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, Turkeys political support for
Qatar which extends to military aid improves Qatars geopolitical power in the
oil industry significantly. On the other hand, Qatars 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 Ramans original crude oil
specifications will persist. Turkeys 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$5 billion in the 2017-2018 financial
year. This is one of the export
opportunities for Turkey. Also, India exports remarkable amount of diesel to
Turkey and certain exchange schemes will also be available in such a trade. Lastly,
considering the very low production capacity of Batı Raman oil field compared
to giant fields in Venezuela, it can be argued that finding one buyer can be sufficient for the desired export levels. If not, United
States as a major heavy crude importer can also be a viable option.
The enhanced
recovery method (EOR) employed in Batı Raman oil field since 1986; is one
of the enhanced secondary recovery methods that uses the vapor pressure of
carbon dioxide (CO2)
to push the oil to the inner reservoirs and later collect with midstream
operations. With the capacity of 1.85 billion barrels of oil, the Batı
Raman field is the largest oil field in Turkey. The reservoir fluid in
Batı Raman is a very heavy crude oil, having an API gravity ranging from
9.7 to 15.1 (mainly accepted as 12o API) and a viscosity ranging
from 450 to 1000 centipoises (which means highly vicious) at reservoir
conditions. The asphaltene content in Batı Raman oil was found to be 29%
by
Immiscible CO2
injection in Batı Ramans fractured limestone reservoirs harbouring heavy
oil was acknowledged to be a successful EOR application by Turkish Petroleum
Corporation with the achievement of lowering the oil gravity requirement to
>12°API. However, the increase in the oil production has fell far below the
values that simulation studies predicted. Over more than 20 years of injection,
the recovery peaked around 13,000 bbl/d and began to decline around 7,000 bbl/d
in 2008. Today, the oil production is around 6,500 bbl/d. Despite
ongoing problems, the Batı Raman reservoir clearly presents a significant
development opportunity for recovery improvement. The current operation
expenditure in Batı Raman field is 11,99$/bbl. according to our findings.
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
·
Deodorized Field Condensate (DFC): The field
condensates found in Qatars 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; Qatars 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.
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).
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 (2535) % 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.
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.
|
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 |
|
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 |
|
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 |
|
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 |
|
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 |
|
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 |
|
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 |
|
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 |
$51.69/bbl |
|
Year |
Total Exports ($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
|
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 others 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 fields
remaining unused potential would also strengthen the already in a good state geopolitical
relationship between two countries.
|
|
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
|
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
|
Year |
Global
LNG trade of the World(Billion Cubic Meters) |
LNG
trade of Qatar (Billion Cubic Meters) |
Qatars
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
|
|
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
|
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 |
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. Irans SPC was
as much as $5 per barrel cheaper than Qatars 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, Qatars 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 Koreas 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.
Source: JODI Database
Source: JODI Database
As
Figure 2 shows, Qatars 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 Qatars 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.
Produced
as a result of liquefaction of natural gas found in Qatars 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.
|
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% |
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.
|
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
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.
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.
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((ħ4)%(Pourabdollah et al.,2011).
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 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.
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.
|
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 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)
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
The 201718 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
|
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 |
|
|
Total Depth of Wells |
8,251 million meters |
|
|
Panel C: Well Stats (2017) |
||
|
The Most Produced Crude Oil Well (2017) |
Batı Raman / Batman |
|
|
Minimal Production of Crude Oil Well (2017) |
Çiksor / Diyarbakır |
|
|
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
|
|
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
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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
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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] A 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