By identifying the numerous
barriers obstructing 24/7 reservoir fracturing, a newly developed system utilizes
advanced processes and technologies. The system has led to gains in operational
efficiency, consistency and safety, enabling operators to fracture a reservoir
more hours/day compared to standard procedures and techniques.
SEF Energy, AUSTIN JOHNSON, Downing, PHILLIP DOUGET and MICHAEL
MAST, Blue Ox Resources, JOHN DYER and JORDAN KUEHN, SEF
Energy and BRIAN WIESNER, Downing
In 2018, the first framework for adding automation to a frac stack
was proposed internally. The proposal
called for adding sensors and automated controls to hydraulic valves with a
live data stream and post job analytics.
Shortly thereafter, a novel third-party technology was identified and
acquired. Pairing the service company’s
operational expertise with the automation expertise of the third party, an
expansive vision formed to methodically eliminate the primary barriers to
fracturing the reservoir 24/7.
These barriers, identified as: 1) the time between stages (this
includes transition time and pressure tests); 2) downtime associated with gate
valve maintenance and failures; 3) pump maintenance; and 4) sand and water
logistics, would be eliminated through novel, fit-for-purpose products,
automated workflows and integrated control systems.
A roadmap was established that emphasized continual system
development and increased levels of automation, as each hurdle was overcome, Fig.
1. Similar to the roadmap used for
autonomous vehicles, the hydraulic fracturing roadmap utilizes successive
improvements and integrations to functions and subsystems to achieve ever
higher levels of autonomy, safety and consistency. Table 1 describes
each automation level and its impact on safety, consistency and pump
The surface system currently has
been integrated into a single subsystem, achieving Level 4 automation. This
subsystem is integrated into the wireline and pump subsystems, laying the foundation
to achieve Level 5. Contrast this with most operators using Level 2 surface
systems that employ multiple, non-integrated controls, leaving most process
control to checklists, procedures, and human expertise.
surface system (Freedom Series Completion System) to achieve 24/7. Several papers have been published regarding the automated surface system
in its initial phases. The automated surface system has the following
components, with several of the recent upgrades highlighted for further
These system components are integrated into a single, automated
surface system that enables an operator to instantaneously transition from one
stage to the next continuously, day after day.
The system eliminates the four barriers to pumping 24/7 through the
An automated lubricator reduces decision time, as well as
potential NPT events:
Automated missile equalization.
In many frac operations today, personnel enter the
red zone to bleed off the missile. Integrated into the automated surface system
is the bleed-down and equalization of the missile from the safety of the frac
van, shortening the time required to switch out pumps and removing personnel
from a hazardous red zone operation. This enables frac crews to always be completely
red zone-free, eliminating the need for any exceptions. And it saves additional time and expense by
automatically greasing the equalization plug valves, eliminating a potential
source of NPT.
Automated pump swapping.
The key remaining barrier is ensuring pumps are
operational 24-hr/day to keep pumping at the prescribed rate. Today, the average frac crew utilizing
zippers operates consistently at 16 hr/day, leaving a 50% upside in pumping
each day when this problem is resolved. Figure 2 highlights the potential efficiency and utilization gains of employing
the automated pump swapping technology.
traditional approach to pump maintenance has focused on improvements to the
pump truck. The automated pump swapping addition to the automated surface
system approaches the problem differently by enabling a pump to be replaced
without stopping operations or personnel entering the red zone. The system is placed between each frac pump
and the missile. When a pump needs to be
repaired or replaced, the system isolates the pump, bleeds down the pressure,
and unlatches the pump. The pump truck
is then removed out of the red zone to be repaired or replaced with another
repaired pump truck is backed into a set position, actuated arms couple the
automated pump swapping skid with a hose plate mounted to the back of the
truck, and the plates are clamped. A
prime up-pressure test and equalization is performed before the pump is brought
back online. Provided the benefits of the automated surface system, this
additional technology enables an operator to achieve 24 hr of pumping per day. Benefits
to the pumper include higher pump truck utilization, greater revenue, more frac
jobs per month, and fewer trucks required on any given pad to maintain rate. A
prototype was tested in July 2022, with eight pump swaps successfully completed
without stopping the frac job, Figs. 3 and 4. Lessons learned
from the prototype have been incorporated into the final product.
the goal of 24/7 fracturing required a number of industry firsts as outlined
automated valve. The base system, commercialized
in 2019, automates the equalization process, enabling rapid transitions.
integrated latch. Part of the base system, the
integrated latch is interlocked with the automated valve, eliminating potential
pressure releases by ensuring the latch is properly tested and in place before
the valve can actuate. In addition, the
system allows the lubricator to be attached during frac, eliminating time on
critical path for this task.
handshake. A unique authentication code, changing every 30 sec, is tied to
each person authorized to use the system. The digital handshake reduces the
risk of NPT by ensuring the system is operated only by qualified personnel and
provides traceability, if issues occur.
greasing. Other greasing systems traditionally use pneumatics to drive
grease. Using hydraulics delivers a pressure curve, providing assurance of
grease, eliminating greasing time as well as reducing valve-related NPT
of the surface system. Traditional surface systems have multiple, non-integrated controls. For illustration, the typical surface system has separate controls for each valve, the greasing system, and the latch system. Process control is achieved through human-driven workflows, checklists, placards, lock-out/tag-out. Human-driven workflows are prone to error and, therefore, NPT. The Freedom Series completion system fully automates these sub-systems into an integrated system.
pumping well transitions. The first continuous pumping
transition was conducted in October 2020, in the northeastern U.S. Continuous
pumping is a process that reduces stage-to-stage transition time to seconds.
continuous pumping. This milestone was first
achieved in September 2021 and represents the initial step toward continuous
plan execution. The ability to execute the next
well transition from a remote frac plan entered by the completion engineer,
providing frac flexibility to the engineer, as well as ensuring the correct
stage is completed. The system maintains a queue of fractured wells and will
work through prescribed steps suggesting swaps in order of wireline activity or
will pull from a stage list provided by a completion engineer. Either way, it
will then remove the well from the available wells to frac until it sees
wireline activity again. It eliminates the human decision factor when swapping,
providing the ability to auto-swap as we progress to Level 5 automation.
pump while treating. Demonstrated in July 2022.
simulfrac transitions. In May 2022, the automated
surface system was adapted to simulfrac operations, eliminating stage-to-stage
time on simulfrac jobs.
pumping on a simulfrac job. In May 2022, the automated
surface system transitioned from two wells to two separate wells, performing 11
valve actuations, and initiating greasing of each valve, all in under 40 sec,
facilitating the opportunity to pump 24/7 on simulfrac operations.
debate that is generated when a new technology stands to replace current
practice is well-documented. This same debate can be heard today within the
frac community, relative to surface system automation. Historically, OFS has
done manually what Downing (an SEF Energy company) does automatically (but have you done it every
time), we need to work on all our issues before we take on a new system (SEF’s
system removes many problems, so you can focus on other issues), our pumps
cannot keep up, we have sand and water issues.
What is lost
in the debate is that each issue masks another. If you have pump issues, this
may be masking valve issues; supply issues may be masking pump issues. In
addition, without the high-resolution data available, determining the root
cause of an issue is often difficult and sometimes impossible. Process
improvement involves systematically, eliminating an issue, and then focusing on
the next issue to be resolved. Referring to the roadmap in Fig. 1, Level
0 to Level 3 automation involves human interaction between functions, requiring
time-consuming processes, checklists, and personnel expertise. As noted, when
issues inevitably occur, it is difficult to find the root cause with the
disparate systems on pad.
change over time, process discipline and experience are lost, leading operators
to again experience issues they thought they had resolved. Automated workflows
found in Levels 4 and 5 are driven by one second of data capturing every system
function. System data and automated workflows reduce non-productive time in two
ways: 1) through real time alerts warning the operator of impending issues that
need resolution; and 2) NPT-causing issues that occur are positively identified
through root cause analysis and, unique to automation are engineered and/or
programmed out, permanently eliminating that issue.
illustrates why automation is key to permanently eliminating issues. With the
passage of time, the system becomes more robust, leading to faster and more
consistent frac jobs. To illustrate this concept, the system initially used
wellbore fluid to equalize through a ball valve and choke. Sand in the fluid
caused wear on the ball valve. In addition, the choke had to be properly sized,
based on well parameters. Identifying this as an opportunity for improvement,
the ball valve was engineered out of the system, replaced by a boost pump and
clean fluid to perform equalization and fill the lubricator.
surface system generates gigabytes of data per job, tracking everything from
pressures to valve positions, to open and close events. These data are used in
real time for lockouts, ensuring the system only operates when the prescribed
conditions are present. In addition, the data are used for live and post-well
analytics to improve operator performance. The data are also used for failure
mode analysis, leading to new signatures for alerts identifying potential NPT.
A few of the data applications are highlighted below.
Unique to the automated surface system, an
operational dashboard (Fig. 6) provides the interface for the operator, onsite
service personnel, and remote operations personnel to maintain the surface
system, preventing NPT events prior to occurrence, as well as identifying
improvement opportunities in real time. The dashboard trends operational data,
provides real-time status of all systems, alerts personnel of both potential
failures, as well as predictive maintenance events, and provides insight for
An adaptive grease algorithm (AGA) has been added
recently to the automated surface system. The AGA was developed to ensure all
gate valves are greased properly upon every actuation (defined as packing off
the grease void with grease and then stopping), reducing grease and valve
repair costs and eliminating premature valve failures. This both ensures the grease void is full for
every actuation while also eliminating excess grease and subsequent issues
associated with grease in the borehole.
Initial deployment occurred in October 2022 with
striking results, Table 2. Pump
strokes (correlated to the amount of grease consumed) to grease each zipper,
pump down and stack valve were measured before and after implementation of the
AGA. Overall, grease volume decreased by
55% across all valves (see adjacent table), with no detrimental effects to
valve repairs or NPT. Subsequent
application of the AGA has seen grease volume decrease by up to 90%.
Latch-to-latch (L2L) is calculated and plotted as a measure of wireline turnaround time, from
the time of unlatching the wireline to when it is stabbed and latched again, Fig. 7. In addition to L2L, fill and
drain times are also captured to the second.
Stage-to-Stage (S2S) time is defined at two locations: 1) the
time between stages at a prescribed pressure (just under treatment pressure)
and 2) at treatment pressure, Fig. 8. Stage-to-stage captures the white space between
stages, consisting primarily of transition time, pressure test time, non-pump
maintenance time, and ramp up/down of pressure and pump maintenance time. It also includes non-productive pumping (NPP)
time, defined as time after a transition but before the frac is back at
treatment pressure, not captured in traditional pump efficiency calculations. NPP includes time to ramp up pressure,
pressure tests and spotting acid on critical path.
Stage-to-stage is a better indicator of job
efficiency than pump efficiency. Pump efficiency suffers from several flaws
that make it difficult to compare one job to another including the following:
vs short stages. Long stages artificially inflate
pump efficiency. Comparing two frac jobs, one with long stages (e.g. 3 hr) the
other with short stages (e.g. 1 hr), the longer stage job could be deemed more
efficient, due to the operational cost of transitions on the shorter stages.
This can give the false impression that one crew is better than another. As a
side note, significantly reducing the operational cost of the transition with
the automated surface system, provides completion engineers more flexibility
when designing their treatment program (i.e. providing additional options for
limited entry fracs through shorter stages).
calculation. Pump efficiency is not captured in a consistent way from
operator to operator or from pressure pumper to pressure pumper. This leads to
errors comparing different crews, operators, or pressure pumpers.
NPP (Non-Productive Pumping). Pump time is often started after the transition but before the
pumper is back at treatment pressure. Recalling the goal to pump 24/7 at
treatment pressure, transitioning is only one part of the time between stages.
As noted above, the time between stages can also include NPP, slow ramp up times,
and waiting. Not only does this provide a false measure of efficiency, but when
charged by the pump hr, a job will cost more.
compare the efficiency of one job to another, the S2S is plotted on a histogram
ranging from 0.5 minutes (min.) to 60 min. between stages, Fig. 9. Stage-to-stage
is plotted as a percentage of the total number of stages. For example, using
Fig. 9, 28% in the 0.5-min. range signifies 28% of the stages were
transitioned in less than 30 sec, representing continuous pumping operations
(continuous pumping typically is in the 30-60 sec range). The 60-min. bucket was chosen as a cutoff, given
anything over 60 min. indicates serious problems on the pad that can span days,
unnecessarily skewing the S2S. This also is an indicator of the quality of a
job, as a low percentage in the 60-min. bucket (<90%) indicates more
problems than the typical pad.
10 highlights S2S plotted as an overall average time, with a 95%
confidence interval showcasing transition consistency throughout the job. As noted, S2S over 60 min. has been removed,
as larger issues, some lasting days, can skew what would otherwise be an
not a universal practice, many operators utilize ISIP to gauge the quality of
each frac stage. Traditionally, this
requires a well to be shut-in for a set period.
An engineer selects several points on a screen to establish an ISIP
number. There are several issues with this practice including: 1) requires up
to 5 min. between stages in which operation is shut down; 2) requires time for
an engineer to collect and then manually pick points on a pressure curve; and
3) can be inconsistent, based on the level of experience of the person calculating
operator requested this process be automated from surface system data. They
recognized that by utilizing the automated surface system, the ISIP could be
calculated without operational or administrative cost. The system is open to
each well the entire job, eliminating the need to stay on a specific well for
minutes after the end of the stage waiting for the data to be captured. In
addition, the lengthy ISIP data process includes downloading the data, plotting
the data, and manually capturing the ISIP. This process was automated and is performed
in real time by the automated surface system’s edge computers on the specific
well, utilizing derivatives to capture ISIP. The ISIP is then streamed to the
cloud, where the engineer can download the specific number for each stage.
validate the results, an experienced engineer captured the ISIP data manually,
using the “Superior ISIP” method and compared it to both the ISIP derived from
the automated surface system as well as that supplied by the pumping
company. Figure 11 highlights
that the system-derived ISIP from the automated surface system and the superior
ISIP match almost exactly, establishing the accuracy of the automated surface
system ISIP calculation. The yellow ISIP points (collected from the pressure
pumper) are obviously flawed by continuous pumping operations but also inherent
inconsistencies of data collection at the human level.
Blue Ox Resources, a
private equity-backed Permian Delaware company based in Dallas, Texas, chose to
employ the automated surface system after utilizing it with their former
company, Primexx. Primexx was an early adopter of the automated surface
system and has contributed insights to its development over the past three
years. The system was chosen for its efficiency, the elimination of human
error, interlocks that prevent deadheading or cutting wireline, and the
inherent safety of the system through the removal of people from the red zone
and the pad. With their previous experience, and employing the latest additions
to the automated surface system, Blue Ox Resources set new efficiency records with the
system on the El Duderino East and El Duderino West pads, Fig. 12.
south of Pecos, Texas, both El Duderino pads (Fig. 13) consisted of 3
wells each, spaced 200 ft apart, Fig. 14. The east pad comprised 130
total stages, with the west pad at 126 stages.
Pump times averaged 110 min./stage (at treatment pressure), and 100 mesh
sand was used. The stack configuration
(manual valve, hydraulic valve, cross, with the base system on top of the
cross) is 15k-rated. The zipper consists of two hydraulic valves, which are
both actuated during the transition, providing a constant double barrier. The
pressure pumper provided 22 Tier II pumps with 2007/2008 manufacturing dates.
rate, 16 pumps were required at any one time. The pressure pumper contract does
not include any mandatory maintenance periods. The pressure pumper does have
internal personnel incentives to pump more hr/day. The pressure pumper runs
until they are down to 16 pumps, completing the stage they are on before
shutdown. The operator then shuts down the pad, the non-operational pumps are
repaired, and preventative maintenance is done on the other pumps. As soon as
18 to 20 pumps are ready, the frac job resumes.
Prior to the
job, Operator 2 required the surface system provider, wireline and pressure
pumper representatives, along with the field operators, to meet to fully
understand the automated surface system and how it operates. Expectations were set by Operator 2 that at
least 10 stages would be pumped each day, and continuous pumping would be done
on every stage possible.
stage-to-stage times to accurately judge the performance, the Operator 2 jobs
were compared to the previous 15k record in the Delaware basin, Fig. 15. In September 2021, the first job to continually pump for 24 hr was recorded
(with subsequent records set on the same pad at 35 hr), with the average S2S
time for the job at 10 min., continuously pumping 50% of the stages.
In the same
year, Operator 1’s Nimitz pad dropped the S2S average to 9.2 min. The average
S2S for Operator 2’s two pads was lowered to 5.4 min. and 3.3 min,
respectively, in December 2022, continuously pumping 70% of the stages. The 95%
confidence interval also tightened with the latest Operator 2 jobs, documenting
the consistency of the S2S. A job continuously pumped 24/7 would show 100% in
the upper left-hand corner of Fig. 12.
Both jobs pumped over 10.6 stages per day, with the El Duderino East
achieving 10.7 stages per day.
noted above, the first version of the automated pump swapping system was tested
in July 2022, with the test validating the coupling/decoupling sequences.
Lessons learned from the first iteration were applied to the second prototype
revised system was tested in late January 2022 on Operator 2’s Gutterballs
State 14-15 pad. The system under test utilized a missile automation skid
connected to the missile (automates the functionality of any missile) and two
automated pump swapping skids each connected to a frac pump on one side and the
missile on the other through the missile automation skid, Fig. 16.
frac pump was modified with a simple plate on the back of the truck mounted at
a set location. This plate contains two
subs for the pump’s high-pressure and low-pressure lines connected to the frac
pump, Fig. 18. Adapted to any
frac pump, this enables a frac pump of one manufacturer to be swapped with a
frac pump from a second manufacturer. With each pump backed into the skid, a
coupling sequence is run, securing the frac pump to the automated pump swapping
skid. The suction and discharge valves are then opened, allowing the frac crew
to run their normal pressure test routine on the initial rig-up, prior to the
start of the frac job. The coupled pump and automated pump swapping skid can be
seen in Fig. 17.
coupling and decoupling sequences were run with the pumps offline to verify the
coupling sequences. Automated pump swapping while continuing to frac was then
tested. This involved isolating the pump requiring repair, bleeding down the
pump, and decoupling while the remaining pumps continue to frac. The pumps were
then repaired outside the red zone, pulled back into the automated pump
swapping skid, coupled, primed, pressure-tested, and equalized (suction and
discharge lines are opened), bringing the pump back online while the remaining
pumps continued to pump. This was done four times, with each test more rigorous
than the prior test. Results of the four
tests are shown in Table 3.
two key lessons learned from the first iteration, making the system agnostic to
the pump and missile, and isolating the pump vibration, were successfully
integrated into the second version of the system. The system worked as intended
and is being integrated into the automated surface system. The new automated
pump swapping system is now in production and will be deployed as an integral
part of the automated surface system.
surface system, the Freedom Series Completion
System, has been developed to systematically eliminate the primary
barriers to fracturing the reservoir 24/7. With the integration of the frac and
wireline systems into the automated surface system, the system has successfully
pumped continuously for multiple days on multiple pads. The final hurdle to 24/7 fracturing was to
eliminate pump maintenance as a barrier. With the advent of automated pump
swapping, this barrier has been eliminated. The system is now in place to
achieve continuous 24/7 fracturing operations and with ongoing development, the
automated surface system is nearing Level 5 automation. WO
The authors would like to thank ProFrac for their help testing the second
iteration of the automated pump swapping system. Also, thanks go to Liberty
Energy and Steward Energy for their help testing the first iteration of the
system. This article contains excerpts
from SPE paper 213101-MS, “Automated completion surface system: The path to fracturing 24/7,” presented at the SPE Oklahoma City Oil and Gas
Symposium, held at the Oklahoma City Convention Center, April 17-19, 2023.
TIM MARVEL is V.P.
and technology at SEF Energy. Prior to joining SEF Energy, he served in a variety of domestic and
international executive roles at Baker Hughes, Alcoa and Dover. Mr.
Marvel graduated from Colorado School of
Mines with a BS degree in mechanical engineering
and is a licensed professional engineer in the state of Texas. He holds 21
patents and has co-authored nine
technical and trade journal articles.
AUSTIN JOHNSON is V.P. completions for Downing. Prior to
joining Downing, he served in a variety of operations and managerial
roles at Oil States and owned a business at the start of his career. He specializes in completion optimization and
his expertise has played a critical role in the development of automated
completion systems. Mr. Johnson holds multiple patents for automated completion
PHILLIP DOUGET is V.P. and general manager of the Permian basin
for Blue Ox Resources. Prior to Blue Ox, he served as manager of integrated service
planning and manager of midstream at Primexx.
In those roles he managed $1 billion of capital investments and oversaw
the buildout of the Primexx gas and water infrastructure in the Delaware basin. He began his career at Halliburton holding
various roles in drilling, completions and water management. Mr. Douget graduated with a BA degree from
Northwestern State University.
is V.P. of engineering for Blue Ox Resources. Prior to Blue Ox, he served as subsurface
engineering manager at Primexx. He began
his career with Halliburton holding various engineering roles ultimately ending
his time as a member of their technical team. Mr. Mast graduated from
Rose-Hulman Institute of Technology with a BS degree in chemical engineering.
JOHN DYER works
to develop automated equipment for completions at SEF Energy. He has also applied
his expertise in the areas of cardiac electrophysiology, aviation and
navigation and airborne weather radar. His main research interests are in
instrumentation and measurement, data acquisition and signal processing of
acquired data. Dr. Dyer holds a BS in physiology from Oklahoma State University,
in addition to BS and MS degrees and a PhD in electrical engineering from the
University of Oklahoma. He has taught junior and senior level classes in electrical
engineering and developed a graduate course in statistical digital signal processing.
is focused on designing the control system for the Freedom Series automated
completion system for SEF Energy. He started his career with the Colex Group,
designing and building automated end-of-line test systems for aerospace, defense
and energy companies. Mr. Kuehn received a BS degree in computer engineering
with a focus in digital signal processing in 2009 and a MS degree in electrical
and computer engineering in 2010, both from the University of Oklahoma. He
holds one patent.
BRIAN WIESNER is president of surface systems at SEF
Energy, which is comprised of the Downing brand. He joined SEF in 2015 after 20
years in various technical, management and international positions at Baker
Hughes, FMC Technologies and GE Oil & Gas. Mr. Wiesner holds a BS degree in
engineering from the Colorado School of Mines and an MBA from both Cornell University
and Queen’s University.