Transient modeling was used to address hydrate formation issues in pipelines connecting wells to processing facilities in Kuwait's North Kuwait Jurassic fields. The modeling aimed to optimize methanol injection to prevent hydrate plugging while accounting for different well fluid compositions and transient flow conditions. Wells were categorized based on their water salinity and modeled individually. The transient modeling provided hydrate and surge advisors to monitor temperature margins and predict slug flow issues better than steady-state models. The solution was expanded to additional wells to minimize production losses from hydrates and pipeline corrosion.

1. Transient Simulation
for Hydrate Mitigation Aims
for Optimal Production
In kuwait field

2. In the deep high-pressure/high-temperature North Kuwait
Jurassic (NKJ) fields, the pipelines connecting the wells to the
processing facility are neither buried nor insulated.
During the winter, the well fluid cools to below hydrate-
formation temperature in the flowline, causing hydrate
crystallization and even plugging.
This paper presents the traditional methods of hydrate
mitigation used in the NKJ fields and the way in which a
transient model was initially built and continuously improved.

3. Challenges

4. Hydrate Formation
Hydrates usually forms at night and early morning in
winter.
Robust solution is needed for minimizing production
downtime.
No proper flow-assurance study or modeling was
conducted.
predictive transient tool is needed to know.

5. Slug Flow
Low-condensate/gas--ratio and high-water/gas-ratio
wells have a tendency to create slug flow in the
pipeline.
when the pipeline is heated, the -fluids expand and
gas holdup increases in the line.
when the pipeline cools, liquid hydrocarbon
accumulates in the line, increasing the liquid holdup.
At night, when the pipeline cools, liquid hydrocarbon
accumulates in the line, increasing the liquid holdup

6. Pipeline Corrosion
An acid-gas environment with water
production makes the system very corrosive.
The current practice is to inject 10 L/h of
corrosion inhibitor, which is expected to coat
the whole pipeline and protect it from
corrosion.

7. Hydrate-Inhibition Operational Envelope
Available pumps have a maximum capacity of 20 L/h
per pump, which is not enough.
MeOH injection is performed manually and pumping
is continued throughout the day during the winter.
The injection pumps and the chemical tanks are not
connected to the supervisory control and data
acquisition system.

8. Current Well Modeling and
Liquide loading
current well and pipeline models are steady state
Choke reduction will result in liquid loading in some
of the low-reservoir-pressure wells.
Proper design of hydrate inhibition will eliminate the
need for the choke reduction and, thus, avoid liquid
loading.

9. Solution

10. To address some of the challenges, a transient
modeling solution began in 2014 for the producing
NKJ wells.
In the first phase, a pilot of an offline transient
solution was deployed, with hydrate and surge
advisers as the key deliverable.
Hydrate Adviser :- From the initial -hydrate-
prediction results, additional water-sample analysis
was conducted to account for different salts in the
formation water.
On the basis of the transient-modeling and sampling
results, NKJ wells can be divided into three
categories.

11. Category A Wells
These wells have no brine production.
water content in these wells is so low (<5%) that it
falls out of the water-measurement range of
available multiphase flowmeters.
The modeling of Category A wells was performed by
saturating the fluid composition to the reservoir
pressure and temperature to account for the
condensed water from the gas phase.

14. Category B Wells
Wells That Produce Saline Formation Water.
more detailed overview of the concentrations of
different types of salt is required.
Sensitivity analysis was conducted for different salt
types and their effect on the hydrate curve.
The hydrate curves with detailed salt descriptions
have a close match with actual field conditions.

15. Category C Wells
Wells That Produce High-Salinity Formation Water.
formation water with high salt concentrations
(>280,000 ppm)
Overdosing with MeOH is not recommended for
high-salinity-water wells.
Surge Adviser :-accounting for changes in the flow
behavior in the pipeline resulting from various
factors

16. Corrosion and Gas Velocity :- the fluid velocity in gas
pipelines should be less than 60 to 80 ft/sec to
minimize noise and to allow for corrosion inhibition.
A lower velocity limit of 50 ft/sec should be used in
the presence of known corrosive agents such as
carbon dioxide.
The minimum gas velocity should be between 10 and
15 ft/sec, which minimizes liquid fallout.
If the velocity is high, the fluid will disturb the
corrosion-inhibitor coating and generate corrosion
sites

17. Conclusion

18. Hydrate Formation
Transient modeling can mimic field conditions if
accurate water properties are used to generate the
hydrate curve.
The effect of the salts present in the formation water
and the MeOH injection is well-understood, and
MeOH injection can be optimized by the use of
transient modeling.
The solution should be scaled up to include all the
new wells, and the system should be used to
minimize the production losses resulting from
hydrates.

19. Slug flow and pipeline corrosion
Sensitivity analysis conducted for ambient
temperature and the choke changes clearly
demonstrates that the flow from wells will always
have slug behavior at the inlet of the facility.
Modeling of the gas velocity in the pipeline is
important for predicting pipeline corrosion

20. Transient Modeling
steady-state models are capable of simulating flow-
assurance scenarios.
Dynamic hydrate and surge advisers can be used with the
transient modeling.
key function of the hydrate adviser is to monitor the
temperature margins of potential hydrate-formation
regions throughout the production network
the key function of the surge adviser is to calculate the
formation, location, and size of terrain slugs or liquid
surges in the production system.