Scale Evaluating Water Constituents To Understand Which ...
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ScaleEvaluating Water Constituents To Understand Which
Constituents Encourage Scale Formation Downhole And How To Utilize Scale Inhibitors And Dissolvers
Economically To Reduce Build-Up
Stephen Vance
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What is scale?
• They are solids that block pipes, pore throats, etc.
• They are mainly inorganic minerals that do not like to dissolve in water
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Why does this happen?
• It can happen in several ways
• Water incompatibility
– Fresh water usually has high amount of insoluble anions
• Sulfates – SO42-
• Carbonates and bicarbonates – CO32- and HCO3
-
– Indicated by a high pH
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Why does this happen? (cont.)
• Water in the shale formation usually has high amounts of cations
• Calcium – Ca2+
• Magnesium – Mg2+
• Barium – Ba2+
• Strontium – Sr2+
• Iron – Fe2+
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Why does this happen? (cont.)
• These connate waters mixed with fresh waters can upset the equilibrium of the solvated ions
• When one type of cation sees a particular anion, their ability to remain apart is threatened
– Ca2+(aq) + CO32- (aq) CaCO3(s)
– Ba2+(aq) + SO42-(aq) BaSO4(s)
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Crystal Lattice
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Why does this happen? (cont.)
• If there is no mixing of fresh water with produced water, the solubility of the ions are dictated by temperature and pressure
– Under pressure ions stay dissolved
– Usually scale will form when there is a drop in pressure
– Equations of state are used to determine if scale will form
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Why does this happen? (cont.)
• Temperature
– Calcite and siderite scale out when temperature goes up
– Barite scales out when temperature goes down
– Celestite and gypsum scale varies with temperature
• Solubility goes up with temperature, then goes down
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Water Analysis
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Water Analysis (cont.)
Red line shows saturation index
Blue line shows pounds of scale per thousand barrels of water
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Water Analysis (cont.)
0.00
0.50
1.00
1.50
2.00
2.50
3.00
3.50
30 40 50 60 70 80 90 100 110
Satu
rati
on
ind
ex,
Bar
ite
Temperature, F
Barite Saturation Index vs. Temperature (F)Inhibitor Concentration Risk Curves
SIBar+10 mg/L Inh
SIBar+3 mg/L Inh
SIBar+1.0 mg/L Inh
SIBar+0.3 mg/L Inh
SIBar+0.0 mg/L Inh
Water Sample SICal
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Calcite and Aragonite
• Calcium carbonate
CaCO3
• A very common
scale
• Acid soluble
• Solubility goes up
when pH goes down
• Solubility goes down with increasing heat
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Gypsum
• Calcium Sulfate
CaSO4
• Acid insoluble
• Can be chelated with things like EDTA
• Can be converted then acidized
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Barite
• Barium sulfate
BaSO4
• Acid insoluble
• Proportionally soluble with increasing heat
• Usually mechanical removal is only method
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Siderite
• Ferrous carbonate
FeCO3
• Usually caused by corrosion by-product
• Same issues as calcite
• Can be useful in corrosion protection
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Iron Sulfide
• FeS
• Product of H2S and ferrous iron
• THPS or Acrolein is used to get rid of it
• Needs time and surfactants help get through the oil wet solids
• Acrolein is very dangerous
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How to prevent scale
• Crystal Inhibitors– Phosphate Esters
• Example: citric acid phosphate
• Heat restrictions
• 175 °F?
• o-Phosphate (orthophosphate can cause calcium phosphate)
• Apatite
• Acid insoluble
Kelland, Malcom A. Production Chemicals for the Oil and Gas Industry. Boca Raton: Taylor and Francis Group, 2009. Print.
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How to prevent scale (cont.)
– Organophosphonates
• Examples: ATMP, DETA, BHMT, AEEA
• Always though of them like the 300 Spartans
• More heat tolerant compared to phosphate esters
• Calcium tolerance can be an issue
–Bonds with calcium to make a precipitate itself
» BHMT is better at avoiding that than DETA
Kelland, Malcom A. Production Chemicals for the Oil and Gas Industry. Boca Raton: Taylor and Francis Group, 2009. Print.
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How to prevent scale (cont.)
– Organophosphonates• N,N’-bis(3-aminopropyl)ethylene diamine
phosphonate is claimed to be better at barite scales
• Can be overwhelmed with high brine concentrations
• pH is critical
–Keep around 4.5-7
– Loses effectiveness above 7
–Chloride corrosion has been suspected
Kelland, Malcom A. Production Chemicals for the Oil and Gas Industry. Boca Raton: Taylor and Francis Group, 2009. Print.
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How to prevent scale (cont.)
• Crystal Modifiers (polymers)– Polycarboxylates are the most common in our field
• Examples: Salts of polyacrylic acid, polymethacrylic acid, and polymaleic acid
– Hard to deliver
– Heat tolerant
– Does not stop precipitation of the insoluble ions• Stops the adherence of the precipitated solids
– Not overwhelmed by high salt brines
– Usually can’t be tracked without tags
Kelland, Malcom A. Production Chemicals for the Oil and Gas Industry. Boca Raton: Taylor and Francis Group, 2009. Print.
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Solvent Package
• Most scale inhibitors are water based
• Water can evaporate in hot wells
• Ethylene glycol, butyl cellusolve, etc. have higher boiling points
– Keep scale inhibitors in solution
– Usually adds ~20% more to cost
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Chemical Delivery
• Capillary String
• Costly ($1-$2/foot installed)
• Best way to ensure chemical delivery
• There are strings that can go past packers
• Very good for ESPs and downhole scale inhibition
• Have to ensure chemical is cap string approved
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Chemical Delivery (cont.)
• Downhole
• Gas Lift
• Always inject on side of gas injection
• Dry gas dehydrates chemical more than wet gas
• Packers – only treat to bottom gas lift valve
• Best to use a 50-200’ stinger of capillary tubing
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Chemical Delivery (cont.)
• Backside no gas lift
• If flowing or packer in place, unable to treat down hole
• No idea of life cycle of chemical– Could be in for a few hours
– Could be in for days
– When does it get around?
– Have to test residuals
– Coupon data
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Chemical Delivery (cont.)
• If well is surging on backside, the chemical could come out the backside and not ever get to tubulars
• Backside flush with produced fluid to ensure delivery
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Scale Squeeze
• Not preferred
• Squeezing is not correct name for lateral wells
– Spot is more appropriate nomenclature
– Assumed to go to most water bearing zone
– More than likely goes to least pressured zone
• Costly (Ex. $6500/spot)
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Scale Squeeze (cont.)
• Tagged polymers are best to use in spot
– Monitor residuals by ICP or tag
– Once levels get below usually 5 ppm, squeeze is needed again
• Most of the squeezed chemicals come out in the first months after squeeze
– Usually need to redo after six months
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Scale Squeeze (cont.)
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Solids AnalysisWhat if you don’t prevent scale?
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How to remove scale
• Calcite (calcium carbonate)
– Acid
– Mainly HCl, because HF can cause CaF2(S)
• Corrosive
• Time to shut in and react
– Acetic Acid usually too weak and slow
– THPS could be used but not really its purpose
– Surfactant is used sometimes to wash oil off
Kelland, Malcom A. Production Chemicals for the Oil and Gas Industry. Boca Raton: Taylor and Francis Group, 2009. Print.
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How to remove scale (cont.)
• Gypsum (calcium sulfate)
– EDTA salts can be used to chelate it which dissolves it
• Need high pH (~8) to make the EDTA functional
– Can be converted to be acidized
• Use of strong bases are used to make calcium sulfate into calcium carbonate or calcium hydroxide
• Then acid is used to dissolve it
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How to remove scale (cont.)
• Barite (barium sulfate)
– Basically has to be mechanically milled out
– Chelation and conversion can’t really be effective
– Costs to chemically remove barite usually is more than removing it mechanically
– Usually present in surface equipment
– Diethylenetriamine pentaacetic acid (DTPA) has been used at a pH of 12 or higher
– Best bet is to prevent it
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Chelation Dissolution
M = Divalent ion like Ca2+ or Ba2+
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Dynamic Tube Block Test
• Scale chemicals are best tested by dynamic tube block apparatus
• Mixes a synthetic brine to make a representative fluid that may be encountered
• If scale inhibitor does not work tube scales up
– This is evident by pressure going up
• If scale inhibitor works, the fluids will not scale
– This is evident if pressure stays low
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Dynamic Tube Block Apparatus
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Cost Exercise
• Scale inhibitor cost $8/gallon
• Recommended rate 100ppm
• Well makes 650 barrels of water a day
• That would be ~11 quarts a day of chemical
• ~$22 a day or ~$8000 a year
• Usual replacement of a string of tubing is ~$30,000
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Phosphate Residuals
• Ex: 5 ppm of phosphorus– Phosphorus 30.97 g/mol
– DETA phosphonate 573.20 g/mol
– There are five in DETA, so weight percent is [(30.97 x 5)/573.20] x 100 = 27.0% Phosphorus
– Reciprocal factor is 3.70
– So 5 ppm P x 3.70 = 18.5 ppm of DETA phosphonate
– Minimum inhibition concentration (MIC) may be as low as 5 ppm DETA therefore GOOD
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QUESTIONS OR COMMENTS?