gas processing and ngl extraction

Gas Processing and NGL Extraction: Gas Conditioning

04/05S8

March 2006

44 South Broadway, White Plains, New York 10601, USA Tel: +1 914 609 0300 Fax: +1 914 609 0399

This report was prepared by Nexant, Inc (“Nexant”) and is part of the Process Evaluation Research Planning Program (PERP). Except where specifically stated otherwise in this Report, the information contained herein is prepared on the basis of information that is publicly available, and contains no confidential third party technical information to the best knowledge of Nexant. Aforesaid information has not been independently verified or otherwise examined to determine its accuracy, completeness or financial feasibility. Neither NEXANT, Subscriber nor any person acting on behalf of either assumes any liabilities with respect to the use of or for damages resulting from the use of any information contained in this Report. Nexant does not represent or warrant that any assumed conditions will come to pass. The report is submitted on the understanding that the Subscriber will maintain the contents confidential except for the Subscriber’s internal use. The Report should not be reproduced, distributed or used without first obtaining prior written consent by Nexant. Each Subscriber agrees to use reasonable effort to protect the confidential nature of the Report.

Gas Processing and NGL Extraction PERP 04/05S8

i

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Contents

Section Page

1 Executive Summary ................................................................................................. 1 1.1 INTRODUCTION ......................................................................................... 1

1.1.1 The Gas Chain.................................................................................... 1 1.1.2 Natural Gas Properties ....................................................................... 2 1.1.3 Gas Specification ............................................................................... 3

1.2 GAS CONDITIONING AND TECHNOLOGIES ........................................ 5 1.2.1 Processing Requirements of Natural Gas .......................................... 5

1.3 GAS ECONOMICS....................................................................................... 8 1.4 COMMERCIAL ANALYSIS........................................................................ 9

1.4.1 Commercial Applications of Natural Gas.......................................... 9 1.4.2 Global Natural Gas Market................................................................ 10

2 Introduction.............................................................................................................. 12 2.1 BACKGROUND AND OBJECTIVES ......................................................... 12 2.2 NATURAL GAS TERMINOLOGY ............................................................. 13 2.3 THE GAS CHAIN ......................................................................................... 14 2.4 NATURAL GAS “WELL” PROPERTIES ................................................... 16

2.4.1 Well Gas Composition....................................................................... 16 2.4.2 Well Gas Properties ........................................................................... 17

2.5 GAS SPECIFICATION................................................................................. 18 2.5.1 Sales Gas............................................................................................ 18 2.5.2 CNG Specification ............................................................................. 19 2.5.3 LNG Specification ............................................................................. 19

2.6 DEGREE OF GAS TREATMENT ............................................................... 20 2.6.1 Minimum Condensate Content of Sales Gas ..................................... 21 2.6.2 Condensate and NGL Recovery, Blending and Inert Gas Injection and

Removal ............................................................................................. 21 2.7 PROCESSING REQUIREMENTS OF NATURAL GAS............................ 22

3 Gas Reception and Processing ................................................................................ 24 3.1 INTRODUCTION ......................................................................................... 24 3.2 DEHYDRATION .......................................................................................... 25 3.3 GAS RECEPTION FACILITIES .................................................................. 27

3.3.1 Gas Separators and Slug Catchers ..................................................... 27 3.4 DEW POINT CONTROL.............................................................................. 31

3.4.1 Low Temperature Separation............................................................. 31 3.4.2 Desiccant Absorption......................................................................... 39

3.5 IMPURITY REMOVAL ............................................................................... 46

Contents


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3.5.1 Acid Gas Removal ............................................................................. 46 3.5.2 Mercury Removal .............................................................................. 52 3.5.3 Nitrogen Removal.............................................................................. 52 3.5.4 Helium Removal ................................................................................ 52

3.6 CONDENSATE STABILISATION.............................................................. 54 4 Current Process Technologies ................................................................................ 56

4.1 INTRODUCTION ......................................................................................... 56 4.1.1 Engineering Companies With Track Record in Onshore Gas

Processing .......................................................................................... 56 4.2 GAS RECEPTION TECHNOLOGIES ......................................................... 58 4.3 DEW POINT CONTROL TECHNOLOGIES .............................................. 59

4.3.1 Water Dew Point Control................................................................... 59 4.3.2 Water and Hydrocarbon Dew Point Control...................................... 62

4.4 IMPURITY REMOVAL TECHNOLOGIES................................................ 67 4.4.1 Acid Gas Removal ............................................................................. 67 4.4.2 Mercury Removal .............................................................................. 69 4.4.3 Nitrogen and Helium Removal .......................................................... 71

5 Emerging Technologies ........................................................................................... 75 5.1 DEHYDRATION .......................................................................................... 75

5.1.1 Kinetic Inhibitors ............................................................................... 75 5.2 WATER DEW POINT CONTROL............................................................... 77

5.2.1 Regenerative Desiccants .................................................................... 77 5.3 ACID GAS REMOVAL................................................................................ 78

5.3.1 Membrane Systems............................................................................ 78 5.3.2 Solvent Based Systems ...................................................................... 80 5.3.3 Biological Systems............................................................................. 82

6 Economics ................................................................................................................. 83 6.1 OVERVIEW .................................................................................................. 83 6.2 BASIS OF DESIGN ...................................................................................... 84 6.3 COST OF PRODUCTION BASIS ................................................................ 86

6.3.1 Battery Limits .................................................................................... 86 6.3.2 Utilities and Services ......................................................................... 87 6.3.3 By-Product credit ............................................................................... 87 6.3.4 Pricing Basis ...................................................................................... 88 6.3.5 Gas Shrinkage .................................................................................... 88

6.4 COST OF PRODUCTION ............................................................................ 91 6.4.1 Wellhead Extraction........................................................................... 91 6.4.2 Capital Costs ...................................................................................... 91

Contents


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6.4.3 Cost of Production ............................................................................. 92 7 Commercial Assessment .......................................................................................... 95

7.1 INTRODUCTION ......................................................................................... 95 7.2 COMMERCIAL APPLICATIONS............................................................... 95

7.2.1 Natural Gas ........................................................................................ 95 7.2.2 Gas Condensate.................................................................................. 97

7.3 NATURAL GAS MARKET - GLOBAL OVERVIEW................................ 98 7.3.1 Supply ................................................................................................ 98 7.3.2 Demand .............................................................................................. 100 7.3.3 Demand Growth Projections.............................................................. 100 7.3.4 Trade .................................................................................................. 102

7.4 REGIONAL NATURAL GAS MARKET OVERVIEW.............................. 104 7.4.1 North America ................................................................................... 104 7.4.2 South and Central America................................................................ 104 7.4.3 Europe and Eurasia, including FSU................................................... 105 7.4.4 Middle East ........................................................................................ 106 7.4.5 Africa ................................................................................................. 107 7.4.6 Asia Pacific ........................................................................................ 108

7.5 WORLDWIDE GAS PROCESSING CAPACITY....................................... 110 8 Glossary of Terms .................................................................................................... 111 Appendix Page A Nexant’s ChemSystems Capital Cost Estimates ................................................... A-1

B PERP Program Title Index ..................................................................................... B-1

Contents


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Figure Page

1.1 Gas Transportation Routes......................................................................................... 2 1.2 Natural Gas Drivers ................................................................................................... 9 1.3 Regional Natural Gas Reserves.................................................................................. 10 1.4 Regional Natural Gas Marketed Production .............................................................. 11 2.1 Terminology and Constituents of Natural Gas .......................................................... 13 2.2 Gas Transportation Routes......................................................................................... 14 2.3 Phase Diagram of a Fixed Composition Well Fluid .................................................. 21 2.4 Gas Processing Schematic with NGL Extraction ...................................................... 23 3.1 Hydrate Equilibrium Curve........................................................................................ 26 3.2 Horizontal Separator Vessel....................................................................................... 28 3.3 Vertical Separator Vessel........................................................................................... 29 3.4 Typical “Pipe Type” Slug Catcher Technology......................................................... 30 3.5 Joule Thomson Effect Shown on a Phase Diagram ................................................... 32 3.6 Joule Thomson Plant Flow Scheme with Glycol Injection (Lean Gas)..................... 34 3.7 Joule Thompson Plant Without Glycol Injection....................................................... 35 3.8 Hydrate Separator ...................................................................................................... 36 3.9 Mechanical Refrigeration Plant (Lean Gas) Simplified Flow Scheme...................... 38 3.10 Inability of Mechanical Refrigeration to Enter Two Phase Region for Dew Point

Control For High Pressure Feed Gas ......................................................................... 39 3.11 Glycol Contacting Dehydrogenation Flow Scheme................................................... 41 3.12 Solid Adsorption Schematic....................................................................................... 43 3.13 Loading of Molecular Sieve 5 Å................................................................................ 44 3.14 Split-Stream Amine Process ...................................................................................... 49 3.15 Claus Sulfur Recovery Process .................................................................................. 51 3.16 UOP Mercury Removal and Recovery System.......................................................... 53 3.17 Gas Stabilization (Courtesy of OGCI Publishing)..................................................... 55 4.1 Taylor Forge Harp Type Separator/Slug Catcher ...................................................... 58 4.2 ECOTEG© BTEX Rich Gas Dehydration................................................................. 61 4.3 Drizo Gas Dehydration .............................................................................................. 63 4.4 Sordeco Process Flow Scheme .................................................................................. 64 4.5 IFPEXOL Process for Dehydration and NGL Removal ............................................ 66 4.6 Benfield Process Flow Scheme.................................................................................. 68 4.7 Selexol Solvent Process Flow Scheme ...................................................................... 70 4.8 Costain Double Column Process for Nitrogen Rejection .......................................... 72 4.9 MEHRA Process NRU............................................................................................... 74 5.1 Engelhard-Molecular Gate® Process Schematic ....................................................... 79 5.2 Morphysorb................................................................................................................ 81 7.1 Natural Gas Drivers ................................................................................................... 95 7.2 Regional Natural Gas Reserves.................................................................................. 98 7.3 Regional Natural Gas Marketed Production .............................................................. 99

Contents


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7.4 Gas Reserves to Production ratio ............................................................................... 100 7.5 Regional Natural Gas Consumption .......................................................................... 101 7.6 Historical and Forecast Natural Gas Demand............................................................ 101 7.7 Global Gas Market in 2004........................................................................................ 103 7.8 Global Gas Market in 2010........................................................................................ 103 7.9 Gas Consumption by Sector in the Asia – Pacific Region......................................... 109

Table Page

1.1 Typical Sales Gas Specifications ............................................................................... 3 1.2 Typical LNG Product Specifications ......................................................................... 4 1.3 Licensed Technologies and Products......................................................................... 7 1.4 Utility and Product Costs ........................................................................................... 8 2.1 Typical Well Gas Compositions ................................................................................ 16 2.2 Properties of Well Gas Components.......................................................................... 17 2.3 Typical Sales Gas Specifications ............................................................................... 19 2.4 Typical LNG Product Specifications ......................................................................... 19 3.1 Advantages and Disadvantages of the JT-expansion................................................. 36 3.2 Acid Gas Removal Methods ...................................................................................... 47 3.3 Physical Solvents versus Chemical Solvents ............................................................. 48 3.4 Amine Performance ................................................................................................... 50 6.1 Raw and Sales Gas Composition ............................................................................... 84 6.2 Assumptions Used for Estimating Certain Elements of the Cost of Production ....... 86 6.3 Utility Consumption................................................................................................... 87 6.4 Summary of Raw Material, Utility, Product and Labor Costs................................... 88 6.5 Calculation of Shrinkage............................................................................................ 89 6.6 Calculation of Shrinkage............................................................................................ 90 6.7 Gas Processing Plant Capital Costs ........................................................................... 92 6.8 Cost of Gas Treatment For Sales Gas (Pipeline) Production – Base Case ................ 93 6.9 Cost of Gas Treatment For Sales Gas (Pipeline) Production – Including

NGL/Condensate Co-Product Credit ......................................................................... 94 7.1 Gas/Gas Liquids Processing Capacity and Production .............................................. 110 7.2 Change in Gas Processing Capacity and Throughput Between 1994 and 2004 ........ 110


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Section 1 Executive Summary

1.1 INTRODUCTION

Natural gas is a commonly occurring gaseous hydrocarbon mixture that is either produced in conjunction with crude oil (“Associated Gas”) or in the exclusion of crude oil (“Non-Associated Gas”). Natural gas is a gaseous hydrocarbon mixture which is primarily composed of methane with lesser amounts of paraffin hydrocarbons including ethane, propane and butanes.

Since its discovery, natural gas has become an indispensable fuel resource throughout most of the industrialized world. The value of natural gas lies in the combustion properties of methane, a colorless, odorless gas that burns readily with a pale, slightly luminous flame. Natural gas is the cleanest burning fossil fuel, producing a by-product water vapor and carbon dioxide on combustion. Methane is also a key raw material for making solvents and other organic chemicals. It is an important fuel for the generation of electric power, running residential and industrial equipment. Value is also derived from the hydrocarbon liquids that can be extracted from the gas.

The scope of this report will be limited to “Gas Conditioning” processes and will not cover “Natural Gas Liquids” (NGL’s) extraction for its use in downstream product derivatives. The report therefore aims to provide an overview of various gas conditioning processes available and identify the technologies and licensed processes available on the market today. As gas treatment is highly dependent on well fluids (natural gas from the field) received at a gas processing terminal and on the treated gas specification, a certain set of assumptions will be made on both well gas and sale gas specification for the purpose of the economic analysis. A commercial assessment for natural gas will also be touched upon.

1.1.1 The Gas Chain

There are two main ways of transporting natural gas, by gas pipelines and via low temperature tankers in the form of Liquefied Natural Gas (LNG). The two transportation routes are shown in Figure 1.1.

In pipelines, gas is moved under pressure differentials. For onshore pipelines 70–100 bars is a standard inlet pressure, whereas, for offshore pipelines the pressure at the entry of the pipeline typically ranges from 100–150 bars depending to the distance from the onshore facilities to the gas user. During transportation, pressure drops will occur over long distances and therefore compression stations are sometimes required.

In the form of LNG (Liquefied Natural Gas), natural gas is transported at a temperature close to its boiling point at atmospheric pressure, which is approximately –160°C, as the boiling point of methane is –161.49°C. The gas is liquefied in a liquefaction plant. Before being liquefied, the gas must be treated. The treatment specifications are more severe than in the case of pipeline transport, as it is necessary to avoid any risk of solid-phase formation during the liquefaction process. LNG is transported in a liquid state to overseas receiving terminals. At the reception terminal, LNG is re-gasified and sent to the distribution grid at the specified pressure and caloric value.



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Figure 1.1 Gas Transportation Routes

PP:4119.0005/Sec 1

Well Gas Processing

Liquefaction

Storage/Loading

LNG Carrier Reception/Storage RegasificationExtraction

Well Gas Processing

Liquefaction

Storage/Loading

LNG Carrier Reception/Storage Regasification

Well Gas Processing

Liquefaction

Storage/Loading


Well Gas Processing

Liquefaction

Storage/Loading


(b) LNG Tanker Transfer Route

Well Gas Extraction

Processing

Compression Gas Pipeline

Gas Pipeline

Recompression Reception/Storage

(a) Sales Gas Pipeline Transfer Route

Well Gas Extraction

Processing


Gas Pipeline


Well Gas Extraction

Processing


Gas Pipeline


Well Gas Extraction

Processing


Gas Pipeline



PP: 4119.0005/Sec 1

1.1.2 Natural Gas Properties

Natural gas composition at the field source (well gas) depends on whether it originates from associated or non-associated fields. Comprising mainly of methane, well gas also contain ethane, propane, butane and minor quantities of heavier hydrocarbons. Gaseous non-hydrocarbons such as nitrogen, sulfur compounds, carbon dioxide, helium, trace metals (mercury) and water vapor can also be found in well gas streams.

The single most useful combustion property of natural gas is the Wobbe index or Wobbe number as it is a measure of how a gas will burn. As Wobbe number increases, the rate of energy delivered to a burner increases until a point where there is insufficient time and oxygen for complete combustion to occur. Gas must be treated to ensure that the Wobbe index is maintained within an optimal range for combustion.

Because carbon dioxide and nitrogen do not burn, they reduce the heat value of the gas and therefore are often removed as by-products. When heavy hydrocarbons are removed, they reduce the heat value of gas. These heavy hydrocarbons can in turn be sold as condensate, a co-product of natural gas. Helium is valuable in electronics manufacturing. Hydrogen sulfide is very poisonous and extremely corrosive, which means in the presence of water, it can damage gas equipment and piping, so it must also be removed before the natural gas can be delivered to the pipeline. The water component in well gases can form hydrates (an “ice-like” structure) which under certain conditions can lead to pipeline blockages. Therefore it is necessary to remove water prior to gas transmission.



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1.1.3 Gas Specification

The degree to which natural gas will be treated will depend on its ultimate use. Various gas specifications for pipeline gas, compressed gas and LNG exist and treatment will therefore ensure that the natural gas delivers satisfactory combustion performance for the application. Additional treatment is often required for long distance gas transportation purposes, whether it is by pipeline to convey sales gas or liquefied natural gas (LNG).

Gas conditioned for transmission and distribution via pipelines is regarded as sales gas specification. The characteristics of sales gas can vary dependent on requirements of the gas purchaser and/or contractual obligations imposed to protect the pipeline itself.

Table 1.1 shows typical specifications for gas transmission and distribution systems in France, Italy, UK, Canada, California U.S.A. and Japan.

Table 1.1 Typical Sales Gas Specifications

Country France Italy UK Canada USA Japan UnitsSpecification Limitation (GTN System) (California) SI

Hydrogen Sulphide maximum 7* 6.6 5 6 6 1 to 5 mg/Nm3

Total Sulphur maximum 75 150 50 240 18 8 to 30 mg/Nm3

Sulphur from Mercaptan maximum 16.9 15.5 n/a n/a 7.3 n/a mg/Nm3

Carbon Dioxide maximum 3 3 2 2 3 n/a volume %Oxygen maximum n/a 0.6 n/a 0.4 n/a n/a volume %Water Dew Point maximum n/a - 5 at 70 bar -10 at any pressure 4 lbs/MMscf + 4 lbs/MMscf + ¥ -10 at 80 bar deg CHydrocarbon Dew Point maximum n/a 0 at 1 to 70 bar -2 at 1 to 70 bar -10 up to 55 Bar - 10 at op. Pressure ¥ -1 at 1 to 80 bar deg CGross Calorific Value minimum 990 - 1,160 885 - 1145 1 065 995 1 065 1 090 BTU/scfGross Calorific Value minimum 39-46 35 - 45 42 39 42 43 MJ/m3

* Average over 8 days+ Water content¥ Alliance USA Pipeline

n/a Non AvailableNm3 = normal cubic metres at 0 deg C and 101.325 kPa

The general purpose pipeline gas quality standards do not necessarily serve the needs of engines and vehicles, which operate within much wider ranges of pressure and temperature than conventional gas burning appliances. To accommodate the requirements of NGV engine and vehicle application, a number of international standards have been established, i.e. SAE J1616 and ISO 15403. These will not be discussed within the scope of this study.

LNG specification tends to be more stringent than sales gas specification as it is set for plant operation reasons, particularly for the liquefaction plant. CO2, water and aromatics can freeze on exchanger surfaces (“riming”), reducing efficiency and possibly causing blockages in the heat exchanger. Mercury, a common trace contaminant of gas, attacks aluminum, the favored construction material for low temperature exchangers. Table 1.2 lists the typical specifications on levels of impurities contained in the gas feeding a liquefaction plant.



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Table 1.2 Typical LNG Product Specifications

Component Maximum Limit Hydrogen Sulfide 3-3.5 ppmv Total Sulfur 30 milligrams per standard cubic meter Carbon Dioxide 50 ppmv Mercury 0.01 milligrams per standard cubic meter Water Vapor 1 ppmv Benzene 1 ppmv Pentanes and heavier 0.1 mole percent



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1.2 GAS CONDITIONING AND TECHNOLOGIES

1.2.1 Processing Requirements of Natural Gas

The objective of “Gas Conditioning” is to separate well streams into saleable gas and liquid hydrocarbon products. This involves recovery of the maximum amounts of each component at the lowest overall cost; however the extent of gas conditioning required is dictated by the well stream quality, the end uses of the sales gas and extent of liquid hydrocarbon recovery.

Stated simply, “Gas Conditioning” usually means the remove undesirable components from well streams to reach pre-established specifications prior to processing, pipeline transportation, or liquefaction. This stage typically includes the extraction of impurities and contaminants but can also include the separation of gas from heavier liquid hydrocarbon components using a process known as “Dew Point Control”.

To achieve sales gas quality gas conditioning will include these four basic processes:

Dehydrating the gas to remove condensable water vapor, which under certain conditions might cause hydrate formation

Separation of gas from free liquids such as crude oil, condensate, water and entrained solids

Processing the gas to remove condensable and recoverable hydrocarbon vapors (Dew Point Control)

Treating the gas to remove other undesirable components, such as hydrogen sulfide or carbon dioxide.

Some of these processes can be accomplished in the field, but in most cases, the gas undergoes further processing at a gas treatment facility and/or liquid extraction plant.

It should be noted that the “Gas Conditioning” process is sometimes referred to as “Open Art” design. This pertains to sizing and design of gas conditioning equipment. Typically contractors use API equipment standards, process simulations and with equipment vendor consultations are able to design gas processing facilities which predicates the need to used licensed technologies. Licensed technologies however do exist for gas operations and are mainly for specific unit processes where design has been optimized or proprietary materials (adsorbents, membranes) are used. The specific areas in which process optimization has occurred are listed below:

Gas reception facilities (condensate recovery in a slug catcher)

Gas dehydration and water dew point control

Hydrocarbon dew point control

Acid gas removal (hydrogen sulfide and carbon dioxide)

Nitrogen rejection and

Mercury removal.



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The technologies and licenses for gas operations which are covered in this study can be found in Table 1.3.

Work on process optimization has included increasing control over the gas specification, reduction in energy consumption and waste generation and reduction of capital costs through improved technologies and design. Technology advancements have been seen in the areas of hydrate prevention and dehydration, with the development of kinetic inhibitors such as Gas TreatTM HI and Hydrablock; but also in the area of acid gas removal with the development of proprietary solvent technologies such as the Morphysorb® process and membrane technology such as the Engelhard – Molecular Gate ® which uses Pressure Swing Adsorption technology for the removal of nitrogen and carbon dioxide. Such technologies and technology advancement are detailed in Section 5 of this report.



7

Q106_00101.0005.4119

Ta

ble

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Tec

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Pr

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Prod

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quipm

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catch

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is be

twee

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have

a life

time o

f 3-5

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s and

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cle

time d

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on ap

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a Gel

UOP,

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ve

mater

ial. S

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el de

hydr

ation

can a

lso be

sold

as pa

rt of

a pac

kage

for

exam

ple by

NAT

CO, B

echte

l, Petr

eco K

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as P

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tions

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ratio

n con

dition

s exis

t (de

pend

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n fee

d con

dition

s).

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nera

tion t

empe

ratur

e is a

ppro

ximate

ly 20

0 o C. S

ilica g

el ha

s a

lifetim

e of 3

-5 ye

ars b

ut un

der c

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n app

licati

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nown

to

last 1

0-15

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s. Cy

cle tim

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appli

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ith hi

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om th

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at 20

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rizo

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sed b

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sern

at IF

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oup

Tech

nolog

ies an

d OPC

Driz

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ct be

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n ‘we

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d gas

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lution

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, TEG

or

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ne gl

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in an

abso

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roce

ss is

used

to re

move

wa

ter an

d aro

matic

s fro

m na

tural

gas s

tream

s.

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proc

ess i

s typ

ically

used

for w

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ew po

int de

pres

sion o

f up t

o 180

o F

(80 o C)

and i

s said

to be

comp

etitiv

e at w

ater d

ew po

int be

low -3

0o C.

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ol pu

rity as

high

as 99

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t% ca

n be a

chiev

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Licen

sed b

y She

ll Glob

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lution

Int

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tiona

l B.V

. in co

-ope

ratio

n wi

th En

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rd

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bed a

bsor

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proc

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) app

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pres

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drop

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trea

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in ov

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nits w

orldw

ide.

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lic

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rose

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p Te

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ses m

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ve w

ater f

rom

natur

al ga

s stre

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pans

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echn

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or m

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nical

refrid

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s us

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ns of

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l (con

dens

ate ex

tracti

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NGL

re

cove

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n with

capa

cities

of up

to 35

0 MMS

FCD.

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pr

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s can

achie

ve w

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int of

arou

nd -3

0 o C an

d hyd

roca

rbon

de

w po

int do

wn to

- 10

0 o C at

stand

ard p

ress

ure.

Acid

Gas R

emov

al- B

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ldLic

ense

d by U

OPSo

lvent

extra

ction

meth

od us

ing a

solve

nt ba

sed o

n 30%

potas

sium

carb

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8

Q106_00101.0005.4119

1.3 GAS ECONOMICS

This study aims to determine the cost of conditioning well gas to sales gas specification. A feed gas composition, pressure and temperature were chosen based on Nexant’s industry knowledge and a basic process was chosen to meet hydrocarbon dew point specification of -5oC, High Heating Value higher than 950 Btu/scf with 99.9 percent acid gas removal.

This basic process comprises gas reception facilities (which includes slug catcher, bulk condensate separation and filtration of particles and fines); stabilisation of condensate using LP separation; an amine (MDEA) unit for selective acid gas removal; a sulphur recovery unit with tail gas treatment for disposal of the resulting sour gas; gas cooling; water removal by TEG contacting; and finally hydrocarbon dew point control by mechanical refrigeration to meet dew point specifications.

Process simulation allowed the evaluation project capital costs and utility consumption for a 650 MMCFD plant capacity. 650 MMSCFD was chosen as the base case for this analysis since this represents a world scale single train gas processing facility, such as the one currently being built in the Middle East.

Average wellhead extraction, utility and condensate product costs for early 2008; planned start date of the project; were used to evaluate the cost of production of sales gas, as shown in Table 1.4.

Table 1.4 Utility and Product Costs (Middle East, 2008)

Middle EastProduct PricesCondensate $/ton 30

UtilitiesPower $/MWh 40.5LP Steam (50 psi) $/Ton 4.3MP Steam (200 psi) $/Ton 4.6

LaborLaborers $/Year 7 200Foremen $/Year 30 700Supervisors $/Year 75 300

The cost of producing sales gas was estimated at US$0.54 per million Btu based on a project Return on Investment (ROI) of ten percent. This cost reduced to US$0.43 per million Btu with the addition of revenues from the produced liquid hydrocarbon stream.



9

Q106_00101.0005.4119

1.4 COMMERCIAL ANALYSIS

1.4.1 Commercial Applications of Natural Gas

Natural gas can be utilized as an energy source (for power generation, liquid fuel generation as GTLs and/or space heating) or as a petrochemical feedstock particularly for methanol and ammonia production. This is demonstrated in Figure 1.2.

Figure 1.2 Natural Gas Drivers

Exports (LNG/Pipeline)

Liquid Fuels (GTL/MTBE/DME/Others)

Local FuelValue/Power

Ammonia (Fertilizers/Others)

Methanol (Formaldehyde/Acetyls/Others)

Methanol (MTO/MTP)

Energy UsesEnergy Uses

Chemical UsesChemical Uses

NaturalGas

NGLs forPetrochemicals

ProcessingFacility

ProcessingFacility Methane

PP: 4119.0005/Sec_1

Natural gas is transported to consumers by pipeline, or in the case of more distant users, in liquid form as liquefied natural gas, LNG. The gas is cooled to –160oC at which temperature it becomes a liquid and is transported in insulated tankers to distant markets. Compared to crude oil and petroleum products, natural gas is relatively expensive to transport by pipeline or liquefied and transported in dedicated LNG carriers.

Associated with natural gas conditioning, condensate is produced as a co-product consisting of pentanes and heavier components. By virtue of it being a liquid, condensates are easier to transport as compared to natural gas. Condensates typically have very low sulfur levels in comparison with most crude oils and typically have API gravity of greater than 50. Condensates generally have four possible disposal options, which are summarized individually below:

Sale to a Steam Cracker as Ethylene Feedstock Sale to a Refiner On-Site Splitting and Sale of Straight Run Cuts Third Party Splitting and Sale of Straight Run Cuts



10

Q106_00101.0005.4119

1.4.2 Global Natural Gas Market

Global natural gas reserves have almost doubled over the last 20 years. The evolution of proved gas reserves has been dynamic in several regions, where significant increases have been recorded: in the Former Soviet Union (FSU) gas reserves increased by more than 50 percent, those in Africa registered an increase of 125 percent and the reserves in the Middle East increased by more than 160 percent. The breakdown of natural gas reserves by region for 2004 is shown in Figure 1.3.

Figure 1.3 Regional Natural Gas Reserves (tcf, at the end of 2004)

0

500

1000

1500

2000

2500

3000

NorthAmerica

South &CentralAmerica

Europe &Eurasia

(ExcludingFSU)

FormerSovietUnion

MiddleEast

Africa AsiaPacific

Trilli

on cu

bic f

eet

XL: 4119.0005 Sec_1

The greatest concentration of natural gas reserves are in the Middle East and the Former Soviet Union, which together account for more than 72 percent of the global world reserves.

Global gas reserves, however, are not matched to global gas production, for example, North America, which has one of the lowest overall reserves currently, actually has the highest marketed production for any region (refer Figure 1.4).



11

Q106_00101.0005.4119

Figure 1.4 Regional Natural Gas Marketed Production (tcf, at the end of 2004)

0

5

10

15

20

25

30

NorthAmerica


Europe &Eurasia

(ExcludingFSU)

FormerSovietUnion

MiddleEast

Africa AsiaPacific

Trilli

on cu

bic f

eet

XL: 4119.0005 Sec_1

Out of a total marketed production of almost 95 tcf (2,700 BCM) in 2004, North America represents 28 percent, South and Central Americas represent 5 percent, Europe 12 percent, FSU 28 percent, Middle East 10 percent, Africa 5 percent and Asia 12 percent. Production of natural gas is therefore greatest in North America, where demand is highest, followed by the FSU then Europe and Asia.

In general terms, the mismatch between reserves and production rates is in part a reflection of the high cost of transporting gas. This means that gas reserves relatively close to markets are most economic to develop and are preferentially produced. Thus, with the exception of FSU, the regions of highest consumption, North America and Europe, have the lowest reserves to production ratio.


12

Q106_00101.0005.4119

Section 2 Introduction

2.1 BACKGROUND AND OBJECTIVES

Natural gas is a commonly occurring gaseous hydrocarbon mixture that is either produced in conjunction with crude oil (“Associated Gas”) or in the exclusion of crude oil (“Non-Associated Gas”). Natural gas is a gaseous hydrocarbon mixture which is primarily composed of methane with lesser amounts of paraffin hydrocarbon family, including ethane, propane and butanes. Natural gas also contains a degree of impurity that may need to be removed.

Since its discovery, natural gas has become an indispensable fuel resource throughout most of the industrialized world. The value of natural gas lies in the combustion properties of methane, a colorless, odorless gas that burns readily with a pale, slightly luminous flame. Natural gas is the cleanest burning fossil fuel, producing as a by-product water vapor and carbon dioxide on combustion. Methane is also a key raw material for making solvents and other organic chemicals and an important fuel for the generation of electric power and running residential and industrial equipment. Value is also derived from the hydrocarbon liquids that can be extracted from the gas.

This scope of this report will be limited to “Gas Conditioning” processes and will not cover “Natural Gas Liquids” (NGL’s) extraction for its use in downstream product derivatives. The report therefore aims to provide an overview of various gas conditioning processes available and identify the technologies and licensed processes available on the market today. As gas treatment is highly dependent on well fluids (natural gas from the field) received at a gas processing terminal and on the treated gas specification, a certain set of assumptions will be made on both well gas and sale gas specification for the purpose of the economic analysis.



13

Q106_00101.0005.4119

2.2 NATURAL GAS TERMINOLOGY

Natural gas is produced as a mixture of hydrocarbons and impurities from underground reservoirs through wells that have been drilled for that purpose. This mixture is then treated to remove the impurities (expanded upon in Section 3 of this study) and render the residual gas to processing or pipeline specification. Gas can be further processed to extract specific hydrocarbon fractions and this is referred to as “Natural Gas Liquids” recovery.

The term “Natural Gas Liquids” (NGL) as applied in this report refers to the hydrocarbon components heavier than methane contained in natural gas. They include ethane, propane, butanes, pentanes and heavier hydrocarbons as shown in Figure 2.1.

Figure 2.1 Terminology and Constituents of Natural Gas

Methane

Ethane

PropaneButanes

Pentanes and heavier fractionsalso referred to as:

C5+Pentanes plusNatural gasolineCondensate

Non Hydrocarbonse.g. water, carbon dioxide etc.

LNG =- Liquefied Natural Gas NGL = Natural Gas Liquids

NaturalGas

ex well

LPG

NGL

PP:4119.0005/Sec 2

Propane and butane can be extracted from natural gas and sold separately. Liquefied petroleum gas (LPG), which is a mixture of propane and butane, is a common substitute for natural gas in rural areas not served by gas pipelines.

Natural gas with high content of heavy hydrocarbon can be categorized as “rich” or “wet” gases, whilst those having low heavy hydrocarbon content are referred to as “lean” or “dry” gas. Natural gas containing a high content of hydrogen sulfide and carbon dioxide is termed “sour gas” and gases with low hydrogen sulfide are termed “sweet”.

LPG= Liquefied Petroleum Gas NGL= Natural Gas Liquids



14

Q106_00101.0005.4119

2.3 THE GAS CHAIN

Natural gas is a dilute form of energy when compared to oil. At standard conditions (15°C, 101.325 kPa), 1 ton of gas occupies a volume around 1,350 m3

whereas 1 ton of oil occupies a volume slightly higher than 1 m3

according to its specific gravity. On an energy equivalency basis, 1 barrel of oil is approximately equivalent to 6000 cubic feet of gas (or about 170 m3 at standard conditions).

It means that for the same energy, natural gas is more difficult and costly to transport than oil, especially for overseas routes. There are two main ways of transporting natural gas, by gas pipelines and via low temperature tankers in the form of Liquefied Natural Gas (LNG). The two transportation routes are shown in Figure 2.2.

Figure 2.2 Gas Transportation Routes

PP:4119.0005/Sec 2

Well Gas Processing

Liquefaction

Storage/Loading


Well Gas Processing

Liquefaction

Storage/Loading


Well Gas Processing

Liquefaction

Storage/Loading


Well Gas Processing

Liquefaction

Storage/Loading


(b) LNG Tanker Transfer Route

Well Gas Extraction

Processing


Gas Pipeline



Well Gas Extraction

Processing


Gas Pipeline


Well Gas Extraction

Processing


Gas Pipeline


Well Gas Extraction

Processing


Gas Pipeline



In pipelines, gas is moved under pressure differentials. For onshore pipelines 70–100 bars is a standard inlet pressure, whereas, for offshore pipelines the pressure at the entry of the pipeline typically ranges from 100–150 bars depending to the distance from the onshore facilities. During transportation, pressure drops will occur over long distances and therefore compression stations are sometimes required.



15

Q106_00101.0005.4119

In the form of LNG (Liquefied Natural Gas), natural gas is transported at a temperature close to its boiling point at atmospheric pressure, which is approximately –160°C, as the boiling point of methane is –161.49°C. The gas is liquefied in a liquefaction plant. Before being liquefied, the gas must be treated. The treatment specifications are more severe than in the case of pipeline transport, as it is necessary to avoid any risk of solid-phase formation during the liquefaction process. LNG is transported in a liquid state to overseas receiving terminals. At the reception terminal, LNG is re-gasified and sent to the distribution grid at the specified pressure and caloric value.

In both cases, gas transportation involves heavy and expensive infrastructure, which results in rather rigid ties between the producer and the consumer. This is the reason why the different steps involved form what is called a natural gas value chain.



16

Q106_00101.0005.4119

2.4 NATURAL GAS “WELL” PROPERTIES

2.4.1 Well Gas Composition

The composition of natural gas at the field source (well gas) depends on the type of reservoir from which it originates. Well gas is mainly composed of methane, ethane, propane, and butane. In addition, it usually contains minor quantities of heavier hydrocarbons and varying amounts of gaseous non-hydrocarbons such as nitrogen, carbon dioxide, and hydrogen sulfide. Typical compositions are given in Table 2.1.

Table 2.1 Typical Well Gas Compositions

Gas Source Non Associated Gas Associated Gas

Example number 1 2

Hydrogen Sulphide 0.6 0.1Carbon Dioxide 0.2 1.0Nitrogen 0.6 1.0Methane 92.0 79.0Ethane 3.5 7.0Propane 1.4 5.0Iso - Butane 0.4 0.6normal Butane 0.3 1.3Iso - Pentane 0.2 1.0normal Pentane 0.1 0.8Hexane plus 0.7 3.2Total 100.0 100.0

Calorific Value (Btu/scf) 1101 1334Wobbe Index (Btu/scf) 1395 1500

(compositions in mole percent)

The Wobbe index or Wobbe number is the most useful single measure of how a gas will burn. The Wobbe index is a calculated number – the calorific value of the gas divided by the square root of relative density i.e. CV/√RD where CV is the calorific value and RD is the density of a gas relative to air. The relative density of a gas will affect how quickly a gas will flow through a burner. As Wobbe number increases, the rate of energy delivered to a burner increases until a point where there is insufficient time and oxygen for complete combustion to occur. Gas must be treated to ensure that the Wobbe index is maintained within an optimal range for combustion.



17

Q106_00101.0005.4119

Often natural gas also contains non hydrocarbon impurities such as nitrogen, sulfur compounds (hydrogen sulfide and mercaptans), carbon dioxide, helium, trace metals (mercury) and water vapor. Because carbon dioxide and nitrogen do not burn, they reduce the heat value of the gas and therefore are often removed. Helium is valuable in electronics manufacturing and can also be removed. Hydrogen sulfide is very poisonous and can be lethal in very low concentrations. Further as hydrogen sulfide is also extremely corrosive, it can damage the tubing, fittings and valves in the gas wells and surface facilities, so it must be removed before the natural gas can be delivered to the pipeline.

Quantities of NGL contained in the natural gas will be dependent on the type of reservoir from which it originates. The highest concentration of NGL’s is found in rich associated gas streams.

2.4.2 Well Gas Properties

Chemical and physical properties for natural gas components are shown in Table 2.2.

Table 2.2 Properties of Well Gas Components

ComponentMolecular

WeightSpecific Gravity

(g/mole) (Btu/scf) (MJ/scm) (oF) (oC) (Air = 1)

Carbon Dioxide 44.0 nil nil -109.3 -78.5 1.52Nitrogen 28.0 nil nil -320.6 -195.9 0.97Hydrogen Sulphide 34.1 637.1 23.7 -76.4 -60.2 1.18Methane 16.0 1010.0 37.6 -258.9 -161.6 0.55Ethane 30.1 1769.7 65.9 -127.7 -88.7 1.04Propane 44.1 2516.1 93.8 -43.8 -42.1 1.52iso-Butane 58.1 3251.9 121.2 10.9 -11.7 2.01normal-Butane 58.1 3262.3 121.6 31.1 -0.5 2.01iso-Pentane 72.2 3999.9 149.0 82.2 27.9 2.49normal-Pentane 72.2 4008.9 149.4 97.0 36.1 2.49normal-Hexane 86.2 4755.9 177.2 155.7 68.7 2.98

Gross Calorific Value Boiling Point



18

Q106_00101.0005.4119

2.5 GAS SPECIFICATION

The natural gas will be treated and processed to deliver satisfactory combustion performance dependent on its ultimate use and sales gas specification, which may in fact vary upon location. Additional treatment is often required for long distance gas transportation purposes, whether it is by pipeline to convey sales gas or liquefied natural gas (LNG). Various gas specifications for pipeline gas, compressed gas and LNG will be described below.

2.5.1 Sales Gas

Gas conditioned for transmission and distribution via pipelines to gas purchaser is sometimes referred to as sales gas specification. The conditioning and treatment of natural gas may be necessary so that the gas has the necessary characteristics and can be efficiently utilized by end users. Additionally, certain gas specification may be imposed contractually or legally to protect the pipework itself.

The sales gas specification can be divided into three categories:

Combustion Properties: The combustion properties can be described by the Wobbe Index and other parameters like SI (Soot index), ICF (Incomplete Combustion Factor) and Hydrogen content of the gas. Such parameters are safety related.

Gross Calorific Value (GCV): The billing process of gas is based on its gross calorific value, i.e. gas priced in $/MMBTU. The limitation on the Gross Calorific value of gas that can be distributed in certain areas can arise from billing practice and legal framework. These practices have been developed to safeguard consumer interests. Billing problems may arise mainly when two or more sources of gas managed possibly by two or more different suppliers are feeding the same distribution network. An additional consideration in setting the GCV range is that a high GCV reduces the gas transportation capacity and may result in additional investment being required.

Level of Gas Treatments: Concentration hydrogen sulfide, sulfur dioxide, COS, mercaptans, oxygen, carbon dioxide, nitrogen, and other impurities are limited. Hydrocarbon dew point and water dew point also need to be controlled in order to meet sales gas specification. The contractual and legal component ranges differ in the various countries mainly for historical reasons but might, given the evolution of technology, be aligned more closely without compromising on safety.

The required sales gas quality often dictates the processing requirements of a given raw gas stream. Sales gas specifications differ according to the requirements of the gas purchaser.

Table 2.3 shows typical specifications for gas transmission and distribution systems in France, Italy, UK, Canada, U.S.A. (California) and Japan.



19

Q106_00101.0005.4119

Table 2.3 Typical Sales Gas Specifications

Country France Italy UK Canada USA Japan UnitsSpecification Limitation (GTN System) (California) SI

Hydrogen Sulphide maximum 7* 6.6 5 6 6 1 to 5 mg/Nm3

Total Sulphur maximum 75 150 50 240 18 8 to 30 mg/Nm3

Sulphur from Mercaptan maximum 16.9 15.5 n/a n/a 7.3 n/a mg/Nm3

Carbon Dioxide maximum 3 3 2 2 3 n/a volume %Oxygen maximum n/a 0.6 n/a 0.4 n/a n/a volume %Water Dew Point maximum n/a - 5 at 70 bar -10 at any pressure 4 lbs/MMscf + 4 lbs/MMscf + ¥ -10 at 80 bar deg C

Hydrocarbon Dew Point maximum n/a 0 at 1 to 70 bar -2 at 1 to 70 bar -10 up to 55 Bar - 10 at op. Pressure ¥ -1 at 1 to 80 bar deg CGross Calorific Value minimum 990 - 1,160 885 - 1145 1 065 995 1 065 1 090 BTU/scf

Gross Calorific Value minimum 39-46 35 - 45 42 39 42 43 MJ/m3

* Average over 8 days+ Water content¥ Alliance USA Pipeline

n/a Non Available

Nm3 = normal cubic metres at 0 deg C and 101.325 kPa

2.5.2 CNG Specification

The general purpose pipeline gas quality standards do not necessarily serve the needs of engines and vehicles, which operate within much wider ranges of pressure and temperature than conventional gas burning appliances. To accommodate the requirements of NGV engine and vehicle application, a number of international standards have been established, i.e. SAE J1616 and ISO 15403. These will not be discussed within the scope of this study.

2.5.3 LNG Specification

LNG specification tends to be more stringent than sales gas specification as it is set for plant operation reasons, particularly for the liquefaction plant. CO2, water and aromatics can freeze on exchanger surfaces (“riming”), reducing efficiency and possibly causing blockages in the heat exchanger. Mercury, a common trace contaminant of gas, attacks aluminum, the favored construction material for low temperature exchangers. Table 2.4 lists the typical specifications on levels of impurities contained in the gas feeding a liquefaction plant.

Table 2.4 Typical LNG Product Specifications

Component Maximum Limit Hydrogen Sulfide 3-3.5 ppmv Total Sulfur 30 milligrams per standard cubic meter Carbon Dioxide 50 ppmv Mercury 0.01 milligrams per standard cubic meter Water Vapor 1 ppmv Benzene 1 ppmv Pentanes and heavier 0.1 mole percent



20

Q106_00101.0005.4119

2.6 DEGREE OF GAS TREATMENT

This section (as will the remainder of the report) will be limited to conditioning of natural gas to achieve sales gas specification. The level of gas treatment is dependent on one or more of the sales gas specifications on:

Gross Calorific Value

Wobbe Index

Hydrocarbon Dew Point.

Gross calorific value refers to the energy released when the gas is burnt under a given set of standard conditions. Wobbe Index (WI) is an important parameter describing the burning characteristics of the gas. The calorific values for individual hydrocarbon components are listed in Table 2.2. Typically the gross calorific value increases with molecular weight. Consequently, the greater the amount of liquid hydrocarbons (or condensate) that remain in the sales gas, the higher its heating value. Further as sales gas can sometimes be priced based on its calorific valve there is clearly a benefit in leaving heavier hydrocarbons within the sales gas.

However leaving the heavier hydrocarbons in the gas has their disadvantages. Frequently, the temperature of gas in a pipeline can fall significantly below the entry temperature therefore causing the gas stream to condense. This liquid drop-out must be avoided as it reduces the reliability of gas quality and causing possible damage pipeline distribution network and end-user assets. Hence, a limit is usually imposed on the hydrocarbon dew point, i.e. the point at which liquid begins to condense from the gas.

Heavier hydrocarbons (C5+) condense at higher temperatures, at a given pressure, and a maximum limit on hydrocarbon dew point temperature restricts the quantities of condensates that can be left in the gas. The condensation behavior of heavier hydrocarbons is illustrated in Figure 2.3 showing the phase envelopes of a raw natural gas stream and a processed sales gas stream. The effect of removing condensate from the raw gas stream is to collapse the phase envelope such that the resultant sales gas stream satisfies the hydrocarbon dew point limit, in this case 0oC.



21

Q106_00101.0005.4119

Figure 2.3 Phase Diagram of a Fixed Composition Well Fluid

Temperature

Pressure

Feed Gas Phase Envelope

Sales Gas Phase Envelope

Note: Sales gas cricondentherm < hydrocarbon dew point limit

Hydrocarbon Dew Point

0oC

PP:4119.0005/Sec 2

Any of the three specifications, i.e. heating value, Wobbe Index, and hydrocarbon dew point, can limit the maximum quantity of NGLs in the sales gas depending on the specification limits and the composition of the gas.

2.6.1 Minimum Condensate Content of Sales Gas

The quantity of condensate that can be extracted from the raw gas for economic reasons can be limited by minimum limits placed on the sales gas heating value and/or Wobbe Index. This can be particularly restrictive if non-combustible inerts such as nitrogen and or carbon dioxide are present in significant quantities. These components dilute the hydrocarbon content and therefore lower the heating value of the gas mixture.

2.6.2 Condensate and NGL Recovery, Blending and Inert Gas Injection and Removal

A raw gas that is “rich” in condensate and NGL can be made to achieve the sales gas heating value specification by removing the appropriate quantity of heavy hydrocarbons. Alternatively, it can be blended with another “lean” gas stream, which has a lower heating value, such that the heating value of the aggregate stream falls within the allowed limits. Blending sales gas is often subject to contractual arrangements. If a lean gas stream is unavailable, nitrogen can be injected to dilute the rich gas although establishing a nitrogen supply for this purpose can be expensive.

While blending and nitrogen injection may achieve the heating value specification, the presence of heavy NGL components (e.g., pentanes plus) may still infringe the hydrocarbon dew point limit such that these components must still be removed.



22

Q106_00101.0005.4119

2.7 PROCESSING REQUIREMENTS OF NATURAL GAS

The objective of “Gas Conditioning” is to separate well streams into saleable gas and liquid hydrocarbon products. This involves recovery of the maximum amounts of each component at the lowest overall cost; however the extent of gas conditioning required is dictated by the well stream quality, the end uses of the sales gas and extent of liquid hydrocarbon recovery.

Stated simply, “Gas Conditioning” usually means the removal of undesirable components from well streams to reach pre-established specifications prior to processing, pipeline transportation, or liquefaction. This stage typically includes the extraction of impurities and contaminants but can also include the separation of gas from heavier liquid hydrocarbon components using a process known as “Dew Point Control”.

To achieve sales gas quality gas conditioning will include these four basic processes:

Separation of gas from free liquids such as crude oil, condensate, water and entrained solids

Dehydrating the gas to remove condensable water vapor, which under certain conditions might cause hydrate or ice formation

Processing the gas to remove condensable and recoverable hydrocarbon vapors (Dew Point Control)

Treating the gas to remove other undesirable components, such as hydrogen sulfide or carbon dioxide.

Some of these processes can be accomplished in the field, but in most cases, the gas undergoes further processing at a gas treatment facility and/or liquid extraction plant. The typical steps involved in raw gas conditioning are presented in a general flow schematic shown in Figure 2.4.

It should be noted that the Gas Conditioning process is sometimes referred to as “Open Art” design. This pertains to sizing and design of gas conditioning equipment. Typically contractors use API equipment standards, process simulations and with equipment vendor consultations are able to design gas processing facilities which predicates the need to used licensed technologies. Licensed technologies however do exist for gas operations and (as indicated in Figure 2.4), are mainly for specific unit processes where design has been optimized or proprietary materials (adsorbents, membranes) are used.

Gas conditioning techniques to meet sales gas specification will be discussed in detail in Section 3, whereas the licensed technologies which exist for the treatment of natural gas to sales gas specifications will be discussed in detail in Section 4 of this report.



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Figure 2.4 Gas Processing Schematic with NGL Extraction

CompressionStation

Gas ReceptionFacilities

GasSweetening

Dew PointControl

NGLExtraction

NitrogenRejection

ProductionFacilities

CondensateStabilizer Sulfur

Recovery

Storage FractionationProductTreating

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Re-injectionCompression

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Gas to Pipeline

CO2

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Residue Gas

LNG

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Oil

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Export

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C4

Gasoline

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“Open Art Design” or Contractor Experience

Hydrocarbons

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Gas Dehydration(Hydrate Inhibition)

&

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&

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Section 3 Gas Reception and Processing

3.1 INTRODUCTION

The degree of natural gas conditioning to meet sales gas specification will be dependent on the well stream quality and the end uses of the sales gas. These variations in feed gas composition and product gas quality makes gas handling facilities difficult to define as a single scheme. However, gas handling facilities have common process units and as such these will be described in this section.

Typically at gas processing facilities there are two separate processes that occur before gas is sold or sent for further processing i.e. for NGL extraction or LNG liquefaction plants. The initial step in gas conditioning is gas – liquid separation, where liquid hydrocarbons (known as condensates) and any water contained in the gas stream (known as produced water) are separated from the gas. The second step in gas conditioning is gas treating where impurities such as sulfur, carbon dioxide and other components are removed dependent on the sales gas quality required. Additional processing may include transforming the gas to a value added product such as LPG via NGL extraction processes and / or production of LNG via gas liquefaction. These additional processes are considered in the “Natural Gas Liquid Extraction” PERP study1 and in “Advances in LNG Technology” PERP study2 and therefore will not be further considered in this report.

Gas conditioning to generate gas to a sales gas specification will be the subject of this section and therefore described in some detail below.

1 Reference: Natural Gas Liquid Extraction ChemSystems’ Process Evaluation Research Planning, Report number: 94/95 S4, May 96. 2 Reference: Advances in LNG Technologies ChemSystems’ Process Evaluation Research Planning, Report number: 03/04 S10, Sept 2004.



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3.2 DEHYDRATION

Prior to gas arriving at gas processing facility, some treatment at the well or platform may be necessary to prevent hydrate formation in the gathering system and along the pipeline to shore.

Gas hydrates (clathrates) are crystalline compounds consisting of an “ice like” water lattice structure formed by a physical combination of water and other trapped small molecules. Hydrates form only when liquid water is present with the gas as water molecules form hydrogen bonds.

Hydrate formation may be influenced by temperature, pressure, trapped molecule size and concentration of the gas component. Generally, hydrates form at high pressure and low temperature, but they can occur at temperatures as high as 30 °C and below 0.7 MPa. Hydrate formation could therefore occur in the pipeline transporting the gas from the well to the gas processing plant. Their formation results in restrictions and interruptions in well gas flow by causing plugs in pipelines, equipment, and instrumentation. Their formation must therefore be prevented.

Hydrate formation can be predicted from empirical vapor – solid equilibrium ratios, empirical correlations, and laboratory measurements. To avoid the formation of gas hydrates in pipelines, the water vapor content of natural gas is commonly reduced by dehydration before transport. Lowering the water dew point to –5 to –8 °C in relation to the maximum transmission pressure is a common stipulation in gas specifications.

A number of methods can be used for dehydration to manage and prevent hydrate formation. These include:

Thermal Treatment: by keeping the fluids warm using insulation, hot oil, and electrical trace heating

Mechanical Treatment: by removing the water using Glycol dehydration tower, pigging the pipeline and displacement with non-hydrate forming fluids

Operational Treatment: by operating at a lower pressure by lowering pipeline pressure and/or regular blow-down

Chemical Treatment: by injecting traditional hydrate inhibitors using methanol or glycol.

The most common way of preventing hydrate formation is by contacting or injecting the well stream with hydrate inhibitors. Hydrate inhibitors work by changing the “freezing point” or hydrate formation temperature of the fluids. Hydrate equilibrium curves are shown in Figure 3.1. These curves show the conditions at which hydrates are thermodynamically stable. Operating a system in the stable hydrate region implies that the system is at risk for hydrate formation. As a measure of the potential for hydrate formation, the term subcooling is often used. Subcooling is the difference between the operating temperature and the hydrate equilibrium temperature at the system pressure. Increasing risk of subcooling increases the potential for hydrate occurrence.



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Figure 3.1 Hydrate Equilibrium Curve

PP:4119.0005/Sec 3

30 40 50 60 70 80 90

0

1000

2000

3000

4000

5000

6000

7000

Pres

sure

(psia

)

Temperature (°F)

Shut-in Conditions at Wellhead

30°F Subcooling

Hydrate Free Region

Stable Hydrate Region

Water soluble chemicals such as methanol, ethylene glycols (EG), di-ethylene glycol (DEG) and tri-ethylene glycol (TEG) are typically used for hydrate inhibition. The most popular is ethylene glycol because of its lower cost, lower viscosity, and lower solubility in liquid hydrocarbon. The disadvantage of using glycol comes in its regeneration where it generates a salty sludge which can lead to environmental disposal problems. The salty sludge produced is a consequence of sea water being present in the well gas stream.

Methanol is also popular as a hydrate prevention agent due to its low cost and availability. Some methanol can be lost in the sales gas stream; this will add to the calorific value of the sales gas. Methanol losses can be as high as 40 percent and therefore will need to be replaced intermittently as “make-up”.

The hydrate inhibitor is typically injected and placed in direct contact with the gas stream in a chemical distribution system. The hydrate inhibitor can be recovered at the onshore facilities with the aqueous phase, regenerated and re-injected.

The quantity of hydrate inhibitor (i.e. methanol or glycol) to inject in the gas stream depends on its composition (e.g. water content), temperature and pressure. Hydrate formation temperature and pressure, as well as, the quantity of inhibitor required can be computed based on the wellhead gas composition and pressure. The rate of injection typically ranges between 0.2-0.4 gallon of glycol per million Scf/hr of gas treated.



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3.3 GAS RECEPTION FACILITIES

3.3.1 Gas Separators and Slug Catchers

Separators are the primary equipment that separate gas from free liquids present in the well gas stream. Slug catchers are typically used downstream of the production facilities to capture any liquid (slugs) that may not have been removed by the separators, (which is generally placed at the production facility and only if large volumes of hydrocarbon liquids are expected). Slug catchers are typically used before the well gas enters a gas conditioning facility. Filters are typically placed downstream of the slug catcher to prevent entrained solids build-up (i.e. sand, scale, etc) in the gas processing pipe work.

Liquid in the gas stream may form slugs at high fluid velocities. Slugs will travel at the same velocity as the gas through the pipe and can cause significant damage to the equipment and pipelines. Liquid slugs can exist at superficial liquid velocities of 1 to 4 m/s and a superficial gas velocity of 4 to 20 m/s.

Separator and slug catcher design is dependent on the composition of the well stream which determines the quantity of liquid present in the stream. The quantity of liquid present is directly related to the pressure; temperature and composition of wellhead stream which are fixed by the characteristics of the reservoir (e.g. field properties and depletion levels) and transport of the fluid from the well to the onshore facilities. For example, the liquid recovered from gas condensate streams could be as high as 100 barrels per MMSCF of gas treated.

Current “Slug Catcher” designs are based on reducing fluid velocities to promote a “stratified” flow regime and subsequent gravity separation. Two gas separator types are widely used in industry for gas-liquid separation; these are the single “vessel type” (either horizontal or vertical separators) or the “finger type”. Each system provides liquid separation and hold-up; has its own unique characteristics, and their installation must be examined on a case by case basis. Some characteristics of each separator system are briefly discussed below.

3.3.1.1 Horizontal Separator

The horizontal separator may be more economical as compared to the vertical separator type of equal capacity as it has a much greater gas-liquid interface area. Several horizontal separators can be stacked easily into stage separation assemblies minimizing space requirements. Some separators have closely spaced horizontal baffle plates that extend lengthwise down the vessel upon which the baffle plates are evenly paced at a 45o angle to the horizontal. The gas flow in the baffle surfaces and forms a liquid film that is drained away to the liquid section of the separator.



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The advantages of using a horizontal separator are as follows:

Useful where small particle separation (10 microns) is required and where there is more liquid and lower gas flow.

Good separation expected even with slug sizes ranging between 5 – 700 barrels.

A limitation of this separator type is that it becomes heavy and expensive when large sizes are required.

Figure 3.2 Horizontal Separator Vessel

Gas In

Gas Out

Impinglement Baffle

Liquid OutV: 4119.0005/Sec_3

3.3.1.2 Vertical Separator

A vertical separator occupies less floor space than horizontal separators; this is an important consideration in the design of offshore processing facilities. However because the natural upward flow of gas in a vertical vessel opposes the falling droplets of liquid, a vertical separator for the same capacity may be larger and more expensive than a horizontal arrangement.

The advantages of using a vertical separator are as follows:

Useful where small particle separation (10 microns) is required and gas flow is large in relation to liquid slug size

Good separation expected with slug sizes ranging between 5–700 barrels.

Can be fitted with a false cone bottom to handle sand production.

A limitation of this slug catcher type is that it becomes heavy and expensive when large sizes are required.



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Figure 3.3 Vertical Separator Vessel

3.3.1.3 Pipe and Finger Type Slug Catcher

“Pipe Type” Slug Catchers are based on reducing fluid velocities to promote a "stratified" flow regime and subsequent gravity separation. To attain this, the slug catcher must control and dissipate the energy of the incoming gas stream as it enters the slug catcher. This is to minimize turbulence and ensure that the gas and liquid flow rates are low enough so that gravity segregation can occur. Velocity reduction is achieved by enlarging the pipe diameter. A rule of thumb is that the gas velocity cannot exceed 1.5 m/s (5 f/s) for liquid removal to occur.

Pipe type slug catcher is a very economical way to remove small slugs of up to 150-200 bbls. It is a large diameter pipe structure in which gas/liquid mixture is injected at low velocity. An impingement plate at the inlet encourages liquid drop out by gravity and liquids are separated/collected at the bottom of the pipe. For economic reasons, these slug catchers are usually designed as pipe and fittings, rather than as pressure vessels. A typical Pipe Type slug catcher is shown in Figure 3.4.



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Figure 3.4 Typical “Pipe Type” Slug Catcher Technology

The current slug catcher design must not only promote stratification, but must also be capable of handling the largest slug volume without permitting slug formation in the slug catcher. Thus, selecting slug catcher length is an important part of the slug catcher design. To conserve on land area, it is common to use "Finger Type" slug catcher which is essentially a manifolded system of several “Pipe Type” slug catchers allowing increased gas/liquid mixture throughput.

Finger type slug catchers were developed for large scale applications and advantages of using a “Finger Type” slug catcher include:

Predictable particle separation of up to 50 micron

Good separation expected with slug sizes in excess of 1000 barrels (of oil)

Ease of shipment in pieces for field assembly with line pipes

Cheaper than the equivalent vessel design (i.e. economical way to catch large slugs)



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3.4 DEW POINT CONTROL When gas is transported in pipelines, consideration must be given to the control of the formation of hydrocarbon liquids in the pipeline system in order to prevent damage to the equipment and to avoid decreasing gas transmission capacity. It is therefore important to reduce the hydrocarbon dew point of the mixture (i.e. pressure and temperature at which hydrocarbons begin to condense from a gas stream). The control of water dew point (i.e. pressure and temperature at which water vapor contained in the gas stream begins to condense) is also necessary to prevent the formation of hydrates and reduce the potential for corrosion in sales gas pipelines. Both hydrocarbon and water dew point conditions will need to be low enough to prevent condensation in the pipeline, i.e. dew point of the sales gas needs to be below the pipeline operating condition.

Equations of state are used to predict vapor-liquid behavior and hence mixture dew points. These equations of state show that heavier hydrocarbons have higher dew points. Consequently, since pipeline operating conditions are usually fixed by design, user specifications, and environmental considerations, single-phase flow can only be assured by removal of the heavier hydrocarbons from the gas.

There are several ways in which water and hydrocarbon dew-point control can be achieved and include: Low Temperature Separation (LTX): which can be achieved using Joule-Thompson

(JT) auto-refrigeration or mechanical refrigeration Desiccant Absorption: achieved by using a short cycle desiccant (silica gel) plant.

These are further described below.

Turbo expander and lean oil absorption technologies can also be used for dew point control, but are often associated with NGL recovery and can also be used for deep NGL recovery. Lean oil absorption processes often require large processing equipment with excessive energy requirements and are less thermodynamically efficient than turbo-expander plants such that it is seldom selected today for NGL extraction. Neither of these processes are discussed further in this study.

3.4.1 Low Temperature Separation The most effective means of handling high pressure gas and condensate separation to meet dew point conditions is low temperature separation (LTX). The technique performs the following functions:

Separation of water and hydrocarbon liquids from the inlet well stream Recovery of more liquids from the gas than can be recovered with normal temperature

separators, and Dehydration of gas, usually to pipeline specifications.

Within LTX systems, the inlet gas is cooled by expansion due to pressure reduction, causing water and liquid to condense. In some cases a means must be provided to prevent formation of hydrates in the low temperature separators. This is achieved by either piping hot well stream through the separator or by injecting hydrate inhibitor upstream of separator.



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3.4.1.1 Joule Thomson Expansion

Low temperature expansion can be achieved using a Joule Thomson (JT) effect to increase the recovery of condensate and at the same time lower the water content of the gas. The cooling is achieved through a sudden adiabatic pressure drop of the feed gas which will reduce the gas temperature and hence condense the heavier hydrocarbons and other condensables such as, for example, water. The effect produced by a sudden adiabatic pressure drop in which no work is done is termed a “free expansion” or Joule-Thomson expansion, as illustrated in Figure 3.5.

Figure 3.5 Joule Thomson Effect Shown on a Phase Diagram

Temperature

Pressure

Feed Gas Phase Envelope

Sales Gas Phase Envelope

(2)

Key:(1) Upstream conditions of Joule Thomson Valve

(2) Downstream conditions of Joule Thomson Valve

(1)

PP:4119.0005/Sec 3

The performance of Joule-Thomson plants are very much dependent on the condition of the incoming raw gas stream as they use excess pressure energy of the raw gas stream to auto-refrigerate the gas. Therefore, if sufficient pressure is available, i.e. feed gas pressure is high enough; the liquid removal can be accomplished and hydrocarbon dew point achieved by expansion refrigeration in an LTX unit. The actual temperature drop will be affected by the composition of gas, flow rates, liquid rates, feed pressure, bath temperature and ambient temperature. This temperature reduction results in not only hydrocarbon liquid condensation but also water condensation. The process can therefore accomplish dew point control of both water and hydrocarbon to sales gas specification in a single unit.



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The change in state of the fluid stream caused by the sudden reduction in pressure at the valve together with the amount and composition of the product streams can be computed and therefore predicted when inlet stream composition, pressure, temperature are known and used in combination with gas laws, equilibrium data and/or enthalpy-entropy charts.

The hydrocarbon and water dew point achievable with this process are limited by the pressure differential available as well as the composition of the feed gas. The LTX system can only be used where sufficient pressure is available to perform the desired processing and separation. It is an attractive process step if sufficient liquid removal can be achieved at the available operating conditions. A further modification to this process is to add glycol injection to the high pressure gas to allow achievement of lower water dew point when available pressure is limited. The use of glycol eliminates the need to heat the LTX liquid phase and helps to ensure that no hydrate formed will block the process equipment downstream of the LTX separator. A typical flow scheme is shown in Figure 3.6.

In this scheme, condensates are removed in the liquid knockout drum. The incoming gas is cooled against cold sales gas prior to pressure reduction and cooling across a valve. Condensed liquids are then separated in a downstream vessel. Because the gas enters the hydrate region on cooling, glycol (or methanol) is injected upstream of the valve. Liquids removed from the separator vessel are heated to enable effective separation of the condensed hydrocarbon and glycol phases. The glycol, which is laden with water, is regenerated for re-use, whereas the recovered condensates are stabilized and then sent to storage for export or further treatment.

A variation on the above scheme is shown in Figure 3.7 where there is no glycol injection.

This scheme encourages hydrates formation in the low temperature separation vessel. The formed hydrates float to the top of the liquid surface where they are melted by a heating coil (refer to Figure 3.8). The gas is then separated from the liquids and the solids through gravitational difference leaving the vessel from the low temperature (or hydrate) separator. Heat control is critical in this scheme. Insufficient heat results in excess hydrates while too much heat vaporizes some of the condensed NGLs, such that the sales gas specifications are infringed.

Usually the desired water content specification for pipeline gas is 2.5- 3.5 kg of water per MMScf of gas at standard conditions (15oC and 1.013 bar). With sufficient well pressure the operating conditions can be adjusted to fulfill this requirement. The low temperature dehydration process is continuous and limited only by the pressure drop available for the process. The necessary pressure drop in the process is approximately 50 to 100 bar and a wide range of temperatures can be handled by suitable modification of the equipment with the necessary heat-exchange requirements. Advantages and disadvantages of applying this form of dehydration method can be found in Table 3.1.



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Figure 3.8 Hydrate Separator (Records and Seely, 5-66. Courtesy AIME)

Table 3.1 Advantages and Disadvantages of the JT-expansion

Advantages Disadvantages Usually least expensive system where a

pressure drop is necessary in a process Restricted to those applications where a

large pressure drop is available

Increased revenue from most natural gas systems with increased condensate recovery

Effectiveness lost as pressure declines. In this case, it must be supplemented by other equipment (i.e. refrigeration system, recompression or desiccants adsorption)

Low dew points when sufficient pressure drop is available

Danger of low-carbon-steel embrittlement and equipment failure is operated below -28oC

Simple automatic operation requiring minimum attendance

Close control often necessary to prevent formation of hydrates prior to the low temperature separator.

Low temperature separation cannot usually be justified when used solely for gas dehydration.



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Due to the dependence of JT plants on utilizing pressure differential to achieve separation, they are most suitable for gas streams that have a high wellhead pressure or where no compression is required to meet the sales gas delivery pressure. Declining wellhead pressure can sometimes be overcome by the installation of compressors and/or retrofitting mechanical refrigeration upstream of the Joule-Thomson valve.

3.4.1.2 Mechanical Refrigeration

Often excess pressure is not available to operate a low temperature separation system. An alternative to the expansion refrigeration system is to utilize a mechanical refrigeration system to remove heavy hydrocarbons and reduce gas to dew point. The schematic for a refrigeration dew point control unit is shown in Figure 3.9.

The gas pressure is generally maintained through the process allowing for equipment pressure drops. The gas is heat exchanged and then cooled by the refrigeration chiller to specified temperature. Liquid is separated in the cold separator. The temperature is set to provide the desired dew point margin for sales gas operations. This temperature specification must take into account the gas which is recombined from the liquid stabilization step as well as potential variations in the feed gas pressure.

Provision must be made in this process for hydrate prevention. This can be accomplished by either dehydration upstream of the unit or by integrating the dehydration with the refrigeration unit. The use of glycol injection is usually the most cost effective means of controlling water dew points. The only drawback is that the refrigeration must be in operation to accomplish the dehydration. If it is desired to operate the dehydration at times independent of the refrigeration then separate unit are used.

Mechanical refrigeration plants have more process equipment items than Joule-Thomson plants and may be unfeasible for high pressure gas streams where a pressure reduction is required to enter the two phase region and condense-out the heavy hydrocarbons. This is illustrated in Figure 3.10.

Refrigeration process can be flexibly used for simple dew point control to deep ethane recovery depending on refrigeration cycle used. Typically, multi stage propane chilling will be used for propane recoveries (C3), and ethane recovery, which requires lower refrigeration temperatures, will use mixed refrigerant or cascade cycle processes.



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Figure 3.10 Inability of Mechanical Refrigeration to Enter Two Phase Region for Dew Point Control For High Pressure Feed Gas

Temperature

Pressure

Joule Thomson

Mechanical Refrigeration

Two Phase Gas Liquid Region

Raw Gas Conditions

PP:4119.0005/Sec 3

3.4.2 Desiccant Absorption

An alternative to low temperature separation or mechanical refrigeration for gas dehydration includes desiccant absorption.

There are a number of desiccant absorption options available and include: liquid desiccant absorption (e.g. glycol contacting), solid desiccant adsorption (e.g. silica gel, molecular sieve) and dehydration using calcium chloride. These adsorption processes can be used for hydrocarbon dew point and water dew point control in a single process step or can be used for selective removal of water only. Details of desiccant absorption processes are further described in the section below.

3.4.2.1 Liquid Desiccants Absorption

Liquid desiccant used in gas dehydration are mainly methanol, Ethylene Glycols (EG), diethylene glycol (DEG), triethylene glycol (TEG) and tetraethylene glycol (TREG). Triethylene glycol (TEG) is the most commonly used for natural gas dehydration (removing water) and it is usually used for application where the dew point depression in the order of 15oC to 50oC is required.



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These desiccants attract water and will change its ‘freezing point’ such as they will also act as hydrate formation inhibitors. Actual outlet water concentration (represented by its dew point) depends on the desiccant circulation rate, the desiccant concentration (concentration of up to 99.99 percent may be required for efficient absorption) and number of equilibrium stage of the contacting tower. The quantity of desiccant to circulate in the system also depends on the gas composition (i.e. water content) and it can be computed based on the gas stream composition, pressure and temperature. As a rule of thumb, TEG system would require, for an economical design, 20 to 40 liters of TEG circulating for each kilogram of water to be absorbed.

A basic glycol contacting scheme is shown in Figure 3.11. The natural gas stream is contacted with a glycol solution to which water is attracted. It is important to note that aromatic compounds, such as BTEX, and other hydrocarbon vapors are soluble in glycol and will also be absorbed in the circulating solution. The contacting usually takes place at an elevated pressure, e.g., first stage separator pressure or gas export pressure, and can take place at very low temperature (e.g. dehydration by refrigeration in presence of freeze protection). After contacting, the water/glycol solution is sent to a regeneration unit where the water will be separated from the glycol solution.

The regeneration unit typically includes a flash tank, where methane and other light gases are flashed off, a reboiler and a regeneration still column. The water laden glycol is heated in the regeneration column to drive off absorbed water. Dry glycol is then recovered for reuse in the absorber; TEG concentration of 99.9 wt% is typically achieved after heating. Unfortunately, this heating also vaporizes hydrocarbons that have been absorbed into the glycol, and these are sent, along with the water vapor, in vent stream from the still column. These organic emissions are now classified as Hazardous Air Pollutants (HAPs), and are subject to emissions regulations both in the United States and internationally. Alternative technologies have been developed to reduce BTEX emissions from solvent stripping (namely the ECOTEG® process) which is described in more details in Section 4.

Liquid desiccant dehydration equipment is simple to operate and maintain. It can easily be automated for unattended operation.



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3.4.2.2 Dry/Solid Desiccant Adsorption

Solid desiccant uses physical adsorption of molecules onto the surface of those adsorbent. Several solid desiccants are used in water adsorption and hydrocarbon adsorption applications. These are typically sold as pellets or beads (either spherical or cylindrical shaped) of various sizes and porosity. Standard sizes are pellets of 1/16 inch (1.6 mm) or 1/8 inch (3.2 mm) diameter and beads of 8x12 mesh (1.6-2.5mm) and 4x8 mesh (2.5-5mm). Desiccants in common commercial use fall into one of those three categories:

Gels: water and hydrocarbon removal can be achieved with silica gel. Silica gels are manufactured from sulfuric acid and sodium silicate, essentially pure silicon dioxide (SiO2). Silica gels can also adsorb polar compound such as methanol or mercaptans and can deliver a water dew point of 0oC and hydrocarbon dew point 5oC at approximately 70 barg.

Alumina: typically a hydrated form of alumina oxide (Al2O3); can achieve water dew points in the order of -70oC and standard pressure (1.013 bar).

Molecular Sieves: manufactured or naturally occurring alkali metal aluminisilicates which give outlet water dew point of approximately -90oC at standard pressure and are capable of dehydration to less than 1 ppm water content. Additional applications include gas sweetening (i.e. hydrogen sulfide and mercaptans removal for feed gas containing low sulfur concentrations, in the order of a few hundred ppm as general rule for economical design).

Solid desiccants are generally used in dehydration systems consisting of two or more adsorption towers and associated regeneration equipment (i.e. fired heaters, regeneration gas cooler and auxiliary/supporting equipment). A process schematic is shown in Figure 3.12. This shows a three bed system where one bed is used for water removal, another is being heated (first step of regeneration), and the third is cooling (second step of regeneration), which is typically used in Silica Gel adsorption.

The system operates on a cyclical basis where the operating modes of the beds are switched over once the bed in service is fully loaded with water (just before breakthrough occurs). Regeneration is carried out by passing a heated gas, e.g. a slip stream of the treated gas across the bed at a sufficiently high temperature such that the adsorbed water in the bed is desorbed. The gas slip stream is then cooled to condense out most of the bulk water vapor. Gas flow during adsorption is usually downflow, allowing higher gas velocities which avoid bed fluidization. The adsorption process can be in open or closed loop, depending on whether the regeneration gas is recycled to the inlet of the unit or not.

Solid desiccant units generally cost more to buy and operate than glycol units but this depends on the gas water content and the environment of the unit. Solid desiccant units can be more economically viable at low water concentration and remote units where utilities and access are limited. Their use is therefore typically limited to low H2O content gases feed, very low water dew point requirements and/or in cryogenic processes to prevent hydrate and ice formation.



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Molecular Sieves

Typically these are crystalline metal aluminosilicates having a three dimensional interconnecting network of silica and alumina tetrahedra. Natural water of hydration is removed from this network by heating to produce uniform cavities (or “pores”) which selectively adsorb molecules of a specific size.

The 3Å, 4Å, 5Å and 13X (where 1Å or angstrom = 1 x 10-10m) pore size sieves can be designed for size-selective separations. For example:

3 Å Molecular Sieves: are formed by substituting potassium cation for the inherent sodium ions of the 4 Å structure reducing the effective pore size to ~ 3 Å. Primary application of 3 Å molecular sieves are commercial dehydration of unsaturated hydrocarbon streams and selective removal of water from natural gas streams.

4 Å Molecular Sieves: the standard type for an A type zeolite, the sodium form, with effective pore openings of ~ 4 Å can adsorb species such as H2O, SO2, CO2, H2S, N2, C2H4, C2H6, C3H6 and methanol. Generally considered a universal drying agent in polar (non aqueous) and non-polar media.

5 Å Molecular Sieves: are divalent calcium ions in place of sodium cations give apertures of ~5Å which exclude molecules of effective diameter >5Å, e.g., all 4-carbon rings, and iso-compounds. Primary application therefore removal of H2S, CO2 and linear mercaptans from natural gas. Other applications include adsorption of nC4H10, nC4H9OH and dichlorodifluoro-methane (Freon 12®).

13 X Molecular Sieves: The sodium form represents the basic structure of the type X family, with an effective pore opening in the 9-10¼ Å range. Primary liquid hydrocarbon/natural gas application of 13 X molecular sieves are that can be used in liquid hydrocarbon/natural gas sweetening (i.e. removal of H2S and mercaptans).

Typical equilibrium loading curves are shown in Figure 3.13.

Figure 3.13 Loading of Molecular Sieve 5 Å (Courtesy of: Wiley-VCH Verlag GmbH & Co. KGaA)

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Molecular sieve adsorption typically occurs in a 2+1 solid bed arrangement, where two beds are used for adsorption and one bed is being regenerated. Adsorption generally occurs at around 20-50oC and regeneration takes place at around 200oC-300oC. Higher regeneration temperature or higher regeneration gas flow rate are required for high pressure regeneration. The process produces a gas with less than 1 ppm water content suitable for further downstream processing such as NGL recovery and LNG.

Molecular sieves are typically more versatile as they can be used to simultaneously sweeten and dry gases, and are typically less expensive than silica gels. However, molecular sieves have higher heat of desorption, and are usually more expensive to build and operate than other methods.

In most cases, molecular sieves will be the preferred choice of adsorbent for: Drying fluids at a temperature above 50oC Drying fluids when heavy hydrocarbon and/or aromatics are present, which can reduce

the capacity of absorption of alumina and gels Co-adsorption of water and sulfur compounds Acid gas feed with pH of the absorbed water less than 5 Dew point required is less than -70oC at standard pressure (1.013 bar).

3.4.2.3 Membrane Processes Gas separation with membranes has developed into an economically viable process in the last decade. Membranes can be used for almost all aspects of natural gas treating. The following are of particular interest: Separation of carbon dioxide and methane Removal of carbon dioxide and hydrogen sulfide Dehydration Recovery of heavier hydrocarbons,

Poreless, dense polymer films are used for the separation of gas mixtures. Individual components of the gas dissolve in the polymer and move through it by diffusion. Material transport can be described by the following steps: absorption from the gas phase into the membrane matrix, diffusion through the membrane, and desorption out of the membrane into the gas phase. The general rule is that a larger available membrane surface area, thinner effective membrane separating layer, greater difference in partial pressures, higher membrane-specific flow rate of the components to be separated (permeation coefficient), and better selectivity for individual gases result in more complete separation of a mixture.

A multitude of polymer membranes are connected in a module to reach as high a packing density as possible. Hollow fiber, spiral-wound, and envelope-type modules have become generally accepted. However as the pressure drop across the process is quite high; this makes membrane use economical if production of low pressure natural gas is acceptable or for plants that receive high pressure feed gas resulting from high well pressure streams. Feed gas pre-treatment by compression is possible, however, it leads to an increase in the capital cost of investment and also increases operating costs.



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3.5 IMPURITY REMOVAL

In addition to water and hydrocarbon dew point control, contaminants such as acid gases may have to be removed from the gas stream to meet pipeline and sales gas specification. Additional treatment may also be required to meet gas specification for LNG production. Such treatments are listed below and include:

Acid Gases & Organic Sulfur Compounds: removal of carbon dioxide (CO2), hydrogen sulfide (H2S) and other sulfur compounds including mercaptans (RSH) and carbonyl sulfides (COS).

Mercury: mainly for LNG and cryogenic applications, it is removed to prevent risk of metal embrittlement of materials of construction

Nitrogen: removal of inerts for LNG processing and to improve sales gas heating value

Helium: removal of inerts for LNG processing and to improve sales gas heating value.

The overall gas processing plant may therefore incorporate units to remove these components, as well as dew point control unit. Processes used for the removal of those contaminants are described in this section.

3.5.1 Acid Gas Removal

Acid gases generally refer to carbon dioxide, CO2, and hydrogen sulfide, H2S, because they form an acidic solution when absorbed in water. The process of removing those acid gases from a natural gas stream is called ‘Gas Sweetening’. Gas sweetening is performed for a number of reasons:

To prevent corrosion in the presence of free water,

To meet limits on the H2S and CO2 content of sales gas and

To avoid reduction in heating value due to excess CO2.

Sales gas specification for transmission and distribution, as seen in Table 2.3, specify a maximum H2S content of about 5 to 7 milligrams per standard cubic meter. Other sulfur components may be present in the feed gas such as mercaptans and carbonyl sulfide and these may also have to be removed to meet sales gas specifications. It has to be noted that more stringent standards may be set, particularly for the liquefaction of natural gas into liquefied natural gas, LNG, where CO2 can freeze on exchanger surfaces (riming), thus reducing efficiency of the process and blocking heat exchangers.

Processes available to remove acid gases and other sulfur containing compounds are summarized in Table 3.2.



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Table 3.2 Acid Gas Removal Methods

Process Type Process Mechanism

Chemical Process (Solvent) Amine contacting (MEA, DEA, MDEA, DGA.)Potassium carbonateCaustic wash (non regenerative)Chelated iron

Chemical Process (Dry) Iron Sponge Fixed Bed Sweetening (Batch Process)Zinc oxide (non regenerative)

Physical Process (Solvent) Glycol AbsorptionMethanolPatented solvents

Physical Process (Dry) Molecular sieves AdsorptionActivated charcoal Fixed Bed SweeteningCryogenic condensation and distillation Gas liquid separationMembrane Separation

Absorption and reaction of acid gas with a chemical solution

The choice of process to be used depends on the composition of the feed gas stream and the sales gas specifications.

Natural gas streams with low content H2S can be sweetened in a chemical reactive process using iron sponge as an absorbent. However, this is a batch process requiring replacement of iron sponge upon saturation with H2S, as this process consumes the active chemical in the sponge. This process will therefore not be suitable for large volume of gases with high acid gas content. The same applies for Zinc Oxide processes.

Physical adsorption units using molecular sieve (mole sieve) are designed for adsorption of H2S and CO2 down to very low levels, i.e. 4ppm H2S in the treated gas. Molecular sieves adsorption will typically be done on a 4Å molecular sieve after deep dehydration of the gas. The use of molecular sieve will be dependent on the sales gas specification to be achieved and the inlet gas compositions. It has to be noted that the treatment of large amount of gas with relatively large acid gas concentration would require large adsorption and regeneration equipment, which may prove uneconomical.

The most commonly used processes for acid gas removal are solvent processes, both chemical and physical solvent processes are described in more details below.

3.5.1.1 Solvent Processes

Solvent processes are based on physical and/or chemical absorption of acid gases. A comparison between physical solvent processes and chemical solvent processes, which are most commonly used for acid gas treatment, is shown in Table 3.3.



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Table 3.3 Physical Solvents versus Chemical Solvents (source: Q.B. Johnson Manufacturing Inc.)

Physical Solvents Chemical SolventsNeed high acid gas partial pressure (above 3 bar) Operates for all acid gas partial pressure in the feed gasNeed low heavy hydrocarbon concentration in the feed gas Lower overhead specification achievedUsed for bulk removal Low solvent lossesLow regeneration heat required Low hydrocarbon solubilitiesLarge contactors may be required – many traysMay use of proprietary solvents

Solvent such as glycols (physical processes) are mainly used for bulk removal of acid gas from high acid gas concentration gases where stringent acid gas concentration of the treated gas is not required. Alkanolamines (amine – chemical process) are widely used for the removal of hydrogen sulfide and carbon dioxide from natural gas streams for a wide range of acid gas inlet concentration and very low acid gas concentration requirements of the treated natural gas. In addition, proprietary solvent such as Sulfolane (Shell), ACT-1TM (UOP) and Morphysorb® (BASF) are typically used for bulk CO2 removal or for trace H2S removal when used in conjunction with an amine. This is described in more details in Section 4 and Section 5.

3.5.1.2 The Amine Process

The removal of acid gases from a raw gas stream is done by a chemical reaction which occurs between the alkanolamine (amine) and the acid gases (H2S and CO2); this typically occurs in an absorption column where the gas contacts the amine solution. Amine processes typically operate with pressures between 1 bar and 180 bar, however this will depend on the inlet gas conditions. A basic process flow diagram for a typical gas sweetening by adsorption is presented in Figure 3.14.

Amines are clear, colorless liquids that can be categorized on a chemical basis as being primary (MonoEthanolAmine - MEA), secondary (DiEthanolAmine – DEA and DiIsoPropanolAmine - DIPA), and tertiary (MethylDiEthanolAmine - MDEA). Their classification depends on the number of substitutions onto a central nitrogen element.



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The chemical structure of amine influences its properties as a treating solvent and therefore, leads to different applications. Table 3.4 shows typical treated gas purities and required anime loading for the three types of amine.

Table 3.4 Amine Performance

MEA DEA/DIPA MDEA

Loading (moles/moles) 0.3 to 0.4 0.3 to 0.7 0.2 to 0.6Solution Concentration 15 - 20 wt% 25 - 30 wt% 25 - 50 wt%Treated Gas Purity - H2S < 3 ppm < 3 ppm < 3 ppmTreated Gas Purity - CO2 < 50 ppm < 200 ppm < 1000 ppm

The acid gas produced from the amine stripper may then be sent to a Claus unit for sulfur recovery provided that the volumes of sulfur that can be recovered are sufficiently large to justify the investment. When the volumes of sulfur are low the off gases are often just flared or incinerated, though stringent environmental regulations may require further treatment. Consideration can also be given to acid gas re-injection to maintain pressure of a gas reservoir, for example for enhanced oil recovery. However, this has the disadvantage of making the field gas increasingly more sour and is therefore not commonly used in gas field except as a disposal method.

3.5.1.3 Sulfur Recovery Unit - The Claus Process

A schematic flow diagram of the Claus sulfur recovery process is illustrated in Figure 3.15.

Sulfur is recovered from the hydrogen sulfide (H2S) in the acid gas in two steps.

Thermal Step: The H2S is partially oxidized with air. This is carried out in a reaction furnace at high temperatures (1,000-1,400ºC). Sulfur is formed, but some H2S remains unreacted, and some SO2 is made.

Catalytic Step: The remaining H2S is reacted with the SO2 at lower temperatures (about 200-350ºC) over a catalyst to make more sulfur. A catalyst is needed in the second step to help the components react with reasonable speed. Unfortunately the reaction does not go to completion even with the best catalyst. To maximize conversion to sulfur, two or three catalytic reaction stages are used, with sulfur being removed between the stages. Factors like concentration, contact time and reaction temperature all influence the reaction, and are optimized to give the best conversions.

The reaction in the converters is 2H2S + SO2 = 3S + 2H2O.

Inevitably a small amount of H2S remains in the tail gas. This residual quantity, together with other trace sulfur compounds, is usually dealt within a tail gas unit, which removes and recycles the hydrogen sulfide to the Claus Unit. The Claus unit together with the tail gas unit can give overall sulfur recoveries of about 99.8 percent.



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3.5.2 Mercury Removal

Mercury, which is a common natural contaminant of gas, attacks piping and equipment made from aluminum and aluminum compounds. Aluminum is a favored material of construction for low temperature exchangers used for example in a cryogenic NGL extraction process or in LNG plants. Mercury must therefore be removed prior to the feed gas entering the cryogenic sections of the plant, i.e. deep ethane recovery or LNG plant. Another reason for removing mercury is to produce mercury-free product streams if, for example, ethane is used as feed for an ethylene plant, the mercury needs to be removed to prevent heat exchanger and catalyst deactivation problems in the ethylene plant. Typical mercury specifications are for less than 0.01 micrograms per standard cubic meter, which corresponds to about 1 ppt by volume.

Activated carbon absorption has been successfully used for mercury removal since the 1970s. The activated carbon is typically impregnating with a compound that will chemically react with the mercury, e.g. sulfur, which will enhance the capacity of absorbing Mercury. The carbon is then disposed of by landfill or, where there are environmental concerns, it is regenerated, as shown in Figure 3.16.

In the process option presented in Figure 3.16, mercury is removed from the feed stream, condensed in the regeneration knockout, and leaves the process as a separate liquid stream.

The mercury removal facility is typically placed after the dehydration unit before entering the dew point control system. However, technology suppliers such as UOP, as part of their work to develop molecular sieve use to remove mercury, propose to combine the dehydration unit with the mercury removal unit. This will be done by replacing a portion of the dehydration grade molecular sieve with HgSIV™ regenerative mercury removal adsorbent, more details on this particular technology can be found in Section 4.4.2.

3.5.3 Nitrogen Removal

Removal of nitrogen may be required if it is present in large enough concentration to give an unacceptably low gas calorific value of the sales gas. Cryogenic processes or solvent processes can be employed for nitrogen removal. In the case where cryogenic technology is employed, the nitrogen rejection unit is typically a component of an NGL recovery units.

Solvent absorption can also be used for nitrogen rejection. This may be a preferred process as it does not require deep dehydration and CO2 removal as it is required for the cryogenic process in order to prevent freezing in the cryogenic equipment. Molecular sieves can also be used for nitrogen rejection; this will usually be limited to small volume application to limit the size of the equipments. Further details are available in Section 5.3.1).

3.5.4 Helium Removal

Helium, like nitrogen, is an inert but is rarely present in large concentrations in natural gas. However, in a few cases, it is present in sufficiently large quantity to justify its extraction as a valuable by-product. As with nitrogen removal, cryogenic processes are usually employed for helium removal.



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3.6 CONDENSATE STABILISATION

Stabilization is a means of removing lighter hydrocarbons from the liquid present in the bottom of the slug catcher with a minimum loss of heavier hydrocarbons. Stabilisation results in a larger volume of stock tank liquids available for sale.

The stabilization system consists of a vertical vessel, which may be packed with ceramic rings or fitted with trays spaced from 12 to 24 in. apart inside the vessel. The liquid in the lower section of the tower is heated by an indirect heater or steam coils. The condensate from the bottom of the slug catcher flows directly to the top of the stabilizer. The liquid hydrocarbons flow through the packing or down the trays, adsorbing some of the heavier gaseous hydrocarbons which have been vaporized at the bottom of the vessel. At the bottom of the vessel, the heat added from the heater or reboiler vaporizes most of the lighter hydrocarbons. After being cooled, the stabilized liquid flows to storage and the lighter ends flow upwards to be reabsorbed or to leave the top of the vessel (refer to Figure 3. 17). The produced gas stream, mainly light hydrocarbons, is routed to become fuel, sales gas or routed in a vent line.

The amount of condensate that can be recovered by stabilization unit is dependent on the pressure and temperature at which the slug catcher is operated and the composition of the gas being processed.



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Section 4 Current Process Technologies

4.1 INTRODUCTION

Gas conditioning process is sometimes referred to as “Open Art” design. This pertains to sizing and design of gas conditioning equipment. As previously mentioned in Section 2, contractors use internationally recognized equipment standards, process simulations and equipment vendor consultations to design gas processing facilities that, under certain circumstances can predicate the need to used licensed technologies. Some Project developers prefer the reliability and security that comes with using licensed technologies, and as so bias towards using them. However such technologies exist only for specific unit operations where design has been optimized or proprietary materials (adsorbents, membranes etc.) are used.

The licensed processes and proprietary technologies will be covered in this section and exist for the following ‘units’, including:

Gas reception facilities (condensate recovery in a slug catcher)

Gas dehydration and water dew point control Hydrocarbon dew point control Acid gas removal (hydrogen sulfide and carbon dioxide) Nitrogen rejection and Mercury removal.

Natural gas production and natural gas treatment at the gas reservoir well-head are not considered in this study.

4.1.1 Engineering Companies With Track Record in Onshore Gas Processing

A number of engineering companies have formidable track records in gas processing technology, and in selecting a company to undertake front-end design responsibility for a major project, it would normally be considered unnecessarily risky to choose a company with lesser experience.

The technology of natural gas processing originated primarily in the U.S., with roots going back to the 1920s and 1930s. As a consequence, a large proportion of the companies in the field are American-origin, although often with offices in Europe and elsewhere. Some of the most well known companies are listed below:

ABB Lummus has a specialist gas processing subsidiary, Randall. ABB projects and services in gas processing covers field development, gas conditioning and treating, sulfur removal, deep ethane extraction and LPG recovery. To date, ABB technology has been used in more than 220 plants around the world with more than 16 BSCF processed daily.

BASF and Lurgi are major technology providers for acid gas (carbon dioxide and sulfuric acid) removal and sulfur recovery with their joint Omnisulf® process. BASF also developed various acid gas removal processes based on solvent extraction such as the aMDEA®, ADEG®, PuraTreatTM R und F, Morphysorb® and sMDEATM processes.



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UOP LLC has been delivering gas technology to the gas processing industry for over 90 years. UOP has licensed several gas processing processes in various applications such as gas dehydration and NGL recovery. NGL recovery turbo-expander-based technologies and sulfur recovery processes are supplied through UOP’s alliance with Ortloff Engineers Ltd. UOP also patented processes for acid gas removal, sulfur recovery, gas dehydration and nitrogen rejection.

For more than 50 years, Fluor Enterprise Inc. has provided gas processing technology to more than 200 gas treating plants with individual train capacities of up to 600 million standard cubic feet per day (MMSCFD). Fluor has developed patented carbon dioxide recovery process technologies, such as the EconamineSM, the Improved EconamineSM, the Econamine FG PlusSM, and the Fluor SolventSM process.

Bechtel Ltd. has provided gas processing services for more than 30 years. Its achievements include 110 gas processing plants, 50 major oil and gas field developments, and about a third of the world’s gas liquefaction capacity. IPSI LLC, formerly International Process Services, Inc., is an affiliate of Bechtel Corporation and is a provider of conceptual/front-end design of gas processing facilities. IPSI’s has patented and patent pending processes in cryogenic facilities for NGL extraction and deep ethane recovery, as well as, cryogenic nitrogen and helium separation from natural gas.

Axens a Process licensor, supplier of catalysts and adsorbents and associated services for refining and petrochemicals was created in 2001 from the merger of Procatalyze and IFP’s Industrial Division (which supplies IFP’s gas processing patented technology worldwide).

Prosernat, formed in 1998 from the merger of Proser (Framatome) and Nat (IFP), supplies patented technology such as Progly and Drizo®, as well as, the IFP Ifpexol technology for gas solvent dehydration.

Merichem (specialized in hydrogen sulfide removal) supplies The EliminatorTM; LO-CAT®; Sulfur-Rite®, ARI-100® and ARI-100EXL® for the bulk and trace removal of hydrogen sulfide (H2S) and removal of other sulfur compounds such as mercaptans.

Other major companies in the gas processing industry include: Air Products and Chemicals; M. W. Kellogg Limited; Technip USA Corporation; Parsons Energy & Chemicals Group Inc.; Costain Oil; Gas & Process Limited; Linde BOC Process Plants LLC (LBPP – co-operation between Linde HG and BOC); JGC Corporation; JF Pritchard & Company (now the process division of Black & Veatch); Snam Progetti (an E.N.I. - Ente Nazionale Idrocarburi company); ConocoPhillips; Shell; and Statoil all license gas processing technology



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4.2 GAS RECEPTION TECHNOLOGIES

Slug catchers are typically used to separate free liquids (condensates, mercaptans and water) from the natural gas stream before it is fed to the gas processing plant. There are basically two options employed: a single “vessel type” or “finger type”. Both types provide liquid separation and hold-up.

Slug Catcher design is an open art technology. Taylor Forge, Hanover Maloney, Sices, Cimtas, Bassi Luigi, Oilfield Production Equipment Ltd. and Rolle S.p.A are all slug catcher fabricators, some provide basic design others just fabricate other companies designs. Taylor Forge, one of the most renown in the industry, offers proprietary design for slug catchers and developed its finger “Harp” type slug catchers suitable for larger installations.

Taylor Forge’s “Harp Type” Slug catcher, shown in Figure 4.1.

Figure 4.1 Taylor Forge Harp Type Separator/Slug Catcher

“Finger Type” slug catcher, as seen in Figure 4.1 is a row of large diameter pipelines in which the gas/liquid mixture is injected at low velocity into a distribution manifold. The stream then splits at the distribution manifold into several smaller streams to allow uniform flow into the separation chambers. In the separation chambers, the majority of the gas liquid separation is accomplished. The required length, size and number of these chambers are a combined function of gas flow, gas chemistry and other known conditions. The primary function of the dry gas risers is to deliver dry gas back into the system. As some secondary separation occurs here, their sizing is important. The storage Harps hold the liquids at line pressure and the number and length of these Harps is determined by the storage requirements, i.e. slug size, if the system is two-phase, three-phase and the residence time desired. The liquid and slug manifolds provide separation of water, oil and debris. The oil and water are then removed from the storage end for further processing. The debris is cleaned out on an as needed basis.

This Harp Type slug catcher technology has been used in more than 50 plants around the world for gas processing capacities ranging from 3 MMSCFD to more than 4,000 MMSCFD.



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4.3 DEW POINT CONTROL TECHNOLOGIES

4.3.1 Water Dew Point Control

Several methods exist for the removal of water from a natural gas stream. This is to control the gases water dew point temperature to meet sales gas or LNG specification. Most commonly used processes for water dew point control include: dry/solid desiccant adsorption process (silica gel beds or molecular sieves beds) and liquid desiccant absorption process (solvent processes); some licensed processes used for gas dehydration are described below.

4.3.1.1 Molecular Sieves

Molecular sieves are used to reduce water concentration to less than 1ppm which is necessary for further downstream processing such as deep NGL recovery and LNG. Technology vendors such as UOP, CECA (Arkema Group), Zeochem and Grace are main suppliers in the gas industry and will provide full product design and the material. UOP and CECA, the two main players, offer products for all molecular sieve applications in the oil and gas industry. For example, UOP offers MOLSIV®, HgSIV®, COSMIN® and TRISIV® for various applications, CECA (Arkema group) offers SILIPORITE® molecular sieves and Grace produces and distributes SYLOSIV®, SYLOBEAD® and PHONOSORB® molecular sieves.

There is no typical process operating pressure as these are directly related to the feed gas conditions. Molecular sieves operate best below 50oC and regeneration temperature is often in the order of 200oC to 300oC. Molecular sieves for water removal are typically sold with a three year lifetime guaranty for a cycle time of 24 to 30 hours (i.e. cycle time includes absorption, heating and cooling of the beds) and a 5 year lifetime guaranty for a cycle time of 60 to 80 hours. The tendency for natural gas water dew pointing is to go to five years life time for a cycle time of 24 to 30 hours which can be achieved through good unit design, by using guard bed layers of activated alumina and an optimized regeneration procedure. This enhances the need for adsorbent producers to provide technical services, know-how and experience, for example CECA has developed a simulation program SIMATEP® for regeneration optimization.

4.3.1.2 Silica Gel

Silica gel dehydration is not a licensed process. Designs can be obtained from the manufacturers and these are typically the same as for molecular sieves described above, i.e. UOP, CECA, Zeochem, Grace and Engelhard. Silica gel dehydration system can also be sold as part of a package for example by NATCO and Petreco KCC Gas Processing Solutions. There is no typical process operating temperature and pressure as these are directly related to the feed gas conditions. Silica Gel regeneration temperature and pressure also depend on feed gas composition, pressure and temperature, however, regeneration temperature is often in the order of 200oC.

Silica gel adsorption technology can also be used for hydrocarbon dew point control as shown in Section 4.3.2.1. - SORDECO®.



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4.3.1.3 ECOTEG ®

The ECOTEG® process was developed and patented by SIIRTEC NIGI. The ECOTEG process is mainly used for the removal of water in feed gas with high BTEX concentration and is based on conventional glycol regeneration unit (i.e. stripping) in which the stripped gas is recycled into the process. The advantages of the ECOTEG ® process are that it releases no BTEX into the environment, consumes no stripping gas, needs no storage of gasoline and does not require incineration or water treatment of the recovered water stream. This process treats gas flow rates of up to 500 MSCFD with feed gas temperature of up to 60oC and feed gas pressure of up to 150 bar.

ECOTEG® has three different process arrangements, depending on the desired dew point depression. ECOTEG® -1 process, used for moderate dew point depression, is shown in Figure 4.2. In this process, a flash drum is placed at the exit of the absorption column in order to separate light hydrocarbons absorbed in the TEG solution. A large proportion of the gas stream produced from the flash drum is used as fuel for the stripper/reboiler firebox while the TEG/water solution is fed to the top of the stripper. The main characteristic of the ECOTEG® process is the fact that the stripping gas is recycled and not sent to a flare, which may be done in other processes. The vapors exiting the top of the stripper, which contain the stripping gas with evaporated water and BTEX, are cooled in the overhead cooler and separated in a three phase separator. The residual vapor from the separator is recycled as stripping gas. The water stream is then sent to an air stripper to reduce its BTEX concentration from 1,000 ppm to about 1 ppm, which is acceptable for direct disposal. The BTEX stream is recycled to the middle of the absorption column. This is done in order to saturate the TEG solution in the absorption tower, which would otherwise prevent further BTEX absorption into the solution and leave BTEX in the dry gas stream. The Lean TEG solution from the bottom of the stripper is recycled to the top of the absorption tower.

The other two ECOTEG® processes further treat the lean TEG solution exiting the bottom of the stripper. Further treatments involve the increase of TEG solution purity, i.e. by further dehydrating the stripping gas. This is done either with the addition of a small atmospheric absorber irrigated by the rich TEG to be regenerated and the stripping gas (ECOTEG® -2) or the addition of a second packed section to the additional ECOTEG®-2 tower, which is fed by lean TEG solution. This process is the ECOTEG® -3 and can achieve TEG concentration of 99.985 percent.

Operating conditions for ECOTEG® processes include:

Glycol circulation rates between 2.5-5 US gallons per pound of water to be removed

Regenerator stripping gas flow rate typically 3-5 SCF per US gallon of glycol recirculated and

Reboiler temperatures typically set at 200oC.



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4.3.1.4 Drizo®

DRIZO® is a glycol process licensed by Prosernat IFP Group Technologies and OPC Drizo, Inc. This process involves the contact between the “wet” feed gas and a glycol solution (DEG, TEG or tetraethylene glycol) in an absorption column or absorber, as shown in Figure 4.3. This process can be used to remove water and heavy hydrocarbons such as aromatics (BTEX) from natural gas streams.

Water, heavy hydrocarbons and aromatic components are absorbed in the glycol solution to create a wet glycol stream. The wet glycol stream is then heated and flashed to remove the lighter absorbed. As shown in Figure 4.3, the liquid stream from the flash drum, containing water, glycol and hydrocarbons, is thermally regenerated in a reboiler. The regenerated glycol stream exiting the bottom of the reboiler is recycled as solvent at the top of the absorber. The gas stream exiting the top of the reboiler is cooled and is then fed to a still column in which the gas, water and condensed hydrocarbon streams are separated. The water is used as reflux to the reboiler.

To date, more than 45 units have been put into commercial operation around the world. This process is typically used for water dew point depression of up to 180oF (80oC) and is said to be competitive at water dew point below -30oC. Glycol purity as high as 99.99 wt% can be achieved, thus enabling residual water content in the treated gas down to below 1 ppm. In addition, no external stripping gas is required and all BTEX compounds are recovered from the vapor before release to the atmosphere.

4.3.2 Water and Hydrocarbon Dew Point Control

Processes have been developed which achieve simultaneous water and hydrocarbon dew point control through removal of both heavy hydrocarbons and water. The main processes used for both water and hydrocarbon dew point control include solid bed adsorption process such as the Sordeco® Process or the ADAPT (Advantica Ltd.) process. Other processes such as J-T valves and/or refrigeration processes, used in conjunction with solvent (glycol or methanol solution) dehydration and recovery, such as the IFPEXOL process, could also be considered as a one step water and hydrocarbon dew point control to meet sales gas specification.

4.3.2.1 SORDECO®

SORDECO®, licensed by Shell Global solution International B.V. in co-operation with Engelhard, is a solid bed absorption process which selectively removes water and heavy hydrocarbons, typically C5+, from a natural gas stream. This process typically extracts 40 percent of C5 and 85 percent C6+ from the natural gas feed and would be considered economical for lean feed gases (i.e. typically 0.4 mol percent C6+) and where water dewpoint specification are not too stringent (i.e. <20pppmv). The SORDECO process uses Sorbead adsorbent which is a special grade of silica gel manufactured by Engelhard. The gas is fed at the top of an absorption column in which the adsorbent selectively removes water and hydrocarbons from the natural gas feed. When the adsorbent is saturated, it is generated by stripping with hot regeneration gas, i.e. treated gas exiting the furnace. The hot gas stream exiting the adsorption column is then cooled, and heavy hydrocarbons and water condense and are then separated. In a typical natural gas plant, up to four adsorbers are used to allow for on-line regeneration.



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SORDECO is typically used for low pressure feed gas stream (< 100 bar) or when limited pressure drops over the treating unit is allowed. Engelhard’s Sorbead adsorbent is used in over 200 natural gas processing units worldwide. This process is known to be used for plant capacity of up to 200 MMSCFD and is usually the preferred process option for the treatment of lean gases.

4.3.2.2 IFPEXOL

IFPEXOL is a methanol-based solvent, developed by the Institut Francais du Petrole (IFP) and licensed by Prosernat IFP Group Technologies. This process can be used to remove water and hydrocarbons from natural gas streams. Figure 4.5 shows a process for the removal of water and condensate. A slip stream of raw gas is contacted against a mixture of solvent and water entering the top of a contactor. The ambient heat of the incoming raw gas is sufficient to completely strip the solvent from the water such that high purity water is obtained as a bottom liquid product. A solvent rich gas slip stream leaves the top of the contactor and is recombined with the main feed gas flow. This stream contains sufficient solvent to act as a hydrate inhibitor as the gas is cooled in the gas chilling process by any appropriate means - Joule-Thomson expansion (as shown here), turbo expander or external refrigeration. Depending on process and feed conditions, NGLs could also be recovered in this process. A three phase separator is then used to separate sales gas, condensate and the solvent/water mixture which is returned to the contactor.

The IFPEXOL process does not require a heated reboiler for solvent regeneration, unlike conventional glycol absorption or injection dehydration schemes, thus saving on capital and operating costs. The process also avoids emissions of solvent, however, water vapor leaving the top of a glycol regeneration may still contain some glycol which itself may contain aromatics. This stream may therefore require further treatment in order to remove aromatics present.

To date, 15 IFPEXOL units have been put into commercial operation with capacities of up to 350 MMSFCD. Depending on process and feed conditions, this process can achieve water dew point of around -30oC and hydrocarbon dew point down to - 100oC, at standard pressure.



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4.4 IMPURITY REMOVAL TECHNOLOGIES

4.4.1 Acid Gas Removal

Acid gas removal technology is well established from numerous applications in natural gas treating units installed worldwide. In their basic form, the units employ open art designs. However proprietary processes have been developed around amines and other solvents where additives can be added to improve such properties as selectivity for H2S, energy consumption, and corrosion resistance.

Conventional amine processes, the most widely used method to remove acid gases from natural gas, are typically used for bulk and trace removal of both hydrogen sulfide and carbon dioxide. Selective hydrogen sulfide removal is usually achieved by absorption on tertiary amines such as in the aMDEA® process (BASF), the Omnisulf® process (Lurgi GmbH), and the sMDEATM process (BASF). The process flow diagram for a typical amine process can be found in Section 3, Figure 3.14.

A combination of amine with other chemicals can be used, for example, for gases with higher acid gas content. This is achieved, for example, in the BenfieldTM process (UOP) using potassium carbonate (K2CO3) solution mixed with amine. The Benfield process is described in Section 4.4.1.1. The Sulfinol® Process (Shell International Petroleum Co., Ltd) also uses a mixture of amine, water and a proprietary solvent, Sulfolane (tetrahydrothiophene dioxide), which combines the chemical absorption properties of amines and the physical absorption properties of Sulfolane.

Hybrid chemical/physical solvents were also developed, such as the UCARSOLTM, a family of solvent developed by the Dow Chemical Company. Their products include LE 701, LE 702 and LE 703 that are used in the Amine Guard FS (UOP) process. The Vetrocoke process, developed by Giammarco-Vetrocoke, an Italian company, uses a hybrid physical-chemical absorbent process from the N-formylmorpholine family (US Patent 4080424). In addition, the Selexol Process (UOP) uses union Carbide’s Selexol solvent, a physical solvent made of dimethyl ether of polyethylene glycol and the Morphysorb process developed by BASF uses N-acetylmorpholine solvent. These solvents can be used for deep H2S removal, bulk CO2 removal and trace sulfur (e.g., mercaptans and carbonyl sulfide) removal.

4.4.1.1 Benfield

The Benfield process, licensed by UOP, uses a chemical absorbing solvent to remove CO2, H2S and other acid gas components. The solvent is based on 30 percent potassium carbonate (K2CO3) in water plus an activator and corrosion inhibitor. The activator, which is added to the solvent to enhance the absorption rate of CO2, is an amine such as DEA (diethanolamine) or UOP proprietary chemical ACT-1, which is claimed to be more stable and more resistant to degradation than DEA. This process is also used for bulk CO2 removal for example in ammonia plants. To date, 700 units are in operation worldwide with 65 treating natural gas. A process flow diagram is shown in Figure 4.6.



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The gas to be treated is fed into an absorption column in which the acid gas reacts with the solvent. The rich solvent is then fed to the top of the regenerator/stripper column in which the concentrated acid gas exits the top of the column and then partly condensed in a flash drum to allow for reflux. The lean solution exiting the bottom of the regeneration column is fed back into the top of the Benfield Absorber. This process is particularly suitable for high concentration of acid gas in the feed. Typical feed conditions range between 150 psia (10 bar) and 1,800 psia (120 bar) with acid gas compositions (H2S + CO2) from five percent to more than 35 percent by volume. Residual CO2 and H2S concentration in the treated gas can be in the order of a few ppm to a few percent, depending on the rich/feed gas conditions and composition. The acid gases by-products can then re-injected in the gas reservoir, exported to a Claus process or to an incinerator for further purification and sulfur recovery.

4.4.1.2 SELEXOL

The SELEXOL process was introduce over 30 years ago and over 50 units have been put into commercial service. The process, licensed by UOP, is a solvent absorption process ideally suited for the selective removal or for the bulk removal of CO2 SELEXOL also removes COS and mercaptans, which are difficult to remove with amines. The SELEXOL process uses Union Carbide Selexol solvent, a physical solvent made of dimethyl ether of polyethylene glycol, which is inert and not subject to degradation. Typical feed conditions range between 300 psia (20 bar) and 2,000 psia (130 bar) with acid gas composition (H2S + CO2) from five percent to more than 60 percent by volume. A flow scheme is shown in Figure 4.7.

Feed gas enters the bottom of the absorber column where it is contacted against descending solvent. The components to be removed are physically absorbed into the solvent, which passes out of the bottom of the column while treated gas leaves at the top. Regeneration of the solvent is achieved by thermal regeneration in a stripper. The regenerated solvent is cooled and returned to the main absorber.

The application of this process is dependent on the conditions and composition of the incoming gas stream. Being a physical absorption process, the proportion of a component absorbed is, in part, proportional to the component partial pressure in the feed gas. The component must be present in sufficient quantity to provide an adequate concentration, which is the driving force for effective absorption.

4.4.2 Mercury Removal

As seen in Section 3, the need for mercury removal is required before cryogenic processes such as the one used for deep ethane extraction or LNG production. Processes for mercury removal are similar to solid bed dehydration and are also open art design although companies such as UOP, Axens or JGC Corporation provide design, support and the material required for mercury removal.



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Typical process flow diagram for mercury removal is very similar to other solid adsorbent processes such as the one used for gas dehydration using molecular sieves, as shown in Section 3, Figure 3.12. This is due to the fact that mercury can be adsorbed onto a solid to produce a gas stream with less than 1 ppt mercury concentration. Materials used for mercury removal are proprietary solids such as, for example, the Axens CMG 275 adsorbent, a sulfur on alumina pellets or bead, and UOP HgSIVTM adsorbent, a silver coated molecular sieve sold as pellet or bead.

UOP, as part of their work to develop molecular sieve used to remove mercury, proposes to combine the dehydration unit with the mercury removal unit. UOP has installed HgSIVTM adsorbent in over 25 gas dryers around the world which treated feed gas mercury content from 25 to 50 μg/Nm3 (2.5 to 5.0 ppb) down to 0.01 μg/Nm3 (1 ppt). The pressure and temperature of the adsorption column depends on feed gas temperature and pressure. Typical gas feed pressure would range between 150 psia (10 bar) and 1,800 psia (120 bar), whereas, feed gas temperature would be in the order of 70oF (20oC). Regeneration would occur at feed pressure and similar temperature used in the gas dehydration process, i.e. 200 F (100oC) to 500oF (250oC).

4.4.3 Nitrogen and Helium Removal

Removal of nitrogen may be required if it is present in large enough concentration to give an unacceptably low gas calorific value and are most commonly removed in LNG plants or other plants operating at cryogenic temperature (e.g. deep ethane recovery). Helium, like nitrogen, is an inert gas but is rarely present in large concentrations in natural gas. However, in a few cases, it is present in sufficiently large quantity to justify its extraction as a valuable by product. Cryogenic or solvent processes are usually employed for nitrogen and helium removal.

4.4.3.1 Cryogenic Processes

Suppliers of cryogenic nitrogen and helium rejection units are, for example, Costain, Oil, Gas & Processes Ltd with their double-column process for nitrogen rejection and UOP’s PolybedTM PSA Technology. Both of these processes use cryogenic technology for nitrogen removal, and it is suggested that overall economics can be improved by integrating the recovery of natural gas liquids (NGLs) with the nitrogen rejection unit.

Natural gas stream with between eight percent and 80 percent nitrogen can be treated in the Costain process and gases with pressure above 27 bar typically do not need recompression. A simplified process flow diagram is provided in Figure 4.8; the feed gas to this process is treated gas, i.e. dehydrated and free of carbon dioxide, that may freezes in the cryogenic section of the process.



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4.4.3.2 Solvent Processes

Another method for Nitrogen rejection, which does not involve cryogenic processes, involves the absorption of hydrocarbon, including methane, on paraffinic solvents having molecular weights ranging from 75 to 140 or naphthenic solvents having molecular weights ranging from 75 to 130, as it is the case in the Mehra Process from Advanced Extraction Technologies, Inc. (patent US4883515). This process treats the gas in two columns at different pressures. The first column, the extractor, in which the gas contacts the solvents is at the feed gas pressure and temperature, which is typically above 500 psia (30 bar). The second column, the stripper column, which recovers the solvent and produces the sales gas stream operates at no more than 500 psia (30 bar). The gas exiting the stripper can be compressed to meet sales gas specifications.

The process for nitrogen rejection is similar to the one used for lean oil absorption used in NGL recovery. In the Mehra process, as shown in Figure 4.9, the feed gas is cooled to -25oF (- 30oC) in a propane refrigerant heat exchanger and the liquid NGL are separated from the gas before is enters the absorber. All hydrocarbons present in the feed gas to the absorber will be absorbed in the solvent, with a nitrogen stream leaving the top of the absorber. The liquid stream leaving the bottom of the absorber is then flashed at lower pressure in order to strip the solvent of lighter hydrocarbon. This light hydrocarbon stream is then sold as sales gas. This stream may need recompression to meet sales gas specifications.



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Section 5 Emerging Technologies

A number of patents pertaining to developments in unit processes within the field of gas processing have been awarded in recent years. The fundamental technology advancements have occurred in the areas of hydrate prevention, dehydration, acid gas removal and desulfurization. Optimization objectives have included increasing control over the gas specification, reduction in energy, inhibitor inventory and waste generation, improved catalysts, and reduction of capital costs through improved technologies and design.

5.1 DEHYDRATION

5.1.1 Kinetic Inhibitors

Thermodynamic hydrate inhibitors, such as methanol or glycols, have traditionally been used to prevent hydrate formations. However, in order to be effective, thermodynamic hydrate inhibitors may be used at very high concentrations leading to high hydrate inhibitor circulation rate. This high volume complicates spacing requirements, logistics, and inventory management. As a result, low dosage hydrate inhibitors (LDHI) have been developed, which allow for control of hydrate formation at dosage rates much lower than those for thermodynamic hydrate inhibitors.

The most common of the LDHI are kinetic inhibitors or kinetic hydrate inhibitors (KHI). Unlike thermodynamic hydrate inhibitors, KHI do not alter the fundamental hydrate formation properties of the fluid. Instead, they interfere with the growth of hydrate crystals. KHI generally includes organic moieties with size and shape similar to the dimensions of an active growing site in the hydrate’s water lattice.

The KHI occupies the active site, preventing further addition of water molecules to the lattice and hence stopping its growth. Over a long period of time, a KHI in a static system will be completely consumed, such that additional hydrate nucleation sites will grow without inhibition. Hence, KHI do not actually prevent hydrate crystal growth, they postpone it. Once the inhibited hydrate nuclei pass into a production zone whose temperature or pressure lie outside the hydrate region, they dissolve harmlessly.

Examples of kinetic hydrate inhibitors include poly(N-methylacrylamide), poly(N,N-dimethylacrylamide), poly(N-ethylacrylamide), poly(N,N-diethylacrylamide), poly(N-methyl-N-vinylacetamide), poly(2-ethyloxazoline), poly(N-vinylpyrrolidone), and poly(N-vinylcaprolactam).

5.1.1.1 Champion – Gas TreatTM HI

Champion’s line of Gas TreatTM HI kinetic hydrate inhibitors includes products formulated for high and low pressure situations, with or without water ice inhibition properties. Gas TreatTM HI products can free a customer’s asset from the logistical and hazard issues, which accompany the use of methanol as a thermodynamic hydrate inhibitor. Unit costs decrease while production remains steady, and all without the space constraints or hazard management required with thermodynamic inhibitors like methanol.



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5.1.1.2 Baker Petrolite – HI M PACTI

Baker Petrolite’s LDHI product line is designed to provide control of hydrates in hydrocarbon production and transmission systems operating specifically under mild to moderate sub cooling. Baker Petrolite HI M PACT kinetic hydrate inhibitors represent the third generation of KHI, applied by continuous low dosage injection into the systems, typically at one to five percent of water volume.

HI M PACT KHI can also be used in conjunction with methanol or ethylene glycol, allowing a significant reduction in the dosage rate of these inhibitors.

For a recent hydrate problem in a gas pipeline in the US northeast, Baker Petrolite formulated H M PACT 5441 KHI. The formulation corresponded to a rate of one to two quarts per day, which was 0.9 percent of the water volume for application. With a pour point of - 40ºF, the product is easily employed in cold winter weather. Through the use of the product, the operator was able to protect the pipeline from hydrate blockages, reduce pigging frequency, maintain pipeline up-time, and potentially eliminate the need for a dehydrator unit.

5.1.1.3 M-I SWACO – HYDRABLOCK*

Deepwater is an ideal breeding ground for the growth of gas hydrates, and when these ice-like crystals form in the circulating system, attempts to manage them can be costly and dangerous. M-I SWACO has developed techniques and products to control the formation of hydrate crystals and impede the operation of critical offshore drilling and circulation equipment.

Besides targeting full primary and secondary thermodynamic inhibition, M-I SWACO models and hydrate testing apparatus allow temperature and pressure conditions at the mud line to be simulated in the laboratory. There, drilling fluid rate formulated in combination with various inhibitors to develop hydrate-inhibitive drilling fluid systems that are customized for particular offshore drilling projects. This extensive research into gas hydrates has led to the development of HYDRABLOK* inhibitor. This advanced deepwater product represents one of the latest efforts to provide protection against gas hydrate formation in the deepwater and ultra-deepwater where thermodynamic inhibition often is not possible.



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5.2 WATER DEW POINT CONTROL

5.2.1 Regenerative Desiccants

5.2.1.1 MATCO – DESI_DRIC®SYSTEM

NATCO’s desiccants are various blends of alkali-earth halide salts that have varying degrees of hydro-scopicity. Depending on the specific application, either a single DESI-DRI desiccant or a series of increasingly hygroscopic desiccants can provide exactly the gas dryness needed. The DESI-DRI® System is a complete line of proprietary desiccants and eutectics gives operators a cost effective solution for many dehydration applications.

With the NATCO DESI-DRI Dehydration system wet gas flows upward through one or a series of vessels that contain deliquescing beds with any one of five DESI-DRI desiccants. As wet gas contacts the DESI-DRI tablets, moisture is removed from the gas and accumulates on the surface of the tablets. Eventually, enough water accumulates to cause a droplet of brine to form. In time, the brine makes its way down to a brine sump in the bottom of a vessel, collecting even more moisture in the process. Periodically, the brine is purged to an environmentally safe location. There is no need for regeneration. New DESI-DRI tablets are used to replenish the beds at a rate consistent with operational requirements.

New salt formulations enable deliquescing desiccants to dry to pipeline specifications in many while using these grades in series to minimize operating costs. The new approach offers an integrated system, where piping, gas flows, dryer design and desiccant performance are all considered. New technology enables dry gas at nearly two feet per second, compared with traditional velocities of 0.5 - 0.75 ft/s, while at the same time greatly increasing the amount of water removed per pound of desiccant (referred as “dilution rate”). Flowing through a low grade, low cost desiccant first removes most of the water vapor. Then gas is further dried using higher-grade (more hygroscopic) desiccants. New dry tableting technology also produces a hard, non-porous, low permeability tablet. Hydration can only occur on the outside of the tablet, which helps to maintain its general shape as it is consumed. Flow efficiency remains relatively constant as the tablet bed is consumed.

Since deliquescing desiccant systems are closed, there are no volatile organic compounds (VOC) or aromatic hydrocarbon (BTEX) emissions. With new EPA Clean Air Act regulations

now in

place this advantage alone often makes deliquescing desiccants a better choice over triethylene glycol (TEG).



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5.3 ACID GAS REMOVAL

5.3.1 Membrane Systems

5.3.1.1 Engelhard – Gate®

The Engelhard – Gate® adsorption system is a new and unique technology developed and patented, which was installed in Southern Illinois to remove N2 and CO2 from coal mine gas.

Unlike other technologies, Engelhard Molecular Gate® adsorption system removes N2 and CO2 in a single, step and provides high on-stream factors with minimal operator attention. It is gaining further market acceptance with eight units either in operation or fabrication with flows up to 10 MM SCFD.

Engelhard – Gate® uses molecular sieves technology with pore size precisely manufactured within an accuracy of 0.1 angstrom. Nitrogen will be adsorbed in a 3.7 angstroms (Å) opening, whereas carbon dioxide will be adsorbed in a 3.3 Å opening. Engelhard –Gate® is an adsorption process which uses pressure swing adsorption (i.e. decrease in pressure or so called PSA) for molecular gate adsorbent regeneration, as apposed to temperature swing adsorption (heat regeneration or so called TSA) which is typically used in solid desiccant natural gas dehydration. This process is illustrated in Figure 5.1.

The system is offered as a prefabricated, modular system based on patented adsorbent materials. Molecular Gate® is generating significant interest in the natural gas industry. It is easy start-up, unattended operation, and located at the natural gas wellhead, the Southern Illinois unit is powered on-site using tail gas generated by the process. No pre-treatment other than dehydration is required and the system can remove CO2 along with nitrogen in a single step. The system recovers 90-95 percent of the methane as sales gas and the rejected nitrogen containing “tail gas” is normally used as fuel to gas engines or other local uses. In CO2 removal, water and CO2 is removed in a single step, again with product methane delivered at high pressure. Cost is generally 20 percent lower than amine processing. Due to the impurity being removed from the methane, the system can always achieve pipeline specifications regardless of the feed composition.

At the facility in Southern Illinois, the system is designed to reduce nitrogen levels in the natural gas from up to ten percent to the local pipeline specification of four percent. It also removes water and carbon dioxide (CO2) from the gas and can treat up to one million standard cubic feet per day (1 MM SCFD). The purified natural gas is then sold to an interstate transmission pipeline. Other treatment methods have proved too costly for developing the coalmine for natural gas recovery.



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5.3.2 Solvent Based Systems

5.3.2.1 BASF – Amine process – Morphysorb®

The UHDE Morphysorb® process is an acid gas removal technology based on the use of a physical solvent supplied by BASF. The key advantage of Morphysorb® technology is a high acid gas capacity coupled with low solubility of methane to propane hydrocarbons, resulting in a higher product shield. Morphysorb® is capable of removing organic sulfur compounds (mercanptans, CS2 and COS) from the feed gas at the same time. Due to high selectivity of the solvent, the Morphysorb® process is capable of generating an acid gas stream that is suitable for a Claus plant.

Duke Energy Gas Transmission Corp. (DEGT) started up the first commercial application of the morphysorb process at its 300 MMSFD Kwoen gas plant in August 2002. The solvent showed a higher relative absorption of acid-gas compounds compared to competitive solvent, which lowered circulation rates.

Morphysorb® is part of the morpholine chemical family, used since 1968 as N-formylmorpholine (NFM) to recover high purity aromatics and separate butane and propane, as used in the Morphylane, Morphylex and Butenex processes. Morphysorb technology uses mixture of NFM and N-acetylmorpholine as solvent to remove carbon dioxide and hydrogen sulfide. The solvent has lower relative absorption of higher hydrocarbon, which results in fewer losses and more heating value in the sales gas.

Because of its hydrophilic characteristics, the solvent can also dehydrate simultaneously. Conversely, no additional dehydration step is required downstream from a Morphysorb unit if the feed gas is already dehydrated. Morphysorb® process owned by Uhde, the solvent is manufactured by BASF AG.

5.3.2.2 Dow Chemical – GAS/SPEC CS-2000

Dow Chemical Company is introducing GAS/SPEC CS-2000 formulated amine for removing large amounts of carbon dioxide from natural gas streams. When present, carbon dioxide reduces the BTU value of natural gas. It is also corrosive and freezes at a relatively high temperature, forming blocks of "dry" ice that can clog equipment lines and damage pumps. Its removal is an important step in the successful treatment of natural gas.

GAS/SPEC CS-2000 Solvent is designed to efficiently remove carbon dioxide levels from several percentage points down to parts per million, more efficiently than other commercially available solvents. The best known amines for gas treating applications are MEA (monoethanolamine) and DEA (diethanolamine). Many are still used for bulk carbon dioxide removal. Without the use of heavy metal corrosion inhibitors, the concentration and loading of these products must be limited to minimize equipment corrosion. For example, MEA is generally limited to less than 20 percent weight in solution and operated with a maximum carbon dioxide loading of 0.30 to 0.4 mole carbon dioxide/mole amine and DEA is usually maintained at less than 30 weight percent and 0.40 to 0.7 mole/mole loading.



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In contrast, GAS/SPEC CS-2000 Solvent can be used in concentrations up to 55% in solution and 0.45 mole/mole loading. This additional capacity allows an existing plant to expand its carbon dioxide removal capacity with less potential for equipment wear caused by corrosion. GAS/SPEC CS-2000 represents the latest in several decades of research and development in the field of gas treating by Dow Chemical.

5.3.2.3 FLUOR Solvent TM This technology is a physical solvent based gas treating configurations for removing acid gas from high pressure natural gas streams. The processes are targeted for offshore applications where the feed gas CO2 partial pressure is above 60 psia. These new configurations are based on the physical solvent propylene carbonate (FLUOR Solvent TM).

The advantages of these new configurations include no fired duty for solvent regeneration, high CO2 solubility (SCF CO2/gallon solution), no process makeup water requirements, minimal hydrocarbon losses, operational simplicity, and a dry treated gas.

Another advantage of the FLUOR Solvent process is minimal winterization requirements. Propylene carbonate freezes at –57°F in comparison to about 20-30°F for many amine processes. Other advantages are plant simplicity and ease of operation, all carbon steel construction with no stress relieving, no fired heat duty required for solvent regeneration, minimal solvent foaming tendency, no corrosion, and minimal environmental impacts due to the use of a biodegradable solvent.

5.3.3 Biological Systems 5.3.3.1 CCR Technologies – Desulphurization Biotechnology The technology utilizes naturally occurring Thiobacillus organisms to purify natural gas to sales gas specifications by converting hydrogen sulfide to solid, fertilizer grade sulfur. The process to sweeten sour gas eliminates the need for continuous flaring and virtually eliminates hydrogen sulfide emissions from sour gas facility vents.

This biological gas desulfurization process is licensed by New Paradigm Gas Processing Ltd., a wholly owned subsidiary of CCR.

Scientists first became aware of the significance of naturally occurring sulfur-converting micro organisms through the discovery of deep-sea hydrothermal vents, several kilometers below the ocean's surface. These types of organisms, found virtually everywhere on earth, have since been identified as one of the primary reasons the earth is able to sustain biological life.

Although in 1992, Shell Global Solutions International B.V., together with Paques Bio Systems in Holland commercialized a breakthrough gas treatment technology utilizing sulfur-converting micro organisms, the process is still considered an emerging technology because of its rather limited application worldwide.

CCR Technologies is a technology solutions company focused on the purification of process chemicals and sweetening of sour gas through the innovative use of proprietary patented technologies. New Paradigm Gas Processing Ltd., a wholly owned subsidiary of CCR Technologies, is the authorized licensor of the Biological Gas Desulfurization Technology for natural gas applications within Canada.


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Section 6 Economics

6.1 OVERVIEW

The economic evaluation of gas processing can be a complex matter and a number of possibilities exist for comparing and contrasting the costs associated with natural gas processing to meet sales gas (pipeline) specification. This is due to the variety of process technology available and the number of applications to which each technology may be applied (i.e. various degree of treatment possible). The feed gas or wellhead gas composition, pressure and temperature as well as the level of treatment required will greatly influence the choice of technology to be used and typically more than one method may be technically appropriate for a given feed gas composition and sales gas specification.

A gas composition was chosen based on Nexant’s industry knowledge and feed gas temperature and pressure were also determined based on Nexant’s industry knowledge. As this study does not cover the cost of producing gas at the well which is very much dependent on the location of the reserves and the reservoir properties, an average wellhead production cost for the Middle East will be used. Although the study team has considered several processes which would achieve a defined sales gas specification based on the chosen feed gas composition, temperature and pressure, only the capital and operating costs for the reference or basic case will be analyzed in depth here.

This basic process comprises gas reception facilities (which includes slug catcher, bulk condensate separation and filtration of particles and fines); stabilization of condensate using LP separation; an amine (MDEA) unit for selective acid gas removal; a sulfur recovery unit with tail gas treatment for disposal of the resulting sour gas; gas cooling; water removal by TEG contacting; and finally hydrocarbon dew point control by mechanical refrigeration to meet dew point specifications. However, there are many alternatives that might also be considered depending upon circumstances, which are describe in Sections 3 and 4 of this report and will not be discussed further here.

A plant of design capacity of 650 MMCFD was chosen as the base case for this analysis since this represents a world scale single train gas processing facility, such as the one currently being built in the Middle East. This study focuses on the Middle East as it is the most dynamic region for the development of gas processing capacity (refer to Section 7).

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6.2 BASIS OF DESIGN

The economic analysis is based on a raw gas composition as shown in Table 6.1.

Table 6.1 Raw and Sales Gas Composition (compositions in mole percent)

Raw Gas Sales Gas Mole Percent Base Case

Water 0.02 0.00 Carbon Dioxide 2.00 1.1 Nitrogen 0.60 4.20 H2S 4.00 0.001 Methane 81.98 86.0 Ethane 5.00 5.2 Propane 2.00 2.1 Iso - Butane 0.50 0.45 normal Butane 0.70 0.57 Iso - Pentane 0.20 0.12 normal Pentane 0.20 0.10 n-Hexane 0.40 0.09 n-Heptane 0.40 0.03 n-Octane 0.50 0.01 n-Nonane 0.30 0.001 n-Decane plus 1.20 0.0003 Total 100.0 100.0 Mercaptans (ppmv) 50 <50 Heating Value (HHV Btu/scf) 1159 1062 Wobbe Index 1356 1317 Dew Point @ 40 Bar (oC) 57 - 5 Molecular Weight (kg/kmol) 21.11 18.82 Specific Gravity (air = 1) 0.73 0.65 Pressure (Bar) 80 70

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Feed gas will be processed to meet a typical sales gas specification for transmission and distribution, such as the ones presented in Table 6.1. 99.9 percent of the Hydrogen sulfide in the feed gas is removed in the acid gas removal unit to meet pipeline specifications. The treated gas dew point is specified at less than -5oC for a HHV of more than 950 BTU/scf. The Nexant study team has selected the process which would achieve sales gas specification based on the chosen feed gas composition, temperature and pressure as follows:

Gas reception facilities comprising a finger type slug catcher, followed by gas filtration, gas cooling and stabilization of the separated natural gas liquids (NGL). A two stage compressor is needed to return the stabilizer overhead gas to the process;

Absorption of the acid gas in a contactor column using a circulating lean amine (MDEA). After regeneration of the rich amine the offgas is sent to a Claus unit with two catalytic reaction stages and tail gas treating by selective oxidation to achieve 99.9 percent sulfur recovery;

Cooling and dehydration of the sweetened gas from the amine contactor. The gas is refrigerated to 25oC to reduce the water content of the gas before dehydration; the gas then enters the TEG contactor for further dehydration. TEG is recovered and recycled to the TEG contactor.

A hydrocarbon dew point control unit using propane refrigeration. Separated NGL is recycled to the stabilizer;

Gas metering for export.

Storage and pumping of the recovered hydrocarbon condensate (oil/NGL) stream.

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6.3 COST OF PRODUCTION BASIS

6.3.1 Battery Limits

Plant capital normally consists of two key cost elements, i.e. the capital for inside battery limits (ISBL) facilities and capital for outside battery limits (OSBL) facilities. For this study investment costs assume a two year construction period in the Middle East starting in the First Quarter of 2006. Nexant ChemSystems, has developed its own methodology for assessment of working capital and other project costs for a particular facility based on monthly operations. All these costs contribute to the total capital investment for the plant.

Production costs basically include four different cost components: variable costs, direct fixed costs, allocated fixed costs, and financing costs. Variable costs are costs for raw materials, by-product credit, and utilities. Direct fixed costs constitute direct operating costs from labor cost, maintenance, and associated overhead charges. Allocated fixed costs include general plant overhead, insurance and property taxes set as a proportion of total plant capital. The sum of variable, direct, and allocated fixed costs becomes the total cash cost of production. To estimate the full cost of production, cost of financing is then added to the total cash cost. Two components contribute to the financing costs: depreciation and return on investment.

For consistency and simplicity, the uniform percentages, shown in Table 6.2, are employed in calculating certain elements of the cost of production estimates for all processes in this study regardless of the individual nature of the processes.

Table 6.2 Assumptions Used for Estimating Certain Elements of the Cost of Production

Cost Element Basis Middle East

Other Project Costs % of Total Plant Capital 25Working Capital % of Total Capital Investment 10

Maintenance (Materials and Labour) % of ISBL 3Direct Overhead % of Labor & Supervision 85Interest on Working Capital % of Working Capital 10General Plant Overhead % of Direct Fixed Costs 45Insurance, Property Tax, etc % of Total Plant Capital 1.5

Depreciation % of ISBL & Other Project Costs 10% of OSBL 5

Environmental levy is not considered in this study and Outside Battery Limit (OSBL) was taken constant at 100 percent of ISBL. This OSBL cost covers, for example, utilities, condensate storage, condensate stabilization, offsites such as drains and flares; and infrastructure such as roads and administration buildings.

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6.3.2 Utilities and Services

Utilities required for onshore gas processing include, for example, electric power for motors, tracing and compressors, steam for boilers, instrument and plant air, nitrogen for purging, potable water, and fire water. These utility requirement, vary greatly depending on process condition, feed gas condition and sales gas specification. Consequently, only the largest utility costs, including for example steam for MDEA regeneration or power for propane refrigerant compressor, will be included in this analysis. Utility requirements for the chosen base case process are shown in Table 6.3.

Table 6.3 Utility Consumption

LP Steam MP Steam Power(ton/hr) (ton/hr) (MW)

Gas Reception FacilitiesSlug Catcher - - -

Acid Gas Removal UnitMDEA Regeneration 75.0 - -Amine Pump - - 1.0

Gas Dehydration - - -TEG Reboiler - - 0.5

Sulphur Recovery - - -SRU & TGU (8.0) (5.0) 1.0

Dew Point Control UnitPropane Refrigerant Compressor - - 6.0

NGL StabilizationStabilizer - 20.0 -Stabiliser Offgas Compression - - 1.5NGL Pumps - - 0.5Coolers and Pumps - - 1.5

The costs of chemicals used in the process such as amine and glycol are not included in this study and the plant operates for 8,000 hours per year.

6.3.3 By-Product credit

A condensate stream, composed mainly of C5+ components entering the gas processing facility, is recovered from the gas reception facility (slug catcher) and from the hydrocarbon dew point control step of the process. These streams are mixed and stored after stabilization. This stream could feed an NGL fractionation unit (not included in this study) and will therefore be sold as a separate single stream at a transfer cost. This revenue will be added as by-product credit into the cost of production analysis.

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6.3.4 Pricing Basis Nexant’s product prices, labor and utility costs forecasts for 2008 in the Middle East used in the Cost of Production analyses, are given in Table 6.4.

Table 6.4 Summary of Raw Material, Utility, Product and Labor Costs (2008, Middle East Prices)

Middle EastProduct PricesCondensate $/ton 30

UtilitiesPower $/MWh 40.5LP Steam (50 psi) $/Ton 4.3MP Steam (200 psi) $/Ton 4.6

LaborLaborers $/Year 7 200Foremen $/Year 30 700Supervisors $/Year 75 300

6.3.5 Gas Shrinkage

The reduction in volume of raw natural gas due to the extraction of some of its constituents, such as hydrocarbon products (condensates and NGL, where applicable), hydrogen sulfide, carbon dioxide, nitrogen, helium, and water vapor is known as gas shrinkage. Gas shrinkage in a plant where a large quantity of hydrocarbon is removed from the sales gas represents a loss in revenue for the sales gas which must be considered in the economics of a gas processing plant.

Gas shrinkage is calculated based on feed gas composition used and sales/treated gas composition derived from process simulations, as shown in Table 6.5.

The thermal value of shrinkage represents the opportunity cost of the extracted condensates in terms of the value they would have if they had been left in the sales gas. To illustrate this, shrinkage value calculation, for a sales gas value of 0.75 $/MMBTU, is shown in Table 6.6.

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Tabl

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The selected process produces 620 MMSCFD of treated natural gas, which is equivalent to a gas shrinkage of 30MMSCFD. This would reduce the gas value, based on a fuel gas price of $0.75 per MMBTU, by $26 million per year equivalent to a loss of more than 12 percent of annual revenues.

Table 6.6 Calculation of Shrinkage(2)

Raw Gas Sales Gas ShrinkageFlow kmol/hr 32 379 30 850 1 529

MMSCFD 650 620 30Gross Heating Value Btu/scf 1 159 1 062Thermal Flow MMBTU/d 753 259 658 389 94 870Thermal Value $ million/ year 206 180 26

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6.4 COST OF PRODUCTION

The total built-up production cost from wellhead to sales gas specification for both processes considered is based on gas shrinkage value, cash costs and capital charges estimates. Average costs are calculated on the basis of the volume of gas treated (per unit MMSCFD), then converted per unit of energy of the gas (MMBTU).

6.4.1 Wellhead Extraction

Cost of producing gas very much depends on the location of the reserves and will vary greatly depending on field location (offshore or onshore), depth below surface, reservoir pressure, reservoir temperature, impurity content and the distance to the gas processing plant. Various technology developments have occurred over the past few years that have lowered gas production costs. These include:

Use of 3D seismic

Deviate and horizontal drilling techniques for wells, minimizing the total number of wells that need to be drilled for a dispersed reservoir system

Subsea wellheads

Offshore unmanned platforms and floating production systems

Multiphase pipeline for transport of well fluids to processing plants.

Gas Development costs (Investment Costs + Operating Costs) for natural gas production/extraction in the Middle East can be in the order of US$0.25 per million Btu for offshore production. This value will be used in this study.

6.4.2 Capital Costs

Nexant has analyzed the cost of production of a 650 MMSCFD gas processing facility to meet sales gas specification. The plant is based in the Middle East and come on stream in Q1 2008. Capital costs presented below include free liquid separator (i.e. slug catcher), acid gas removal (H2S and CO2) unit, sulfur recovery unit and water and hydrocarbon dew point control units for the base case option. Capital costs estimates for the base case option are presented in Table 6.7.

Inside Battery Limits typically accounts for about 40 to 50 percent of total plant costs, with offsites, storage and export facilities (ISBL) make up the remainder. In this analysis, ISBL equals to 50 percent of total plant capital or 100 percent of ISBL.

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Table 6.7 Gas Processing Plant Capital Costs

Base Case Mechanical Refrigeration

percent plant cost (millions)

Inside Battery Limits (ISBL) Gas Reception facilities 3% $10 Acid Gas Removal Unit 14% $25 Gas Dehydration 8% $5 Sulfur Recovery 17% $20 Dew Point Control Unit 8% $30 Battery Limits 50% $90

Outside Battery Limits (OSBL) Utilities 15% $14 Condensate stabilization and storage 25% $23 Offsites (flares, drains etc.) 5% $5 Infrastructure (roads etc.) 5% $5 Total Offsites 50% $90

Total Cost 100% $180

(1) In 2006 US dollars

6.4.3 Cost of Production

Nexant has analyze the cost of production for a modern 650 MMSCFD gas processing plant, as shown in Table 6.8. It has been assumed that the plant is based in the Middle East and comes on stream in Q1 2008. For this evaluation depreciation and return on investment (ROI) levels have been set to give project cash flow return (CFR) of 5, 10 and 15 percent for comparison. Standard depreciation rates have been used, at ten percent for inside battery limits (ISBL) costs and five percent for offsites (OSBL).

The feed gas entering the plant has been valued at the marginal cost of gas production, in this case assumed at US$0.25 per million Btu for the Middle East. This assumes gas produced from shallow-water offshore production.

The cost of processing gas to meet sales gas specification is estimated at US$0.54 per million Btu based on a project Return on Investment (ROI) of 10 percent, as shown in Table 6.8.

The presence of oil or heavy condensates, which are usually separated from the gas at the field, can provide an additional stream of valuable income to offset field development costs and revenue losses due to shrinkage. This is included in this study and affects cost of production as shown in Table 6.9. The cost of processing gas to meet sales gas specification, including revenues from condensate, is estimated at US$0.43 per million Btu based on a project ROI of ten percent.

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Table 6.8 Cost of Gas Treatment For Sales Gas (Pipeline) Production – Base Case

CAPITAL COST $Million U.S. Plant start-up Q1 2006 ISBL 90.0Analysis date Q1 2008 OSBL 90.0Location Middle East Total Plant Capital 180.0Capacity 650 MMscf/d of feed gas Other Project Costs 45.0Gas Produced 620 MMscf/d of feed gas Total Capital Investment 225.0Operating rate 100 percent Working Capital 22.5Production 206667 Million Cubic feet per year Total capital Employed 247.5

Units Price Annualper Million US$ US$ Cost US$ per

PRODUCTION COST SUMMARY Cubic Feet per Unit per MMSCF million US$ MMBtu

RAW MATERIALS Produced Gas, MMBTU 1 0.250 265.5 54.87 0.250TOTAL RAW MATERIALS 265.5 54.87 0.250

BY-PRODUCT CREDITSCondensate, Ton/MMSCF 4.3 0.0 0 0.000

TOTAL BY-PRODUCT CREDITS 0 0.000 0.000NET RAW MATERIALS 265 54.866 0.250

UTILITIES LP Steam, ton/ MMSCFD 3 4.3 11.2 2.30MP Steam, ton/ MMSCFD 0.6 4.6 2.7 0.55Electricity, MWh/ MMSCF 0.5 40.5 18.81 3.89

TOTAL UTILITIES 32.6 6.7 0.03VARIABLE COST 298.1 61.6 0.28

DIRECT FIXED COSTS Labor 100 Men 22.0 Thousand $ U.S. 0.0034 2.20Foremen 20 Men 46.0 Thousand $ U.S. 0.0014 0.92Supervisor 15 Men 78.0 Thousand $ U.S. 0.0018 1.17Maintenance 3.0% of ISBL 0.0042 2.70Direct Overheads 85% of Labor Costs 0.0056 3.65Interest on Working Capital 10% of Working Capital 0.0035 2.25

TOTAL DIRECT FIXED COSTS 0.020 12.89 0.06ALLOCATED FIXED COSTS

General Plant Overhead 45% Labor & Maintenance 0.0048 3.15Insurance & Taxation 1.5% of Total Plant Capital 0.0052 3.38

TOTAL ALLOCATED FIXED COSTS 0.010 6.52 0.030

TOTAL CASH COST 298.1 81.02 0.37

Depreciation 10% of ISBL Investment 0.014 9.00 0.0085% of OSBL + OPC Investment 0.010 6.75 0.006

FULL COST OF PRODUCTION 298.2 96.8 0.091

AVERAGE NATURAL GAS PRICE FOR 5 PERCENT ROI 0.166 108.0 0.492AVERAGE NATURAL GAS PRICE FOR 10 PERCENT ROI 0.183 119.3 0.543AVERAGE NATURAL GAS PRICE FOR 15 PERCENT ROI 0.201 130.5 0.595

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Table 6.9 Cost of Gas Treatment For Sales Gas (Pipeline) Production – Including NGL/Condensate Co-Product Credit

CAPITAL COST $Million U.S. Plant start-up Q1 2006 ISBL 90.0Analysis date Q1 2008 OSBL 90.0Location Middle East Total Plant Capital 180.0Capacity 650.00 MMscf/d of feed gas Other Project Costs 45.0Gas Produced 620 MMscf/d of feed gas Total Capital Investment 225.0Operating rate 100 percent Working Capital 22.5Production 206667 Million Cubic feet per year Total capital Employed 247.5

Units Price Annualper Million US$ US$ Cost US$ per

PRODUCTION COST SUMMARY Cubic Feet per Unit per MMSCF million US$ MMBtu

RAW MATERIALS Produced Gas, MMBTU 1 0.250 265.5 54.87 0.250TOTAL RAW MATERIALS 265.5 54.87 0.250

BY-PRODUCT CREDITSCondensate, Ton/MMSCF 4.3 30.0 -128 -26.5

TOTAL BY-PRODUCT CREDITS (128) -26.5 (0.121)NET RAW MATERIALS 137.2 28.4 0.129

UTILITIES LP Steam, ton/ MMSCFD 3 4.3 12.5 2.58MP Steam, ton/ MMSCFD 0.6 4.6 2.7 0.55Electricity, MWh/ MMSCF 0.5 40.5 18.813 3.89

TOTAL UTILITIES 33.968 7.02 0.032VARIABLE COST 171.186 35.38 0.161

DIRECT FIXED COSTS Labor 100 Men 22.0 Thousand $ U.S. 0.0034 2.20Foremen 20 Men 46.0 Thousand $ U.S. 0.0014 0.92Supervisor 15 Men 78.0 Thousand $ U.S. 0.0018 1.17Maintenance 3.0% of ISBL 0.0042 2.70Direct Overheads 85% of Labor Costs 0.0056 3.65Interest on Working Capital 10% of Working Capital 0.0035 2.25

TOTAL DIRECT FIXED COSTS 0.020 12.89 0.059ALLOCATED FIXED COSTS

General Plant Overhead 45% Labor & Maintenance 0.0048 3.15Insurance & Taxation 1.5% of Total Plant Capital 0.0052 3.38

TOTAL ALLOCATED FIXED COSTS 0.010 6.52 0.030

TOTAL CASH COST 171.2 54.79 0.250

Depreciation 10% of ISBL Investment 0.014 9.00 0.0085% of OSBL + OPC Investment 0.010 6.75 0.006

FULL COST OF PRODUCTION 171.2 70.5 0.066

AVERAGE NATURAL GAS PRICE FOR 5 PERCENT ROI 0.126 81.8 0.373AVERAGE NATURAL GAS PRICE FOR 10 PERCENT ROI 0.143 93.0 0.424AVERAGE NATURAL GAS PRICE FOR 15 PERCENT ROI 0.160 104.3 0.475


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Section 7 Commercial Assessment

7.1 INTRODUCTION

This section provides global and regional reviews of the markets for natural gas. The reviews are preceded by a presentation of the general market characteristics of natural gas and followed by a brief statement on worldwide and regional natural gas processing capacity.

7.2 COMMERCIAL APPLICATIONS

7.2.1 Natural Gas

Natural gas can be utilized as an energy source (for power generation, liquid fuel generation such as gas to liquids, or GTLs and/or space heating). Additionally natural gas can be used as petrochemical feedstock particularly for methanol and ammonia (in fertilizer) production. These are demonstrated in Figure 7.1.

Figure 7.1 Natural Gas Drivers

Exports (LNG/Pipeline)

Liquid Fuels (GTL/MTBE/DME/Others)

Local FuelValue/Power

Ammonia (Fertilizers/Others)

Methanol (Formaldehyde/Acetyls/Others)

Methanol (MTO/MTP)

Energy UsesEnergy Uses

Chemical UsesChemical Uses

NaturalGas

NGLs forPetrochemicals

ProcessingFacility

ProcessingFacility Methane

PP: 4119.0005/Sec 7

Gas utilization in power generation currently accounts for the largest proportion of demand growth in the global markets and is therefore the major natural gas market driver. This is principally due to the advent in the 1990s of combined cycle gas turbine (CCGT) technology. CCGT has an overwhelming economic advantage compared to other types of thermal plants on account of its lower capital costs and higher thermal efficiency.



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Gas can also be converted to other forms of hydrocarbon liquid, which in turn would be used as an energy source. Gas to Liquids (GTL) technology, which converts the gas to naphtha and diesel through a syngas process has now reached commercial operation. The conversion of natural gas to liquid (GTL) products (termed, GTL naphtha and GTL diesel) is a relatively recent adaptation of Fischer-Tropsch technology, which was first used at large scale in Germany during the Second World War. At Q4 2004, the only two large-scale operational facilities that employ this technology are:

Shell at its Bintulu facility in Malaysia, using its in-house technology

PetroSA in its Mossgas facility, using technology licensed from Sasol.

However, a number of GTL facilities are presently in planning and development stages in the Middle East and Africa (Nigeria and Algeria).

Demand in the residential/commercial sectors is highly seasonal, e.g., increasing in winter for heating purposes in cold climates and for cooling during summer in warm regions. Many large industrial, power and commercial users have the flexibility to switch fuels, such that natural gas frequently competes with alternative fuels, e.g., fuel oil. However, in the residential sector, where volumes purchased per consumer are small, fuel flexibility is constrained by the cost of switching to other fuels. As a result of this, gas demand is relatively inelastic for such a captive category of gas consumers.

Gas consumption for methanol production has continued to grow steadily over recent years. Part of the growth has come from traditional end-uses such as formaldehyde (which is used in producing glues for use in plywood and chipboard/particle board production), whilst newer end-uses such as acetic acid and MTBE have also contributed to the growth. The dynamics of the development of methanol capacities reflects the continuous growth in the global consumption of methanol, favorable natural gas prices and the location of the markets with growing demand. The impending loss of a significant quantity of demand in the US through the phase-out of MTBE has not deterred investment in Trinidad however, and the two largest methanol plants in the world are set to enter production there over 2006.

The use of natural gas as a petrochemical feed stock for ammonia is principally used in fertilizer applications. Around 90 percent of the current global production of ammonia is based on natural gas feedstock, with remainder coming from older technology bases of coal, fuel oil, naphtha etc. Gas based producers have enjoyed the most favorable production economics for some time, and all new ammonia capacity under consideration is based on gas. Access to low priced gas feedstock has therefore lead to the concentration of new plants in Latin America, the FSU, the Middle East, and some parts of Asia. Despite the recent instability in US gas prices, there is no evidence of any resurgence in interest in ammonia production from heavier feedstocks.

Natural gas is transported to consumers by pipeline, or in the case of more distant users, in liquid form as liquefied natural gas, LNG. The gas is cooled to –160oC at which temperature it becomes a liquid and is transported in insulated tankers to distant markets. Compared to crude oil and petroleum products, natural gas is relatively expensive to transport by pipeline or liquefied and transported in dedicated liquefied natural gas (LNG) carriers.



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7.2.2 Gas Condensate

By virtue of it being a liquid, condensates consisting of pentanes and heavier components, are easier to transport as compared to natural gas. Condensates, a co-product of natural gas conditioning, typically have very low sulfur levels in comparison with most crude oils and typically have API gravity of greater than 50. Condensates are stabilized to prevent problems related to vapor pressure; it can be easily blended into crude oil streams either for transport by ship or pipeline.

Condensates generally have four possible disposal options, which are summarized individually below: Sale to a Steam Cracker as Ethylene Feedstock: Many steam crackers are designed to

accept a range of different feedstocks, typically including naphtha and LPG, but also occasionally heavier distillates. However, the cracker design usually requires the feedstock to be pre-cut into different boiling ranges before being processed. Cracker operators therefore typically buy pre-cut feedstocks, or (in a few cases) have access to splitting facilities to cut the feedstock themselves. There are a very limited number of ethylene plants that are able to take gas oil feedstock.

Sale to a Refiner: This is the prime focus for the sale of condensates, containing a significant proportion of heavier distillates. The greatest interest in purchasing condensate is likely to come from refineries that have a direct market for steam cracker feedstock from a neighboring plant (since other refineries will typically place a lower value on naphtha production).

On-Site Splitting and Sale of Straight Run Cuts: This option would typically only be attractive if the sale of the whole stream directly to a refiner or a steam cracker is considered unattractive compared to sale of the individual cuts.

Third Party Splitting and Sale of Straight Run Cuts: As per on-site splitting, with additional costs associated with the delivery of condensate to third party splitting facility.



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7.3 NATURAL GAS MARKET - GLOBAL OVERVIEW

7.3.1 Supply

Global natural gas reserves have almost doubled over the last twenty years. The evolution of proved gas reserves has been dynamic in several regions, where significant increases have been recorded: in the Former Soviet Union (FSU) gas reserves increased by more than 50 percent, those in Africa registered an increase of 125 percent and the reserves in the Middle East increased by more than 160 percent. The breakdown of natural gas reserves by region for 2004 is shown in Figure 7.2.

Figure 7.2 Regional Natural Gas Reserves (Tcf, at the end of 2004)

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The greatest concentration of natural gas reserves are in the Middle East and the Former Soviet Union, which together account for more than 72 percent of the global world reserves.

Global gas reserves, however, are not matched to global gas production, for example, North America, which has one of the lowest overall reserves currently, actually has the highest marketed production for any region (refer Figure 7.3).



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Figure 7.3 Regional Natural Gas Marketed Production (tcf, at the end of 2004)

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Out of a total marketed production of almost 95 tcf in 2004, North America produces 28 percent, South and Central Americas represent five percent, Europe 12 percent, FSU 28 percent, Middle East ten percent, Africa five percent and Asia 12 percent. Production of natural gas is therefore greatest in North America, where demand is highest, followed by the FSU then Europe and Asia.

North America, which has the highest demand, has some of the smallest reserves to production ratio at about ten years. Europe faces a similar situation of high demand and low indigenous reserves. Conversely, production in the Middle East, which accounts for ten percent of total world production, has the highest reserves to production ratio at 260 years at constant rate of production. Similarly, Africa has low demand and comparatively high reserves. The high reserves of the FSU, mean that despite its high consumption it still has a relatively high reserves to production ratio compared to Europe or North America. Reserves to production ratio in different regions are shown in Figure 7.4.

In general terms, the mismatch between reserves and production rates is in part a reflection of the high cost of transporting gas. This means that gas reserves relatively close to markets are most economic to develop and are preferentially produced. Thus, with the exception of FSU, the regions of highest consumption, North America and Europe, have the lowest reserves to production ratio.



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Figure 7.4 Gas Reserves to Production ratio (years, at the end of 2004)

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7.3.2 Demand

In 2004, global gas consumption stood at 95 tcf (260 bcf per day), representing 24 percent of the global consumption for primary energy. The major natural gas consuming regions are North America, FSU and Europe & Eurasia, which represent 29 percent, 22 percent and 19 percent of total world consumption respectively. South and Central America, the Middle East, Africa and the Asian regions together accounted for the remaining 30 percent of world consumption in 2004 (refer to Figure 7.5).

In 2004, 24 percent of the natural gas global consumption was in the electric power sector, with a consumption of 22 tcf. It is expected that this will increase to more than 30 percent of total 2025 demand as a result of both the construction of new gas-fired generating plants and higher capacity utilization at existing plants.

7.3.3 Demand Growth Projections

Natural gas is the fastest growing primary energy source. Between 2003 and 2004, world natural gas consumption increased by 3.3 percent to 95 tcf. Global gas markets are forecast to continue growing at between 2 and 3 percent for the foreseeable future, with gas demand/consumption set to double by 2025.

The share of gas in primary energy use is set to increase from 24 percent in 2004 to 28 percent in 2025, as shown in Figure7.6.



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Figure 7.5 Regional Natural Gas Consumption (Global Demand in 2004 = 95 tcf)

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Figure 7.6 Historical and Forecast Natural Gas Demand (In tcf)

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1980 1983 1986 1989 1992 1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025

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Regionally, growth in North America and Europe will be driven by environmental pressures which favor gas use over coal and oil in power generation. In the Far East, demand growth will be driven by the rapid pace of economic development. Major centers of gas demand growth over the next decade are expected to be China and India.

Sectorally, growth in global demand is expected to be strongest in the power generating sector with increasing use of natural gas-fired combined-cycle gas turbine (CCGTs), which are more efficient and less polluting than conventional oil and coal fires generating plants. Natural gas consumption in the industrial, residential, commercial, transportation sectors will also increase in the next 20 years. Natural gas use is projected to increase in the residential sector by 0.7 percent per year and in the commercial sector 1.2 percent per year on average from 2005 to 2025.

7.3.4 Trade

The international cross border gas trade represented 25 percent of the total gas marketed production in 2004. The international trade of gas reached a volume of more than 18 tcf via pipelines and 6.4 tcf as LNG in 2004. The major LNG importing countries in 2004 were: Japan 43 percent, South Korea 17 percent, Spain 10 percent, U.S. 10 percent, France 4 percent and Italy 3 percent. Whereas, in 2004, the major LNG exporting countries were: Indonesia, Malaysia, Algeria, Qatar, and Australia which together account for almost 70 percent of the global LNG trade.

The major pipeline gas importers in 2004 were: USA 20 percent, Germany 18 percent, Italy 12 percent and France 7 percent and the major exporters were: Russian federation 30 percent, Canada 20 percent, Norway 15 percent, Netherlands 10 percent and Algeria 7 percent. International pipeline and LNG trades are represented for 2004 in Figure 7.7.

Global inter-regional gas trade is expected to rise significantly and may double to 46 tcf by 2030, as a result of the mismatch between resource location and demand.

All regions that are currently net importers of gas will see their import rise. Most of this increase will be met by the Russia Federation and the Middle East. Several LNG liquefaction terminals and import terminals are being expanded or are currently under construction, which will significantly increase LNG trade capacity over the next decade. Cross border pipelines are also being planned, which would also significantly increase pipeline cross-border trade capacity.



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Figure 7.7 Global Gas Market in 2004

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LNGPipelines

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Figure 7.8 Global Gas Market in 2010

From Alaska

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7.4 REGIONAL NATURAL GAS MARKET OVERVIEW

7.4.1 North America

7.4.1.1 Supply

The North American continent is presently almost completely sufficient in natural gas and produces 97 percent of what it consumes. Within the North American continent, which consists of the U.S., Canada and Mexico, the U.S. is the largest consumer. Most cross border trade within and into the region consists of pipeline export from Canada (3.6tcf in 2004). LNG import to the U.S. (from Trinidad and Tobago, Algeria, Malaysia, Australia, Nigeria, Qatar and Oman) which reached 0.65 tcf in 2004. It is expected that incremental demand for natural gas in the U.S. will be mainly filled by LNG import as the prospects for increasing gas production in the region are very uncertain. At current rate of production, the North American continent reserves to production ratio is only of ten years.

In addition, as declining domestic sources of natural gas have forced US gas prices up over recent years, LNG imports have again become competitive and underutilized plants are now operating at full capacity (Everett, Massachusetts and Lake Charles, Louisiana), plants that had previously been mothballed have been reopened (Elba Island, Georgia and Cove Point, Maryland), and a large number of future projects have been proposed.

7.4.1.2 Demand

The North American market for natural gas is served by one of the most extensive networks of pipelines and storage. The degree of penetration of gas as a percentage of primary consumption is one of the highest in the world.

Gas demand in North America is projected to grow by 1.3 percent per year over the next 20 years. The power sector will absorb almost two-third of the increase in demand, as the majority of new power stations will be gas-fired CCGTs.

7.4.2 South and Central America

7.4.2.1 Supply

The gas market in South America is characterized by large reserves (four percent of global reserves), a relatively under-developed infrastructure, and a potentially large future demand. Venezuela, Trinidad & Tobago, Brazil and Argentina have the most reserves and the largest production.

The international cross border trade in the region reached 1 tcf in 2004. 0.53 tcf were pipeline export from Argentina and Bolivia to Brazil and Chile. Trinidad & Tobago exported 0.46 tcf of LNG to the U.S., 25 bcf to Puerto Rico and less than 7 bcf to Dominican Republic. Supply is expected to grow more rapidly than demand as new LNG export projects are expected to be developed in several countries, including Trinidad and Tobago, Venezuela, Peru and possibly Bolivia and Brazil. It is noted that no countries in South America are currently importers of LNG, although both Brazil and Chile have tentative plans in place for import projects, from Nigeria and Indonesia respectively.



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7.4.2.2 Demand

The gas infrastructure of the region is under development and even inadequate in some regions. This was demonstrated during the 2004 energy crisis in Argentina regarding the inadequacy of its domestic natural gas transmission network to meet increasing demand.

Principal natural gas consumption in this region is in the industrial and power sectors with relatively little domestic/residential use. Governmental policies are in place in, for example, Brazil and Chile for the development of the use of natural gas as a primary fuel. Gas demand in Latin America is projected to grow by at least four percent each year over the next two decades, to reach 9.6 tcf in 2025 compared with 4.3 tcf in 2004. Currently, major consuming countries are Argentina (1.4 tcf in 2004), Venezuela (1 tcf) and Brazil (0.7 tcf), which together represent 72 percent of the regional natural gas consumption. As production rate increase is higher than the one of demand, it is expected that incremental demand will be filled by indigenous production.

7.4.3 Europe and Eurasia, including FSU

7.4.3.1 Supply

Natural gas reserves in this region are estimated at more than 2,200 trillion cubic feet (tcf) in 2004, which represents 35 percent of the global world reserves. Russia holds the world’s largest natural gas reserves, with 1,700 tcf; nearly twice the reserves in the next largest reserves in Iran. Other major natural gas reserves in the region are in Kazakhstan (105 tcf), Turkmenistan (100 tcf), Norway (85 tcf), Uzbekistan (65 tcf) and the Netherlands (52 tcf).

Out of a regional consumption of 39 tcf in 2004, Europe imported 1.4 tcf via pipelines from Algeria, Libya and Iran to Italy, Spain, Turkey, Portugal and Slovenia; and 2.8 tcf was imported into the region as LNG mainly from Algeria and Nigeria. The remaining 35 tcf was met by indigenous production. The largest producer, by far, is the Russian federation (21 tcf in 2004), followed by the UK (3.4 tcf), Norway (2.8 tcf) and the Netherlands (2.5 tcf). In 2004, the Russian Federation was the world’s largest natural gas producer, as well as the world’s largest exporter.

Natural gas production in the UK and in the Netherlands are mainly from offshore fields in the North Sea; a mature producing region with a reserve to production ratio of 20 for the Netherlands. There is therefore limited potential for increasing gas production in this region as resources are small. Production in Western Europe could even reduce significantly over the next two decade. In addition, natural gas production in Russia was relatively constant over the last decade and there is little hope for this trend to change due to ageing fields, state regulation, Gazprom’s monopolistic control over the industry, and insufficient export pipelines. Incremental demand will therefore be met through the development of LNG imports from, for example, Egypt, Qatar and Nigeria and new cross-border pipelines.



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7.4.3.2 Demand

Demand for natural gas in Europe is growing mainly due to the environmental advantages it offers over oil and coal and reached 39 tcf in 2004. This is being encouraged by European Union legislation which is steadily reducing permissible emission limits. Demand growth in this region is expected to be higher than production growth. Imports are expected to rise to meet the incremental demand, especially to meet the demand in a growing power sector.

The degree of gas penetration as a percentage of primary energy consumption varies widely between countries within Europe, generally being highest in Western countries, e.g. U.K. and the Netherlands.

Increased pipeline import capacity from Algeria together with the expansion of the gas grids in Spain, Portugal and Southern Italy led to increased use in these countries, particularly in the industrial and power sectors. Strong growth is expected in the power generating sectors when countries switch from coal firing to gas utilization; and new gas fired power plants are built. Natural gas demand in the region is projected to grow by an average of 2 percent over the next decade, to reach 50tcf in 2015.

7.4.4 Middle East

7.4.4.1 Supply

The Middle East has the largest proven reserves of natural gas (40 percent of global world reserves), large production (10 tcf or 10 percent of global world production) but low demand (8.5 tcf). Reserves are estimated at about 2600 trillion cubic feet, 38 percent of which are in Iran and 35 percent in Qatar. Saudi Arabia and United Arab Emirates each have about 9 percent of the regional reserves.

As regional production is expected to grow faster than demand, surplus natural gas reserves are such that exports are viewed as the best way to realize their value. Most additional output will therefore be exported, predominantly as LNG.

Pipeline exports from the region are small and consist of pipelines from Iran to Turkey (0.12 tcf) – opened in 2001 – from Oman to United Arab Emirates (0.04 tcf or 40 bcf) and Egypt to Jordan. At present, the only major export of natural gas from the region is as LNG which represents 90 percent of the region natural gas export (i.e. 1.4 tcf or 26.5 MTPA in 2004). The main LNG exporting countries are Qatar, Oman and UAE with exports mainly to Asia (e.g. India, Japan and south Korea) but also to Spain, France and the U.S.

LNG export projects are rapidly expanding in the Middle East, with Iran and Yemen vying to join the ranks of Abu Dhabi, Oman and Qatar as regional LNG exporters. The current expansion of the region’s LNG capacity is dominated by Qatar’s development of the Qatargas and RasGas liquefaction complexes but also by the development in Oman of the Qalhat complex and in Iran as part of the development of the South Pars Field.



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7.4.4.2 Demand

Middle East gas demand should reach 13 tcf by 2020, up 4tcf from 2004. Iran and Saudi Arabia, which together accounted for more than 60 percent of the region’s gas demand, will remain the main markets. Gas demand growth will be led by the power sector but also in the industrial sector as a petrochemical feedstock, i.e. Gas to Liquid (GTL) Plants. Power for desalination plants will also be another important use.

A number of countries in the region have plans to increase gas production either to meet growing domestic demand in the industrial, petrochemical, and power sectors (e.g., Iran, Saudi Arabia), to increase existing LNG exports (Qatar, Oman), to develop new LNG exports (Yemen). For example, the Qatari government believes that the country's economic future lies in developing its vast natural gas potential and the expansion of Saudi Arabia Master Gas System (MGS) is planned to meet an ever expanding domestic gas demand. The MGS feeds gas to the industrial cities of Yanbu on the Red Sea and Jubail in Saudi Arabia eastern province, which combined account for ten percent of the world's petrochemical production.

7.4.5 Africa

7.4.5.1 Supply

Africa has the fourth largest proven natural gas reserves (500 tcf), after the Middle East, Europe and Asia. Algerian (160 tcf) and Nigerian (180 tcf) reserves together account for almost 70 percent of the continent’s global reserves. Algeria is, by far, the largest producer of natural gas in Africa followed by Egypt and Nigeria. More than 55 percent of the African natural gas production comes from Algeria, i.e. 2.9 tcf in 2004. Total African natural gas production reached 5.2 tcf in 2004 or 5 times less than the North American continent which has the equivalent of half of Africa’s proven reserves.

Local demand is still quite low compared to production; Africa is therefore a net exporter of natural gas. Export of natural gas outside Africa is currently in the order of 3 tcf, 50 percent of which are made via pipelines and the rest as LNG mainly from Algeria to the European and American Markets. Algeria, which has the largest proven reserves of any African country and close proximity to the European market, has been a significant gas exporter over the last 40 years.

Algeria currently has an LNG export capacity of around 20 MTPA at its Arzew and Skikda facilities. Pipelines from Algeria also deliver natural gas to Italy via the Trans Mediterranean Gas pipeline and to Spain via the Gazoduc Maghreb Europe (GME) line. With the recent improvement of its international relations, Libya exports gas by pipeline to Italy and is considering developing its very limited LNG capacity, although any such developments are unlikely much before the end of the decade.



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Nigeria began exporting LNG in 1999 from its NLNG facility at Bonny Island. The plant currently has a combined capacity of around 9 MTPA. A number of other LNG projects (Brass River LNG, West Niger Delta LNG and a floating LNG project) have been proposed for Nigeria, although no firm developments have yet been made. It is noted that most of Nigeria onshore associated gas production is flared and governmental programs and policies are in place to stop gas flaring by 2008 – in 2003, 40 percent of Nigeria natural gas gross production was flared or vented.

7.4.5.2 Demand

Gas demand in Africa is expected to grow, on average, by five percent over the next two decades to reach 7 tcf in 2025 compared to 2.5 tcf in 2004. However, a lack of infrastructure and warm climatic conditions are all factors limiting the potential increase in demand in certain regions.

The principal demand for natural gas in Algeria, Egypt and Libya is for power and industry with very little demand in the domestic residential sector. In Nigeria, gas that is not flared is used for power generation and some is used for petrochemical and fertilizer production at plants constructed near Port Harcourt. The remaining gas is re-injected.

7.4.6 Asia Pacific

7.4.6.1 Supply

With 500 tcf of proven gas reserves, the Asia Pacific region accounts for eight percent of the total world reserves. The largest reserves are located in Australia, Indonesia, Malaysia and China which almost equally share 70 percent of the region’s reserves. The countries with the largest reserves are also the largest producers of the Asia Pacific region.

Overall, the gas supply situation in Asia is mixed. North East Asia countries such as Japan and South Korea are heavy importers of natural gas, more than 50 percent of which comes from South East Asia and Australia as LNG. China and India, which are currently gas producers but also major consumers are set to join the list of heavy importers over the remainder of the decade and beyond, as their demand growth should exceed production growth. Australia should remain a net exporter of natural gas whereas countries such as Bangladesh and New Zealand are currently and could remain self sufficient. All the other countries in the region, such as the Philippines, Singapore and Thailand are net importers or natural gas.

Cross-border natural gas pipeline trade is currently not well developed in Asia- Pacific and pipelines trade represents roughly 14 percent of the total international gas trade in the region and four percent of the region’s gas consumption. The cross-border pipeline imports/exports are currently between the following:

Indonesia to Malaysia (Sumatra to West Natuna pipeline)

Indonesia to Malaysia (Duyong pipeline)

Malaysia to Singapore (PGU pipeline) and

Myanmar to Thailand (Yetagun/Yadana pipeline).



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These pipelines have a combined capacity of 0.5 tcf, 8 times less than the current LNG trade in the region. The gas market of Far East Asia is therefore currently dominated by LNG trade.

Asia Pacific is currently the largest market for LNG, accounting for around 66 percent of the 178 MTPA global LNG trade in 2004. 2004 LNG trade was made up as follows: Japan 43 percent, South Korea 17 percent, Taiwan 5 percent and India 1 percent. LNG trade in Asia Pacific now includes the new markets of India and China. Both countries are major emerging markets for LNG and are likely to see significant capacity expansion by 2010. India’s first import terminal opened at Dahej, Gujarat in early 2004, with a capacity of 5 million tons per annum and expected to be expanded to 10 MTPA. China’s first LNG terminal is scheduled for completion in Guangdong province by 2006.

7.4.6.2 Demand

The overriding demand for LNG in the Far East arises from power generation where the clean burning characteristics of natural gas offer advantages over oil and coal in densely populated cities. Residential and commercial consumption is generally limited (refer to Figure 7.9).

Figure 7.9 Gas Consumption by Sector in the Asia – Pacific Region (2004)

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The rapid economic growth in the area is increasing the demand for natural gas such that there are plans to increase LNG supply and pipelines cross border trades. Different demand growth rates are expected for different countries. For example, Japan natural gas demand should grow by two percent over the next two decades, whereas demand growth could reach up to four percent in developing economies such as China, Indonesia and India.



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7.5 WORLDWIDE GAS PROCESSING CAPACITY

Global gas processing capacity exceeds 235,000 MMSCFD, with more than half of it built in North America. The Middle East now holds the second largest gas processing capacity, followed by the Asia Pacific region (Asia & Australia) and Western Europe.

Table 7.1 Gas/Gas Liquids Processing Capacity and Production (Source: Oil & Gas Journal – Gas Processing Survey 2004)

Capacity Gas Liquids(MMscf/d)

North America 119 478 74 402 103 739Central & S. America 18 198 13 394 27 391Western Europe 24 375 9 904 9 931FSU & East Europe 2 796 1 427 10 142Middle East 29 112 20 546 65 040

Africa 17 254 9 642 16 777Asia & Australia 24 487 18 692 22 404Total 235 701 148 007 255 424

(1,000 gal/d)

2004 Troughput

Since 1994, worldwide gas processing capacity has increased from about 180,000 MMSCFD up to 235,000 MMSCFD, this represents an increase of 30 percent over ten years. However, growth in the gas processing industry varied in different regions of the world. For example, gas processing capacity increased by almost 150 percent in the Middle East whereas it decreases by 30 percent in Eastern Europe.

Table 7.2 Change in Gas Processing Capacity and Throughput Between 1994 and 2004 (Source: Oil & Gas Journal 2005)

Capacity Gas Liquids(MMscf/d)

North America 11% -3% -13%Central & S. America 56% 37% 5%Western Europe 10% 70% 107%FSU & East Europe -30% -52% -31%Middle East 147% 290% 645%Africa 86% 30% 48%Asia & Australia 63% 97% 95%

Troughput Change

(1,000 gal/d)


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Section 8 Glossary of Terms

Acid Gas CO2 and H2S, possibly other compounds such as COS.

Associated Gas Gas produced from reservoirs containing crude oil. The gas may be dissolved in the oil (solution gas), or lie above the oil as a gas cap.

CapEx Capital Expenditure.

Cap Gas Layer of gas separated from oil in an oil field.

CGR Condensate/gas ratio (e.g. for condensate recovered at wellhead in gas production from gas or gas/condensate fields, usually in bbl condensate/million SCF gas).

Cold Box Enclosed, insulated assembly of cryogenic equipment.

Condensate C5 and heavier hydrocarbons recovered in gas production and processing.

Core A plate-fin exchanger unit.

CIF Cost, Insurance, Freight.

CNG Compressed Natural Gas used as fuel in the transport sector.

Cricondenbar Highest pressure at which gas and liquid can co-exist as separate phases.

Cricondentherm Highest temperature at which gas and liquid can co-exist as separate phases.

Critical Point Temperature above which a pure compound can only be a single fluid phase.

DEG Diethylene Glycol

Dense Phase Condition of fluid at high pressure, above the cricondenbar (in dense phase fluids can be cooled to low temperature without going through a two-phase zone).

Dense Phase Gas/NGL stream held in single phase by high pressure.

Dry/Lean Gas Natural gas with very low heavy hydrocarbon content.

EG Ethylene Glycol

F-T Fischer-Tropsch (GTL technology).

Gas/ Field Condensate Field where substantial quantity of condensate separates from gas when wellstream is reduced in pressure.

Gas Conditioning Treatment of gas for the removal of liquids (water and heavy hydrocarbons) to meet sales gas specification

Gas Sweetening Removal of acid gas from a natural gas stream



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GDP Gross Domestic Product.

GOR Gas/oil ratio (e.g. for production from oil field, usually in SCF gas/bbl oil).

GOSP Gas/oil separator plant.

GTL Gas-to-Liquids.

GTP Gas-to-Power.

HAP Hazardous air Pollutants

HSFO High Sulfur Fuel Oil.

HHV Higher Heating value (alternative term is Gross Heating Value GHV). This is the heat produced by complete combustion of gas with the theoretical amount of required air when the water produced is completely cooled and condensed to a defined reference temperature.

Hydrocarbon Dew Point Pressure and temperature at which hydrocarbons begin to condense from a gas stream.

IPP Independent Power Producer.

J-T valve Valve used for pressure reduction, giving cooling due to “Joule-Thomson effect”.

LHV Lower Heating Value (Alternative Term: Net Calorific Value). This is the heat produced by complete combustion of the gas with the theoretical amount of required air when the water produced from the combustion remains in the vapor state.

LNG Liquefied Natural Gas.

LPG Liquefied Petroleum Gas.

LSFO Low Sulfur Fuel Oil.

LTX Low Temperature Separation

MCR Multi-Component Refrigerant (trademark of APCI).

Mercaptans Sulfur containing organic compounds.

MEG Mono-Ethylene Glycol

MR Mixed Refrigerant.

Natural Gasoline Light condensate recovered from gas processing and conditioning.

Non Associated Gas Gas produced from reservoirs generally containing no oil or very lean condensate



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NGL Natural Gas Liquids, general term for liquid hydrocarbons separated from natural gas stream, can include components from ethane to C5 plus.

NGV Natural Gas Vehicle.

OpEx Operating Expenditure.

Retrograde Condensation Phenomenon of condensate being formed from gas stream as pressure is reduced.

RFO Residual Fuel Oil.

Rich/Wet Gas Natural gas with high heavy hydrocarbon content.

SCF, SCFD U.S. Standard cubic foot, SCF per day (measured at 14.696 psia and 60 °F).

Shrinkage Reduction in volume of natural gas due to removal of NGL and/or acid gas components.

Sour Gas Natural gas with high acid gas content

Sweet Gas Treated natural gas after the removal of acid gas

TEG Triethylene Glycol

US$ U.S. Dollar

Wobbe Index This is the gross heating value divided by the square root of the relative density of the gas with respect to air. Wobbe Index indicates the heat output from a burner.

Water Dew Point Pressure and temperature at which water vapor contained in the gas stream begins to condense.



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Natural Gas Components

C1 Methane

C2 Ethane

C3 Propane

i-C4 i-Butane

n-C4 n-Butane

C5+ Condensate

H2S Hydrogen Sulfide

CO2 Carbon Dioxide

N2 Nitrogen

H2 Hydrogen

He Helium

Hg Mercury

BTEX Aromatic compounds

COS, CS2 Mercaptans



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Units of Measure

Barg Bar Gauge (Pressure Measurement)

BBL Barrels

BCF Billion Cubic Feet

BCM Billion Cubic Meters

B, G Billion, Giga (10^9)

BOE Barrels Oil Equivalent

CF, CFD Cubic Feet, Cubic Feet per Day

GJ Gigajoule

GW, GWh Gigawatt, Gigawatt-hours

kCAL Kilocalorie

kTPA Thousand Tons per Annum

kW, kWh Kilowatt, Kilowatt-hour

MCAL Megacalorie

MMBOE Million Barrels Oil Equivalent

MMBTU Million British Thermal Units

MMCM Million Cubic Meters

MM, M Million, Mega (10^6)

MMSCFD Million Standard Cubic Feet per Day

MW, MWh Megawatt, Megawatt-hour

ppm Parts per million (1 mg/m3)

psi Pounds per Square Inch (Pressure Measurement)

TOE Tons Oil Equivalent

TCF Trillion Cubic Feet

TCM Trillion Cubic Meters

T, k Thousand Kilo (10^3)

TJ Terajoule

TPA Tons per Annum

T, T Trillion, Tera (10^12)



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Conversion and Equivalences Volume

1 CM 35.315 CF

1 000 CF 28.32 CM

1 BBL 159 liters; 0.159 CM

1 CM 6.29 BBL

Energy Content (LHV) kcal/kg BTU/kg

Fuel Oil/Oil Equivalent 10 000 39 700

Heavy/Residual Fuel Oil 9 800 38 900

Gas Oil, Diesel Oil 10 100 40 100

Jet Fuel 10 470 41 520

Kerosene 10 390 41 230

LPG 10 810 42 900

Fuelwood 3 000 11 940

Charcoal 7 000 27 860

Energy Equivalences

1 kWh = 0.86 Mcal = 3.6 MJ

1 MMBTU = 252 Mcal = 293 kWh = 1 055 MJ

1 GWh = 3412 MMBTU

1 000 cm natural gas = 0.85 TOE

1 000 kWh electricity = 0.11 TOE (final consumption)

1 ton wood = 0.30 TOE

1 ton charcoal = 0.70 TOE

Rules of Thumb

Natural Gas: 1 MCF ~ 0.95 MMBTU

Natural Gas: 1 MMSCFD ~ 10 MMCM/Y

Oil: 1 BPD ~ 50 TPA

Natural Gas: US$1.0/MMBTU ~ US$0.95/1,000 CF


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Appendix A Nexant’s ChemSystems Capital Cost Estimates

Elements of Nexant’s ChemSystems Capital Cost Estimates Process Evaluation/Research Planning, 2005

Costs typically included in Nexant’s ChemSystems capital cost estimates are defined as follows:

A.1 INSIDE BATTERY LIMITS INVESTMENT

The inside battery limits (ISBL) portion of a plant can be thought of as a boundary over which are imported raw materials, catalysts and chemicals, and utility supply streams. In a like manner, main products, by-products, and spent utility return streams are exported over this boundary.

ISBL investment includes the cost of the main processing blocks of the chemical plant necessary to manufacture products. It represents an "instantaneous" investment (i.e., no escalation) for a plant ordered from a contractor and built on a prepared site with normal load-bearing and drainage characteristics of a developed country.

Battery limits investment includes the installed cost of the following major items:

Process equipment: vessels and internals, heat exchangers, pumps and compressors, drivers, solids handling

Major spare equipment/parts (e.g., spare rotor for turbine or compressor)

Building housing process units

Process and utility pipes and supports within the major process areas

Instruments, including computer control systems

Electrical wires and hardware

Foundations and pads

Structures and platforms

Insulation

Paint/corrosion protection

Process sewers

Fire water pipes and monitors

Utility stations

The installed cost also includes construction overhead: fringe benefits, payroll burdens, field supervision, equipment rentals, small tools (expendables), field office expenses, site support services, temporary facilities, etc.



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A.2 OUTSIDE BATTERY LIMITS INVESTMENT

Outside battery limits (OSBL) investment includes the plant investment items that are required in addition to the main processing units within the battery limits. These auxiliary items are necessary to the functioning of the production unit, but perform in a supporting role rather than being directly involved in production. A distinguishing characteristic is the potential for sharing offsite facilities among several production units in a large plant, in which case investment cost would be allocated or prorated.

OSBL investment includes the installed cost of the following major items:

Storage for feeds, products, by-products, including tanks/silos, dikes, inerting, process warehouse, and bagging/palletizing equipment

Steam generation units

Cooling water systems, including cooling towers and circulation pumps

Process water treatment systems and supply pumps

Boiler feed water treatment systems and supply pumps

Refrigeration systems, including chilled water/brine circulating pumps

Heat transfer medium systems, including organic vapor, hot oil, molten salts

Electrical supply, transformers, and switchgear

Loading and unloading arms, pumps, conveyors, lift trucks, including those to handle barge, tank/hopper car, and tank/hopper/other truck traffic; weigh scales

Auxiliary buildings, including all services, furnishings, and equipment:

− Central control room − Maintenance − Stores warehouse − Laboratory − Garages/fire station − Change house/cafeteria − Medical/safety − Administration

General utilities, including plant air, instrument air, inert gas, stand-by electrical generator, fire water pumps

Site development, including roads and walkways, parking, railroad sidings, electrical main substation, lighting, water supply, fuel supply, clearing and grading, drainage, fencing, sanitary and storm sewers, and communications



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Yard pipes, including lines for cooling water, process water, boiler feed water, fire water; fuel; plant air, instrument air, inert gas; collection of organic wastes, aqueous wastes, and flare/incinerator feeds; and process tie-ins to storage

A.3 CONTRACTOR CHARGES

These charges are typically 15 to 25 percent of installed ISBL and OSBL costs and are included proportionately in the ISBL and the OSBL investments. Contractor charges include the following major items:

Detailed design and engineering, including process and offsites design and general engineering, equipment specifications, plant layout, drafting, cost engineering, scale models

Administrative charges, including project management, engineering supervision, procurement, expediting, inspection, travel and living, home office construction expenses, general home office overhead

Contractor profit

A.4 PROJECT CONTINGENCY ALLOWANCE

A project contingency allowance is typically 15 to 25 percent of installed ISBL and OSBL costs and is included proportionately in the ISBL and the OSBL investments.

A project contingency allowance is applied to the total of the above costs to take into account unknown elements of the process being estimated. For well-defined processes where primary input has come from engineering contractors, a contingency of 10 to 20 percent would be typical. At the other end of the spectrum, a capital estimate for a speculative process developed from patent and literature data alone might warrant a contingency of 20 to as much as 50 percent in extreme cases.

A.5 OTHER PROJECT COSTS

These costs are very site/project specific; however, they typically range from 20 to 40 percent of installed ISBL + OSBL costs. A norm value of 25 percent will be used in the absence of more specific information.

For the purpose of our study, other project costs normally include startup/commissioning costs, miscellaneous owner’s costs, etc. They are described below:

Startup/Commissioning Costs

Extra operating manpower

Owner's technical manpower

Startup services



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− Licensor representatives − Contractor personnel − Equipment supplier/other vendor representatives

Operating manuals and training programs

Modifications and maintenance during startup

Operating expenses to the extent that they do not result in saleable product

Miscellaneous Owner's Costs

Licensing/royalty/expertise fees: basic process and engineering design package

Jetties, marine terminals, docks, etc.

Long distance pipelines for raw material/products

Land, rights of way, permits, surveys, and fees

Piling, soil compaction/dewatering, unusual foundation requirements

Sales, use, and other taxes

Freight, insurance in transit, and import duties (equipment, pipe, steel, instruments, etc.)

Escalation/inflation of costs over time, assuming instantaneous construction

Interest on construction loan, assuming instantaneous construction

Overtime pay during construction

Construction workers' housing, canteen, other infrastructure for remote site

Field insurance

Project team, including preliminary planning studies, HAZOP studies, environmental reviews, design, engineering, estimating, inspection, accounting, auditing, legal, construction management, travel, and living

Initial charges of raw materials, catalysts, chemicals, and packaging materials

Initial stock of maintenance, laboratory, operating, and office supplies

Transport equipment, including barges, railcars, tank trucks, bulk shipping containers, plant vehicles

Provisions for temporary shutdown expenses

Owner's scope contingency allowance



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A.6 WORKING CAPITAL

Working capital typically includes the following items:

Accounts receivable (products and by-products shipped but not paid by customer), typically one month's gross cost of production (COP)

Cash on hand (short-term operating funds), typically one week's gross COP minus depreciation

Minor spare equipment and parts inventory, percentage of replacement BL capital

Credit for accounts payable (feedstocks, catalysts, chemicals, and packaging materials received but not paid to supplier), typically one month's delivered cost

Value of product and by-product inventories, typically two weeks' gross COP

Value of raw material inventory, typically two weeks' delivered cost

* To be published * To be published B-1

Appendix B PERP Program Title Index

PERP Program Title Index (1994/1995 – 2004/2005)

This index is intended to be a handy and convenient tool for quickly identifying PERP reports of interest. It should be noted, however, that this is a title index only. For a more complete search, dating back to 1972, the full subject indices should be used. See your local technical information service department for the PERP subject indices or contact Nexant. To browse all Nexant ChemSystems reports, please visit: www.nexant.com/products/CSReports/index.asp

Title Report Date Acetic Acid 02/03-1 09/03 Acetic Acid/Acetic Anhydride 97/98-1 01/99 Acetic Acid Directly from Ethylene 94/95S9 12/96 Acetic Acid via Ethane Oxidation 99/00S5 01/01 Acetic Anhydride/Cellulose Acetate 03/04S1 06/04 Acetone/Phenol/Cumene 01/02-2 10/02 Acetone/Phenol/Cumene 96/97-2 12/97 Acrylamide 01/02S10 11/02 Acrylic Acid 04/05-6 * Acrylic Acid 00/01-7 05/01 Acrylic Acid/Acrylates 96/97-8 11/97 Acrylonitrile 00/01-6 03/02 Acrylonitrile 96/97-7 12/97 Adipic Acid 03/04-3 11/04 Adipic Acid 98/99-3 07/99 Advances in LNG Technologies 03/04S10 10/04 Aliphatic Diisocyanates 98/99S11 09/99 Alkylbenzene, Linear (LAB) 01/02S8 05/03 Alkyl Vinyl Ethers 97/98S6 07/98 Alpha Olefins, Developments in Production Technology 97/98S14 01/99 Alpha Olefins 02/03-4 01/04 Alpha Olefins 98/99-7 12/99 Alternative Uses for MTBE Facilities 99/00-7 03/01 Ammonia 97/98-6 08/98 Amorphous High Temperature ETPs 03/04S12 01/05 Aniline/Nitrobenzene 02/03-2 06/03

Title Report Date Aromatics from Light Olefins 97/98S1 04/99 Ascorbic Acid and Sorbitol 97/98S11 03/99 Barrier Monomers for PET 02/03S12 12/03 Benzene/Toluene 02/03-5 04/03 Benzene/Toluene 98/99-6 05/99 Biodegradable Polymers 94/95S13 02/97 Biodesulfurization of Petroleum Fractions 98/99S7 01/00 Biodiesel 02/03S2 12/03 Bioprocessing Technologies, Developments in Alternative Routes to Specialty Chemicals 96/97S1 05/97 Biotech Route to Lactic Acid/Polylactic Acid 00/01S3 05/02 Biotransformation Routes to 1,3-Propanediol 97/98S4 09/98 Bisphenol A 01/02-6 09/02 Bisphenol A 97/98-4 05/98 Butadiene/Butylenes 01/02-3 02/03 Butadiene/Butylenes 97/98-2 06/98 Butadiene, Chemicals from 99/00S13 01/01 Butadiene, Oxo Alcohols from 98/99S13 01/00 Butadiene Rubber/Styrene Butadiene Rubber (SBR/BR) 02/03S1 12/03 Butanediol, 1,4-/THF 02/03-7 01/04 Butanediol/THF 98/99S1 09/99 Butyl Acetate/Ethyl Acetate 97/98S5 08/98 Butylenes/Butadiene 01/02-3 02/03 Butylenes/Butadiene 97/98-2 06/98 Caprolactam 04/05-3 *


Title Report Date Caprolactam 99/00-4 03/01 Caprolactam 94/95-6 03/96 Caprolactam from Adiponitrile 96/97S8 03/97 Carbon Monoxide Production and Purification Technologies 96/97S10 04/98 Catalytic Ethane Dehydrogenation, Ethylene via 98/99S9 04/99 Catalytic Naphtha Cracking, Ethylene via 96/97S12 09/97 Cellulose Acetate/Acetic Anhydride 03/04S1 06/04 Chemicals from Butadiene 99/00S13 01/01 Chlor Alkali 01/02S4 03/03 Chlorine Recovery via HCl Recycle Technologies 96/97S6 04/98 Coal Gasification Technologies 03/04S11 01/05 Compounding, Polypropylene 04/05S6 * Copolyester and Copolyamide Elastomers, Thermoplastic 02/03S9 10/03 Copolymers, Cyclic Olefin 94/95S5 05/96 Cost/Performance of Fuel Oxygenates 99/00S3 09/00 Crystalline High Temperature Polymers 04/05S3 * Cumene/Phenol/Acetone 01/02-2 10/02 Cumene/Phenol/Acetone 96/97-2 12/97 Curtailing Coke Formation in Ethylene Furnace Tubes 02/03S10 06/03 Cyclic Olefin Copolymers 94/95S5 05/96 Dehydrogenation, Light Paraffin 94/95S2 04/96 Desulfurization Technologies, Novel 00/01S8 10/02 Detergent Alcohols 98/99S5 01/02 Developments in Alpha Olefin Production Technology 97/98S14 01/99 Developments in Bioprocessing Technolo- gies: Alternative Routes to Specialty Chemicals 96/97S1 05/97 Developments in Dimethyl Carbonate Production Technology 99/00S6 05/00 Developments in Methanol Production Technology 96/97S14 08/98 Developments in Natural Gas to Liquid Fuels Conversion Technologies 96/97S13 02/98 Developments in Non-Phosgene Poly- carbonate Technology 02/03S8 10/03 Developments in para-Xylene Technology 96/97S7 07/97 Developments in PET Recycling 99/00S4 07/00

Title Report Date Developments in Propylene Oxide Technology 00/01S12 11/01 Developments in PTA Production Technologies 00/01S7 02/02 Developments in Superabsorbent Polymer Technology 94/95S8 12/96 Developments in Syngas Technology 03/04S4 02/05 Developments in Thermoplastic Elastomers 98/99S12 11/99 Dicyclopentadiene and Derivatives 97/98S7 08/98 Dimethyl Carbonate Production Technology: Developments in 99/00S6 05/00 Dimethyl Ether (DME) 97/98S8 03/99 Dimethylnaphthalene, (2,6-) 99/00S7 06/00 EDC/VCM 03/04-6 12/04 EDC/VCM 99/00-3 04/00 EDC/VCM 94/95-5 08/96 EPDM Rubber 04/05S2 05/05 Epichlorohydrin 99/00S11 07/00 Epoxy Resins 04/05S11 12/05 Ethane and Benzene, Styrene from 04/05S10 * Ethane Dehydrogenation, Ethylene via Catalytic 98/99S9 04/99 Ethane Oxidation, Acetic Acid via 99/00S5 01/01 Ethane Partial Oxidation, Ethylene via Catalytic 03/04S2 07/04 Ethanol 04/05-8 * Ethanol 99/00-8 08/01 Ethanolamines 01/02S2 08/02 Ethyl Acetate/Butyl Acetate 97/98S5 08/98 Ethylbenzene/Styrene 03/04-8 11/04 Ethylbenzene/Styrene 99/00-6 08/00 Ethylbenzene/Styrene 94/95-8 03/96 Ethylene Oxide/Ethylene Glycol 04/05-5 12/05 Ethylene Oxide/Ethylene Glycol 00/01-2 11/01 Ethylene Oxide/Ethylene Glycol 96/97-4 08/97 Ethylene 04/05-7 09/05 Ethylene, Propylene 00/01-4 06/01 Ethylene, Propylene 96/97-6 03/97 Ethylene Trimerization to Hexene-1 94/95S12 09/96 Ethylene via Catalytic Ethane Dehydrogenation 98/99S9 04/99


Title Report Date Ethylene via Catalytic Naphtha Cracking 96/97S12 09/97 Ethylene via Catalytic Ethane Partial Oxidation 03/04S2 07/04 Extending the Methane Value Chain 99/00S9 10/00 Fiber Spinning Technology, Nylon 04/05S5 * Fiber Spinning Technology, PET 03/04S8 08/04 Fiber Spinning Technology, PET 97/98S13 02/00 Fischer-Tropsch Liquids as Steam Cracker Feedstocks 01/02S9 12/02 Fluidized Bed Vinyl Acetate Process 98/99S3 02/00 Formaldehyde 00/01-8 04/01 Formaldehyde 94/95-2 04/96 Fuel Cells for Transportation 02/03S5 12/03 Fuel Oxygenates, Cost/Performance of 99/00S3 09/00 Fuel Switching with NGLs/Small Scale LNG 04/05S1 08/05 Gasification Technologies, Coal 03/04S11 01/05 Gas Processing and NGL Extraction 04/05S8 03/06 Glycerin 00/01S4 11/01 Glycol Ethers 01/02S6 08/02 HCl Recycle Technologies, Chlorine Recovery via 96/97S6 04/98 Heavy Oils, Unconventional 04/05S9 * Hexene-1 via Ethylene Trimerization 94/95S12 09/96 High Density Polyethylene 01/02-1 12/02 High Density Polyethylene 96/97-3 04/98 High Performance Polyesters 94/95S6 10/96 High Temperature ETPs, Amorphous 03/04S12 12/04 High Temperature Polymers, Crystalline 04/05S3 * High Temperature Thermoplastic Nylons 01/02S3 06/02 Hydrocarbon Resins 99/00S10 03/01 Hydrogen Peroxide 03/04-5 10/04 Hydrogen Peroxide 98/99-8 09/99 Impact of Supply Chain IT Applications on The Refining Industry 04/05S4 * Iron and Cobalt Based Olefin Poly- merization Catalysts 97/98S9 09/99 Isophthalic Acid/meta-Xylene 94/95S14 02/97 Isoprene 98/99S2 09/99 Lactic Acid/Polylactic Acid, Biotech Route to 00/01S3 05/02 LDPE 04/05-1 06/05

Title Report Date LDPE 00/01-5 04/01 LDPE/LLDPE 94/95-1 02/97 LDPE Specialties 03/04S9 12/04 Light Olefins, Aromatics from 97/98S1 04/99 Light Olefins from Natural Gas 94/95S11 05/97 Linearalkylbenzene (LAB) 01/02S8 05/03 Liquefied Natural Gas 96/97S2 11/97 Liquid Crystal Polymers 00/01S10 09/01 LLDPE 03/04-1 01/05 LLDPE 99/00-1 06/00 LLDPE/LDPE 94/95-1 02/97 Maleic Anhydride 03/04-7 02/05 Maleic Anhydride 99/00-5 06/00 Maleic Anhydride 94/95-7 06/96 Managing Technology Development in the Chemical Industry 97/98S2 06/99 MDI/TDI 98/99S8 09/99 Medium Quality Terephthalic Acid 03/04S6 10/04 meta-Xylene/Isophthalic Acid 94/95S14 02/97 Methacrylic Acid/Methacrylates 94/95-3 08/96 Methane Value Chain, Extending the 99/00S9 10/00 Methanol 03/04-4 01/05 Methanol 98/99-4 05/00 Methanol Production Technology, Developments in 96/97S14 08/98 Methanol to Olefins 00/01S9 01/02 Methyl Methacrylate 04/05-2 * Methyl Methacrylate 99/00-2 09/01 Methyl t-Butyl Ether (MTBE) 94/95-4 06/96 Modified Polyphenylene Oxide (MPPO) 02/03S3 03/03 MTBE Facilities, Alternative Uses of 99/00-7 03/01 MTBE Phaseout on Chemical Markets, Impact of 00/01S2 06/01 Nanocomposites, Thermoplastic 00/01S11 09/01 Naphthalene and Derivatives 96/97S9 03/98 Natural Gas, Light Olefins from 94/95S11 05/97 Natural Gas Liquids Extraction 94/95S4 05/96 Natural Gas to Liquid Fuels Conversion Technologies, Developments in 96/97S13 02/98 NGL Extraction, Gas Processing and 04/05S8 *


Title Report Date NGLs/Small Scale LNG, Fuel Switching with 04/05S1 * Nickel and Palladium Olefin Polymeriza- tion Catalysts 96/97S11 09/98 Nitric Acid 97/98S12 10/98 Nitrobenzene/Aniline 02/03-2 06/03 Non-Phosgene Polycarbonate Technology, Developments in 02/03S8 10/03 Novel Desulfurization Technologies 00/01S8 10/02 Nylon 6/Nylon 6,6 99/00S1 03/00 Nylon Fiber Spinning Technology 04/05S5 * Nylons, High Temperature Thermoplastic 01/02S3 06/02 Olefin, Cyclic, Copolymers 94/95S5 05/96 Olefin Polymerization Catalysts, Iron and Cobalt Based 97/98S9 09/99 Olefins, Methanol to 00/01S9 01/02 Oleochemicals 99/00S12 05/01 On-Purpose N2O Production for Phenol Manufacture 98/99S14 09/99 Options for Refinery C5's 98/99S4 09/99 Oxo Alcohols 01/02-8 04/03 Polytrimethylene Terephthalate (PTT) 01/02S7 10/02 Oxo-Alcohols 96/97S3 02/98 Oxo Alcohols from Butadiene 98/99S13 01/00 Paraffin, Light, Dehydrogenation 94/95S2 04/96 para-Xylene Technology, Developments in 96/97S7 07/97 PET Fiber Spinning Technology 03/04S8 08/04 PET Fiber Spinning Technology 97/98S13 02/00 PET Manufacture, Reducing Costs in 04/05S7 06/05 PET Recycling, Developments in 99/00S4 07/00 Petroleum Coke Utilization Options 97/98S10 03/99 Phenol/Acetone/Cumene 01/02-2 10/02 Phenol/Acetone/Cumene 96/97-2 12/97 Phenol Manufacture, On-Purpose N2O Production for 98/99S14 10/99 Plants as Plants 00/01S6 12/02 Plastic Beer Bottles 00/01S1 04/02 Polyacetal 01/02S12 10/02 Polyaspartic Acid 96/97S4 04/98 Polybutylene Terephthalate 98/99S6 07/99 Polycarbonates 01/02-5 07/02

Title Report Date Polycarbonates 97/98-8 10/98 Polyesters, High Performance 94/95S6 10/96 Polyesters, Unsaturated 94/95S7 10/96 Polyether Polyols 03/04S5 10/04 Polyethylene, High Density 96/97-3 04/98 Polyethylene, LDPE/LLDPE 94/95-1 02/97 Polyethylene Terephthalate 02/03-6 09/03 Polyethylene Terephthalate 98/99-5 01/00 Polylactic Acid/Lactic Acid, Biotech Route to 00/01S3 10/02 Polymers, Biodegradable 94/95S13 02/97 Polymers, Super Absorbent (SAP) 03/04S3 04/04 Polymer Compounding 99/00S2 04/00 Polyphenylene Oxide, Modified (MPPO) 02/03S3 03/03 Polyphenylene Sulfide (PPS) 02/03S4 04/03 Polypropylene 02/03-3 08/03 Polypropylene 98/99-1 01/00 Polypropylene Compounding 04/05S6 * Polystyrene 04/05-4 * Polystyrene 96/97-1 05/97 Polystyrene/ABS 00/01-1 06/01 Polyurethanes, Thermoplastic (TPUs) 02/03S7 05/03 Polyvinyl Alcohol 01/02S5 11/02 Polyvinyl Chloride (PVC) 03/04-2 03/04 Polyvinyl Chloride 98/99-2 04/99 Propanediol, (1,3-), Biotransformation Routes to 97/98S4 09/98 Propionic Acid 98/99S10 06/99 Propylene, Ethylene 00/01-4 06/01 Propylene, Ethylene 96/97-6 03/97 Propylene Oxide 02/03-8 11/03 Propylene Oxide 97/98-7 12/98 Propylene Oxide Technology, Develop- ments in 00/01S12 11/01 Propylene Refineries 03/04S7 01/05 Propylene, Routes to 97/98S3 02/00 PTA Production Technologies, Develop- ments in 00/01S7 02/02 PTMEG/Spandex 01/02S11 12/02 Pulp Bleaching: A Life Cycle Case Study 94/95S10 09/96


Title Report Date Pyromellitic Dianhydride/Trimellitic Anhydride 99/00S8 07/00 Pyrrolidones, Routes to 94/95S1 02/97 Reducing Costs in PET Manufacture 04/05S7 07/05 Refineries, Propylene 03/04S7 01/05 Refinery of the Future as Shaped by Environmental Issues 02/03S11 12/03 Routes to Propylene 97/98S3 02/00 Routes to Pyrrolidones 94/95S1 02/97 Silicones 00/01S5 05/02 Sorbitol and Ascorbic Acid 97/98S11 03/99 Spandex/PTMEG 01/02S11 12/02 Specialty Chemicals, Alternative Routes to: Developments in Bioprocessing Technologies 96/97S1 05/97 Stationary Fuel Cells 02/03S6 11/03 Steam Cracker Feedstocks, Fischer- Tropsch Liquids as 01/02S9 12/02 Styrene Butadiene Rubber/Butadiene Rubber (SBR/BR) 02/03S1 12/03 Styrene/Ethylbenzene 03/04-8 11/04 Styrene/Ethylbenzene 99/00-6 08/00 Styrene/Ethylbenzene 94/95-8 03/96 Styrene from Ethane and Benzene 04/05S10 * Sulfide, Polyphenylene (PPS) 02/03S4 04/03 Super Absorbent Polymers (SAP) 03/04S3 04/04 Superabsorbent Polymer Technology, Developments in 94/95S8 12/96 Supply Chain IT Applications on the Refining Industry, Impact of 04/05S4 * Syngas Technologies, Developments in 03/04S4 02/05 TDI/MDI 98/99S8 09/99 Technology Management, Managing, in the Chemical Industry 97/98S2 06/99 Terephthalic Acid 01/02-4 12/02 Terephthalic Acid 97/98-5 02/99 Terephthalic Acid, Medium Quality 03/04S6 10/04 Thermoplastic Copolyester and Copolyamide Elastomers 02/03S9 10/03 Thermoplastic Elastomers, Developments in 98/99S12 11/99 Thermoplastic Nanocomposites 00/01S11 09/01 Thermoplastic Polyolefin (TPO) and Vulcanizate (TPV) Elastomers 01/02S1 07/02

Title Report Date Thermoplastic Polyurethanes (TPUs) 02/03S7 05/03 Titanium Dioxide 99/00S14 08/00 Toluene/Benzene 02/03-5 04/03 Toluene/Benzene 98/99-6 05/99 Trimellitic Anhydride/Pyromellitic Dianhydride 99/00S8 07/00 Unconventional Heavy Oils 04/05S9 11/05 Unsaturated Polyesters 94/95S7 10/96 Urea 96/97S5 09/97 Utilization Options, Petroleum Coke 97/98S10 03/99 UV/EB Curable Materials 94/95S3 05/97 Title Report Date Vinyl Chloride/Ethylene Dichloride 03/04-6 01/05 VCM/EDC 99/00-3 04/00 VCM/EDC 94/95-5 08/96 Vinyl Acetate 00/01-3 02/02 Vinyl Acetate 96/97-5 07/97 Vinyl Acetate Process, Fluidized Bed 98/99S3 02/00 Xylenes 01/02-7 05/02 Xylenes 97/98-3 07/98

gas processing and ngl extraction

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