Ethane to Ethylene (G1)

Team G1 Final Report

Authors: Tahir Kapoor, Brandon Muncy, Alex Valdes

Instructors: Fengqi You, David Wegerer

March 13, 2015

Introduction

The goal of this project is to design a process for the manufacture of ethylene from shale gas. Ethylene is a fundamental chemical in the production of various important polymers, including poly(ethylene terephthalate), low density polyethylene, and high density polyethylene. For this reason, ethylene is the most produced organic chemical in the world and demand will soon surpass 200 million metric tons per year.

Market Analysis and Design Basis

The Marcellus shale in the northeastern states contains the largest reserve of natural gas in America. It is estimated that 141 trillion cubic feet of gas reserves are present in the Marcellus shale.6 Gas production in the Marcellus shale was insignificant before 2008, but has rapidly risen to be one of the most important areas in the American energy industry with over 14 billion cubic feet of gas being extracted every day in 2014. As a result of this rapid energy boom in the Marcellus shale region, gas processing infrastructure has not been able to keep up with the amount of gas being extracted and much of the processing that is done to the raw shale gas occurs on refineries located in either the east coast or the gulf coast.

Due to the infant nature of gas processing infrastructure in the Marcellus region, it is very attractive to build a processing plant directly on the Marcellus shale. Eastern Ohio provides a good location for a new large scale gas processing plant due to the presence of several major pipelines (which West Virginia lacks) and favorable taxes. Ohio has a gross receipts tax of 0.26% compared to a 9.99% corporate tax rate in Pennsylvania and a 7.1% rate in New York. Ohio is also a good location for a large capital investment due to generally lax hydraulic fracturing regulations compared to other more progressive states in the Marcellus shale. Stark County is an ideal location within Ohio due to lower county taxes (6.50%) and its close proximity to Pittsburgh, where most existing wells are located. Stark county also has the added benefit of having existing gas pipeline infrastructure running through it, minimizing potential capital expenditure.

Due to the size of the immense reserves in the Marcellus shale and the void of natural gas processing plants, a large volume plant would be demanded to cope with the rising number of shale wells. Current liquefied natural gas (LNG) plants in the northeast can process 60,000 barrels per day (bpd) while production of gas from the Marcellus shale in 2016 is forecast to exceed 650,000 bpd.6 Due to this large discrepancy between projected production and existing capacity, a large gulf coast LNG plant was used for capacity determination (Freeport, Texas LNG terminal will refine up to 2.1 bcf of gas per day). By this comparison and the capability of the market to handle large volumes of ethylene production, the plant should be designed for the processing of 2 billion cubic feet (38 MM kg) of raw shale gas per day. Current use of ethylene is around 156 million tonnes/year worldwide. Targeting around 1% of this market would yield a plant producing around 1.5 million tonnes of ethylene per year, which is also near the size of larger plants in Texas. These large Gulf plants were used because the Marcellus shale region is underdeveloped so a comparison to existing plants in the region would fail to account for forecasted growth in the area.

Currently, a weak energy market threatens production of oil and gas from the Marcellus shale. A supply glut of oil has led to greatly reduced oil prices and a decline in investment in non-traditional oil fields such as shale oil. Higher production costs of shale oil reduce profitability when compared to cheaper drilling in the Middle East. Along with the decline in oil prices, natural gas and refined products such as ethylene have also experience dramatic fall in prices. It is important to consider the instability in oil prices when analyzing the benefit of a large, long term capital investment. Sustained low oil prices will reduce investment in the Marcellus shale region and will decrease gas production volumes. Despite these risks, the large gap in gas production and gas processing capacity in the Marcellus shale indicate that there is a market for a new gas purification plant.

Design Basis

Based on analyzing the current market, our design will be based on the following production targets.

Production Targets

Component	Annual Production (MMkg/Year)
Shale Gas	13,300
Processed Natural Gas	< 11,000
Ethylene	< 1,500

Economic Analysis

Operating Costs

Total operating costs were determined to be $2,122 (MM) by summing together the individual components of operating costs. Both variable operating costs and fixed operating costs were considered.

Fixed Operating Costs

Operating costs were split into fixed and variable operating costs. Fixed operating costs were largely calculated as an annual percentage of capital cost. Maintenance costs, property taxes and insurance, labor cost, management costs, and labor overhead were all included in fixed operating costs. All fixed operating costs were based on design principles in Towler and Sinnott.

Fixed Operating Costs

Cost Component	Cost ($MM)	Reasoning
Maintenance	$62.88	5% of Capital Cost
Property Taxes and Insurance	$25.15	2% of Capital Cost
Environmental Charges	$12.58	1% of Capital Costs
Labor Cost	$1.50	10 Employees per Shift
Management Cost	$0.60	40% of Labor Cost
Labor Overhead	$1.26	60% of Labor and Management costs
Total Fixed Costs	$103.97

Variable Operating Costs

The primary components of variable operating costs consisted of heating and cooling utilities, electricity costs from condensers and pumps, waste disposal costs, and raw material costs. After a heat exchanger network was developed and process heat recovery was optimized, total heating and cooling utility loads were extracted from ASPEN Energy Analyzer. Cost parameters for each type of utility were also estimated using data retrieved from ASPEN Energy Analyzer. Electricity costs were estimated using energy stream data from HYSYS and assuming a cost of electricity of $0.0662 per kW*hr - the average cost of industrial electricity in Ohio.

Utilities Costs

Utilities	Cost ($MM)	Load (kJ/hr)	Cost ($/kJ)
Refrigerant 1 (C2H6)	$39	1.70E+09	0.000002739
Refrigerant 4 (C2H4)	$194	2.70E+09	0.000008531
Water	$2	1.40E+09	2.125E-07
Fired Heat	$68	1.90E+09	0.000004249
100 PSI Steam	$55	3.40E+09	0.0000019
Electricity	$189	1.22E+09	0.0662 ($/kWhr)
Total	$547

The final component of variable operating cost was the cost of raw materials and waste processing. Waste water treatment was assumed to cost $1.5 per metric ton (Towler). Our process inputs consist primarily of raw shale gas but also include water, MEA, and crude oil. The price of water was estimated from industrial water pricing in Ohio and the price of MEA was estimated using industrial suppliers from Alibaba. Raw shale gas costs can vary drastically depending on location, but were estimated using data from Morningstar’s energy observer. Wet gas costs in the Marcellus shale are among the cheapest in america and range from 1-3 dollars per thousand cubic feet of gas. Using the average value of $2 per thousand cubic feet, the cost per kilogram of raw shale gas was calculated.

Raw Material Costs

Raw Material	Cost ($MM)	Cost ($/KG)	Usage (Millions of KG/Year)
Shale Gas	$1,396	0.104	13440
Oil	$66	0.368	184.8
Water	$0.30	0.0007769	$336.00
MEA	$5	1.6	3.36
Waste Disposal	$1	0.0015	644.7
Total	$1,468.30

Estimating Revenues

Due to the extreme volatility in commodities pricing, revenues were not projected to be constant over the lifetime of the plant. Revenues were estimated using current commodities prices and futures from the Chicago Mercantile Exchange (CME). Future revenue estimations are shown in appendix E. An example of revenue calculations using current prices is shown below.

Example Revenue Projections

Product	Revenue	Price($/kg)	Production (Millions of KG/Year)
Sales Gas	$1,557	0.1421	10953.6
Polymer Grade Ethylene	$256	0.1568	1635.48
Propane and Higher	$263	0.3232	812.95
Total	$2,070

Based on these futures, revenue is expected to be approximately $2,900 MM on average between 2017-2026.

Profitability Analysis

Once all cost estimations were completed, a discounted cash flow analysis was performed to examine the economic viability of the process. The discount rate and corporate tax rate used for our analysis was determined by averaging the weighted average cost of capital (WACC) and corporate tax rates for a few large integrated oil and oil refining corporations. All data was retrieved via filings from the Securities and Exchange Commission. (Total S.A. was not included in the tax average due to an unusually high tax rate in 2014)

WACC and Corporate Tax Rates for Publicly Listed Oil Corporations

Company	WACC	Tax Rate
Exxon Mobil	11.08%	41.18%
Chevron	11.09%	36.46%
BP	9.67%	29.99%
Total	8.36%	60.04%
Valero	15.39%	37.29%
Phillips 66	14.96%	33.49%
Average	11.76%	35.68%

Capital costs were depreciated over five years using MACRS depreciation and 1.5% annual inflation was added to operating costs. It was also assumed that the plant would take two years to build, all capital costs would come in the first two years, and production would start in the third year and last 10 years. It is extremely likely that a large scale chemical plant will be in operation for well over 10 years, but due to uncertainties in both commodities prices and future regulation against fossil fuels the model was only projected for 10 years of production.

Economic Analysis Results

Net Present Value ($MM)	$1,206.60
IRR	28.99%
Discounted Payback Period	6 Years

Our initial cost estimations show that our process will be profitable in the long run as shown by a positive net present value and that the discounted payback period will be 6 years. It is very important to note that the cost estimations are extremely sensitive to commodities prices and future energy crises can greatly impact profitability.

Sensitivity Analysis

If natural gas prices prices fall over 11%, the 12 year NPV will become negative. It is important to consider using financial instruments to hedge against commodity price declines and to ensure a positive net present value in a volatile future.