Techno-Economic Analysis of CO 2 Capture Technologies in O ﬀ shore Natural Gas Field: Implications to Carbon Capture and Storage in Malaysia

: Growing concern on global warming directly related to CO 2 emissions is steering the implementation of carbon capture and storage (CCS). With Malaysia having an estimated 37 Tscfd (Trillion standard cubic feet) of natural gas remains undeveloped in CO 2 containing natural gas ﬁelds, there is a need to assess the viability of CCS implementation. This study performs a techno-economic analysis for CCS at an o ﬀ shore natural gas ﬁeld in Malaysia. The framework includes a gas ﬁeld model, revenue model, and cost model. A techno-economic spreadsheet consisting of Net Present Value (NPV), Payback Period (PBP), and Internal Rate of Return (IRR) is developed over the gas ﬁeld’s production life of 15 years for four distinctive CO 2 capture technologies, which are membrane, chemical absorption, physical absorption, and cryogenics. Results predict that physical absorption solvent (Selexol) as CO 2 capture technology is most feasible with IRR of 15% and PBP of 7.94 years. The output from the techno-economic model and associated risks of the CCS project are quantiﬁed by employing sensitivity analysis (SA), which indicated that the project NPV is exceptionally sensitive to gas price. On this basis, the economic performance of the project is reliant on revenues from gas sales, which is dictated by gas market price uncertainties.


Introduction
Anthropogenic carbon dioxide (CO 2 ) emissions in the atmosphere are significantly increasing and critically impacting global climate. Thus, there is an urgent need to gauge and combat its effect on global climate change. In general, the source of CO 2 comes mostly from combustion of fossil fuel, natural gas stream, and industrial processes [1][2][3][4][5]. As stated in BP energy statistics in 2018, there were 33,890.8 MT (metric tonne) of CO 2 emission worldwide and the value was driven by the high energy demand. Moreover, recently in the year 2018, the global energy consumption grew at a rate of 2.9%, which is almost twice its 10-year average of 1.5% per year that is the fastest trend since the year 2010. For natural gas, its production increased by 5.2% to 136,594 Tscf (Trillion standard cubic feet) while its consumption rose by 5.3% to 135.92 Tscf, which is one of the fastest rates of increase since the year 1984. This high demand is mainly driven by the booming Liquefied Natural Gas (LNG) industry in The CCS performance results for the natural gas field models are incorporated into two types of models, which are the revenue model and cost model. The revenue model comes from the value of the recovered natural gas, while the cost model is the cost of CCS, including CO 2 capture, transportation, and injection for storage. The output of both models is net cash flow that is then discounted to obtain fiscal precursors comprising of Net Present Value (NPV), Internal Rate of Return (IRR), and Pay Back Period (PBP) of the project as shown in Figure 1.
Since Malaysia has not yet regulated CCS implementation in its national regulatory setting, the cost model does not take into consideration the value of incentives and credits that could be obtained for CO 2 storage, which would be a potentially added economic benefit to offset cost framework [30,31]. In this study, the economic analysis evaluates a CCS project's impact by evaluating its costs and benefits to the overall economy. This techno-economic analysis compares four scenarios where the project is implemented using various CO 2 capture technology options, assessing the effects, including quantifying parameters in quantitative terms.

Gas Field Model
This paper investigates the cost of carbon capture from the natural gas field through a case study. In this paper, Tangga Barat Cluster situated in the PM (Peninsular Malaysia) 313 Block, as the referred case study is a typical natural gas field at water depths in the range of 60 m to 71 m, about 150 km north-east of Kertih, Terengganu offshore Peninsular Malaysia. Tangga Barat Cluster is presently operated by PETRONAS Carigali Sdn Bhd (PCSB), the upstream arm for PETRONAS that has 100% working interest. The content level of CO 2 at Tangga Barat is above the gas specifications required for sales gas. Tangga Barat Cluster consists of a total of 3 producing platforms, which are Laho (LHDP-A), Melor (MLDP-A), and Tangga (TGDP-A), and a central processing platform, which is Tangga Barat (TBCP-A), while a separate riser and wellhead platform TBDR-A bridge-linked to TBCP-A will accommodate the development wells for the Tangga Barat field as shown in Figure 2. Existing gas facilities nearest to the Tangga Barat Cluster fields are the gas production and pipeline facilities of the Resak field, which is located 52 km away. The main power generation, processing facilities, natural gas compression, utilities, and living quarters is located at the central processing platform (TBCP-A). The Tangga Barat field was chosen as the gathering point for gas from the Tangga, Melor, and Laho fields based on the fact that the Tangga Barat gas volumes remain the largest along the four fields and distance is the shortest to the Resak complex. It is designed for a peak capacity of 440 MMscf/d of raw gas with an initial blended CO 2 level of 37 mole% (Tangga Barat CO 2 content) prior to CO 2 removal. The raw gas is then processed, pretreated, reducing the CO 2 content to 8 mole% to meet the specifications of the downstream sales gas process requirement from the PETRONAS gas processing plant at Kertih Terengganu [32].

Gas Field Model
This paper investigates the cost of carbon capture from the natural gas field through a case study. In this paper, Tangga Barat Cluster situated in the PM (Peninsular Malaysia) 313 Block, as the referred case study is a typical natural gas field at water depths in the range of 60 m to 71 m, about 150 km north-east of Kertih, Terengganu offshore Peninsular Malaysia. Tangga Barat Cluster is presently operated by PETRONAS Carigali Sdn Bhd (PCSB), the upstream arm for PETRONAS that has 100% working interest. The content level of CO2 at Tangga Barat is above the gas specifications required for sales gas. Tangga Barat Cluster consists of a total of 3 producing platforms, which are Laho (LHDP-A), Melor (MLDP-A), and Tangga (TGDP-A), and a central processing platform, which is  Tangga Barat (TBCP-A), while a separate riser and wellhead platform TBDR-A bridge-linked to TBCP-A will accommodate the development wells for the Tangga Barat field as shown in Figure 2. Existing gas facilities nearest to the Tangga Barat Cluster fields are the gas production and pipeline facilities of the Resak field, which is located 52 km away. The main power generation, processing facilities, natural gas compression, utilities, and living quarters is located at the central processing platform (TBCP-A). The Tangga Barat field was chosen as the gathering point for gas from the Tangga, Melor, and Laho fields based on the fact that the Tangga Barat gas volumes remain the largest along the four fields and distance is the shortest to the Resak complex. It is designed for a peak capacity of 440 MMscf/d of raw gas with an initial blended CO2 level of 37 mole% (Tangga Barat CO2 content) prior to CO2 removal. The raw gas is then processed, pretreated, reducing the CO2 content to 8 mole% to meet the specifications of the downstream sales gas process requirement from the PETRONAS gas processing plant at Kertih Terengganu [32].
In this case study, an annual average sales gas of 220 MMscf/d with 15 years of production life is estimated [33]. CO2 storage identified for this study is situated at an underground geological storage site approximately 20 km away from the Tangga Barat fields (near the Laho and Tangga fields) whereby the injected CO2 is to be stored while ensuring there is no increase of the reservoir pressure above the fracture pressure of the storage formation [34,35]. The facilities required will be a dedicated CO2 compression platform and its associated pipelines and injection wells at the Tangga wellhead platform [34,35].  In this case study, an annual average sales gas of 220 MMscf/d with 15 years of production life is estimated [33]. CO 2 storage identified for this study is situated at an underground geological storage site approximately 20 km away from the Tangga Barat fields (near the Laho and Tangga fields) whereby the injected CO 2 is to be stored while ensuring there is no increase of the reservoir pressure above the fracture pressure of the storage formation [34,35]. The facilities required will be a dedicated CO 2 compression platform and its associated pipelines and injection wells at the Tangga wellhead platform [34,35]. There are several routes available for CO 2 capture technologies from the gas stream. The technologies are generally based on different physical and chemical processes comprising of absorption, cryogenic distillation, and membrane. The selection of technology route mainly relies on the type of plant, gas type, and CO 2 separation level. In this study, to meet the Tangga Barat gas field sales gas specifications, suitable CO 2 capture technologies that have been widely been used for CO 2 separation from natural gas were evaluated. Four technologies have been selected for this techno-economic analysis study, which are:
Cryogenic distillation Membrane is a type of semipermeable barrier that has the ability to separate components using various separation mechanisms such as sorption/diffusion, adsorption/diffusion, ion-conducting, and molecular sieving, with selection of organic material (polymeric) and inorganic material (metallic, zeolite, ceramic). Figure 3a shows the basic method for membrane separation for CO 2 capture. Among all the available mechanisms, polymeric membrane with solution-diffusion has been commercially applied in the upstream business for natural gas separation at offshore CO 2 containing gas fields. Natural gas separation utilizing polymeric hollow fiber cellulose triacetate membrane has been installed at an offshore platform in Thailand [36]. In this solution-diffusion process, it starts with gas molecules from the feed side being absorbed by the membrane, which is then diffused across the membrane matrix and finally desorbed through to the other permeate side. The membrane selectivity is dependent on the polymer molecular structure that allows preferential passing of selected gas based on their molecule sizes, while the membrane permeability is highly dependent on the gas solubility [37][38][39].
Chemical absorption technology for CO 2 capture has been commonly applied in the petroleum and natural gas industry. CO 2 is an acidic gas; therefore, chemical absorption of CO 2 is a method that utilizes necessary solvents for acid-based neutralization reactions in gaseous streams/flue gas. In this process, CO 2 reacts with chemical solvents to produce an intermediate compound that is weakly bonded, which is further broken down using heating, then regenerating back into the original solvent to produce pure CO 2 stream. For more than 60 years, chemical absorption process using amine chemical solution, such as monoethanolamine (MEA), has been commercially applied in the natural gas industry and is considered as one of the most well-known chemical absorption technologies to absorb CO 2 from natural gas [27]. In this process, in order to capture CO 2 , in a packed absorption column, the flue gas is bubbled through the solvent during which preferentially separates the CO 2 from the flue gas stream [40,41]. Next, the solvent flows through a regenerator unit, whereby the absorbed CO 2 is separated from the solvent by counterflowing the steam at temperature between 100-200 • C. This results in condensation of water vapor that leaves a high concentration of more than 99% of CO 2 stream, which would then be compressed and used for storage or commercial. Finally, the lean solvent is cooled down to the temperature of 40-65 • C and is recycled back into the absorption column. In fundamental, the chemical reaction is shown as follows: During the absorption process using MEA, the chemical reaction starts from left to right while during regeneration, the reaction is from the opposite direction, right to left [40,42].

CO2 Storage and Abandonment
The storing of the produced CO2 underground could benefit in addressing climate change by ensuring it is not released into the atmosphere. The prospective opportunities for CO2 storage are at geological storage saline aquifers and depleted oil and gas reservoirs. These approaches are considered as the most feasible storage as there is great potential capacity for storage at an estimation of 236 Gt, worldwide [46,47].
In CCS chain, after the capture process, the CO2 is compressed into a 'supercritical phase' whereby it becomes fluid almost as dense as water and is transported by pumping it along the pipeline to the storage site and subsequently into an underground geological formation that is typically situated several kilometers under the earth's surface. As the injected CO2 is slightly more  Physical absorption is also a commercially available CO 2 capture method in the petroleum and natural gas industry. In this physical solvent process, it employs organic solvents to absorb gas components physically rather than reacting chemically. The solubility of CO 2 of solvents determines the separation rate of CO 2 by physical absorption processes, in which the solubility hinge on the temperature and the partial pressure and of the feed gas. Low temperature and high CO 2 partial pressure will increase the CO 2 in the solvent solubility. Selexol (dimethylether of polyethylene glycol) is a liquid glycol-based solvent and has since been used to process natural gas especially for bulk CO 2 removal. In the Selexol process, the flue gas is first dehydrated. After that, in an absorption column at a pressure about 450 psi with a low temperature of 0-5 • C, the flue gas is contacted with the solvent to produce a loaded CO 2 solvent. Then, flash desorption or separation of the CO 2 loaded solvent will regenerate the original solvent. Finally, the produced CO 2 gas stream is compressed and stored while the regenerated solvent is recycled back to the column [25,40,43]. Figure 3b shows the basic method for CO 2 capture through absorption.
In the cryogenic distillation CO 2 separation method, CO 2 is purified by separating the gas mixtures using distillation at low temperature and fractional condensation, leveraging on their de-sublimation properties and different condensation level as shown in Figure 3c. The low-temperature distillation is a mature process used to liquefy and purify CO 2 from relatively high purity (>90%) sources. The process starts with the cooling of the gas to a very low temperature of <−73.3 • C, to freeze out/liquefied and separate the CO 2 . During which, cryogenic air separation unit (ASU) was used to supply high purity oxygen to a boiler. This step condenses most of the moisture and removes any carried over particles. The produced high purity oxygen is then blended with the recycled flue gas before combusted in the boiler to maintain combustion conditions comparable to air fired configuration. This is crucial as the presently existing materials for construction could not survive the high temperatures resulting from combustion in pure oxygen [44]. Table 1 shows the advantages and disadvantages of the selected CO 2 capture technologies. • Hydrocarbon losses, resulting in reduced product output and often require recycle compression • High energy for solvent regeneration is required [45] Cryogenic distillation Eliminates water consumption and chemicals, hence no corrosion issues • Allows pure CO 2 recovery (liquid), and transportable or pumpable to injection site conveniently [38] • Process consumes high energy

CO 2 Storage and Abandonment
The storing of the produced CO 2 underground could benefit in addressing climate change by ensuring it is not released into the atmosphere. The prospective opportunities for CO 2 storage are at geological storage saline aquifers and depleted oil and gas reservoirs. These approaches are considered as the most feasible storage as there is great potential capacity for storage at an estimation of 236 Gt, worldwide [46,47].
In CCS chain, after the capture process, the CO 2 is compressed into a 'supercritical phase' whereby it becomes fluid almost as dense as water and is transported by pumping it along the pipeline to the storage site and subsequently into an underground geological formation that is typically situated several kilometers under the earth's surface. As the injected CO 2 is slightly more buoyant than the salty water that coexists within the storage reservoir, a portion of the injected CO 2 will migrate to the top of the formation and acts as a seal as it is trapped underneath the impermeable caprock structure. Some of the trapped CO 2 will dissolve slowly into the saline water and become trapped permanently (solution trapping), whilst others become trapped in tiny pore spaces (residual trapping). The ultimate trapping process involves dissolved CO 2 reacting with the reservoir rocks, which forms into a new mineral. This process called mineral trapping effectively locks the CO 2 into a solid mineral. As the storage mechanisms change over time from solution to residual then to mineral, the CO 2 becomes less and less mobile. Therefore, the longer the CO 2 is stored, the lower the risk of any leakage. Typically, the following geologic characteristics are associated with effective storage sites, whether at onshore or offshore site [48]: • rock formations have adequate millimeter-sized voids or pores; this is to ensure available capacity to store the CO 2 ; • pores in the rock are efficiently linked, which is a feature called permeability for injectivity; this is to receive the amount of CO 2 at the rate it is injected, allowing the CO 2 to move and spread out within the underground storage formation; • extensive cap rock or barrier at the top of the storage formation; this is to contain the CO 2 permanently; • stable geological environment; this is to avoid any potential geological effect that could compromise the storage site integrity.
The saline aquifers can be found at 700-1000 m below ground level and it consists of porous rocks with high salinity formation brine. These saline aquifers have no commercial value but it can be used to store the captured CO 2 . These aquifers can be found at onshore/offshore and are usually estimated to have large storage potential volume. However, from an economic view, it is less desirable as storage option due to the unavailability of required infrastructure such as injection wells, surface equipment, and pipelines that would need a brand new capital investment altogether as compared to depleted oil and gas reservoirs. Depleted oil and gas reservoirs are more likely to be used for projects as extensive information from geological and hydrodynamic assessments is already available and equipped with readily available infrastructures. On average, about 40% of the residual is left after a typical oil and gas field production. The CO 2 can be injected in the depleted (or almost depleted) oil and gas reservoirs to increase their pressure, which in turn could provide the driving force to extract residual oil and gas while the CO 2 can then be stored inside permanently. This makes it more economical than storage in saline aquifers [46].
After the geological storage has reached its capacity, it will be retained for an extremely long period with an estimated minimum residence time of 1000 years without seepage/leakage back to the surface, also referred to as abandonment phase [48]. During which, the migration of the injected CO 2 in the storage volume will be monitored to ensure that it will not have any negative effect on the surrounding environment, e.g., groundwater pollution. In the monitoring stage, there are a few available methods that are commonly used, seismic monitoring, geo-electrical methods, temperature logs, gravimetry methods, remote sensing, geochemical sampling, atmospheric monitoring, tracers, soil gas monitoring, and microbiology [46]. These methods have since been applied at offshore CO 2 storage sites worldwide, such as at the Sleipner and Snohvit project. For example, at Sleipner, since the start of injection, it was found that the CO 2 plume has risen through shale rock layers nearing the caprock using seismic monitoring method. The project is currently under post-injection process and no leakage has been reported to date [48,49].

Carbon Capture and Storage (CCS) at Tangga Barat
The Tangga Barat CCS case study comprising of different CO 2 capture technologies units, transportation, and storage is shown in Figure 4. It begins with the central processing platform TBCP-A that will treat all produced gas originating from the producing platforms, TGDP-A, LHDP-A, and MLDP-A. The selected CO 2 capture technologies options consist of polymeric membrane, chemical absorption amine, physical absorption solvent (Selexol), and cryogenic distillation. Among the main criteria used to shortlist the selected CO 2 capture technologies is that the technologies have already been proven and suitable for large applications (>200 MMscfd) and capable of bulk removal of CO 2 (37% mole to 8% mole) as per Tangga Barat sales gas specification requirement. Following the CO 2 capture, the treated gas is transported via offshore pipeline to Resak platform for compression followed by pumping for sales export. Then, the captured CO 2 will be stored at the identified geological site near Tangga Barat. Moreover, please note that the intention of this study is not to endorse nor discriminate any of the CO 2 capture technologies presented, but rather to gauge the CCS techno-economic impact of using different method of CO 2 capture.
Processes 2020, 8, x FOR PEER REVIEW 9 of 22 criteria used to shortlist the selected CO2 capture technologies is that the technologies have already been proven and suitable for large applications (>200 MMscfd) and capable of bulk removal of CO2 (37% mole to 8% mole) as per Tangga Barat sales gas specification requirement. Following the CO2 capture, the treated gas is transported via offshore pipeline to Resak platform for compression followed by pumping for sales export. Then, the captured CO2 will be stored at the identified geological site near Tangga Barat. Moreover, please note that the intention of this study is not to endorse nor discriminate any of the CO2 capture technologies presented, but rather to gauge the CCS techno-economic impact of using different method of CO2 capture.

Revenue Model
Based on the annual gas production estimates, the annual revenue estimation could be generated. In the US Energy Information Administration (EIA) projections reference case, natural gas prices remain comparatively low as compared to average historical prices. To estimate the economic, an average gas price between the year 2000 and projection up to 2050 whereby the estimated gas price for the year 2020 was used for this analysis [50]. The gas produced from Tangga Barat data is based on estimated studies from PETRONAS [33]. The revenue model calculates net revenue from the recovered gas production and then sold at a specified gas price, with a 10% deduction in royalty and 38% tax deduction based on Malaysian Petroleum Income Tax Act [34]. This revenue model structure will generate a time series of incoming net cash flows in which the resultant net revenue of the project could be assessed incrementally during production lifetime period and also cumulatively during the end of the project life. The tax payment is based on the estimation of capital cost depreciation of 5 years. There are also tax incentives being introduced by some countries, for example in the United States, the federal government has sanctioned supplementary tax credit for CO2 sequestration activities that provide USD 10 per ton CO2 stored, 15% tax credit applied to all costs associated with CO2 purchase cost as well as CO2 operation cost for injection [51]. For this study, since there is no tax incentive for CCS projects implemented in Malaysia, hence no additional tax incentives have been calculated. Table 2 shows the associated parameters assessed in this revenue model.

Revenue Model
Based on the annual gas production estimates, the annual revenue estimation could be generated. In the US Energy Information Administration (EIA) projections reference case, natural gas prices remain comparatively low as compared to average historical prices. To estimate the economic, an average gas price between the year 2000 and projection up to 2050 whereby the estimated gas price for the year 2020 was used for this analysis [50]. The gas produced from Tangga Barat data is based on estimated studies from PETRONAS [33]. The revenue model calculates net revenue from the recovered gas production and then sold at a specified gas price, with a 10% deduction in royalty and 38% tax deduction based on Malaysian Petroleum Income Tax Act [34]. This revenue model structure will generate a time series of incoming net cash flows in which the resultant net revenue of the project could be assessed incrementally during production lifetime period and also cumulatively during the end of the project life. The tax payment is based on the estimation of capital cost depreciation of 5 years. There are also tax incentives being introduced by some countries, for example in the United States, the federal government has sanctioned supplementary tax credit for CO 2 sequestration activities that provide USD 10 per ton CO 2 stored, 15% tax credit applied to all costs associated with CO 2 purchase cost as well as CO 2 operation cost for injection [51]. For this study, since there is no tax incentive for CCS projects implemented in Malaysia, hence no additional tax incentives have been calculated. Table 2 shows the associated parameters assessed in this revenue model. Table 2. Input and definition for parameters assessed in the revenue model.

Parameter Input/Definition
Gas produced (Million British Thermal Unit (MMBtu)) Incremental or cumulative natural gas production volume simulated for reservoir performance estimation Gas price (USD) Average market price of natural gas CO 2 produced (tonne) Incremental or cumulative CO 2 production volume simulated for reservoir performance estimation CO 2 price (USD) Average market price of CO 2 Gross revenue (USD) Revenue from natural gas recovered and cost and sold at specified gas price Royalty (%) 10% of gross revenue Tax (%) 38% of (revenue-royalty -maintenance cost-abandonment cost -capital cost depreciation) Net revenue (USD) Revenue after deduction of royalty and tax (Gross revenue ($) − Royalty ($) + Tax ($)

Cost Model
In this study, the CCS project cost model could be categorized into four main types: capital cost, CO 2 capture cost, operation and maintenance (O&M) cost, and abandonment cost. In the cost model, the capital costs are accrued at the start of the project. Capital cost accounts for the gas field, compressor, pipeline, wells, and injection platforms. These capital costs are amortized over the lifetime of the field using the project discount rate [52]. For CO 2 capture cost, it is estimated based on the requirement of the gas field, including the processing equipment, production equipment, injection of platforms, and wells along with transportation pipeline. Furthermore, it includes 'on-cost' which is the insurance, obtaining rights-of-way, and legal and regulatory cost. CO 2 capture cost is the capital cost to implement the selected CO 2 capture technologies for the CCS project. O&M costs comprise of services, consumables, labor for site operation and maintenance (surface & subsurface), as well as general administration purposes [53]. Abandonment cost is the decommissioning cost after the injection period. These thorough analyses of CCS cost have been conducted by prominent research centers in this field. The costs in this study were estimated based on studies conducted by established studies by reputable bodies such as Asia Pacific Economic Cooperation (APEC), CO2CRC, IEAGHG, and GCCSI as well as previous research reports [22].
All cost data were updated to represent constant 2020 US Dollar (USD): Whereby, PV is present value, FV is future value, i is discount rate, and n is the project lifetime number of years. Table 3 shows the parameters included in the cost model.

Net Present Value (NPV)
NPV represents the value of future cash flows that is accrued incrementally and also cumulatively over the CCS project lifetime duration. It is the total value of cash inflows and outflows that are discounted to account for the time value of money and the risks/uncertainties associated with future cash flows. Net revenues (cash inflows) obtained from the revenue model was incorporated with the total costs (cash outflows) calculated by the cost model to develop NPV estimates in time series (years). At the end of the project lifetime, the cumulative NPV calculated is used as input to estimate the CCS project profitability, whereby positive values represent scenarios of profit while negative values represent fiscal losses sustained by investors/stakeholders in the project. The project is considered feasible if NPV > 0 and vice versa. NPV calculation is as presented [54]: Whereby; i is the discount rate, C t the annual cash flow in the t th year, and N the total number of years. Time period t = 0 relates to the investment during the project lifetime.

Internal Rate of Return (IRR)
In the CCS project, the overall investment along with its profit gain could be gauged using IRR. From the calculations, as the IRR value increases, the greater the project gain will be and vice versa. Moreover, it is the discount rate value that is resulting the project cash flow NPV to become equal to zero (0), hence defining the least rate of return required in order to achieve project viability. If the IRR value obtained is higher than the defined discount rate, hence the CCS project is considered viable. The IRR is calculated and shown as [54,55]: Whereby; i is the discount rate, C t the annual cash flow in the t th year, and N is the total number of years. Time period t = 0 relates to the investment during the project lifetime.

Payback Period (PBP)
The duration of time needed to recover the initially invested capital cost in a CCS project is represented by PBP. From the calculations, as the PBP value becomes shorter, the project fiscal viability strength will increase and vice versa. Moreover, PBP is defined by identifying the specific year when the calculated cumulative cash flow becomes positive and achieves breakeven. The PBP is expressed as below [54]: Whereby; A is the final year with negative cumulative cash flow, B is the value of cumulative cash flow at the end of year A, and C is the total annual cash flow during the year after A.

Sensitivity Analysis (SA)
SA is an assessment of the projected performance with key assumptions and projections based on the base values. There are several important key variables that could impact CCS project, which are the gas price, discount price, initial capital cost, and CO 2 capture cost and tax. Key economic assumptions and associated references used as input in this study are listed in Table 4.

Techno-Economic Model Results and Discussion
This study on techno-economic analysis provides the fiscal precursor and its outlook for Tangga Barat natural gas field for CCS implementation starting from the year 2020 with a projection of 15 years project lifetime. The calculation outputs of project cash flow and total annual cash outflows, as well as its inflows throughout its lifetime, is as shown in Figure 5a-d. It can be seen that as the project extends into the exploration stage, the annual project cash flow will begin to increase in a positive note. During operation, inflow arrives from the natural gas sales revenue and outflows derive from the O&M, royalty, and tax costs.
For base case (without any CO 2 capture technology implementation), during project investment in the year 2020, the initial sum proceeding from equity and capital cost is USD 427.9 Million [34]. It reflects the extent of the total cost expenses required to start a project indeed. The initial investment increases as it includes the implementation of CO 2 capture technologies. The total capital cost required including the CO 2 capture technologies implementation for the polymeric membrane is USD 639.9 Million, chemical absorption (Amine) is USD 838.69 Million, using physical absorption solvent (Selexol) is USD 590.51 Million, and using cryogenic distillation is USD 817.29 Million (refer Table 5). These costs are investments to achieve the targeted natural gas production output of 83,512,000 MMBtu per year for the overall project lifetime of 15 years.
For polymeric membrane, the case is shown in Figure 5a, where the project annual cash flow will gradually surpass its values in the succeeding years, which is the result of large investments for the capital cost being subjected to reduction from financial amortizations. This trend is reflected by the slope of the curve ranging between the year 2020 and 2027. Only by 2028 onwards, the gas field is anticipated to operate at a fairly constant speed and ultimately reaches breakeven. After that, the project cash flow is inclined to increase continuously as the revenue exceeds the cost expenditures during which its inflows and outflows also increase based on the specified discount rates over the project lifetime. From which, the revenue demonstrates a relatively optimistic cash flow increment over the years, which in turn highlights the significance of the profit obtained from natural gas sales price toward the overall feasibility of the CCS project. The entire field system and equipment will free from debt without further amortization by the end of the field production lifetime. Case using chemical absorption (Amine) is shown in Figure 5b, whereby a larger capital investment than the previous case (polymeric membrane) was made causing the project annual cash flow exceeds even higher. This is shown by the curve slope between 2020 and 2029. By 2030 onwards, the gas field reaches breakeven. For physical absorption solvent (Selexol) case shown in Figure 5c, the initial capital cost is the lowest of all the CO 2 capture technologies analyzed. The project is projected to breakeven in 2027 with payback obtained 7.94 years, which is about half of the project lifetime. In the case of using cryogenic distillation, the initial capital cost is slightly lower as compared to using Amine. As a result, the project is projected to breakeven one year earlier in 2029 (Figure 5d).

Sensitivity Analysis (SA) Results and Discussion
Sensitivity Analysis (SA) examines the effect of input variables variation on the model's conclusion to gauge and identify the most significant variables affecting the CCS project performance. By quantifying their elasticity range and assessing the project performance effect when subjected to different scenarios impacted either by the favorable or unfavorable perspective of the variables concurrently, the feasibility of the project fiscal precursor could be defined. In this study, these variables are considered to be significantly affecting the project viability in terms of economic as well as performance risks:


Gas price provides input to the project revenue and has long-term uncertainty as it is highly dictated by supply and demand, global market fluctuation, and political-economic decisions;  Tax is dependent on the country tax requirement as well as its government political decision;  Discount rate directly affects the present value of future costs and its profits;  Initial capital cost is highly reliant on the capital outflow investment ability by the oil and gas producers and investors.  CO2 capture technology cost is highly reliant on the technology provider profit margin and its maturity status; Figure 6a-d depicts variation scenarios and its impact change to the five input variables, gas price, discount rate, tax, CO2 capture technology cost, initial capital cost, and its effect on the risks affecting the fiscal precursor that is NPV and its sensitivity range. The sensitivity bound is defined as favorable/unfavorable by changing the baseline value, testing the different scenarios of that certain investment based on the specified five input variables. A ±10% range was implemented for the initial capital cost, tax, and CO2 capture technologies and this is as supported by the literature [54]. For the gas price, the range of ±USD 1.0 Million/MMBtu was selected as it reflects the gas price trend for the past 5 years [58]. The discount rate of ±2% was estimated based on previous studies conducted by established bodies such as the US Department of Energy, International Energy Agency Greenhouse Gas (IEAGHG), Electric Power Research Institute (EPRI), and UK Department of Energy and Climate Change (DECC) [62].
The SA result for all four scenarios of CCS with different CO2 capture technologies is reflected by NPV, which visualizes the gas price as the main key influencer affecting the viability of the project. In comparison to the other variables, gas price demonstrates the most substantial NPV impact change. The output from discount rate, tax, CO2 capture cost, and initial capital cost (from the most affecting) variables are found to less influencing as compared to gas price. The feasibility of the project could significantly be affected by gas price during all four scenarios that are using polymeric   Table 5 displays the main outputs from the model for the four CO 2 capture technologies scenarios. Generally, a CCS project is considered to be techno-economically viable when it achieves the trio combination fiscal precursor of NPV > 0, followed by IRR value higher than the specified discount rate along with PBP value being lower than the gas field production lifetime. The physical absorption solvent using Selexol result shows the most favorable profitability with a fairly positive NPV equal to USD 367.37 Million with an IRR equal to 15% with the shortest PBP as compared to the other capture technologies. This is followed by CO 2 capture using a polymeric membrane with just a slight difference with NPV of USD 292.94, IRR at 13%, which is higher than the specified discount rate, and PBP of 8.55 years. Cryogenic distillation comes third at NPV of USD 25.58, IRR at 8%, which is the same as the specified discount rate, and PBP of 10.45 years. And finally, the least feasible CO 2 capture is by using chemical absorption (Amine) as the NPV has negative value at −USD 6.67, IRR same as the specified discount rate at 8%, and the longest PBP at 10.68 years. Even so, although the obvious viability is by physical absorption solvent using Selexol, oil and gas producers/investors may not find it is as economically attractive since there are many other factors that may directly influence project decision making. External factors such as market price and financial support also are very likely to have either a negative or positive impact. On that account, it is imperative that consideration of associated risks are analyzed when conducting investment analysis. For that reason, in order to decide which considered variables are the most significant to the CCS project, SA would be the best path to reflect its worthiness.

Sensitivity Analysis (SA) Results and Discussion
Sensitivity Analysis (SA) examines the effect of input variables variation on the model's conclusion to gauge and identify the most significant variables affecting the CCS project performance. By quantifying their elasticity range and assessing the project performance effect when subjected to different scenarios impacted either by the favorable or unfavorable perspective of the variables concurrently, the feasibility of the project fiscal precursor could be defined. In this study, these variables are considered to be significantly affecting the project viability in terms of economic as well as performance risks: • Gas price provides input to the project revenue and has long-term uncertainty as it is highly dictated by supply and demand, global market fluctuation, and political-economic decisions; • Tax is dependent on the country tax requirement as well as its government political decision; • Discount rate directly affects the present value of future costs and its profits; • Initial capital cost is highly reliant on the capital outflow investment ability by the oil and gas producers and investors. • CO 2 capture technology cost is highly reliant on the technology provider profit margin and its maturity status; Figure 6a-d depicts variation scenarios and its impact change to the five input variables, gas price, discount rate, tax, CO 2 capture technology cost, initial capital cost, and its effect on the risks affecting the fiscal precursor that is NPV and its sensitivity range. The sensitivity bound is defined as favorable/unfavorable by changing the baseline value, testing the different scenarios of that certain investment based on the specified five input variables. A ±10% range was implemented for the initial capital cost, tax, and CO 2 capture technologies and this is as supported by the literature [54]. For the gas price, the range of ±USD 1.0 Million/MMBtu was selected as it reflects the gas price trend for the past 5 years [58]. The discount rate of ±2% was estimated based on previous studies conducted by established bodies such as the US Department of Energy, International Energy Agency Greenhouse Gas (IEAGHG), Electric Power Research Institute (EPRI), and UK Department of Energy and Climate Change (DECC) [62]. References (a)

Limitation of This Techno-Economic Analysis
The techno-economic analysis conducted in this study achieves the targeted evaluation of CCS prospect with four different CO2 capture technologies scenarios at Tangga Barat gas field could be used as an early decision making indicator for investors and enabling other natural gas fields to be rapidly evaluated. However, this study was based on limited and readily available statistical economic parameters and storage reservoir properties. A more detailed storage site characterization and equipment and material cost parameters inventory for the Tangga Barat CCS during detailed engineering design stage could assist in obtaining a higher precision project techno-economics.

Conclusions
In this study, it presents a techno-economic analysis of an actual gas field Tangga Barat in Peninsular Malaysia and assesses its potential for CCS to be implemented in Malaysia as a means of achieving targeted CO2 reduction aim. The deployment of this CCS project will contribute to a significant decrease of the environmental impact, by storing the captured CO2 at an estimation of 1646 tonnes/day. The result of this paper focuses on the possibilities for CCS project comprising of 4 cases of CO2 capture for offshore gas field along with a fixed CO2 transport and storage infrastructure development. In this study analysis, a techno-economic model spreadsheet is established to obtain the fiscal precursors, which include NPV, IRR, and PBP. In the cost model, the considered cost factor is capital cost that includes CO2 capture technology cost, O&M cost, and abandonment cost incurred. While for the revenue model, the estimation is based on the profit from the produced natural gas sales. The techno-economic analysis is conducted based on previous literature and then benchmarked and updated catering to suit market gas prices, plant equipment, revenues, operating cost, tax rates, and interest rates. Then, a SA is conducted to evaluate the risks and measures associated with the project investment uncertainties. Favorable and unfavorable scenarios are analyzed within a defined elasticity range basing from the baseline value input. The selected variables include gas price, The SA result for all four scenarios of CCS with different CO 2 capture technologies is reflected by NPV, which visualizes the gas price as the main key influencer affecting the viability of the project. In comparison to the other variables, gas price demonstrates the most substantial NPV impact change. The output from discount rate, tax, CO 2 capture cost, and initial capital cost (from the most affecting) variables are found to less influencing as compared to gas price. The feasibility of the project could significantly be affected by gas price during all four scenarios that are using polymeric membrane, chemical absorption (Amine), physical absorption solvent (Selexol), and cryogenic distillation in an unfavorable scenario. For example, in the case of gas price of USD 1.8/MMBtu, it predicts a negative NPV of up to −USD 161 Million, −USD 517.15 Million, −USD 84.91 Million, and −USD 487.14 Million, respectively. On the other hand, when the gas price increases to USD 3.8/MMBtu, it considerably increases the projects NPV up to USD 941.54 Million, USD 826 Million, USD 970.25 Million, and USD 838.42 Million also, respectively. High gas prices would, therefore, be beneficial for the CCS project's economic feasibility. It also could be seen that, since the uncertainties of the gas price are heavily subjected to the global supply and demand, market fluctuation, political and economic decisions, and government subsidies, henceforth making it one of the most vital factors to deal with to ensure the project success.
In the case of discount rate and tax, both variables share a nearly similar impact on the NPV. This shows that the CO 2 capture technologies cost has the least compromising effect on the NPV performance as it has the least negative range scenario as compared to the other input variables.

Limitation of This Techno-Economic Analysis
The techno-economic analysis conducted in this study achieves the targeted evaluation of CCS prospect with four different CO 2 capture technologies scenarios at Tangga Barat gas field could be used as an early decision making indicator for investors and enabling other natural gas fields to be rapidly evaluated. However, this study was based on limited and readily available statistical economic parameters and storage reservoir properties. A more detailed storage site characterization and equipment and material cost parameters inventory for the Tangga Barat CCS during detailed engineering design stage could assist in obtaining a higher precision project techno-economics.

Conclusions
In this study, it presents a techno-economic analysis of an actual gas field Tangga Barat in Peninsular Malaysia and assesses its potential for CCS to be implemented in Malaysia as a means of achieving targeted CO 2 reduction aim. The deployment of this CCS project will contribute to a significant decrease of the environmental impact, by storing the captured CO 2 at an estimation of 1646 tonnes/day. The result of this paper focuses on the possibilities for CCS project comprising of 4 cases of CO 2 capture for offshore gas field along with a fixed CO 2 transport and storage infrastructure development. In this study analysis, a techno-economic model spreadsheet is established to obtain the fiscal precursors, which include NPV, IRR, and PBP. In the cost model, the considered cost factor is capital cost that includes CO 2 capture technology cost, O&M cost, and abandonment cost incurred. While for the revenue model, the estimation is based on the profit from the produced natural gas sales. The techno-economic analysis is conducted based on previous literature and then benchmarked and updated catering to suit market gas prices, plant equipment, revenues, operating cost, tax rates, and interest rates. Then, a SA is conducted to evaluate the risks and measures associated with the project investment uncertainties. Favorable and unfavorable scenarios are analyzed within a defined elasticity range basing from the baseline value input. The selected variables include gas price, discount rate, tax, CO 2 capture technology cost, and initial capital cost were used to evaluate CCS project feasibility potential.
From the techno-economic analysis model, it presents a positive outlook stating its achievability to deploy the project based on Malaysia's current market and economic setting. The analysis shows two prospective CO 2 capture technology with high positive NPVs by using physical absorption solvent (Selexol) followed by the polymeric membrane. The most prospective CO 2 capture method is using Selexol with IRR at 15% and PBP of 7.94 years. This is closely followed by CO 2 capture using membrane with just a slight difference with IRR at 13% and PBP of 8.55 years. From this analysis, it could be concluded that these two variants of CO 2 capture have a huge economic prospect for deployment at Tangga Barat. Based on the SA, the NPV exhibits to be significantly most sensitive to gas price, followed by discount rate and tax. It also shows that both CO 2 capture technology and initial capital cost has minimal influence on NPV. Although the project feasibility and acceptable risks are provided by all four CCS scenarios from the economic model calculations, two distinct capture technologies, which are using membrane and physical absorption solvent (Selexol), give high IRR with an acceptable time of return period (less than half the production years). This study shows that either one of the CO 2 technologies could be implemented at Tangga Barat, which could further be influenced by the oil and gas producer or investor inclinations, starting with this economics and extending to political and geological factors. Furthermore, the SA illustrates that the gas price has the most significant impact over NPV as compared among all the considered variables. This scenario portrays that the gas sales revenues that is controlled by the uncertain market, tariffs, and reimbursements will eventually impact the overall economic viability of the CCS project.
In order to achieve successful deployment of CCS projects, collaborations between governments, international organizations, and the private sector would be essential and, of course, international financing will be critical to project success. In the scenario, for the case of Malaysia, to adopt and extend its current reduction of tax incentives for marginal field from 38% to 25% for CCS projects, this incentive would positively influence the key decision factor for oil and gas producers/investors to implement CCS. Furthermore, it is hopeful that the upcoming future implementation of the Energy Efficiency and Conservation act in Malaysia would be an appropriate avenue for the climate policy to manage and positively impact the control of CO 2 emissions. The accessibility to sufficient storage capacity could be another restrictive element to reduce CO 2 emissions through CCS, even though there are some fundamental studies that believe there are available geologic storage and also studies on storing back the CO 2 into the origin source well/depleted field. These uncertainties and lack of storage capacity could be overcome by implementing CO 2 utilization method, by transforming CO 2 into valuable products that could serve as project revenue and eventually offset the initial investment cost altogether. Finding creative, cost-effective ways to capture and profit from this CO 2 for use in CCS can result in a vast improvement in the long-term commercial viability of natural gas production in Malaysia, along with increasing the productive life of the economy's natural gas resources. This study on techno-economic analysis could be a reference point in terms of economic viability for implementation of CCS in other CO 2 gas fields in Malaysia and globally.