2. Methodology
One of the solutions to reduce carbon emissions and the operational expenditure (OPEX) of power generation, whilst maintaining reliable power availability, is to implement a floating wind including gas turbine as a hybrid micro-grid power generation approach, as illustrated in
Figure 3. In this concept, one GTG is replaced by a WT system. There will be one generator running with a WT and one other generator on standby.
The sizing of the GTGs needs to be properly studied, where each GTG should be able to take up 100% of the load. The system is housed on a floating platform held by a gravity anchor. It will be an unmanned platform and will be remotely operated with embedded condition monitoring systems. Since it is a non-fired system, the maintenance is low compared to gas turbine maintenance; hence, this will result in a reduction in the maintenance cost. In addition, the fuel gas usage will be reduced, which lowers the fuel gas cost and reduces carbon emissions. Moreover, the unused fuel gas is converted into additional gas revenue, thereby improving the economics of the hybrid power generation compared to conventional power generation. Firstly, the technical framework was established. An offshore O&G field in Malaysia with a 5 MW power generation requirement was selected. Two scenarios were developed: brownfield and greenfield. The brownfield scenario is an existing field that has existing GTGs in operation. Therefore, there were no additional GTGs being purchased, hence zero CAPEX for GTGs. The greenfield scenario is a new field where the CAPEX for GTGs are included. For each scenario, two power generation concepts were drawn up, namely, conventional and hybrid power generation. In the conventional power generation scenario, there were three GTGs, whereas in the hybrid power generation scenario, there were two GTGs and one WT system. The OPEX consisted of maintenance cost, carbon tax, and abandonment cost. Meanwhile, the CAPEX of the hybrid concept omitted one GTG and included one WT instead. The OPEX considerations for both concepts were similar for the two scenarios.
Next, the economic framework was established. The cash flow was based on revenue minus royalty minus cost minus tax and discounted to 2022. In the lifecycle cost, the present value (PV) for each year was calculated based on the discounted revenue minus the cost formula, and the net present value (NPV) was determined over the lifecycle period, as shown in Equation (1).
where:
PV = present value,
CF = future cash flow,
r = discount rate,
t = number of years.
The NPV was based on the incremental gain between conventional and hybrid concepts for each scenario. The important parameters that are considered in this study are the gas-heating value of 1000 mmBTU/mmscf, fuel gas efficiency of 0.5 mmscfd/MW, carbon tax rate of USD 26.10/ton of carbon dioxide, escalation rate of 3%, weighted average cost of capital (or the discount rate) of 7%, and the OPEX of USD 27.70/MWh [
11], and the EUR to USD exchange is taken as 1.14. The Malaysian tax rates applicable here are the oil and gas upstream tax of 38% and downstream tax of 24%. The abandonment cost and sales gas price are confidential company data.
Next, the LCOE, as shown in Equation (2) [
11], was calculated, where the incremental gain between the conventional and hybrid case was analyzed.
where:
Next, the sensitivity analysis was performed, where the CAPEX, OPEX, and wind energy (AEP) were analyzed. Lastly, the economic threshold for a viable hybrid concept was defined and the optimum configuration was recommended.
3. Results
The 10 min average wind speed at a 10 m height at various oil and gas platforms based on 20 years of SEAFINE hindcast data was studied, as illustrated in
Figure 4. Generally, the average annual mean wind speed was found to be between 5 and 6 m/s. The wind was strongest at platforms in offshore Peninsular Malaysia and offshore Sabah.
For the techno-economic analysis, Field 5 was selected based on the following selection criteria:
In this study, the power law was applied to the measured data and the hindcast data, where the alpha value was derived and shown in
Figure 5 to be 0.12.
As per the SEAFINE hindcast, the annual wind speed at 110 m mean sea level was found to be 6.80 m/s, which was chosen for this study. The Weibull shape factor is assumed to be equal to Rayleigh distribution where k is assumed as 2.
In this study, it is assumed that the power required on Field 5 is 5 MW. The parameters based on ELEON WT are shown in
Table 1.
The Weibull distributions and the corresponding energy yield per wind speed bins (
Figure 4) were calculated and are shown in
Table 2. The AEP is the total power generated in each bin, which was found to be 16,507 MWh/a. At the annual mean wind speed of 6.8 m/s, the Weibull distribution was found to be the highest at 11%. However, the energy yield was only 5% of the AEP (797 MWhr/a). The energy yield was the highest from 10 to 11 m/s, even though the Weibull distribution was only 13%; this range gave the highest energy output, which catered for approximately 1/3 of the AEP.
The AEP was based on a P50 probability value. The other probability values (P70, P75, P80, P90) were based on 15% uncertainty, where the industrial practice ranged between 8% and 15% (for example, the wind data, metrology data, power curve, etc.). A summary of the probability values for the Field 5 AEP is shown in
Table 3. From here, it can be calculated that the capacity factors for P50 and P90 are 38% and 30%, respectively, which is within the industry standard.
There is an incentive given by the Government of Malaysia for undertaking petroleum operations that require intensive capital investment, called capital allowances on qualifying plant expenditure [
25]. GTGs fall under the category of “Any other case” and WTs fall under the category of “Environment protection equipment and facilities”, and the rates of the initial and annual allowances up to 100% of the capital expenditure against the gross income for each year of assessment are illustrated in
Table 4. This can be carried forward to offset future business income. Here, it can be seen that the tax allowance for WTs can be obtained as early as 3 years, while for GTGs, this will take longer—at least 10 years.
A generic cost for three 6.5 MW GTGs including engineering, procurement, construction, installation, and commissioning costs, along with the related topside and jacket requirements, is assumed to be USD 11 Mil higher than two units of similar GTGs in the hybrid concept (based on the PETRONAS inhouse 5–6.5 MW GTG cost database). The WT OPEX is taken as USD 27.7/MWh [
11]. OPEX included GTG OPEX, WT OPEX, and carbon tax. The fuel gas cost was not included here. The abandonment costs of three GTGs are USD 2 Mil higher compared to two GTGs. The WT abandonment was taken as USD 2 Mil with the assumption that the abandonment costs are shared with the field abandonment.
The lifecycle cost was analyzed, where the discounted cash flow for the conventional and hybrid concepts was calculated and the incremental NPV@7 between them was derived.
Figure 6 and
Figure 7 illustrate the lifecycle costs for the brownfield and greenfield scenarios, respectively, where the incremental lifecycle costs were USD 10.77 Mil and USD 18.79 Mil, respectively. For both scenarios, the earlier cash sink was due to CAPEX in the development phase. The conventional cash flow was worse than hybrid for both scenarios, as the latter had reduced OPEX and additional revenue from diverted fuel gas. Greenfield had a higher incremental gain due to GTG CAPEX considerations in the conventional concept. The incremental NPV for the hybrid compared to the conventional concept for brownfield and greenfield were found to be 37% and 22%, respectively. Greenfield had a lower incremental gain due to higher CAPEX from GTG CAPEX inclusion.
Figure 8 illustrates the discounted cumulative cashflow of both scenarios. As Greenfield has a higher incremental gain, the payment period is only 4 years compared to 12 years for brownfield. The greenfield scenario is 43% better than the brownfield scenario. The positive incremental NPV for both the greenfield and brownfield scenarios for the hybrid concept in comparison to the conventional approach was due to the additional sales gas revenue, which is the main advantage for oil and gas platforms compared to the typical power to grid cases.
Next, the LCOE was calculated and is shown in
Table 5. It was found that the LCOE for the WT, hybrid, and conventional concepts was USD 165.52/MWh, USD 213.59/MWh, and USD 273.28/MWh, respectively. For 5 MW power generation, the total AEP required (345 days of operation annually) is 41,400 MWh. The WT capacity factor is 38%, which shows adequate performance in low wind areas. The WT will supply about 40% of the power requirements of Field 5, and the remaining will come from the GTG. Whilst the CAPEX of the hybrid is higher than the GTG, the OPEX is reduced by 27% due to the lower maintenance costs, carbon tax, and ABEX, as the ABEX for WTs is lower than for GTGs. The hybrid solution has the revenue stream for additional sales gas that offsets the LCOE by USD 56.26/MWh, without which the hybrid LCOE will be USD 269.85/MWh, which is 12% lower than for GTG only. It can be concluded that the WT LCOE was 39% lower than the conventional approach, while the hybrid solution was 22% lower than the conventional. It can also be concluded that the LCOE for the WTs in low wind speed areas was found to be between 19% and 34% higher than the expected first commercial project targets.
Sensitivity analyses were performed on the greenfield scenario as a base. The parameters were CAPEX (±20%), OPEX (±20%), and AEP (+20% and P90), where the P90 AEP was approximately 19% lower than the base case. This analysis will be used to determine the core parameters that will impact the techno-economics.
Table 6 illustrates the analysis, and
Figure 9 gives the graphical representation. The lifecycle cost was impacted the most by the AEP (wind energy), followed by CAPEX, and then OPEX with the least impact.
It is also interesting to note that for all of the cases, the resultant incremental NPV was higher than the brownfield scenario, between 30% (low AEP case) and 52% in the high AEP case. The payback period ranged between 4 and 8 years, which indicates robust economic performance.
4. Conclusions
The importance of marine renewable energy is gaining traction with governments around the globe committed to COP26 on carbon reduction, where offshore wind, wave, tidal, and other energies are key drivers to promote the decarbonization of power generation at offshore O&G platforms. Since renewables are not as reliable as full standalone power, a hybrid concept has been shown to be more economically feasible compared to the conventional concept. The incremental NPV7 for the hybrid concept in the greenfield scenario (USD 18.79 Mil) was around 43% better than for the brownfield scenario (USD 10.77 Mil). This is expected, as for brownfield, there was no CAPEX for the included GTGs as there were pre-existing GTGs available. In addition, the OPEX for the GTGs was higher in the brownfield case, as there was an additional GTG to maintain, and the addition of the WT OPEX in the greenfield case was still lower than the extra GTG available in the brownfield scenario. The payback periods for greenfield and brownfield, at 4 and 12 years, respectively, are strong indicators that wind energy in low wind speed areas can yield economic benefits for oil and gas platforms.
The LCOE of the WT was calculated to be USD 165.52/MWh, around 39% lower than the LCOE for the conventional approach (USD 273.28/MWh). The LCOE for the hybrid solution including a combination of GTGs and WTs was found to be USD 213.59/MWh, around 22% lower than the conventional concept.
For the sensitivity analysis of the NPV, the variable parameters taken were the wind energy (AEP), CAPEX, and OPEX. Wind energy gave the most impact, and OPEX the least. It was interesting to note that the incremental NPV for all cases was still higher than for the conventional approach.
This study has shown that with the careful design and selection of a WT system, harnessing wind energy is viable in low wind speed regions. Thus, it is hoped that these findings give confidence to the adoption of offshore wind power, not only in southeast Asia, but also other regions around the world where low wind speeds prevail.