Dr. deepjyoti mech hydrocarbon assurance - a research implications

Department of Petroleum Engineering
Presidency University, Bangalore
By
Dr. Deepjyoti Mech
Hydrocarbon Assurance: A Research
Implications

Introduction of the subject
Dr. Deepjyoti Mech, Presidency University Bangalore 2
 Increasing hydrocarbon production from the conventional and
unconventional reservoirs in the cold environments has led oil
companies to face a critical operational challenge of one or more
of the fluid flow assurance issues during production and
transportation of pipelines.
 Flow assurance issues such as hydrates, wax deposition are one
of the important areas being studied today due to the high cost of
deepwater exploration and production.

Schematic of a Slug

Gas Hydrates
Ice
that burns
Clathrates of natural gases in which the guest molecules of natural gases are
trapped inside the three dimensional lattice structure made by the host water
molecules.
Dr. Deepjyoti Mech, Presidency University Bangalore
Specific structure of a gas hydrate piece, from the
subduction zone off Oregon
(http://en.wikipedia.org/wiki/Methane_clathrate)
Burning of gas hydrate
(http://en.wikipedia.org/wiki/Methane_clathrate)
5

Advantage: An energy source
9
Hydrate Formation Stages

 Flow Assurance
Solutions
Hydrates plugging in the pipelines
*NGH phase diagram: Effect of inhibitor
Lw - Liquid Water; H - Hydrate and V - Vapor
Koh and Sloan, Ind. Eng. Chem. Res. (2009)
10

Wax Deposition

Wax Deposition Problems
 Wax deposition is, a common problem, a critical operational
challenge and one of the main flow assurance problems in the oil
industry around the world including the offshore and onshore oil
fields.
 The wax existing in crude oil mostly contains paraffin hydrocarbon
(C18-C36) recognized as paraffin wax and naphthenic hydrocarbon
(C30-C60). The hydrocarbon element of wax is able to present in
several phases, i.e., gas, liquid, and particles (solids), relying on the
flow conditions, i.e., pressure and temperature.

 The wax appearance
temperature (WAT), also
known as the cloud point, is
an important characteristic to
evaluate the possible wax
precipitation of a given fluid. It
is defined as the temperature
at which a crude oil first
precipitates.
Wax Appearance Temperature (WAT)

Asphaltenes
Asphaltenes are polar compounds, as
shown in figure, which present in the
heaviest fractions of the
crude oil and are defined by their
solubility characteristics.
Asphaltenes that mostly leads to
choking in pipelines and reservoirs’
wells. Normally, due to its high
tendency toward association and
aggregation, it is called as “Cholesterol
of Petroleum”.

Asphaltenes Deposition Envelope (ADE)

Scale Formation
The thermodynamic instability and
incompatibility of solutions often
cause a series of technical problems
in oil and gas exploitations, such as
the obstruction of equipment and
pipes, which could result in serious
damages and economic losses.
Scale deposition occurs in reservoirs
and in production facilities.

Energy Recovery

Gas Hydrate Reservoir

Different Hydrocarbon Reservoir

Flow Assurance for Drilling Operations

Basic Two types--
1) Thermodynamic Hydrate Inhibitors- Salts, Monoethylene
Glycol and Methanol.
2) Kinetic Hydrate Inhibitors Low Dosage Hydrate
Inhibitors (LDHI) & Anti-Agglomerant (AA) - Poly(N-
Vinylpyrrolidone/N-Vinylcaprolactam) copolymer and
Poly(N-Vinylpyrrolidone).
HYDRATE INHIBITORS:

HYDRATE INHIBITORS:

THERMODYNAMIC HYDRATE INHIBITORS:

KINETIC HYDRATE INHIBITORS:

Development of Experimental Setup:
Thermodynamic and Kinetic

Experimental Procedure:
• Vacuum is created in the reactor
• High pressure reactor rinsed
• An aqueous solution of 600/160 mL
water, with several wt % of
thermodynamic promoters say TBAB
will be added.
• Reactor pressurized (1-2 bar) with
natural gas and purged.
• Reactor was pressurized with natural
gas upto a desired pressure (say from
about 50 bar ≈ 750 psia), cooled upto
263 K.
• Heated slowly at (0.2-0.1 K/h) to get
equilibrium temperature and pressure.
Equilibrium Pressure: 5.63 MPa
Equilibrium Temperature: 280.85
K
(
)
33
Thermodynamics

Experimental Procedure:
Equilibrium Pressure: 5.63 MPa
Equilibrium Temperature: 280.85
K
(
)
34
270
280
290
300
310
320
0
2
4
6
8
10
0 5 10 15 20 25 30
T
(K)
P
(MPa)
Time (h)
Pressure Temperature
Hydrate formation period
Induction time = 0.85 h
Injection of gas
Kinetics
 The reactor allowed to stabilize
at desired temperature and
methane gas filled upto a
desired pressure say 7.5 MPa.
 The magnetic stirrer is turned
on again to a speed of 400 rpm.
 Data recorded every 30 s
intervals.
 Hydrate crystallization was then
allowed to run for a 12/24 h.
 The hydrate dissociated by
increasing the reactor
temperature upto room
temperature (299 K).

Phase Stability of Methane Hydrate in Polyethylene
Glycol (PEG) aqueous systems
+, 0.2 mf MEG (Mohammadi and Richon, 2010); ◊, Pure methane hydrate (this work);
∆, 0.2 mf PEG-200 (this work);
(a) ○, 0.2 mf PEG-400 (this work); □, 0.2 mf PEG-600 (this work);
(b) ■, 0.4 mf PEG-200 (this work).
4
5
6
7
8
273 275 277 279 281 283
P
(MPa)
T (K)
2.2 K
1.5 K
1.1 K
(a)
4
5
6
7
8
271 273 275 277 279 281 283
P
(MPa)
T (K)
2.2 K
7.3 K
(b)
Applicable for drilling fluid

Formation and Dissociation Kinetics of Methane Hydrate
in PEG aqueous systems
0.025
0.035
0.045
0.055
0.065
0.075
0.085
0.095
0 4 8 12
N
t
(mole
of
gas/mole
of
water)
Time (h)
7.5 MPa
Purewater 0.2 mfPEG-200 0.2 mfPEG-600
0.4 mfPEG-200 0.4 mfPEG-600
Rate of Formation
Hydrate Formation

Formation and Dissociation Kinetics of Methane Hydrate
in PEG aqueous systems
Hydrate Dissociation
0
0.01
0.02
0.03
0.04
0.05
0.06
0.07
0 0.5 1 1.5 2
N
'
(mole
of
gas/mole
of
water)
Time (h)
7.5 MPa
0.2 mf PEG-600
0.2 mf PEG-200
0
0.02
0.04
0.06
0.08
0.1
0 0.5 1 1.5 2
dN
'
/dt
(rate
of
hydrate
dissociation) Time (h)
7.5 MPa
PEG-200; 0.2 PEG-600; 0.2

Inhibitors for recovery of gas from
hydrate reservoir
• Natural gas hydrate exists in geological formations and constitutes
a potentially large natural gas resource for the future.
• To make recovery of natural gas from hydrates commercially
viable, hydrates must be dissociated in-situ. At the present stage,
depressurization method is expected to be a main dissociation
procedure because of its high energy profit ratio and so on.
• Whereas, there is a worry that some interruptions for gas
production i.e. plugging by hydrate formation will occur. Also there
is a demand to enhance the recovery ratio of natural gas.

Gas Recovery Setup

Gas Recovery: Polymer Flooding

Methane Recovery from the Artificial Hydrate Reservoir
through Injection of Polyethylene Glycol (PEG):

Crude Oil Recovery:

Surfactant Flooding

Surfactant Flooding: Recovery

Recovery %

Winsor phase behavior

Natural Gas Hydrate Potential
• Natural Gas Hydrates
• Source of Energy (India: 1.9 × 1015 m3 of gas1)
• Flow Assurance
• Transportation and Storage of Natural Gas
• Gas separation
• CO2 sequestration
• Desalination
Hydrate Potential of Indian Basins
• Andaman, K-G Basin, Mahanadi Basin
World Potential
Flow
Assurance
Energy
Source
1Collett et al., DGH, India. 2008.
*Petrobras
Gas
Hydrates

Promoter – Thermodynamic and Kinetic
• Clathrate/semiclathrate hydrates belong
to the family of the gas hydrates only, but
have a different lattice structure as
compared to the natural gas hydrates.
• This structural difference arises
because they are formed when the gas
hydrate system contains some
thermodynamic promoter like tetra-n-
butyl-ammonium bromide (TBAB),
tetra-n-butyl- ammonium chloride
(TBAC), tetra-n-butyl- ammonium fluoride
(TBAF), tetrahydrofuran (THF).
Structure of Semiclathrate Hydrates
Lee et al. (2011)
 Storage and Transportation

Structure of clathrate Hydrates - SII
Mech (2018)

(1) Phase Stability of Methane Hydrate in THF and TBAB
aqueous systems
◊, pure CH4 hydrate (Gayet et al., 2005); ×, 0.05 mf TBAB (Li et al., 2007);
(a) ■, 0.016 mf THF (Mohammadi and Richon, 2009); +, 0.1741 mf THF (Deugd et al., 2001);
ο, 0.3672 mf THF (Deugd et al., 2001); ∆, 0.1 mf TBAB (Sun and Sun, 2010); ▬, 0.2 mf TBAB
(Arjmandi et al., 2007); ■, 0.04 mf THF (this work); ♦, 0.016 mf THF (this work); ●, 0.01 mf THF
(this work); ▲, 0.005 mf THF (this work); *, 0.1 mf TBAB (this work)
(b) ∆, 0.1 mf TBAB (Arjmandi et al., 2007); +, 0.1 mf TBAC (Pirzaman et al., 2013);
●, 0.05 mf TBAC (Sun and Liu, 2012).
0
2
4
6
8
270 280 290 300
P
(MPa)
T (K)
(a)
0
2
4
6
8
274 279 284 289 294
P
(MPa)
T (K)
(b)

(2) Phase Stability of Methane Hydrate in THF and Salt
aqueous systems
◊, pure CH4 hydrate (Gayet et al., 2005);
(a) ▲, 0.005 mf THF (this work); +, 0.005 mf THF + 0.03 mf NaCl (this work); *, 0.005 mf
THF + 0.05 mf NaCl (this work); ×, 0.005 mf THF + 0.1 mf NaCl (this work);
(b) ●, 0.01 mf THF (this work); ■, 0.01 mf THF + 0.03 mf NaCl (this work); ▬, 0.01 mf THF +
0.1 mf NaCl (this work).
0
2
4
6
8
270 275 280 285 290
P
(MPa)
T (K)
(a)
0
2
4
6
8
270 275 280 285 290 295
P
(MPa)
T (K)
(b)

(3) Phase Stability of Methane Hydrate in THF and Inhibitor
aqueous systems
◊, pure CH4 hydrate (Gayet et al., 2005); ∆, 0.005 mf THF (this work);
×, 0.005 mf THF + 0.1 mf NaCl (this work); ●, 0.005 mf THF + 0.1 mf MeOH (this work);
+, 0.005 mf THF + 0.1 mf EG (this work).
2
4
6
8
274 280 286 292
P
(MPa)
T (K)

(4) Phase Stability of Methane Hydrate in Mixed Promoter
(THF+TBAB) systems and the Effect of Inhibitors
+, pure CH4 hydrate (Gayet et al., 2005); ■, 0.01 mf THF + 0.1 mf TBAB (this work);
(a) ▬, 0.1 mf TBAB (Sun and Sun, 2010); ×, 0.005 mf THF (this work); *, 0.01 mf THF (this
work); ▲, 0.005 mf THF + 0.1 mf TBAB (this work);
(b)▲, 0.01 mf THF + 0.1 mf TBAB + 0.1 mf NaCl (this work); ×, 0.01 mf THF + 0.1 mf TBAB
+ 0.1 mf MeOH (this work); ●, 0.01 mf THF + 0.1 mf TBAB + 0.1 mf EG (this work).
1
3
5
7
272 278 284 290
P
(MPa)
T (K)
(a)
1
3
5
7
272 278 284 290
P
(MPa)
T (K)
(b)

(5) Kinetics of Methane Hydrate Formation in Thermodynamic
promoter (THF and TBAB) systems with and without
Kinetic promoter (SDS)
0
0.005
0.01
0.015
0.02
0.025
0.03
0.035
0.04
0.045
0 5 10 15 20 25
N
t
(mole
of
gas/mole
of
water)
Time (h)
7.5 MPa
Pure water 600 ppm SDS 0.05 mf TBAB
0.1 mf TBAB 0.2 mf TBAB
Gas consumption

Rate of formation at 7.5 MPa
0
0.005
0.01
0.015
0.02
0.025
0 5 10 15 20 25
dN
t
/dt
(rate
of
hydrate
formation)
Time (h)
Pure water SDS; 600 TBAB; 0.05
TBAB; 0.1 TBAB; 0.2

Cumulative Gas Consumption using Thermodynamic
0
0.01
0.02
0.03
0.04
0.05
Pure
water
600
ppm
SDS
0.05 mf
TBAB
(0.05
mf
TBAB
+ 600
ppm
SDS)
0.01 mf
THF
(0.005
mf
THF+
600
ppm
SDS)
(0.01
mf THF
+ 0.10
mf
TBAB)
N
t
:
Cumulative
(mole
of
gas/mole
of
water)
7.5 MPa

(5) Kinetics of Methane Hydrate Formation in Thermodynamic
0
0.002
0.004
0.006
0.008
0.01
0.05 mf
TBAB
0.1 mf
TBAB
0.01 mf
THF
(0.01 mf
THF + 0.1
mf TBAB)
N
t
:
Cumulative
(mole
of
as/moleof
water)
3.0 MPa

Summary
THF showed higher promotion effect as compared to TBAB on the phase
stability of methane hydrate.
At lower pressure, promoters has shown higher moles of gas consumption per
mole of water.
TBAB is seen to reduce the induction time of the hydrate formation over pure
water, SDS and THF.
In general, for gas consumption in hydrate, TBAB is more effective than THF
but in the presence of SDS, THF showed much improvement over pure water
and TBAB.
Low molecular weight PEG-200 shows more inhibition than PEG-400 and
PEG-600 on both the phase stability and kinetics conditions.

Shale

Production technique
THF

Other techniques
Exploitation Shale Gas Reservoirs by High-Temperature Mixture Gas
• High-temperature mixture gas refers to the mixture of N2 and CO2 in a certain
proportion and blending with steam of 300oC.
• The proportion of gas existing in shale gas reservoirs in an adsorption state is
about 20–85%.
• In the early development period, free gas flows fast and results in a prolific
period (Lewis and Hughes, 2008; Cipolla, 2009; Anderson, 2010).

Non-damaging drilling fluids (NDDF)

Non-damaging drilling fluids (NDDF)
Composition
of NDDF
Type of
formation
drilled
Purpose Success rate for the
purpose / If failure,
cause of that
Reference
Xanthan gum
Polymer
Shale Weighing agent
and bridging
element
(reduces
formation
damage)
Effectively used where
formation protection,
solids suspension and
improved borehole
cleaning are the
primary concerns. But,
the drawback of XCP
is that it is highly
degradable.
[14]
Oil based
drill-in fluid
Sandstone
beds with
shale
interbeddings
To prevent
asphaltene
deposition,
wettability
alteration and
emulsions
invasion
Minimized the
formation damage is
the key performance
by this NDDF.
[16]
Potassium Sandstone To drill Provided enhanced [17]

NDDF – Recent work

Mud-1 (NDDF): 1000 mL DW + 0.25% CMC + 0.25% CaCO3 +
0.35% KCl + 0.35% NaOH + 0.3% PHPA + 1% Rice Husk;
Mud-2 (bentonite-based): 1000 mL DW + 1% Bentonite + 0.25%
CMC + 0.25% CaCO3 + 0.35% KCl + 0.35% NaOH + 0.3% PHPA +
1% Rice Husk.

Properties NDDF Bentonite Based
Density (ppg) 8.52 8.60
Specific Gravity 1.02 1.03
pH 12.57 12.41
Effective Viscosity (cP) 51.0620 54.6930
Apparent Viscosity (cP) 47.9948 51.6030
Plastic Viscosity (cP) 70.4501 81.0176
Yield Point (lb/100ft2) 46.9667 52.2504
Gel Strength 10sec
(lb/100ft2)
10.5870 10.9589
Gel Strength 10min
(lb/100ft2)
11.0567 11.6438

Properties Day 0 Day 2 Day 4
Mud-1 Mud-2 Mud-1 Mud-2 Mud-1 Mud-2
Density (ppg) 8.52 8.6 8.52 8.6 8.52 8.6
Specific
Gravity
1.02 1.03 1.02 1.03 1.02 1.03
pH 12.57 12.41 12.31 12.24 12.12 12.05
Effective
Viscosity (cP)
51.0620 54.6930 55.1959 61.2781 56.1635 64.2617
Apparent
Viscosity (cP)
47.9948 51.6030 52.1286 58.1881 53.0693 61.1717
Plastic
Viscosity (cP)
70.4501 81.0176 71.6242 83.3659 74.7553 88.0626
Yield Point
(lb/100ft2)
46.9667 52.2504 45.4011 48.5322 42.8571 45.7925
Gel Strength 10.5870 10.9589 10.5675 10.7632 10.6262 10.9393

Shale stability
setup

Hou
r
Shale Volume (ml)
Mud-1 (NDDF) Mud-2
Fluid Volume Level (mL) Fluid Volume Level (mL)
0 7 14 14
2 7 14 14
4 7 13.9 13.8
6 7 13.9 13.7
8 7 13.7 13.6
10 7 13.7
13.6
12 7 13.6
13.5
14 7 13.6
13.4
16 7 13.5
13.4
18 7 13.5
13.2
20 7 13.5
13.2
22 7 13.4
13
24 7 13.4
13

Mud-1 Mud-2
Initial Dry Weight (g) 7.580 7.580
Wet Weight (g) 10.724 11.904
Dry Weight after Immersion
(g)
7.301 7.063

Summary
 A rice husk based non-damaging drilling fluid (NDDF) was formulated
and compared with the conventional mud which was tested over time
to observe how they degrade.
 The non-damaging drilling fluid (NDDF) is formulated free from
bentonite and causes lower formation damage than the conventional
drilling fluid.
 The rice husk based NDDF shows a huge potential to be used in pay
zone sections to a greater advantage and reduces chances of
complications during production due to lower formation damage.

Dr. deepjyoti mech hydrocarbon assurance - a research implications

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