The Prinos Oil Field is the main structure in the Prinos-Kavala basin, located offshore in the Gulf of Kavala. It covers an area of 6 km2, about 8 km north-west of the island of Thassos and 18 km south of the mainland of North Greece, in a water depth of 31 meters.

Following the wells already drilled in the context of the ongoing drilling programme and the interpretation of the 3D seismic data acquired in the summer of 2015, Prinos 2P reserves have been independently audited at 20,8 mbbls (2P), while the 2C contingent resources associated with a notional extension of water injection are 16,6 mln bbls.

Since the summer of 2015, “Energean Force”, Energean’ s own drilling rig, has been executing a 7-well drilling programme in the field, as a part of a new 200-million-dollar investment. After the completion of the drilling of four wells (PA-35A, PA-40, PA-36 and PA-41), production rates exceeded 4,500 bopd of medium grade sour oil plus associated gas within 2016.

Currently, and since the drilling of PA-38 and PA-33 was completed in Q1 2017, fourteen wells are producing and four are injecting sea water. Prinos’ oil production averaged 3,177 bbls daily in 2016, that is a 151% increase compared to 2015 production.

The field

The Prinos field is formed by a low relief faulted anticline, with oil trapped in the Prinos Group reservoir of Miocene Age at a depth of between 2490 and 2770 m TVDSS. The reservoir produces under-saturated sour crude oil with an API gravity of between 27 and 30 degrees.

Prinos contains up to 60% hydrogen sulphide gas. The onshore ‘Sigma’ plant complexity is driven by facilities to remove this toxic gas and convert it to Sulphur. Sulphur is sold to a local fertilizer plant. Excess gas is sold to
the same company.


The Prinos basin was explored in the 1970’s and the Prinos field was discovered in 1974, through the drilling of Prinos-1, the first exploration well drilled in the area. It was developed in the late 1970’s and brought into production in 1981.

The initial development of the field, following the drilling of the delineation wells which confirmed the extent of the Prinos reservoir, took place from 1979 until 1981. Facilities were installed offshore and onshore to allow 30,000 bopd to be produced along with associated gas. Two drilling jackets were installed above the Prinos field, bridge linked to an unmanned offshore processing platform. These offshore facilities were linked by pipeline to shore where a complex gas and oil processing plant was constructed along with oil storage tanks (500,000 bbl capacity) and offshore loading terminal.

Crude oil production commenced in early 1981, at initial rates of 8,000 to 10,000 bopd. Production peaked at more than 27,000 bopd in 1985, however it has steadily declined since then.
Prinos 2P reserves were initially estimated at 60 million oil bbls, but the field has already produced more than 110 million bbls since 1981.

Prinos North

Prinos North Oil Field is one of the satellite Fields within Prinos – Kavala Basin. It is located approximately 3 km north of Prinos Oil Field and about 18 km south-west of the mainland of Eastern Macedonia, Northern Greece, where the water depth is 38 meters.

Since 2008, Energean has invested more than US$ 30 million in redevelopping the field, managed to revive oil production which was interrupted back in 2004. In the context of the new investment programme which is in progress, Energean has planned to sidetrack the well PNA-Η3 in 2017 aiming to increase the current production up to 2,000 bopd.

In 2016, and after some technical interventions, the average oil production rate was 313 stb/d, a 58% increase compared to 2015 production.

The cumulative oil production is 4,0 MMstb, while 2P independently audited reserves stand at 2,9 mbbls.


The Prinos North structure had been initially identified as a potential exploration opportunity in 1976, when the Prinos-4 (P-4) delineation well encountered small quantities of oil to the north of the Prinos oil field.

This led to the acquisition of 3D seismic data in 1993 and the drilling of Prinos North-2 (PN-2) exploration well in 1994, which discovered the main field, as well as a second deeper and thinner sandstone reservoir, called the Delta prospect.

Prinos North was appraised and developed as a satellite field to Prinos by an extended reach horizontal well, PNA-H1, in 1996. In 1997, PNA-H1 was brought in production and produced until 2004 at initial rate of 3,000 bbls/d with an interruption during the period 1998-1999 when a decline set in on water breakthrough.

At the time of field shut-in in late 1998 the well was producing some 1,500 stb/d at a water cut of some 50 per cent. On the resumption of production the well continued declining to ca 300 stb/d at a water cut of some 80 per cent when it was closed in for side-track in 2004.

Following the unsuccessful side-track in 2004, an extended reach well, PNA-H3, was successfully drilled by Energean in 2009, through a challenging operation due to the geological complexity of the targeted reservoir.

The well reached a total depth of 4,370 m, with a 358 m horizontal section into the reservoir.
The production started at initial rates of more than 1500 bopd, but it declined to less than 200 bopd, until its new increase after the interventions conducted during Q1 2016.

South Kavala

On November 2015, Energean was awarded a 3-year (2+1) extension in the duration of South Kavala license and has been preparing a new development plan for the period 2017-2019 that will cost approximately US $1.5 million.

The project is under evaluation and includes the installation of down-hole pumps in two of the existing wells to remove liquids from the well bores and will enable the field to be placed back into continuous production, increase condensate yields and bring recovery eventually up to 98.5%, as the remaining gas reserves are approximately 2.6 Bcf.

The depleted field is suitable to be converted into an Underground Gas Storage (UGS) linked to the TAP pipeline that will transit Greece 2km from Energean’s onshore processing plant.

Energean has submitted on 1st July 2011 to the Regulatory Authority of Energy (RAE) an application for the acquisition of a license that permits the installation of the storage and the conversion of the almost depleted field into a UGS. This development is on hold awaiting approval from the Greek government. Conversion to UGS would require an investment of approximately initially estimated at US $400 million.


The South Kavala Field was discovered by SK-1, the first exploration well drilled in the Basin in 1972, in the same initial exploration campaign that found the main Prinos oil field and Zeta. The structure was confirmed by 6 more exploration and appraisal wells. It was developed in parallel to Prinos as a remote satellite during the period 1979-1980. Two producing wells are active since then, with an average total depth of 2,050 meters.

A single well jacket was installed and linked back to Prinos with a 12” pipeline. South Kavala contained approximately 1 BCM of sweet, lean gas. It was developed to supply fuel gas to Prinos and the onshore plant. In the 1990’s wellhead compression was added to the jacket to maintain production.


Energean Israel, is the Operator of the Karish and Tanin leases, offshore Israel, having a 100% working interest. The Karish and Tanin fields are world class assets with 2,4 TCF of natural gas (contingent resources) and more than 20 million barrels of light oil (contingent and perspective resources).

In February 2017, Kerogen Capital, a private equity fund manager focused on oil & gas, agreed to invest 50 million dollars in Energean Israel and to participate with 50% in the company, subject to the approval of the deal by the Israeli authorities.

Energean Israel has planned to develop the two fields with an FPSO and to invest US$ 1,3-1,5 billion to first gas, which is expected by early 2020. Energean has committed to submitting a Field Development Plan to the Israeli Government by mid 2017. The company estimates that it needs sale contracts of 3BCM annually in order to take Final Investment Decision.

The gas that will be produced from the Karish and Tanin reservoirs is intended for the domestic Israeli market. The Israeli economy is growing at a fast pace (2,8% in 2015, 3,2% in Q3 2016, according to Bank of Israel) while the electricity consumption is expected to increase between 2% and 3% annually for the next decade.

Assuming a modest 2% annual electricity consumption growth, the Israeli economy will need an additional 300 MW capacity annually, which will be supplied by natural gas and renewables.

The fields

The Tanin and Karish fields are located in the north of Israel’s exclusive economic zone (EEZ), in water depths exceeding 1,700 meters and approximately 40 km from each other. They were discovered by Noblew in the Levantine Basin in 2012 and 2013:
– Karish-1 proved 2 Tcf GIIP
– Tanin-1 proved 1.2 Tcf GIIP
– Karish C sands represent THE first significant offshore oil discovery
The Karish field was mapped from 3D seismic based upon amplitude anomaly. Discovered GWC conforms to the anomaly and matches the seismic flat spot. The Tanin field was mapped based upon 3D amplitude anomaly.

Both fields are part of the prolific Early –Miocene Tamar Sands play. The fields are located north of the Tamar field, in water depths exceeding 1700m. Discovery wells de-risk adjacent prospective fault blocks which represent a significant upside;
– Karish lease: 0.5 Tcf in Karish North
– Tanin lease: 0.8 Tcf in Eastern fault blocks

Deeper targets in Jurassic have been identified below Karish and Tanin blocks. The Latter extends below the Leviathan discovery, while Jurassic is expected to be thermogenic oil play


Karish-1 was spudded on 21 March 2013 and reached a total depth of 4,812 m. The drilling lasted 77 days and discovered 135 m gross gas column with 72 m of net pay over three Tamar A-B-C Sands (90% of net pay in C-Sand).

Tanin-1 was spudded on 9 Dec 2011 and reached a total depth of 5504 meters. It lasted 88 days and discovered 31m gross gas column with 24 m of net pay in two Tamar (A and B) Sands (55% of net pay in A-Sand).

Both Karish -1 and Tanin -1 wells are abandoned over the reservoir interval, but it is available to be sidetracked.

30-year Leases (10-year option extension) were granted in November 2014 covering the field plus adjacent exploration targets, without gas export rights.

In August 2016, Energean bought from Delek Drilling and Avner the Karish and Tanin natural gas fields, offshore Israel, and four months later the company was granted approval by the Israeli Government which transferred the two Leases to Energean israel, a group’s subsidiary.


Prinos 2P reserves stand at 20,8 mbbls, while according to the new geo-cellular model of Prinos reservoir, STOIIP is estimated at 289 MMstb (38% recovery factor), 85% of which coming from A1 and A2 sands.

On December 2015 and in the context of the new Prinos License Area development programme, the first well (well PA-35A) that was drilled from Alpha Platform came on stream.

Energean has already completed the drilling of six wells from the Alpha platform in Prinos and plans to proceed with drilling from the Beta platform.

The execution of the drilling programme as well as small interventions and re-completions are expected to further increase production from the Prinos Oil Field which averaged 3,177 bopd in 2016.


The Epsilon Oil Field has 17,4 mmboe 2P reserves which have been audited by ERC Equipoise.

Energean has planned to develop the field through a new development project which consists of:
– The design, fabrication, installation, commissioning and subsequent operation of a new well-head jacket platform (called “Lamda”) approximately 3.5 km’s NW of the existing Prinos platforms. Lamda has been designed to be normally unmanned.
-The installation of three sub-marine pipelines that connect Lamda to Prinos Delta.
-The drilling of 5- 9 wells.

This new development plan will cost approximately $50 million for the jacket and pipelines and approximately $60 million for the wells.


Exploration activity in the Epsilon field area began in the 1990s, when the anticlinic Epsilon structure was identified by interpretation of 2D seismic data. The area remained a low priority, and was only partially covered by the 1993 3D seismic cube. The 3D seismic survey acquired in 1997 however, covered the whole area, and made it possible to map the structure, and consequently upgrade Epsilon as a high priority exploration target.

The field was discovered in 2000 when Well E-1 tested sour crude oil with an API gravity of 36 degrees in reservoirs belonging to the Prinos Group at a depth of about 2800 m TVDSS.  The well was side-tracked a year later to a location some 500 meters to the south east, confirming the reservoir presence and tested oil.

Energean drilled an extended reach multi -lateral well, EA-H1, which was successfully completed in January of 2010 and produced for a 12 month period cumulative oil production over 0.3 MMbbls. The length of the well reached 5,297 m, with more than 450 m horizontal section of each leg, being thus far the longest well in the Mediterranean.

A geophysical campaign took place in Q3 2015 as part of the Epsilon development project. A detailed bathymetry survey of the area affected by the Epsilon project was conducted and used as input for both the design and ESIA work stream.


On November 2016, Energean and the Greek Greek Ministry of Energy agreed the conversion of the exploration license for the proven West Katakolon offshore field to a 25-year exploitation license. The West Katakolon Exploitation area is part of the Katakolon Concession Area and covers a 60km2 area with circa 10mmbbls recoverable oil and 35-40mmbls STOIP.

Energean is the operator of the field development. A Field Development Plan (FDP) and an Environmental and Social Impact Assessment will be submitted to the Ministry of Energy by the end of February 2017.

Drilling is planned for 2019. Energean will use Extended Reach Drilling (ERD) technology to drill from onshore to offshore reservoirs, in a similar manner to several wells Energean has drilled in Prinos (Greece) and the Gulf of Suez in Egypt (East Magawish).

The programme includes also the building of roads and the installation of the necessary facilities (storage deposits, buoy etc.). The total investment for the development of the field is estimated to be US$ 50 million.

West Katakolon is the third oil and gas field to go into development in Greece, following on from the Prinos Oil Field and South Kavala Natural Gas Field, both located offshore in the North Aegean Sea. Both of these fields are operated by Energean.

The field

The Katakolo license covers onshore, shallow water and deep water acreage on the west coast of the Peloponnese. The block, 545 km2 both offshore and onshore, contains 3 discoveries and multiple leads. The water depth is 200 – 300m while the depth of the reservoir is 2,300-2,600m.

The field contains approximately 180m of sour gas underlain by an oil rim of approximately 120m in a large carbonate structure with further undrilled deeper potential. There are 2 biogenic gas discoveries onshore from a drilling campaign undertaken in the 1960’s.

The West Katakolon reservoir is believed to be a dual porosity system (matrix, fractures and vugs), with an overlaying gas cap and an underlying aquifer.

The wider onshore area was first drilled Katakolo-1 well) in 1939. Thirteen onshore wells followed until 1984, finding oil and gas in most cases, while three wells went dry.

The Katakolo discovery was made by the Greek State Oil company just off the coast of Peloponnese in the Ionian Sea in 1981 through the drilling of the West Katakolo -1 well. The well tested gas and condensate in fractured Eocene and older carbonates, which lie unconformably below thick Pliocene shales. West Katakolo-1 was followed by West Katakolo -1A and South Katakolo -1 wells, which found oil.

A second well (West Katakolo-2) in 1982 tested oil from two zones with flow rates 1200 – 1400 BOPD. The oil gravity is 26 – 28 API. In the same year, South Katakolo 1A well found gas.

A 3D seismic survey was acquired in 1984 and since then there was no activity, until thirty years later, when Energean was awarded the block.

Energean has been exploring the block since October 2014, after the ratification by the Greek Parliament of the License Agreement signed with the Greek State on May 14th 2014. The company declared commerciality for the field after having finalized the reprocessing and interpretation of the existing 3D seismic data.

Prinos North

In Prinos North, 3,3 mmbo 2P reserves have been independently audited, while STOIIP is 16mboe with a recovery factor of just 24%. A new development well will be drilled in 2017 which will add a further $ 8 million of investment.

The new well will increase production to above 2,000 bopd from the current 400-500 bopd.

Energean has also developed a field development plan for the Prinos North Area that requires a new satellite platform (Omicron) to be installed.

The envisaged new satellite development plan would cost approximately $32 million and from this platform four additional Prinos North wells will be drilled. Ten additional wells may also be drilled from this platform into undeveloped discoveries Zeta and Delta and exploration prospect Alpha.

The commerciality of this project will be confirmed following appraisal drilling of Zeta in 2017.

Prinos Basin

Energean conducted a 340 km2 broadband 3D seismic survey over the Prinos Oil Field and its surrounding licenses in the Gulf of Kavala during the summer 2015. The survey also included a complex undershooting operation in the vicinity of the Prinos offshore platform.

The Fast Track processed seismic dataset was available within two months of the seismic acquisition operation being concluded. The final processed 3D cube was completed during the summer 2016 and the seismic interpretation including Quantitative Interpretation and PSDM imaging is currently ongoing.

This new, state of the art, high resolution 3D seismic data will enable Energean to optimize the location of future development wells within the main Prinos Field and the nearby Epsilon and Prinos North satellite oil fields. During the period 2017-2018 a total of more than 10 development wells are planned to be drilled.

In addition the new seismic is being used to further evaluate existing prospects and leads and to identify new exploration opportunities, with the objective of increasing the contingent and prospective hydrocarbon resources within the Prinos Basin.

The new targets

Energean’s G&G team has already identified the following three appraisal opportunities, named Kazaviti, Athos and Delta.
• Kazaviti was recently drilled by deepening a Prinos development well which discovered sweet oil within a 7 m sandstone layer with no indication of a contact. The sands are thought to be stratigraphically trapped and the area is currently being further evaluated.
• Athos is a sweet oil discovery made in 1983 which is poorly imaged on the historical seismic data. The prospect is being re-evaluated using the new 3D seismic data.
• Delta was discovered in and tested sour oil from a stratigraphic deeper level than Prinos North field. It was poorly imaged on the old seismic data, thus the prospect is currently under evaluation, using the new 3D seismic data.
New exploration prospects have also been identified and booked as prospective resources, these include Omicron, Alpha and SE Prinos (B&C).
• Omicron prospect is a stratigraphic trap identified as an AVO anomaly laying at the Evaporitic Sequence. It shows similarities with the adjacent South Kavala sweet Gas field.
• Alpha prospect is a fault bounded 3way dip closure located adjacent to the Prinos North field. The main reservoir unit comprise sandstones of the Prinos group and its proximity to the reservoir at Prinos North suggests similar rock characteristics, and the same OWC level and drive.
• SE Prinos comprises a stacked 4 way dip closure structure on the equivalent B and C reservoir units which are producing at the Prinos oil field. The prospect can be drilled from the existing platform facilities and given discovery developed as a tie back to the existing production facilities.


On March 31st 2017, Energean agreed to farm -out to Repsol a 60% working interest in the Ioannina block, Western Greece. Repsol will be the operator and plans to acquire a 2D seismic survey over the block in 2017/2018.

In August 2015, Energean acquired a high resolution Airborn Gravity Gradiometry (AGG) survey which included acquiring aeromagnetic data and high resolution digital elevation mapping as part of the exploration work programme.

The purpose of this data was to identify Areas Of Interest (AOI) for hydrocarbon exploration in advance of the 2D seismic acquisition programme planned for 2017/2018.

The block is an under explored (less than 1500 Km 2D seismic and only one well drilled during the last 25 years) area of 4,187 km2.

The block

The Ioannina block is located onshore Western Greece and is part of the Hellinide fold belt, which hosts the prolific Ioanian Basin and Apulian platform and are on trend with recent large discoveries made in Albania. In total over 10 billion barrels of oil and 30 TCF of gas have been discovered throughout this region primarily in Albania, Italy and Croatia.

The proven, productive oil play(s) of the Ionian Basin onshore Albania extend south into the Energean Ioannina Block, where they remain substantially underexplored. It should be noted that Royal Dutch Shell has acquired the neighbouring “Block 4” in Albania. Significant potential can be demonstrated in the “classic” thrusted Mesozoic carbonates play productive in Albania, and in the Apulian sub-thrust play similar to onshore Southern Italy. Numerous oil seeps are well documented throughout the block area which have been typed to the known source rocks.

Exploration History

The Ioannina block was initially explored by the Italian Army during World War II. During the 60’s, the Greek State and IFP drilled two dry wells.

Eight State operated exploration wells drilled in the 1980’s have encountered oil and gas shows throughout the Mesozoic section, as well as drilling thick sections of high quality potential source rocks in the Cretaceous, Jurassic, and Triassic. During this period, approximately 1,000 kilometers seismic lines (2D) were acquired.

The last concession holder was Enterprise Oil, which relinquished the block in 2001 after the unsuccessful drilling of the exploration well “Dimitra”. Enteprise Oil was later acquired by Royal Dutch Shell.

A post mortem evaluation of the wells drilled to date indicates that no valid traps were tested and this is considered the main reason for the dry holes. Due to the complex subsurface geology the data quality of the vintage seismic is extremely poor which makes identification of traps extremely difficult. Recent seismic reprocessing has dramatically improved the image quality which allows the identification of previously unseen prospects and leads.

Energean has been exploring the block since October 2014, after the ratification by the Greek Parliament of the License Agreement signed with the Greek State on May 14th 2014.


In March 2017, Energean Oil & Gas signed a Concession Agreement with the State of Montenegro about hydrocarbons exploration and exploitation in offshore blocks 4219-26 and 4218-30.

The two blocks are located offshore at a water depth of 50-100 meters, close to the Montenegrin coast in the vicinity of the town of Bar.

Total investment over an exploration period of seven years will be US$ 19 million, including the funding of a new 3D seismic survey, geophysical and geological studies, and the drilling of one well.

Energean plans to begin the 3D seismic acquisition during the first quarter of 2018.

The company believes Montenegro may sit in the “sweet spot” of an untapped, under explored potential in the eastern Adriatic.

The Adriatic Region

The eastern Adriatic remains substantially underexplored, despite having what appears to be all the necessary hydrocarbon generating components in place and that the western offshore Adriatic has been a prolific hydrocarbon producing province for over 50 years for both oil (Italy) and biogenic gas (Italy and Croatia).

The widespread distribution of seeps and oil shows in the region indicates the presence of an active petroleum system. Large prospects and leads, comprising Cretaceous age carbonate reservoirs, have been identified in offshore Montenegro that lie on trend with recent oil discoveries in northern Albania such as the onshore Shpirag-2 discovery. To date over 5 billion barrels of in place oil has been discovered in Albania within this prolific carbonate play.

In addition to the carbonate oil play, the Tertiary age sandstones in offshore Montenegro are considered highly prospective for biogenic gas. The biogenic gas play is prolific in the analog Po Basin of offshore northern Italy / Croatia where over 30 TCFGIP have been discovered. The play has been proven in the Duresi basin offshore Albania and Italy, but to date only limited exploration drilling has been carried out in offshore Montenegro.

Future 3D seismic acquisition will be key in identifying and drilling the most attractive prospects in order to unlock the true potential of this play.

Exploration history

Montenegro covers a total surface area of 21,500km2, including 8,500km2 in the offshore. To date only 20 exploration wells have been drilled, 16 wells in the onshore and 4 wells offshore.

Initial exploration activity took place from 1949 – 1966 which resulted in the drilling of 16 onshore exploration wells by the state company Nafta Crne Gore. The well locations were chosen primarily using surface geology mapping and are not considered to be optimally located. As a result no discoveries were made despite the presence of oil and gas shows in several wells drilled.

In 1973 the responsibility for exploration for hydrocarbons in Montenegro was taken over by the government-owned Jugopetrol Kotor, which was primarily engaged in downstream activities. In cooperation with foreign oil companies, Jugopetrol Kotor acquired in the offshore region over 10,000 km 2D seismic and 400km2 3D seismic. In addition approximately 1,250 km of onshore 2D seismic data was also acquired.

Three offshore and one nearshore well were drilled between 1975 and 1991 targeting basinal and platform carbonates. The JJ-1 well (TD @ 4.700m) found significant quantities of natural gas within the clastic deposits of the Oligocene. The JJ-3 well recovered 183bbls of 24deg API mobile oil from Cretaceous age shelfal carbonates. In addition all offshore wells had significant gas shows in Lower Tertiary sands but were not tested.

Due to the complex structural geology the seismic imaging remains a challenging issue particularly for the Cretaceous carbonate structures. As a result all 4 offshore wells are not considered to have tested the full potential of the carbonate structures. New state of the art 3D seismic acquisition and processing should enable new prospects and leads to be identified and drilled that were previously unrecognized.

In May 2014, Energean Oil and Gas submitted a bid in the context of Montenegro’s First Round for Production Concession Contracts for offshore hydrocarbons exploration and exploitation. The company reached an agreement with the Ministry of Economy of Montenegro in June 2016 and six months later the agreement was ratified by the Montenegrin parliament.


West Kom Ombo is an exploration block in Upper Egypt, which is in its second exploration period and covers an area of 20,948 sq km after the first period relinquishment.

In Q1 2016, ahead of the drilling of two exploration wells (2/2017), Energean conducted a 2D seismic survey and acquired 400 km of data, bringing the total coverage on the block to 2000 Km.

Preliminary processing results and interpretation on Line 50001 (see picture on the left) showed well pronounced prospective structure developments within the well identified interior rift system at the northern part of the Concession.

The new integrated study over the Sin El Kaddab interior/ Lacustrinal Rift System at the southern part of the concession, showed a well developed thick sedimentary sequence, partially deeper than the adjacent oil producing Kom Ombo Rift system.

One large prospective structure was seismically mapped over a deep seated/ well pronounced paleo-Magnetic 4-ways dip closure.

The mapped drilling location is surrounded by adjacent synclines that are thought to contain potential mature late Paleozoic-Jurassic source rocks.

Several additional prospects/leads have been identified within the vicinity of the Sin El Kaddab rift, indicating significant upside potential given the presence of a proven play.

Exploration history

Energean acquired a block wide high resolution aeromagnetic survey together with 700 km of 2D seismic and drilled two wells during the first and second exploration period (2010 – 2014).

Both wells encountered good quality reservoir sands (25-30% porosity ) however the local presence of mature source rocks is considered the main reason for failure.

Energean was awarded an extension to the second exploration period in January 2015 during which an additional 400 km of seismic was acquired. The third well on the block (Apis-1) was spudded in May 2017 to test the a large structure within the Sin El Kaddab rift basin.


On March 31st 2017, Energean agreed to farm -out to Repsol a 60% working interest in the Ioannina block, Western Greece. Repsol will be the operator. Energean has signed a Lease Agreement with the Greek Government for oil & gas exploration on the block, in the context of the Western Greece Onshore Licensing Round.

The farm-out agreement is subject to the approval of the Greek Government.

In the first exploration phase, basic environmental studies will be implemented, as well as geological and geophysical survey, including a Full Tension Gravity Gradiometry survey and a 2D 400-km seismic survey (2018/2019)

Aitoloakarnania is a large underexplored block of 4,360 km2.

The block

The Aitoloakarnania block is located onshore Western Greece and is part of the Hellinide fold belt, which hosts the prolific Ioanian Basin and Apulian platform and are on trend with recent large discoveries made in Albania. In total over 10 billion barrels of oil and 30 TCF of gas have been discovered throughout this region primarily in Albania, Italy and Croatia.

Over 10 billion barrels of oil and 30 trillion cubic feet of gas have been discovered in place associated with the hydrocarbon systems throughout this area. Moreover, Jurassic oil recovered on Paxi Island.


Eight wells have been drilled in the block to date. In the early 1960’s BP targeted a Triassic evaporite target that tested small quantities of 37 deg oil during on test at ~4000m.

During the period 1999 – 2000, Triton drilled two shallow commitment wells (TD at ~ 1500 m) which failed to test viable prospects. The block remains significantly underexplored, with very large areas of evaporite at outcrops which indicate sub-evaporite targets, in addition exploration potential associated with Ionian Zone carbonates thrust structures is also recognized.

Other Projects

Energean Oil and Gas has submitted on 1st July 2011 to the Regulatory Authority of Energy (RAE) an application for the acquisition of a license that permits the installation of the storage and the conversion of the almost depleted field of South Kavala into an underground gas storage in accordance to the Law No 3428/2005 (relates to the release of the natural gas market in Greece).

Key characteristics

• Investment of €350 -400MM

• Working gas volume 530×2 MCM, with annual Working gas volume 1 BCM, delivery of minimum 2 cycles per year, with a duration of up to 90 days

• Maximum injection 7 mln m3/day

• Pipeline gas for fill-up and operations

• Existing Kappa Platform with new 32 km high capacity pipeline to Sigma site

• 5 wells; 7″ completion; min THP 18 bar

South Kavala is considered a strategic location for the stability of the country and region’s energy supply. The UGS project was adopted by the European Commission as a Project of Common Interest under Regulation (EU) No 347/2013 on Guidelines for trans-European energy infrastructure, but since there are no decision from the Greek State, the project is now frozen.


The Prinos oil field covers an area of approximately 4 km2 and it is located offshore in the Gulf of Kavala, 8 km west of the island of Thassos and 18 km south from the main coast. The main facilities of the companies consist of:

• The Prinos Platform Complex (two production platforms «Alpha» and «Beta», one processing platform «Delta», one flare structure and inter-connecting bridges).
• The South Kavala gas production platform «Kappa».
• The oil and gas transport pipelines.
• The onshore processing and storage facilities in Nea Karvali, the «Sigma Plant».
• The crude oil loading terminal and mooring facilities.

The Prinos platform complex is located at the center of the field. The offshore installation consists of:

Two four-leg production platforms, Alpha and Beta. Each platform can accommodate 12 wells and is compatible with a jack-up rig, work-over rig and service rig. Today there are 18 active production wells, 3 water injection wells for reservoir pressure support and 3 inactive wells. At all times there is a work-over rig on one of the platforms and a service rig on the other platform.

An 8-leg processing platform Delta, with the necessary equipment for the following functions:

1. Three phase (oil, gas and water) production separation (at 15 barg and 85 deg C).
2. Test separator, for measuring the production performance of each well (15 barg and 85 deg C).
3. Crude dehydration (15,5 barg and 80 deg C).
4. Crude oil transfer to shore, with high pressure pump via an 8” submarine pipeline.
5. Sour gas dehydration with TEG (14 barg and 50 deg C), for the protection of the 12” submarine pipeline from corrosion.
6. Treatment of waste water for disposal (de oiling and stripping).
7. Sea water injection in to the reservoir (300 barg), for Prinos reservoir pressure support.
8. Injection of sweet natural gas into the producing wells (90-120 barg and 100 deg C) for gas lifting (enhanced oil recovery).

South Kavala Gas Facilities-Kappa Platform

The South Kavala Gas field, an almost depleted gas field, is located offshore in the Gulf of Kavala and produces gas with more than 80% methane. The reservoir is at a depth of 1700 metres, and the sea depth in the area is about 51 metres.

The four leg platform, designated as Kappa, is 12 km southwest of the Prinos platforms, is the same design as Alpha and Beta platforms of the Prinos Platform Complex. It accommodates two wells and is compatible with drilling, workover and service rigs.

It is equipped with three-phase separation facilities, a gas booster compressor unit and a TEG gas dehydration unit. The platform has two deck levels; the lower deck contains a topsides completion system, a dehydration unit and the wellheads. The upper drilling deck has cabin style quarters and diesel power generation facilities.

The gas is dehydrated and then exported to the offshore oil production platform at Prinos, where the gas is used for fuel and gas lift.

At present the gas well head operating pressure is 4 barg, while the gas leaves the platform and enters the 6” submarine pipeline at 12 barg and 30 degrees centigrade. Total annual production is 1,7mcm.


The processing plant, designated as Sigma, is located 14 km east of the city of Kavala and 18 km north of the Prinos platform complex. It consists of facilities for the final processing of the oil and gas streams, from the offshore facilities, into stabilized crude oil, natural gas, natural gas liquid and elemental sulphur.


The major processing areas are:

1. Crude oil desalination and dehydration (20 barg and 80 deg C).

2. Low pressure separation (8 barg and 75 deg C).

3. Crude oil stabilization (reboiler at 160 deg C and 2.5 barg).

4. Stabilized crude oil storage and shipping (three floating roof tanks with total storage capacity of 500,000 bbls).

5. Gas treating (DGA contactor at 7 barg and 80 deg C).

6. Natural gas liquid recovery (gas and liquid dehydrators, gas cooling and chilling to -25 deg C and a de-ethanizer operating at 4 barg and 10 deg C overhead conditions).

7. Sulphur Plant and sulphur storage facilities (two Claus units in parallel with 95% conversion of H2S to sulpfur, three Sulfreen type batch reactors with an overall H2S conversion of 99.2%, two liquid sulphur pits, one liquid sulphur storage tank, liquid sulphur loading facilities and a sulphur granulating unit).

8. Residue gas compression and recycling offshore for gas lifting (30-40 barg).

Drilling Rig

Energean Oil & Gas bought from KCA Deutag the self-erecting drilling tender rig “Glen Esk” on August, 2014.

The rig is renamed “Energean Force” and it is going to execute a 15-well drilling programme in Kavala Gulf, N.E. Greece. The rig has hull dimensions 321 ft. x 70 ft. x 34,5 ft and it is designed for water depth between 40 ft and 656 ft. while it can drill wells with a maximum depth of 20, 000 ft.

It has an 8 anchors mooring system, a hoisting capacity of 1000 kips and 2000 HP draw works and it is able to accommodate 116 persons. It’s helideck is Sigorsky S-61N and S-92.

“Energean Force” carries two cranes, with rating capacity 100 mt. and 20 mt. each and can operate at a maximum wave of 8,2 ft. at 11 sec. and at a maximum wave speed of 40 knots.


Offshore supply ship “Valiant Energy” supports Energean Oil & Gas’ ongoing investment programme in the Gulf of Kavala.

“Valiant Energy”, which was constructed in Norway according to DNV’s standards and has participated in oil & gas activities in the North Sea, is the first supply ship of this size and standard ever to arrive in Greece. It is 62,5 meters long and It carries modern fire-fighting systems (FF3 water, FF2 foam) and can pump 7,500 cubic meters of water per hour.

It is able to support any drilling program (supply and carry platforms, equipment and material transportation to platforms and to jack – ups etc.) and participate in anti-pollution and rescue operations as well, as it can collect and treat 155 persons on board.

“Valiant Energy” has a DWT of 1,800 tons and a crew of 22 persons.


Six pipelines are used for the transport of hydrocarbons as follows:

• 6” submarine pipeline of 12 kilometres length for the transfer of dehydrated sweet natural gas from Kappa to Delta platform (operating pressure of 10 barg).

• 12” submarine pipeline of 18 kilometres length for the transfer of dehydrated sour natural gas from Delta platform to the onshore facilities (operating pressure of 8 barg).

• 8” submarine pipeline of 18 kilometres length for the transfer of dehydrated sour crude oil from Delta platform to the onshore facilities (operating pressure of 25-40 barg).

• 5,3” submarine pipeline of 18 kilometres length for the transfer of dehydrated sweet natural gas from the onshore facilities to Delta platform for gas lifting the production wells (operating pressure of 20-40 barg).

• 6” underground pipeline of 7 kilometres length for the transfer of dehydrated natural gas from the network of PUBLIC GAS CORPORATION, at PFI facilities, to the onshore facilities (operating pressure of 30-40 barg).

• 24” submarine pipeline of 3 kilometres length for the transfer of stabilized crude oil from the storage tanks to the tanker compartments (operating pressure of 12 barg).

• 16” submarine pipeline of 3 kilometres length for the transfer of ballast from the tanker compartments to the onshore ballast storage tank (operating pressure of 12 barg).

Auxiliary systems

The following auxiliary process systems support the operations:

• Flare system (hydrocarbon and acid gas flare collection headers and blow-down drums).

• Process liquid drainage system and network.

• Nitrogen and purge gas supply and distribution system.

• Firewater pump station and distribution network. Instrument and Utility gas system.

• Drinkable water system.

• Breathing air system.

• Electrical substation.

• Sulphuric acid and caustic soda storage and supply system.

• Steam generation and distribution system and condensate recovery.

• Electrical power generation.

• Fuel gas system.

• Seawater cooling system.

• Water demineralization unit for BFW.

• Sour water treating.

• Ballast and oily water storage and treating facilities.


The plant operation and maintenance is also supported by the following essential services:

• Electrical and Instrument shop.

• Two Warehouses and a Warehouse Yard.

• Mechanical shop.

• Welding shop.

• Mooring Facilities (3 km from «Sigma» shore).

• Dock with harbour facilities with a pedestal crane.

• Three office buildings.

• Guard house.

• A tank-truck Weighing Scale.

• Supply boat «Epsilon».

• Two Crew boats («AKRA PRINOS» and «SKALA PRINOS»).

• A barge («LIMIN PRINOS»).


A new Self-Installing Platform (SIP 2) planned to be installed (2017, 2Η) for the Epsilon Oil Field development in the Gulf of Kavala. A feed study has been performed by SPT Offshore which has developed a basic design for the facility, incorporating the requirement to support the Energean Force tender assist rig drilling program.

The new SIP-2 concept is a four leg platform suitable for water depths ranging from 10 to 60m, founded on suction piles and can accommodate a topside weight of up to 8,000 mT. The platform is transported to the field on a flat top cargo barge with the legs jacked-up. The concept is very similar to that of a jack up rig, with the exception that the platform is not self-floating, and requires a barge to be transported to the field. Once on location, the legs and suction piles are lowered to the seabed and the deck is jacked up along the legs using strand jacks. The platform in its later life may also be relocated to another field by reversing the installation technique.

The installation of the SIP is a part of Energean’s new 200-million-dollar investment programme. The SIP will be named “Lamda” and will contain slots to allow up to 15 wells to be drilled. The basic design of the SIP-2 is being carried out by SPT Offshore. Energean has also developed a full field plan to connect the greenfield facilities to the existing offshore processing facility (Prinos Delta), including j-tube and riser retrofits.

The construction and fabrication contracts will be tendered by Energean during the 3Q of 2016 and it is expected that the platform will be built mainly in Greece.