Natural Gas Processing

Dr. Stathis Skouras, Gas Processing and LNG

RDI Centre Trondheim, Statoil, Norway

Outline

Natural Gas Processing

• Gas quality specifications

• Water dew point (WDP)

• Acid gas removal (AGR)

• Trace component removal (H2S and Hg)

2

Gas Processing

Why gas processing?

• Ensure unproblematic transport and processing

• Prevent ice and gas hydrates

• Prevent condensation of hydrocarbon liquids

• Prevent corrosion and erosion of equipment

• Fulfill commercial requirements

• Ensure safe use of gas to end-users

3

Gas quality specs along the value chain (1/2)

Specifications for “rich gas” transport Offshore processes

Prepares gas for

further transport

Onshore processes

Designation and unit Specification

Max operating pressure (barg) 210

Min operating pressure (barg) 112

Max operating temperature (°C) 60

Min operating temperature (°C) -10

Max cricondenbar pressure (barg) 105

Max cricondentherm temperature (°C) 40

Max water dew point (°C at 69barg) -18

Max carbon dioxide (mole%) 2

Max hydrogen sulphide and COS (ppmv) 2

Max O2 (ppmv) 2

Max daily average methanol content (ppmv) 2.5

Max peak methanol content (ppmv) 20

Max daily average glycol content (LT/MSm3) 8

4

• Space and weight

limitations

• Expensive labour

• Expensive utilities

(cooling, water,

chemicals, electricity)

• Escape issues

Specifications for “sales (dry) gas” transport

Gas quality specs along the value chain (2/2)

• Prepares gas

for end user

• Recovers

valuable

NGL

products

Onshore processes

Receiving terminals

Designation and unit Specification

Hydrocarbon dew point (°C at 50 barg) ˂-10

Water dew point (°C at 69 barg) -18

Maximum carbon dioxide (mole%) 2.50

Maximum oxygen (ppmv) 2

Maximum hydrogen sulphide incl. COS (mg/Nm3) 5

Maximum mercaptans (mg/Nm3) 6.0

Maximum sulphur (mg/Nm3) 30

Gross Calorific Value (MJ/Sm3) 38.1 – 43.7

Gross Calorific Value (MJ/Nm3) 40.2 – 46.0

Gross Calorific Value (kWh/Nm3) 11.17 – 12.78

Wobbe Index (MJ/Sm3) 48.3 – 52.8

Wobbe Index (MJ/Nm3) 51.0 – 55.7

Wobbe Index (kWh/Nm3) 14.17 – 15.47

5

• No space and

weight

limitations

• Access to

utilities

(cooling, water,

chemicals,

electricity)

• Easy escape

• Water occurs naturally in the reservoir

• Free water phase is removed in 3-phase separators

• Water (vapour) is physically dissolved in the natural gas

(in equilibrium)

• Water must be removed from the gas to avoid:

− Free water in gas pipelines (corrosion)

− Ice/hydrate formation (plugging of equipment and pipes)

• Water removal processes:

− Condensation (cooling and separation)

− Absorption by glycol processes (moderate dew-pointing)

− Adsorption on solids (severe dew-pointing)

Water dew point

6

7 -

Water dependency of water dew point line

Phase envelopes

0

20

40

60

80

100

120

140

160

180

200

-150 -100 -50 0 50 100 150 200

Temperature [C]

Pre

ss

ure

[B

ar]

HC curve

3 % Water

2 % Water

1 % Water

0.5 % Water

0.1 % Water

0.05 % Water

Water dew point specifications

Transport

specification:

-18ºC at 69 barg

(20-30 ppm)

Process needed:

Glycol absorption

process

Offshore processes Onshore processes

Process

specification:

0.1 to 1 ppmv

Process needed:

Adsorption on

solids

8

Glycol

Contactor

Cooler

Filters

Glycol

Regenerator

Surge drumPump

Filter

Glycol/condensate

separator

Wet natural

gas

Dry natural gas

Rich TEG

Lean TEG

LT HX HT HX

Water

vapour

Flash drumP=70 bar

T=30ºC

P=1bar

T=200ºC

• Counter-current mixing with tri-ethylene glycol (TEG)

• Meets pipeline water dew point specifications (-18ºC at 69 barg)

Water removal offshore - Glycol absorption (physical)

9

Water removal onshore - Adsorption on solids

10

• Adsorption in to a solid material

− Used in “deep” gas processing at low temperatures

− Removal of smaller amounts of water

− Extreme dryness, down to 0.1 ppm water

• Porous structures with high internal surface area (200 –

800 m2/g)

• Strong affinity for water, 5 – 25 % by weight

• Common adsorbents

− Molecular sieve (3A or 4A type) (Zeolite)

− Activated alumina (Al2O3)

− Silica gel (SiO2)

• Regenerative process

Water removal by adsorption

12 -

TSA or PSA

Source: Engelhard

Regeneration at

low pressure and

high temperature

Absorption at

high pressure and

low temperature

Acid/sour gas removal (CO2 and H2S)

• Most natural gas contains acid gas

− CO2 (acid)

− H2S and other sulfur compounds (sour)

• Why remove acid gas:

− Corrosion induced by acid gas (+ free water)

− Freezing of acid gas in process equipment

− Sales specifications

− Toxicity and reactivity (H2S)

• Typical specification for sweetened gas:

− CO2 in pipeline gas: <2 - 2.5 mol%

− CO2 in LNG: <50 ppmv CO2 (very low because of very low process temperatures)

− H2S: a few ppmv

13

Acid gas removal (CO2 and H2S) by absorption (physico-chemical) in amines

14

H2S (traces) removal on metal oxide

15

• Scavenger (offshore)

− Reactive amines based solution (triazines)

injected as chemicals

− Normally used off-shore for small amounts of H2S

− Non-regenerative

• Adsorption (onshore)

− Reaction oxides like for instance Iron oxide or

Zink Oxide

− MeO + H2S MeS + H2O

− <0.1ppmv H2S in product gas

− Non-regenerative

N

N

N

R

RRS

N

N

R

R

RNH2

R= CH3, CH

2CH

2OH

H2S +

H2S

S

S

NR

RNH2+

H2S

S

S

S

RNH2+

• Occurs naturally in virtually all oil & gas reservoir

• Mineral cinnabar (red), HgS, is believed to be the

main source of mercury in reservoirs

• Concentrations vary from few to hundreds of ppb

• Mercury compounds are highly toxic

Mercury in oil & gas

Geologic cinnabar, HgS (red)

16

➢ Hg°

➢ Hg+2X➢ R-Hg➢ HgS

Introduction – Mercury concentration in gas & condensate

* Yan, Ind. Eng. Chem. Res. 33 (1994) 3010-3014

** Abu El Ela et al., Oil & Gas J., vol. 104, (2006)

SE Asia, Australia

Hg (gas) = 200-300 µg/m3*

Hg (cond.) = 10-800 ppb

South America

Hg (gas) = 50-120 µg/Sm3**

Hg (cond.) = 26-40 ppb*

Africa (Nigeria)

Hg (gas) = 50-80 µg/m3*

Hg (cond.) = 500-1000 ppb**

NCS

Hg (gas) = 0.01-40 µg/m3

Northern Europe

Hg (gas) = 180 µg/m3*

North Africa

Hg (gas) = 50-80 µg/Sm3**

Hg (cond.) = 26-40 ppb*

➢ Hg°

➢ Hg+2X➢ R-Hg➢ HgS

23 august

201517Classif

ication

:

Introduction – Mercury implications

1. Process Equipment

✓ When in liquid form, can lead to equipment failure (Heat Exchangers) either through corrosion or Liquid Metal Embrittlement (LME)

✓ Adsorbs on equipment and pipelines

2. Health-Safety-Environment

✓ How to handle equipment during maintenance (entrance, hot work)

✓ How to dispose contaminated equipment, wastes (treat before recycle)?

✓ Special guidelines and procedures are necessary

23 august

201518Classif

ication

:

For gas and LNG processing, where aluminium equipment

is used, a specification of0.01 μg/Sm3 (10 ng/Sm3)

is established

Mercury removal by adsorption on solidsMain removal methods:

• Sulfur impregnated activated carbon

Hg + S HgS

• Reaction between Hg and a metal sulfide

(typically alumina) forming HgS (Chemisorption)

Hg + MSx MS(X-1) + HgS

• 10 ng/Sm3 Hg in product gas (LNG spec.)

• Can not be regenerated

• Typical intervals for adsorption beds: 4-6 years

19

20

Presenters name: Dr. Stathis Skouras

Presenters title: Principal Researcher

efss@statoil.com, tel: +47 97 69 59 62

www.statoil.com

Thank you