Tailoring Frac Fluids in Vaca Muerta

SPE-212571-MS
Tailoring the Frac Fluid's Paradigm in Vaca Muerta. A Complete Review from
Traditional Guar to New High Viscosity Friction Reducer Systems – Case
History
Juan Carlos Bonapace and Luis Atilio Riolfo, Total Austral; Fabio German Borgogno, WellKnows; Rodrigo Zrain,
Jorge Nicolás Santander, and Mohamed Lamine Moussi, Total Austral
Copyright 2023, Society of Petroleum Engineers DOI 10.2118/212571-MS
This paper was prepared for presentation at the SPE Argentina Exploration and Production of Unconventional Resources Symposium held in Buenos Aires, Argentina,
20–22 March 2023.
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
of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect
any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written
consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may
not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
Abstract
Developing unconventional reservoirs requires a continuous optimization process to increase well
productivity while reducing costs. Over the last years, the oil & gas industry has adopted a new fracturing
fluid system (High Viscosity Friction Reducer-HVFR) for regular hydraulic fracturing operations in shale
reservoirs around the world. In 2017, Total Austral performed the first trials in Argentina with this type of
fluids in 3 tight gas wells. With good results obtained in these tight wells, it was then decided to adopt this
fluid as the new basis to complete and stimulate all Vaca Muerta shale wells.
In an early stage, the classical guar-based fluid was replaced by a new emulsion base (liquid) HVFR
system as part of a hybrid pumping schedule. To validate this new fluid introduction, several laboratory tests
were carried out, including water analysis, hydration curves, dynamic rheology test and single particle fall
test. Field trials were then conducted, showing consistently promising results in different oil and gas wells.
Further in time, various improvements in the fluid formulation were introduced to comply with different
applications and objectives, for example: use of medium salinity waters; implementation of surfactants
booster to improve friction reduction/rheological aspects, and optimization of product dosification to
minimize costs.
Afterward a new stage was launched, replacing emulsion base HVFR additives by powder base HVFR
systems and applying a similar workflow for validation (lab test, field trials, friction calibration, well trials
and full implementation). By the end of 2019, the first stimulations with this new system were successfully
completed in Argentina. Finally, a new set of laboratory tests was carried out; these tests used an advanced
rheometer oscillatory-shear with parallel-plate and a friction loop to obtain a comprehensive rheological
understanding of the fluid (viscosity, elasticity, and friction profiles). Viscosity behaviors were assessed on
a wide range of shear rates and the influence of elasticity was examined over a range of frequencies.
The achievements and results obtained in the last five years have positively impacted our unconventional
developments from technical, logistic, economic, and environmental viewpoints. Among these, we can
mention booster application allowing to reach a faster and higher fracture rate in longer slim wells; fluid
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system adaptability to several fresh water sources applied in different fields; the optimization process
impacting on costs and material volumes without jeopardizing operations reliability even when using lower
additives concentrations, and powder system showing lower treatment pressure even in longer wells with
slim architecture. Another aspect worth highlighting is the reduction in enviromental impact brought about
by this optimization process, moving from guar system, through HVFR emulsion to HVFR powder, by
reducing location footprint, additives logistics and CO2 emissions and thus providing enhanced operational
simplicity and reliability.
This paper will cover the historical timeline and the work done to change, improve and optimize the
frac fluid used for hybrid pumping design in Vaca Muerta. It will also show a predetermined set of
laboratory tests, planed field trials, coordinated implementation, and progressive improvement obtained in
field operations.
Introduction
High-Viscosity Friction Reducers (HVFR) are PolyAcrylaMide-based (PAM) additives that in general
provide a greater reduction in pipe friction at lower chemical concentrations than linear guar gels. They
also comparatively improve proppant transport at higher proppant loadings during hydraulic fracturing
treatments.
In the last seven years, more than 50 technical papers have been published to cover HVFR systems
technical features such as: nature of chemistry, viscosity and elasticity, proppant transport, regain fracture
conductivity, laboratory tests, slot flow test, performance in high salinity water or surfactant addition
as performance booster. Another set of papers has covered some of their benefits like: cost reduction,
lower treating pressure (less hydraulic horsepower), footprint reduction, lessening in handling activities and
equipment utilized on site, simplified logistics and improvement in production. A good starting point to
review these main points can be found in Van Domelen, et. al, 2017; Hu, et. al., 2018 and Ba Geri, et. al,
2019.
The initial HVFR applications were reported in the Bakken (Motiee et al. 2016), from where it was
expanded to all the unconventional plays in USA, e.g., Utica (Chipola et al. 2018), Stack play (Dahlgren et
al. 2018), Marcellus (Johnson et al. 2018), EagleFord (Luster et al. 2019) and Permian (Zakhour et al. 2021).
Recently, a new set of works presented HVFR applications around the world: e.g., in Saudi Arabia (Kurdi et
al. 2020), Kazakhstan (Abdrazakov et al. 2020), China (Casero et al. 2021) and Oman (Sayapov et al. 2022).
From the early days in Vaca Muerta (exploration wells) hybrid designs (combining fluids of different
viscosity) have been executed for fracturing stimulation treatments, being Slickwater (SW), Linear Guar-gel
(LG) and Crosslinked Guar-gel (XL) the most used. In recent years, HVFR has been introduced in VM as
replacement for the most viscous portion of the treatments (Sentinelli et al. 2021; Arias et al. 2022). Figure
1 shows the evolution of the timeline of the fluid systems for the three main pumping service companies
operating in the Neuquén basin. In general, since 2018 the hybrid guar treatment has migrated to SW-
HVFR (with some operators still using guar systems in new appraisal fields). In 2021, a new evolution has
appeared, when the HVFR system has switch from emulsion-based additives to a powder additives system,
maintaining emulsion type as operational contingency.
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Figure 1—Fracturing fluid systems utilization timeline in Vaca Muerta for main Service Companies and Total Austral
HVFR fluid systems in Total Austral
Within the Argentina-Neuquén context explained in the previous section, this segment tells the history of
the HVFR fluid system applied by Total Austral in tight and shale reservoirs in its operated fields. During
the last five years, a solid learning curve has been developed showing many benefits in technical, logistic,
economic, and environmental aspects. The fluctuating local market conditions and availability of frac sets
have imposed the need to evaluate and work with different HVFR systems (Fig.2). This has forced the
application of a methodical workflow to validate and standardize results until full implementation in field
operations. This workflow includes lab testing, equipment yard revisions, planned trials in certain stages
and final results evaluation.
Figure 2—Total Austral HVFR system tested and implemented
Initial applications in tight gas wells
HVFR fluid was first applied in Argentina in 2017 in a horizontal well in a wellknown tight gas field in the
Neuquen basin (Schnaidler et al. 2013). For this first trial, an extensive set of lab tests was designed in order
to validate the new fluid system, i.e., rheology, fluid profiles, stability and break tests, and proppant settling
tests (see Fig.3). The fluid was pumped for the first time in the last 10 stages of well TG#1 using HVFR-A as
a direct replacement for the standard Lineal Gel (25ppt), which was the standard fluid for these operations.
Table 1 shows the history of HVFR-A implementation in TG wells and the main variables related to well
architecture, completion technique, proppant, and fracture design.
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Figure 3—Laboratory fluid tests and Hydraulic Fracture chart (for HVFR-A)
Table 1—Summmary information of first Tight Gas wells completed with HVFR-A system in Neuquén basin
Field trial and implementation in Vaca Muerta
Vaca Muerta development for Total Austral has focused mainly on Field A, extrapolating in general the same
well architecture and completion to other operated fields in Neuquén (fields B and C). This was essentially
Plug-and-perf completion in slim well architecture (4 ½" P110 - 15.1 lb/ft), stimulating with a hybrid fracture
design (SW-LG-XL), mainly due to final high proppant concentration (5ppg), at a fracture rate of 70bpm.
Endorsed by the good results in TG wells with HVFR-A, it was decided to replicate a similar field trial
in VM shale wells with this new fluid technology. The first one was carried out in 2017, completing the last
six stages of a PAD with HVFR-A as a direct replacement for the guar gel system (LG and XL). Results
were encouraging.
From 2018 to mid 2019, HVFR-A was successfully utilized in 22 wells (465 frac stages) in three different
fields. In all cases, the water used in the fluids was sourced from existing water wells in fields, characterized
by a low salinity content (< 5000mg/L TDS).
Table 2 summarizes the main information related to the well architecture and fracture design applied with
HVFR-A. All the wells shown in the table were completed in a 4 ½ slim architecture, presenting higher
pipe friction losses and hence limiting the pumping flow rates. The maximum allowed wellhead pressure
(MAX WHP) for the first 6 wells was 11,500psi (based on casing design architecture), impacting on the
frac rate design. After applying modifications to well construction, this value was upgraded to 12,500psi
for the following wells.
Table 2—Summary of completed wells in Vaca Muerta using HFRV-A system and main frac design parameters
Significantly lower WHP compared with guar system was observed in this architecture. Figure 4
compares WHP and average fracture rate using guar gels and different HVFR systems. A clear change in
WHP was observed in well group #1 (wells with a constraint of MAX WHP of 11,500psi) between wells
stimulated with guar systems (wells in red) and wells stimulated with HVFR-A (wells in green), when the
maximum fracture rate by designs was 60bpm for all cases.
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Group #2 (with higher Max WHP = 12,500psi) has a lower WHP than group #1 stimulated with guar
gels, even when increasing the fracture rate by 10 bpm to improve the limited entry design to 2.0 bpm/hole.
Figure 4—Wellhead Pressure and Fracture Rate along the drain for different groups of wells in Field A
Several lessons have been learned and benefits have been obtained during this implementation phase.
HVFR-A application has provided: (i) lower friction pressure, reflected in lower WHP, reducing risks
and greenhouse gas (GhG) emissions while protecting equipment from wear; (ii) good proppant transport
capacity, being able to place up to 4.5ppg of 30/70 white sand and 5.0ppg of 30/50 Light Weight Ceramic
(LWC) in the formation; (iii) improved operational efficiency and reliability; (iv) reduction in chemical
storage (decreased spill risk); (v) smaller equipment footprint on location; (vi) easier to implement on-the-
fly changes; (vii) a cleaner fluid with lower damage and (viii) 10%-15% cost reduction in fracturing fluid.
Water well with medium salinity level
At the beginning of 2019, two wells were scheduled to be completed in Field B, far from the normal
development in Field A. These wells presented diverse technical and logistical challenges such as: (i) longer
horizontal drain in a slim architecture (5650 MD), (ii) larger proppant intensity fracture designs with a final
proppant concetration of 4.5ppg LWC and (iii) the need to test and implement the HVFR-A system.
Given the water requirements for the job execution and the wells distance to the main water sources, it
was decided to use two water wells in Field B to fulfill the fracturing stimulation high volume water demand.
This implied the need to consider the use of water with medium salinity level (Table 3), considerably higher
salinity than that of the wells in Field A, where the HVFR-A was typically used.
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Table 3—Physical-chemical variables for sources of water used in different fields
Hazra et al 2019, studied and documented specific ions affecting the performance of HVFR fracturing
fluids. Calcium, magnesium, and iron were found to have the largest detrimental effect on viscosity of the
HVFR system. Magnesium and sulfate delay the hydration rate of the HVFR but do not affect the level of
friction reduction achieved.
Extensive lab testing (hydration curve and single particle fall rate test) was conducted to evaluate and
guarantee the fluid performance with water from Field B WW#2 (highlighted in red in Table 3). Initial
results showed a degradation of the viscosity of the system (in average 50% compared with WW#1 source
Field B). Many alternatives were tested: (i) water blend (dilution), (ii) higher HVFR-A concentration, and
(iii) the addition of specific surfactant.
The left side of Figure 5 shows the results of a set of lab tests performed using different proppants,
(WS and LWC), showing an increase in viscosity and a reduction in particle fall velocity when a specific
surfactant was added to the HVFR fracturing fluid. Encouraged by these results, this alternative formulation,
HVFR-A + specific surfactant, was used for the stimulation of these appraisal wells in Field B. During the
execution a strict quality control was held to ensure the fluid performance. The right side of Figure 5 shows
the values measured during operations.
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Figure 5—Laboratory test and field operation control (82 data points from 32 frac stages)
This control was also important to optimize surfactant and HVFR additives concentrations and reduce
the cost of chemicals. Some examples of this optimization process were: (i) removal of surfactant from the
fluid formulation at the end of treatment with LWC (executed in the last stages of the wells) and (ii) lower
HVFR-A concentration (7 to 8gpt), minimizing surfactant dosage (1gpt) while pumping WS.
In summary, 46 stages were successfully completed by using a combination of HVFR-A + surfactant
with no operational impact from the fluid performance perspective. This shows that it is possible to design
a tailored HVFR fluid for medium salinity water, even if there is still room for optimization towards a more
cost-effective solution.
Surfactant as friction reducer booster for longer slim well completion
In 2019, during the second development phase in Field A (Bonapace et al 2023), a new completion design
was implemented (longer slim wells with more stages and larger stimulation intensity). To achieve the design
fracture rate (especially at the stages at the toe of the wells), it was decided to evaluate if a surfactant (SURF)
could improve FR performance of the polyacrylamide base frac fluid, and in particular at the beginning of
the treatment (during the slickwater portion, with PAM concentrations below 1gpt).
Seymour et al 2018 explains how to improve the performance of freshwater friction reducers in brine
solutions through the addition of a surfactant blend. Properly selected surfactants can synergically increase
the performance of certain friction reducers in the presence of monovalent and divalent anions. At lab scale,
the author shows that a significant reduction in inversion time and increase in maximum friction is obtained
in all brines tested when specific surfactants are added together with friction reducer to the frac fluid.
Figure 6a shows the impact in WHP and fracture rate when adding the SURF to FR in the frac fluid
formulation during job execution. A clear gain in fracture rate was obtained whenever SURF was added as
a booster to the FR. With these initial results, in the following frac stages of the wells, sensitive tests were
performed to find the optimum relation of SURF: FR. The results obtained (Fig.6b) show that a minimum
concentration of SURF (0.5gpt, red bars) is necessary to achieve a considerable WHP reduction. Lower
SURF concentration than 0.5gpt provides too low impact in friction reduction, reflected in a smaller WHP
reduction. Then, already with a medium SURF concentration (0.8 to 1.0gpt, yellow and green bars), an
effect on WHP reduction is observed.
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Figure 6—(a) Field trial for surfactant booster application: lower WHP or higher rate
is achievable when adding FR+SURF together in the frac fluid (b) Wellhead pressure
variation for different SURF-FR (gpt: gpt) combinations at design fracturing rate (72bpm)
This FR-surfactant booster was applied in 4 wells at the toe sections (44 stages) during the pad step of the
fracture and the initial proppant steps (0.25 to 0.5ppg) group#3 HVFA-A in (Fig.4). The best performance
has been observed with the relation (FR: SURF = 1:1), allowing for lower wellhead pressure at the beginning
of the fracturing treatment, faster achieving the design fracture rate in longer slim wells to ensure limited
entry design (diversion 2.2 to 2.5bpm/hole) from the beginning of the treatments.
Optimization of HVFR (emulsion)
By mid 2019, and after a long tendering process, the frac service company was changed. Therefore, it was
necessary to reevaluate and understand the performance of the new proposed HVFRs. The first two wells
to be completed under this new service contract were executed with guar systems due to insufficient HVFR
stock but a field trial was scheduled for the final stages of these wells (4 stages). The objective was to
introduce and test the new HVFR system, similar to what had been done with the previous provider.
A set of lab tests was conducted with the new systems (HVFR-B and HVFR-C), looking to match HVFR-
A properties (viscosity and particle fall rate test) at different concentrations. Additionally, a new frac design
(with a lower maximum proppant concentration up to 3.5ppg of WS) was evaluated.
Figure 7 shows the lab results, where 4gpt (black dotted line) was considered as the benchmark for
evaluating and comparing HVFRs performance. Even when HVFR-C exhibited better results than the other
products, the use of HVRF-B was decided for the field trial and implementation due to availability and cost.
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Figure 7—Viscosity and Single Particle Fall Rate measurements performed for different types of HVFRs tested by Total Austral
A chemical optimization process was then carried out during completion of the first wells with HVFR-
B. A fast learning curve was developed during the first 20 stages, with a significant reduction in chemical
volumes (up to 68%), dramatically improving fluid costs. Following this optimization process, the standard
concentration adopted for regular operations was as stage #9 pumping scheme (highlighted on Fig.8). This
scheme did not jeopardize fluid performance during the operation.
Figure 8—Fluid optimization progression during the completion of the second PAD of wells with HVFR-B. Two
lines of improvement, increasing SW portion (red arrow) and decreasing HVFR concentration (yellow arrow)
HVFR-B was used in 8 wells with very good results during 2019 and 2020 (Table 4). This system allowed
to apply the new fracture design in longer slim wells, achieving the design fracture rate and improving
limited entry with lower chemical concentrations (lower cost and formation damage). Figure 4 group#3
shows comparative WHP and fracture rate trend along the stages of the wells for guar systems, HVFR-A
(with SURF booster) and HVFR-B optimized.
Table 4—Summary of completed wells using HFRV-B system and main frac design parameters
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The main achievements obtained by using HVFR-B have been: (i) an important chemical reduction
compared with HVFR-A, which entails a cleaner alternative with less logistics (ii) excellent operational
reliability, (iii) very good proppant transport (up to 3.5ppg 30/70 mesh WS with 1.5 gpt @ 5.5cp of
viscosity), and (iv) a reduction of 35% in fracture fluid costs (comparing HVFR-A to HVFR-B optimized).
New Powder System
The last step in this historical timeline was the transition from emulsion-based HVFR to HVFR powder
system. One of the main advantages of this new option is that more than 90% is active PAM compared
with typical water-in-oil emulsion containing only 30%. Sander 2016 and Blevins 2021 described several
benefits achieved with this new dry system such as: (i) reduction in material cost, (ii) eliminate mineral
oils used in emulsion (HSE risk - spill and safety), (iii) operational simplicity (dosage adjustment) and (iv)
superior performance in pipe friction (up to 1,200psi less) compared to liquid systems.
Three types of dry HVFR (D, E and F) have been tested and used during recent years in Field A. Table
5 shows the main completion and stimulation variables, and total wells completed with these systems.
Table 5—Summary of completed wells using HFRV-E and HVFR-F systems and main frac design parameters
The first field trial was performed by the end of 2019 (slim well architecture), using HVFR-D (Fig.7) in
only eight stages, six of them using the additive as FR in SW portion of the treatment and the remaining
two as fluid package FR-HVFR. This experience was the first job executed with this powder HVRF in Vaca
Muerta and the first worldwide application of this particular dry PAM additive as HVFR fluid system.
In 2021 the well architecture was changed to 5" P110 - 21.4 lb/ft casing, unlocking longer horizontal
drains (3000m). Also, changes to the completion and fracture stimulation design were introduced: (i) more
aggressive limited entry design with fewer holes and (ii) lower final max proppant concentration decreased
to 2.5ppg. Hence, it was necessary to improve fluid performance, mainly in terms of friction reduction.
A new dry HVFR-E system was therefore introduced following a similar workflow to that previously
followed with emulsion HVFR introductions for product validation and additives dosage calibration. First,
lab testing was conducted in order to try to match the profile (viscosity and particle fall rate test) of HVFR-
B "optimized" with dry HVFR-E. Figure 7 shows the results, where 2.5gpt (red dashed line) represents
the baseline to evaluate and compare powder PAM with previously used HVFR-B. The 8ppt concentration
matched the HVFR-B optimized viscosity but provided a better value in single particle velocity (yellow
area).
During the 2021 field trial using HVFR-E, it was necessary to increase chemical dosage up to 14ppt
due the high and erratic WHP reading during the operations where screenout tendency was suspected.
Additionally, to calculate the actual friction pressure of the fluid, a set of calibration tests (12 per well)
distributed through the entire drain of the well was conducted during the pad step of the fracture (to
remove the effect of the proppant from the analysis). The results of these tests are shown in Figure 9. This
information was useful in the following wells to estimate expected WHP during the first stages (longer
drain) considering the new limited entry design.
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Figure 9—Fluid friction estimation for HVFR-E obtained during 2nd field trial in two wells. Tests
performed at different concentrations (3 and 4ppt) and fracture rate 60-70-80 bpm in 24 stages
A total of 12 wells were completed with HFVR-E using both water wells and river water as water sources
(only in the last two wells river water was used). Depending on the type of water, differences in viscosity
and particle fall velocity (Fig.7 - blue dots vs crosses) were already detected in pre-job laboratory tests.
Figure 10 shows results from fluid QA/QC during operations for two wells in which different water sources
were used. A significant variation in viscosity values were measured between 2 to 5cp; more viscosity is
obtained with river water for a fixed additive concentration. This implied the possibility of reducing the
concentration of HVFR-E in 2ppt when using river water, impacting on the chemical cost for these stages.
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Figure 10—Quality control for fluid viscosity during operation for different sources of water when using HVFR-E
With the good performance of HVFR-E in friction reduction, design frac pumping rates of 80bpm were
normally achieved from the beginning of the treatments, even at the initial stages (toe section) of wells
with 3250m of lateral drain (Fig.4 group #4, blue curves). Additionally, a more aggressive limited entry
design (diversion 3.3 bpm/hole) could be executed in these wells. Also, the chemical dosage was optimized
(Fig.11), reducing the material consumption by 33% when comparing between toe and heel stages.
Figure 11—Optimization perfomed, decrease FR concentration (yellow arrow), decrease HVFR concentration (red arrow)
In other wells, it was not possible to maintain this chemicals optimization due the WHP behavior observed
in several stages during the last portion of the treatments (1.75 to 2.5ppg). This forced the introduction of
on-the-fly changes (increase HVFR concentrations) and the cost reduction objective was not met (Fig.12
see HVFR-E treatment).
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Figure 12—Comparative WHP and fracture rate behavior for HVFR-E and HVFR-F
Finally, the last 2 wells considered in this paper were completed using a new third-party service company
and powder HVFR-F. Several observations were gathered during completion, such as: (i) a delay to achieve
the designed fracture rate (possibly associated with the fluid friction of the system), (ii) a decreasing WHP
tendency in the last part of the treatment (see HVFR-F treatment Fig.12), (iii) important optimization
process, reducing up to 69% of chemical material (Fig.13).
Figure 13—Fluid optimization developed in SW and HVFR during completion of wells with HVFR-F
The main benefits obtained from the use and implementation of a dry HVFR system can be summarized
as: (i) significant lower WHP (1,500 to 2,000psi below MAX WHP) due to excellent pipe friction reduction
performance, (ii) higher rate achieved, allowing for the improvement of limited entry design even for longer
laterals, (iii) reduction in footprint due to fewer chemicals used and transported to the well, (iv) lower fuel
consumption (approximately 40,000 lt less of diesel per well just considering the WHP reduction provided
by the system) representing 43.2 ton fewer CO2 emissions, and (v) a reduction of 8% in fracture fluid costs
(comparing HVFR-B optimized to HVFR-F optimized).
Laboratory testing - Fluid performance understanding
During 2022, it was decided to conduct a set of lab tests using an advanced rheometer with parallel-plate
system (Anton Paar USD 200 – MC200). The objectives were to evaluate the performance of different
HVFRs make a comparison with operational results and complement from a fluid performance standpoint
the changes introduced along these years. The testing considered the HVFR fluids implemented in our fields,
but it is important to mention that it was not possible to evaluate HVFR-A (first step of this 2017-2019
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timeline) due to lack of a sample. A total of 40 test were performed for 3 PAM systems (B, E and F) at
different concentrations (0.5, 1, 1.5, 2, 3, 4, 6, 8gpt and 4, 6, 8, 10, 12, 14ppt) and types of water sources
(river and water wells).
The reference for comparison of the fluids is the HVFR-B optimized formulation. The following section
will describe these steps: (i) understand HVFR-B optimization, (ii) substitution from HVFR-B optimized
to HVFR-E (dry), (iii) water sources (river-water well) impact on HVFR-E and (iv) replacement HVFR-
E for HVFR-F and optimization.
Laboratory tests
To perform every test in the same conditions, the first step was to reach an agreement on sample preparation
and rheometer setup. In both cases, in the absence of standards, hydration was defined by field operation
conditions and rehlogical testing was in accordance with state-of-the-art testing conditions commonly
accepted by the industry.
Sample preparation was performed by HVFR hydration using variable speed mixer Grace Instruments
M3080 with a Warring Blender Jar, in 250mL water sample at room-controlled temperature and 2,000rpm
@ 2min., and then @ 1min. relaxation time. Rheological test was performed with an oscillatory rheometer
Anton Paar USD 200 – MC200, configured with cone-plate geometry, using a 75mm cone with an angle of
1°. The set of testing sequences and conditions was: (i) Flow Curve (FC): 0,1-5000/s ramp, (ii) amplitude
sweep (AS): 0,1-100% strain ramp @ 10/s angular frequency, (iii) frequency sweep (FS): 0,1 to 100/s
angular frequency ramp @ 2% amplitude.
This set of testing sequences was stablished to generate a database that allowed us to get a better
understanding of fluid behavior related to different HVFR, different water and operation conditions (Hu,
et. al., 2015 and Ba Geri, et. al, 2019). Each type of test provided the following data:
i. Flow Curve (FC): behavior of dynamic fluid viscosity under rotational conditions, that shows the
fluid viscosity at different share rates. High shear conditions can be linked to the fluid behavior
while traveling through the pipe, its friction and resistance to the shear. Measures at low to very
low shear rates, is possible to analyze the potential capabilities for proppant transport, and effects
like tortuosity. But this test provided just partial information without the viscoelastic information
provided by the AS, FS and Friction Loop.
ii. Amplitude Sweep (AS): behavior of fluid under deformation at constant speed, that shows the
polymer viscoelastic properties (LVE regions). This test is related to the response at stress, for
example, what is the behavior of the polymer chain if it is stretched at constant speed, in other words,
what is the response to the buoyancy effect to delay the settling of a particle.
iii. Frequency Sweep (FS): behavior of fluid under variable deformation speed at constant strain, which
shows the polymer viscoelastic properties (LVE regions). This test is related to the response at the
speed that the stress is applied at, for example, what is the behavior of the polymer chain if it is
stretched at different speeds, in other words what is the response of the properties under higher flow
rates or the effect when crossing perforations.
AS & FS provide a lot of variables to analyze, but we focus on Storage Modulus (G’) related to elasticity
or potential energy (understood as capacitor behavior) and Loss or Viscous Modulus (G’’) related to
viscosity or kinetic energy (understood as resistor behavior). G’ is related to proppant transport capacity,
the higher the G’ is the better the proppant suspension properties. G’’ is related to viscosity (friction), the
higher the G’’ the more energy is necessary to pump the fluid. Fluids are considered VES (Viscoelastic)
when G’>G’’, while the higher is G’ against G’’ the better expected transport properties during pumping.
This comparison between G’ and G’’ helps to understand how a HVFR is affected by different waters, or
to compare between different HVFR expected performance.
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SPE-212571-MS 15
In the absence of standards, consensus or expected values, the comparison between lab results for
different polymers and waters with post-job field results becomes almost mandatory for field operations
improvement.
Fluid performance evaluation
Figure 14 sketches the typical shear rate sequence for a fracturing fluid and how it can be observed in a flow
curve chart. We will evaluate mainly the lower shear rate (proppant transport) and high shear rate portion
(friction properties). A second set of tests in a friction loop currently is in progress to complement fluid
friction evaluation.
Figure 14—Fracture fluid shear reate history
(i)-HVFR-B optimization, in this case the following chemical concentrations were evaluated, tested and
used during the optimization process: 1.5, 2.0, 3.0 and 4.0gpt (Fig.8). Flow curve and amplitude sweep chart
shows the behavior of this system using water well as sources of water (Fig.15)
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16 SPE-212571-MS
Figure 15—(a) flow curve and (b) amplitude sweep for HVFR-B optimized
Results: as expected, a good performance at high shear rate was observed for lower concentration 1.5pgpt
(Fig.15a). In terms of proppant capacity (Fig-15b). we identified different G' values for several dosages
successfully pumped. As previously mentioned, this is the initial step (reference), but it was understood
the viscoelastic properties required for the fracture fluid according to the actual design applied (Max Prop
3.5ppg WS).
(ii)-Substitution of HVFR-B (emulsion) optimized for HVFR-E (dry), in this case the objective was to
identify the dry concentration to match the viscoelastic properties of optimized emulsion (2.0gpt) and define
a proper concentration. Flow curve and amplitude sweep chart shows the behavior of these systems using
water wells.
Figure 16—(a) flow curve and (b) amplitude sweep for HVFR-B optimized and HVFR-E
Results: a better performance at high shear rate (potentially less friction) has been observed for HVFR-
E comparing HVFR-B (Fig.16a). Viscoelastic properties (Fig-16b, red and green family curve, G'-G")
show a better match with 8ppt HVFR-E; this means that for 1 gallon of emulsion 4 pounds of powder are
needed to have the same behavior. Review and evaluation: there is a good correspondence between lab
tests and historical operational performance in terms of less WHP (better fluid friction) and the maximum
concentration applied in some wells (8ppt optimized schedule, Fig.11) using dry PAM.
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SPE-212571-MS 17
(iii)-Water sources impact on HVFR-E, in this case, we evaluated how the powder system can be affected
according to different sources of water used. Flow curve and amplitude sweep chart shows the behavior
of this HVFR at 8ppt.
Results: no significant change was observed at high shear rate (pipe friction) due the type of water used
(Fig.17a). Viscoelastic properties (Fig-17b) show a detriment (red arrow) for the same concentration when
using water well sources. To compensate for this situation, when water well sources are used, it is necessary
to increase 2ppt (yellow arrow) to obtain the same level as river water. Review and evaluation: there is a
good correlation between lab tests and historical operational information related to the loss of viscosity with
water well sources (Fig.10). Pre-job lab tests performed (Fig-7, dots vs crosses), showed a clear difference
(single particle fall rate) depending on the water type, which matches with loss of viscoelastic properties
observed.
Figure 17—(a) flow curve and (b) amplitude sweep for HVFR-E considering different sources of water (water well and river)
(iv)- Replacement of HVFR-E for HVFR-F and optimization, in this case, we comparatively evaluated
the two dry PAM at two contrasted concentrations with the intention to understand behaviors and possible
concentration limits to be used. Flow curve and amplitude sweep chart shows results for 6 and 12ppt using
river water.
Results: a difference was observed at high shear rate in both concentrations, showing a better performance
for HVFR-E than HVFR-F (Fig.18a), this initial observation will be complemented with future friction loop
test results. Viscoelastic properties (Fig-18b) presented differences (high values, yellow arrow, and more
amplitude between G'and G") for HVFR-F than HVFR-E; this was more notorious at high concentrations.
Review and evaluation: there is a good correlation between lab tests and historical operational observations,
two of which were mainly identified: I) Unlike HFVR-F, HVFR-E showed an excellent fluid friction
reduction, reaching the fracture rate design very fast (Fig. 12), and II) the optimization (lower concentration
used) with HVFR-E was 8ppt while with HVFR-F was 6ppt, this is in line with the better viscoelastic
properties observed for this system (Fig.18b)
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18 SPE-212571-MS
Figure 18—(a) flow curve and (b) amplitude sweep comparative for HVFR-E and HVFR-F using river water
Conclusions
Over these years (2017 to 2022) Total Austral has pioneered testing, introducing and implementing different
HVFRs (emulsion and powder systems). This allows to build a strong and consistent learning curve. The
key points are listed as follows:
• A methodological workflow was applied to assess each type of HVFR, to validate and standardize
results, until full implementation in field operations. This approach helps to develop tailor-made
solutions (e.g,, surfactant booster and HVFR formulation for medium salinity water).
• The field test and full implementation of new powder HVFR in Vaca Muerta formation allowed
Total Austral to save more than 65% compared with the initial frac fluid cost (guar systems).
• HVFR contributed to an important footprint reduction due to fewer products on location and lower
fuel consumption (less Hydraulic Horsepower used) and its associated GhG emissions.
• Operational benefits as low MAX WHP along the jobs (reduced pump time maintenance) and the
fluid simplicity (single chemical) boosted operational efficiency
• Advanced laboratory tests have been useful to get a better understanding of the latest results and
the pros and cons of different HVFRs available. Laboratory results have helped Total Austral to
select and continue optimizing products for future developments.
Acknowledgments
We would like to thank TOTAL Austral's management for the continuous support along this project and all
the stakeholders involved in unconventional projects in Argentina. Special thanks are extended to Youssouf
Zotskine, Jose Luis Morales (Calfrac Well Services) and Federico Cafardi (Schlumberger) for the support
provided.
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