India is in the early stages of a key transformation of its economy. According to an IMF report from 2017, India's economy is 3rd in the world (International Monetary Fund, 2017). It is home to about 1.4 billion people, equivalent to almost 18% of the world's population. It is a close second to China's population, which it is set to overtake by 2025. The pace of India's population growth is 15 million per year, which is currently the world's greatest numerical growth (Figure 2).

This growing population is expected to contribute more than any other country to the global energy demand by 2040. India's increasing urbanization is also a driver of the rising energy demand. According to estimates, an additional 257 million people would be living in Indian cities by 2040. Amidst rapid development, these factors are expected to intensify the current energy deficit which has about 240 million people living without access to modern energy. This gap and the need to diversify its energy portfolio will likely guide the country's energy policy in the coming years. Primarily, fossil fuels have met this demand thus far. Further expansion for oil and natural gas are difficult not just for environmental concerns, but also for the economy since India imports most of its oil and gas. As homes have moved away from traditional sources of biomass including cow dung, fuelwood, and straw, a majority of the Indian energy demand is now met by fossil fuels. Coal accounts for about 57% of the primary energy mix in India. Oil is second at 29% and followed by natural gas at 7%. Hydro, renewables, and nuclear meet the rest of the demand contributing 4, 2, and 1% respectively. Given that India is the second largest producer of coal in the world and has the fourth largest reserves, the availability and affordability of coal relative to other fossil fuels has contributed to its abundant usage in the energy sector. On the other hand, India imports almost 80% of its oil requirements, and 45% of its natural gas requirements. Figure 3 provides further insights on how energy consumption across the world has transformed over time, and the trends that can be expected in future.

By 2040, energy demand is expected to grow by ~165% as compared to current levels. Natural gas demand is expected to grow ~160%, hydropower by ~100%, nuclear by 320%, and renewables by a massive 710% (BP, 2017). Although India has added substantial renewable electricity production capacity recently, coal is expected to remain the dominant fuel in India with ~50% share in total production in 2040. Table 1 details how the world's energy mix is expected to change through 2040, while Figure 4 presents the case for India in specific.

With abundant use of coal comes the environmental challenge of increased CO₂ emissions (Guttikunda and Jawahar, 2014). India is the world's fourth largest emitter of CO₂, with emissions growing at ~5% per year in 2017, with an average steady growth of 6% over the last decade. Figure 5 provides a current sectoral view of the origin of CO₂ emissions in India (Department of Science and Technology, 2018).

The impact of emissions is widespread, going far and beyond the domains of environment and energy security. Escalating pandemic diseases and other impacts on human health are being linked to increasing emissions. Research suggests that the rampant issue of protein deficiency in India will magnify as the growing CO₂ levels in the atmosphere will affect the yield and quality of crops, putting 53 million people at a new risk of consuming protein deficient diet (Smith et al., 2017). Studies have also suggested that crops like rice will be adversely affected in terms of important nutrients like vitamin B, iron and zinc along with protein levels (Zhu et al., 2018). States like Assam that produce and consume rice as a staple will likely face the most nutritional deficits and other associated health risks such as effects on early childhood development, respiratory and cardiovascular issues, vector, and water-borne diseases.

The first oil well in India was a hand dug well at a depth of 102 feet in Upper Assam, but the well could not produce satisfactorily. The first commercial discovery of oil took place in 1889 at Digboi in north-eastern Assam. Over the next few years, systematic drilling began in the region, and India's first refinery was set up in Digboi soon after. India's first discoveries, post-independence, were also made in Assam, in Naharkatiya and Moran oilfields, in the years 1953 and 1956, respectively. These and all other modern wells exploit oil and gas reservoirs that are at depths of 1,200–5,000 m. A number of oilfields like Geleki, Rudrasagar, Lakwa, Jorajan, Dikom, Kathalani, Makum, and Hapjan were discovered next. This was followed by the exploration of more than 100 oil and gas fields. Till the 1960s, Assam was the only oil producing state in India (Bharali and Borgohain, 2013). Most of the oil and gas discovered in the 1980s was found in the Barail Group of Upper Eocene to Lower Oligocene age and the Tipam group of upper Miocene age. In 1989, a major discovery was made when oil was found in Lakadong member of Sylhet Formation (Lower Eocene) in Dikom oilfield. Since then many oilfields have been discovered that are producing hydrocarbons from reservoirs of Lower Eocene—Upper Palaeocene age. Over the next years several new fields were discovered in Assam, Andhra Pradesh, Gujarat, Cambay basin and Rajasthan. The Digboi oilfield, which is still producing oil, though at a very low rate, is producing oil from reservoirs in Tipam Formation (Miocene). Naharkatiya and Moran oilfields are producing from reservoirs in Barail Formation (Oligocene)¹. During the last 10 years, fields have been discovered mostly in Paleocene to Lower Eocene age. For the Borholla oil fields specifically, accumulations were in the fractured granitic rocks belonging to the Precambian age. The area south and south-east of the Brahmaputra river have been explored so far, but the area north of the river has not been explored suitably. Figure 6 maps major oil fields, power plants and fertilizer plants in Assam.

The advantage of CCUS over traditional CCS is in the utilization of the CO₂ feedstock toward valuable commercial products such as enabling EOR, making fuels and chemicals, while contributing to climate change mitigation at the same time. In general, the process of CCUS can be classified into three stages: capture, transport, and utilization and/or storage. The capture phase separates CO₂ from other gases during production and can be further broadly categorized based on the technological approach used. These categories are- pre, post, and oxy-combustion. Pre-combustion capture involves converting fuels into a mixture of hydrogen and CO₂ before the combustion is completed. The hydrogen rich fuel is combusted while the CO₂ is separated, transported, and utilized. In post-combustion capture, CO₂ is captured from the exhaust of the combustion process by absorbing in a suitable solvent. Upon separation from the solvent, the CO₂ can be transported and utilized. Oxy-combustion uses oxygen instead of air for combustion of the fuel. This process produces an exhaust stream that mainly consists of water vapor and carbon dioxide, easing the separation of CO₂ (Carbon Capture and Storage Association, 2011a). The transport phase is usually characterized by pipeline-based transport to sink or as raw-material for utilization. The utilization or storage phase can be categorized based on the end use of the CO₂- utilized in production of valuable products, used for CO₂ based EOR or for storage in geological formations such as saline aquifers, basalt formations etc_. Modeling for this paper has been based on post-combustion capture based on reviewed literature that suggests the costs and ease of retrofitting the same are the least when compared to oxy and pre-combustion, even though the environmental benefits for the other methods may be greater (Global CCS Institute, 2010; Peter and Bongartz, 2015).

Apart from a few small-scale private demonstration projects, India currently has no CCUS projects at scale. CO₂-enabled EOR provides a business case for CCUS in India since (Department of Science and Technology, 2018):

Estimates suggest that for every ton of CO₂ sequestered, between 1.5 and 4 barrels of additional oil can be extracted;

Proven reserves in Assam are currently at 1,600 million tons, and the production from the state accounts for about 12% of India's total oil and gas production. The Ultimately Recoverable Resources or URR for oil in Assam is about 174 million tons. The production trends in Assam are summarized in Figure 7.

The average oil and gas recovery factor in India is about 37%, with Assam fields ranging from 20 to 40%. Amidst severe social, geographical and geopolitical challenges, which are discussed later, oil production in Assam is faced with multiple technological and environmental handicaps as well. Obtaining environmental permits for the heavily forested areas around the Brahmaputra river valley, which is grappling with pollution, lack of sewage treatment plants and disposal of waste in the river is becoming the top barrier for oil companies. Well-bore instability and the resulting inability to drill gauge holes in the pay zone is also a common challenge. For shallow wells improved drilling fluid technology has resolved the issue to some extent, but deep wells are still problematic to drill, despite changes in casing policy, mud systems, mud weight etc. Along with a natural decline in well pressure, artificial lifts face frequent downtime due to power cuts. Poor inflow, high gas-oil ratio, inability to retrieve unserviceable equipment despite fishing attempts, and increasing water cuts (99+% in certain cases). With Assam's current state of falling oil production and India's commitments toward climate change mitigation, CCUS is an attractive solution.

An updated assessment of CO₂ storage potential of fields in India, and Assam in particular, has not been carried out in recent times. An assessment carried out by IEA in 2008 attempted to classify the storage alternatives in India, and calculate their capacity (Holloway et al., 2009). The calculation was based on the assumptions that:

In the absence of field-specific data, it was assumed that all the gas produced from these fields with the oil production is dissolved gas, the reservoir volume of which can be accounted for by applying a formation volume factor. This may lead to underestimating the storage capacity since some of the pore space occupied by gas caps will not be accounted for;

Using the same assumptions and method of calculation, the storage capacity was calculated using the following equation (Equation 1):

where, M_CO2is the CO₂ storage capacity, V_oil is the volume of ultimately recoverable oil at standard conditions, Bo is the oil formation volume factor, and ρ_CO2 is the density of CO₂ at reservoir conditions which is typical of supercritical CO₂.

Given an oil formation volume factor of ~1.5 for a typical field in the Assam geological area, the resultant storage potential for all the known fields in Assam (with total hydrocarbon volume of ~ 3.5 billion barrels of oil equivalent; 174 million tons of ultimately recoverable oil) (Wandrey, 2004) is in excess of 100 Megatonnes of CO₂.

Assam has a long-standing history of a shortage of power supply, especially in rural pockets. Assam's current demand stands at about 1,800 MW for 2016–17. Since 2004, India's Central and the Assam State governments undertook several reforms to strengthen the power sector. As of 2017, Assam has an installed capacity of ~1,500 MW, out of which about 1,000 MW is coal-based, 40 MW is gas-based, 400 MW is hydropower and 45 MW is renewables. As per the Assam budget of 2017, 2,526 villages have been electrified, which is 13% short of total rural electrification. A recent forecast of the long-term power requirements of the state expects demand to shoot up to 2,534 MW by 2021–22. Much of this demand is expected to be met through coal-based resources. Assam has also acquired loans from the Asian Development Bank to aid its ailing thermal plant infrastructure, to expand its transmission and distribution capacity, and increase access for remote communities (Asian Development Bank, 2018).

Asia's oldest gas-based fertilizer plant was started in Assam in the early 1960s by the Fertilizer Corporation of India. Discovery of fossil fuel resources in the Naharkatiya region propelled the government to plan for proper utilization of the vast amount of natural gas that was flared before the unit was set up. In 2002, the plant bifurcated from the erstwhile Hindustan Fertilizer Corporation Ltd. and was renamed the Brahmaputra Valley Fertilizer Corporation Ltd. (Brahmaputra Valley Fertilizer Corporation Limited, 2016). The plants were then rejuvenated and constituted as Namrup I, II, and III, with the former producing ammonia and the other 2 units producing both ammonia and urea. The existing plants have already surpassed the average life of 15–20 years for a chemical plant; the technology they operate with is now obsolete and finding spare parts for their archaic plant design has become increasingly difficult. However, given the dearth of supply in the region, the plants are still running, though, at a much-reduced efficiency of about 80% incurring financial loss to the order of $15 million (MEF Partners, 2009). The plant currently produces 351,000 tons per annum of ammonia and 311,400 tons per annum of urea. Efforts began in 2018 to ramp up production, to install a new unit to match demand, to provide direct and indirect employment, to offer incentives to ancillary industries, and to take advantage of cheaply available natural gas resources from the nearby fields in Namrup, Moran, Naharkatiya, and Lakwa regions (Press Trust of India, 2016).

The production of ammonia creates CO₂ as an unavoidable by-product. These CO₂ streams are highly concentrated and in excess of ~95% purity. Often considered the lowest-hanging fruit of industrial CCUS (International Energy Agency, 2015), these streams only require compression, transport and storage, thus bringing down capture costs significantly by eliminating the cost of separation.

Assam's mountainous terrain and thrust-belt geology make it difficult and investment intensive to build critical infrastructure such as pipelines for transportation. Also, Assam shares international borders with Bangladesh, and transport of coal is dependent on the Siliguri Corridor or the Chicken Neck, that connects West Bengal to the North-Eastern States. Any CO₂ enabled EOR efforts will be closely linked to a steady supply of coal from the Raniganj field, which has dwindled in recent years owing to the absence of other transport routes. Also, inclement weather conditions in Assam, that include annual torrential rains and flooding in the Brahmaputra valley, cause disruptions in power plant and oil field operations, often leading to shutdowns. Historically, the commercial relationship between national oil companies that operate the oil wells in the Assam basin and the Assam Power Generation Company Limited have been tarnished by occasions of miscommunication and mistrust leading to supply and demand challenges and operational inefficiencies in the past. These dynamics will influence the planning and scoping of the source and sink resources. Most importantly, carbon capture and transportation efforts are accompanied by a significant energy penalty. Since a considerable section of the population in India does not have access to power, the energy penalty associated with carbon capture and transport will put further pressure on the grid. Additionally, all CCUS efforts will have to account for the ancillary exhausts from the system. Assam also has a tumultuous history of insurgency from anti-establishment local separatist groups, that not only vandalize equipment at state-owned facilities, but have also paved the way for political instability and security threats to officials working in the facilities, which makes any new technological advancement vulnerable to the threat of physical damage, as well as that of being politically stalled (Nayak, 2012). Along with techno-economic viability, the challenge of public perception is also a key factor of concern for the implementation of CCUS. Lack of public awareness, a not-in-my-backyard (NIMBY) mindset, associating CCUS with the promotion of coal, and the perception of associated risks surrounding storage and transport can significantly stall progress for CCUS in the politically sensitive and volatile state of Assam.

Potential sources and sinks for CCUS were first identified to understand the economic and performance implications of undertaking CCUS activities in Assam, given the demand and supply economics, logistics, and the above-motioned challenges. Three categories of sources were identified: coal-fired power plant, natural gas-fired power plant, and fertilizer production plant. The distance between these sources and CO₂ demanding sinks were mapped to identify the least-cost alternative in terms of transport and storage infrastructure (Figure 6).

Amine based and ammonia based capture systems were considered for Namrup and Lakwa plants, while for Bongaigaon plant a membrane based capture system was also considered in addition to the amine and ammonia based systems. To maintain the same yardstick for comparison an amine based system with an FG+ amine was employed. Other available alternatives included MEA and Cansolv. FG+ was chosen because it allows for higher absorption, and higher CO₂ carrying capacity, while lowering energy demand and capital costs. It also lowers solvent losses, reduces reclaimer waste production and further lowers handling and disposal costs. FG+ was also chosen because of its vast commercial experience, its solvent being neither custom made nor expensive to produce, and the primary ingredient being readily available worldwide. For the purpose of this study, the CO₂ removal efficiency was set at 90% and a Direct Contact Cooler was used to cool the flue gases before it entered the amine system to enhance the reaction. The performance parameters in Table 2 were used while simulating plant conditions in IECM. Details for the performance parameters, additional parameters, and alternative capture scenarios can be found in Appendixes A,B (Bharat Heavy Electricals Limited, 1983; Mukherjee and Srivastava, 2005; Assam Electricity Regulatory Commission, 2012; Indian Power Sector, 2012; Assam Power Generation Corporation Limited, 2013; Gupta, 2015; Bakshi and Iyer, 2017).

The levelized cost of electricity (LCOE) is a common and convenient measure to evaluate the competitiveness of different technologies and is used here to compare the efficacy of adding CCUS to their operations and the results are presented in Table 3. LCOE assumes a financial life and duty cycle, and calculates the cost of building and operating the technology, and therefore, depends directly on fuel characteristics and costs, fixed and operating costs of the plant, assumed utilization rates and capacity factors. As discussed, when calculating the cost of electricity for a CCUS enabled plant, the transportation method, distance between source and sink, and the storage method are also crucial. Since this study is based in Assam, the hilly terrain will add to the costs, will require boosting stations over long distances. On the other hand, since the chosen method of storage is EOR, all potential financial benefits through utilization are taken into account while calculating final costs, as discussed in section Power Plants.

The results in Table 3 suggest that although both Namrup and Lakwa gas-fired plants are excellent potential sources in terms of distance from the nearest sink and CCUS related costs, it would increase the LCOE by almost 56–61% as against 7% in case of the Bongaigaon plant, despite it being farthest from the CO₂ sink at Khoraghat. Even though Assam benefits from the presence of vast natural gas resources and low prices, the age of these gas plants, older design practices, and their crippling infrastructure makes taking advantage of these low prices for enabling economical CCUS extremely difficult. In fact, both these gas-fired plants have operated for longer than the average life, only to bridge the supply-demand gap in Assam, and may be unable to support a retrofit without a total system overhaul. Bongaigaon Thermal Power Station (BTPS), on the other hand, given its relative youth, newer design practices and plans for a potential expansion in the next few years, is perfectly positioned for a CCUS retrofit. BTPS' capacity factor of ~80%, as against the national average of about 60%, its steam generator efficiency of 100% TMCR, particulate emissions from its ESP not exceeding 31 mg/Nm³, and guaranteed removal of minimum 95% sulfur by its FGD system are some of its infrastructural advantages. A projected 250 MW expansion, if executed, will add to these advantages. However, comparing the energy penalties with and without CCUS, we see an almost 2-fold increase in penalty in case of a CCUS retrofit. This loss contradicts the aim of providing all consumers with access to electricity. Any CCUS efforts at BTPS will put additional burden on the plant and expansions may be needed to substantiate for the penalty while ensuring adequate supply to consumers.

Precise values for cost of capture and avoidance are difficult to quantify since we do not have adequate data on flue gases emitted from each of these plants. Although, current estimates in literature suggest the levelized cost of capture for a subcritical plant with an amine-based CCUS system to be ~ $56/ton CO₂ captured and the cost of avoidance to be ~ $67/ton CO₂ avoided for typical Indian conditions (Kapila et al., 2011; Rao and Kumar, 2014; Viebahn et al., 2014; Singh et al., 2016).

The negative cost or benefit of utilizing CO₂ via EOR instead of traditional storage can be observed in the levelized O&M costs for transport and storage. Although, the per MWh costs are lowest and EOR-based storage benefits highest for the Namrup plant, the low capacity of the plant will limit the benefits. Bongaigaon plant, on the other hand, despite the largest source to sink distance amongst the three cases, provides a competitive opportunity at ~$19 million in O&M benefits from storage per year. Therefore, analyzing the additional value of extracting more oil through EOR with the injection of CO₂ is a good indicator of the supplementary revenue that can be achieved through utilization. Although, it should be noted here that IECM does not include functionalities to simulate for different well characteristics and detailed storage parameters that will influence the benefits. As discussed in the background section, 1.5 to 4 barrels of additional oil can be extracted per ton of sequestered CO₂, as discussed above_. Assuming a cost of $53/barrel, the economic benefits extend to ~$80–$210/ ton of sequestered CO_2.

The BVFCL plant produces ~350,000 tons of ammonia annually. According to the efficiency of the reaction in Equation 4, this is equivalent to ~75,000 tons equivalent of AN solids. According to Equation 5, this would imply a CO₂ equivalence of ~270,000 tons per year for this plant. The value of the CO₂ sequestered from this project would be energy equivalent to ~360,000 MWh of electricity (Environmental Protection Agency, 2008).

Estimates suggest the cost of capture for high purity CO₂ sources like ammonia production is approximately $16.50 t/CO₂, while the cost of CO₂ avoided is $30/t CO₂ (Leeson et al., 2017). Therefore, the annual cost of CO₂ capture and avoidance for this plant are ~$4.5 million and $8.1 million, respectively.

The authors declare that the research was conducted in the absence of any commercial or financial relationships that could be construed as a potential conflict of interest.