This study focuses on the Búzios field, one of the largest fields in the Santos Basin Pre-Salt Cluster (SBPC). The field was selected based on its high gas-oil ratio (GOR) and elevated CO₂ content [47] - [52] , making it a representative case for broader application within the SBPC. The estimated potential volume of natural gas to be produced in the Búzios field is approximately 5.4 billion m³/year, equivalent to 15.04% of Brazil’s total NG consumption [51] . This selection criterion ensures that the methodology can serve as a reference for other similar pre-salt reservoirs. While the case study approach provides valuable insights, one key limitation is that the findings may not be fully generalizable to fields with significantly different geological and economic conditions.

The foundation of this study’s methodology is the development of a techno-economic model based on the work of Gaffney, Cline & Associates (GCA) [2] , which performed a review and economic evaluation of ten selected prospects in SBPC. The Brazilian National Agency for Petroleum, Natural Gas, and Biofuels (ANP) originally commissioned GCA to assess hydrocarbon resources, with a primary focus on oil volumes. Our study expands upon this benchmark by integrating gas monetization strategies into the model, making it more relevant in the context of energy transition and carbon management.

One of the strengths of this approach is its ability to incorporate updated data and real-world constraints, improving the accuracy of economic projections. However, a limitation is the reliance on assumptions regarding future market conditions and policy frameworks, which may evolve in unpredictable ways.

To refine the production profiles, we incorporated updated GOR and CO₂ content data from Petrobras reports submitted to IBAMA. This step ensured that the analysis reflects the latest field conditions and production constraints. Additionally, based on [27] , we simulated the impact of liquefying the CH₄-rich stream via ssm-FLNG after gas separation, while the CO₂-rich stream was reinjected using the CO₂-WAG method for enhanced oil recovery and permanent CO₂ storage. The model was calibrated against historical production data to improve accuracy.

A key strength of this methodology is its reliance on empirical calibration, which enhances model reliability. However, the availability of high-quality field data remains a potential limitation, as missing or outdated information could affect model precision.

Figure 1 has a simplified representation of the described methodology, which starts by developing a techno-economic model to represent GCA numbers, passing through populating the model, performing a simulation, and finally performing the required analysis.

Sources: [2] [51] [55] , and author’s estimation.

To assess the economic feasibility of the proposed solution, four distinct scenarios were modeled:

Base Case Scenario (Benchmark): GCA’s original evaluation, considering conventional WAG reinjection of associated gases.

Expected Case Scenario: Incorporates updated assumptions with the most probable outcomes.

High Case Scenario: Assumes improved economic results, driven by favorable market conditions.

Low Case Scenario: Represents a conservative estimate with unfavorable economic conditions.

The key assumptions driving these scenarios—including oil prices, NG prices, unit capital expenditure (Capex), and operational expenditure (Opex)—are summarized in Table 1 . The structured scenario framework allows for straightforward replication in future studies on similar offshore reservoirs. While this approach provides a robust comparative framework, a key limitation is the inherent uncertainty in forecasting long-term economic and policy trends.

A comparative analysis between the conventional gas management approach and the proposed gas management strategy was conducted. Figure 2 and Figure 3 illustrate these approaches:

Conventional Approach: The CH₄-rich stream is primarily used as fuel for the FPSO, with any surplus either reinjected with CO₂ (WAG) or flared if reinjection capacity is exceeded.

Proposed Approach: Deploys ssm-FLNG to commercialize the CH₄-rich stream, reducing flaring and venting while optimizing CO₂-WAG for enhanced oil recovery and permanent CO₂ storage.

A key advantage of this comparative analysis is that it highlights the potential environmental and economic benefits of the proposed approach. However, one limitation is that external factors such as regulatory changes, infrastructure constraints, and market dynamics could influence the actual feasibility of large-scale implementation.

The impact of each scenario was evaluated based on key performance indicators, including:

The methodology applies a sensitivity analysis to account for fluctuations in oil and gas prices, plant utilization rates, and cost variations, ensuring that the findings are robust and generalizable to other offshore fields. While the inclusion of sensitivity analysis strengthens the model’s applicability, the limitation remains that it cannot fully account for disruptive technological changes or policy shifts that could impact long-term project viability.

To facilitate replication of this methodology in other studies, we provide a clear breakdown of assumptions, data sources, and modeling parameters. The structured approach—including stepwise model development, data calibration, scenario analysis, and sensitivity testing—ensures adaptability to different offshore environments with varying reservoir conditions.

Researchers can apply this framework to assess gas monetization strategies in other developing countries facing similar challenges in balancing economic viability with sustainable resource management. However, one key limitation is that this methodology does not explicitly account for geopolitical risks, financing constraints, or operational challenges unique to each region, which may affect its practical implementation.

The gas-oil ratio (GOR) is a fundamental parameter influencing hydrocarbon field profitability and the feasibility of gas monetization strategies. It represents the volume of gas released per unit of oil produced under standard conditions. In this study, GOR values were estimated based on data from Gaffney et al. (2010) [2] and Petrobras reports [47] - [52] , ranging between 184.34 and 426.47 m³/m³. This variability affects not only the volume of methane (CH₄) available for commercialization but also the technical and economic feasibility of gas utilization solutions.

The concentration of CO₂ in the associated gas stream is a key factor in determining the commercial value of methane and the operational requirements for gas processing and transportation. High CO₂ levels can lead to increased processing costs, pipeline corrosion risks, and lower hydrocarbon revenues. However, when effectively managed, CO₂ can be reinjected into reservoirs as part of an Enhanced Oil Recovery (EOR) strategy, improving oil recovery rates while simultaneously serving as a means of permanent CO₂ storage. Based on Petrobras’ production forecasts [51] , the CO₂ content in the gas stream at the Búzios field varies between 24.30% and 48.50%, reinforcing the need for integrated CO₂ management strategies.

To maximize the economic potential of the Búzios field while addressing CO₂ emissions, this study evaluates three complementary technologies:

Liquefied Natural Gas (LNG): A conventional approach for transporting natural gas in liquid form via cryogenic cooling.

Small-Scale Mobile Floating Liquefied Natural Gas (ssm-FLNG): A flexible offshore liquefaction solution tailored for fields with variable gas output.

Enhanced Oil Recovery with CO₂ Storage (CO₂-WAG): A method to boost oil production while providing a long-term CO₂ sequestration solution.

Each of these technologies plays a distinct role in optimizing CH₄ and CO₂ management, as described below.

LNG involves cooling natural gas to cryogenic temperatures (−162˚C) to convert it into a liquid state for transportation and storage. This well-established technology enables large-scale gas exports and has evolved into a cost-effective solution for global gas markets [19] . In the context of the Búzios field, LNG provides a stable monetization pathway, particularly for CH₄-rich streams that exceed local demand or pipeline transport capacity.

Unlike conventional large-scale LNG plants, Small-Scale Mobile Floating Liquefied Natural Gas (ssm-FLNG) offers a more adaptable solution for offshore gas monetization. This technology integrates gas processing and liquefaction on a floating unit, allowing it to be deployed near production facilities and relocated as needed.

In this study, a dynamic allocation model ( Figure 4 ) illustrates how SSM-FLNG can optimize CH₄ utilization in the Búzios field:

Phase A: Initial deployment of ssm-FLNG units near FPSOs with high CH₄ availability.

Phase B: Relocation of units to FPSOs with increasing CH₄ output.

Phase C: Further redeployment within the Santos Basin Pre-Salt Cluster (SBPC) as localized CH₄ reserves decline.

The key advantage of ssm-FLNG is its ability to adjust production capacity based on gas availability, reducing the financial risks associated with large-scale infrastructure investments [45] . Additionally, it minimizes flaring and venting by commercializing CH₄ that would otherwise be wasted. However, technical challenges such as start-up/shutdown stability, gas composition variability, and offloading safety under offshore conditions must be carefully managed [34] . In this study, ssm-FLNG utilization rates were modeled between 33.33% and 87.00%, reflecting different operational scenarios.

CO₂ injection is widely used in Enhanced Oil Recovery (EOR) to improve oil displacement efficiency and increase overall recovery factor [28] [53] . The Water Alternating Gas (WAG) method enhances this process by periodically injecting CO₂ and water in alternating cycles, maximizing oil production while simultaneously facilitating long-term CO₂ sequestration [54] .

This study integrates CO₂-WAG into the techno-economic model to evaluate its impact on oil production, gas management, and project economics. Key considerations include: a) Oil Recovery Optimization: CO₂-WAG enhances oil displacement efficiency, increasing the recovery factor beyond conventional methods; b) CO₂ Storage Potential: The method provides a dual benefit by securely storing CO₂ underground, mitigating emissions from hydro-carbon production; c) Economic Sensitivity: Multiple production scenarios (expected, high, and low cases) assess the viability of CO₂-WAG adoption under different market conditions; d) By incorporating CO₂-WAG into the overall field development strategy, this approach aligns with global sustainability goals while improving project economics.

Price volatility represents a significant challenge for investment decisions. Historical oil prices ( Figure 5 ) have ranged from USD 10.00 to USD 123.00 per barrel in real terms. Based on these fluctuations, this study assumes a base oil price of USD 50.00 per barrel, with a sensitivity range of −50% (USD 25.00) and +50% (USD 75.00) to reflect market uncertainties.

For modeling purposes, LNG plant capacity was considered 1.0 MTPA based on information from [55] , and for ssm-FLNG, a plant capacity of 0.5 MTPA was assumed. It was believed that plants should achieve at least 33.33% of nameplate capacity; otherwise, they would not be implemented due to excessive idle capacity. Conversely, it was presumed that liquefaction plants do not exceed 87.00% of nameplate capacity.

In the case of critical assumptions, in the GCA base case scenario, the oil price was considered at 75.98 USD/bbl and increased annually by inflation (2.0% per year). In the expected case, the oil price was considered at 50.00 USD/bbl and the natural gas price at the wellhead at 5.50 USD/bbl, both with a 50% plus and minus variation for high and low scenarios, increasing by inflation over the years (2.0% per year).

According to the International Gas Union (IGU), plant costs vary widely and depend on oil and gas prices, location, capacity, and liquefaction process, among other cost drivers. The average liquefaction estimated by IGU for 2017-2022 is around 500 to 1541 USD/tonne (IGU, 2017). Based on that information and the correlation between Capex and oil prices, a unitary floating capital expense (Capex) was assumed to range from 800 to 1200 USD/tonne, with the expected case at 1000 USD/tonne.

In the case of ssm-FLNG, an additional unitary Capex of 7.00% was assumed, mainly due to the diseconomy of scale and mobility requirements, delivering an equivalent value of USD 1070 USD/tonne. This additional Capex for ssm-FLNG considers the net effect between diseconomy of scale partially compensated by savings relating to reducing space utilization on the Floating Production Storage and Offloading (FPSO) deck. Then, a 20% plus and minus variation was considered for high and low scenarios. In Table 1 , there is a summary of Capex for base, expected, high, and low cases.

Finally, regarding operational expenses (Opex), it was assumed that applying the evaluated gas-integrated technologies would result in a minor increase in Opex. Since most of the Opex is linked to the existing oil and gas production system, including treating the associated gas, we assumed that annual operational expenses relating to the deployment of integrated-gas technologies will vary in line with yearly corresponding capital expenses variance, based on the following metric: ∆ Annual Opex = ∆ Annual Capex X 5%. This rationale applies to either FLNG or ssm-FLNG technologies.

This work proposes to develop an alternative and improved management of gas streams by promoting a better allocation of natural gas (CH₄-rich stream) and carbon dioxide streams (CO₂-rich stream). The hypothesis is that the appropriate allocation and monetization of CH₄ and the enhanced substitution of WAG by CO₂-WAG improve these products’ profitability and intrinsic utility. To achieve this goal, it is necessary to fill the logistics gap through the effective deployment of ssm-FLNG combined with enhanced oil recovery (CO₂-WAG) and permanent storage of CO₂.

Figure 2 shows a schematic description of the conventional gas management (base case) versus the proposed gas management, considering deploying ssm-FLNG in the Búzios field. The process starts in the production manifold (1), where you separate oil, gas, and water. Then, the gas, a by-product of oil production, is treated and split into two major streams. One stream (2) is rich in natural gas (CH₄), and the other (3) is rich in carbon dioxide (CO₂).

In conventional gas management, the CH₄-rich stream is primarily used to fuel the FPSO (4), and the remaining volume is used for gas lifting and sold through pipelines whenever possible (5 and 6). If, at this point, there is still CH₄ available, it will join the CO₂-rich stream and be reinjected (WAG) (7). Finally, there is still residual CH₄ that cannot be reinjected for any technical reason. In that case, it will be sent to flaring or venting, which has environmental issues (highlighted in the red box). Therefore, the proposed strategy is to allocate as many volumes of CH₄ as possible to commercial activities that will allow its monetization, such as final users’ electricity production, transportation fuel, and high-value chemicals. In the case of the CO₂-rich stream, the goal is to allocate as much as possible volumes of CO₂ to sweep oil from reservoirs based on the theory that pure CO₂-rich streams have better sweeping properties than a mixed gas stream [56] .

Figure 2 represents the proposed gas management, which aims to increase the sales volume of CH₄ by offshore pipelines and ssm-FLNG units (5). Consequently, the flaring and venting of CH₄ would be reduced compared to the conventional process described in Figure 2 . At the same time, most of the rich CO₂ stream would be allocated to low-value activities such as gas lifting and CO₂-WAG enhanced oil recovery (7) with permanent CO₂ storage (8).

Figure 3 represents four scenarios of the gas-oil ratio (GOR) over the production cycle. There is the base case scenario, based on Gaffney et al. (2010) [2] , and there are the expected, high, and low case scenarios, based on updated information from Petrobras.

The grey line represents the base case [2] . The peak is in year 5 (GORmax 237.05 m³/m³) and slightly reduces over time, reaching year 26 (162.82 m³/m³), and then there is a reversal, and GOR starts growing gradually until year 36, reaching 196.65 m³/m³. From year 36 onwards, GOR presents a sharp reduction, going to 147.00 m³/m³ in year 39 just before ending its production lifetime by the 40th year. The blue line represents the revised expected case, the dotted green line represents the high case, and the dotted red line represents the low case.

This work reviews the values and shape of the GOR curve over the project lifecycle and, consequently, on oil and gas production curves. In the specific case of GOR, the original curve decreased over time, and the updated curves (expected, high, and low cases) increased over time. The updated shape of the curves was calculated based on the forecasted oil and gas volumes that Petrobras informed IBAMA [52] . This new shape, which has a higher GOR over time, is also consistent with enhanced oil recovery (EOR), considering gas reinjection. Unlike the base case, the expected, high, and low cases, GOR consistently grows from year five to the peak of production by year 37.

Using the same scheme of colors and line types, in Figure 4 , the grey line indicates the base case forecasted oil production by [2] . The production ramp-up starts in year 5 and goes up to year 11, when it reaches a plateau until year 18, and then goes down. Simulating new oil production, considering updated GOR and CO₂-WAG application as the enhanced oil recovery method, there is an anticipation in oil production compared to the GCA base case. It was assumed that the CO₂-WAG method anticipates oil production in all updated scenarios, keeping the same amount of total oil recovery by the end of the production lifetime, as indicated by Ahmadi et al.’s (2015) study.

The following figure utilizes the same scheme of colors and lines as the previous figures. Thus, the grey line indicates the base case forecasted oil production by [2] , and the other lines show the impact of GOR variance and CO₂-WAG application in gas production. As indicated in Figure 5 , the material variance of gas production over the years can imply a material idle capacity of assets or monetizing a tiny portion of the total produced gas, resulting in poor economic results. Thus, deploying mobile, modular plants, such as ssm-FLNG, has been identified as an attractive solution to overcome that issue [44] . Thus, assuming the possibility of allocating these plants with higher utilization rates improves the project’s financial numbers.

Gaffney et al. (2010) [2] estimated revenue generation from the Búzios field at 545.84 USD billion (oil price at 75.98 USD/bbl). This work revised the financial evaluation initially developed by Gaffney et al. [2] , considering updated and complementary techno-economic information over the last years.

The first point to highlight in the revenue analysis is related to oil and natural gas prices, representing a non-technical factor outside operational control. This factor has the most considerable impact on the base case revenue forecast. The revised prices reduced revenues by 186.67 USD billion (−34%). It is mainly driven by an oil price update that, in the expected scenario, reduces from 75.98 to 50.00 USD/bbl (−34%). On the other hand, the price of natural gas is expected to increase from 4.00 to 5.50 USD/MMBTU (+38%), which had a minor financial impact.

In Figure 6 , there is a step-by-step illustration of the initial revenue [2] and the revised revenue calculated by the model. In addition to the expected result, high and low scenario ranges for each value driver are analyzed.

It is essential to highlight that oil price variation impacts revenue streams for social programs. Table 3 summarizes oil and gas price variation and the corresponding impact on revenue generation for social services, considering the different case scenarios.

Source: Authors’ economic model (2025).

The expected price will reduce the project’s revenue and, subsequently, the corresponding revenue stream for social projects, projected to be reduced by USD 32,425 million. In the high-case scenario, this reduction would reduce to USD 919 million; in the low-case scenario, the reduction would achieve USD 65,648 million.

The fourth, fifth, and sixth columns in Figure 6 indicate the evaluated gas-integrated technologies that aim to promote better management of associated gas and corresponding gas streams (CH₄ and CO₂-rich). Regarding technology options to liquefy natural gas, it was identified that LNG increases revenue by USD 21,738 million and ssm-FLNG supplements with a limited revenue of USD 20 million (chart 6, fourth and fifth bars).

On the other hand, in the case of CO₂-WAG, it reduces revenue by USD 21,306 million, leading to a lower financial contribution in terms of the combined result of gas-integrated technologies at USD 452 million.

Table 4 summarizes the nominal revenue impact driven specifically by gas-integrated technologies for the different scenarios. According to Table 4 , gas-integrated technologies would increase nominal revenue by USD 452 million, increasing social services’ revenue by USD 79 million.

Source: Authors’ economic model (2025).

One of the key assumptions analyzed in this work is the gas-oil ratio (GOR), which is indicated in Figure 6 and Figure 7 as the seventh bar. Gaffney et al. (2010) [2] indicated that GOR for Búzios would range from 184.34 to 225.31 m³/m³. From the informed production volumes, an average of 197.38 m³/m³ was calculated.

Additionally, Petrobras reported that GOR starts at 223.00 m³/m³ and grows over the 35-year production period to an equivalent average of 36,003 m³/m³. Based on the developed model and updated information from Petrobras, the projected GOR average for the Búzios field was revised to 35,358 m³/m³ (an increase of 79.14% versus Gaffney’s base case).

Considering the assumption of monetizing part of this gas volume through the liquefaction and commercialization of natural gas (CH₄-rich stream), the GOR growth represents an equivalent revenue increase of 17,219 USD million (expected case).

The positive contribution in terms of potential revenue increase coming from GOR growth assumes that total oil production remains the same and, consequently, there is a corresponding increase in gas production. This assumption is aligned with the latest Petrobras reports, which indicate that the expected recoverable oil from the Búzios field is higher than forecasted in preliminary contracts.

The last value driver analyzed is CO₂ content in associated gas and its corresponding impact on revenues. From a financial perspective, it was calculated that a CO₂ content of 32.77% would reduce revenue by 12,773 million, assuming that it would reduce the availability of natural gas (CH₄) that could be commercialized.

In summary, Figure 6 indicates that the initial revenue forecast from Gaffney was USD 545,835 million, and this study revised it down considering the revised lower oil price forecast. On the other hand, deploying gas-integrated technologies combined with higher GOR could partially compensate for this loss, delivering a final revenue of USD 350,969 million.

Concerning the project’s value, the net present value (NPV) from the Búzios field was estimated at 56,832 USD million [2] . Considering the revised expected price for oil and gas, NPV would drop to 31,793 USD million, representing a reduction of 44.06%.

Pricing is the most critical value driver for value creation. In the case of gas-integrated technologies (fourth, fifth, and sixth columns), they can potentially increase NPV by 6449 USD million (20.28% increase), most of this result relating to CO₂-WAG, which accelerates oil extraction. The gas-oil ratio (GOR) has an expected NPV contribution of USD 739 million, and CO₂ content in gas is expected to reduce NPV by USD 490 million. As can be analyzed by Figure 7 regarding NPV.

The model indicates that ssm-FLNG application has a significantly higher utilization rate ( Table 5 ) than LNG plants.

In summary, the NPV forecast from Gaffney et al. (2010) [2] was USD 56,832 million over the production cycle, and then it was revised considering the revised oil price forecast. On the other hand, deploying gas-integrated technologies could partially compensate for this loss, delivering a final NPV of USD 38,491 billion.

Source: Authors’ economic model (2025).