GAS DEHYDRATION USING TRIMETHYLENE GLYCOL (A CASE STUDY OF SHELL, UGHELI)
TABLE OF CONTENT
Title Page………………..i
Certification………….…ii
Dedication………………iii
Acknowledgement……….iv
Table of content……...…v
CHAPTER ONE
INTRODUCTION
1.1 NATURAL GAS DEHYDRATION PROCESSES
1.11 REFRIGERATION
1.12 ADSORPTION
1.13 ABSORBTION
1.2 STATEMENT OF PROBLEM
1.3 AIMS AND OBJECTIVES
1.4 SCOPE AND LIMITATIONS
1.5 METHODOLOGY
1.6 CASE STUDY
CHAPTER TWO
LITERATURE REVIEW
2.1 SURFACE PRODUCTION FACILITIES
2.2 GAS LIQUID SEPARATION
2.3 GAS SWEETENING
2.4 GAS DEHYDRATION
2.5 ORIGIN OF WATER IN NATURAL GAS
2.6. REASONS FOR DEHYDRATING NATURAL GAS
2.7. METHODS OF GAS DEHYDRATION
2.7.1 REFRIGERATION
2.7.2 ADSORPTION DEHYDRATION
2.7.3 ABSORPTION DEHYDRATION
CHAPTER THREE
METHODOLOGY
3.1. BRIEF HISTORY AND LOCATION OF THE UTOROGU GAS PLANT
3.2. FLOW DESCRIPTION OF THE UTOROGU GAS PLANT
3.3 EQUIPMENT DESCRIPTION
3.3.1 The Inlet Manifold
3.3.2 Contactor Column
3.3.3. Glycol Flash Tank
3.3.4. Rich TEG Mechanical Filter
3.3.5. Lean/Rich TEG Exchanger
3.3.6. TEG Reboiler and Still (Stripper) Column
3.3.7. The Reflux Condenser
3.3.8. Lean TEG Circulation Pumps
3.3.9. Dry Gas/Lean Glycol Heat Exchanger
3.4. OPERATIONAL PROBLEMS IN A GLYCOL PLANT
3.4.1 Insufficient Dehydration
3.4.2 Foaming
3.4.3 Pump Failure
3.4.4 Vapourization Loss
3.4.5 Salt Contamination
3.4.6 Corrosion from Acid Gases
3.4.7 Glycol Degradation
3.4.8 Emission Problem
3.5 PRESENTATION OF DATA
3.5.1 INLET GAS TEMPEARTURE
3.5.2 LEAN TEG TEMPERATURE
3.5.3 REBOILER TEMPERATURE
3.5.4 STRIPPING GAS FLOWRATE
3.5.5 LEAN GLYCOL CIRCULATION
CHAPTER FOUR
ANALYSIS AND INTERPRETATION OF RESULTS
4.1 INLET GAS TEMPERATURE
4.2 LEAN TEG TEMPERATURE
4.3 REBOILER TEMPERATURE
4.4 STRIPPING GAS FLOWRATE
4.5 LEAN GLYCOL CIRCULATION RATE
4.6 GLYCOL LOSSES
4.7 SOLUTIONS TO THE OPERATIONAL AND GLYCOL LOSS PROBLEMS IN A GLYCOL PLANT
4.7.1 Insufficient Dehydration in the Absorber
4.7.2 Foaming
4.7.3 Pump Failure
4.7.4 Vapourization Loss
4.7.5 Salt Contamination
4.7.6 Glycol Degradation
4.7.7 Corrosion from Acid Gases
4.7.8 SOLUTIONS TO EMMISSION PROBLEMS
4.7.8.1 Optimizing Glycol Circulation Rate
4.7.8.2 Installation of Flash Tank Separator
4.7.8.3 Electric Pump Installation
4.7.8.4 Optimizing Stripping Gas Rate
CHAPTER FIVE
CONCLUSION AND RECOMMENDATION
5.1 CONCLUSION
5.2 RECOMMENDATIONS
REFERENCES
CHAPTER ONE
INTRODUCTION
Natural gas is a combustible gaseous mixture of gaseous hydrocarbons, very light liquid hydrocarbons, free water, water vapour and other undesirable non – hydrocarbon gaseous and solid compounds found in conventional natural gas reservoirs as non-associated gas (NAG), as associated gas (AG) or as gas condensates.
Associated gas or gas-wellhead-gas is found in contact with oil in the reservoir and is produced with the oil and separated at the casing head or wellhead whereas non- associated gas contains little or no natural gas liquids (oil) at reservoir condition and it is termed dry gas or lean gas if the fluid at the surface still remains gas. However if the surface pressure cause some liquid hydrocarbon to evolve, it is called a wet gas or rich. Condensate occurs not as liquid or gas but as a very dense and high pressure fluid due to its high pressure and high temperature reservoir condition.
Natural gas may also occur in tight sands, tight shales, methane gas occluded in coal, as gas hydrates in geo-pressurized acquifer and as deep gas. These gases are more technologically difficult or more expensive to produce than conventional gas and are termed non- conventional natural gas.
Hydrocarbon majorly contained in the natural gas mixtures are methane and ethane which exist as gaseous components, propane and butane existing as volatile fluid, pentane, small amount of hexanes and heavier components existing as liquid components. Typical non- hydrocarbon which may exist in the gas stream are solid particles, water vapour or free water, mercury, formaldehyde, benzene, toluene, ethyl benzene and xylene (collectively referred to as BTEX), undesirable gases such as carbon oxides, sulfur gases and nitrogen oxides (collectively called acid gases), oxygen, helium and naturally occurring radioactive materials such as radon.
Table 1.0: Typical composition of Natural gas
Name Formula Volume (%)
Methane CH4 >85
Ethane C2H6 3-8
Propane C3H8 1-2
Butane C4H10 <1
Pentane C5H12 <1
Carbon dioxide CO2 1-2
Hydrogen sulfide H2O <1
Nitrogen N2 1-5
Helium He <0.5
Mercury Hg Traces
Benzene C6H6 Traces
Toulene C7H8 Traces
Xylene C6H4(CH3)2 Traces
Natural gas is a fossil fuel composed almost entirely of methane. The composition of natural gas varies depending on the field, formation, or reservoir from which it is extracted. Natural gas which contains acid gases above customer’s specification is termed sour gas while Natural gas containing acid gas below customer’s specification or no acid gas is termed sweet gas.
Natural gas is a fossil fuel formed by either the biogenic or thermogenic degradation of organic matter which has been accumulated over time within the earth’s crust. Biogenic mechanism involves shallow depth and low temperature decomposition of sedimentary organic matter by anaerobic bacterials whereas thermogenic mechanism involves deeper depth and high temperature thermal cracking of sedimentary matter or oil into gas. Natural gas being a fossil fuel is today, one of the most important fuels in our lives as it is the source of energy for household, industrial and commercial use, as well as to generate electricity.
Natural, associated or tail gas usually contains water, in liquid and/or vapour form, at source and/or as a result of sweetening with an acqueous solution. Operating experience and thorough engineering have proved that it is necessary to reduce and control the water content of gas to ensure safe processing and transmission. This is accomplished by the process of dehydration.
1.1 NATURAL GAS DEHYDRATION PROCESSES
Natural gas dehydration is the removal of water or water vapour from the natural gas stream. Free water in natural gas gives rise to difficulties in production, handling and transmission of natural gas. It is therefore necessary that water be removed from the gas stream as soon as possible.
There are several methods of dehydrating natural gas but the most common of these methods are:
(i)Refrigeration
(ii)Adsorption
(iii)Absorption
1.11 REFRIGERATION
This method employs cooling the natural gas to condense the water molecules to the liquid phase with the subsequent injection of inhibitor to prevent hydrate formation.
1.12 ADSORPTION
This is the removal of water from the gas stream by solid materials called desiccants which take in and hold water molecules within themselves by adhesive forces. Several types of solid desiccant used are silica gel, silica-based beads, activated alumina, activated bauxite, membranes and molecular sieves.
1.13 ABSORBTION
This is the process whereby water or water vapour is removed or absorbed from the gas stream by intimate contact with a liquid desiccant. Of all the liquid desiccants, the glycols have proved to be the most effective in current use as they approximate the properties that meet commercial application criteria. The glycol with absorbed water is regenerated and re-circulated into dehydration cycle for further water removal.
Chemically, glycol is an aliphatic organic compound belonging to the group of chemicals referred to as dihydric alcohols (diols). Physically, glycols are similar to water in that, they are colourless, clear and odourless liquids. They however possess greater specific gravity and viscosity than water at all temperatures and are soluble in water.
The four types of glycols that have been successfully used to dehydrate natural gas are;
Monoethylene glycol (MEG) Diethylene glycol (DEG) Triethylene glycol (TEG) Tetraethylene glycol (T4EG)
Triethylene glycol has gained nearly universal acceptance as the most cost effective of the glycols due to superior dew point depression, operating cost and operation reliability.
Among the different gas dehydration processes, absorption dehydration is more economically attractive hence has become the most popular method.
1.2 STATEMENT OF PROBLEM
Gas dehydration is a common process in gas treatment plant because water in the presence of acid compounds in natural gas can cause corrosion; water also combines with hydrocarbons to form hydrates which can block valves and pipelines. During an absorption dehydration process of natural gas using tri-ethylene glycol, an appreciable quantity of glycol could be lost and a significant amount of volatile organic compounds emitted during regeneration which may be as a result of operational faults or inadequate plant design. Excessive loss of glycol may lower the efficiency of the dehydration process consequently increasing the cost of dehydrating the gas. VOCs emissions may raise concern from environmental regulatory bodies.
1.3 AIMS AND OBJECTIVES
This project work is aimed at
1. Analyzing the basic process of gas dehydration using Triethylene Glycol.
2 Studying glycol regeneration process as well as examining the causes of associated glycol loss during the regeneration process with possible solutions proffered.
3. Examining the causes of Volatile organic compounds emission with possible solutions proffered.
1.4 SCOPE AND LIMITATIONS
1. Use of TEG for the dehydration of natural gas.
2. Investigating the Parameters affecting glycol regeneration.
3. Investigating the parameters influencing BTEX emissions.
1.5 METHODOLOGY
The various units of operation of the plant will be studied. Sensitivity analysis of process parameters such as temperature of inlet gas and inlet TEG, in relation to the degree of dehydration and BTEX emissions will be carried out. Previous works on the subject will also be examined.
1.6 CASE STUDY
The Shell Petroleum Development Company (SPDC) gas compression and dehydration plant in Ughelli will be used as case study to achieve the major objectives of this research work.
CHAPTER FIVE
CONCLUSION AND RECOMMENDATION
5.1 CONCLUSION
Results from the analysis carried out shows that glycol losses in the plant is primarily due to:
1. Insufficient Dehydration in the Absorber
2. Foaming
3. Hydrocarbon solubility in TEG solution
4. Vapourization loss
5. Salt contamination
6. Glycol degradation
7. Corrosion from acid gases
8. Overcirculation of stripping gas
Results also show that emissions from the dehydration plant is primarily due to:
1. Glycol overcirculation
2. Absence of Flash Tank Separator (FTS)
3. Use of gas-driven pumps
4. Overcirculation of stripping gas
Considering an excess glycol loss of 356 605litres per annum from the Utorogu gas plant, it is evident that the plant is not running efficiently. The problem can be treated by one or more of the following:
1. Turn-around maintenance of the entire glycol plant system
2 Frequent draining and reclaiming of the glycol so as to prevent dissolved salt from exceeding its maximum allowable concentration.
3 Amine solution should be added to the glycol in the reboiler and still column to provide corrosion protection from the acid gases.
4 The reboiler temperature should always be kept below 4020F so as to prevent thermal degradation of the glycol.
5 Liquid hydrocarbon, salts and solids should adequately be separated from the glycol so as to avoid foaming due to chemical contamination.
6 The temperature of the still column and the reboiler pressure should constantly be monitored to prevent glycol losses due to vapourisation or carry over.
7 The circulation of stripping gas should be optimized.
8 Lean TEG temperature should be optimized so as to prevent glycol loss due to vapourization in the absorber.
The problem of emissions can be treated by the following:
1. Optimizing glycol circulation
2. Flash Tank Separator Installation
3. Installing of Electric Pumps
4. Optimizing stripping gas rate.
5.2 RECOMMENDATIONS
After finishing this study, it is recommended that detailed study should be carried out on the Drizo process of enhanced glycol regeneration which yields up to 99.99%wt glycol. The cost implications as regard to the benefits should be studied to see if it is a GO or NO GO option.
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