INTERNATIONAL OIL CORPORATIONS (IOCS), ASSOCIATED GAS UTILIZATION
TECHNOLOGIES AND GAS FLARE ELIMINATION STRATEGIES: IMPLICATION FOR ZERO-GAS
FLARING REGIME IN NIGERIA
Ernest Toochi Aniche1
1 Department of
Political Science, Faculty of Humanities and
Social Sciences, Federal University Otuoke (FUO), P.M.B. 126. Yenagoa. Nigeria.
|
|
ABSTRACT |
Keywords: Oil, Gas, Flaring, Policy, Utilization, Rentierism,
Multinationals, Nigeria . |
|
The purpose of this
study is to determine if the adoption of inefficacious gas utilization
technologies and gas flare elimination strategies by IOCs hinders their
compliance to the zero-gas flaring deadlines resulting to the failure of
zero-gas flaring policy in Nigeria. By adopting rentier state theory, using
qualitative methods and relying on secondary sources of data, the study
concludes that adoption of ineffective gas utilization technologies and gas
flare elimination strategies by oil multinationals impedes them from
complying with the zero-gas flaring regime leading to the failure of zero-gas
flaring policy in Nigeria. Publisher All rights reserved. |
INTRODUCTION
Most
IOCs operating in the Nigerian upstream oil subsector such as Shell, Agip, Elf,
Texaco, Mobil, Phillips, Pan Ocean, etc. are in joint venture partnerships with
Nigerian National Petroleum Corporation (NNPC). IOCs are still flaring
associated gas in Nigeria and have consistently failed to comply with the
zero-gas flaring deadline in Nigeria leading to perpetual shift in zero-gas
flaring deadlines from 2003 to 2004 to 2008 to 2009 to 2011 to 2012. The oil
multinationals were unable to eliminate gas flaring given that the total gas
utilized being 1,781,370,022 scf was below the total gas produced, that is,
2,400,402,880 scf resulting in 619,032,858 scf of total gas flared in 2011
(Ifesinachi and Aniche, 2014).
IOCs place emphasis on
maximization of profits over adoption of effective gas flare elimination
strategies and efficacious gas utilization technologies. Also, available
records indicate that oil multinationals in the oil joint ventures with NNPC
prioritized profits and revenues through increase in oil production without
pegging oil production to the gas utilization capacity required to meet policy
deadline (Aniche, 2015). Perhaps it is noteworthy to state here that gas
flaring has global and local environmental, economic and health implications.
The objective of this study, however, is to
sufficiently establish if the adoption of ineffective gas utilization
technologies and gas flare elimination strategies by IOCs impedes their
compliance to the zero-gas flaring deadlines resulting to the failure of zero-gas
flaring policy in Nigeria.
THE ASSOCIATED GAS UTILIZATION TECHNOLOGIES OF IOCS FOR MEETING
ZERO-FLARING DEADLINE IN NIGERIA
Apart
from providing gas gathering facilities as discussed below, IOCs operating in
Nigeria upstream oil subsector in joint ventures with NNPC are also active in
providing gas processing facilities. Some of these technologies which are
adopted by the IOCs in storing and processing associated gas (AG) include gas flow meters, reinjection, Liquefied
Natural Gas (LNG), Liquefied Petroleum Gas (LPG), Gas-to-Liquids (GTL),
Compressed Natural Gas (CNG), Gas-to-Power (GTP), Gas-to-Solid (GTS), etc.
The available gas flow meters to measure flared and
vented gas flow rates associated with oil production include ultrasonic flow
meters, optical flow meters, insertion turbines, averaging pilot tubes, and
measuring technologies like insertion turbines, pitot tubes, differential
pressure flow meters and thermal mass meters are limited by such factors as
high flow velocities, large pipe diameters, changing gas composition, low
pressure, dirt wet gas, wax, condensate and high concentrations of contaminants
like CO2 and H2S. Ultrasonic flow meters have been in use
since 1987. They measure flow velocity by determining the time it takes for an
ultrasonic pulse to travel between two fixed transducers located in the pipe.
Ultrasonic meters are cost effective for measuring gas flare volumes in that
maintenance is minimized by self-diagnostics. They are independent of pipe
size, and are not affected by extreme flow velocities and changing gas
composition. The measurement accuracies of ultrasonic flow meters range from
2.5 percent to 5 percent of the actual values. Orifice and Venturi meters can
be used instead of ultrasonic for stable gas flows and they are applicable to
wet and dry gas streams containing contaminants. But they do not perform well
for a broad range of flow rates, and need to be calibrated frequently for
changing gas composition (Buzcu-Guven, Harriss and Hertzmark, 2010).
Optical flow meters are devices capable of deployment
in harsh oil field conditions and use laser or LED light to determine the flow
velocity by measuring the time between two perturbations in light beans using
the small particles in the gas steam. The perturbations are detected using two
optical sensors separated by a known distance. Optical flow meters are
independent of gas composition, flow characteristics, pressure and temperature,
and have measurement accuracies ranging from 2.5 percent (Buzcu-Guven, Harriss
and Hertmark, 2010).
Re-injection is a commonly used method to preserve gas
for future use or to increase the efficiency of the oil production process
while utilizing the AG that would otherwise be flared or vented. The technology
involves the installation of a gas compressor to re-pressurize areas of
low-pressure formation gas thereby enhancing oil production. As an alternative
to gas compressors, multiphase pump systems in which oil and gas can flow
together, have a smaller equipment size and allow determination of the flow
characteristics without the need to separate oil and gas. However, the
re-injection option is not applicable in some geological formations (Tengirsek
and Mohammed, 2002; Broere, 2008).
The LNG technologies involve liquefaction, shipping
and regasification and delivery into the pipeline grid. This is the process by
which natural gas, mainly methane, is cooled and liquefied through cryogenic
processes at a temperature of
approximately -2600F (-163oC) leading to formation of
liquefied natural gas. As result of this, natural gas volume is reduced to one
six-hundredth (1/600) allowing its transportation by specialized LNG tanker
ships over long distance. LNG technology uses a refrigeration process in which
the gas is pre-treated for impurities like Sulphur, CO2, water, and other contaminants; and transformed into
liquid by being cooled to -162oC and stored until it is shipped
on-board LNG tankers (Zhang and Pang, 2005; Lichun, et al 2008). A typical LNG receiving terminal includes storage
tanks and infrastructure for the regasification processes. The three basic
vaporizers or gasifiers are Submerged Combustion Vaporizers (SCV), Open Rack
Vaporizers (ORV) and Ambient Air Vaporizers (AAV). This process was adopted by
Nigerian Liquefied Natural Gas (NLNG) (Ahmad, et al, 2002; Fleisch, et al,
2002; Rahman and Al-Masamani, 2004; Apanel, 2005; Rahmin, 2005).
LPG is an alternative way of utilizing AG because of
its easy storage and transport to local markets, and due to the higher
percentage or proportion of propane and butane. To extract the LPG, AG must
first be treated for removal of impurities including water vapor, CO2,
mercury vapor and H2S. Conventional LPG processes treat the whole
gas steam before extracting the LPG content. However, these processes are not
economical and practical for AG which is produced in much lower volumes with a
lower pressure than non-associated gas (NAG) from gas wells. The LPG is
produced in a three-step process involving the compression of the AG,
condensation of the heavy carbon fraction by cooling the compressed gas, and
separation of the heavy fraction to produce LPG. LPG production does not
require extreme cooling temperatures or extreme pressures, chemicals, and
cooling agents (Sonibare and Akeredolu 2006; Buzcu-Guven, Harriss and
Hertzmark, 2010).
GTL or syngas involves a chemical reaction of dry
natural gas (methane) with either oxygen or steam using reformer producing a
mixture of hydrogen and carbon monoxide (H2 + CO) in a ratio of two
is to one (2:1). There are three principal technologies for GTL or syngas
production using natural gas as feedstock which include steam methane reforming
(SMR), partial oxidation reforming (POXR), and auto-thermal reforming (ATR).
The conversion of H2 and CO mixtures to liquid hydrocarbons is based
on F-T Catalytic synthesis with ideally H2CO ratio of two is to one
(2:1). The reaction is strongly exothermic meaning that significant heat must
be removed. In this process, reactors are designed to efficiently remove heat
to required practically uniform temperature conditions for the reaction,
depending on the reaction conditions, type of catalyst used and the reactor
configuration (Aniche, 2015).
Fischer-Tropsch (F-T) Synthesis can be used to produce
liquid alkenes (paraffin), liquid alkenes (olefins) and oxygenates such as
alcohols. F-T products like paraffin and olefins can be further treated to
maximize their sales value or to meet particular market needs. In other words,
paraffin and olefins can be upgraded using standard hydro-cracking,
hydrogenation, oligomerization, and isomerization processes. The breakdown of
the fractions of GTL is naphtha 15-25%, middle distillates 65-85%, and
associated LPG condensates about 0-30%. This is the gas utilization proposed
strategy by Chevron operated JV Escravos Gas-to-Liquids (EGTL) (Ahmad, et al, 2002; Rahmin, 2005).
Therefore,
GTL technology is a chemical process that converts methane gas into
transportation fuels like naphtha, etc. the GTL technology is therefore often
called Fischer-Tropsch-Gas-to-Liquids (FT-GTL) technology because the
Fischer-Tropsch (F-T) chemical conversion is the main process in converting the
gas into liquid hydrocarbons. The utilization of AG through GTL processes is
more challenging and capital intensive for offshore production facilities. The
GTL diesel is a low Sulphur, low aromatics, and high cetane number fuel,
providing high combustion quality and significant emission reductions and as
well compatible with existing diesel engine technology. Also, GTL naphtha with
high quantity chemical composition free of metals, aromatics and Sulphur is an
ideal feedstock for petrochemical production. GTL kerosene blends or GTL jet
fuel have significantly lower emissions of particulate matter and other
pollutants and higher energy density which has recently been approved for use
in commercial aircraft (Fleish, et al,
2002; Hall, 2005; Oguejiofor, 2006; Buzcu-Guven, Harriss and Hertzmark, 2010).
CNG is obtained when a fluid natural gas is compressed
at low or ambient temperature to a density of about 150 to 250 kg/m3 compared
to 600 kg/m3 for LNG. The CNG is filled into large pressure bottle
of about 110cm diameter and 36cm in length and transported by ship to a
receiving terminal. This technology is most efficient alternative channel of
harnessing stranded gas. CNG is a safe and environmentally friendly fuel that
produces non-toxic vapor and provides operations with reduced noise pollution.
It provides toxic soot pollution reduction by about 75 to 90 percent and smog
forming pollution reduction by about 25 percent compared to conventional
automobile fuel (Rahman and Al-Masamani, 2004; Apanel, 2005).
Thus, CNG is natural gas compressed to a much lower
volume (1/200 of the original volume) at pressures between 8,300 and 30,000
kilopascals (kpa). CNG is stored and transported in cylinder usually made with
fiber reinforced plastic (FRP). The advantages of FRP over metal/steel gas
containment systems are that it is light weight, corrosion resistance, durable,
safer, and lower capital and operational costs. CNG technology is suitable for
land transport over short distance and has the potential to become preferred
method of utilizing AG in offshore platforms where building pipelines or LNG
plants are not economical or practical. Since CNG is land transportable and
easily redeployable, it can be used in fields with relatively short production
horizons. Thus, CNG is used primarily as a transport fuel and in small scale
transport road projects (Marcano and Cheung, 2007; Buzcu-Guven, Harriss and
Hertzmark, 2010).
Gas-to-Power
(GTP) or Gas-to-Wire (GTW) or Gas-Fired Power Generation is a strategy of using
natural gas to generate electricity in a variety of ways. The most basic
natural gas-fired electric generation consists of a steam generation unit, in
which fossil fuels are burned in a boiler to heat water and produce steam that
turns a turbine to generate electricity. This process of generating electricity
through steam boiler has fairly low energy efficiency in that only 33 to 35
percent of the thermal energy used to generate the steam is converted into
electrical energy. Gas turbines and combustion engines are also used to
generate electricity. In this process, instead of heating steam to turn a
turbine, hot gases from burning fossil fuels (particularly natural gas) are
used to turn the turbine and generate electricity. Gas turbine and combustion
engine plants are traditionally used primarily for peak-load demands, as it is
possible to quickly and easily turn them on. However, this process is still
traditionally slightly less efficient than large steam-driven power plants
(Ahmad, et al, 2002; Apanel, 2005;
Rahmin, 2005).
The “Combined-Cycle” Units involve many of the new
natural gas fired power plant. In this hybrid process of gas-to-power
generating facility, there is both a gas turbine and a steam unit, all in one.
The gas turbine operates in much the same way as a normal gas turbine using the
hot gases released from burning natural gas to turn a turbine and generate
electricity. In combined-cycle plants, the waste heat from the gas-turbine
process is channeled or directed towards generating steam, which is used to
generate electricity much like a steam unit. As a result of this efficient use
of the heat energy released from the natural gas, combined-cycle technologies
are much more efficient than steam units or gas turbines alone and can achieve
thermal efficiency of 50 to 60 percent. Gas-to-Power technologies are utilized
by the NIPP and JVIPP in Nigeria (Fleisch, et
al, 2002; Rahmin, 2005).
GTS or Gas Hydrates are ice like solid crystalline
compounds formed by the chemical combination of natural gas and water. This
process is obtained where individual gas molecules exist within cages of water
molecules, CH4.nH2O where n is greater than or equal to
5.75, under pressure and temperature considerably higher than the freezing
point of water. In the presence of free water, hydrate will form when
temperature is below a typical temperature called hydrate temperature. Natural
Gas Hydrate (NGH) can contain about 160m3 of methane per 1m3
of hydrate. Hydrate technology therefore focuses on using gas hydrate to
convert gas to a solid to transport natural gas to market as a low cost
solution to managing AG in regions lacking in gas infrastructure and/or
market. The advantages is that large
quantities or volumes could be stored because volumes are reduced by a factor
of about 180 which is less than the 200 and 600 volume reductions for CNG and
LNG, respectively (Alawode and Omisakin, 2011).
Thus, natural gas hydrate (NGH) is crystallized
natural gas which is a solid material or substance in an ice state and
chemically stable at -20oC. The stabilizing temperature is
considerably higher than the LNG temperature -162oC, which leads to
lower capital transportation and storage costs. However, NGH is far less dense
than LNG and the quantity of gas transportable in hydrate form is lower than
LNG technology (Buzcu-Guvan, Harriss and Hertzmark, 2010).
Compared to other gas processing technologies such as
LNG and GTL, GTS hydrates conversion technology is relatively simple, low cost,
less complex, low pressure and temperature. This GTS technology does not
require complex processes or extremes of pressure or temperature. It can be
small-scale, modular and particularly appropriate for offshore associated gas
applications. In much simpler form, the hydrate production concept amounts to
adding water to natural gas and “stirring”. Gas hydrate could be produced by
contacting natural gas with water at 10oC and 20 bars, after which
the temperature is lowered to -10oC for the gas molecules to be
trapped in metastable ice structure that forms solids at ambient temperature.
Gas hydrate crystals resemble ice in appearance but do not have the solid
structure of ice. They are much less dense and exhibit properties that are
generally associated with chemical substance. The main framework of their
structure is water and the hydrate molecules occupying the space in the crystal
structure are held together by chemically weak bonds with the water (Alawode
and Omisakin, 2011).
Methane in AG can also be converted to methanol, which
is further used to produce dimethyl ether (DME) and olefins such as ethylene
and propylene in simple rector systems, conventional operating conditions and
commercial catalysts. Lurgi’s Mega Methanol, MTP, and MegaSyn technologies and
Topsoc’s DME process provide cost-effective and large economy-of-scale
solutions to gas conversion. Methane in AG can also be converted to ammonia through
the Haber process to produce nitrogen fertilizers (Buzcu-Guven, Harriss and
Hertzmark, 2010).
However, none of the current gas utilization
technologies and methods is economical if the AG volumes are below 10 mcm per
year and the oil field located more than 2,000 km from the closest market. As
for LNG and GTL technologies, LNG has higher plant efficiency and less complex
infrastructure needs. Both LNG and GTL have comparable full life cycle capital
costs. Although LNG has slightly lower operating costs than GTL, the total
production costs for LNG and GTL products for the same amount of natural gas is
quite equivalent. Both are environmentally friendly alternatives, but LNG
products are generally used as fuel in power generation, heating and industrial
processes. GTL serves a different energy market than LNG with most of the GTL
plants yield as low Sulphur transportation fuels. The pricing for LNG products
requires long-term contracts (more than 20 years) between the supplier and the
consumers, and the actual price is adjusted according to the price of crude
oil. On the other hand GTL products can be sold in open markets and does not
require long term contracts (Buzcu-Guven, Harriss and Hertzmark, 2010).
In the case of LNG to pipeline and CNG alternatives
for exploitation of stranded gas, the full chain cost of a typical CNG process
including compressing, loading, shipping and unloading, is substantially
cheaper than that of an LNG process at moderate distances (up to 3,000 km) and
for smaller fields (less than 100 mmcf per day). A CNG plant with load
facilities, compressors, pipelines, and buoys costs $30 to $40 million. CNG
ships with chillers and fluid displacement on-board cost about $230 million,
but carry less gas than LNG tankers. For smaller fields or longer distances,
CNG becomes uneconomical. CNG facilities
require a shorter construction period or timeframe (between 30 and 36 months)
than LNG and GTL facilities which are usually completed in 4 to 5 years (Buzcu-Guven,
Harriss and Hertzmerk, 2010).
THE GAS FLARE ELIMINATION STRATEGIES OF IOCS FOR ACHIEVING ZERO-GAS
FLARING POLICY IN NIGERIA
In
spite of the shortcomings, the IOCs operating in the Nigerian upstream
subsector in joint venture partnerships with NNPC have made some efforts at
complying with gas flare out regime. At best, the oil multinationals have been
able to reduce the volume of associated gas (AG) flared in Nigeria both in
absolute and relative terms, for example, from 59.64 percent amounting to
792,247,965 in 1999 to 23.84 percent in 2011 totaling 514, 799,616 (Aniche,
2014).
The efforts of the oil multinationals in Nigerian
upstream oil subsector can be divided into providing gas gathering, gas
processing and gas distribution facilities. The gas gathering facilities are
provided to gather gas for field injection purposes and to be channeled to the
flare stack. Some of these gas gathering facilities are ChevronTexaco
facilities, ExxonMobil facilities, Shell facilities, Nigerian Agip Oil Company
(NAOC) facilities, etc. The ChevronTexaco gas gathering facilities consist of
three phases or stages of Escravos Gas Pipeline (EGP). The first phase of the
EGP, EGP-1 was completed in 1997 which facilitates expansion of utilization of
natural gas within Nigeria. EGP-1 processes 165 mmcf/d of associated natural
gas which is supplied to domestic market by pipeline. The second phase of the
EGP, EGP-2 processes an additional 135 mmcf/d of AG, which began operation in
2000 utilized within Nigeria with a provision for export to Benin, Togo, and Ghana
through the West African Gas Pipeline (WAGP) when completed. The third phase of
the EGP-3 will increase gas processing to 400 mmcf/d of AG from Chevron’s
fields (Dayo, 2008).
The ExxonMobil gas gathering facilities consist of gas
re-injection facility which was completed in 1978. The facilities assisted the
ExxonMobil operated JV to reduce flaring of associated gas on its oil fields by
about 1.2 bcf from 49.9 bcf in 1977 to 48.7 bcf in 1978. The facilities also
consist of ExxonMobil operated Oso Gas Compression facility which commenced
operations in 1997 and built to re-inject about 600 mmcf/d of AG to aid the
recovery of about 100,000 bbl/d condensate deposits. The facility located at
Bonny Island, Rivers State covers 15 wells, 6 gas re-injectors and a 61
kilometer pipeline. The combined gas streams from the wells are compressed to
5500 Psia (Dayo, 2008).
The Shell Gas Gathering facilities which were built as
early as the seventies had gas transportation infrastructure to serve specific
industrial customers in Port Harcourt and Aba in the south-eastern parts of
Nigeria. Other examples of Shell gas gathering facilities at different advanced
stage of completion include Cawthorne Channel Gas Injection or Associated Gas
Gathering which involve the gathering of about 176 mmcf/d of rich gas,
extraction of liquids and supply of the lean gas to the domestic market;
Forcados Yokri Integrated project which involves the gathering of about 108
mmcf/d of associated gas (AG) for gas lift and about 53 mmcf/d as fuel. The facilities
will also supply about 55 mmcf/d to NLNG Train 3, while some will as well be
used for gas lift (Dayo, 2008).
The NAOC Gas Gathering facilities operate two gas
re-injection plants. The first was established in 1985 at Obafu/Obrikom. The
second was commissioned in 1987 at Kwale/Okpai. Both facilities were built to
reduce associate gas flaring in Nigerian oil fields. In 1994, NAOC commissioned
another gas plant for the supply of national gas liquids to the Eleme
Petrochemical Plant. One other more recent gas gathering facility that is being
implemented by NAOC is the NLNG Gas Supply Phase 3 which will supply additional
gas of about 164 mmcf/d to meet the LNG requirements of train 3 and increase
total capacity to 650 mmcf/d came on stream in 2005. Another of these
facilities, Idu Field Revamping and Gas Recovery built to gather about 100
mmcf/d of associated gas (AG) in Idu and Samabiri fields for gas, supply to
NLNG Trains 4 and 5 (Dayo, 2008).
Thus, over the years there has been a growing
utilization of natural gas in Nigeria. For instance, in 1970, about 8.1 bcm of
natural gas was produced in Nigeria and about 0.1 bcm (slightly less than 1.4%)
was utilized for productive activities mostly for gas injection in oil fields
for field pressurization and oil lifts and some small amount for power
generation mostly in the oil fields. The balance of about 98.6 percent
amounting to about 8.0 billion cubic meters (bcm) was wastefully flared. By
2005, there was improvement in gas utilization as out of the 59.3 bcm of
natural gas produced about 61.2 percent was utilized domestically as input in
production of LNG, injected in oil fields, utilized as fuel in power generation
even in power facilities outside the oil and gas fields; as fuel industries
while the balance was flared (Dayo, 2008).
The significant increase in domestic utilization in
the recent years was propelled by its increased use in generating power, and
the use as an industrial energy fuel. Also, the export of natural gas commenced
on October 1999 when a consignment of LNG was shipped out of the facilities of
NLNG in Bonny. The total production of the NLNG of Trains 1 and 2 of 7.22 bcm
per year is exported under a long term sales and purchase agreement with
international buyers such as Enel of Italy (3.50 bcm per annum), Gas
Natural/Enagas of Spain (1.60 bcm Per annum), Botas of Turkey (1.20 bcm per
annum), Gas De France (0.50 bcm per annum), and Trangas of Portugal (0.35 bcm
per annum) (Dayo, 2008).
As at February, 2003, NLNG had loaded 318 LNG cargoes
to its long term customers since October 1999. A year earlier, in 2002, 107
were actually loaded and four out of the 107 cargoes were sold as spot cargoes.
In 2007, 130 cargoes were loaded. The Train 3 which began operation during the
fourth quarter of 2002 guarantees the delivery of 317 bcm a year. A 21-year
sales and purchase agreements have been executed with the Gas Natural/Enagas
(2.7 bcm per annum) and Trangas (1.0 bcm per annum). The above makes NLNG the
largest supplier of LNG to Portugal (Dayo, 2008).
The IOCs operated joint venture gas supply systems in
Nigeria include one, Shell’s gas supplies systems to the defunct National
Electric Power Authority (NEPA) in Delta I, II and III, Aba industries and the
Rivers State Utility Board (RSUB); two, Nigerian LNG gas transmission; and
three, NAOC gas supply system to Eleme Petrochemicals (Dayo, 2008). Shell
operated joint venture partnership claims to have pioneered gas utilization in
Nigeria, which it pursued since 1960s. For history of the Shell operated JVs
gas utilization program, see Table 1 below.
Shell claims that under its flare-out policy or in
compliance to Nigeria’s zero-gas flaring policy, no new oil field is developed
without a comprehensive plan for the immediate utilization of the associated gas
produced from it (Omiyi, 2001). Thus, in order to actualize its gas utilization
program, some seven major gas gathering projects have been initiated to gather
associated gas from over 52 out of the 87 flowstations. For information on
Shell operated JV gas gathering projects see Table 2 below. Shell operated JV
planned to increase gas gathering capacity in proportion to increase in oil and
AG production by gathering and supplying the gas to proposed Trains 4 and 5 of
the NLNG plant as well as supply power generation plants. For major future gas
gathering projects see Table 3 below.
Shell also claims to have 17 gas gathering projects
including the integration of the Forcados oil and gas development which will
start in the first quarter of 2015, and will cost $6 billion when completed.
Shell claims that already its investments cost more than $3 billion to build
gas gathering facilities since 2000. Thus, it claims that gas flaring dropped
by more than 60 percent from over 0.6 billion cubic feet of gas a day to about
0.2 billion cubic feet. In spite of these efforts made by the oil multinational
companies in joint ventures with NNPC, associated gas (AG) is still flared in
Nigeria. Thus, the associated gas utilization technologies and gas flare
elimination strategies adopted by oil multinationals in joint venture
partnerships with NNPC has only reduced associated gas flaring but not able to
end associated gas flaring since 1970s.
THE IMPACT OF IOCS’ INEFFECTIVE GAS UTILIZATION TECHNOLOGIES AND GAS
FLARE ELIMINATION STRATEGIES ON ZERO-GAS FLARING REGIME IN NIGERIA
The
IOCs are preoccupied by the desire to maximize profits or revenues. The goal of
maximizing profits even at the expense of the NNPC, host communities and
governments overrides all other considerations including environmental
concerns. In pursuit of these primary concerns, all other considerations are
secondary or peripheral including adopting a suitable AG utilization
technologies and gas flare elimination strategies (Aniche, 2015).
Thus,
in spite of the three options to stop gas flaring like re-injection,
utilization for local use or market and utilization for export as well as the
numerous economical gas utilization technologies and effective gas flare
elimination strategies, gas flaring is still the most common practice to
dispose of the gas produced in association with crude oil. The reason being
that for oil companies to gain maximum economic profit, flaring is the most
efficient way to dispose AG. Since Nigeria has huge non-associated gas
deposits, it is more economical for the IOCs operating JVs to use NAG to
produce gas for energy source, export and local use and other purposes. This is
because AG recovery in terms of gathering, processing and distribution costs
four times more than the straight extraction of NAG (Aniche, 2014).
Going by the joint operating agreement developed by
the IOCs operated joint venture partnerships for Nigerian government approval
in 1992; one, all investment necessary to separate oil and gas from the reservoir
or deposit into useable products is considered part of the oil field
development; two, capital investment for facilities to deliver AG in useable
form at utilization or designated custody transfer points will be treated for
fiscal purpose as part of the capital investment for oil development.
Therefore, much of the capital costs for the gas gathering projects are
embedded in the capital costs (CAPEX) associated with oil production
(Economides, Fasina and Oloyede, 2004). For example, the cost estimate of constructing
an LNG plant that will process 1.35 bcf/d of natural gas either with a floating
LNG or onshore LNG plant is put at $2.80 billion which approximate with or even
slightly less than the cost of recently completed LNG plant in Nigeria. The
first phase of the Bonny LNG plant which costed $2.5 billion is expected to
treat 900 million cubic feet (mmcf) per day of feed gas. The cost estimate
gives an average activation index (IA) of $2,074 mscf/d and equilibrium price
of $2.35 mcf for just liquefaction process in Nigeria (Aniche, 2015).
The cost of transportation and regasification of LNG
is equally enormous. The cost of transporting LNG from Nigeria to the United
States and the cost of regasification has been put between $0.80/mcf and
$1.05/mcf of natural gas. If the feed gas can be made available at the current
tariff price of $0.30/mcf to the liquefaction plant, then the equilibrium price
for supplying LNG from Nigeria to the United States would be $3.45 mcf. If we
consider the cost of gathering gas, the equilibrium price could be at least
$4.25 mcf which is outside the price range that is currently considered
attractive and competitive in the international market for export.
In order to be competitive in the international
market, the IOCs resort to the drilling of NAG to supply NLNG which it was
originally meant for, and thus, avoid the use of AG in order to minimize or
reduce cost. The cost of Nigerian natural gas through LNG in terms of
developing or constructing gas infrastructure or utilization projects is very
capital intensive. To obtain commercial benefits from natural gas exported from
Nigeria or for the Nigerian natural gas to be commercially viable or beneficial
to IOCs, the price of gas in the export market must be greater than the cost of
production, liquefaction, transportation and regasification. The most critical
of these costs is liquefaction which in most cases represent between 55 and 75
percent of the total cost.
No wonder, most of the IOCs operated JVs preferred
setting up of the Liquefied Natural Gas (LNG) plants which is more
cost-efficient for processing NAG than AG thereby de-emphasizing other gas
utilization technologies like GTL, CNG and GTS which are more cost-efficient
for processing AG in Nigeria. Even in case of gas-to-power technologies, the
IOCs have continued to build steam boiler technologies and turbines and
combustion engines technologies instead of the combined cycle technologies with
most energy and cost efficiency (Aniche, 2014).
Also, pressure from home states or states of origin of
these IOCs for more crude oil supply to meet their oil import targets, meant
that they have to be preoccupied with increasing production of crude oil to
meet these targets all at the expense of the local or immediate environment.
The is because with an inadequate gas utilization or infrastructure facilities
increase in oil production will mean increasing volume of gas flaring in
Nigeria. IOCs are just willing to gain the short-term profits rather than
pursue long-term profits. These driving forces or contradictions have led to
keeping the oil flowing at minimal cost without considering the local and
immediate environment of the host communities and the people. Thus, gas flaring
in Nigeria is a consequence of cost minimization strategy though ineffective
for AG utilization or gas flare elimination (Aniche, 2015).
In other words, environment of the oil communities are
sacrificed in the altar of cost minimization strategy. The point being that
cost minimization strategy is pursued by the IOCs at the expense of effective
gas utilization technologies and gas flare elimination strategies. Ishisone
(2004) has demonstrated in his study that the LPG production and gas transmission
to power plant and industries would be the best solution to eliminate gas
flaring for oil communities in Imringi and Obama. But often the IOCs calculate
only the economic or monetary cost rather than environmental and health costs,
or in terms of economic or material resources than in terms of human resources.
The implication of the above is that the IOCs
prioritize cost minimization strategy over efficacious associated gas
utilization technologies and gas flare elimination strategies. This leads to
five major contradictions; one, contradiction between economic cost and
environmental cost; two, tension between monetary cost and health cost; three,
conflict between economic benefit and environmental benefit; four,
contradiction between monetary benefit and social benefit; and conflict between
material resources and human resources. By emphasizing the economic benefit
therefore, IOCs de-emphasize the social and environment benefits especially to
the oil communities. Thus, gas flaring is not only the cause of economic loss
in terms of wasting of energy source, among others, but is also the cause of
environmental degradation and health hazard. Gas flaring is rarely successful
in the achievement of complete combustion releasing a significant amount of
carbon monoxide (CO) and a reasonable amount of methane particularly when
vented and both greenhouse gases (GHG) results to carbon emission which
contributes to global warming and climate change.
More so, the gas flaring process with incomplete
combustion emits a variety of compounds or chemical substances such as methane,
propane, and hazardous air pollution like volatile organic compounds (VOCs),
polycyclic aromatic hydrocarbons (PAHs) and soot as well as benzene,
naphthalene, styrene, acetylene, fluoranthene, anthracene, pyrene, xylene, and
ethylene (Strosher, 1996; Leahey and Preston, 2001). The negative or hazardous
effects on human health of these gas flare substances or pollutants include
cancer, neurological, reproductive and development effects. Gas flare contains
enough amount of substances or compounds like benzene, naphthalene, toluene and
xylene to be hazardous to human health or cause numerous illness associated
with them (Kindzierski, 2000).
Although the elimination of gas flaring is accompanied
by increasing economic costs in the short-run, but when the economic, social,
health and environmental benefits are calculated there is a net economic
benefit for oil companies, oil communities, agriculture, industries and
Nigerian government even in the short-run. The improved health will provide
human resource for manpower development in Nigeria to harness her abundant
mineral resources (Ishisone, 2004).
There is no significant increase in gas re-injected
from 332,806,436 scf in 2004 to 348,331,140 scf in 2011 which peaked to
409,848,718 scf in 2009 and dipped to 21,182,682 scf in 2010. The gas for LNG
decreased from 463,380,371 scf in 2003 to 313, 087,278 scf in 2011, which
dipped to 25,866,822 scf in 2010. Similarly, gas for liquefied petroleum gas,
LPG/NGL, as feedstock to Eleme Petrochemical Company Limited (EPCL) reduced
from 47,721,060 scf in 2002 to 38,607,385, scf in 2011 dipping in 2010 to
5,204,476 scf (Aniche, 2015).
Also, fuel gas to Eleme Petrochemical Company Limited
(EPCL) shows an insignificant or marginal increase from 9,159,870 scf to
9,434,734 scf from 2002 to 2011. The result was that total gas utilized
increased insignificantly from 897,789,582 scf in 2002 to 1,781,370,022 scf in
2011 while gas flared reduced insignificantly from 45.64 percent amounting from
753,801,906 scf in 2002 to 25.79 percent
amounting to 619,032,858 scf in 2011 as gas produced increased from
1,651,591,488 scf in 2002 to 2,400,402,880 scf in 2011. Generally, the
reduction both in absolute and relative terms in gas flaring and increase in
gas utilization have not been substantial (Aniche, 2014).
Perhaps, the inference that can be drawn from the
above is that various gas flaring elimination strategies and gas utilization
technologies like LNG, etc. adopted by IOCs have not been effective in
significantly or drastically mitigating gas flaring in Nigeria let alone
meeting the zero-gas flaring deadlines leading to incessant shift in zero-gas
flaring deadlines. The IOCs operating joint venture with NNPC are preoccupied
with the gas utilization strategies which will yield more income or maximize
profits by minimizing costs and maximizing revenues, which explains the reason
for opting for LNG which is meant to process NAG at much lower costs than AG
(Aniche, 2015).
The result is that utilization of associated gas and
reduction of gas flaring have not been substantial. The IOCs were unable to
eliminate gas flaring given that the total gas utilized being 1,781,370,022 scf
was below the total gas produced, that is, 2,400,402,880 scf resulting in
619,032,858 scf of total gas flared in 2011. It resulted in insignificant
reduction in gas flaring in Nigeria from 45.65% in 2002 to 25.79% in 2011 of
all the oil companies, instead of total elimination. Thus, we conclude that
adoption of ineffective gas utilization technologies and gas flare elimination
strategies by IOCs impedes their compliance to the zero-gas flaring deadlines
thereby contributing to the failure of zero-gas flaring policy in Nigeria.
Hence, the use of inefficacious gas utilization technologies and gas flare
elimination strategies by IOCs contributes to the failure of enforcement of
zero-gas flaring regime by the Nigerian state.
CONCLUSION AND RECOMMENDATIONS
IOCs
in joint ventures with NNPC are still flaring associated gas in Nigeria and
have consistently failed to comply with the zero-gas flaring deadline in
Nigeria leading to perpetual shift in zero-gas flaring deadlines from 2003 to
2004 to 2008 to 2009 to 2011 to 2012. The IOCs were unable to eliminate gas
flaring given that 1,781,370,022 scf of the total gas utilized was below
2,400,402,880 scf of the total gas produced resulting in 619,032,858 scf of
total gas flared in 2011. It resulted in insignificant reduction in gas flaring
in Nigeria from 45.65% in 2002 to 25.79% in 2011 of all the oil companies,
instead of total elimination. Thus, we conclude that adoption of inefficacious
gas utilization technologies and gas flare elimination strategies by IOCs
hinders them from achieving the zero-gas flaring deadlines thereby resulting to
the failure of zero-gas flaring regime in Nigeria. This fact is sufficiently
explained by four main contradictions of IOCs in joint venture partnerships
with NNPC as captured by rentier state theory, namely, (a) contradiction
between rents or revenues and environment (b) conflict between profits and
environment (c) tension between national security and environmental security;
and (d) contradiction between increase in oil production and efficient
utilization of resources. Perhaps, the import of this is that needs of the
future generation are sacrificed in the altar of immediate gains. Consequently,
the environmental concerns and health of the present generation of oil
producing communities as well as global community are endangered. The fact that
environment and health of the present generation of oil bearing communities are
endangered is secondary to IOCs. In their preoccupation to maximize revenues
and profits, oil production is increased and gas flaring continues at the
expense of oil communities (Aniche, 2015).
For instance, the contradiction between profits and
environment explain the reason why IOCs are driven by desire to sustain
competitive edge over their competitors through increasing oil production in
Nigeria in order to make more profits at the expense of the oil communities.
The IOCs place high emphasis on profits, through increasing oil production,
more than on environmental protection. Thus, their major preoccupation has been
on how to develop cutting edge technology to enhance oil recovery from oil
wells and to increase deep water drilling than on developing sophisticated
technology to increase the capacity of associated gas gathering facilities in
Nigeria. The point being made is that the IOCs are more concerned in maximizing
profits through improved and efficient crude oil production in Nigeria than
developing or improving the capacity of associated gas gathering facility to
meet the zero-gas flaring deadline. In other words, the IOCs would not be able
to meet any future gas flare out deadline so long as they are preoccupied with
the drive to sustain their competitive edge over their rivals through increase
in oil production and profit maximization. IOCs are investing more in oil
production to maximize profits through increased oil production than investing
to increase the capacity of associated gas utilization facilities (Aniche,
2014).
From the
foregoing therefore, we recommend that the fundamental thing to do, given the
rentier character of the Nigerian state, is to diversify the revenue base of
the economy to reduce the excessive dependence on oil revenue by mainstreaming
other domestic sources of revenue like direct tax as well as developing other
sectors of the economy like manufacturing sector. This is a fundamental and far
reaching solution that will enable Nigerian state to de-emphasize oil revenue
in limiting oil production to the gas utilization capacity of oil
multinationals required to meet policy deadline. This will compel the IOCs to
adopt efficacious gas utilization technologies and gas flare elimination
strategies.
REFERENCES
Ahmad, I.M., Zughaid, M., El-Arafi, M. & Mohammed,
G.A. (2002). Gas-to-Liquid (GTL) Technology: New Energy Technology for the
Third Millennium. SPE Paper 78573 Presented at the 10th Abu Dhabi
International Petroleum Exhibition and Conference, Abu Dhabi.
Alawode, A.J. & Omisakin, O.A. (2011). Monetizing
Natural Gas Reserves: Global Trend Nigeria’s Achievements and Future
Possibilities. The Pacific Journal of
Science and Technology 12 (1), 138-151.
Aniche, E.T. (2014). The Effects of Oil Joint Venture
Partnerships on Enforcement of Zero-Gas Flaring Policy in Nigeria, 2003-2011. A
Ph.D Thesis Presented to the Department of Political Science, University of
Nigeria, Nsukka (UNN).
Aniche, E.T. (2015). Oil Sector and Non-enforcement of Zero-gas Flaring Policy in Nigeria.
Saarbrucken: Lambert Academic Publishing (LAP) and OmniScriptum GmbH & Co.
KG.
Apanel, G. (2005). GTL Update. SPE Paper 93580
Presented at the 14th SPE Middle East Oil and Gas Show and Conference, Bahrain.
Asada, D. (2010). The Legal Regime of Concessions
Agreements in the Nigerian Oil Industry. [Online] Available: http://dspace.unijos.edu.ng (July 6, 2012).
Broere, W. (2008). The Elusive Goal to Stop Flares. Shell World, May 5.
Buzcu-Guven, B., Harriss, R. & Hertzmark, D.
(2010). Gas Flaring and Venting: Extent, Impacts and Remedies. In J. Barnes, et al (eds.), Energy Market Consequences of an Emerging US Carbon Management Policy,
Energy Forum. Houston: James A.
Baker III Institute for Public Policy, Rice University.
Dayo, F.B. (2008). Clean
Energy Investment in Nigeria: The Domestic Context. Manitoba: International
Institute for Sustainable Development.
Fleish, T.H., Sills, R.A. & Briscoe, M.D. (2002).
Emergence of the Gas-to-Liquids Industry: A Review of Global GTL Developments. Journal of Natural Gas Chemistry 11,
1-4.
Hall, K. (2005). A New Gas to Liquids (GTL) or Gas to
Ethylene (GTE) Technology. Catalysts
Today 106, 243-246.
Ifesinachi, K. & Aniche, E.T. (2014). Oil Joint
Venture Partnerships and Nigerian Economy. University
of Nigeria Journal of Political Economy, 7 (1&2), 1-24.
Ishinone, M. (2004). Gas Flaring in the Niger Delta:
The Potential Benefits to its Reduction on the Local Economy and Environment.
[Online] Available: http://nature.berkeley.edu/classes (September 21, 2012).
Kindzierski, W.D. (2000). Importance of Human
Environmental Exposure to Hazardous Air Pollutants from Gas Flares. Environmental Reviews, 8, 41-62.
Leahey, D.M. & Preston, K. (2001). Theoretical and
Observational Assessments of Flare Efficiencies. Journal of the Air and Waste Management Association, 51, 1620-1616.
Lichun, D., Shun’an, W., Shiyu, T. & Hongjing, Z.
(2008). GTL or LNG: Which is the Best Way to Monetise ‘Stranded’ Natural Gas. Petroleum Science, 5, 388-394.
Marcano, J. & Cheung, R. (2007). Monetizing
Stranded Natural Gas. Oil and Gas
Financial Journal, 4 (2).
Oguejiofor, G.C. (2006). Gas Flaring in Nigeria: Some
Aspects for Accelerated Development of SasolChevron GTL Plant at Escravos. Energy Sources, 28, 1365-1376.
Omiyi, B. (2001). Shell Nigeria Corporate Strategy for
Ending Gas Flaring. A Paper Delivered at A Seminar on Gas Flaring and Poverty Alleviation in Oslo, Norway, June 18-19.
Rahman, G.A. & Al-Masamani, M. (2004). GTL: Is it
an Attractive Route for Gas Monetization? SPE Paper 88642 Presented at the 11th
Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi.
Rahmin, I.I. (2005). GTL Prospects: Stranded Gas,
Diesel Needs Push GTL Work. Oil and Gas
Journal (OGJ), 103 (10).
Sonibare, J.A. & Akeredolu, F.A. (2006). Natural
Gas Domestic Market Development for Total Elimination of Routine Flares in
Nigeria’s Upstream Petroleum Operations. Energy
Policy, 34, 743-753.
Strosher, M. (1996). Investigation of Flare Gas Emissions in Alberta. Alberta: Alberta
Research Council.
Tengisirek, A. & Mohamed, N. (2002). Towards Zero
Flaring. Middle East and Asia Reservoir Review,
3, 6-9.
Zhang, K. & Pang, M. (2005). The Present and Future
of the World’s LNG Industry. International
Petroleum Economics, 13, 55-59.
LIST OF TABLES
Table 1: History of Shell’s Gas
Utilization in Nigeria
Year |
Gas
Utilization Program |
1962 |
Commenced
the supply of piped gas to industries at Aba and Port Harcourt. |
1963-1965 |
Gas
for electricity generation to NEPA plants in Afam and Delta Power Station. |
1976 |
The
establishment of the Port Harcourt Refinery gave a big boost to the gas
utilization program. |
1976 |
Supply
of gas to NEPA power stations at Sapele. |
1986 |
Gas
supply to Delta Steel Company, Aladja. |
1987 |
Supply
to National Fertilizer Company of Nigeria (NAFCON). |
1988 |
Gas
Supply to Ajaokuta Steal Plant. |
1989 |
Gas
Supply to another NEPA Station, Egbin Station. |
1998 |
Piped
gas supply to Aluminum Smelter Company (ALSCON). |
1998 |
The
Shell Group incorporated Shell Nigeria Gas (SNG) to boost gas utilization by
promoting it as fuel of first choice in industry. |
1999 |
The
Nigerian LNG project began operation and to export LNG. Shell has been
involved in the various attempts to promote the project since early 1960s. |
Source:
Omiyi B (2001) Shell Nigeria Corporate Strategy for Ending Gas Flaring. In: A Seminar on Gas Flaring and Poverty
Alleviation in Oslo, Norway, 18-19 June.
Table 2: Major Shell’s Gas Gathering
Projects
Gas Gathering Projects |
Capacity of Supplies |
Soku
Gas Project |
Completed
and already delivering some 60 mscf/d to NLNG as from the first half of 2000.
Additional supplies to NLNG later will raise total supply to some 200 mscf/d
by the end of 2001. |
Obigbo
North AGG |
It
will take some 100 mscf/d of AG from number of fields to the North and East
of Port Harcourt. AG will be supplied to NEPA power plant at Afam, the NAFCON
fertilizer plant and ALSCON. |
The
Odidi Project |
This
project will take gas from the flares of Egwa, Batan and Odidi fields, and
would supply about 80 mscf of associated gas (AG) initially to the Nigerian
Gas Company (NGC) and NLNG Train 3. |
Cawthorne
Channel Project |
This
is SPDC’s largest gas gathering project which will supply 200 mscf/d of AG
from four oil fields to Local markets and the NLNG Plant, Bonny. |
The
Forcados Yokri Project |
It
will collect some 80 mscf/d of AG from four flowstations. The gas will be
combined with AG from Odidi and taken by Offshore Gas Gathering System (OGGS)
to the NLNG Plant at Bonny. |
South
Forcados Project |
The
Project will gather 150 mscf of AG from Tunu area. |
The
Belema Project |
This
is moving into the construction phase. Already some 50 mscf/d of AG from
Belema and Odeama fields is being sent to Soku for supply to NLNG Trains 1
and 2. |
Source: Omiyi B (2001) Shell
Nigeria Corporate Strategy for Ending Gas Flaring. In: A Seminar on Gas Flaring and
Poverty Alleviation in Oslo, Norway, 18-19 June.
Table 3: Major Future Gas Gathering
Projects
Gas Gathering Project |
Capacity of Supply |
Greater
Ughelli Project |
This
involves gathering AG from the surrounding oil fields. More than 60 mscf/d
will be gathered between 2001 and 2002 for supply to the Delta Power Station
and other industries in Delta State. Later additional production will be sent
to NGC’s Escravos Lagos Pipeline System to supply industries in Lagos and the
planned West Africa Gas Pipeline (WAGP). |
The
Otumara Gas Gathering Project |
This
involves gathering 80 mscf/d from oil fields to the North of the Forcados
Estuary. |
The
Oguta Gas Gathering Project |
AG
will be injected into the oil field to maintain pressure in the reservoir,
and Gbaran/Ubie will supply gas to the NLNG Train 4. |
Source:
Omiyi B (2001) Shell Nigeria Corporate Strategy for Ending Gas Flaring. In: A Seminar on Gas Flaring and Poverty Alleviation in Oslo, Norway, 18-19 June.