Summary
A dry tree well in the Gulf of Mexico (GOM) has been producing oil with more
than 50% water cut. This raises a concern, because the existing
Anti-Agglomerants Low Dosage Hydrate Inhibitor (AA LDHI) used during extended
shutdowns and cold restarts, is effective only up to 50% water cut. Because
more time and resources would be required to bring a new AA LDHI, more detailed
analysis were performed to evaluate the possibility of managing hydrate risks
through operating procedures. It was found that during extended shutdown, the
wellbore fluid can be pushed down below the mudline using the dry gas from the
glycol contact tower followed by diesel or methanol. Thus, it eliminates the
hydrate risk during extended shutdowns. Confirmed by the actual data, the cold
restart simulations found the warm-up time in the wellbore to be less than an
hour. The actual data also show the cumulative water cut one hour after restart
was found to be below 50%. The cold restart procedures have been updated with
the strategy to outrun the water and come out of the hydrate condition as
quickly as possible. Since then, the well has been brought on production using
the existing LDHI without any hydrate problems, even with a water cut
approaching 90%.
Introduction
Under favorable conditions of high pressure and low temperature,
hydrocarbons and water can combine to form crystalline solids, which resemble
wet snow or ice, that are also called hydrates. The crystal structure is
composed of cages of hydrogen bonded water molecules which surround “guest”
hydrocarbon molecules such as methane, ethane, and propane. The thermodynamic
stability of these structures increases as pressure increases and temperature
decreases (Sloan 1998). These ice-like structures could agglomerate to block
tubing, flowlines, and/or facilities.
To determine the conditions of temperature and pressure under which hydrates
can form, the best approach is to conduct experimental measurements on the
appropriate hydrocarbon/water mixture. However, this is not always practical.
Thus, the method for predicting hydrate behavior using thermodynamic models is
more common. A thermodynamic model is used to calculate the hydrate equilibrium
curve, also known as the hydrate disassociation curve. The hydrate
disassociation curves for Well A-4 gas is presented in Fig. 1. The curves are
generated based on gas composition given in Table 1. The reason to use the
hydrate curve based on gas composition instead of combined reservoir fluid
composition is to give more conservatism, although it was found that the
difference between the two curves happens to be very small. The combination of
pressure-tempreature (P-T) condition on the right side of the curve is safe,
while the left side is subjected to hydrate formation. The curve shifts by
approximately 15°F because of the 13.3% salinity of the produced water, which
will have a major impact in flow assurance analysis. This shows the importance
of having the accurate water chemistry analysis in generating the curves. Based
on the saline hydrate curve and maximum shut-in wellhead pressure of 3,000
psia, the temperature in the entire tubing must stay above 60°F to be free from
hydrate risks.
To keep the operating condition of a well or a hydrocarbon production system
free from hydrate risks, several techniques can be applied. Mechanically, the
flow conduit along the production path can be insulated to keep the heat
carried by the reservoir fluid contained within the flow conduit. However,
depending on the overall heat-transfer coefficient of the flow conduit and the
ambient temperature, the operating condition could soon enter into the hydrate
risks condition during shutdown or restart. Thermodynamically, hydrate
inhibitor (such as methanol or glycol) can be injected into the flow stream to
shift the hydrate equilibrium curve to the left; thus, when the flow conduit
cools down to the ambient temperature during shutdown or restart, it stays on
the right side of the hydrate curve. However, shifting the hydrate curve to the
left until the operating condition during any production scenario saved from
hydrate risks might require an excessive amount of inhibitor that would then
require larger injection and storage systems for that inihibitor. If the
injection system, such as a pump or umbilical, is already in place and has
limited capacity, well-production rates might have to be choked back to keep
the effectiveness of the inhibitor. One of the possible solutions for this
problem is by injecting a low-dosage hydrate inhibitor (LDHI). By definition,
LDHI should be able to manage hydrate risks with a lower amount as compared to
the conventional inhibitor such as methanol or glycol.
© 2008. Society of Petroleum Engineers
View full textPDF
(
1,522 KB
)
History
- Original manuscript received:
30 May 2006
- Meeting paper published:
11 September 2006
- Revised manuscript received:
3 May 2007
- Manuscript approved:
1 June 2007
- Version of record:
20 February 2008
View Cart
