cnx_vinyl/docs/sustainability.md

Sustainability

Two commitments are fixed design requirements for this plant, not aspirations to be traded away during engineering: run on as much renewable energy as possible, and discharge no contaminated water. Both are decisions we can actually make, because the two biggest utility systems (steam and cooling) are explicitly excluded from the Newbilt scope and will be sourced and installed locally in Thailand. That gives us a free hand to spec them green from day one.

Renewable energy: large solar installation

The pressing machinery itself is a modest electrical load: 32 kVA connected, ~21 kW average for a full Duplex line, ~118 kVA for the five-press fleet. The real energy demand sits in the utilities around it, above all the steam (750 to 900 kg/h of saturated steam at 10 bar / 180 °C for five presses) and process cooling (up to ~650 kW), drawn in steam and cooling.

• A large rooftop/ground PV installation is planned. Northern Thailand's solar irradiance is favorable, and daytime-heavy production shifts align well with PV output.
• The chosen hardware direction: multiple large Deye three-phase hybrid inverters (30 to 80 kW class, parallelable up to 10 units) paired with a Gobel Power high-voltage LiFePO4 battery stack at 271 kWh (15 stacked 18 kWh packs, LFP 314 Ah cells, rated 8000+ cycles). Deye is an officially supported protocol on the Gobel BMS, and Deye has established Thai distribution. Two engineering checks are open: matching the battery rack's DC voltage window to the specific Deye model (a full 15-pack rack can exceed the 800 V window of the smaller Deye series), and obtaining Gobel's safety certifications (not published) for a Thai commercial install. At 271 kWh the stack is a ride-through buffer, not full off-grid autonomy, against loads like the chiller bank's ~210 to 325 kW peak draw; under PEA's time-of-use tariff it earns little from peak shaving (grid tariff).
• The machine load and cooling system are straightforward PV targets.
• Steam is the open engineering question. Options under evaluation are an electric boiler (maximizes the solar share) and a biomass boiler (locally abundant fuel); solar-thermal pre-heating of boiler feedwater was considered and is not recommended. No technology choice has been made yet; it will be driven by honest numbers on load profiles, storage, and grid backup, not by what sounds greenest. At PEA's tariff and current northern fuel prices, biomass heat costs a quarter to a tenth of electric steam (grid tariff).
• Whole-factory HVAC (continuous temperature, humidity, and PM control, see facility systems) adds a major tropical-climate load on top of process cooling and must be part of the PV and battery sizing.
• System sizing (kWp, storage, grid-connection model) is open until the site is chosen.

Roof design for PV (candidate Mueang Chi site)

Sized against the candidate 5-0-66.5 rai parcel in Mueang Chi (18.4708 N, 98.9642 E), whose narrow skewed shape fixes how the building can sit. Two findings drove the roof form:

• Orientation barely matters at this latitude. An annual geometric clear-sky model puts the optimum fixed tilt near 18° facing due south, but the response is very flat — at 10° tilt, swinging the azimuth from due south to ESE costs under 2%. Rotating the building toward due south would gain under one percentage point of yield while cutting boundary clearance from 16 m to 12 m. The building therefore stays aligned with the plot, which also keeps truck circulation on the site's long axis.
• Roof form matters more than orientation. The plot puts the long axis on a 212° bearing, so a symmetric gable would strand half the array on a WNW-facing slope worth only ~94% of ideal. A monopitch roof at 10°, falling toward ESE, puts the entire roof on one plane at ~98% of ideal and yields a single uninterrupted rectangular array field — simpler racking, stringing, and roof penetrations.

10° was chosen over a shallower pitch deliberately: the yield difference between 6° and 10° is under 0.2%, but northern Thailand's dry-season dust and burning haze make self-cleaning in the rains worth more than the ~1.8 m of extra building height the steeper pitch costs.

Item	Figure
Sloped roof plane	~1,520 m²
Module assumed	generic 580 W, 2,278 × 1,134 mm (~225 W/m²)
Modules (1 m perimeter strip, walkway every 4 rows)	425
Installed capacity	~247 kWp
Array coverage of the roof plane	72%
Expected yield	~335 to 360 MWh/yr
Share of mature two-shift use (1,000 to 1,500 MWh/yr)	~25 to 35%

No module has been selected. The 580 W / 2,278 × 1,134 mm figure is a generic placeholder for the current large-format n-type TOPCon class (the size and power band shared by Trina Vertex, JA Solar DeepBlue, Longi Hi-MO and Jinko Tiger Neo in their 570 to 600 W ratings), chosen so the layout count is realistic. Capacity scales almost linearly with whatever module is actually procured: the roof fits ~425 modules of that footprint, so a 550 W module gives ~234 kWp and a 620 W module ~264 kWp. String sizing must then be matched to the Deye inverters' MPPT voltage window before anything is fixed.

Caveat on method: the tilt/azimuth comparison is a geometric clear-sky model, so it is reliable for ranking orientations but not for absolute energy. The kWh/kWp figure behind the yield column is the regional 1,400 to 1,500 kWh/kWp/yr assumption, derated to ~98% for the ESE azimuth. Confirm against PVGIS or a TMY dataset before committing capital.

This supersedes the older "150 to 200 kWp on a ~1,500 m² roof" figure in scale, which assumed lower module power density; current large-format modules reach roughly 225 W/m². Roughly 70 m of plot depth remains undeveloped behind the building for ground-mount, which matters if the electric-boiler route is chosen.

Energy efficiency architecture: recover before generating

The deepest efficiency in this plant comes from its own thermodynamics: the steam's job is to heat the molds, and the cooling water's job is to remove that same heat again, so roughly 98% of the press cooling load (up to 125 kW a press, ~650 kW for the five-press fleet) is heat leaving the press molds, put there almost entirely by the steam, and the press cooling return exits at ~60 °C (Newbilt site requirements; the concept is drawn in steam and cooling). That warm return is a premium heat source, and the architecture is built around reusing it before generating anything new:

• Feedwater heat recovery: a water-to-water heat pump lifts the 60 °C press cooling return into boiler feedwater at 90 to 95 °C. Each kWh it consumes does double duty: it cuts the boiler's work and removes load from the chiller at the same time. Together with condensate return, this saves roughly 10 to 15% of steam energy while shrinking the cooling system.
• Waste heat for low-grade consumers: the label dry oven and HVAC dehumidification reheat (the 35 to 60% RH spec means air is cooled below dew point and reheated continuously) run on recovered press heat instead of fresh electricity.
• Solar thermal feedwater preheat (considered, not recommended): flat-plate or evacuated-tube collectors reach 60 to 90 °C easily in the Thai sun, but that is the temperature the heat pump already recovers for free, and the roof earns more as PV (see the grid tariff section below).
• Steam accumulator: the presses draw steam in bursts, so an accumulator (already a Newbilt option) lets a smaller boiler ride the peaks.
• The boiler only does the final lift: whichever technology is chosen (electric, LPG, or biomass), it supplies just the last step to 180 °C / 10 bar from already-hot feedwater.

Two honest exclusions, checked and ruled out:

• Heat pumps cannot make the final steam: commercial steam-generating heat pumps top out around 120 to 165 °C at lower pressures than the fixed Newbilt spec of 10 bar / 180 °C; hybrid heat-pump-plus-compression systems exist as industrial pilots, but core utility reliability is the wrong place to pioneer.
• Ground-source (earth temperature) does not work in tropical Thailand: the ground sits at 28 to 30 °C year-round, far too cold to be process heat and warmer than the 20 to 25 °C cooling loop wants, so boreholes help neither side. That budget is better spent on PV panels.

Fuel-side context for the boiler choice: there is no natural gas pipeline in northern Thailand, so gas firing means an on-site bulk LPG tank (roughly 2.5 to 5 tonnes, with hazardous-storage separation distances and licensing), and diesel means a fuel tank with price exposure. The electric and biomass paths avoid a fossil tank on the property entirely, which matters for both the sustainability commitments and the BOI story.

Grid tariff (PEA) and what it decides

Source: PEA's electricity tariff schedule effective from the May 2023 bill (unofficial English translation, filed as finance/pea/EN_Electricity_Tariffs_May_2023.pdf), still the current schedule on PEA's tariff page, and the Ft on PEA's Ft page, both checked 7 October 2026. Plant consumption and demand are this repo's estimates (scale).

Which tariff applies. At ~430 to 700 kW of peak demand without electric steam (five presses, scale) the plant is Schedule 3, Medium General Service (30 to under 1,000 kW and at most 250,000 kWh a month on a three-month average). The flat-rate 3.1 is closed to customers classified after November 2015, so a new plant is on 3.2, Time of Use, and with a 22 kV connection on 3.2.2:

Item	Rate
Demand charge	132.93 THB per kW of the highest 15-minute demand in peak hours
Energy, peak (09:00 to 22:00, Monday to Friday)	4.1839 THB/kWh
Energy, off-peak (22:00 to 09:00 on weekdays; all day on weekends and public holidays)	2.6037 THB/kWh
Service charge	312.24 THB/month
Ft, fuel adjustment (September to December 2026)	+0.1623 THB/kWh, reset every four months
VAT	7 % on top; reclaimable for a VAT-registered company, so left out below

Rules that shape the design: metering on the low-voltage side of our own transformer adds 2 % to kW and kWh, so meter at 22 kV; the minimum bill is 70 % of the highest demand charge of the last twelve months; a power factor below about 0.85 (reactive demand above 61.97 % of active) costs 56.07 THB per kVAR, so the motor loads need correction. With electric steam the plant would average ~210,000 kWh a month (estimate) and its ~950 to 1,330 kW peak crosses 1,000 kW, which moves it to Schedule 4; that schedule's TOU rate 4.2.2 is identical, so the price does not change. Connecting a high-voltage meter below 69 kV costs a 15,000 THB inspection fee plus a security deposit of 400 THB per kVA (PEA tariff page, rates from January 2020): ~320k to 400k THB for the 800 to 1,000 kVA transformer the five-press plant needs without electric steam, 500k to 640k THB for 1,250 to 1,600 kVA with it.

What it costs the plant. Two shifts from 06:00 to 22:00 on ~300 days (about 243 weekdays and 57 Saturdays, estimate) put ~66 % of process energy into peak hours: a blended ~3.81 THB/kWh including Ft, before the demand charge. Without electric steam (1,000 to 1,500 MWh a year, 430 to 700 kW peak) the bill comes to roughly 4.5M to 6.8M THB a year before solar, 0.7M to 1.1M of it demand charge (estimate).

Electric versus biomass steam, for the same heat as in biomass: 350 to 400 t of wood at 80 % boiler efficiency, ~1,120 to 1,280 MWh of heat a year at maturity (about 1.0 million records; the start fleet at its full ~1.5 million needs ~1,750 MWh, and both columns scale with it).

	Electric boiler (~98 %)	Biomass boiler (~80 %)
Price of heat	~3.9 THB/kWh, plus the demand charge	~0.5 to 0.9 THB/kWh at 1.35 to 2 THB/kg delivered (reported market prices, October 2026; no supplier quote yet)
Running cost, mature two shifts	~5.2M to 6.0M THB/yr: 1,140 to 1,310 MWh plus 520 to 625 kW of extra peak demand for the five-press boiler bank (0.8M to 1.0M)	~0.6M to 1.2M THB/yr of fuel, plus fuel handling and ash
Boiler package (utilities CSV)	4.5M to 7M THB for 2 × 500 kg/h	~6M to 10M THB, plus the fuel store
Grid	peak ~950 to 1,330 kW: Schedule 4, 1,250 to 1,600 kVA transformer and deposit	unchanged (~800 to 1,000 kVA)

The electric boiler is the more efficient machine; biomass is by far the cheaper heat. At maturity the fuel saving of ~4.0M to 5.4M THB a year repays the biomass premium in under a year (estimate). Even early, at a quarter of the heat, electric steam costs ~1.6M to 1.8M THB a year (one 500 kg/h module) against ~0.15M to 0.3M of fuel, because the demand charge is set by the boiler's full-power draw, not by its average. Moving electric steam to off-peak hours barely helps: the presses need steam while they run, and the peak window covers 13 of the 16 production hours. The staged electric-first path in biomass is therefore a permitting and fuel-logistics choice, not a cost one.

PV, not solar thermal. Self-consumed PV is worth ~3.7 THB/kWh (weekday daytime at the peak rate, weekends and early mornings at off-peak, Ft included), so the 247 kWp roof saves ~1.2M to 1.3M THB a year and pays back in ~4.5 to 7 years at 25,000 to 35,000 THB/kWp (estimate). It does not lower the demand charge, because the peak window runs to 22:00, long after sunset. Solar thermal loses on every count here: flat-plate and evacuated-tube collectors reach only the 60 to 90 °C that the feedwater heat pump already recovers from the press cooling return; concentrating collectors that could reach 180 °C need strong direct sun, which northern Thailand's haze and burning season do not give; and PV through a heat pump at a COP of ~3 delivers low-grade heat for ~1.2 THB/kWh while also serving every other load. So the roof gets PV throughout and no solar thermal, and feedwater preheat stays with heat recovery.

The battery does not pay through the tariff. Charging off-peak and discharging at peak earns ~1.1 THB/kWh after losses, ~70k THB a year for the 271 kWh stack, and spread over the 13-hour weekday peak window it can hold demand down by only ~20 kW (~30k THB a year) (estimates). Its case is ride-through and outage resilience, not peak shaving.

Water supply

The zero-discharge commitment below governs water leaving the plant. It says nothing about water arriving, and that side is still open: no source has been confirmed for the candidate site — PWA mains, a licensed deep well, or both. That choice drives storage, treatment, and part of the utilities budget.

Estimated demand at mature two-shift operation (16 h/day):

Draw	m³/day
Cooling tower evaporation	6.0
Cooling tower blowdown (4 cycles of concentration)	2.0
Boiler makeup + blowdown (80% condensate return)	1.6
Galvanics rinse, after the recycling below	3.0
Domestic, canteen, showers (25 staff)	2.0
Total	~15, call it ~20 with margin

The cooling tower is over half of it — worth remembering when the heat recovery above is sized, because every kW the feedwater heat pump lifts off the chiller is also water the tower does not evaporate.

Storage is two tanks, not one:

• Fire reserve ~200 m³ — dedicated, never drawn on by process or domestic, per facility security.
• Raw/process ~50 m³ usable (5 m dia × 3 m) — roughly 2.5 days at peak, feeding a softening/RO skid for boiler feedwater and dosing for the tower.

A combined ~250 m³ tank, with the fire volume protected by taking the process suction from a higher level, is cheaper and has a real side benefit: process turnover stops the fire reserve going stagnant. Worth pricing, but only the fire design and the insurer can approve it, so the split above stands as the safe default until they do.

Open items: confirm the source, its yield and its quality (a well needs a licence and a pump test; hardness and iron set the treatment spec), and settle whether racking height pushes the fire reserve past 200 m³ before either tank is ordered.

Zero contaminated water

The reference process schematic shows a conventional open "dirty water" cooling loop. We will not build it that way.

• Cooling (up to ~650 kW and 540 l/min for the five presses, roughly 98% of it mold cooling) will run as a closed loop with a cooling tower/chiller, so process water is recirculated rather than discharged.
• Steam condensate will be recovered and returned to the treated feedwater cycle instead of being dumped.
• The planned in-house galvanics line (silvering and stamper electroforming) involves plating chemistry: silver solutions and nickel baths. This is the hardest part of the zero-discharge commitment. Rinse water will need closed-loop treatment and metal recovery, designed in from the start rather than retrofitted. The stamper back-finisher (Sibert VSF) runs wet too, on a closed loop whose filters collect nickel fines; its spent water and filters take the same route (galvanics and stamper prep).
• Solvent handling (flagged in the site requirements) will be contained and disposed of as controlled waste, never via wastewater.
• Target: no process-water discharge to the local environment. Detailed water balance and treatment design are pending site selection.

Materials

The plant design already includes a PVC recycling loop: an in-house grinder returns trimmings and rejects to the extruder, with the standard feed mix at 80% virgin / 20% recycled compound. Record scrap becomes feedstock, not landfill.

For the virgin compound itself, the preference is local (Thai/regional) PVC sourcing if the quality meets vinyl-record specifications. The current supplier list (2021) is almost entirely European, with one US option; qualifying a local compound would cut shipping distance, cost, and the carbon footprint of the feedstock. European suppliers remain the fallback where quality demands it.