Levantine Basin

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Location, Basin History, Ownership

The Levantine Basin is located in the eastern Mediterranean Sea off the coast of Israel. Specifically, the main discovery of this basin is the Leviathan Gas Field. The water depth averages 1600m or roughly 5250ft. Drilling started in 2010 by Houston-based Noble Energy which contracted drilling operations to Transocean[1]. The basin is estimated to hold recoverable reserves of 122 trillion cubic feet (Tcf) of gas with 1.7 billion barrels of oil (Bbbl)[1]. Since the commercialization of this field is relatively recent, new aspects are being discovered every year.

Several countries surround the Basin which complicates ownership claims. International oil and gas mineral rights are subject to different legal considerations compared to domestic jurisdictions. Chevron, which acquired Noble in 2020, owns roughly 39.66% of the drilling and exploration rights while Israel-based Delek Group’s subsidiaries Delek Drilling and Avner Oil Exploration each own 22.67%. Israel's Ratio Oil Exploration owns 15%[2]. Israel's mineral reserves estimate to more than 35 Tcf of gas, the largest of all the countries. Cyprus has total estimate reserves of approximately 7 Tcf, Gaza (controlled by the Palestinian Authority) obtains 1.1 Tcf and Lebanon holds 30 Tcf[3]. The other mineral owners include Egypt and Syria. However, these two countries have their own fields that equate to higher and more prolific amounts than their share of the Levantine Basin.

Location of the Levantine Basin in respect to neighboring countries. Fault traces, gas location, and other known exploration variables are described.[4]


Relative description of Levantine basin as a cross-sectional map area.[5]

The geology of the Levantine Basin has been studied significantly for being a recently discovered field. 3-D seismic data has been widely used to determine where formations are located, faults, traps, and other distinguishable geologic features. Due to the size of the basin and the amount of hydrocarbons in place, this allows for companies to invest in extensive geologic work to better analyze the reservoirs present. The geologic aspects to consider are the time and rate of deposition, trap, seal, reservoir and potential migration path.

Depositional History

During the late Paleozoic and Early Mesozoic time period, significant rifting took place in what is now the eastern Mediterranean Sea region. This created the opening and closing of the Neo-Tethyan sea, which was an ancient sea that separated and closed the continental plates of the African and Arabian plates[6]. Such rifting during this time period created approximately 15 km of accommodation for sediment to settle. This amount of accommodation created multiple reservoir rocks and seals. The rate of deposition was relatively constant until 10 million years ago when the rate of deposition increased[7]. Although the reservoir rocks were not deposited rapidly, the depth at which they were deposited created the large gas field due to excessive temperatures.

Depositional history for the Levantine Basin with the opening and closing of the sea over millions of years[8].

Source Rock

Since the Levantine Basin's discovery just over a decade ago, there have been minimal studies performed on potential source rock areas. There has not been enough time to study The Basin due to its offshore location and being a relatively new discovery.  Further, the high the cost of obtaining core samples has made companies reluctant to make these investments. However, there have been a few studies that have shown potential source rock areas. The cores that have been obtained have all undergone rock eval pyrolysis. According to Grohmann et al the source rocks studied were deposited during the lower to upper Cretaceous time period or during the Mesozoic Era. The source rocks indicated an average of roughly 0.9% - 4.8% weight total organic carbon (TOC) with a hydrogen index of around 400 HC/g TOC. By rock eval pyrolysis, it was determined that the source rock is Type II or exinite with both oil and gas potential due to its marine and terrestrial material composition. The source rock itself was determine to be mostly carbonate form varying from 12% - 99% of the total weight of the rock[9].


Between the source rock and the migration route, these are the two challenging factors to determine in a petroleum system. Tracing the migration route from the source rock to the reservoir rock is challenging. One potential and costly way to obtain this knowledge is 4-D seismic data. Obtaining 3-D seismic data over a period of many years can be useful for tracking potential migration paths. Although there has not been any 4-D seismic data acquisition on the Levantine Basin yet, there will most likely be some in the future due to its potential production output. Other than the high cost, the only aspect not allowing for 4-D seismic data to be conducted is time, hence the 4th dimension. Hypothesis have been made about the potential migration paths taken from the source rock to the reservoir rock. The source rocks contained in the upper Cretaceous potion are believed to have migrated vertically through other permeably beds, such as more carbonate rocks, and then up through fault cracks through mud rocks or shale[10]. Similarly, the lower Cretaceous source rock is believed to also migrate hydrocarbons vertically through fault cracks and other permeable carrier beds to the source rock.

Reservoir Rock

Rock type

Porosity, permeability, and pressure profile of the western portion of the Levantine Basin. Most of the productive zone is over pressured with a high pressure profile[11].

There are primarily three different reservoir rock types of the Basin. First, is a sandstone from the lower Cretaceous Yafe Formation.  However, there is not a significant amount of production and proven reserves within this reservoir rock[10]. The second reservoir rock present is a deeper sandstone that formed during the Jurassic time period. There is little knowledge to how hydrocarbon migration occurred to this reservoir but it is believed that this occurred from the limestone and shale above which can also act as a seal rock for the reservoir[10]. However, this rock is proved to have minimal hydrocarbons since it is not as thick as the main production zone and due to the depth at which it is located, there are concerns about temperature and the continuous cooking of gas. The third, and most prolific, reservoir rock is the Oligocene-Miocene turbidite sandstone.  This rock is the shallowest of the three, thickest, and poses the thickest and most laterally extensive seals on both the bottom and top of the reservoir[10]. Due to its proximity to the present day ocean bottom, it is most economical to drill in this zone due to drill depth, pressures, fault systems, and many more factors. Since this reservoir rock is the most prolific, most studies have come from this zone. Therefore, porosity, permeability, and resistivity numbers have been acquired.


There are two main types of porosity. The first being total porosity which refers to the total amount of void space in the rock. The second is effective porosity which is the amount of void space interconnected within a rock. It is important to note that porosity that is not connected through pathways and isolated results in no hydrocarbon production unless unnatural fractures are created. The Levantine Basin has a wide range of porosity values due to the cementation compaction of the sand. The values range from 4% - 22%[12]. Although it is nearly impossible to determine the effective porosity, average porosity values greater than 10% can be highly profitable due to the potential volume of hydrocarbons.


Permeability plays a significant role in production potential as it determines the fluid flow through the rock matrix. In the Levantine Basin, permeability values are high when the porosity is high. Although it may seem that there is a correlation between porosity and permeability, such as high porosity relates to high permeability, there is not. However, typically, permeability does correlate with porosity[11]. For this reason, permeability values range between 1000 millidarcy (md) - 2000md where the formation is not highly cemented[12]. However, where it is cemented, permeability values decrease drastically. The range of permeability values can make it difficult to determine where to drill but knowing seismic data and various geologic structures mitigates the error of low production if drilled into a prolific zone with low permeability.


Based on log values after drilling started, resistivity values were readily available throughout the main production zone of the Oligocene-Miocene turbidite sandstone. Using the resistivity log with the gamma ray log helped to determine where the hydrocarbon bearing zones were located in the basin. Gas bearing zones showed values as high as 200 ohm-m with investigation depths of 10 inches to 50 inches[12]. The water portions showed resistivity values around 1 with averages at 1.5 ohm-m. When determining the hydrocarbon bearing zones, the resistivity values ensured production would be accomplished in the correct areas of interest. Although there is a large volume of oil in place, the volume of gas overpowers the idea of oil for the most part.


The Levantine Basin is filled with multiple types of traps. The main two are structural and stratigraphic traps with the subdivisions of folds and faults for the structural traps and rock matrix changes and unconformities for stratigraphic traps. Due to the size of the basin and the formation, all of these traps exist making it a unique system to analyze and drill because no two parts are the same. During the formation of the basin, most of the structural traps formed during the early Cretaceous period while the stratigraphic traps formed during the upper Cretaceous and Paleogene time periods after the folding and faulting took place[7]. This is important because without the traps in place, by the time the hydrocarbons are migrating, there is no place for them to accumulate. According to Marlow, two discovery wells drilled within a relatively close distance of each other revealed the potential of more than 5 Tcf of gas being trapped by a salt structural trap[7]. Since the creation of the basin, due to rifting, this created a significant amount of normal faults. Some of the fault structures are growth faults however, most are normal faults creating large bodies of rock with the potential of storing hydrocarbons. These faults trap the hydrocarbons and keep them in place. Using seismic data, some of the stratigraphic traps studied showed pinch-outs and unconformities. Typically the pinch-outs were limestone with the surrounding rock matrix as shales or other impermeable layers. Similarly, unconformities were common but occurred in zones higher within the basin. This explains why much of the reservoir is deep because there were minimal unconformities found deeper within the basin allowing for sediments to deposit without being disturbed.


Since there are multiple zones of interest, there are also multiple seal rocks. The main seal rock of the upper most zone of interest is a mudstone that is laterally extensive and thick creating an impermeable barrier on both the upper and lower parts of the reservoir[10]. Relating this to the depositional environment, this would indicate that during the opening and closing of the sea, when the mudstone is present the deposits took place during deep sea burial. When the ocean started closing, the water became shallow creating the reservoir rock (Oligocene-Miocene turbidite sandstone) and when the ocean re-opened, more mudstone was created. It is important to examine the composition of seal rocks because it dictates the depositional environment after the reservoir rock was created. It also helps drilling engineers determine what type of mud should be used and pore pressure predictions. The only seal rock present is where the deepest reservoir rock is located and it is primarily a carbonate rock that also has the potential of being a source rock. Although not relatively typical, due to the depositional history and environment, this seal rock acts as two important systems.

Stratigraphic rock column of the southern portion of the Levantine Basin[13].

Engineering Risks and Uncertainties



Many risks must be considered when drilling in deep water formations. The first risk is pore pressures. Since the Oligocene-Miocene turbidite sandstone is the most productive zone, all the risks and uncertainty considerations will be focused around this zone. The sandstone is approximately 5,250 meters deep or 17,224.41 ft. Pore pressure estimates average around 75-80 MPa or 10,870 - 11,603 psi[7]. When considering pressures this great, it is important to maintain a mud weight adequate of combating pressures this high. When examining the simple bottom hole pressure calculation (BHP) = 0.052 * mud density * TVD, mud density values will need to equate to at least 13 pounds per gallon (ppg) to avoid a kick. By drilling on paper this can mitigate the error for not having the correct mud weight. If the mud weight is too high, the formation will be fractured causing a loss of drilling fluids and damage around the wellbore. If the pressure is too small, a kick will occur where an influx of reservoir fluids will enter the wellbore and could potentially cause a blowout.

Another risk that is associated with drilling is fault systems. Since the most of the main faults in the Levantine basin occur deeper and away from the main zone of production, this is not the highest concern.  However, growth faults within the basin can cause problems. By knowing seismic data, drilling engineers can steer the bit away from these faults. However, if one is hit, loss of fluids can occur and unknown overpressure areas can be present.

The final risk associated with drilling in deep-water, and especially the Levantine Basin, is the salt regimes imbed within the stratigraphic column of rock. Although typically not thick, there are areas that posses thick and laterally extensive salt areas. Although it is sometimes hard to avoid salt areas, at all cost drilling should not take place through a salt column. Typically in offshore drilling, the restrictions to mud types are regulated more than land-based operations due to greater environmental concerns. Using an oil-based mud would be most ideal as salt would not dissolve with contact. However, oil-based muds are typically not allowed in offshore drilling areas andsynthetic based muds are used instead. Although the muds are similar in properties, synthetic muds are more expensive and increase the overall drilling cost. To put this in perspective, if a water-based mud was used to drill in the Levantine Basin and salt zone was encountered, the salt area would be solution mined and a void space within the rock would be created. This would cause significant problems and the potential of wellbore collapse.


Offshore production is complicated due to transportation of reservoir fluids, offshore production facilities, and production maintenance. There are few ways to transport reservoir fluids from offshore wells. The two most common ways are by pipelines and by boats. Pipelines are attached to the wellhead at the bottom of the seafloor and run along the bottom of the ocean to a production facility on land. This method of transportation involves a few risk factors. The first is continuously maintaining a high enough line pressure to export the fluids the well to a facility. Fluids cannot flow if the line pressure is not high enough. If the line pressure is too high, fluids cannot flow from the well. Another risk with pipeline systems is leaks. Due to environmental regulations, offshore locations are always placed on higher alerts than land operations. Similarly with boats, the cause of leaks is also a high concern. Typically liquids are transported by boat from the platform rather than gas. When producing from a gas well, a common problem is liquid loading. Liquid loading is when condensate comes out of the gas and forms a column of fluid within the wellbore. If the gas does not have enough pressure to push the column of liquid up to the surface, the well will not produce to its potential. This first signs of this occurrence can be observed by production history data where one day may be normal or high production totals and the next may be low. This is known as slugging and can be the first sign of liquid loading occurring. Artificial lift methods are needed to unload and keep the liquid unloaded.


When drilling any well there are always uncertainties that no one can expect. Some of these uncertainties include unexpected high pressure zones, wellbore deviation from center, actual log data such as resistivity, gamma ray, and other important logs to determine zones of interest, how much hydrocarbons will be present, the non productive time (NPT) of the drilling rig and many more. All of these uncertainties will affect the economic outcome of the well. The goal is to mitigate as many of these uncertainties as possible. For instance, making sure the drilling crew is maintaining the rig properly to prevent NPT or making sure estimated reservoir characterizations on initial hydrocarbons in place are as accurate as possible where minimums would still return favorable results. Although no well drilled ever goes to plan or to schedule, it is important to understand how to minimize the risk and uncertainties of any potential well.

Future Production and Basin Potential

The future potential of the Levantine Basin is unmatched. The large volumes of gas and relatively large volumes of oil make it a hot spot for large companies to explore. The high costs of offshore drilling and the resources needed to attempt to drill a well limits the Levantine Basin opportunity to companies that can afford to spend more than $100 million dollars on one well. As 4-D seismic data comes out, new areas may be discovered and potential reserve estimates may be altered. Due to the size of the Basin and how little it has been fully explored, more areas of interest will present themselves. If companies can figure out how to drill to deeper depths without encountering as many issues, this could also be beneficial and give better estimates to potential recovery. The challenges that are present make this a difficult place to drill a well and careful consideration needs to be discussed prior to drilling due to the risk that are present within the Basin.

  1. 1.0 1.1 Duddilla, Krishna. “Leviathan Gas Field, Levantine Basin, Mediterranean Sea.” Offshore Technology, 6 Oct. 2016, www.offshore-technology.com/projects/leviathan-gas-field-levantine-israel/.
  2. NS Energy. (n.d.). Leviathan gas field, Leviathan Basin, Mediterranean Sea. NS Energy. Retrieved May 10, 2022, from https://www.nsenergybusiness.com/projects/leviathan-gas-field-mediterranean-sea/
  3. Newman, N. (2013, November 5). Levant Basin Holds Massive Energy Potential. Hart Energy. Retrieved May 10, 2022, from https://www.hartenergy.com/exclusives/levant-basin-holds-massive-energy-potential-19795
  4. Liu Xiaobing et al. “Gas Field Distribution and Regional Structure Map of Levant Basin in Eastern Mediterranean.” Science Direct, Petroleum Exploration and Development , Aug. 2017, https://www.sciencedirect.com/science/article/pii/S1876380417300666. Accessed 5 Apr. 2022.
  5. “Offshore Levant Basin Petroleum System and HC Resource Assessment.” Israel Ministry of Energy
  6. Fürstenau, J., Hawie, N., Comstock, J., and C. J. Lowrey. "Aspects Of The Depositional History Of The Levant Basin, Offshore Cyprus And Lebanon." Paper presented at the Offshore Mediterranean Conference and Exhibition, Ravenna, Italy, March 2013.
  7. 7.0 7.1 7.2 7.3 Marlow, Lisa, et al. “2-D Basin Modeling Study of Petroleum Systems in the Levantine Basin, Eastern Mediterranean.” GeoArabia, vol. 16, no. 2, 9 Mar. 2011, pp. 17–42.
  8. LIU, Xiaobing, et al. “Structural Characteristics and Petroleum Exploration of Levant Basin in Eastern Mediterranean.” Petroleum Exploration and Development, vol. 44, no. 4, Aug. 2017, pp. 573–581., https://doi.org/10.1016/s1876-3804(17)30066-6.
  9. Grohmann, Sebastian, et al. “Source Rock Characterization of Mesozoic to Cenozoic Organic Matter Rich Marls and Shales of the Eratosthenes Seamount, Eastern Mediterranean Sea.” Oil & Gas Science and Technology – Revue D'IFP Energies Nouvelles, EDP Sciences, 30 Oct. 2018, https://ogst.ifpenergiesnouvelles.fr/articles/ogst/full_html/2018/01/ogst180108/ogst180108.html?mb=0.
  10. 10.0 10.1 10.2 10.3 10.4 LIU, Xiaobing, et al. “Structural Characteristics and Petroleum Exploration of Levant Basin in Eastern Mediterranean.” Petroleum Exploration and Development, vol. 44, no. 4, Aug. 2017, pp. 573–581., https://doi.org/10.1016/s1876-3804(17)30066-6.
  11. LIU, Xiaobing, et al. “Structural Characteristics and Petroleum Exploration of Levant Basin in Eastern Mediterranean.” Petroleum Exploration and Development, vol. 44, no. 4, Aug. 2017, pp. 573–581., https://doi.org/10.1016/s1876-3804(17)30066-6.
  12. 12.0 12.1 12.2 Brambilla, F., and E. Tuyrin. "Advanced Logging Technology Combined With Integrated Formation Evaluation Analyses Provides Confident Petrophysical Information in the Giant Gas Discoveries of the Levantine Basin." Paper presented at the Offshore Mediterranean Conference and Exhibition, Ravenna, Italy, March 2015.
  13. LIU, Xiaobing, et al. “Structural Characteristics and Petroleum Exploration of Levant Basin in Eastern Mediterranean.” Petroleum Exploration and Development, vol. 44, no. 4, Aug. 2017, pp. 573–581., https://doi.org/10.1016/s1876-3804(17)30066-6.
  14. “Offshore Levant Basin Petroleum System and HC Resource Assessment.” Israel Ministry of Energy