Page 135 - Handbook Of Multiphase Flow Assurance

Hydrate of natural gas 131

SG is gas specific gravity relative to air.
The Makogon correlation had been found as best simple correlation in Gjellesvik (2011),
corresponding surprisingly well with results from software simulator in many situations.
Gas gravity is calculated from gas composition as follows:

%
 molN ×28 + molCO × 44 
%
2
2
 + molCH ×16 + mol CH ×30 
%
%
 4 2 6 

Gasgravity = + mol%CH × 44 + moliCH × 58  / 28 96 100
%
/
.
%
 3 8 4 10 
%
 + molC H × 58 + mol %iC H × 72 
4
12
5
10
 + molC H × 72 + molC H × 86 
%
%
 5 1 12 6 14 
Case studies and process safety
Multiple cases are known where blockages formed, and more emerge on an almost daily
basis. Liquid loading and hydrate plugging are primary sources of unplanned losses in on-
shore wells.
Historically, majority of blockages have been dissociated but there are several examples
in the North Sea and several in the Gulf of Mexico where hydrate blockage remained in the
well or the flowline as it was uneconomic to attempt to or to carry on the hydrate removal
operation.
There were 16 reported cases of hydrate blockages in flowlines reported to US MMS be-
tween 1991 and 1998. In comparison there were 39 paraffin blockages.
Operators in general found it difficult to determine the position of these blockages.
All 16 hydrate blockages were removed successfully. Of these 12 were complete blockages,
5 were offshore GOM.
There was only one reported instance of hydrate in a multiphase flowline (GOM). This was
a complete hydrate blockage following a shut-in. It was removed with coiled tubing/jetting
glycol.
Of the other 15, 5 were in condensate lines, one was in a gas lift injection line and the others
were in gas lines.
The Staffa 8″ flowline which suffered 2 complete blockages in the North Sea, was believed
to be a combination of wax and hydrate. The water cut in this flow line was surprisingly low
(<1%). Staffa field was eventually abandoned following two pipeline blockages with a com-
bined wax hydrate plug. The nature of the 8″ multiphase flowline was such that the fluids
cooled to seabed temperatures within the first 2 miles from the tree having a further 4 miles
before reaching the Ninian platform. The fluids arrived well below the wax appearance tem-
perature of the oil. Round trip scraping was not possible. The subsea line was also undulating
and at one point crossed another flowline, both exposing it to additional cooling and intro-
ducing restrictions into the flow path. Following the first blockage in June 1993 which could
not be removed, 2 km of the line was cut out and replaced. After a further occurrence the field
was abandoned in November 1994 (Gluyas and Underhill, 2003).
A large number of hydrate blockages case studies is described in the SPE Hydrate
Engineering monograph (Sloan, 2000).
Instead, we will focus on the hydrate incidents associated with process safety because
these involve multiple steps leading to the event. Case studies below focus on process safety