Air Emission & GHG Estimation from Marib Oil Refinery

A Practical Methodology for Quantifying Air Pollutant and Greenhouse Gas Emissions from Petroleum Refineries in Data Scarce Settings

About this finding: "This finding represents a summary of an air pollutant and greenhouse gas (GHG) assessment undertaken by CORAL for Environmental Services at the request of an investor planning to develop an oil refinery project in Yemen. The investor required a realistic picture of refinery air pollutant and GHG emissions, in terms of pollutant types, emission sources and emission rates, and an indication of how closely such a facility would meet international emission standards, to inform the environmental planning and impact assessment for the proposed facility. The Marib Oil Refinery was selected as a benchmark case study, as it is one of only two operating refineries in Yemen and represents a comparable scale and configuration to the proposed development."

Yemen contributes little to global greenhouse gas emissions, yet it ranks among the nations most vulnerable to climate change. Within its energy sector, petroleum refining is a notable source of hazardous air pollutants and GHG, and one that has historically gone unquantified. Yemen operates only two refineries: the Aden Refinery (170,000 bpd) and the Marib Refinery (10,000 bpd). Both are essential to meeting domestic fuel demand, yet both release a range of air pollutants and GHG whose emission rates have never been systematically estimated and published in the open literature. This finding sets out a defensible methodology for estimating air and GHG emissions from refinery operations where site specific measurement data is limited or absent, using the Marib Oil Refinery as a worked case study. The aim is not only to present results but to demonstrate an approach that environmental practitioners across the region can replicate.

1 The Challenge: Estimating Emissions Without Measured Data

The central difficulty in quantifying refinery emissions in Yemen is the near total absence of credible, site specific emission measurements. Continuous emission monitoring systems are not installed, and historical stack test data does not exist. The assessment therefore drew on internationally recognized and conservative references: the USEPA AP-42 Compilation of Air Emission Factors, the EPA Protocol for Equipment Leak Emission Estimates, IPCC methods for greenhouse gases, and and the World Bank Group Pollution Prevention and Abatement Handbook (1998) for Petroleum Refining. These factors represent average emission rates derived from measurements across many comparable sources and are widely accepted where direct measurement is unavailable.

2 Defining the Emission Source Inventory

The Marib refinery comprises two main processing units, a Crude Distillation Unit and a Catalytic Reforming Unit, together with utilities and tank farm facilities. Based on field data collection and review of facility documentation, including process flow schemes, P&IDs, design bases, material balances and heat balances, the following release points were identified.

Table 1.1: Environmental sources (releases) identified at Marib Refinery

Process Unit	Environmental Sources / Releases
Crude Distillation Unit (CDU)	Emissions from crude heaters to stack; overhead receivers to the flare
Catalytic Reforming Unit (CRU)	Emissions from reformer charge heaters; net gas and off gases to the flare
Utilities	Fugitive emissions from product loading racks
Storage Facilities (Tank Farm)	Fugitive emissions from the storage tanks
All Units	Fugitive emissions from valves, pump seals, the compressor and pipeline fittings; vehicle movements and dust on graded roads

Emission sources fall into two categories that must be treated differently: point sources, which discharge through a defined outlet such as a stack or flare, and fugitive sources, which release diffusely and cannot be captured at a single outlet.

3 Point Source Emissions

Five process heaters operate at the facility, all fired exclusively on natural gas from the Marib field: two crude unit heaters (F-181 and F-182, 16 MMBtu/hr each) and three reformer heaters (H-1 at 20, H-2 at 14 and H-3 at 9 MMBtu/hr). One flare with a routine load of 25,000 kg/day burns the refinery's surplus light gas, comprising reformer net gas (10 percent methane by mass) together with the C2 to C4 light ends of the crude. Emission rates for the five principal pollutants were calculated using AP-42 factors for natural gas combustion and industrial flares, with sulphur dioxide computed by mass balance on a 60 ppm fuel gas sulphur content.

Table 1.2: Emissions from stationary point sources (g/sec)

Unit	NOx	SOx	CO	VOC	PM
Crude Heater F-181	0.198	0.012	0.166	0.011	0.015
Crude Heater F-182	0.198	0.012	0.166	0.011	0.015
Reformer Heater H-1	0.247	0.015	0.208	0.014	0.019
Reformer Heater H-2	0.173	0.010	0.145	0.010	0.013
Reformer Heater H-3	0.111	0.007	0.093	0.006	0.008
Flare	0.424	0.035	2.307	0.873	0.000
TOTAL	1.351	0.090	3.085	0.924	0.070

The flare dominates the CO and VOC point source emissions, a direct consequence of the incomplete combustion inherent to flaring. These findings are consistent with the established emission profiles of comparable refinery equipment globally and point to flare gas recovery and storage tank vapour control as the two priority areas for emission management at this facility.

4 Fugitive Emissions Sources

Fugitive emissions are diffuse releases that escape from equipment and storage rather than through an engineered outlet. They are frequently underestimated, yet at refineries they can represent the largest share of total VOC loss. Storage tank losses were calculated with the full AP-42 Chapter 7.1 equations (standing and working losses) using field measured dimensions, confirmed throughputs and vapour pressures derived from the crude assay; loading rack emissions follow the AP-42 Section 5.2 equation for submerged fill in dedicated normal service; equipment leaks apply the EPA petroleum refinery average emission factors.

Table 1.3: Fugitive VOC emissions

Source	Number of Units	VOC (kg/year)
Fixed roof tanks (gasoline, diesel, LSWR, crude and slop)	10 tanks	614,735
Gasoline loading rack (submerged fill, no VRU)	2 loading racks	93,923
Diesel loading rack (submerged fill, no VRU)	2 loading racks	857
Fuel oil loading rack	2 loading racks	5
Equipment leaks (valves, pump seals, compressor and fittings; counts partly estimated)	437 components	63,466
Total		772,985

Fixed roof tanks account for 79.5 % of this total, loading racks for 12.3 % and equipment leaks for 8.2 %. The tank farm, not the loading racks, is the dominant vapour source: the crude arrives live with its light components still in it and the gasoline is blended to market vapour pressure, so both breathe and displace vapour from fixed roof tanks in a hot desert climate.

5. Greenhouse Gas Inventory

The greenhouse gas inventory covers the operating sources of the refinery, aggregated with the IPCC 100 year global warming potentials adopted under the Kyoto Protocol (Second Assessment Report: methane 21, nitrous oxide 310). The flare is computed by a carbon mass balance on its actual gas composition, a method whose CO2 result holds regardless of how the composition might vary; the methane share of its unburned slip is counted at its full warming potential.

Table 1.4: Greenhouse gas emissions by source, IPCC AR5 GWP100

Source	Gas	Emission	Share
Process heaters	CO2	34,867 t CO2e/yr	55.6%
Flare combustion	CO2	26,813 t CO2e/yr	42.7%
Flare unburned slip	CH4	383 t CO2e/yr	0.6%
Equipment leaks	CH4	377 t CO2e/yr	0.6%
Heaters	N2O	199 t CO2e/yr	0.3%
Flare	N2O	78 t CO2e/yr	0.1%
Heaters	CH4	14 t CO2e/yr	0.0%
TOTAL		62,732 t CO2e/yr	100%

Total emissions from operating sources are 62,732 tonnes CO2 equivalent per year. The carbon intensity of 0.1350 tonnes CO2 equivalent per tonne of crude processed is below the typical global refinery range of 0.15 to 0.25 tonnes per tonne, reflecting the plant's simple topping and reforming configuration and its use of natural gas for process heating.

6 Methodology: Key Assumptions and Data Inputs

Transparency in assumptions is what separates a defensible estimate from a black box figure. Process heaters: all fired on natural gas; AP-42 natural gas factors applied to the fuel firing rate; stack height 26 m and exit velocity 10 m/s from design documents. Flare: height 28.4 m, diameter 0.61 m, capacity 25,000 kg/day; gas properties (molecular weight 45.4 g/mol, heating value 50.1 MJ/kg) derived from the confirmed composition of 10 percent methane with the crude assay light ends; combustion efficiency 98 percent per AP-42; SO2 estimated by sulphur mass balance on 60 ppm fuel gas sulphur. Tanks: full AP-42 Chapter 7.1 equations with assay derived vapour pressures, half full average level and Marib meteorology. Loading: AP-42 saturation factor 0.60 for submerged fill in dedicated normal service. Equipment leaks: EPA refinery average factors on the component inventory.

7 Understanding the Uncertainties

A credible estimate is honest about its limitations. The principal uncertainties are: reliance on generic AP-42 emission factors rather than site specific measured rates; limited operational data for some sources; equipment component counts partly estimated pending a field survey, making the leak figure a likely lower bound; and the 60 ppm fuel gas sulphur premise, pending field confirmation. The approach is deliberately conservative and represents the best available method given the data environment. Where monitoring or stack test data later becomes available, these estimates should be validated and refined.

8 Emission Reduction Opportunities

Two measures stand out. First, fitting internal floating roofs or equivalent covers to the crude and gasoline tanks would eliminate over 95 percent of their vapour losses, around 575 tonnes per year of recoverable product, using mature technology with payback measured in months. Second, recovering the routinely flared gas, whether into the fuel system, through a small recovery compressor or in a gas engine generating around 3 MW of power, would remove most of the flare's 27,274 tonnes CO2 equivalent per year while turning a waste stream into energy. Both measures recover saleable hydrocarbon, so the path to environmental improvement and the path to commercial recovery are the same path.

9 Comparison with World Bank EHS Guidelines

The applicable World Bank Group benchmark at the time of this assessment is the Pollution Prevention and Abatement Handbook (1998), whose Petroleum Refining guideline expresses indicative air emission levels as load per tonne of crude processed. The refinery's emissions were converted to the same basis for direct comparison.

Table 1.5: Refinery air emissions compared with World Bank PPAH (1998) Petroleum Refining guideline, per tonne of crude processed

Pollutant	Marib (kg/t crude)	PPAH typical (range), kg/t	Status
Sulphur oxides	0.006	1.3 (0.2 to 0.6)	Far below guideline
Nitrogen oxides	0.092	0.3 (0.06 to 0.5)	Within range, below typical
Particulate matter	0.005	0.8 (less than 0.1 to 3)	Far below guideline
VOC	1.73	1.0 (0.5 to 6)	Within range, above typical

On the combustion pollutants the refinery performs strongly, sitting far below the guideline figures for sulphur oxides and particulates, a direct result of firing natural gas and processing a sweet crude, and within the range for nitrogen oxides. Volatile organic compounds, at 1.73 kg per tonne of crude, fall within the guideline range of 0.5 to 6 kg per tonne but above the typical value of 1.0, the difference arising almost entirely from the fixed roof tank farm. The Handbook does not rely on a numerical limit alone here: it explicitly calls for minimizing losses from storage tanks and product transfer by vapour recovery systems and double seals, and for leak detection and repair programmes. The storage of live crude and blended gasoline in uncontrolled fixed roof tanks therefore falls short of the good practice the guideline sets out, even where the numerical figure remains within range, and tank vapour control is the clear route to bringing the facility in line with World Bank expectations.

Conclusion

The Marib refinery emits 62,732 tonnes CO2 equivalent per year from its operating sources at an intensity of 0.1350 tonnes per tonne of crude, with 99 % arising from just two sources, the gas fired heaters and the routine flare, and 802 tonnes per year of total site VOC, of which 96 % is fugitive and 77 % escapes from the fixed roof tank farm alone.

This assessment demonstrates that a rigorous, defensible air emission and GHG inventory can be developed for a petroleum refinery even where measured data is scarce, provided the methodology is transparent, the emission factors are internationally recognized and the assumptions are clearly stated. For the Marib refinery, the analysis identifies storage tank vapour control as the dominant fugitive opportunity and flare gas recovery as the principal greenhouse gas opportunity. For operators, regulators and lenders applying World Bank and IFC environmental standards in Yemen and the wider region, this kind of structured estimation provides an essential evidence base, both for environmental compliance and for targeting practical mitigation where it matters most.

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References

1. USEPA AP-42, Compilation of Air Pollutant Emission Factors, Fifth Edition (1995, with supplements): Chapter 1.4 Natural Gas Combustion; Chapter 7.1 Organic Liquid Storage Tanks; Section 5.2 Transportation and Marketing of Petroleum Liquids; Section 13.5 Industrial Flares.

2. USEPA (1995). Protocol for Equipment Leak Emission Estimates, EPA-453/R-95-017.

3. IPCC (1996). Revised 1996 Guidelines for National Greenhouse Gas Inventories.

4. IPCC Second Assessment Report (1995), 100 year global warming potentials as adopted under the Kyoto Protocol.

5. World Bank Group (1998). Pollution Prevention and Abatement Handbook, Part III, Petroleum Refining.

6. American Petroleum Institute (1990). Evaporation Loss from Fixed Roof Tanks, Manual of Petroleum Measurement Standards.