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. The real energy demand sits in the
utilities around it, above all the steam generator (400 kg/h saturated steam
at 10 bar / 180 °C) and the 250 kW cooling system.

- 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 250 kW cooling system; under
  PEA's time-of-use tariff it earns little from peak shaving
  ([grid tariff](#grid-tariff-pea-and-what-it-decides)).
- 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](#grid-tariff-pea-and-what-it-decides)).
- Whole-factory HVAC (continuous temperature, humidity, and PM control, see
  [facility systems](facility-security.md)) 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](scale.md), 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 250 kW cooling load is heat
leaving the press molds, put there almost entirely by the steam, and the
press cooling return exits at ~60 °C. 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`](finance/pea/EN_Electricity_Tariffs_May_2023.pdf)),
still the current schedule on PEA's
[tariff page](https://www.pea.co.th/en/our-services/tariff), and the Ft on
PEA's [Ft page](https://www.pea.co.th/en/our-services/tariff/ft), both
checked 7 October 2026. Plant consumption and demand are this repo's
estimates ([scale](scale.md)).

**Which tariff applies.** At 300 to 750 kW of peak demand 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 busy months could cross
250,000, 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): 200k to 400k
THB for a 500 to 1,000 kVA transformer.

**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, 300 to
450 kW peak) the bill comes to roughly **4.3M to 6.4M THB a year** before
solar, 0.5M to 0.7M of it demand charge (estimate).

**Electric versus biomass steam**, for the same heat as in
[biomass](biomass.md): 350 to 400 t of wood at 80 % boiler efficiency,
~1,120 to 1,280 MWh of heat a year at maturity.

| | 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](biomass.md#fuel-prices-market-check-october-2026), October 2026; no supplier quote yet) |
| Running cost, mature two shifts | **~4.7M to 5.5M THB/yr**: 1,140 to 1,310 MWh plus 200 to 300 kW of extra peak demand (0.3M to 0.5M) | **~0.6M to 1.2M THB/yr** of fuel, plus fuel handling and ash |
| Boiler package ([utilities CSV](finance/utilities-investment.csv)) | 2.5M to 4M THB | 4M to 7M THB, plus the fuel store |
| Grid | peak demand 600 to 750 kW: bigger transformer and deposit | unchanged |

The electric boiler is the more efficient machine; biomass is by far the
cheaper heat. At maturity the fuel saving of ~3.5M to 4.9M THB a year
repays the biomass premium in under a year (estimate). Even early, at a
quarter of the heat, electric steam costs ~1.4M to 1.7M THB a year 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](biomass.md) 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](facility-security.md).
- **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 250 kW, 220 l/min peak, 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](equipment/galvanics.md)).
- 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.