upheaval buckling of gas injection pipelines onshore abu dhabi
TRANSCRIPT
Upheaval Buckling of Gas Injection Pipelines Onshore Abu Dhabi - A Case Study
Upheaval Buckling of Gas Injection Pipelines Onshore Abu Dhabi - A Case Study
Hisham Saadawi, SPE, Abu Dhabi Company for Onshore Oil Operations (ADCO)
Abstract
Upheaval buckling is a potentially serious problem for buried pipelines operating at high temperatures and pressures.
In recent years, this problem has been receiving wide attention in the oil industry. Most of the published literature deals with offshore applications in the North Sea. The problem of upheaval buckling, however, is not limited to offshore pipelines operating in a cold climate, but can also affect onshore pipelines in a desert environment.
Shortly after commissioning a major gas project onshore Abu Dhabi, some sections of the injection gas pipelines protruded through the trench and the soil cover. Extensive
investigations were carried out to analyze the problem, identify the causes and remedy the situation. This paper describes a case study of the problem of upheaval buckling of high pressure gas pipelines in a desert environment.
Introduction
A major project has been recently implemented to develop a large gas condensate field onshore Abu Dhabi. The field is located in the desert, 200 km south of Abu Dhabi City. The project aims at exploring the huge condensate reserves in the field. The project facilities is comprised of :
• a gas gathering system made of 29 producing wells, 29 flowlines, 4 gas remote stations and 4 gas gathering trunklines.
• a central gas processing plant for condensate recovery and export.
• An injection system to re-inject the lean gas, together with the make-up gas needed to compensate for shrinkage in gas volume due to the recovery of condensate, back into the reservoir. The injection system is made up of 3injection trunklines, 13 injection flowlines and 13injection wells.
Figure 1 is a block diagram of the complete system. The central gas processing plant and export system were designed and constructed under one project, while both the gas gathering and injection system were handled under a second project. The contract for the gathering and injection systems was warded to an international Contractor in September 1997.
The contract was an EPC one; i.e. Engineering, Procurement and Construction.Engineering was done in the U.K. home office of the subcontractor (Engineer) during 1997/1998. Construction of the project began in the summer of 1998 and continued till late 1999, when pre-commissioning activities took place. Before discussing the problems experienced during the commissioning of the facilities, a description of the pipeline system is given in the next section.
The Pipeline System
The pipelines of both the gas gathering and injection systems were designed and constructed in accordance with
ANSI B31.8 piping code [1]. The pipelines are constructed in a remote desert area. Therefore, a code Location Class 1,Division 1 was chosen which gives 0.72 as the basic design factor. Since the problems experienced were with the injection pipelines, the discussion here will focus on the injection system.
The key design and operating parameters of the injection trunklines are:
design pressure = 423 bars
hydrostatic test pressure = 1.25 x design pressure
wellhead injection pressure = 385 bars
maximum temperature of injection gas = 83 oC
design installation temperature = 21oC
pipe material = API 5L X65
nominal pipe diameter = 12 inch
wall thickness = 22.8 mm
coating = 3-layer polypropylene
coating thickness = 3 mm
The pipelines are laid in a desert area known for its numerous large and small sand dunes. The large-scale dunes are in general relatively stable. On the other hand, smaller scale dunes, comprising of loose sand, are in a mobile state, and subject to movement by wind action across the more stable underlying topography. The wind blown desert sand deposits are characterized by their uniform grading, and the uniform roundness of the sand grains.
In order to minimize the footprint in the field, the pipelines are grouped in main pipeline corridors. The project specifications called for the pipelines to be buried 1m below grade and a berm with a minimum height of 1m to be constructed. The berm is stabilized by 0.3 m of gatch, which is essentially Calcium Sulfate and can be found in the flat areas between the sand dunes. A typical trench detail is shown in figure 2. The fiber optics cable, which transmits the SCADA signals, is also buried in the same trench.
The layout of the injection system is shown in figure 3.
Injection trunkline # 1 supplies gas to the flowlines and injection wells in the southern part of the field. Injection
trunklines # 2 and # 3 feed gas to the flowlines and injection
wells in the north.
The Problem
Commissioning of the project facilities began in April 2000 by
commissioning the gas gathering and injection systems in the
southern part of the field. After introducing the well fluids
into the plant, injection system #1 was first commissioned
during the first week of May 2000. This was followed by
injection trunkline # 3, which was pressurized, on 18/5/2000
and injection in the wells associated with this trunkline
commenced three days later. At the same time, injection
trunkline #2 was commissioned. This line was depressurized
2 weeks later to repair a leaking flange before it was recommissioned
again.
By early June 2000, the three injection systems were
operational and injecting gas at a wellhead injection pressure
of 385 bars. On a routine survey of injection trunkline # 3
during that month, it was found that a pipeline section with a
span of 25 m protruded through the soil above the ground as
shown in figure 4. A sketch of the profile of this buckled
section is given in figure 5. The location where the buckling
took place was approximately 0.6 km downstream the gas
plant.
Further survey of injection trunkline # 2 revealed two more
locations where the sections of this pipeline came above the
ground. The first location was 3.4 km downstream the gas
plant. The pipe was exposed out of the ground over a
distance of 23 m and moved diagonally out of the flank of the
berm at an angle of approximately 55 degrees to the
horizontal. The second location was 6.8 km downstream the
plant. At this location, the buckle was less severe, and out of
the ground over a distance of about 12 m.
A survey of injection trunkline # 3 in the southern part of the
field revealed no such problems. Nor was there any problem
with the gas gathering trunklines or flowlines.
Analysis of the Problem
As noted before, all the pipelines of the gathering and
injection network are buried. The total length of the pipelines
is several hundred kilometers. The three-injection systems
are subject to the same operating conditions. As shown from
figure 6, the three lines are essentially “floating” together and
the injection gas is flowing through them at the same
temperature and pressure. Yet, the buckling problem took
place in three locations only of injection trunklines # 2 and 3.
This raised a number of questions;
• Is the pipeline deformation elastic or plastic?
• Is it safe to continue operation and gas injection?
• Why did the other pipelines not buckle?
• What caused the problem in the first place?
• What is the corrective action?
• How can we ensure that the problem is not repeated in the
future?
It was important to understand the buckling phenomena in
order to analyze the problem and address the above questions.
Upheaval buckling is a phenomena experienced in buried
pipelines operating at elevated temperatures and high
pressures. It is a known phenomenon in both land and
submarine pipelines. Many of the reported cases in the
literature deal with North Sea applications, e.g. references [2]
and [3].
A buried pipeline, under the influence of high temperature and
internal pressure, will be subject to axial compressive forces or
compressive stresses. If the pipeline profile contains
overbend or hills, these axial forces will try and “push” the
pipe at these locations upward (figure 7). The upward
movement will be resisted by the weight of the pipe and its
contents as well as the weight of the soil cover above it.
Therefore the driving mechanism for upheaval buckling is the
compressive axial stresses generated in the pipe. The
equations for the driving force as well as the resisting force are
discussed in the appendix.
Investigations
The Company, the EPC Contractor[4] and the Engineer[5]
conducted extensive investigations to analyze the problem.
These investigations included review of the original design
calculations, review of the construction records, new soil
investigations, and a review of the operational history of the
injection system.
In order to establish if it is safe to continue the operation of
the line, the deformed shapes of the buckles were analyzed.
For injection trunkline # 3 (figure 5), the buckle profile was
idealized as a sinusoid of length 40.6m and height 2.94m.
The corresponding maximum curvature and bending strain
were calculated. The latter was found to be 2.7 times the
nominal yield strain that corresponds to the specified
minimum yield strength of the pipe. Therefore, the pipeline
has definitely bent into the plastic range. The critical bending
strain at which bending buckling starts, was calculated using
formulae based on Euler buckling theory as well as DnV rules.
It was concluded that there is still a substantial margin of
safety against both localized bending buckling and rupture
under internal pressure. Hence, it was decided to continue
gas injection till the investigations and preparation work for
repair were completed.
In the original design report by the Engineer, the upheaval
buckling calculations were done using the method proposed by
Palmer et al [6], which is discussed in the appendix. The
Engineer assumed an imperfection height of 0.3m and
calculated the height of effective cover for two different soil
cases; a loose soil case and a compact one. There was no
mention of a safety factor.
New soil investigations were carried out at the locations where
the upheaval buckling took place [7]. Trial pits were hand
excavated to a target depth of 2m. Bulk disturbed samples
were taken at 0.5m intervals. In-situ soil density
determination was made in each of the pits, in accordance with
the ASTM D1556 sand replacement method. Other
properties that were determined included the internal angle of
soil friction and the angle of friction between the pipe and the
soil. The latter was determined using polypropylene surface.
Variances were found between the in-situ values of these
properties and the values that were used in the original design
report. The design was based on initial soil investigations that
were done at the beginning of the engineering phase of the
project.
The operational history of the injection system was reviewed.
The three injection lines have a common header (figure 6).
They are subject to the same operating conditions; i.e. same
injection pressure and same temperature. Since this was the
early commissioning phase, the records of the operational
history were not complete. However, there was no evidence
to suggest that the operating pressure exceeded 400 bars or
that the operating temperature exceeded 80 oC. The pressure
relief valve at the compressor discharge was set at 423 bar,
which is the design pressure of the injection pipeline. The
injection gas flows from the compressor to the after-cooler
before it enters the injection system. The aftercooler is of the
fin-fan type air cooler. Even using a conservative assumption
of an approach temperature of 20 oC and an ambient
temperature of 55 oC, the gas temperature will be about 75 oC.
Although the high temperature trip at the compressor
discharge was set higher than 83 oC.
The possibility of a surge wave in the injection line, as a result
of sudden pressurization, was also investigated. Although
this will not cause axial compressive stresses as such, a sudden
rush of high density gas in the injection pipeline will generate
a radial force at an overbend which may cause the pipeline to
lift. Each of the three injection trunklines is isolated from the
plant injection header by an ESD valve as shown in figure 6.
There is a 2-inch by-pass globe valve around the ESD valve.
During start up, the injection compressors are run on recycle
till the pressure builds up in the plant injection header to some
370 bars. The injection trunklines are then pressurized one by
one. This is done by opening the 2-inch by-pass valve. This
procedure is strictly used by the Company operating staff and
it can take up to a full day to pressurize one injection system.
Causes of the Problem
There was a disagreement between the EPC Contractor and
the Engineer on the exact causes of the upheaval buckling.
The EPC Contractor view was that the cause of the problem
was related to the design whereas the Engineer believed that it
was more of a construction issue. It is the Company’s view
that the problem did not occur due to one single cause. It is
the accumulation of several factors related to both the design
and construction that contributed to the upheaval buckling
problem.
Design issues
• No safety factor was used in the original report for design against upheaval buckling. When using semi-empirical formulae, a factor of safety should be used to account for the various uncertainties.
• The original design report did not document explicitly what is the effective height required to prevent upheaval buckling. Furthermore, the report did not clearly state that the pipeline berm was part of the effective height necessary to prevent upheaval buckling. This fact was not reflected in the construction specifications, which were prepared during the engineering phase of the project.
• The design calculations were based on an imperfection
height of 0.3m and length of 56m, which correspond to
elastic deformation of the pipe. Again, this was not
reflected in either the construction specifications or the
construction procedures.
• As discussed in the appendix, the semi-empirical
formulae are based on the assumptions that the pipe is not
plastically deformed. Yet, the construction specifications
allowed the use of cold-bent overbends.
• The soil data used in the design, which were based on an
initial survey, were found to be different from the in-situ
soil properties.
Construction issues
• Inadequate berm construction.
• In one buckled location, the berm did not cover the
pipeline. It was offset by approximately 1.5 m from the
trench. When the pipelines was constructed, the EPC
Contractor did not construct the berm after backfilling the
trench. This was not done till some weeks later. In
areas of sand dunes, the trench locations and marker
stacks can be easily lost after a sand storm.
• Two out of the three locations where buckling occurred
were at or near a hill were cold-bent overbends were used.
Even though the construction procedures did not exclude
the use of overbends, their use was unnecessary. In sand
dune areas, carbon steels pipelines are elastic enough to
accommodate the changes in trench profiles without the
need for using cold-bent overbends.
• A Cathodic Protection station is installed at the second
location of injection trunkline # 2 where the pipe came
diagonally out of the berm flank. The pin-brazing of the
CP cables was done after the berm was constructed. It is
possible that when the CP crew excavated to pin-braze the
cables, they did not properly compact the backfill nor
reconstruct the berm correctly.
• It was observed that upheaval buckling took place in the
injection pipelines in the northern part of the field only.
Injection trunkline # 1 (in the South) was constructed
during October / November 1998. The buckled sections
of injection trunklines # 2 & # 3 (in the North) were
constructed during January 1999. The buckled section of
injection line # 3 was welded on 21/1/1999. The construction records did not give the ambient temperature at the time of welding and backfilling. A check was made with the meteorological office in Abu Dhabi Airport. He advised that the minimum temperature on that day was 13 oC. The design was based on a minimum temperature of 21 oC.
Corrective Action
The measures that were taken to remedy the situation included a new stress analysis of the system as well as repairing the pipelines.
Stress analysis
A new stress analysis of the complete injection pipeline system was carried out [4]. The analysis was done using the as-built alignment sheets of the pipelines. A margin of safety was added to the calculated cover height. Particular attention was given to locations were a cold-bent overbend was installed. In some locations, the effective cover height was calculated to be 50 % higher than the value calculated by the Engineer. Moreover, a detailed survey was made of the pipelines berm. In areas where the berms were defective, they were repaired and augmented.
Pipeline Repair
Since the buckled parts of the pipeline suffered from plastic deformation, it was decided to cut these sections and replace them. The preparatory work was done before decommissioning the pipelines. For each of the three locations where buckling occurred, the length of the pipe section to be replaced was calculated. This varied between 100 m and 140 m. There were enough surplus coated pipes of the same size. As the original construction workforce was de-mobilized, a local subcontractor who was already present in the area was used for doing the repair work.
Welders had to be pre-qualified. The welding procedures that were adopted in the original project were also used for the repair work. Fabrication of the new section was done outside the trench.
This included welding, nondestructive testing, hydrostatic testing, gauging and field joint coating. Injection systems # 2 and # 3 were then taken out of service; one at a time. Each line was de-commissioned by purging with Nitrogen. A total of five foam pigs were run through the line with Nitrogen to ensure that the line is gas free. Analysis done at the receiver end showed that the LEL (lower explosive limit) was less than 3 %. The H2S contents were zero ppm.
Manual excavation was carried out to expose the section that will be replaced. The line was cold cut. The new section was lowered in the trench and it was gold-welded to the pipeline. The above work was done during the summer of 2000 under the warranty of the EPC contract. In order to avoid interruption to the gas plant operation, the time of pipeline repair was chosen to coincide with the shut down for inspection and cleaning of the process
trains of the plant.
Conclusions
This paper presented a case history of upheaval buckling of gas injection pipelines onshore Abu Dhabi. The problem, analysis of the problem and the corrective measures were discussed. The accumulation of various factors during the design and construction of the pipelines contributed to the upheaval buckling of the lines.
As exploration for gas is increasingly moving into deeper reservoirs at higher pressures and temperatures than before, more attention should be given to the phenomena of upheaval buckling. Based on the experience described in this paper, the following recommendations are made. These recommendations are particularly relevant to the design and construction of pipelines operating in a desert environment.
• Semi-empirical formulas for upheaval buckling are useful tools for preliminary design. A conservative safety factor (e.g. 2) should be used to compensate for the various uncertainties in the design and construction.
• The limitations of semi-empirical formulas should be clearly understood by designers and reflected in the construction procedures. One such limitation is the assumption of smooth symmetric imperfection in the pipeline profile.
• If the pipeline berm is part of the effective cover against upheaval buckling, the designer should document this requirement clearly and reflect it in the construction procedures.
• The depth of the pipeline trench should take into consideration the effective height required against upheaval buckling. A deeper trench will increase the capital cost, but it will reduce the operating cost since less effort will be needed to maintain the berm.
• After completion of the pipeline construction, when the actual installed profile is known a finite element analysis of upheaval buckling analysis, using finite element computer package such as UPBUCK program [9], should be carried out. This analysis should be done using the as built alignment sheets. It should be conducted prior to start up to ensure that the effective pipeline cover is in place.
• The importance of using the in-situ soil data along the pipeline route in the design can not be overstated. The key soil data include; in-situ density, internal coefficient of friction and the coefficient of friction between the pipe and soil. For the latter, this should be measured with the actual type of coating used in the project.
• Construction of the berm should be done immediately after backfilling the trench. In areas of sand dunes, the trench locations and marker stacks can be easily lost after a sand storm. In a project involving a single pipeline project, the pipeline corridor is usually well maintained.
However, this is an important issue in projects such as the one described in this paper where there were 47 pipelines combined in single and multiple trenches and scattered over a large geographical area all over the field.
• Field cold-bent overbends should not be used. They can be a source of instability because they can induce upheaval buckling. In sand dune areas, carbon steel pipelines are elastic enough to accommodate the changes in trench profiles without the need for using cold-bent overbends.
• Particular attention should be given to backfilling and berm construction on top of the hills in sand dune areas. These are the vulnerable areas where upheaval buckling may occur.
• If construction is taking place during winter, a realistic minimum installation temperature should be used for the
design. In the desserts of Arabia, the minimum temperature in the early morning can be as low as 6 degrees C.
• The maximum operating temperature used for upheaval buckling design should take into considerations the value of the setting of the height temperature trip of the upstream compressor.
• When excavating to check CP attachments to the pipelines or repair fiber optics cables buried with the pipelines, care should be taken to ensure that the backfill and the berm are re-constructed properly