This report is maintained by Deniz Ege Boz and Oğuzhan Öztürk as a part of Econ 318 course requirement at Bilkent University. The purpose is of this project is to assess if Turkey can be crude oil exporter by using condensate imported from Qatar.

 

 

Making Turkey A Crude Oil Exporting Country: A Possible Cooperation between    Turkey & Qatar

Batı Raman oil field is the biggest oil field in Turkey with the capacity of 1.85 billion barrels of original oil in place which is %40 of total proven reserves. This field is discovered in 1961 and past 57 years total production is 0.15 billion barrels with approximately %1 recovery rate. The reason for this low recovery rate is that the Batı Raman oil is heavy and viscous (overall API gravity is accepted as 12o). In order to increase the recovery rate, several enhanced oil recovery methods had been taken into consideration and CO2 injection method was found favourable. In 1986, CO2 application has started in Batı Raman field and it had been applied to %95 of the field until today. However, the increase in the oil production has fell far below the values simulation studies had predicted. Over more than 20 years of injection, the recovery peaked around 13,000 bbl/d in 1993 and began to decline since then.

This report proposes an application of a tertiary recovery method with the use of condensate as an enhanced oil recovery method on Batı Raman oil field. Condensate is ultra-light (low-density) hydrocarbon product with very high API gravity (45 or more). It is one of the widely used diluents in the heavy oil industry because the viscosity of heavy crude oil can be reduced significantly on blending with condensate. In that manner, condensate injection can be used for increasing the recovery rates of Batı Raman oil field. Various EOR methods and the characteristics of Batı Raman oil field are reported in our paper. Another focus of the paper is the economic cost and benefit analysis of the chosen  EOR method. Certain suggestions on the technical aspect of the application are provided but not discussed further. Mainly, economic analysis of the changing supply/demand dynamics of world condensate market have let us choose the dilution method with the use of DFC type condensate that is produced by Qatar Petroleum.

There are three main types of condensate: lease condensates, plant condensates and light naphtha. Plant condensate and light naphtha are mostly used as a feedstock petrochemical production or a diluting agent in heavy crude production and transportation. Australia, Iran, Qatar, Russia and the USA are the biggest exporters of condensate in the world.

Among the producers of condensate, Qatar is found to be the most favourable country to establish such a trade relationship. Recently, a diplomatic crisis with Saudi Arabia led to sanctions on Qatar which are enforced through regulatory changes in GCC countries’ import terminals. Meanwhile, Turkey’s political support for Qatar which extends to military aid improves Qatar’s geopolitical power in the oil industry significantly. On the other hand, Qatar’s exports of condensate were decreasing markedly with increases in domestic consumption and due to increased supply in the world after the shale gas revolution in US. Condensate is mainly a by-product that comes out with natural gas. Thus, as Qatar continues to produce LNG, they will continue to produce condensate as a by-product. Thus, the good diplomatic relations and developing economic relations between Turkey and Qatar creates a suitable environment for the trade of condensate and production of oil in Batı Raman field.

According to a scenario in which Turkey applies this method on Batı Raman oil field, the blended mixture of the Batı Raman oil and DFC will decrease the viscosity of  the oil for easier extraction. After the crude oil and condensate are separated, Batı Raman’s original crude oil specifications will persist. Turkey’s refineries such as Star and Izmit Tüpraş are suitable for processing this type of oil. Yet, exporting the oil is found to be a more favourable option in terms of increasing the economic value. For instance, Venezuela as one of the biggest heavy oil producers in the world has been suffering from a severe economic crisis which substantially affects their production rates. India on the other hand is one of the major buyers of Venezuelan heavy (both sour and sweet) crude oil with imports worth of US$5 billion in the 2017-2018 financial year.  This is one of the export opportunities for Turkey. Also, India exports remarkable amount of diesel to Turkey and certain exchange schemes will also be available in such a trade. Lastly, considering the very low production capacity of Batı Raman oil field compared to giant fields in Venezuela, it can be argued that finding one buyer can be sufficient for the desired export levels. If not, United States as a major heavy crude importer can also be a viable option.

Oil Recovery Methods Used in Turkey and Characteristics of Batı Raman Oil Field

 

The enhanced recovery method (EOR) employed in Batı Raman oil field since 1986; is one of the enhanced secondary recovery methods that uses the vapor pressure of carbon dioxide (CO2) to push the oil to the inner reservoirs and later collect with midstream operations. With the capacity of 1.85 billion barrels of oil, the Batı Raman field is the largest oil field in Turkey. The reservoir fluid in Batı Raman is a very heavy crude oil, having an API gravity ranging from 9.7 to 15.1 (mainly accepted as 12o API) and a viscosity ranging from 450 to 1000 centipoises (which means highly vicious) at reservoir conditions. The asphaltene content in Batı Raman oil was found to be 29% by (Hasçakır, 2008 ) in a sample that is tested. The sulphur content of the oil is also considered to be very high between 1.23% to 5.6% (calculated from using the sulphur values in 1986 World Bank Engineering Project Completion Report). The main production mechanism in the field is rock and fluid expansion where the original reservoir pressure is 1800psi and the solution gas-oil-ratio is 18 SCF/STB[1] resulting in a low bubble pressure, and located at an average depth of 4300ft. Considering the properties of the oil such as low API gravity, low solution gas and high viscosity as well as low reservoir energy; initial recovery prospects of the oil field are naturally very low. “ Both CO2 and steam applications were found favourable by the producer. However, immiscible CO2 application appeared more feasible because of the nearby Dodan CO2 gas reserve and the high initial investment cost of steam injection” (Sahin et al., 2008). The recovery factor in the oil field was between 1.5-2% through primary production until 1986 and peaked at 5% in 2007 through temporarily increased capacity utilization rates. The long term recovery rate remained similar to the initial levels with primary production and economies of scale couldn’t have been utilised yet.

Immiscible CO2 injection in Batı Raman’s fractured limestone reservoirs harbouring heavy oil was acknowledged to be a successful EOR application by Turkish Petroleum Corporation with the achievement of lowering the oil gravity requirement to >12°API. However, the increase in the oil production has fell far below the values that simulation studies predicted. Over more than 20 years of injection, the recovery peaked around 13,000 bbl/d and began to decline around 7,000 bbl/d in 2008. Today, the oil production is around 6,500 bbl/d. “Despite ongoing problems, the Batı Raman reservoir clearly presents a significant development opportunity for recovery improvement. The current operation expenditure in Batı Raman field is 11,99$/bbl. according to our findings.

What is Condensate?

 

Condensate is ultra-light (low-density) hydrocarbon product with high API gravity[2] (45 or more[3]). In the underground before extraction, condensates are situated in gaseous form. The term itself broadly refers to the by-product of natural gas that condenses into liquid after being freed from high-pressure wells. Certain temperature and pressure conditions in reservoirs and gas fields allow natural gas to condense to a liquid form. The condensation does not occur just in reservoirs; with the correct temperature and pressure, the phenomenon can also be replicated in pipelines and surface facilities(Miles, 2018). Condensate can also exist dissolved in the crude oil or separate from the crude oil in the underground formation. In fact, gas condensate should be regarded as a mixture of light paraffin components, chiefly pentane, hexane, and heptane (Dehaghni,2016).

Relatively lighter condensates are more difficult to manage due to their higher vapour pressure.  They need to be run through stabilizer tanks which vaporise the components that causes high vapour pressure. Only after a stable and low vapour pressure condensate are left behind.

Condensates are also classified according to their mode of production. According to Oil and Gas Financial Journal condensates are grouped into three categories by experts:

 

·         Lease condensates: These condensates are often recovered from the wellhead[4] at atmospheric pressures and temperatures which means they do not need further processing. They are typically a mix of different hydrocarbon compounds like pentane (C5H12) and Cyclohexane (C6H12)  as well as heavier hydrocarbons, like C7.

 

·         Plant Condensates: These condensates go through a gas processing plant and considered as a processed product which can be used in heavy crude industry as a diluting agent.

 

 

·         Light Naphtha: The distillation occurs in the first step of condensate refining process can reveal light naphtha condensates. Also, it can be separated from lighter NGLs through condensate splitting. The resulting clean naphtha product can be used as a feedstock for petrochemicals production. Most of the condensate that Qatar produces is light naphtha type of condensate

 

            Types of Condensates Produced in Qatar:

 

·         Deodorized Field Condensate (DFC): The field condensates found in Qatar’s North Field undergo a ‘sweetening’ process to form DFC which has been used as feedstock to condensate splitters and as incremental feed to blend with heavy crude oil. [5]

·         Qatar Low Sulphur Condensate (QLSC): Most properties and usages of QLSC is similar to DFC. However, QLSC has lower distillate and higher naphtha content compared to DFC and more likely to be preferred where higher naphtha is desired such as petrochemical industry.

 

·         NGL Condensate: Produced in Mesaieed plant, NGL (natural gas liquids) Condensate is a form of light virgin (not consisting of any chemically converted product) naphtha. Being highly paraffinic (typically >90%), it is typically used as feedstock in petrochemical cracking plants.​

 

·         Plant Condensate: It is a type of virgin NGL, recovered in gas processing section of the LNG plants. In the family of light naphtha, it is highly paraffinic (typically >80%) and typically used as feedstock in petrochemical cracking plants as well.

 

·          Refinery Naphtha (RNAP):It is a light virgin naphtha (typical boiling point range of 30-155°C), produced from a condensate splitter in Mesaieed. It is again highly paraffinic (typically >85%) and used as feedstock in petrochemical cracking plants.

 

Considering a scenario in which mining method is used to recover the heavy oil in Batı Raman field with the use of natural gas condensate; Qatar’s DFC would be the preferred option. As stated before Batı Raman oil has very high viscosity and an API around 12o. It was also stated that the usage of condensate can cause asphaltene precipitation but naphtha shows better results addressing this problem. DFC is a very low sulphur and higher naphtha content condensate and a very good candidate for the dilution with this heavy oil.

The Role of Condensate as a Recovery Method  in Heavy Oil Industry[6]

 

Crude Oil Dilution Method with the Use of Natural Gas Condensate[7]

 

Dilution of crude oil is one of the oldest methods used in heavy oil production (since 1930s) and can be accomplished by using condensates obtained in natural gas production. The advantages of the method includes avoiding high pressure drops due to reduction in viscosity and reduced pumping costs. However, the transportation of the solvent requires an additional pipeline for mixing the crude with condensate and requires extra capital for the operational investment in pumping and pipeline maintenance. Another drawback is caused by asphaltenes contained in heavy crude oil that are insoluble in condensate. “Dilution of heavy oils with a light solvent perturbs the delicate balance of asphaltenes, so that segregation and solid phase separation can take place inside transmission pipelines, storage tanks and equipment, causing flow obstructions and pressure build-up” (Orea et al., 2015).

Condensate is one of the widely used diluents in the heavy oil industry because the viscosity of heavy crude oil can be reduced significantly on blending with condensate. “Being the lightest hydrocarbon component, dissolution of heavier components and subsequent reduction in the viscosity is facilitated by natural gas condensates” (Kulkarni & Wani, 2016). The viscosity of the blended mixture depends on the properties of heavy crude oil and the condensate, the dilution rate, operating temperature and the heavy oil-condensate ratio. The lower the viscosity of the blend, easier it is to pump through pipelines at reduced costs.

Provided below are some specific examples for the use of condensate in heavy oil industry with an aim to inform on the potential advantages and disadvantages.

 

a)      Light naphtha shows better compatibility with asphaltenes.  According to (Gateau, 2004) a blend of naphtha and organic solvent would have increased ability to act on asphaltenes components of heavy crude oil because of the higher polarity (hydrogen bonding) of solvents. As a result, higher polarity solvent causes larger reduction in viscosity of the diluted heavy crude oil and enhances dilution efficiency

 

b)     A field study from Omani fields (Shigemoto, et al., 2006): Heavy crude oil (density of 0.9571 g/cm3 at 288 K) and natural gas condensate (density of 0.7848 g/cm3 at 288 K) were sampled from Omani oil fields. The oil was mixed with condensate (5−50 vol %), and the mixture viscosities were measured at the temperature range of 293−348 K. A significant decrease in kinematic viscosity was achieved. An addition of about 12 vol % of condensate gave a viscosity of 265 mm2/s at 303 K. This made it easier to transport the heavy oil mixtures.

 

c)      “A mixture of 25:75 diluent and bitumen can be transported by pipeline and it is called dilbit. In the winter months the ratio required for sufficient fluidity can be as high as 35:65 diluent to bitumen ratio.  Main advantages of producing dilbit is that it can exploit existing heavy oil refining capacity and it requires little additional capital investment at the production site beyond that needed to produce the bitumen. The main disadvantages of this approach are that it reduces pipeline capacity by (25–35) % and it requires a return pipeline for the diluent in order to produce the dilbit” (Klerk et al., 2014).

 

d)     “Changes in inclination from a horizontal to a vertical or almost vertical position produces pressure drops and changes in the flow pattern of the fluid transmitted by the pipeline. In heavy oils diluted with natural gas condensates there is a high probability of developing a slug flow pattern if lighter components of the diluent leave the liquid phase in the form of big gas bubbles” (Guo et al., 2014).

 

e)      In an experiment measuring the degree of viscosity reduction in Iranian heavy crudes diluted with natural gas condensate; heavier oil with gravity of 16 API has undergone significant viscosity reduction upon mixing with gas condensate. Lighter oil (20.5 API) demonstrated lower degree of viscosity reduction. “Influence of naphtha and gas condensate was rather complex depending on type of heavy oil” (Dehaghni,2016).

 

f)       (Bassane et al., 2016) have determined viscosity of heavy oil/ natural gas condensate mixture at various temperatures. Four heavy oil samples of API gravity in range of 13.7 to 21.6 were used in the experiments. Viscosity reduction up to 98% of the original heavy oil viscosity was achieved by blending with gas condensate of 32 vol.%. Based on their experimental measurement, making mixture of 14 vol.% gas condensate is determined to be an optimum point where adding more amount of solvent would jeopardize economic viability.

 

The Economic Cost Benefit Analysis

 

DFC condensate will be imported from Qatar to be used for the explained enhanced recovery method under the goal of significantly increasing the recovery rates of Batı Raman oil field. Applications and experiments in different types of heavy oil and condensates imply that an economically viable (optimum) dilution rate needs to be found for Batı Raman oil and DFC. Considering the technical aspect; first, samples of DFC and Batı Raman oil need to be tested in laboratory conditions (with a target level of increased API gravity of the blended mixture) to find the level of reduction in viscosity. Later, pilot applications in the field need to be conducted in some of the production wells to examine success rate of physical application. Finding an optimum dilution rate and obtain a miscible blended mixture of condensate and heavy oil will suffice to reduce the viscosity of heavy oil and increase the fluidity enough for extraction under the current reservoir pressure. Finally, it needs to be measured and determined that how much of the condensate we put underground will contact the heavy oil and how much oil we can extract with that certain amount of condensate. Thus, we created a model which considers three different scenarios for the optimum dilution rates and runs simulations for the total cost production per barrel for each scenario. The estimations are             based on constant values from the most recent data acquired. It is also proposed that the enhanced recovery method we suggest could be integrated to the ongoing production in the oil field. The required infrastructure for hydrocarbon injection such as the injection wells and pumps are already existent in the oil field and there is no need for any major additional investment cost. According to our findings, with the current heavy oil prices in the world market (which are significantly higher compared to past because of the sanctions on two major heavy oil suppliers, Iran and Venezuela); Turkey can have an annual profit of $544,939,590 in the optimistic scenario; $358,684,846 in the realistic scenario and $207,601,826 pessimistic scenario.

 

Table 1: Constant Values Used in Every Scenario

 

DFC Conversion Factor (ton-bbl) 

8.25

Exchange Rate (USD/TL)

5.63

Dubai Index

$68.98

DFC Price

$4 discount to Dubai Index

Av. Cargo Carrying Capacity of Aframax

750,000 bbl

DFC Injection Rate per day ( 1 Aframax Load of Cargo in 90 days)

8,333 bbl

Current Oil Production  Batı Raman with CO2 Injection

6,500 bbl

Current OPEX in Batı Raman with CO2 Injection per bbl

$11.99/bbl

Table 2: Import Cost (per bbl) Used in Every Scenario

 

DFC Price (per bbl)

$64.98

Pipeline Cost (from Dörtyol to Batı Raman) ($/bbl)

$1.42

Cost of Aframax Shipment per bbl (from Ras Laffan to Dörtyol)

$0.68

Total Import Cost per

bbl

$67.07

Table 3: Injection and Production Costs for Optimistic Scenario                                                   (25% DFC – 75% Heavy Oil)

 

Heavy Oil/DFC Ratio

3

Condensate Injection Cost

$11.59/bbl

Oil production Cost with Condensate

$2.00/bbl

Total Injection and Production Cost to Produce 1 bbl of Heavy Oil

$6.53/bbl

 

Table 4:  Results for the Optimistic Scenario

 

Heavy Oil Production w/ DFC

25,000 bbl/day

New Heavy Oil Production in Batı Raman

31,500 bbl/day

OPEX of Dilution with DFC

$613,344/day

OPEX of CO2 Injection

$77,935/day

Weighted Average Cost

$21.95/bbl

 

Table 5: Injection and Production Costs for Realistic Scenario                                                                (40% DFC – 60% Heavy Oil)

 

Heavy Oil/DFC Ratio

 2/3

Condensate Injection Cost per bbl

$11.59/bbl

Oil production Cost with Condensate per bbl

$2.00/bbl

Total Injection and Production Cost to Produce 1 bbl of Heavy Oil

$11.06/bbl

 

Table 6: Results for the Realistic Scenario

 

Heavy Oil Production w/ DFC

12,500 bbl/day

New Heavy Oil Production in Batı Raman

19,000 bbl/day

OPEX of Dilution with DFC per day

$651,094/day

OPEX of CO2 Injection per day

$77,935/day

Weighted Average Cost per bbl

$38.37/bbl

 

Table 7: Injection and Production Costs for Pessimistic Scenario                                               (50% DFC – 50% Heavy Oil)

 

Heavy Oil/DFC Ratio

 1

Condensate Injection Cost per bbl

$11.59/bbl

Oil production Cost with Condensate per bbl

$2.00/bbl

Total Injection and Production Cost to Produce 1 bbl of Heavy Oil

$15.59/bbl

Table 8: Results for the Pessimistic Scenario

 

Heavy Oil Production w/ DFC

8,333 bbl/day

New Heavy Oil Production in Batı Raman

14,833 bbl/day

OPEX of Dilution with DFC per day

$688,843/day

OPEX of CO2 Injection per day

$77,935/day

Weighted Average Cost per bbl

$51.69/bbl

 

Other Viable Usages of Condensate in Various Industries:

 

 

 

Table 9: Turkey’s Share in Qatar’s Total Energy Exports

 

Year

Total Exports ($Billion)

Total Energy Exports (Fuels, Oils and Distillation Products) ($Billion)

Turkey's Share in Total Energy Exports ($Million)

2008

67.31

61.19

74.00 (%0,12)

2009

-

-

-

2010

74.96

67.52

630.61 (%0,93)

2011

-

-

-

2012

133.71

117.03

477.58 (%0,41)

2013

136.85

119.96

151.63 (%0,13)

2014

131.59

113.89

692.25 (%0,60)

2015

77.97

64.53

515.01 (%0,80)

2016

57.31

46.74

122.29 (%0,26)

Source: World Bank Group WITS 2017 Report

Table 10: Qatar’s Share in Turkey’s Total Energy Imports

 

Year

Total Imports ($Billion)

Total Energy Imports (Fuels, Oils and Distillation Products) ($Billion)

Qatar's Share in Total Energy Imports ($Million)

2008

201.96

15.31

31.26 (%0,20)

2009

140.93

15.13

-

2010

185.54

15.13

43.23 (%0,29)

2011

240.84

19.89

40.65 (%0,20)

2012

236.55

20.79

-

2013

251.66

20.41

-

2014

242.18

20.29

6.25 (%0,03)

2015

207.21

14.56

9.60 (%0.07)

2016

198.62

 12.02

10.75 (%0,09)

Source: World Bank Group WITS 2017 Report

In the past decade, Turkey and Qatar have been improving their political, strategic and economic cooperation. Yet, when we look at the tables 3 and 4, they do not have significantly high shares in each other’s total energy exports & imports. Turkey has good volume of pipeline connections with the countries it is currently importing natural gas (Russia & Iran & Azerbaijan). Yet, there is no existing pipeline connecting Qatar and Turkey directly for the import of DFC condensate. Thus, the only way a trade can happen between Qatar and Turkey would be through the shipments (which will be priced over FOB). The cooperation of Turkey and Qatar in exploiting Batı Raman oil field’s remaining unused potential would also strengthen the already in a good state geopolitical relationship between two countries.

 

 

 

Table 11: Condensate Physical Trade Volume of Qatar By Destination (Kilo tonnes)

 

Years

Destination Countries

2018

2017

2016

2015

China

    400

      149

      216

      363

South Korea

  4.930

  27.535

  19.121

  11.644

Japan

    875

  13.924

  11.132

   2.843

Indonesia

    112

      318

      431

      183

Singapore

    613

   5.686

   4.806

   2.961

India

 -

   4.394

   2.966

   1.485

United Kingdom

 -

        65

        54

      130

Taiwan

 -

      374

      345

      335

Oman

 -

      110

      181

      135

United Arab Emirates

 220

      887

      475

      485

United States

 -

        43

      230

      260

Thailand

 -

        23

      130

      135

Netherlands

 -

        20

      135

        98

Malaysia

 -

      224

      360

 -

Unknown

 380

 -

      135

 -

TOTAL

  7.530

  53.752

  40.717

  21.057

 

Source: Thomson Reuters Eikon Database

 

Table 12: LNG Physical Trade Volume of Qatar

 

Year

LNG Export of Qatar (Bil. Cub. Meters)

2008

39.68

2009

49.44

2010

75.75

2011

102.60

2012

105.44

2013

105.62

2014

103.38

2015

106.36

2016

104.44

2017

103.40

Source: BP Statistical Review of World Energy 2018 Report

Table 13: Qatar’s share in global LNG trade

 

 

Year

Global LNG trade of the World(Billion Cubic Meters)

LNG trade of Qatar (Billion Cubic Meters)

Qatar’s share in global LNG trade (%)

2007

226.4

38.5

17.00

2008

226.5

39.7

17.52

2009

242.8

49.4

20.34

2010

297.6

75.8

25.47

2011

330.8

102.6

31.01

2012

327.9

105.4

32.14

2013

325.3

105.6

32.46

2014

333.3

103.4

31.02

2015

338.3

106.4

31.45

2016

346.6

104.4

30.12

2017

393.4

103.4

26.28

Source: BP Statistical Review of World Energy 2018 Report and Bloomberg Database

Table 14: Global Condensate Export Volume (Kilo tonnes)

 

Year

Load Country

2015

2016

2017

2018

Algeria

80

 

 

 

Angola

 

44

319

71

Australia

74

1160

669

1809

Bahamas

 

 

 

130

Brazil

75

 

 

 

China

 

260

384

 

Republic of Congo

 

 

17

 

Democratic Republic of Congo

 

 

 

46

Denmark

 

 

54

 

Estonia

 

43

 

 

Indonesia

 

 

 

63

Iran

7294

12872

14612

10186

Iraq

 

180

 

 

Malaysia

80

 

57

 

Mozambique

 

23

 

 

Netherlands

 

 

45

 

New Zealand

 

 

40

 

Nigeria

 

699

270

 

Norway

685

132

231

32

Oman

 

 

40

 

Pakistan

 

 

 

206

Qatar

21057

40717

53752

7381

Russian Federation

 

100

139

54

Saudi Arabia

 

 

56

 

Togo

 

49

 

 

Tunisia

 

 

41

 

United Arab Emirates

 

 

10

438

United Kingdom

 

102

114

 

United States

3327

3550

2820

7702

Grand Total

32673

59932

73670

28117

 

Source: Thomson Reuters Eikon Database

Table 15: Customers of Heavy Crude Oil

 

Discharge Country

Total

United States

56203,44

India

49359,81

China

42959,97

South Korea

26732,50

Iran

19052,00

Japan

10821,09

Italy

7330,98

Greece

7020,25

Spain

6856,25

Netherlands

6020,75

Potential Effects of Re-imposed Iranian Sanctions to the Condensate Market

 

After the lift of past sanctions in January 2016, Iran had a lot of stored oil that it can supply to the market instantaneously and they preferred to sell it cheaper than their competitors to increase their market share. “Iran’s SPC was as much as $5 per barrel cheaper than Qatar’s deodorised field condensate (DFC) at the start of the year, but the gap has since narrowed to $2 to $3, trade sources said” (ONG, 2016). The total annual condensate export levels of Qatar declined by 5% in 2016.

In 2017, Qatar’s first condensate splitter refinery in Ras Laffan has started operating. Prior to the beginning of operations, the officials from Qatar Petroleum has stated that the condensate exports of Qatar will decline by 150.000 bpd since the splitter has a capacity to process 146.000 barrels of condensate (DFC and low sulphur field condensate) to double their naphtha output and extract middle distillates (such as jet fuel, heating kerosene and gasoil). This has significantly affected the total exports of Qatar. A decline from 19,888 million barrels in 2016 to 13,893 million barrels in 2017 was observed. There was also a decline in Iranian condensate exports still before the announcement of re-imposed sanctions due to rapid growth in the refining capacity of Persian Star Refinery. Yet, this has not increased the imported volumes of condensate from Qatar. The imports of South Korea fell by 1,40 million barrels compared to 2016 and imports of Japan were decreased by 3,90 million barrels. Only Singapore increased their imports by a small amount in 2017. However, with the upcoming sanctions, a supply gap will occur in the market since the demand for condensate is still growing in Asia. Two months before renewed U.S. sanctions on its oil exports take effect, Iran has already suffered a sharp drop in sales and lost key buyers in Asia and Europe. Major importers are looking for alternatives which can provide constant supply. There have been no shipments from Iran to South Korea, Japan or France since June 2018 while overall exports to the European Union have fallen by about 40 percent since April 2018.

Considering the current changes in market structure, there occurs a great opportunity for major exporters like Australia to increase market share in Asia. Producers of ultralight condensate in U.S. (which has increased substantially after U.S. became a net LNG exporter by virtue of shale gas revolution) can also export higher volumes to petrochemical plants in South Korea and Japan and increase their market share. Thus, with the disappearing of Iran, if Qatar will not increase its condensate production to compensate for its increasing domestic consumption, they can easily lose their dominant position in the growing Asia market. Both South Korea and Japan has increased their condensate imports from the Oceania market in 2018. However, the biggest consumer of condensate South Korea’s first choice of alternative to Iranian condensate would be the Qatari DFC and low sulphur condensate. “A South Korean refinery source indicated that the first alternative to South Pars would be Qatari grades like deodorized field condensate and low sulphur condensate. Among the latest trade deals concluded in the Middle Eastern spot market, Qatar Petroleum for the Sale of Petroleum Products Co., or QPSPP, was said to have sold a 500,000-barrel cargo of DFC for loading in May to Hyundai Oilbank” (Platts, 2018). Therefore, it will not be wrong to expect that Qatar will try to return to old export levels by increasing production over 20 million barrels annually in order not to lose market share. If that would be the case, the indication would be a downward pressure on the prices of DFC.

On the other hand, Qatar may not choose to increase their export levels to Asian market. Yet, they are currently increasing their LNG production substantially to pull the prices down in Asian LNG market, especially after deciding to leave OPEC and increase focus on LNG.  This decision will increase their cost competitiveness even more in an attempt to remain the dominant supplier for the Asian LNG market where current market dynamics impose larger amounts of trade in the spot market. Thus, considering the fact that producing NGLs is a mandatory with the production of natural gas; Qatar will have excess amount of condensate for the foreseeable future and the economic cost of cooperating with Turkey in Batı Raman oil field can even be negligible. This could also mean that Turkey can negotiate and demand lower prices from Qatar and the cost of imported condensate could be lower than anticipated market prices.

 

Figure 2: LNG Export of Qatar Before and After Diplomatic Crisis

Source: JODI Database

Figure 3: Crude Oil Export of Qatar Before and After Diplomatic Crisis

Source: JODI Database

Figure 4: Condensate Export of Qatar Before and After Diplomatic Crisis

 

As Figure 2 shows, Qatar’s export of LNG has decreased after June 2017 in comparison with the same periods before the crisis. In LNG production and exportation, Qatar has serious comparative advantage in operational costs against other LNG exporters such as Australia and United States. They have very good quality infrastructure that are already in place which eliminates any further intensive capex requirements. In addition, their major natural gas fields such as the North Field and Ras Laffan possess high amounts of valuable NGLs  whose profits are naturally subsidizing their natural gas production and exports. With a constant flow of profits coming from the trade of such NGLs, Qatar can export LNG with a breakeven price up to 0$. This allows them to lower prices as much as they like in the race to keep their highest market share in the growing Asian LNG market. Thus, the international trade of NGLs such as condensate and to some extend naphtha actually carries great importance for Qatar.  When we look at Figure 4, it can be observed that there is s significant decline in the exports of Qatari condensates. In terms of total revenue this may not indicate a huge loss for Qatar’s energy exports but its strategic significance should not be underestimated from their perspective. Thus, a cooperation between Turkey and Qatar in Batı Raman oil field that will result in a robust flow of condensate over a span of at least 20 years will certainly have positive economic effects for Qatar as well.

 

 

 

 

 

APPENDIX A

Qatari Condensate Types

Deodorized Field Condensate (DFC)

Produced as a result of liquefaction of natural gas found in Qatar’s North Field in the Arabian Gulf, field condensates undergo a “sweetening” process to convert mercaptans into disulphide oil, to form DFC. DFC has been used both as feedstock to condensate splitters and as incremental feed to refineries (e.g. blended with heavy crude oil). DFC can be loaded from Single Point Mooring (SPM ) in the port of Ras Laffan , which is advantageous for shipping efficiency.

Where used as splitter feed, the naphtha portion of DFC (as indicated in quality of Full-range naphtha from Laffan Refinery splitters) has a paraffinic content of 70% with N+A of about 30% with paraffinic hydrocarbon stream. It has been used both in petrochemical crackers and also as feedstock to naphtha splitters for further processing in light and heavy components. ​

Table 16: DFC Properties

 

Typical Qualities

Unit

Method

Expected Range

Relative Density @ 60/60°F

 

ASTM D4052

0.74-0.75

API Gravity @ 60/60° F

 

ASTM D4052

57-59

Vapour Pressure @ 100°F

PSI

ASTM D5191

≤ 12.0

Total Sulphur

wt%

ASTM D4294

≤ 0.3

Mercaptan Sulphur, ppm (w)

ppmw

ASTM D3227

500-700

B S & W

%Vol

ASTM D4007

0%

Qatar Low Sulphur Field Condensate (QLSC)

QLSC is very similar to DFC in most properties and usages. QLSC has a higher naphtha content (conversely lower distillate content) as compared to DFC, and thus may be more likely to be preferred where higher naphtha content is desired.​

Table 17: QLSC Properties

 

Typical Qualities

Unit

Method

Expected Range

Relative Density @ 60/60°F

 

ASTM D4052

0.74-0.75

API Gravity @ 60/60° F

 

ASTM D4052

58-61

Vapour Pressure @ 100°F

PSI

ASTM D5191

≤ 12.0

Total Sulphur

wt%

ASTM D4294

≤ 0.2

Mercaptan Sulphur, ppm (w)

ppmw

ASTM D3227

400-500

B S & W

%Vol

ASTM D4007

0%

 

 

APPENDIX B

Various Methods Used in the Production of Heavy Oil

 

World oil demand has been increasing beyond the point that the conventional light crude production would suffice. In the face of limited supplies, unconventional oil sources and heavy oil sources that are challenging to extract are getting increased attention for some time. However, the fact that they are hard to extract, process and transport still remains. For a variety of reasons, heavy oil cannot be pumped easily. High viscosity and density, probable contaminations with rock and other solid debris are some of the major causes. On the other hand, refineries which are used to adopting light and sweet oil have to accept heavier oil with different physical properties. For them to have similar yields with favoured proportions, refining performances need to be improved. Essentially, by reducing the viscosity of the oil to ease flow or by literally pushing it through the reservoir, EOR techniques increase oil displacement efficiency in the reservoir. Another objective is to improve sweep (the volume of reservoir that is contacted during extraction) efficiency. The remaining part of this section reports some other options of enhanced oil recovery methods that could have been used in Batı Raman.

 

Cold Heavy Oil Production (Non-thermal): 

Heavy oils can be produced from boreholes by cold production from the reservoirs if the oil is easy to flow (lighter Venezuelan heavy oils, offshore Brazilian oil) or when the oil is closer to the surface to some extend (as in the case of Canadian oil sands). “Horizontal and multilateral wells are drilled in order to contact as much of the reservoir as possible and diluents, such as naphtha, are injected to decrease fluid viscosity further. In order to lift the oil to the surface electrical submersible pumps and progressing cavity pumps, are employed.” Cold production is considered as a low-cost method due noticeably lower capital expenditure compared to thermally assisted techniques. Thus, includes lower risk for but suffers from low recovery rates of the heavy oil. On average the recovery rates are around 5,6% with vertical drilling and may be increased to 10% with the use of horizontal wells. Yet, the increase in the percentage comes with 3 to 5 times higher additional costs due to horizontal drilling.

Steam Assisted Gravity Drainage (SAGD) (Thermal):

In SAGD, two horizontal wells are drilled parallel to one another with one of them remains a few meters lower. To increase the liquidity of the oil, steam is injected into the upper well (with chemical solvents) and heats the crude. With the assistance of gravity, the liquid crude flows into the lower well where it is collected and pumped to the surface. The recovery rate of the method is remarkably high, allowing for up to 40-60%, along with high production rates. In addition to production efficiency, contaminants like methane and carbon dioxide rise with steam while oil falls with greater density. Thus, large portion of contaminants that are common in heavy oil deposits are removed underground. Unfortunately, there are two major disadvantages; first one is the high cost of steam generation. The second is the likely negative externalities caused by the need for a large water supply such as drought and water pollution. During the gravity drainage, up to 90% of the water used during extraction is recycled and used again. However, the remaining 10% water in the form of the steam which interacted with the bitumen exits the upper well, expanding out into the formation in all directions.  This brackish water interacted with petrochemicals may contain a variety of pollutants. “Although the land impact is small, surrounding ecosystems could be dramatically affected depending on the ecological significance of the land” (J.M.K.C. Donev et al., 2018).

Vapor Extraction Process (VAPEX - Non-thermal):

VAPEX is like SAGD, but solvent gas or mixture of solvents (i.e.propane, buthane depending on the reservoir pressure or temperature) are used instead of steam. It is more efficient in terms of energy used than is SAGD. Yet, the dispersion and diffusion of the solvents are relatively slow and the process itself is less efficient compared to SAGD. The recovery factor of the conventional VAPEX process is around 25%. However, using montmorillonite Nanoclays have proved to increase this factor and production rate in VAPEX process by a factor of 30((±4)%(Pourabdollah et al.,2011).

Cyclic steam stimulation (CSS- Thermal):

A three stage process. First, the well is injected with high pressure steam for about a month. Then, the heat is left to distribute within and finally put into production. Once the production starts, it increases to a high rate quickly and after staying at that level for a short-time, gradually declines over several months. The cycle repeats itself when oil production rate stops being economically viable. Geologically speaking, this is a sensitive method because the high pressure steam creates fractures in the formation of the ground. Therefore, there needs to be an overburden cover for at least 300 metres and heat distribution near the well should be able to occur by itself. This method is attractive because it has quick pay out; however recovery factors are comparatively lower than other thermal techniques. Due to the discontinuous nature of the process, the recovery rate differs between 10-40%.

In Situ Combustion (ISC - Thermal):

In ISC, small fraction of the oil is burned by injecting air into the reservoir. Then, flow of the unburned fraction would be enabled, and oil recovery would be improved. This is a favourable method for heavy oil reservoirs because the increase in temperature is high enough (400-650 C) to reduce the oil viscosity by several orders of magnitude due to strong exothermal oxidation reactions between hydrocarbons and oxygen. As a result, effective displacement drive mechanism, high energy efficiency and relatively reduced environmental impact can be achieved. However, controlling this process is still inconveniently difficult in ISC to achieve wide acceptance. Unfavourable rock heterogeneity, unfavourable oil/gas mobility ratios and gas overriding are some of the control problems ISC faces.

Delayed Coking Technology of Inferior Heavy Oil Residual (Thermal):

The features of this method are claimed to have high adaptability, high deep conversion, and low investment. Also, it is argued that the yields of the process include coker gasoline, coker diesel and coker gas which can be used in producing different products such as; ethylene, cetane and hydrogen, respectively. The technical features are: Restraining the production of coke, optimize process parameters during delayed coking, and the developed process package of delayed coking of 4,300,000 tons of heavy oil annually; Improving liquid yield and reducing energy consumption by modifying heating furnace, coking drum, and fractionating system; Combination of optimized viscosity reduction coking process improves total liquid yield by 5% and reducing coke produced by 1.5% comparing to process of delayed coking.”

 

Table 17: Coking Delaying Plant of 1,000,000 T/Y At ‘Liaohe’ Petrochemical Using Venezuelan Super Heavy Oil (2011)

 

Items

Circulating ratio 0.3

Circulating ratio 0.1

Circulating ratio 0.6

Yield (%)

Yield (%)

Yield (%)

Dry gas

9.44

7.95

10.88

Liquefied gas

2.36

2.05

2.56

Gasoline

12.58

11.23

14.81

Diesel oil

37.57

31.31

39.15

Wax oil

8.03

20.15

0.44

Shed oil

2.17

1.83

2.52

Coke

27.71

25.35

29.54

Loss

0.14

0.13

0.1

Yield of light constituent

50.15

42.54

53.96

Liquid yield

58.18

62.69

54.4

Total yield

99.86

99.87

99.9

 

 Toe-to-Heel Air Injection (THAI) (Thermal):

“Toe-to-Heel’’ Air Injection is one of the newest heavy oil extraction processes and combines ISC with a horizontal production well. THAI eliminates the tendency for gas overriding and is considered to be much more stable than conventional ISC. Also, it is claimed that THAI uses less freshwater than other extraction methods like SAGD, have less surface impact and needs less land to be utilized because it uses less equipment. Yet, the main objective is to add more control to the conventional ISC process. “A horizontal producer well is positioned in a line drive in the reservoir and air is injected via a vertical well, an arrangement that effectively solves the problem of gas overriding. Moreover, the horizontal well effectively self-seals as coke is formed as the combustion front progresses, closing off the ‘‘toe’’ and preventing gas bypass” (Shah, et al., 2010). In 2006, when PetroBank first tested the technique in operation, the API of the produced oil had upgraded compared to the original value. Thus, only about 15% of diluent was needed to meet pipeline specifications. When the non-upgraded oil was produced from SAGD and CSS operations, 30-50% diluent was required.

“And added side-effect of THAI is the simultaneous upgrading of the oil which is not only beneficial for the actual oil recovery but also aids transportation, downstream refining and increases the value of the produced oil. Experimental and field pilot results indicate sulfur and heavy metal content is reduced.” (Calgary & Alberta, 2015)

THAI potentially allows the inclusion of a catalytic upgrading stage, since it provides favourable operating temperatures at the production well as the combustion zone is ‘anchored’ to the horizontal well” (Shah, et al., 2010)

Carbon Dioxide Enhanced Oil Recovery (Miscible Method)

A pipeline delivers CO2 to the oil field at certain pressure and density depending on the project. There must be injection wells present and strategically placed within the patterns of well to optimize the areal sweep of the reservoir. Later, the CO2 is directed to these injection wells where CO2 enters the reservoir and moves through the pore spaces of the rock and becoming miscible with the crude coil to form a concentrated oil bank that is swept to producing wells. Oil and water is pumped to the service at the producing wells and then flow to a centralized collection facility.

“Implementing a CO2 EOR project is a capital-intensive undertaking. It involves drilling or reworking wells to serve as both injectors and producers, installing a CO2 recycle plant and corrosion resistant field production infrastructure, and laying CO2 gathering and transportation pipelines. Generally, however, the single largest project cost is the purchase of CO2. As such, operators strive to optimize and reduce the cost of its purchase and injection wherever possible” (U.S. Department of Energy, 2010). 

Appendix C

Sanctions on Qatar

 

The 2017–18 Qatar diplomatic crisis began in June 2017, when Bahrain, Djibouti, Egypt, Jordan, Mauritania, Saudi Arabia, Senegal, the Comoros, the Maldives, the Hadi-led Yemeni government, the Tobruk-based Libyan government and the United Arab Emirates severed diplomatic relations with Qatar and banned Qatar airplanes and ships from entering their airspace and sea routes along with Coia blocking the only land crossing. The Saudi-led coalition cited Qatar's alleged support for terrorism as the main reason for their actions, insisting that Qatar has violated a 2014 agreement with the members of the Gulf Cooperation Council (GCC). Saudi Arabia and other countries also criticized Al Jazeera and Qatar's relations with Iran.

Qatar has been becoming a leading economic power in the Middle East with a population of 2.64 million. As exhibited in Table 6, they have been significantly strengthening their role in the international energy commodity trade, especially in natural gas markets through immensely increasing exports of LNG. Aside from the political rhetoric, it would not be misleading to assume that Saudi Arabia has started to see Qatar as a rival to its economic and political dominance among Middle Eastern countries and OPEC. These sanctions could very well be a signal that this is the case now.

Nevertheless, these sanctions on Qatar do not put any constraints on the physical trade of commodities but only restrict ships originated from Qatar to enter the countries mentioned in the first paragraph. Thus, these sanctions will not increase the transportation costs of potential imports of condensate destined for Turkey.

 

 

 

 

 

Appendix D

Table 18: Operational Oil Wells in Turkey and Their Production Capacity

Panel A: Statistics of Oil Production in Turkey (2017)                                                                                            

Oil Production

 

2,55 million tons

 

Daily Average Production

 

 

51.000 barrel/day

 

Rate of Production Meeting Consumption

 

 

%7

 

Total Producible Reserve

205,4 million tons

 

Cumulative Production (1954 – 2017)

152,8 million tons

 

Remaining Producible Reserve

365,2 million tons

 

 

Panel B: Well Stats (1934 – 2017)

Number of Drilled Oil Wells

4.734

Distribution of Oil Wells

1.751 Exploration wells 
1.745 Production wells 
822 Detection wells

Total Depth of Wells

8,251 million meters

 

Panel C: Well Stats (2017)

The Most Produced Crude Oil Well (2017)

Batı Raman / Batman
(Average 7013 barrels per day)

Minimal Production of Crude Oil Well (2017)

Çiksor / Diyarbakır
(Average 3 barrels per day)

 

Panel D: License Statistics (1954 – 2017)

Total Exploration Application

5.144

Granted Total Exploration License

3.232

Current Exploration License (2017)

175

 

Panel E: Discovery Statistics (1934 – 2017)

Total Crude Oil Exploration

121 production bases 1276 crude oil wells

Total Natural Gas Exploration

231 natural gas wells in 55 production lines

Discovery Rate in Turkey

%32

 

Panel F: Contribution of Exploration - Production Sector to the Turkish Economy (2001 - 2017)

Investment

:

9,5 billion USD

Domestic Production Market Value

:

7 billion USD

Employment

:

10.000 people

Source: Turkish General Directorate of Petroleum Affairs 2017 Report

Table 19: Oil Well Types in Turkey

 

WELL TYPES

 

YEARS

EXPLORATION

EXTENSION

PRODUCTION                    

INJECTION               

GEO.INVEST.

TOTAL

 

 

 

 

   

 

  

 

 

 

  

 

  

 

 

 

NO.         

METRES      

NO.         

METRES      

NO.         

METRES      

NO.         

METRES      

NO.         

METRES      

NO.         

METRES      

2007

43

81,362

55

67,646

32

48,562

 

 

2

879

132

198,449

2008

53

98,598

40

52,151

30

40,88

4

6,207

127

197,835

2009

51

88,907

50

80,185

42

73,265

143

242,357

2010

93

150,982

52

78,258

62

93,815

207

323,055

2011

81

143,675

27

41,176

61

110,306

2

2,792

171

297,949

2012

83

159,451

23

42,083

52

95,042

1

2,94

159

299,516

2013

67

122,681

32

63,465

74

117,499

473

916

173

305,034

2014

48

103,531

39

85,669

99

186,114

2

3,832

188

379,146

2015

31

68,247

8

25,449

23

42,083

62

135,779

2016

13

20,272

9

16,055

22

38,972

44

75,298

2017

21

37,795

20

38,444

40

67,043

 

 

 

 

81

143,282

Source: Turkish General Directorate of Petroleum Affairs

Most of the oil wells in Turkey are located in south-eastern region of the country. Raman, Bati Raman, Garzan, Germik, Kurtalan, Bada, Celikli, Kahta, Kayaköy, Kurkan, Beykan, Bati Kayakoy, Sahaban, Bulgurdag, Silivanka, Malehermo are some of the oil fields in Turkey.

 

 

 

 

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[1] SCF/STB: Standart cubic foot per stock tank barrel

[2] API gravity is a specific gravity scale created by the American Petroleum Institute (API) to measure the density of petroleum liquids. The higher the API gravity value, the lighter the material. Oil that has an API gravity of more than 30° is considered light

[3] According to Oil and Gas Financial Journal, Refiner Philips 66(PSX.N) and Plains All American (PAA.N). Yet, there is no consensus on a specific degree with a universal standard.

[4] wellhead is the component at the surface of an oil or gas well that provides the structural and pressure-containing interface for the drilling and production equipment.

[5] The physical and chemical properties of condensates produced by Qatar are reported in the tables in Appendix A

[6] We had an interview with Necdet Pamir, who has worked in the Bati Raman oil field, about the oil recovery methods being used in Turkey. He asserted that Turkey mostly uses primary oil recovery methods but in some areas secondary and enhanced oil recovery methods are being used. As secondary oil recovery method, Turkey uses water vapour and carbon dioxide injection methods.

[7] Information on other enhanced recovery methods used in heavy oil industry are provided in Appendix B