SIMULATION OF GAS DEHYDRATION ON AN FPSO USING ASPEN HYSYS

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SIMULATION OF GAS DEHYDRATION ON AN FPSO USING ASPEN HYSYS

ABSTRACT

Natural gas is an important energy source among other sources of fossil fuels. It is usually produced saturated with water vapor under production conditions. The dehydration of natural gas is very essential in the gas processing industry to remove water vapor. Water vapor in natural gas stream, poses threat to process facilities if the dew point temperature is not properly controlled. Dehydration of natural gas is the process removal of the water that is associated with natural gases. The mixtures of water in natural gas can cause the problems for the production operation, transportation, storage and use of the gas. The four major methods of dehydration are absorption, adsorption, gas permeation and refrigeration. The process of dehydration by using TEG is absorption, involves the use of a liquid desiccant to remove water content from the gas.

The objective of this experiment is to carry out a simulation on TEG dehydration unit using AspenHYSYS process software. This is important in an FPSO since the removal of water from natural gas is necessary before processing, and due to the fact that Natural gas from the reservoir contains large amount of water which can cause several problems to downstream processes and equipment. TEG was used because it has gained nearly universal acceptance as the most cost effective of the glycols due to its superior dew point depression, operating cost and operational reliability. The composition of the natural gas has been provided on a water-free basis, therefore to ensure water saturation it was mixed with water before entering the first unit operation. The units involved in this simulation are; Contractor, Regenerator, Valve, Component splitter, Cooler, Stripper and Splitter, alongside with an adjust logical tool which was used to find the point at which water is just formed (dew point with a temperature of -13.67Oc). At the end of the converged simulation, 89.92 wt% methane was recovered at a flow rate of 9177kg/hr. which might have resulted due to loss of some of the gases at certain stage of the process.

 

 

Table of Contents

CERTIFICATION.. 3

DEDICATION.. 4

ACKNOWLEDGEMENT. 5

NOMENCLATURE. 6

ABSTRACT. 7

CHAPTER ONE. 10

INTRODUCTION.. 10

1.1         BACKGROUND OF STUDY. 10

1.2         DEHYDRATION OF NATURAL GAS. 12

1.3         STATEMENT OF THE PROBLEM… 14

1.4          OBJECTIVES OF THE STUDY. 15

1.5         RESEARCH QUESTIONS. 15

The research question of this project is based on the following; 15

1.6         JUSTIFICATION OF THE STUDY. 15

1.7         SCOPE/LIMITATION OF STUDY. 16

1.8         RESEARCH METHODOLOGY. 16

CHAPTER TWO.. 17

LITERATURE REVIEW… 17

2.2         NATURAL GAS. 18

2.3         PROCESSES IN OFFSHORE PRODUCTION.. 20

2.3.1            SEPARATION.. 21

2.3.2            GAS TREATMENT. 22

2.3.3          INORGANIC CONTENTS. 23

2.3.4          OTHER CONTAMINANTS. 24

2.3.5          COMPRESSION.. 24

2.3.6          LIQUEFACTION OF THE GAS. 24

2.4         WATER TREATMENT. 24

2.5         WATER IN GAS. 25

2.5.1            GAS HYDRATES. 26

2.5.2          PREVENTION.. 26

2.5.3          INHIBITORS. 27

2.6         PROCESSING OF NATURAL GAS. 28

2.6.1          DEHYDRATION OF NATURAL GAS. 28

2.6.2          TYPES OF DEHYDRATION OF NATURAL GAS. 31

2.6.3          COMPARISON OF THE METHODS. 34

2.6.4            GLYCOLS USED FOR DEHYDRATION.. 34

2.7        DRY GAS. 36

2.8         THE GLYCOL GAS DEHYDRATION PROCESS. 38

2.8.1            PROCESS DESCRIPTION (EQUIPMENT). 39

2.8.2          TEG DEHYDRATION UNIT. 44

2.8.3          DEHYDRATION BY USING TRIETHYLENE GLYCOL (TEG). 44

CHAPTER THREE. 47

METHODOLOGY. 47

3.1 Materials used for the simulation. 47

3.2 Component selected for the simulation in Aspen Hysys. 47

3.3 Fluid package used (Thermodynamics property used). 48

3.4 Equipments used. 48

3.5 Simulation procedure. 48

CHAPTER FOUR. 50

RESULT AND DISCUSSION.. 50

CHAPTER FIVE. 54

CONCLUSION AND RECOMMENDATION.. 54

5.1         CONCLUSION: 54

5.2         RECOMMENDATION.. 54

REFERENCES. 55

 

CHAPTER ONE

INTRODUCTION

1.1      BACKGROUND OF STUDY

Natural gas processing is a complex industrial process designed to clean raw natural gas by separating impurities and various non-methane hydrocarbons and fluids to process what is known as pipeline quality dry natural gas (^ Fact sheet: Natural gas processing). Natural gas processing begins at the well head. The composition of the raw natural gas extracted from producing wells depends on the type, depth and location of the underground deposit and the geology of the area. Oil and natural gas are often found together in the same reservoir. The natural gas produced from oil wells is generally classified as associated- dissolved, meaning that the natural gas is associated with or dissolved in crude oil. Natural gas production absent any association with crude oil is classified as “non-associated”.

Natural gas processing plants purify raw natural gas by removing common contaminants such as water, carbon dioxide (CO2 ) and hydrogen sulfide (H2s). Some of the substances which contaminate natural gas have economic value and are further processed or sold. A fully operational plant delivers pipeline-quality dry natural gas that can be used as fuel by residential, commercial and industrial consumers. The raw natural gas must be purified to meet the quality standard specified by the major pipeline transmission and distribution companies. These quality standards vary from pipeline to pipeline and are usually a function of a pipeline system design and the markets that it serves. In general, the standards specify that the natural gas:

  • Be within a specific range of heating value(caloric value) for example, in the united states, it should be about 1035±5% BTU per cubic feet of the gas at 1 atmosphere and 600 (41 MJ ±5% per cubic meter of gas at 1 atmosphere and 15.60 c).

 

  • Be delivered at or above a specified hydrocarbon dew point temperature (below which some of the hydrocarbons in the gas might condense at pipeline pressure forming liquid slugs that could damage the pipeline).

 

  • Dew-point adjustment serves the reduction of the concentration of water and heavy hydrocarbons in natural gas to such an extent that no condensation occurs during ensuing transport in the pipelines.

 

  • Be free of particulate solids and liquids water to prevent erosion, corrosion or other damages to the pipeline.

 

  • Be dehydrated of water vapor sufficiently to prevent the formation of methane hydrate within the gas processing plant or subsequently within the sales gas transmission pipeline. A typical water content specification in the U.S. is that gas must contain no more seven pounds of water per million standard cubic feet (MMSCF) of gas. (Prof. Jon Steiner Gudmundsson)

 

  • Contain no more than trace amounts of components such as hydrogen sulfide, carbon dioxide, mercaptans and nitrogen. The most common specification for hydrogen sulfide content is 0.25 grain H2S per 100 cubic feet of gas, or approximately 4 ppm. Specification for C02 typically limit the content to no more than two or three percent.
  • Maintain mercury at less than detectable limits (approximately 0.001 ppb by volume) primarily to avoid damaging equipment in the gas processing plant or the pipeline transmission system from mercury amalgamation and embrittlement of aluminum and other metals.

 

The natural gas product fed into the mainline gas transportation system must    meet specific quality measures in order for the pipeline grid to operate properly. Natural gas produced at the wellhead, which in most cases contains contaminants and natural gas liquids, must be processed and cleaned, before it can be safely delivered to the high-pressure, long-distance pipelines that transport the product to the consumers. Natural gas that is not within certain specific gravities, pressures, Btu content range, or water content levels will cause operational problems, pipeline deterioration, or can even cause pipeline rupture. Gas processing equipment, whether in the field or at processing/treatment plants, assures that these tariff requirements can be met. While in most cases processing facilities extract contaminants and heavy hydrocarbons from the gas stream, in some cases they instead blend some heavy hydrocarbons into the gas stream in order to
bring it within acceptable Btu levels. Natural gas processing begins at the wellhead. The composition of the raw natural gas extracted from producing wells depends on the type, depth, and location of the underground deposit and the geology of the area. Oil and natural gas are often found together in the same reservoir. Natural gas production absent any association with crude oil is classified as “Non-associated”. Most natural gas production contains, to varying degrees, small (two to eight carbons) hydrocarbon molecules in addition to methane. Although they exist in a gaseous state at underground pressures, these molecules will become liquid (condense) at normal atmospheric pressure. Collectively, they are called condensates or natural gas liquids (NGLs).

1.2      DEHYDRATION OF NATURAL GAS

Natural gas usually contains significant quantities of water vapor. Changes in temperature and pressure condense this vapor altering the physical state from gas to liquid to solid.A dehydration process is needed to eliminate water which may cause the formation of hydrates. Hydrates form when a gas or liquid containing free water experiences specific temperature/pressure

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SIMULATION OF GAS DEHYDRATION ON AN FPSO USING ASPEN HYSYS

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