**4. Results and Discussion**

The proposed change in the process steam drive from the actual condensing steam turbine to a new backpressure one anticipated a significant increase in HPS consumption. Whereas the actual consumption ranged roughly from 7.5 to 8.5 t/h (Figure 6), preliminary calculations for the turbine at nominal conditions (3.35 MPa, 325 ◦C HPS (BL), 1.0 MPa, 252 ◦C MPS (BL), 65% isentropic efficiency, 85% mechanical efficiency, 100% compressor shaft speed) revealed an increase in turbine HPS consumption to approx. 35 t/h. Hence, steam transport velocities in the interconnecting pipeline were studied (Figure 20).

**Figure 20.** HPS transport velocity as a function of pipe diameter.

As the conducted case study showed (Figure 20), steam transported by a pipeline with a diameter below 7 would breach the erosional velocity limit defined for HPS. Thus, a pipeline with such a diameter would encounter serious erosion. As the diameter of 7 is not typical for industrial applications, an 8 inlet pipeline was considered. A 10 pipeline was chosen for the exhaust side (Figure 21).

The optimal inner pipe diameter was used to calculate nominal performance parameters. For each case, respective assumptions were incorporated in the simulation program to obtain information on nominal HPS consumption. The isentropic enthalpy difference was then determined from the actual enthalpy difference calculated by the model, and the characteristics' intercept was calculated directly, as seen in Equation (13):

$$K = \dot{m}\_{\rm S} - \frac{1}{\Delta h\_{\rm IS}}P\tag{13}$$

For any point of the characteristics (different from the nominal point), isentropic efficiency can be calculated from Equation (14):

$$\eta\_{\rm lS} = \frac{\Delta l}{\Delta l\_{\rm lS}} = \frac{\frac{\mathcal{W}}{\dot{m}\_{\rm S}}}{\Delta l\_{\rm lS}} = \frac{\frac{\frac{P}{\eta\_{\rm mech}}}{\frac{1}{\Delta l\_{\rm lS}}P + K}}{\Delta l\_{\rm lS}} = \frac{P}{\eta\_{\rm mech}(P + \Delta l\_{\rm lS}K)} \tag{14}$$

**Figure 21.** Pipeline inner diameter. Legend: Solid line = existing pipeline; dashed line = new pipelines.

Polynomial fitting of the isentropic efficiencies provided parameters for Figure 19, which, as well as other characteristic parameters of the turbine, are summed up in Table 4.


**Table 4.** Turbine characteristics.

To account for ambient temperature variations during the evaluated period, discrete temperature peaks were considered. These encompassed the highest, the lowest, and the average ambient temperature measured in 2018. Because cases 4–6 did not consider the pipeline properties, turbine characteristics for these cases were identical as they shared the same design point.

As can be seen in Table 4, temperature fluctuations affected the steam consumption minimally. Due to high temperature of the transported medium (HPS, ~325 ◦C), the driving force of heat transfer depended only insignificantly on the change of ambient temperature. Thus, the ambient temperature variations could be neglected, and were not taken into further consideration.

To visualize the differences between individual approaches, HPS consumption over the evaluated period using the methodology of each considered case was examined. For cases incorporating heat loss, the average ambient temperature (10 ◦C) was considered. In Figure 22, an evident discrepancy between the individual cases can be observed. Average deviations from the base cases (case 1 for actual pipeline length; case 7 for tenfold increase in pipeline length) are summarized in Table 5.

**Figure 22.** HPS consumption over the evaluated period.



While the effect of heat losses from pipelines to the ambient space were proven to be minimal for the actual length of piping (average deviation ≤ 0.31%), a tenfold increase in the pipe length increased the average deviation up to 3.74%. Hence, heat loss increased linearly with the distance. An almost identical trend could be observed in the pressure drop calculation, however, with dramatically different impact on the calculated HPS consumption. Thus, for calculations comprising long pipelines, severe errors are to be expected if pressure drop is neglected. Furthermore, models not considering steam quality fluctuations (case 5) and compressor shaft speed variations (case 6) are not capable of predicting peaks in HPS consumption (provide different trends) and are thus unsuitable even for systems comprising short pipelines, though their average deviation is only slightly different to case 4.

For a more comprehensive illustration, the yearly cumulative differences were displayed in Figures 23 and 24 for case 1 and case 7, respectively. For the actual-size pipeline, two most significant contributions were visible: The first caused by neglecting the pipeline pressure drop and the second by considering a constant isentropic efficiency. The latter has proven to be the most severe, resulting in an almost 13 kt/y difference.

**Figure 24.** Cumulative difference in HPS consumption (base case 7).

When considering a pipeline ten times the length of the actual pipeline, the effect of every simplification in the process drive sizing becomes more evident. However, in contrast to calculations of the actual pipeline, the pressure drop is the most crucial. Moreover, cumulative differences in HPS consumption prove the overall trend to be monotonic as opposed to average deviation of case 5 from case 7 (Table 5). These findings underline the fact that even though average deviations for some cases showed only slight differences, significant cumulative differences can occur. This, above all, affected the final economic evaluation.

Practically every unit operates off-design for most of the operational time as the exact conditions defined as nominal are hardly ever met. However, the measure of deviation from the design parameters shows how well the equipment has been designed. To assess a possible negative impact of the steam drive replacement on the driven process, a study was conducted operating the turbine at full load for each case and each day of the evaluated period. The power output provided by the turbine consuming nominal amount of steam (Table 4) was compared to the actual power requirements of the process. A threshold of 5% (65 kW) was set, which is a typical design margin. In this study, again, results for the actual pipeline were compared to the ten-times-longer pipeline variant.

As shown in Figure 25, for a relatively short pipeline (≈100 m), a turbine designed with respect to all abovementioned aspects (Case 1) provided the process with the required power over the whole evaluated period. Simplified models, cases 4–6, also provided satisfactory results with hardly any threshold overshoots. However, the difference in the performance reserve was evident, pointing out nominal turbine inlet steam mass flow undersizing.

**Figure 25.** Required to maximal power output differences for case 1 (**A**) and cases 4–6 (**B**) considering 100% pipeline length. Dashed line represents a typical 5% design reserve.

The situation changed dramatically with the increase in pipeline length. As depicted in Figure 26, even when all the aspects were considered (case 7), there was a short period of time when the turbine was not capable of providing the required mechanical power. The more such periods appeared, the less system properties were considered (e.g., case 9, which did not take heat loss into account). Finally, the worst-case scenario did not take pressure drop into account. As proven below, a turbine designed without regard to pressure drop along the pipeline did not provide the process with the required mechanical power with its lack exceeding 100 kW (approximately 8% of nominal mechanical power requirement) very frequently. The inability of the steam drive designed without steam frictional pressure losses consideration to meet the process-side mechanical power demand inevitably resulted in a decrease of processed C3 fraction mass flow. The C3 fraction splitting process could thus become a bottleneck of the whole FCC reaction products separation section with serious consequences on its profitability.

Based on the process side characteristics (Figure 10), production loss due to insufficient power supply can be quantified. Each 100 kW of lacking power output (i.e., power output below the dashed line in Figure 26) represented 2.16 t/h of production loss (Figure 27). For the studied propylene recovery unit processing approx. 65.8 kt of feedstock yearly, the decrease of 13.2 kt/y (20%) was unacceptable.

**Figure 26.** Required to maximal power output difference for case 7 (**A**), case 9 (**B**) and cases 4–6 (**C**) considering 1000% pipeline length. Dashed line represents a typical 5% design reserve.

**Figure 27.** Loss in production for a system considering 1000% pipeline length.

Besides the impact of the proposed steam drive change on the propylene recovery process, its e ffect on the operation of the refinery's main HPS and MPS pipelines was assessed in terms of transported steam mass flow. A significant change in the steam mass flow may result in new bottlenecks or even an infeasible operation of the network [26]. Current HPS pipeline operation was analyzed in detail by Hanus et al. [26], defining the safe operation window between 20 and 60 t/h of exported HPS from CHP. Such conditions prevent excessive erosion and pressure losses on one hand and steam stagnation in pipelines on the other. An existing pipeline, returning HPS to the CHP, enables HPS network operation with zero or even negative net HPS export from the CHP. Furthermore, exporting more than 60 t/h of HPS from the CHP is possible by utilizing a second main HPS pipeline that is normally closed but can be activated if needed. However, even with both the main HPS pipelines active, exporting more than 80 t/h HPS from the CHP for longer periods is unwanted, though possible. As shown in Figure 28, the proposed steam drive change eliminated the occurrence of undesirably low HPS export from the CHP and simultaneously led to HPS export of over 80 t/h in certain periods, forcing the steam network operators to undertake additional measures to ensure the HPS network stability.

**Figure 28.** Impact of proposed steam drive change on the HPS network. Long-term operation of the HPS network outside the <0; 80> t/h HPS export interval is infeasible.

The MPS network operation was also investigated and the results are shown in Figure 29. Presently, the MPS demand of the refinery exceeds 80 or even 100 t/h, which strains the MPS production capacity of the CHP. MPS export of over 100 t/h cannot usually be met by steam extraction and the deficit has to be covered by 9 MPa steam throttling in the CHP. As presented in Figure 29, the occurrence of such unwanted states is strongly reduced by the new process drive in operation. A few periods appear, though, with MPS export below 20 t/h, which may a ffect the MPS network operation stability and have to be avoided by active MPS network management.

The change in exported steam mass flow at high-pressure and middle-pressure levels a ffects fuel consumption and carbon dioxide emissions of the CHP. The resulting e ffect di ffers according to the season of the year:


**Figure 29.** Impact of proposed steam drive change on the MPS network. Long-term operation of the MPS network below 20 t/h of exported MPS is infeasible.

Based on discussion with CHP managers and operators, the following input data were considered in calculations:


Trends of fuel consumption change and CHP electric power output decrease in the evaluated period are visualized in Figure 30.

**Figure 30.** Economic evaluation.

Evaluation of the economic potential of the condensing steam drive replacement assumed the following prices: Electricity 45 €/MWh; heavy fuel oil 120 €/t; and CO2 emissions 27 €/t. The hourly benefit results from (1) the achieved decrease in fuel consumption and in CO2 emissions, and (2) the amount of additional power purchased from the outer grid. Additional power has to be purchased to

balance the lower CHP output in colder months (Figure 30). The cumulative benefit curve (Figure 30) is obtained by summing up the hourly benefits over the evaluated period. As can be seen, most of the benefit is harvested during colder months. Overall, 3.72 kt/year of fuel can be saved and CO2 emissions from the CHP can be reduced by 11.13 kt/year as a result of the process steam drive replacement. The resulting benefit is expected to be over 300,000 EUR/year. A preliminary estimate of the steam drive replacement cost including new pipelines is around 450,000 EUR, leading to a preliminary simple payback period of 1.5 years. Due to the envisioned CO2 emission cost increase, economic feasibility of this proposal should be retained even if the fuel price decreases or that of purchased electricity increases.

Considering the results presented in Figure 25, it can be concluded that the C3 fraction feed processing capacity is met even with less rigorous steam drive sizing method. However, for the alternative with ten-times-longer pipelines, only the rigorous method presented in this paper ensures the retained process throughput capacity. Less complex sizing methods led to undersizing of the steam drive and the resulting processing capacity limitation (see Figure 27) outweighed the economic potential of the steam drive replacement (Figure 30) by far.

The presented technical and economic results varied significantly depending on the type and operation of the CHP that served as a marginal steam source. Modern industrial CHP units usually comprise a gas turbine-based combined cycle. If such a unit operates in a purely cogeneration mode (no or minimal condensing power production), the resulting change in fuel consumption and power production is di fferent from that in Figure 30. Apart from the electricity production change due to the steam balance shift on HPS and MPS levels, either (a) an increase in condensing power production due to utilization of the saved HPS, or, (b) a decrease in the power output of gas turbine(s) and the associated fuel consumption reduction can be observed. The way is chosen by the CHP managers based on fuel costs compared to marginal power production cost in the combined cycle. In any case, since the combined cycle is a more e fficient marginal cogeneration steam source than a traditional steam CHP, the resulting fuel consumption and CO2 emissions release is lower. This further accentuates the need to analyze the marginal steam source operation carefully prior to steam drive sizing.
