Carbon Sequestration in Sedimentary Basins Module II: Physical Processes in C Sequestration…

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Carbon Sequestrationin Sedimentary
BasinsModule II Physical Processes in C
Sequestration

• Maurice Dusseault
• Department of Earth Sciences
• University of Waterloo

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C Sequestration

• As CO2
• An enhanced oil or gas recovery agent
• Displacing formation water in deep aquifers
• Dissolved in the aqueous phase
• Storage in caverns (salt or rock caverns)
• As solid C
• Injection of petcoke, coal wastes, etc
• Biosolids injection and biodegradation to C
• As a mineral precipitate
• We will not consider this (unlikely) option

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Is Separation Best?

• Costly process
• Membranes (not quite there yet)
• Forced adsorption (amine solutions, etc.)
• High reactivity calcium oxide
• Cryogenic (low T methods)
• These would all double the cost of power in
  current configurations
• Modification of combustion process?
• New sequestration method?

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Coal power with CO2 separation 1982 Lubbock,
Texas. The plant was based on an oil price of
30/barrel and was discontinued when the oil
prices was sinking in the late 1980s. Only the
(now mothballed) MEA separation plant is shown.
The power plant itself is still running and is
located to the right of the picture
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CO2-capture Pilot Plant at Kaarstoe Norway
Capture from exhaust gas by use of membrane/amine
technology
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Carbon Sequestration Options

• Store CO2 as SC fluid in depleted reservoirs,
  suitable traps
• Dissolve CO2 into deep fluid reservoirs
• Use CO2 in Enhanced Recovery to displace oil or
  gas from strata
• Deep slurry injection of biosolids, coal, or any
  other solid organic waste
• Place CO2 in a dissolved salt cavern (the NaCl
  brine is industrial feedstock)

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CO2 Behavior

• Extremely complex (p, T, chemistry)
• Oil swelling with CO2 adsorption
• Interfacial tension issues (changes as a function
  of p, T, oil chemistry)
• Diffusion rates into H2O, oil
• Phase relationships in mixtures of gases, liquids
  (e.g SC-CO2 oil H2O),
• Changes in rock wettability
• Formation of hydrate phases

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Value-Added Options?

• No value-added
• Direct storage, no other resource is accessed
  or extracted
• This is only feasible in an incentive regime that
  favors sequestration or places an explicit value
  on C (e.g. tax or credit)
• Value-added sequestration
• C or CO2 used to access resources, is a byproduct
  of an valuable process,
• Sequestration is a ve but secondary factor

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HC Enhanced Recovery with CO2

• Enhanced Oil Recovery EOR
• Enhanced Natural Gas Recovery EGR
• Enh. Coalbed Methane Recovery - ECBM
• In each of these cases
• HC exists in a fluid or accessible form
• Conventional methods of production leave
  significant behind
• CO2 can improve the recovery factor
• CO2 largely left behind i.e. sequestered

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CCS CO2 Capture Seques.

• CO2 is captured from some source
• Or, flue gas is used, (partly enriched?)
• It is injected into the ground, into suitable
  porous and permeable media
• The CO2 stays there indefinitely

Typical Issues -Capacity and rate -Value-added
process? -Economics -Long-term fate -
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CO2 capture
C-rich coal waste injection
Alberta Research Council
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CO2 Behavior
We must understand the behavior of CO2 and the
site conditions!
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Pure CO2 Behavior

• Gaseous state storage
• Low density, low viscosity, under low p, T
• Liquid state storage
• High density, low µ, high p, low T lt35ºC
• Not compatible with real reservoirs
• Supercritical state, gt 35ºC, gt 7.2 MPa
• (gt 95ºF, gt 1035 psi, approximately)
• High ?, low µ,
• Fully miscible with water and oil
• Hydrate formation low T, high p, H2O

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Depth and CO2 State - I
20
40
60
0
0

• T increases w. depth 20-25ºC/km
• In most areas, T gt 35ºC below 800 m
• In cold conditions, pure CO2 will be in a a
  liquid state
• In the presence of water and high p, a CO2-H2O
  clathrate (hydrate) forms

T - ºC
TSC 35C
7.2 MPa
1000
Practical conditions for CO2 placement
2000
Depth below ground - m
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Depth and CO2 State - II
20
40
60
0
0

• Most reservoirs to Z 3 km hydrostatic
  pressures 10 kPa/m
• Pure CO2 is SC below 750 m, if T gt 35ºC
• In general, CO2 is a supercritical fluid at Z gt
  800 m (2620)
• Otherwise, it is a gas or a liquid, depending on
  p T

T - ºC
gas
TSC
gas
pSC
liquid
1000
liquid
SC-CO2
2000
Depth below ground - m
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Technologies for CO2 use

• In shallow reservoirs, CO2 as an inert gas to aid
  gravity drainage
• Displace CH4 from coal seams
• Deeper seams could be depressurized so pinj lt pSC
  for CO2
• CO2 could be used to chase gas from low
  permeability reservoirs (solubility in water may
  help considerably)
• Miscible CO2 flooding (Weyburn, SK)

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Inert Gas Injection (?? process)
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IGI, With Reservoir Structure
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Is Inert Gas Injection Useful?

• For IGI, a gas phase is needed for gravitational
  segregation and drainage
• So, CO2 must remain in a gaseous phase
• Density is less than 0.05
• Hence, the mass of CO2 that can be sequestered is
  trivial
• CO2 use in gravity drainage methods is of no
  value to sequestration needs
• Supercritical CO2 is needed

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Miscibility of Oil and CO2
102 bar 1500 psi Miscibility begins to develope
170 bar 2500 psi CO2 has developed miscibility
68 bar 1000 psi Immiscible CO2
Higher hydrocarbons (dark spots) begins to
condense
Final stage Higher HC forms continuous phase-
CO2 immiscible
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Miscible Conditions
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CO2, then a Water Slug, etc.
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Cyclic CO2 (also in THEOR)
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N2? Only at very great depth
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CO2 - EOR
Other permeable and non-permeable strata
Cap-rock or seal
Reservoir
?p
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Oil Production Phases
Phase I Primary Depletion ?p Phase II
Water Flood, ?p-maintenance Phase III CO2
miscible injection
Oil Rate
I
II
III
Time
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Why Different Phases?

• History CO2-EOR relatively new (1972)
• Economics
• Primary energy is the cheapest method
• Waterflood, often re-injection of produced H2O,
  is not as cheap, but still not costly
• CO2 is relatively expensive, in comparison
• Recovery Factors - RF
• Primary RF from 20-40 (average ?)
• Waterflood takes RF up to 30 to 55
• Miscible CO2 can take RF up to 80-85

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Potential for CO2 in EOR

• World-wide, perhaps 100109 m3 oil could be
  recovered with CO2-EOR in a supercritical or
  liquid state
• To recover 1 m3 of oil, likely we will have to
  inject from 0.5 to 2 m3 of SC-CO2, ? 0.80, into
  the reservoir permanently
• Mass sequestered
• 100109 m3 0.80 t/m3 0.5 40 Gt
• Other assumptions, other figures

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Miscibility of Oil and CO2
102 bar 1500 psi Miscibility begins to develope
170 bar 2500 psi CO2 has developed miscibility
68 bar 1000 psi Immiscible CO2
Higher hydrocarbons (dark spots) begins to
condense
Final stage Higher HC forms continuous phase-
CO2 immiscible
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Exploring Some Possibilities

• Oil reservoirs suitable for CO2 found at depths
  from 400 to 6000 metres
• Shallower risks of escape too high
• Deeper no oil, very expensive, etc.
• Now, we have to understand several factors
• How does CO2 behave?
• Technical options for oil recovery?
• Does CO2 injection fit in with these?

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HC Enhanced Recovery with CO2

• Enhanced Oil Recovery EOR
• Enhanced Natural Gas Recovery EGR
• Enh. Coalbed Methane Recovery - ECBM
• In each of these cases
• HC exists in a fluid or accessible form
• Conventional methods of production leave
  significant behind
• CO2 can improve the recovery factor
• CO2 largely left behind i.e. sequestered

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Physical Properties

• Porosity - f - controls storage volume available
  
• f fractional void space of the rock

Void space (fluids)
f
V of solid mineral
1 - f
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Physical Properties

• Permeability is the ability to transmit fluid
  (gas or liquid or SC-fluid)

• L 40 100 mm
• In the field, L 100 2000 m

L
?p
A
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Fluids - Oil, H2O, Gas, CO2

• Viscosity ƒ(T), Salinity (of H2O)
• Solubility behavior (diffusivity, mixing, h,
  contact area)
• Density ƒ(p, T), i.e. p-V-T behavior (EOS)
  (API gravity, Compressibility)
• Miscibility-pressure relationships in CO2
• Surface tensions
• Asphaltene, Other oil characteristics
• And so on

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CO2 Solubility in Water
This is at 1.0 atmosphere pressure. Increasing T
means lower solubility
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T Effects on CO2 Solubility

• CO2 solubility decreases with T until about 100ºC
• At higher T, solubility starts to increase with T

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N2 Solubility in Water
N2 is less than 1/10th the solubility of CO2 at
atmospheric pressure
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Gas Solubility in Water

• In water, N2 and CH4 are about 1/10th the
  solubility of CO2
• (Oxygen is slightly more soluble than CH4 but we
  dont worry about it)
• Hence, water will absorb and hold a lot more CO2,
  stripping it from flue gas
• We have also to look at the issue of pressure (
  depth ? 10 kPa/m)

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p-T Solubility of CO2 in H2O
Above 1050 psi, CO2 approaches supercriticality
http//www.kgs.ku.edu/PRS/publication/2003/ofr2003
-33/P 1-05.html
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CO2
Higher p Larger amount of CO2 in solution
h 298.15 mol/ kg bar
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Pressure Solubility, CO2 in H2O

• As p goes up, more gas in solution
• Henrys Law for ideal gases V(gas)STP in
  solution h?p?V(water)
• Henrys constant h 0.832 m3/m3/atm, but only
  for dilute solutions well below pc - the
  critical pressure
• Once pc is approached, the system departs from
  linearity, and then CO2 becomes fully miscible
  with H2O

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Effects of p on CO2 Solubility

• At constant T and constant salinity, the
  solubility of CO2 increases directly with
  pressure
• However, this pressure solubility effect
  decreases with increasing p
• So, at lower pressures the solubility increases
  more rapidly than at higher pressures

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CO2 Solubility in Brine
Sea water
The effect of dissolved NaCl
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Salinity CO2 Solubility in H2O

• Addition of any salt (usually NaCl of course),
  leads to a decrease in the solubility of CO2 in
  water
• There are effects of the nature of the salt (NaCl
  is worst than divalent soalts such as CaCl2)
• So, saturated brine is not as good as fresh
  water!
• In presence of reactive minerals?

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and, the Effect of pH!
Natural waters
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Reservoir Conditions

• Pressure (in the fluids)
• Temperature
• Stress (solid rock matrix)
• pH
• Current bubble point pressure of liquids
• Gas-to-oil ratio in situ
• Saturations So, Sw, Sg
• Production history, well test data

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What Will Governments Require?

• New Class VI wells (US-EPA), will need
• Geomechanical analysis of injection ops.
• Analyze report induced seismicity potential as
  the result of injection ops.
• Integrated modeling monitoring prog.
• Compositional modeling recommended
• Monitoring methods to be negotiated
• p measurements in overlying formation
• CO2 plume geophysical monitoring

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Reservoir Simulation

• A reservoir model is put together (see Module III
  for how this is done)
• The physics are incorporated as well as we can
• pVT laws, dissolution kinetics, multiphase fluid
  flow, hydrate formation
• Supercritical conditions and properties
• Contaminating gases and phase behavior
• Calibration, if possible, then predictions
• Prediction confirmation by monitoring

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Gaseous CO2 Distribution
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Dissolved CO2 Distribution
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Leakage Mechanisms

• Flow through intact pore structure in shale or
  anhydrite cap rocks is slow
• The main concerns appear to be
• Flow along an anthropogenic path, old or new
  wells, perhaps improperly sealed
• Flow through natural fracture systems
• Flow along a faulted structure

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Interfacial Tensions

• In the immiscible state, the CO2 that remains
  undissolved has a surface tension with water ƒ(p,
  T, salinity)
• With SC-CO2, no surface tension (mutually
  miscible)
• Similarly with light oils
• The situation with heavy oils is more complicated
  because of asphaltenes
• However, this means that capillarity as a flow
  barrier almost disappears!

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CO2 Behavior

• Extremely complex
• Oil swelling with CO2 adsorption
• Interfacial tension issues (changes as a function
  of p, T, oil chemistry)
• Diffusion rates into H2O, oil
• Phase relationships in mixtures of gases, liquids
  (e.g SC-CO2 oil H2O),
• Changes in rock wettability
• Formation of hydrate phases

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Pure CO2 Phase Behavior
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p-T-? EOS
Weyburn conditions 15 MPa, 45ºC
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Gas Migration, Segregation
Injection well, later converted to a gas
production well
Gas cap
Shale caprock
Gas bubbles
Sandstone
Biosolids
Base rock
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Chromatographic Gas Cleaning

• CH4 (75), CO2 (25), a bit of H2S, NOx
• These gases start to bubble upward
• But, the aqueous phase absorbs gas until it is
  saturated with each specie
• CH4 is very insoluble (lt 0.01 v/v/atm)
• CO2 H2S are highly soluble
• As gases migrate upward, these are stripped by
  dissolution, but not CH4
• Slow moving H2O carries CO2, H2S away

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Flat-Lying Aquifer Strata
N2 withdrawal
N2 withdrawal
vertical wells
Nitrogen
Dp 0
horizontal wells
2-phase gas-water region
The system must be operated at gravity drainage
conditions to avoid water coning to the
withdrawal wells
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Chromatographic N2 Stripping

• Flue gas is N2 (87), CO2 (13), a bit of H2S,
  NOx
• These gases bubble upward
• N2 far less soluble, H2O becomes CO2 saturated,
  N2 goes to top of reservoir
• Forced gravity convection renews H2O
• Slow moving H2O carries CO2, H2S away dissolved
  in the aqueous phase
• N2 released to atmosphere

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Reefs and CO2
previous injection/ production wells converted to
gas withdrawal wells
N2 withdrawal
vertical wells
horizontal well trajectory
nitrogen
low ?p maintained
gas injection uniform along well path
horizontal well placement based on permeability
below the well are only lower permeability reef
strata, k too low for economical injection
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Staggered Well Injection
Configurations with different combinations of
vertical and horizontal wells may be envisioned
N2 production well
N2 production well
Injection well
The bubbling gas generates forced H2O convection,
bringing fresh water with less CO2 to the
horizontal well region
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Complex Well Arrays
In principle, if gas can be uniformly injected,
it is best to have as much length as the
compressors can handle. Should we cool the gas
before injection into the reservoir? High T
reduces CO2 solubility Careful analysis is
always needed
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IGI, With Reservoir Structure
N2 withdrawal
rates are controlled to avoid gas (or water)
coning
mainly gas
horizontal well parallel to structure
Water and gas
keep ?p to a minimum
Gas segregation is an issue
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CO2, with Reservoir Structure
Gas segregation is an issue
N2 withdrawal
Rates are controlled to avoid gas (or water)
coning.
mainly gas
horizontal well at 90 to strike
water and gas
keep ?p to a minimum
The presence of shale layers can help mixing in
this case.
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How Much CO2 in H2O?

• Depends on p in the aquifer (partial pressure of
  CO2)
• Depends on the T of the reservoir
• Depends on the pH of the water
• Depends whether it is carbonate or not
• Depends on the salinity of the H2O
• Depends on other solutes
• So, to calculate the capacity

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More Coupling

• CO2, H2S gases dissolve in the water
• Gravity segregation occurs, displacing water from
  the system gravity drainage flow model forced
  convection
• Liquid flux carries dissolved gases away
• The cleaned N2 gas produced through upper well
  (p-V-T effects in reservoir)
• The CO2 dissolved in water is sequestered