its third licensing round in July 2016. Scheduled to close by the beginning of 2017, the licensing round is related to Blocks 6, 8 and 10; however, Energy Minister Georgios Lakkotrypis said that “Block 12 will be made available for a next licensing round.” Thus far, no date has been determined for this round.
Upstream activity in the State of Israel is still concentrated predominantly at Tamar and Leviathan natural gas fields. Tamar reportedly holds about 10.8 Tcf of gas, while Leviathan field boasts nearly twice that amount. The fields were discovered in 2009, and Noble Energy has since brought Tamar field online (2013).
According to Noble, Leviathan field is expected to provide another access point into Israel’s domestic natural gas transport system, while also delivering exports to regional countries. In December 2015, the Israeli government moved forward with the enactment of the Natural Gas Framework through execution of Section 52 of the Restrictive Trade Practices Act, which instituted the regulatory assurance necessary to proceed with development of the field. Additionally, it enabled the marketing of Leviathan gas to Israeli customers for the first time.
Leviathan field’s Plan of Development (POD) anticipates a subsea system that will connect production wells to an offshore fixed platform, with an onshore tie-in to northern Israel. According to Noble Energy, the fixed platform’s initial capacity is expected to start at 1.2 Bcfgd, and expand to 2.1 Bcfgd.
In March 2016, however, a ruling by Israel’s High Court hindered plans to develop the country’s largest reserve. The court claimed that a clause in the government’s proposal to regulate the natural gas industry would inhibit major regulatory changes for ten years—affixed to encourage investment. Nevertheless, the government was given a year to revise its plan.
The decision drew concerns regarding the effect that it would have on Israel’s energy sector, and on its economy. It was said in a statement, however, that Leviathan partners—which include Noble Energy (operator), Delek Drilling, Avner Exploration, and Ratio Oil Exploration LP—would work with the Israeli government to resolve the stability clause conundrum, subsequently allowing the field to be developed by the end of 2019.
By June, the Petroleum Commissioner in Israel’s Ministry of National Infrastructure, Energy and Water Resources issued approval for Leviathan’s POD. By the end of the month, the field’s owners authorized Noble Energy to sign a contract for engineering work worth an estimated $120 million. Leviathan partners announced in November that they were close to securing the $4-billion financing required to begin the field’s development. During an interview in Tel Aviv, Delek Drilling’s CEO, Yossi Abu, said, “The Leviathan financing agreements are in the final stages of negotiations.”
Partners in Leviathan field signed an export agreement with Jordan’s Natural Electric Power Co. (NEPCO) in September, prompting a sizable civilian protest in the streets of Amman. The deal, reportedly worth an estimated $10 billion, will see the supply of a gross 1.6 Tcf of natural gas over a 15-year period.
Noble also announced that it signed an agreement to divest a 3% working interest in Tamar field to Harel Group, an insurance provider and pension manager, in partnership with Israel Infrastructure Fund (IIF). Moreover, Noble and partners moved forward with plans to drill and complete an additional development well at Tamar, as Israel’s natural gas demand increased. Drilling of the well was reportedly to begin in fourth-quarter 2016.
Zion Oil & Gas, too, moved forward with plans to drill a deep oil well in northern Israel, about 25 mi south of the Sea of Galilee. In October, the company announced the successful negotiation of a drilling contract with DAFORA S.R.L., as well as with the Israel Land Authority. Drilling reportedly was to begin in November 2016, using DAFORA’s F-400 rig.
Delek Drilling and Avner Exploration signed an agreement, as well, to sell 100% of their holdings in Karish and Tanin natural gas fields to Energean Oil & Gas, Fig. 4. Following approval of the acquisition, which reportedly took place in December, Energean will submit its FDPs for both fields to the Israeli authorities within the following six months.
The fields are found in the north of Israel’s exclusive economic zone. Tanin holds approximately 22.4 Bcm of contingent natural gas, and approximately 12.7 Bcm of prospective resources. About 40 km from Tanin, Karish holds approximately 36.3 Bcm of contingent resources, as well as about 14.0 Bcm of prospective resources. Likewise, Karish was found to have about 14.3 MMbbl of contingent condensate, as well as an additional 4.3 MMbbl of prospective condensate resources. First gas is expected in 2020.