Flow Assurance (2)

Gas Hydrate

 

Gas hydrate is crystalline solids wherein guest (generally gas) molecules are trapped in cages formed from hydrogen bonded water molecules (host).  They are formed as a result of physical combination of water and gas molecules, i.e. methane, ethane, propane, isobutane, normal butane, nitrogen, carbon dioxide, and hydrogen sulfide. 

The necessary conditions are:

– Presence of water or ice

– Gas molecules C₁, C₂, C₃, n-C₄, i-C₄, CO₂, N₂, H₂S

– Suitable temperature and pressure conditions

Figure below shows typical of hydrate curve. Left side is region where hydrate can be formed. When system pressure and temperature is within this region, water and gas will form hydrate. Right side is non-hydrate region. When system pressure and temperature is within this region, water and gas will not form hydrate.

Fig 1. Hydrate curve

Some scenarios which hydrate can occur are:

o   gas expansion or cooling effect

o   startup and shutdown

Hydrate can easily form at downstream of choke valve when system pressure and temperature decreases and it reaches right side of hydrate curve.

 

There are some methods to avoid hydrate problems, i.e.:

1.       Water removal (dehydration)

2.       Increasing/maintaining temperature

– Insulation

– Heating

3.       Decreasing pressure

4.       Injection of thermodynamic inhibitors

– Methanol, ethanol, glycols

5.       Using Low Dosage Hydrate Inhibitors

– Kinetic hydrate inhibitors (KHI)

– Anti-Agglomerants (AA)

6.       Various combinations of the above

 

Source :

Boyun Guo, Shanhong Song, Jacob Chacko, Ali Ghalambor, Offshore Pipelines, Gulf Professional Publishing, Oxford, 2005

E. Dendy Sloan Jr., Natural Gas Hydrates, SPE, Colorado School of Mines, 1991.

Bahman Tohidi, Gas Hydrates: Friend or Foe?, SPE, Heriot-Watt University, Edinburgh, UK.

Flow Assurance (1)

Produced Water Effect

 

Produced water comes from reservoir. Water is good solvent; therefore it can solve many chemical compound and gas in formation. Water also contains suspended solid and contaminant. In formation, water and chemical compound usually is in equilibrium. When produced water move from formation to surface, due to temperature and pressure change, equilibrium is disturbed. Some chemical compound undissolved, precipitated, and form scale. When produced water contact with pipeline wall which made from carbon steel, produced water can dissolve metal and make corrosion problem in pipeline. When produced water and gas flow simultaneously in pipeline at certain pressure and temperature, they can form hydrate. The hydrate can plug pipeline.  Produced water existence can make problem of flow assurance in pipeline.

Important ions regarding flow assurance are below:

Anion

• chloride Cl^-
• sulfide HS^-
• sulfate SO₄^2-
• bromide Br^-
• bicarbonate HCO₃^-
• carbonate CO₃^2-

Kation

• natrium Na⁺
• kalium K⁺
• calsium Ca²⁺
• magnesium Mg²⁺
• strontium Sr²⁺
• barium Ba²⁺
• iron Fe²⁺ dan Fe³⁺
• aluminum Al³⁺

Cation and anion can combine to form several compounds. When pressure and temperature is changed, solubility of each ion can be changed. Ion can be precipitated from produced water and form solid, such as scale. For example, calcium ion and carbonate ion can form calcium carbonate scale.

Ca²⁺ + CO₃^2- à CaCO_3(s)

Barium ion and sulfate ion can form barium sulfate scale.

Ba²⁺ + SO₄^2- à BaSO_4(s)

Produced water with soluble salt is good electrolyte. It can cause corrosion. When produced water contact with pipeline wall, corrosion will occur. The greater amount of salt or ion in produced water, the more conductive produced water, and the more severe corrosion occurs.

When gas contact with produced water at certain pressure and temperature, hydrate may occur. At high pressure and/or low temperature, hydrate can occur and plug the pipeline. Once pipeline plugged by hydrate, it is require weeks even months to dissociate hydrate. Plugging by hydrate is one of main problem in pipeline, especially subsea pipeline.

Produced water can change characteristic of multiphase stream in pipeline and cause slug. If gas quantity is small, while liquid amount is much, it is hard for gas to “carry” liquid. Therefore, slug will be occurred.

Source : Offshore Pipelines, Boyun Guo, Shanhong Song, Jacob Chacko, Ali Ghalambor, Gulf Professional Publishing, Oxford, 2005

Mercury Removal (3)

Factors Influencing Mercury Removal

 

Particle Size Effect

Size of adsorbent particle has effect on performance and pressure drop. For same weight, the smaller particle size, the smaller its surface area, therefore the performance is better.

In contrast with pressure drop, for same weight, the smaller particle size, the greater number of adsorbent (the larger adsorbent surface area), the greater gas friction with adsorbent, therefore the higher pressure drop. 

Gas velocity effect

Below is result of test which conducted  by one of mercury adsorbent vendor.

Table 2. Effect of Residence Time and Gas Velocity to Mercury Removal Efficiency

Residence time (s)	Mercury removal efficiency (%)
	3 ft/min	6 ft/min
1,7	43	58
3,3	80	89
5,0	91	100

From table above, we can conclude that:

-          the longer residence time of gas in bed, the higher efficiency of mercury removal,

-          the higher gas velocity, the higher efficiency of mercury removal

 

Temperature Effect

Generally, the higher temperature, the faster reaction occurs. But at high temperature, the impregnated sulfur will be:

-          vaporized at inert condition, or

-          oxidized if contact with air

Therefore adsorbent performance will be decreased.
 

Mercury Content Measurement

Main problem in mercury content measurement is mercury amount is decreased because some of mercury will be sticked at sample line and container wall. To overcome this issue and to obtain accurate result, purging is conducted.

Currently mercury in gas is usually measured by atomic fluorescence spectrometry (AFS). Gas is flowing to gold trapping tube to dense mercury. For gas with high pressure, gas pressure is decreased utilize pressure regulator. To avoid condensation due to pressure drop, electrical heating is utilized. Then mercury is desorbed from tube by heating (up to 800^oC), utilize carrier gas flowing to analyzer.

To measure mercury content in liquid, same method is utilized with modification, i.e. formerly change liquid to gas.

 

Interaction between Mercury and Metal Surface 

Mercury can stick at steel surface of pipe and vessel with concentration of 2 – 10 g/m². Until now, mechanism of how mercury can be adsorbed by steel is not known. So far, the postulate is mercury reacts with grain boundary of element or compound in steel.

Chemical properties of steel surface which contain mercury is different with chemical properties of steel-with-no-mercury. 

Pipeline

Cooling and compression process can produce liquid mercury which settles in pipeline. This is known when pigging is conducted.

The question is: Does liquid mercury which settles in pipeline accelerate galvanic corrosion? 

Tank in Ship

Contamination can occur:

-          at bottom of tank due to sludge.

-          at exterior of nonmetallic surface layer (scale, inorganic material, sometimes at coating).

-          mercury is possible “in” or “on” steel surface.

Mercury which is at steel surface can make inhalation problem for worker when pipe is welded or cutted.

Mercury interacted with:

-          aluminum: causing LME (liquid metal embrittlement)

-          steel

-          copper: causing crack

Mercury will affect to:

-          equipment integrity

-          health and safety of worker

-          product quality

-          environment

Mercury and Carbon Steel

The good news is:

-          mercury doesn’t accelerate corrosion

-          no significant galvanic effect

-          no detrimental impact to stress corrosion cracking (SCC)

Mercury can be adsorbed by metal. When gas flow from well to plant through pipeline, some mercury is stuck at pipeline wall. Pipeline wall has capacity to adsorb mercury. When saturated, there will be no additional mercury stuck at pipeline wall. The impact is at that time mercury content in gas which comes to plant will increase than previous. Table below shows estimated lag time of mercury at pipeline.

Table 3. Lag Time of Mercury at Pipeline

Surface area (m2)	Gas flowrate (MMSCFD)	Mercury flowrate (g/h)	Surface area capaacity (gram mercury/m2)	Time to come to shore / station (months)
200.000	40 - 50	20 - 40	1	9
			2	18
			5	46
			10	93

 

Source:

-          Interaction of Mercury with Metal Surfaces, Johnson Matthey Catalysts, 2009

-          Carnell and Willis, Mercury Removal from Liquid Hydrocarbons, Johnson Matthey Catalysts, 2005.

-          NUCON, MERSORB® Mercury Adsorbents, Design and Performance Characteristics, Bulletin 11B28 – 2010.

-          https://www.osha.gov/Publications/mercuryexposure_fluorescentbulbs_factsheet.pdf

-          Abu El Ela, I.S. Mahgoub, M.H. Nabawi, and Abdel Azim, Mercury Monitoring and Removal at Gas Processing Facilities: Case Study of Salam Gas Plant, Society of Petroleum Engineer (SPE), 2008.

Mercury Removal (2)

Mercury Removal from Hydrocarbon

 

Dissolved elemental mercury (Hg^o) and mercury compound is removed utilized adsorbent. While mercury in solid phase is removed by physical separation.

There are 2 components of adsorbent, i.e.:

(1)    Support, for example zeolite, activated carbon, metal oxide, and alumina.

(2)    Reactive component, for example Ag, KI, CuS, metal sulfide, and thiol.

Materials which can disturb adsorbent are:

-          H₂S

-          water

-          olefin and aromatic hydrocarbon

-          thiol

-          other metal: arsenic

Mercury is volatile. The volatility of mercury limited operating temperature, usually below 100^oC. Ideally operation is conducted at near ambient temperature.

Adsorbent which is utilized for mercury removal can be divided into 2 groups, i.e. non-regenerative adsorbent and regenerative adsorbent.

 

Non-regenerative mercury removal

Advantage of non-regenerative method is:

-          Simple, “Install it and leave it!”

Disadvantage of non-regenerative method are:

-          High installation cost.

-          There will be additional pressure drop if adsorbent has been saturated.

-          Need cost to dispose used adsorbent.

If mercury is detected in effluent and pressure drop through bed is exceeded, adsorbent need to be changed with new one.

Materials which disposed from adsorbent are:

-          Mercury

-          Others (such as benzene)

 

Non-regenerative mercury removal method utilized some options below:

1.       Sulfur

2.       Metal sulfide

3.       Halide

4.       Ion exchange resin

 

1.      Sulfur

Sulfur is dispersed in porous carrier, for example activated carbon. Sulfur impregnated at carbon. Carbon is support component, while sulfur is reactive component.

Sulfur reacts with mercury to form HgS. This reaction occurs fast.

Hg + S à HgS

       This is old method. On 1970s LNG Badak Indonesia utilized this method.

Quality of product depends on:

-          Quality of activated carbon (as support)

-          Method to make sulfur dispersed at carbon

Sulfur must be dispersed properly without any blockage in porous carrier. If not, then:

-          Mercury removal process can’t be optimum.

-          Sulfur is not impregnated well; therefore sulfur can be carried over by gas stream at high temperature.

Sulfur is dissolved in liquid hydrocarbon. Therefore, method of impregnated sulfur at carbon can only be utilized for gas service. Contact between adsorbent and liquid hydrocarbon should be avoided.

Disadvantage of this method are:

-          Used material should be disposed since it can’t be utilized again.

-          In environmental point of view, acceptable mercury disposal is by burning/incineration.

-          Sulfur is dissolved in liquid hydrocarbon, especially aromatic hydrocarbon, therefore there is possibility sulfur will be carry over in product stream.

 

2.      Metal sulfide

Next development is mercury removal utilized inorganic compound/metal. Metal sulfide is dispersed at solid carrier (activated carbon, alumina). Sulfur is impregnated at metal. Reactivity between mercury and metal sulfide is very high.

Hg + M_xS_y à M_xS_y-1 + HgS

      Advantages of this method are:

-          Used adsorbent can be utilized again.

-          Risk of sulfur carry over to product stream (through sublimation or dissolution) is low. 

Disadvantage of this method is:

-          Not fit for “empty” fluid.

This disadvantage can be solved by installing pre-filter at upstream of mercury guard bed. 

Metal sulfide and polysulfide can remove mercury effectively. Common metal utilized are Cu, Zn, and proprietary metal. If required, metal oxide can be added to remove H₂S. If metal is Cu, the reactions are:

CuO + H₂S    à CuS + H₂O

2 CuS + Hg   à HgS + Cu₂S 

Metal sulfide is utilized for gas and liquid hydrocarbon service. This adsorbent is not damaged if contact with liquid water. 

Adsorbent pellet size is circa 0.9 – 4 mm. Pellet with small size can increase efficiency of mercury removal, but also make high pressure drop. 

	Pellet size
	Small	Large
Efficiency of mercury removal	high	low
Pressure drop	high	low

  

3.      Halida

Halide impregnate at activated carbon. This adsorbent is utilized for liquid hydrocarbon.

Hg + I à HgI₂

Liquid water can make this halide wash off from activated carbon and make vessel corroded. 

4.      Ion Exchange Resin

Ion exchange resin is utilized for liquid naphtha service.

 

Regenerative mercury removal

Regenerative adsorbent is like non-regenerative adsorbent. The difference is in mercury removal process utilized regenerative adsorbent, there is thermal regeneration process. Usually regenerative mercury removal is conducted simultaneously with dehydration process or other contaminant removal process.

For example is silver (Ag) which impregnate at molecular sieve. Mercury (from gas or liquid) will form amalgam with silver. At high temperature mercury will be separated from silver, utilize regeneration gas.

Advantages of regenerative method are:

-          No additional pressure drop.

-          Mercury can be recovered as separated stream.

Disadvantage of this method are:

-          Require additional equipment for regeneration process.

-          Gas which is utilized for regeneration probably need additional treatment to remove mercury (secondary mercury removal treatment).

Source:

-     Interaction of Mercury with Metal Surfaces, Johnson Matthey Catalysts, 2009.

-     Carnell and Willis, Mercury Removal from Liquid Hydrocarbons, Johnson Matthey Catalysts, 2005.

-     NUCON, MERSORB® Mercury Adsorbents, Design and Performance Characteristics, Bulletin 11B28 – 2010.

-     https://www.osha.gov/Publications/mercuryexposure_fluorescentbulbs_factsheet.pdf

-      Abu El Ela, I.S. Mahgoub, M.H. Nabawi, and Abdel Azim, Mercury Monitoring and Removal at Gas Processing Facilities: Case Study of Salam Gas Plant, Society of Petroleum Engineer (SPE), 2008.