SPE-173605-MS
Sand Probe Installations – An Effective Technology for Mitigating Sand
Erosion Incidents in Marcellus Surface Production Facilities
Nicholas A. Piet, and David A. Wozniak, P.E., Talisman Energy USA, Inc.
Copyright 2015, Society of Petroleum Engineers
This paper was prepared for presentation at the SPE Production and Operations Symposium held in Oklahoma City, Oklahoma, USA, 1–5 March 2015.
This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents
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Abstract
The large fluid and sand volumes associated with multi-stage, horizontal shale fracture completions have
placed a major burden on the operating efficiency and integrity of surface equipment designed to handle
sand-laden flowback. Many methods have been attempted to reduce and/or eliminate sand production
during flowback and ongoing operations but due to a variety of flowing conditions sand flow to surface
is inevitable. Talisman has worked extensively on implementing the use of sand probes to effectively
monitor and mitigate incidents related to sand erosion of surface piping related equipment. This simple,
low cost solution has made a major impact on Talisman’s operating philosophy.
As the use of sand probes was not part of Talisman’s standard wellsite design, testing was required due
to the occurrence of multiple sand related incidents following removal of flowback equipment. Although
sand flow is greatly reduced following an initial period of flow (30 to 60 days), the slugging nature of
horizontal wells provides a significant risk for unexpected large quantities of sand to damage permanent
separation equipment, surface piping and valves. Installing sand probes has successfully demonstrated the
ability to shutdown wells prior to compromising the mechanical integrity of surface piping/facilities.
An initial pilot test was performed on several wells to determine whether or not sand probes were
capable of providing adequate indication of erosive flow conditions. This paper details those tests and the
results thereof. As the probes proved to be functional, Talisman now has over 100 installs in its Marcellus
operating area.
Sand probes, although not a new technology, did prove to be challenging in this application. Several
changes have been made since the first design in order to improve performance. In addition, much
emphasis was put on the operating philosophy of the probes and actions required following device trips.
This paper will share that information.
Introduction
Sand separators, also called sand traps, are commonly used on hydraulically fractured wells both during
flowback and during early life production periods. They can be in service at a wellsite for as few as three
months or up to a year. As sand and fluid volumes decline, the traps are then relocated to other new wells.
These traps are the primary method used to remove sand and prevent sand-related erosion on the wellsite
facilities. The traps are manually dumped at specific time intervals as automated level controls are not
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SPE-173605-MS
used due to the nature of the quasi-liquid level that exists within the separator. Two main problems exist
with the use of sand separators: 1) they are subject to sand/fluid carryover for a multitude of reasons and
2) after removal, random sand events can and still do occur. Heavy liquid slugging and generally erratic
flow behavior in the early flowing period of these wells contribute to the carryover issue as does the
manual, time-based dumping of the separator. When carryover does occur, the remaining surface piping
and facilities become subject to sand flow and the resultant pipe erosion.
Samples from the sand separator are taken in order determine an approximate rate of sand production.
When a well produces trace or no sand, it is deemed safe to remove a sand trap. At this point in the life
of the well, it is considered to have produced almost all of the sand possible. However, this assumption
is not entirely correct. Line pressure fluctuations and shut in periods can increase slugging tendencies in
these horizontal wells. Slugging can bring large amounts of sand to surface in a short period of time thus
compromising the mechanical integrity of the surface piping. Toe-up wells in particular have been
observed to produce more solids. This is assumed to be the case because in large 5.5⬙ casing, solids can
fall to the heel of the well near where the tubing is landed and subsequently be carried to surface. Even
though the sand trap is gone, these slugging moments still occur and can produce sand to surface. Once
the traps have been removed, the permanent surface facility must now handle all fluids produced inclusive
of these short term, high rate sand production events. There have been many occasions where these events
have caused pipeline and surface facility integrity issues. Although permanently installed sand separators
have been considered, the minimal frequency of these slugging events together with excessive capital and
operating expenses have deterred Talisman from installing such equipment. The immediate concern is
how to deal with mitigating the impact brought about by these sand events that may only occur once or
twice in the life of a well without incurring the expense associated with permanent sand separator
installations. The solution Talisman is now utilizing involves the installation of sand probes to detect and
shut down the well upon the first signs of sand erosion.
Sand probe technology has been around for several decades and this paper is not intended to show a
new method for their use but rather to demonstrate how probes, in combination with other erosion
mitigation efforts, are able to help this operator reduce process safety incidents in an unconventional shale
gas play.
Description and Application of Equipment and Processes
Design Considerations
Permanent surface production facilities consist of a 3 inch steel flowline feeding a common industry gas
processing unit (GPU). The GPU contains a horizontal separator together with an indirect fired line heater
and manually adjustable choke. At the inlet to the separator is a pressure controlling valve (PCV) designed
to limit inlet pressure to the separator. The choke and PCV are both 2 inch body valves with 1 inch trim,
and represent a very typical setup for GPUs in the Marcellus. Because both valves have a 90 degree bend
along with a reduced flowing area, they become the first point where erosion would occur in the system.
Piping immediately downstream of the valves is also susceptible to erosion because of the jetting effect
caused by the valves. Neither of these situations are a new revelation. Flowback companies have been well
aware of this and typically utilize a larger, thicker blast joint immediately downstream of the primary
choke. This design is not typically implemented in permanent production equipment, although it is
something worth considering. The issue is that the choke needs to be submerged in the line heater bath
to reduce the risk of hydrates. Knowing that these valves are the weak link when it comes to erosion,
several types of trim materials are available to help reduce the rate of wear. Utilizing even some of the
hardest trims such as tungsten carbide, sand erosion has still resulted in unacceptable wear. Overall,
facilities in the Marcellus have evolved to be better suited to withstand sand erosion. Control valves have
been changed from straight-body styles to angle-body styles. Although this sounds counterintuitive, the
flow path is actually less tortuous flowing in an angle-body valve than in a straight-body valve. All turns
SPE-173605-MS
3
in the piping system are installed with either plugged tees (in screwed piping) or cushion tees (in welded
piping). This design, in addition to increasing the flowing area through the bend, also increases the
thickness of the steel thus reducing and nearly eliminating the risk of fully eroding the pipe. Visual
inspections as well as ultrasonic thickness testing have verified no erosion present in the flowline systems.
The only reported case of pipe erosion occurred on a drain line feeding to a tank in which a 90 degree
elbow was installed instead of a plugged tee.
Operating Philosophy
Once the temporary sand separator has been removed, there is still the need to ensure the facilities have
not been subjected to erosion. At this point, a preventative maintenance (PM) program is initiated on the
well consisting of visual inspections of all control valves and the choke. This involves shutting off the
well, blowing down equipment, and removing the valve trim from service. If no wear is detected, the PM
is pushed further in time. Initial frequency is daily and continues to move out as long as no wear is
occurring. If wear is detected, the seat and stem of the valve are replaced and the frequency of inspection
remains the same.
Valve inspections are good is some ways, bad in others. In this author’s opinion, they are a great
opportunity to open up the process piping and inspect for various items along with wear. It is a chance
to look for scales, salts, sands, grease or any other solids that may be building up in the pipe and valves.
Although valuable, valve inspections present both a safety and business concern. In addition to the
associated downtime incurred every time an inspection is performed, operating personnel are exposed to
the risks associated with blowing down and locking out equipment. As there are at least three valves
checked during PMs the resultant down time is less than 2 hours, however, when multiplied by several
hundred wells in the field production losses can add up quickly. Additionally, when a well is shut down,
the resulting build up pressure and subsequent spike in flow rate when returning to production has the
potential to surge sand to surface. This is exactly what the operator is trying to prevent in the first place.
Prior Testing
Previously, the operator was testing an ultrasonic sand sensor. This device attached to the outside of the
pipe and “listened” for sand flow. The device was able to find that there was frequently sand in varying
amounts flowing through the flowlines. While the device was good at detecting sand, the main problem
was detecting an actual erosion event. In addition, the device was installed on multiple wells immediately
after reported sand events. Then sand erosion was not frequently encountered following installation. This
was a direct indicator of the random slugging behavior on multi-stage, horizontal completions which also
highlights the difficulty in testing sand erosion monitoring technologies.
Pilot Test
Sand probes were proposed to be tested for multiple reasons. First and foremost, they presented the
opportunity to directly eliminate sand-related washouts of the valves. Second, they could reduce the
labor-intensive valve inspection PMs and the risks associated with those operations. Finally, their use
could potentially reduce the amount of time sand traps remained in service at the well. If installed
correctly, they could give a direct indication of erosion unlike the ultrasonic sensors.
The big question was whether or not the probes were able to trip in the proper amount of time to
successfully accomplish any of these objectives. If the probes were able to shut down a valve when a
damaging sand event occurred, they could prevent a loss of gas or liquid to the atmosphere. If they could
wear at a similar rate to the valve trim, they could reduce the need for PM inspections. If they could
indicate limited wear near the wellhead, they could provide notice that a sand trap was no longer needed
thus reducing the associated cost.
In order to gather the aforementioned information, the team decided to conduct a pilot study to test the
effectiveness of the probes. The first task was selecting a good candidate. Two wells located on the same
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pad were selected as initial candidates. One well was recently brought online following the initial
hydraulic fracture treatment; the other was expected to come online a few months later. The first subject
well had reportedly encountered several sand events and was toe-up so it seemed a good choice. The
second well was also chosen because of its toe-up orientation and the fact that it had not yet flowed. Sand
production, like water and gas, is typically highest at the very early stages in the life of a flowing well.
Selecting the newest wells gave a high likelihood of sand production to help ensure a good test.
After selecting candidates for the trial test, the next step was selecting the installation locations in the
process piping. In discussions with the manufacturer’s representative, the initial recommendations were
that the probes should be installed in a straight run of pipe, several diameters from turns or valves. There
were doubts that this would be an adequate location with enough velocity to cause the probes to trip.
Because it was a pilot test, the thought was to make sure to test as many locations as possible. See Fig.
1 below.
Figure 1—Sand Probe Installed Locations for Pilot Test
Probes 1 and 2 were installed in 1/2 inch thread-o-lets (TOL) within the 3 inch piping both upstream
and downstream of the PCV. The downstream position of probe 2, being directly past the outlet of the
valve, represents the most turbulent spot in the surface facilities. The only other similar spot would be
directly downstream of the choke, however, there is not typically room for a TOL in this location because
the choke seat needs to sit in the bath for hydrate prevention. The concern at this point was that the jetting
effect of the PCV would cause the probe to trip or break excessively. Probe 1 on the inlet side of the PCV
represented a slightly calmer flow area but was also downstream of the post-heat passes of the choke. The
chokes are typically not used for long periods of time since the separators are sized for maximum potential
flow from the wells. The PCV is the most likely place where a restriction and subsequent high velocity
would occur. Probes 3 and 4 were installed on the inlet and outlet of the sand separator. These locations
were both in vertical 2 inch pipe. The concept was to observe the difference in erosion before and after
sand separation. One thought was that the inlet probe 3 could be inspected and once signs of wear
subsided, it could give an indication for trap removal. The outlet probe 4 was installed to act as a reference
point for the inlet probe as well as to help identify whether or not sand carryover was occurring. Probe
5 was installed at the inlet to the GPU in a straight run of 3 inch pipe. With this being the quietest flow
area on the system, it was believed that it would show the slowest rate of erosion of all locations. It was
anticipated that the location of Probe 5 was not going to show much erosion, however, it was tested in case
the other probes were tripping too quickly.
Probe style and material
Two main probe styles exist in in the marketplace: a switch-type or analog-type. The switch-type has a
hollow probe design and once the thickness of the probe is worn through, a signal is sent to alarm or
SPE-173605-MS
5
shutdown the well. The analog types are a solid design and send out a variable electrical resistance based
on the amount of probe material remaining. Based on cost (approximately one-tenth the cost of the analog
style) and availability, the simpler switch-type probe was selected for this test. The other option to be
evaluated was the type of relay to which they were attached: hydraulic, pneumatic or electric. For the pilot
test, electric relays were selected in order to be utilized in the Scada system for remote monitoring.
Hydraulic or pneumatic relays were not selected as they would typically be tied into a shutdown valve and
it was a distinct possibility that this would lead to a large amount of nuisance down time. The probes
themselves had a 1/4 inch thread which connected to a female port on the relay. The relay had 1/2 inch
male threads that would then connect to the flowline TOLs. Upon probe erosion, the pipe pressure would
force a plunger inside the relay to actuate and trip the signal inside the relay. The probe dimensions were
a 1/4 inch outside diameter and the thickness and length were sized for the pipe diameter and schedule.
See Table 1 below, taken from Ruelco’s sand probe brochure. In this table, the top row shows wall
thickness of the probe for varying pipe schedules. “G” is the probe outside diameter corresponding to the
pipe schedule. “H” is the installation depth depending on nominal pipe size. The manufacturer’s
recommended probe length and thickness was used during the initial test. A longer probe is utilized for
larger pipe diameter while a thicker probe is used in heavier wall pipe. The last item to consider was probe
material. From this manufacturer the standard materials available were 1018 carbon steel and 316
stainless. Other materials could be selected if needed, but for this field 1018 carbon steel was chosen. The
stainless was typically reserved for more of a corrosive environment and in this field, the gas is sweet. The
pipe in service was API grade X-42. The 1018 is a close comparison to X-42 in terms of hardness. The
X-42 has an estimated Rockwell B hardness (HRB) of 65 based on its 60,000 psi tensile strength. The steel
used in the probes was tested in the factory to a 77 HRB. Although these were somewhat similar, there
was a slight discrepancy. This added to the question of whether or not a probe of different material, set
in a spot away from the valve where erosion typically occurs first would be able to give an early indication
of wear without tripping too soon. Not to mention that the choke and PCV trim material are substantially
harder than either steel.
Table 1—Sand Probe Dimensions
The final task prior to the trial probe test was to give direction to the well operators as to what to do
when a probe tripped. It started with a very simple instruction: shut the well in and notify engineering. The
way the probes were setup, the ones around the GPU were on a single circuit and the probes near the
wellhead were on a separate circuit. They were tied to an RTU and the signal was displayed in Scada.
They were set to alarm and callout upon eroding. The only issue with this was that when a callout occurs,
all probes in the same circuit would need to be looked at to determine which tripped. This was adequate
for a pilot test, but would need to be refined for future widespread use.
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SPE-173605-MS
Pilot Test Results.
After all the preparation was complete, it was time
to wait and see if substantial sand production would
actually take place. As was seen before with ultrasonic sensor testing, not every well is subject to the
same sand production at surface. It was very typical
to test the sensors for months on a well and get no
valuable data. This would result in moving the
equipment to another test candidate. With the number of probes and amount of time invested in this
pilot, it would have been disheartening to not have
any sand production and be forced to move on to the
next location. As fortune would have it, a significant
sand event took place not very long after installaFigure 2—Picture of PCV with Sand Probe Locations
tion. A callout was initiated, but the well was not
shut in until a few hours afterwards. Upon inspection by the engineering and commissioning teams,
the choke stem and body showed significant erosion as did the PCV ball and seat. The probe downstream
of the PCV had tripped due to a small hole at the probe tip and showed sand buildup along the length of
the probe. The probes upstream of the PCV, at the inlet to the GPU and the inlet and outlet of the sand
trap showed minimal if any wear and little sand deposition. This was discussed amongst the team and
found to be remarkable that a large sand event occurred enough to damage the choke and PCV with only
one sand probe showing significant erosion. It is important to note that the choke position was wide open
for this test. This well was returned to production at a restricted rate with the probes still in service. After
this, a second pad recently put online was tested in order to validate the results of the initial test. This
second test, however, did not offer a similar situation to the first as no probe trips occurred following
installation.
Field-wide Installations
Following the pilot testing performed in 2012, the team decided to implement probes on all new wellsite
installations to further observe their impact. The intent was to implement their use across a wide variety
of wells in different areas in an attempt to establish a standard design practice. If the larger scaled field
study proved successful, significant economic and safe operating benefits could be derived. This next
phase of testing required a significant design change as compared to that used during the pilot testing. The
number of probes installed was reduced from five to two with probes only installed at the inlet and outlet
of the PCV. See Fig. 2. Location A identifies the position of the probe in the 3 inch piping at the inlet to
the PCV while location B shows the probe in the outlet 2 inch piping. A TOL was installed at location
C for future use to be referenced later in this paper.
These were the only locations selected based on observations on the pilot testing showing little, if any,
wear on the other sites. The 2 inch pipe location was selected because of higher flow velocity, which in
turn causes faster erosion of the probes and quicker trips. The choke body in the first test well eroded after
only a few hours of flow following the probe alarm. With this in mind, it was desired to make the probes
trip as fast as possible to prevent compromising the integrity of the pipe. Another design change was to
implement hydraulic relays instead of electric. These would trip the wellhead emergency shutdown valve
(ESDV) upon eroding, shutting in flow and preventing any further wear on the wellsite facility. The team
did not want to install the probes in a manner that would shut down the PCV because that valve was a
likely place of erosion and frequently did not seal completely after being in service. In an additional effort
to accelerate probe erosion, the minimum thickness of the probe was used regardless of pipe thickness.
SPE-173605-MS
The final item that was changed was the length of
the probe. Due to the heavy wall 6000# TOLs being
used, the probe lengths that matched up with the
pipe size were only extending to about halfway
down the pipe inside diameter. The probes going
forward were instead increased by one nominal size
to get the tip of the probe down within 1/4 inch of
the bottom edge of the pipe wall. The reasoning was
to ensure maximum sand detection by limiting the
area that sand could slip by the probe. The last
action prior to initiating the field study was to
formalize expectations of well operators following a
sand probe trip. A document was drafted, approved
by the team, and sent to operations staff. Operator
training was provided focusing on the main points
of the document which were:
7
Figure 3—3 in. Sch 40 Straight versus Tapered Probe
Table 2—Max Velocity with API 14E C Values
Velocity, ft/s
C Value
1. Pull and inspect the sand probe. Submit to
2⬙ Sch160
300
248
engineering.
3⬙ Sch160
127
102
2. Inspect nearby piping and valves for any
wear.
3. Consult supervisor and return well to sales
on restricted production.
4. If multiple trips were reoccurring, consideration was to be given to return a sand trap to service.
After these final touches were determined, installations and subsequent analysis began. Sand probe
trips began occurring immediately on new wells, however, most were nuisance shutdowns and not
necessarily trips from sand. The probes, in many cases, appeared to be cracking at the shoulder base. In
some instances, the probes would not last more than a day and the main section of the probe would be
completely sheared off. Every probe that cracked was installed in 2 inch downstream of the PCV. This
was very troublesome as new wells – at a development cost of several million dollars – were being shut
down frequently for nuisance trips. Cracked probes were sent to IMR Labs of Ithaca, NY for failure
analysis which demonstrated that the probes were failing due to vibrational fatigue. As fluid passes by the
probe, oscillating pressure waves trail behind causing the probe to vibrate in a direction perpendicular with
the flow path (i.e. the von Karman effect). The frequency at which the probe vibrates is directly
proportional to the flowing velocity. This is the same principle used in vortex metering technology.
Conversations ensued with the manufacturer and it was found that the probe sizing was based on
thermowell design standard ASME PTC 19.3 TW-2010. Upon reviewing this standard, it was noted that
probes or thermowells can fail for two reasons: excessive velocity or resonance effects. Utilizing the
calculations within the standard and all properties of the fluid and steel present, it was determined that the
probes were operating near the fatigue limit because of too high of velocity. The resonant frequency was
found to be very low, so the probes actually operate at a velocity much greater than resonance. The stress
on the probe was also exacerbated by using longer, thinner probes. The additional length caused a higher
stress on the base shoulder of the probe and the thinner wall thickness reduced allowable stress. Based on
this, the manufacturer recommended a tapered probe design (Fig. 3). This would entail having the upper
half of the probe tapered with a gradually increasing thickness up to the shoulder allowing this design to
handle roughly twice the velocity as the current probes. In doing the calculations, velocities were checked
to compare with API RP 14E recommendations. See Table 2. These were based on maximum design rates
of 6 mmcfd at 200 psig. Talisman’s Marcellus team uses a C constant of 150 for designing wellsite piping.
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Table 3—Probe Installation History
PROBE STYLE
Straight-body
Tapered
NUMBER OF
INSTALLATIONS
ERODED AS
DESIGNED
FAILED DUE TO
CRACKING
ERODED WITH NO
VALVE WEAR
70
54
12
14
13
0
1
2
Through this it was interesting to note that the velocity in 2 inch is more than double the velocity in 3 inch
pipe and well over the recommended C of 150. This is typical in installations when control valves are
required to be smaller than the main pipe and the reason for why it is preferable to immediately swage
up after the valve.
As the investigation persisted, it became apparent that an immediate change was needed to the
installation standard. The first revision was to move the probe being installed in 2 inch pipe downstream
of the PCV to the 3 inch section (location C in Fig. 2). This put the probe in a much lower velocity
environment and helped to reduce the probe cracking failures, but did not eliminate them. Five wells
encountered cracking failures with probes installed in the 3 inch pipe downstream of the PCV. Another
change that was needed was to update the operator expectations document to reflect cracked probes. The
operators were informed to move the probe to the 3 inch if nuisance cracking trips occurred. In
conjunction with these changes, testing began on the tapered probes. The major concern with tapered
probes was that the additional thickness could cause slower trips and reduced effectiveness of the device.
This was not found to be the case. Almost every successful probe trip from sand showed erosion at the
probe tip which is the thinnest section. The tapered version also held up well to high velocity without a
single reported cracking failure since the first install in late 2013. Moving to 2014, the new probe standard
was tapered installed in the 3 inch downstream and upstream of the PCV.
Results
Overall, 124 wells were equipped with sand probes as shown below in Table 3. Ninety-four of those were
newly completed and in service since the first day online. Nine of the first 43 new wells, or 20%,
experienced nuisance failures due to cracking on straight-body probes. The transition to tapered probes
began in early 2014, and to date, 54 wells had them installed with no reported cracking failures.
Twenty-six erosion-related probe trips occurred in which case the PCV or choke were also observed with
wear. In some cases, the wear was minimal and in others, the wear was extreme. No pipe wear was found
in all instances and the probes appeared to have tripped soon enough to potentially prevent further
damage. There were a few exceptions: three probe trips occurred where no valve or choke wear was
detected. On four wells that were being significantly choked, there was wear found in the choke stem and
seat that was not indicated by the sand probes. This wear on the choke can be noted by increased flowing
rates from the well or the need to continually turn down the choke to manage the flow rate. In one case,
a choke eroded through the seat and body of the valve. In another case, a well was returned to production
without a thorough inspection of the valves and a pin hole in the short run of stainless tubing used as a
bypass for the PCV was overlooked. Another well, which had multiple probe trips due to sand, resulted
in a dump valve washout caused by excessive sand accumulation within the production separator that
eventually carried over to the dump system.
Of the 29 erosion-related trips across 2013 and 2014, only eight were activated at the probe located
upstream of the PCV. When the downstream probes were inspected, they were found to show wear
varying from minor polishing to near through-wall. The standard usage of probes today still includes both
probes straddling the PCV even with the low percentage of activation on the upstream side. In three of
these erosion-related cases, sand traps were still in service at the time of the probe trip. Inspections of the
SPE-173605-MS
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sand traps revealed that they were completely full of sand, unable to handle the large sand slugs that were
produced.
Conclusions
In a paper presented by Hedges and Bodington (2004), the authors made note that the primary factors in
successful probe installations were location, location and location. This proved to be the case again in this
field test. Location meant the difference between a useless device and an effective one. It was necessary
to place the probes immediately adjacent to the most erosive areas of the system. As highlighted over the
years in the Marcellus, the choke and PCV are most susceptible to erosion in these wellsite facility setups.
The contributing factors are directional change and reduction in flowing area. The pipe near these valves
is the next place that eroded metal was seen. Sand probes installed here ultimately ended up being a
critical, complementary addition to Talisman’s erosion management program and have been incorporated
into the wellsite facility design standard. There have been several instances, as described in this paper,
where their use has directly prevented potential gas releases to atmosphere or further damage to pipe. Even
still, sand is a tricky phase to pinpoint. There have been a couple of cases when two probes installed have
not caught sand erosion at the choke. These occurrences were associated with excessively choked flow.
Adding probes right downstream of a choke would likely help. However, there is risk for hydrate
formation on stronger wells with the choke being pulled farther away from the bath to accommodate the
probe. Also, the probe would likely need to be more rugged to withstand extreme jetting velocity in this
location. There was also the case of a dump valve washing after several probe trips. The operator
expectations document was modified to give direction following multiple probe trips. When this occurs,
the production separator is inspected for sand buildup and flushed if necessary before returning to
production. An added measure could be installing a probe on the drain line to actuate as a result of a sand
carryover. The end result would be the same, with the separator needing to be flushed. This additional
probe has not been implemented at this time.
A major impact on the effectiveness of the probes was operator training. Getting buy-in from
operations staff and completing a clear expectations document helped to ensure tripped probes were
responded to properly. If a probe trips and is replaced without inspection or returned to sales at the well’s
maximum potential, the device will not be effective. It is critical to have the operators follow guidelines
and inspect the valves and piping to determine the next steps, whether it be reducing flow or reinstallation
of a sand trap. The cracking issues that occurred nearly derailed the program. It caused low confidence
in the effectiveness of the probes and a feeling that the buy-in could be lost. Due to the development of
the program and the design changes of the installs, it was critical to ensure this issue was managed and
ultimately eliminated. What started as nuisance callouts causing down time escalated into frequent
shutdowns on new, high-volume wells. Several callouts ensued and it is easy to see why the team was
discouraged early. This large failure frequency of straight-body probes ended up being somewhat easily
remedied with tapered probes.
The other ideas behind this project were to see if probes could reduce valve inspections and sand
separator time on site. Valves are still being inspected at specified intervals, though the frequency has been
reduced. This has led to a reduction in down time and labor hours involved with this work. Probes were
not found to be effective when installed near the sand separators, as reported in the pilot test. However,
since they have been installed it has given the team more confidence when making the decision to remove
a trap. Previously, sand traps were installed as a standard when a well was subject to downhole
communication from an offset well being hydraulically fractured. In the majority of cases, the well did not
produce damaging sand but since there was a risk for sand production, the conservative approach was
taken and a sand trap installed. The new standard is to install probes in place of the traps resulting in a
cost savings initiative. As it turns out, about 90% of the time the trap is not needed and those costs are
eliminated. In the rare case of frequent sand production, the trap is required to be installed. Overall, the
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sand probe program has proven to be a reliable complement to existing erosion mitigating efforts. The
implementation of this project across the field has led to a great reduction in man-hours, down time, and
process safety incidents. Most importantly, it has helped put the field staff in a safer situation. Sand probes
have helped Talisman take another step toward their goal of zero incidents.
Acknowledgements
The authors would like to thank Talisman Energy USA, Inc. for consenting to publish this manuscript.
Also, the authors would like to acknowledge the Talisman Marcellus Delivery Unit operations, commissioning, and construction teams who offered immense support and late nights throughout the testing of this
technology. Specifically, Tony O’Sullivan, Jeff Bowers, Dave Glatt, and Pete Lorson helped spur this
project and provided a wealth of experience and knowledge. We would also like to thank Weatherford for
introducing us to the technology and providing technical expertise as well as installation guidance. We
would like to thank Ruelco who manufactured the probes and provided great support in the midst of the
cracking failures and IMR Test Labs for providing the failure analyses on the probes.
References
API RP 14E, Recommended Practice for Design and Installation of Offshore Production Platform
Piping Systems, fifth edition. 1991. Dallas, Texas: API.
ASME PTC 19.3 TW-2010. Thermowells Performance Test Codes. 2010. New York, New York:
ASME
Hedges, B. and Bodington, A. 2004. A Comparison of Monitoring Techniques for Improved Erosion
Control: A Field Study. CORROSION 2004, New Orleans, Louisiana, 28 March – 1 April.
NACE-04355
Ruelco Sand Probe Relay Model IS03 Brochure