Flow Assurance and Production Chemistry

Wellbore and pipeline flow assurance skill covering hydrate prediction, corrosion assessment, wax and scale risk, and chemical inhibitor design.

Important: Flow assurance problems are highly system-specific. Field measurements (fluid samples, corrosion coupons, pigging data) are essential for calibration. Use these equations for risk screening and initial sizing.

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Module 1 — Hydrate Prediction

Hydrate Formation Temperature (Approximate Correlations)

def hydrate_temp_katz(pressure_psia, gas_sg=0.65):
    """
    Approximate hydrate formation temperature using Katz (1945) gravity chart.
    Curve-fit to Katz chart for SG = 0.55–0.80:
    T_hyd (°F) ≈ a + b * ln(P)
    Coefficients for SG = 0.65 (representative Marcellus gas):
      a = -16.5, b = 13.0  (approximate, use chart for design)
    Returns hydrate temperature (°F) at given pressure.
    """
    import math
    # Curve-fit coefficients (SG-dependent; calibrate to actual composition)
    coeffs = {
        0.55: (-22.0, 13.5),
        0.60: (-19.5, 13.2),
        0.65: (-16.5, 13.0),
        0.70: (-13.0, 12.8),
        0.75: (-9.5,  12.5),
        0.80: (-6.0,  12.2),
    }
    # Find nearest SG
    sg_keys = sorted(coeffs.keys())
    sg_use = min(sg_keys, key=lambda s: abs(s - gas_sg))
    a, b = coeffs[sg_use]
    return a + b * math.log(pressure_psia)

Hydrate Subcooling (Driving Force)

def hydrate_subcooling(T_fluid_f, T_hyd_f):
    """
    Subcooling = T_hyd - T_fluid
    Positive subcooling = hydrate formation is thermodynamically favorable.
    > 5°F subcooling: moderate risk
    > 15°F subcooling: high risk — inhibition required
    """
    return T_hyd_f - T_fluid_f

Hammerschmidt Inhibitor Dosage

def hammerschmidt_inhibitor(delta_T_f, inhibitor="methanol"):
    """
    Hammerschmidt (1934): w = delta_T * Mi / (K + delta_T * Mi)
    delta_T_f: required hydrate depression (°F)
    w: weight fraction of inhibitor in aqueous phase
    K: 2335 for methanol, 4000 for ethylene glycol (MEG)
    Mi: molecular weight — 32 for methanol, 62 for MEG
    Returns: weight fraction of inhibitor needed in water phase
    """
    params = {
        "methanol": (2335, 32),
        "meg":      (4000, 62),
        "deg":      (4000, 62),   # approx same as MEG
    }
    K, Mi = params[inhibitor.lower()]
    return (delta_T_f * Mi) / (K + delta_T_f * Mi)

def methanol_injection_rate_gpd(w_inhibitor, water_rate_bpd):
    """
    Volume of methanol to inject per day.
    w_inhibitor: weight fraction from Hammerschmidt
    water_rate_bpd: free water production (bbl/day)
    Returns: methanol injection (gal/day)
    """
    water_mass_lb_day = water_rate_bpd * 42 * 8.34   # gal->lb at ~8.34 lb/gal
    methanol_mass_lb_day = w_inhibitor / (1 - w_inhibitor) * water_mass_lb_day
    return methanol_mass_lb_day / 6.59   # methanol density ~6.59 lb/gal

Hydrate risk conditions — Appalachian Marcellus:

• Wellhead pressure: 1,000–3,000 psia; Temperature: 40–70°F in winter
• Typical hydrate temperature at 1,500 psia, SG 0.65: ~68°F
• Risk highest during early production (high pressure + cold surface equipment)
• Mitigation: methanol injection at Christmas tree or wellhead heating

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Module 2 — CO2 Corrosion

CO2 Partial Pressure

def co2_partial_pressure(total_pressure_psia, co2_mol_frac):
    """
    pCO2 (bar) = y_CO2 * P_total (bar)
    Corrosion risk by pCO2:
      < 7 psia  (0.5 bar): low risk
      7–30 psia (0.5–2 bar): moderate risk
      > 30 psia (2 bar): high risk — corrosion inhibitor required
    """
    p_bar = total_pressure_psia * 0.06895
    return co2_mol_frac * p_bar

de Waard-Milliams Corrosion Rate (1991)

def co2_corrosion_rate(pco2_bar, T_C):
    """
    log10(CR) = 5.8 - 1710/T_K + 0.67 * log10(pCO2)
    T_C:       temperature (Celsius)
    pco2_bar:  CO2 partial pressure (bar)
    Returns:   corrosion rate (mm/year) — bare steel, no inhibitor
    """
    import math
    T_K = T_C + 273.15
    log_cr = 5.8 - 1710.0 / T_K + 0.67 * math.log10(pco2_bar)
    return 10**log_cr

def T_C_from_F(T_f):
    return (T_f - 32.0) / 1.8

Material selection guidance:

CO2 Rate (mm/yr)	Assessment	Typical Response
< 0.1	Low	Carbon steel acceptable
0.1–0.5	Moderate	Corrosion inhibitor or CRA liner
> 0.5	High	13Cr or duplex stainless; inhibitor
> 1.0	Severe	CRA tubing; aggressive monitoring

---

Module 3 — H2S Sour Service

H2S Partial Pressure

def h2s_partial_pressure(total_pressure_psia, h2s_ppm_mole):
    """
    pH2S (psia) = (h2s_ppm_mole / 1e6) * P_total
    NACE MR0175 / ISO 15156 sour service threshold: pH2S > 0.05 psia
    Region 1 (SSC): pH2S > 0.05 psia AND P_total > 65 psia
    """
    return (h2s_ppm_mole / 1e6) * total_pressure_psia

def is_sour_service(p_h2s_psia, p_total_psia):
    """
    Returns NACE MR0175 sour service classification.
    Region 0: Not sour
    Region 1: Sour — SSC risk for susceptible steels
    Region 2: Sour — HIC/SOHIC risk
    """
    if p_h2s_psia < 0.05:
        return "Region 0 — Not sour"
    elif p_h2s_psia >= 0.05 and p_total_psia >= 65:
        return "Region 1 — Sour: SSC risk (use L-80, C-90, or inhibitor)"
    else:
        return "Region 2 — Monitor; low SSC risk but H2S present"

Steel grade restrictions in sour service (NACE MR0175):

Condition	Acceptable	Avoid
pH2S > 0.05 psia	L-80, C-90, C-95, 13Cr	P-110, Q-125
pH2S > 1.5 psia	L-80 type 1, 13Cr alloys	All high-strength grades
Produced water pH < 4	CRA liners, coatings	All carbon steel

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Module 4 — Wax

Wax Appearance Temperature (Approximate)

def wax_appearance_temp_estimate(api_gravity):
    """
    Rough WAT estimate from oil gravity (Dead oil, no dissolved gas).
    WAT correlates with paraffin content and oil API gravity.
    High-paraffin crudes (paraffinic): API 30–45
    WAT typically 70–130°F for Appalachian crude oils
    Use pour point data or laboratory WAT measurement for design.
    Returns: approximate WAT range (°F)
    """
    if api_gravity < 25:
        return (50, 90, "Low WAT, but high viscosity")
    elif api_gravity < 35:
        return (70, 110, "Moderate WAT risk")
    elif api_gravity < 45:
        return (90, 130, "High WAT risk — common Appalachian range")
    else:
        return (40, 80, "Light oil — lower paraffin content")

Wax Inhibition Strategies

Method	Application	Notes
Chemical (PPD/WI)	Continuous injection	Modifies wax crystal structure
Pigging	Gathering system	Mechanical removal
Insulation / heat tracing	Subsea, cold climate	Keeps T > WAT
Hot-oil treatment	Remediation	Dissolves wax deposits
Coiled tubing cleanout	Well intervention	Mechanical removal

---

Module 5 — Scale Prediction

Langelier Saturation Index (CaCO3)

def langelier_saturation_index(pH, Ca_ppm, TDS_ppm, T_f, alk_ppm):
    """
    LSI = pH - pHs   where pHs is saturation pH for CaCO3
    pHs = pK2 - pKsp + pCa + pAlk  (Langelier method)
    LSI > 0: scaling tendency   LSI < 0: dissolving tendency
    Simplified correlation (Carrier 1965):
    pHs = (9.3 + A + B) - (C + D)
    A = log(TDS) - 1
    B = -13.12*log(T_C+273) + 34.55
    C = log(Ca) - 0.4
    D = log(Alk)
    """
    import math
    T_C = (T_f - 32) / 1.8
    A = math.log10(TDS_ppm) - 1.0
    B = -13.12 * math.log10(T_C + 273.15) + 34.55
    C = math.log10(Ca_ppm) - 0.4
    D = math.log10(alk_ppm)
    pHs = (9.3 + A + B) - (C + D)
    return pH - pHs

BaSO4 Ion Product

def baso4_ion_product(Ba_ppm, SO4_ppm):
    """
    IP = [Ba2+][SO42-]  (mol/L)^2
    Ksp(BaSO4) = 1.1e-10 at 25°C
    IP > Ksp -> precipitation risk
    Ba_ppm, SO4_ppm: concentrations (mg/L)
    """
    Ba_mol = Ba_ppm / 137340.0    # mg/L to mol/L
    SO4_mol = SO4_ppm / 96060.0   # mg/L to mol/L
    IP = Ba_mol * SO4_mol
    Ksp = 1.1e-10
    return {"IP": IP, "Ksp": Ksp, "saturation_ratio": IP / Ksp,
            "risk": "HIGH" if IP > Ksp else "LOW"}

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Module 6 — Chemical Inhibitor Selection

Problem	Chemical Type	Typical Dosage	Injection Point
Hydrate	Methanol (MeOH)	0.1–0.3 gal/Mscf	Wellhead / Christmas tree
Hydrate	MEG	10–30% vol in water	Wellhead / subsea umbilical
CO2 corrosion	Imidazoline-based	5–30 ppm continuous	Downhole via capillary
H2S corrosion	Triazine scavenger	0.1–1 ppm H2S	Wellhead
CaCO3 scale	Phosphonate	5–50 ppm	Downhole squeeze or continuous
BaSO4 scale	Phosphonate / DTPMPA	5–20 ppm	Downhole squeeze
Wax	PPD / wax inhibitor	200–1,000 ppm	Continuous tubing

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Output Format

## Flow Assurance Risk Assessment — [Field / Well / Pipeline]
**P (psia):** XXXX | **T range (°F):** XX–XX | **Fluid:** Gas/Oil/Multiphase

### Hydrate Risk
| Location | P (psia) | T (°F) | T_hyd (°F) | Subcooling (°F) | Risk |
|----------|---------|------|------------|----------------|------|
| Wellhead | | | | | |
| Pipeline | | | | | |

**Inhibitor required:** YES/NO | MeOH dose: X gal/Mscf | Water rate: XXX bbl/day

### Corrosion Assessment
| pCO2 (bar) | CR (mm/yr) | pH2S (psia) | Sour? | Recommendation |
|-----------|-----------|-----------|-------|----------------|
| | | | | |

### Scale Risk
| Scale | Ion Product | Ksp | Ratio | Risk Level |
|-------|------------|-----|-------|-----------|
| CaCO3 | LSI: | — | — | |
| BaSO4 | | 1.1e-10 | | |

### Wax Risk: [LOW / MODERATE / HIGH]
WAT estimate: XX–XX°F | Flowing temp at well: XX°F

### Chemical Injection Summary
| Chemical | Dose | Injection Rate | Injection Point |
|---------|------|---------------|----------------|
| | | | |

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Error Handling

Condition	Cause	Action
T_hyd negative	Very low pressure or light gas	Verify pressure input
Hammerschmidt w > 0.5	Very large subcooling	Verify subcooling; consider heating
CR > 5 mm/yr	High pCO2 + high temperature	CRA tubulars required; inhibitor alone insufficient
BaSO4 ratio >> 1	Mixing sulfate and barium water	Segregate source waters; squeeze inhibitor
LSI < -2	Corrosive water (dissolving tendency)	CO2 corrosion likely dominant

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Caveats

• Hydrate temperature from Katz chart is a gas-gravity approximation. CO2, H2S, and heavy components shift the hydrate curve — use NGAS, CSMHYD, or PVTsim for compositional fluids. CO2 forms hydrates at lower temperatures than methane.
• de Waard-Milliams gives bare steel corrosion rate. Protective FeCO3 scale at temperatures above ~140°F can reduce actual rates significantly. The Norsok M-506 model is more rigorous.
• Hammerschmidt equation is valid for w < 0.25 (weight fraction). For higher doses or kinetic inhibitors, use thermodynamic software.
• Scale prediction assumes equilibrium chemistry. Supersaturated conditions can persist kinetically, especially for BaSO4 (very slow nucleation).
• H2S sour service thresholds are for steel selection only. NACE MR0175 / ISO 15156 should be reviewed in full for complete material qualification.