Ot June 2015

User Manual: Resource Library

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THOMAS ROESNER AND
DIANE LANGLEY, CAMERON, USA,
LOOKS AT WHAT SERVICE COMPANIES
ARE DOING TO INNOVATE AND DRIVE
EFFICIENCY AND COST SAVINGS IN
WELL CONSTRUCTION.

T

he industry has shared many excellent articles and case studies on ways
to enhance drilling and completion operations, to increase safety and
decrease the overall cost per barrel of oil equivalent (boe). As the effects of
low oil prices are experienced across the industry, one thing remains self‑evident
– oil companies generate revenue through oil and gas production. Therefore,
service alignment and technology enables a sustainable future for both operators
and service companies in today’s oil price environment.
As the adage goes: necessity is the mother of all invention; service companies
are taking on the challenge to address the ‘other 20%.’ What is the ‘other 20%?’
When one considers all of the players and procedures in the well construction

Figure 1. Frack tree technological evolution and innovation.

Figure 2. Frack tree failure mechanisms.
process, the industry has an excellent understanding of what needs to
be done; this is the 80%. The ‘other 20%’ is discovering ways to further
support the various aspects of well construction in detail in order to
innovate new ways to drive efficiencies and cost savings.
Therefore, the 80/20 rule is applied to the unconventional shale
plays, innovation with respect to holistic reliability in the space of the
‘other 20%’ is critical in today’s low oil price environment.

Innovation of the wellhead

One key component on every well drilled is the wellhead. It is a vital
pressure‑containing component at surface that can often make
operational processes more efficient and flexible. By nature, horizontal
wellbores are deviated, causing fluids and cement to migrate to the low
side of the hole, resulting in a less than optimal distribution downhole.

| Oilfield Technology Reprinted from June 2015

Internal components, such as a rotating mandrel hanger, will allow the
casing to be rotated through the heel of the lateral as well as ensure the
production casing runs the full length of the lateral and achieves a proper
cement job. Once the casing mandrel is landed in the wellhead, slotted
mandrel shoulders permit cement circulation, removing the necessity to
wait on cement as with casing slips.
Other options that can drive operational efficiency are back pressure
valves (BPVs) and wellhead packoff systems. These can be installed
into the rotating mandrel to provide a barrier for both the bore and the
annulus to secure the well at surface. This is especially important to help
increase operational efficiency, as walking drilling rigs often are planned
to move off the current well and onto the next as soon as possible.
Another important wellhead component in the completion and
production process is the tubing hanger. Frequently after a well has
been hydraulically fractured and the well flowed back and cleaned up,
production will naturally flow for a period of approximately six months.
After this time period, production often requires installing artificial lift
and setting a packer downhole. A tension hanger is one easy way of
achieving this, allowing completions to set the packer and keep the
tubing string in tension. This will help prevent rod wear and provide a
standardised solution to the completions team, who is also likely focused
on boosting operational efficiency.
An example of advances made in the area of wellhead reliability and
functionality for unconventionals is Cameron’s advanced multi‑bowl
nested diverter snap ring (MN‑DS) wellhead system. In this wellhead,
the production casing/tubing hanger is nested within the lower casing
pack‑off. It features a nested internally locked upper hanger that
reduces the overall height of the system for easier use with skidded rigs.
This hanger can be either a production casing hanger or a tubing hanger,
providing the option to complete as a one‑stage system if intermediate
casing is not required.

Innovation of the frack tree

As operators have adopted the factory approach to drive efficiencies in
batch drilling and completions, frack tree designs have evolved, moving
away from tall vertical conventional frack trees to more compact designs.
A recent move in forward‑thinking innovation for unconventional
shale plays is Cameron’s F‑T90™ frack tree. It is the industry’s first
horizontal frack tree specifically suited for today’s factory approach to
multiwell pad drilling, batch completions, and simultaneous operations
(SIMOPS) applications. The F‑T90 is engineered 50% smaller and 25%

lighter than conventional frack trees while preserving the rigorous
durability and reliability required by the industry (Figure 1).
By taking the tall vertical configuration of the frack tree and turning
it horizontally, the industry is able to take advantage of this configuration
to reduce vibrational effects of fluctuating pressure caused by the
introduction of solids flowing through frack equipment, enhancing the
integrity of overall frack operations. The 90˚ goat head is located at the
end of the horizontal section, resulting in the distance across which the
bending loads act being less than half of that of a conventional stack‑valve
frack tree. Overall, its ultra‑compact footprint makes installation easier and
reduces bending stress at the wellhead connection.
Frack service is just about as harsh as it gets, and with the adoption
of zipper fracking, frack trees and manifolds are being exposed to
nearly continuous service, flowing and controlling high‑pressure,
high‑volume, abrasive/corrosive frack fluid for days and weeks. To
address these issues for continuous reliability, the frack trees incorporate
metal‑to‑metal seals, feature CRA inlay in seat pockets and ring grooves,
and use zero‑chamfer flowbores to mitigate turbulence that is known to
exaggerate erosion.
These features have proved beneficial in field application; there
will no doubt be more developments as the mission toward increased
reliability continues.

Innovation of frack fluid delivery

One factor in the evolution to multiwell pad drilling and batch
completions is the increased time that pressure pumping crews are
spending on the wellsite. Not long ago, service providers often spent
five to seven days fracking a single well with 20 stages per well, on
average. Nowadays, pressure pumping crews are spending 20 to 30 days
on a multiwell pad and are completing over 50 stages per well; or over
200 stages per multiwell pad.
Meanwhile, demand is rising as operators push lateral lengths,
the number of frack stages, and drill wells more closely together, while
greatly increasing proppant and frack fluid volumes. Operators in some
shale plays are injecting the equivalent of two trainloads of sand (more
than 200 hopper cars) into each four‑well pad. Doing all of this requires
sustained use of pressure pumping equipment at high performance
thresholds, prompting faster wear and tear on frack service equipment.
One of the standard responses to these conditions has been to put
more fluid through more lines. But, that only adds to an already tangled
maze of lines on the well pad. One answer is the Monoline™ frack fluid
delivery system. This system replaces the need to rig‑up four separate
flow lines to the frack tree with a single line featuring a large inner
diameter bore to accommodate the large frack fluid volumes required in
today’s hydraulic fracturing programmes.
The single‑line frack fluid delivery system adheres to API standards
and uses bolted connections to promote a higher level of system
integrity and safety. The system uses a series of 5 in. inner diameter
high‑pressure pipe segments that are bolted together with 90˚ elbows
and swivel flanges. This configuration allows the full range needed
for alignment between the frack tree and the frack manifold. It also
eliminates the potential to mismatch equipment and simplifies the
rig‑up procedure. Installation time is reduced by more than 60% over
conventional frack‑iron piping systems.
During field application in the Eagle Ford Shale, this system was
shown to reduce potential leak paths, eliminate mismatched connections,
remove temporary pipework, and resist erosion during a 23 frack stages
per leg operation. The operator saved over 15 hours in installation time
and 84 man‑hours needed to install typical frack‑iron pipework.
In a Canadian application, the Monoline frack fluid delivery system
was also shown to improve operational efficiencies during an operation
with more than 14 frack stages per leg. A four‑person crew and one crane

Figure 3. An example of advances made in the area of wellhead
reliability and functionality for unconventionals is Cameron’s advanced
multi‑bowl nested diverter snap ring (MN‑DS) wellhead system.

Figure 4. The F‑T90 is engineered 50% smaller and 25% lighter than
conventional frack trees while preserving the rigorous durability and
reliability required by the industry.
Reprinted from June 2015 Oilfield Technology |

were used to install the pre‑assembled system in 3 hours per leg. The
rig‑up time was seen at about half of that time, or around 1.5 hours
per leg. In addition to reducing the wellsite footprint, the system
achieved a 50% reduction in the number of needed hammer union
connections.
As the number of needed connections is decreased, reliability
of the connections is increased and the drastically reduced maze of
flowlines and restraints will have a positive impact on safety. It is the
collaboration of the operator with the service companies in exploring
new ways of delivering today’s high‑volume hydraulic fracturing
programmes that ensures reliability in operational performance.

Innovation for holistic reliability

Figure 5. One of the standard responses to these conditions has been to put
more fluid through more lines. But, that only adds to an already tangled maze of
lines on the well pad.

Figure 6. One answer is Cameron’s Monoline™ Frac Fluid Delivery System. This
system replaces the need to rig-up four separate flow lines to the frack tree with a
single line featuring a large inner diameter bore to accommodate the large frack
fluid volumes required in today’s hydraulic fracturing programmes.

Figure 7. FracServ™ valve integrity protection plan establishes a sequence
of activities and inspections designed to ensure that any degradation of frack
equipment is identified and corrected before the equipment is reassigned to
another frack job.
| Oilfield Technology Reprinted from June 2015

To drive reliability into the frack programme is to understand the
erosion effects on service equipment used in today’s hydraulic
fracturing operations.
The primary type of erosion encountered with surface frack
equipment is erosion due to solid particle impingement. Frequently,
fluctuating pressure coupled with sand loaded frack fluid can damage
the structural integrity of a frack tree. Sand, acid, and many other
erosive and corrosive elements of a frack job reduce the life of the
frack tree’s valve gate and seat. Lacking proper attention, the high
pressure variations and chemical makeup of fluids used during a frack
job can reduce the lifespan of elastomers and other soft goods in the
valves of the frack tree (Figure 2).
In order to fully understand operating conditions and erosive effects
on equipment used in hydraulic fracturing, specifically frack trees and
manifolds, Cameron has conducted extensive erosion studies. From
these efforts, Cameron has developed engineering standards to address
erosion effects and maintenance procedures to ensure reliability of the
frack equipment. These procedures, known as FracServ™ valve integrity
protection plan, establish a sequence of activities and inspections
designed to ensure that any degradation of frack equipment is identified
and corrected before the equipment is reassigned to another frack job.
An example of this diligence helped one Bakken operator achieve more
than 99% uptime in fracturing operations.
Another example of increased frack tree uptime is the experience of
one operator starting up development in the Fayetteville Shale. Faced
with the daunting challenge of entry into a new type of exploration
combined with concerns about finding quality equipment and
personnel to reach the company’s ultimate goals through adherence
to strict operating standards, the operator needed to keep fracturing
operations continuous without unexpected shutdowns for frack tree
repairs. Use of special valves and methodology significantly heightened
confidence in frack tree integrity. Time lost to have a new valve brought
to the wellsite, set a plug, and replace the faulty valve is about the
time it takes to complete a frack stage. For this operator, savings from
not having to replace a faulty valve on the frack tree was valued at
approximately US$1.5 million.
In the Eagle Ford, an operator achieved performance gains through
the use of comprehensive maintenance procedures. The operator
previously had been experiencing three to four failures per week that
had cost on average about US$2.7 million per month. Since instituting
specially designed frack trees and frack manifolds and a comprehensive
maintenance programme, this operator achieved a valve integrity
success rate of 100% on 189 frack stacks and 72 zipper manifolds.
The onus of success in exploitation and production in today’s
unconventionals is on the reliability of necessary technology to keep
the industry moving forward. Therefore, as the gap in the ‘other 20%’
is closed, both operators and service companies will be able to thrive
in a low oil price environment.



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