The Mediterranean Sea has given birth to some of the world’s largest hydrocarbon finds in recent years, transforming the energy scene in environments that have been geologically and at times economically and politically challenging.
Yet the region continues to attract oil and gas companies, with colossal finds such as the Leviathan and Tamar discoveries in the Eastern Mediterranean serving as promising signs of lasting potential. Still considered a frontier area, most of the region’s possible lush deepwater areas have yet to be tapped, but companies are pushing forward with plans in the Mediterranean from the Israeli coast to Spanish shores.
In some instances, businesses are facing challenges before the drillbit reaches the seafloor. Fearing drilling could harm beach tourism, the fishing industry and sea life, some residents in the Balearic Islands offshore Spain have taken to the streets in opposition to drilling in the Gulf of Valencia, as others support the move and the economic benefits such efforts could bring. In other parts of the region, geopolitical risks continue to threaten the regulatory progress of projects. Yet other regions are poised for growth with few of the aforementioned barriers.
But just as in other parts of the world, there are geological challenges, which vary, as regional energy demand grows, providing incentive to proceed with developments.
Mediterranean-focused Energean Oil & Gas has taken the lead offshore Greece, having revived production from the Prinos Field as it pursues further exploration opportunities in Greece and other parts of the Mediterranean region.
“Many areas in the offshore and onshore Adriatic have proven hydrocarbon systems but have not been available to the international exploration community for a quarter century and more for a variety of mostly political reasons,” Hank David, new business development manager for Energean, told E&P in an emailed statement. “During this time, these areas have laid fallow or have been subject to exploration and exploitation efforts almost exclusively by state-run oil companies, most of which were underfunded and lacked up-to-date technology and tools. Consequently, this large area remains today underexplored. Suddenly, and simultaneously, massive amounts of this acreage are now hitting the market.”
These include acreage offshore Croatia, Greece and Montenegro—all of which have recently had or have licensing rounds underway. Studies have shed light on possible petroleum systems in these areas, with billions of barrels of oil in place on the Italian side of the Adriatic and the potential for just as much on the eastern side.
“Oil companies have taken great risk, and at great expense, venturing into the deep waters of the south Atlantic and east Africa over the last several years to test unproven plays, with mixed results,” David continued. “Here is an area of political stability, in the heart of the European market, with abundant new acreage availability not only in deepwater but also in shallow water and onshore, where oil is proven and seeping out of the ground. Energean sees this as a great opportunity and is uniquely positioned to take full advantage.”
Energean CEO Mathios Rigas said the Prinos Field’s potential was initially estimated at 60 MMbbl. However, production since 1981 has nearly doubled, exceeding 115 MMbbl of oil with 850 MMcm (30 Bcf) of gas having been produced. In addition, the Katakolon Block has initial estimates of between 3 MMbbl to 6 MMbbl of oil.
The stock tank oil-initially-in-place (STOIIP) for the Prinos oil field is 289 MMboe, while it’s 16 MMboe in Prinos North and 39 MMboe in Epsilon, with recovery factors at 38%, 24% and 1%, respectively.
The company, which has more than 30 years of offshore operator experience, has unveiled a $225 million development plan that aims to recover 30 MMbbl of 2P reserves and increase production to 10 Mbbl/d within the next couple of years, according to Rigas. The program includes drilling seven wells in the main Prinos Field, one well in the currently producing satellite oil field of Prinos North and seven more wells in the undeveloped Epsilon satellite field.
“Energean investments and scientific surveys have proven that there is significant scope for extracting additional production by means of drilling of new wells and through the extended use of enhanced oil recovery techniques,” Rigas said. “In order to execute the new drilling program, Energean has purchased the tender assist drilling rig Glen Esk from KCA Deutag and will be utilizing its own drilling crews to drill the wells.”
Plans are for the new rig to be renamed Energean Force, which will begin drilling early next year. Two new unmanned self-installed platforms will be placed in the Prinos North and Epsilon oil fields, which will be connected to each other and to the existing Prinos platform complex through pipelines, he said.
Energean is evaluating data and considering whether to pursue additional blocks offered as part of Greece’s licensing round, he added, calling the offshore region south of Crete “a real frontier with deep and ultradeep waters, requiring high-risk exploration investment that could potentially prove a new hydrocarbon play” and the Ionian Sea part of the Adriatic region with producing oil fields offshore.
Fold and thrust belts worldwide have proven to be prolific hydrocarbon provinces, but these rewards have not come easy, David added.
“Tortuous terrains and contorted stratum make for difficult and expensive seismic acquisition and processing, which historically have failed to provide a quality image of the subsurface,” David said. “Add hard rocks into the mix (carbonates), and the situation becomes even more challenging and expensive with regards to imaging and drilling through a fractured and cavernous substrate. The Alpine Dinaride/Hellenide system will be no less challenging. But these challenges are partly why the remaining potential is still there.”
Exploration success onshore nearby Albania has led to hope of the play’s southern extension into western Greece, he added, turning to the onshore Ioannina Block in northwest Greece. Here, the exploration program will include geophysical subsurface imaging including seismic acquisition and processing and the acquisition of a full-tensor gravity gradiometry survey over the entire block.
Interest also has picked up offshore Spain, where Schlumberger recently reprocessed more than 6,500 km (4,039 miles) of 2-D data from 2011 to 2012. The company said the reprocessed data—which spans the east coasts of France and Spain to the west coasts of the Sardinia and Corsica islands—offer increased resolution and improved subsalt imaging over the Valencia Trough around the Balearic Islands and into the Provincial Basin.
According to Olga Shtukert, senior geophysicist of multiclient exploration services for Schlumberger, the Valencia Trough and North Balearic basins have demonstrated high hydrocarbon exploration activity since the 1980s. However, the deep waters of these basins are still considered frontier areas due to a combination of multiple geological and geographic complexities.
“The challenge of the basin is the imaging of the subsalt intervals. The Upper Miocene Messinian salt package is typically over 800 m [2,625 ft] thick and seen to exhibit classic extension (salt welding and rollover anticlines), translation (salt pillows) and contraction (salt diapirs),” Shtukert said. “The tectonic mechanism is critical for the area. Main rifting in the Mesozoic and additional rifting episodes in lower Miocene may have led to localized potential source rock deposition in synrift successions. The post-salt interval is affected by gravity sliding, growth faulting and normal faulting tectonics.”
The reprocessed survey has allowed for better interpretation of the subsalt intervals and fault units due to enhanced velocity analyses and demultiple algorithms, Shtukert added. And the updated data have pointed to some hydrocarbon prospects. As part of the effort, four levels of hydrocarbon plays were observed:
- Postrift post-salt: Ebro Group with biogenic gas expected within clastic turbidite deposits in the Plio-Pleistocene;
- Postrift presalt: San Carlos Group with Deltatic/turbidites deposits in the Miocene age;
- Synrift: Basal Tertiary Group with Deltatic/canyon sands in the Lower Oligocene; and
- Proven prerift with carbonate buildups in the Mesozoic.
“The proven hydrocarbon reservoirs on the western Mediterranean are allocated to the Mesozoic age and represented by Upper Jurassic limestones and Lower Cretaceous shallow marine carbonates (limestones and dolostones),” she said. “We mapped several potential leads of Mesozoic age on the reprocessed data. Also several potential leads of clastic Tertiary reservoirs have been justified and mapped.”
For Madrid-based Repsol, the greatest potential in the Spanish Mediterranean lies near its Casablanca asset, offshore the Tarragona/Ebro Delta region, where the company said improvements in subsea images make it very attractive to produce from smaller structures.
“The strategy in the Spanish offshore is being geared toward new ideas thanks to better technology that allows us to have more precise images and drill in deeper waters. The potential in Mediterranean waters is in areas of the Tarragona coast and areas of León Gulf,” Repsol told E&P.
The Casablanca platform draws about 8 Mbbl of oil from six wells—Turbot, Boqueron, Barracuda, Squid, Seabass and Montanazo, the company said on its website.
Repsol has deemed its Lubina-Montanazo development as one of its 10 key projects, with a planned investment of $20 million euros (US$248 million) between 2012 and 2016. Of the 200 Mboe/d increase in production projected for Repsol’s 10 key growth projects worldwide, Lubina-Montanazo is expected to contribute an additional 5 Mboe/d, according to the company’s strategic plan.
“Lubina and Montanazo are currently producing 4,200 barrels a day,” Repsol said before addressing potential prospects in the Lubina-Montanazo/Casablanca area. “Currently Repsol is finishing the static model; that shows some interesting zones. Spain is not an oil country, but thanks to new technologies it shows some interesting areas.”
But “the biggest obstacle is that Spain is not a country with a strong tradition in this industry so the regulatory procedure is less streamlined,” Repsol said. “However, the government is taking legislative steps that are generating more opportunities.”
Media outlets have reported in recent months on residents protesting drilling plans in areas such as the Gulf of Valencia and other parts offshore Spain, including the Canary Islands, a popular tourist destination.
Meanwhile, Noble Energy continues to make progress offshore Israel.
Speaking during its third-quarter 2014 earnings call, Noble Energy CEO David Stover said the company has executed letters of intent for regional gross daily volumes of more than 42.5 MMcm/d (1.5 Bcf/d) with total volumes of more than 226.5 Bcm/d (8 Tcf/d) of gas from the Tamar and Leviathan fields for customers.
“These agreements highlight the long-term demand for Tamar and Leviathan gas, and all parties are focused on completing them as soon as possible,” he said, later adding “We anticipate we could be in position to provide around 200 million cubic feet per day [5.7 MMcm/d] at off-peak hours to Egypt as soon as regulatory approvals are received. The compression project at the Ashdod onshore receiving terminal, which handles gas for Tamar, remains on schedule to be complete by next summer. Once complete, peak capacity at Tamar will be 1.2 billion cubic feet per day [34 MMcm/d]. This is part of a multiyear expansion at Tamar, which will increase capacity to 2 billion cubic feet per day [57 MMcm/d] by 2017 to meet growing demand in the Eastern Mediterranean.”
Looking back, Stover said volumes, particularly from Leviathan, are significantly higher than what was talked about a year or so ago. The initial phase of Leviathan called for about 24 MMcm/d (800 MMcf/d), but Noble is planning for a capacity of 48 MMcm/d (1.6 Bcf/d)—and that is just the first phase. It’s not just Leviathan; it’s Tamar also.
During the Johnson Rice & Co. Energy Conference, he described Noble’s East Mediterranean finds as discoveries that have gotten bigger. “When we initially found Tamar we were targeting a 3-Tcf [85-Bcm] opportunity, but it’s turned into a 10-Tcf [283-Bcm] discovery,” he said noting that production has averaged 23 MMcm/d (750 MMcf/d). “Downtime is measured in minutes and hours rather than days.”
The focus at Leviathan, which ballooned from 453 Bcm (16 Tcf) during appraisal drilling to 623 Bcm (22 Tcf), is getting letters of intent and regional contracts in place for gas, he added. Already, a contract is in place with BG for an LNG facility in Egypt, and another contract is lined up with Jordan. The field is set to go onstream in late 2017 or early 2018.
Then there is the potential for deep oil.
“We’re still excited about deep oil prospectivity over there, but the timing is going to be dependent on when we bring a rig capable of drilling the deep oil prospect in to go along with the additional Leviathan and Tamar development and then in what sequence we do those things,” Stover said during the third-quarter call. “That all has to fit together.”
Noble anticipates a deep oil test in the Levant Basin in 2015, according to its website, which pointed out multiple prospects have been identified in the company’s acreage.
Energean also is journeying farther east into the deepwater offshore Israel, having farmed in to the Sara/Myra licenses. “And to do so, taking advantage of an existing wellbore suspended only 1,000 m [3,281 ft] above an attractive Oligocene/Eocene-age prospect, makes the economics of the project very attractive, especially for a deepwater venture,” David said, noting the company has formed a joint venture with Ocean Rig.
“The coming of age of the deepwater Levant Basin offshore Israel and Cyprus is now well known. It is proving to be a world-class natural gas resource. But interestingly, exploration in the basin is still in early days. Not only has the full extent of the Miocene gas play yet to be realized (primarily due to the inaccessibility of offshore Lebanon), but the entire sedimentary section below the gas play in the deepwater remains undrilled,” David said. “Only one well has even attempted to test a deeper, older play, and that well failed to meet its objectives.
“Decades of exploration on the shelf and onshore in Egypt and Israel have proven working petroleum systems in the Paleogene and Mesozoic sections, and recent very deep drilling in the deepwater offshore eastern Nile Delta have also proven a working Oligocene-age gas/condensate system,” David continued. “It is more than reasonable to project one or more viable petroleum systems in the pre-Miocene section into the deepwater Levant Basin offshore Israel.”
Broussard previously spent four years working for Schlumberger and held a number of management positions with Baker Hughes over an 11-year period, latterly as regional operations manager for lower completions in the Gulf of Mexico.
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