SPE WVS-593.

Vertical Wells Completion in
Multilayer Reservoirs.
A Decade of Technologies
Implemented in Argentina
SPE-WVPS-593
J.C. Bonapace & G. Perazzo
Halliburton

Abstract
Many fields in Argentina have multilayer reservoirs that require various stimulation techniques, mainly
hydraulic fracturing. A variety of formations and types of reservoirs, such as conventional (mature fields)
and unconventional (tight gas and shale), are present in the Golfo San Jorge and Neuquen basin. The
hydraulic fractures created in these basins present a variety of conditions and challenges related to depth,
well architecture design, bottomhole temperature (BHT), reservoir pressure, and formation permeability.
In the last decade, new technologies were introduced and developed to help achieve greater efficiency and
reduce time and costs associated with completions for these fields. This paper presents experiences
gained using two types of technologies.
First, a new conventional straddle-packer system (SPS) was used in conjunction with a workover unit,
which was part of a technological collaboration agreement between an operator and service company. It
was mainly applied in conventional reservoirs, mature fields, in wells with up to seven fracture stages, and
in new or recompletion wells. Second, a pinpoint technique was used, called hydrajet perforating annular-
path treatment placement and proppant plugs for diversion (HPAP-PPD). This technique was applied in
new wells (rigless completion) and all types of reservoirs, both conventional and unconventional (tight gas
and shale), and allowed performing up to 30 separate fracture stages in a single well, with three stages
completed in a 12-hr operation.
These completion methods allowed operators to focus treatments in desired zones with specific treatment
designs based on reservoir characteristics. Several case histories are presented for different basins,
formations, and reservoirs types, as well as lessons learned and completion time reductions.

Introduction
Hydraulic fracturing is one of the most-widely used stimulation techniques. First application of this
stimulation technique dates back to October 31, 1960 in Argentina. Since then, this type of treatment has
been performed in five producing basins in the country (Fig. 1).
Throughout the years, constant changes have been made to treatment fluid systems used in these
operations, moving from petroleum-based fluids, methanol, CO2 and nitrogen foams, nitrogen-assisted and
water-based systems.
These types of stimulation treatments have a variety of requirements for use
in this productive basin, which presents a wide range:
• Depths: 300 to 4500 m
• BHTs: 100 to 350°F
• Reservoir Pressures (subnormal to overpressured)
• Permeabilities (high, medium, low, and ultralow)
• Types of complex formations, also different types of reservoir problems
(proppant flowback, production of high levels of water).
• Reservois as monolayer or multilayer
• Wells types as multitarget
This paper documents the experiences, lessons learned, and results achieved with two new completion
systems used in the last decade in Argentina for oil or gas reservoirs in mature fields and tight formations in
the Golfo San Jorge and Neuquen basin.
Fig. 1—Argentina production basin.

Straddle-Packer System (SPS)
Golfo San Jorge Basin—Operator A. This completion system was developed because the operator
needed to improve completion times of its wells. A SPS was developed to test the reservoir before a
stimulation treatment (multireservoir layer) that also could be used later for hydraulic fracturing operations.
Thus, a significant reduction in required operation hours could be achieved compared with traditional
systems used for the plug-and-packer method. Greater detail on the scope of the project, descriptions of
the tool, and the operating sequence are provided by Velasquez et al. (2009).
•The standard well geometry for this operator consisted of vertical wells with 5 1/2-in. casing, K-55, 15.5 lb/ft using 2
7/8-in. tubing, J-55, 6.5 lb/ft for completion activities.
•The best progress in this project was achieved when using the tool for fracturing execution. Initial analysis showed
that an average of 15 hr was required to complete the full cycle of performing hydraulic fracturing using the plug-and-
packer methodology.
Once development of the tool was completed, a field test period was initiated consisting of three
progressive stages (2007–2009). During this period, some modifications and adjustment were made to
the tool. The field tests consisted of 55 stages of fracturing performed in 13 wells using different packer
spacing (8 to 30 m) and different types of proppants (RCP and white sand) (Arze et al. 2010).

Implementation Phase. Implementation of this tool as part of completion activities for this operator
began in mid-2009 to late 2013. In late 2009, a comparative analysis was made to evaluate the tool
performance and the new completion methodology.
As part of the evaluation process, five fields were selected in which wells were completed using a
traditional plug-and-packer system in a total of seven wells. In addition, nine wells were completed using
the new SPS completion system. Wells using both applications should meet the following conditions: have
the same number of stages or a minimum difference and be completed almost simultaneously to avoid
delays caused by climatic variables or weather conditions, as wind and/or snow are typical of the area
where the wells exist.
In Fig. 2, the wells are grouped by field (Field A to E). The
bars show the number of fracturing stages performed by well
(left axis), where the black color indicates traditional plug-and-
packer completions while red illustrates the new SPS
completion system.
The marked points referenced in the right axis show the
average time (hours) required per fracturing stage, where blue
marks indicate plug-and-packer completions and red marks
reference SPS completions. It can clearly be observed that an
average of 10 to 16 hr per fracturing stage was required for
the traditional completions, whereas the new methodology
required between 4 and 8 hr.
This reduction in time for each fracturing stage represents an average decrease on the
order of 40 to 63%.
Fig. 2—Wells grouped by field.

A summary of the historical development of using this completion methodology, from the field test phase to
implementation to its current use in well completion operations.
Throughout the current year, 93 wells have been completed for this operator using this methodology,
performing a total of 366 fracturing.
Several characteristics about the stimulations treatments and completions are presented in Fig. 3 and Fig.
4:
• Historical Evolution
• Number Stages per well
• Frac Stages size (proppant lbm)
• Maximun proppant concentracion pumped (lbm/gal)
• Number of zone treated by Frac Stage
• Spacing between packers
• Distance between successive Stimulations
• Type of proppant pumped
Fig. 3—(a) Historical evolution; (b) fracturing stages per well;
(c) fracture size; (d) maximum proppant concentration.
Fig. 4—(a) Number of stimulated zones per fracturing stage;
(b) packer spacing; (c) spacing between successive fractures;

A summary per year from 2009 to 2013 is presented in Table 1, which details the operating performance.
The main variables of each well, including operation times achieved, are shown.
Year 2009 2010 2011 2012 2013
Basin Golfo San Jorge Golfo San Jorge Golfo San Jorge Golfo San Jorge Golfo San Jorge
Formation
Mina El Carmen
Comodoro
Rivadavia
Mina El Carmen
Comodoro
Rivadavia
Mina El Carmen
Comodoro
Rivadavia
Comodoro
Rivadavia
Mina El Carmen
Comodoro
Rivadavia
Reservoir Type Sandstone - oil Sandstone - oil Sandstone – oil Sandstone - oil Sandstone – oil
Stages per Well 5 5 5 4 7
Depth (m) 2300.0 to 2072.5 2790.0 to 1716.5 2528.5 to 2035.0 1212.5 to 1042.5 2346 to 1726
Packer Spacing (m) 25.6 21.7 24.8 31.5 31.6 and 25.4
Injection Test – Diagnostic Fracture
Injection Test (DFIT)
No No Yes Yes Yes
Fluid Volume Stage (gal) 6,400 to 10,600 8,200 to 10,700 8,000 to 22,600 9,100 to 16,100 6,900 to 13,000
Amount of Proppant Stage (lbm) 7,500 to 20,600 16,300 to 25,800 18,900 to 60,400 16,100 to 46,600 13,400 to 33,300
Total Fluid Pumped (psi) 36,590 48,740 70,850 44,350 76,120
Total Amount of Proppant (lbm) 70,100 107,300 179,100 118,900 185,500
Type of Proppant RCP RCP RCP RCP RCP
Proppant Mesh 20/40 20/40 20/40 12/20 20/40
Max Prop Concen (lbm/gal) 6 to 7 7 to 8 7 to 8.2 6 to 8.2 6 to 8
Slurry Rate (bbl/min) 15 to 16 14 to 14.5 15.4 to 16 13.5 to 14.8 14 to 16
Wellhead Pressure (psi) 3,150 to 2,950 3,420 to 2,640 4,100 to 3,100 2,570 to 2,200 4,040 to 3,110
Fracture Gradient (psi/ft) 0.55 to 0.63 0.66 to 0.69 0.62 to 0.69 0.66 to 0.69 0.60 to 0.70
Well Control after Fracturing Forced closure Forced closure Forced closure Forced closure Forced closure
Screenout No (1) - Third stage No (1) - Third stage No
Comments —
After fourth
stage, rest crew 4
1/2 hr
DFIT: 60 min for
pressure decline
and analysis
DFIT: 45 min for
pressure decline
and analysis
DFIT: 30 min for
pressure decline
and analysis
After fourth
stage, change
spacing tool [pull
out of hole
(POOH) and run
in hole (RIH)] 12
hr
Fracturing Time per Stage (hr:min) 24:30 18:55 32:00 24:45 33:30
Time (min/stage) 294 227 384 371 287
Time (hr/stage) 5 3 3/4 6 2/4 6 1/4 4 3/4
(Table -1)

Hydrajet Perforating Annular-Path
Treatment Placement and Proppant Plug
for Diversion (HPAP-PPD)
This completion technique, referred to as pinpoint stimulation, was introduced in the industry in 2004
(Surjaatmadja et al. 2005) in vertical wells initially and was quickly applied in horizontal wells (McDaniel et
al. 2006). It consists of abrasive perforation through coiled tubing (CT) and subsequent fracturing
treatment pumping through the annulus between the CT and casing, resulting in a fracturing stage with a
sand plug for zonal isolation.
In Argentina, it was introduced in 2006 in the Golfo San Jorge and Neuquen basins for conventional and
unconventional reservoirs. This completion technique has been successfully applied in a wide variety of
formations, such as Mina el Carmen, and Comodoro Rivadavia in the Golfo San Jorge basin and Molles,
Lajas, Punta Rosada, Tordillo, Quintuco, Precuyo, and Vaca Muerta in the Neuquen basin. To date, 37
wells have been completed with a total of 336 fracturing stages for six different operators. Fig. 6, Fig.7
shows the distribution of wells completed with this technique in terms of basins, operators, types of
reservoir, and well geometry.
Fig. 6—(a) Wells completed by basin; (b) wells completed by
operator; (c) wells completed by reservoir type; (d) wells
Fig. 7—(a) Conventional gas well completion; (b) conventional
oilwell completion; (c) tight gas well completion; (d) shale oilwell

Neuquen Basin—Operator B. The HPAP-PPD technique has been used by this operating company
since 2007 in a total of 13 wells (124 fracturing stages), mostly in conventional gas wells.
A multitarget well for this operator was evaluated and developed without using standard completion
techniques. Over the years, the operator included new reservoirs to be stimulated, thereby generating
multitarget wells. Usually, the following zones are considered for stimulation: Quintuco and Lajas (oil and
gas producers), and the upper section of Los Molles (dry gas producer). Los Molles formation is exclusively
a dry gas producer, where its basal section is a reservoir with very low permeability (tight gas) and is highly
sensitive to damage during well construction. As such, the basal section can experience damage during
completion operations into the upper reservoirs, so the completion strategy used is important.
The operator proposed the goal of completing all zones in the wells—Los Molles (tight and conventional),
Lajas, and Quintuco. These zones would be stimulated selectively, allowing the application of the new
technique.
A total of 30 fracturing stages were selected to be performed:
a) basal Los Molles formation—tight: eight fracturing stages (F1 to F8);
b) middle-upper Molles formation: 10 fracturing stages (F9 to F18);
c) Lajas formation: five fracturing stages (F 19 to F23);
d) Quintuco formation: seven fracturing stages (F24 to F30).
The completion strategy consisted of performing well operations in three phases, corresponding to each of
the formations being stimulated. Based on this, once operations for each formation were completed, a
wellbore cleanout and mechanical plug setting operation was conducted using a wireline unit. Afterward,
the same strategy and procedure was followed as for the previous formations.

Fig. 8—(a) Fracture gradient; (b) total proppant in formation.
Los Molles Basal (Tight). High fracture gradients greater than initially assumed values (> 0.8 psi/ft) were
observed (Fig. 8a). This led to changing the fracturing treatment to include an increased pumping rate based on the
completion technique. Also, modifications to the proppant mesh size were required, changing from 16/30-mesh to
20/40-mesh for fracturing Stages 4 to 18. Three screenouts were observed (Fig. 8b) in this section of the well (Stages
1, 3, and 7), and it was not possible to perform stimulation treatments for Stages 5 and 8 because of high pressures.
Los Molles. Fracture gradients measured were according to expected values; 0.7 to 0.8 psi/ft for fracturing Stages
9 to 15. Moreover, screenouts were observed in the last stages, and only 60% of the total proppant mass was pumped
into formation (20/40-mesh proppant was used) (Fig. 8b). Similarly, Stage 16 was not stimulated because of high
pressures. After completing the first 18 fracturing stages in the formation, the well was cleaned and a wireline plug
was set at 2575 m to isolate the first section of the well.
Lajas. Fracture gradients measured were much lower than previous wells. All treatments were successful, but
because of the rapid pressure decline observed, modifications to the pad percentage were considered.
The proppant agent used was 16/30-mesh, as
designed. Once the five fracturing stages were
completed, a cleanout phase was performed. Finally, a
mechanical plug was set at 2210 m to isolate the
second section of the well.

Quintuco. Fracture gradients observed were
according to values measured in offset wells. Because
of experience in the area, the fracturing design used a
20/40-mesh proppant agent, and treatments were
conducted successfully. Once the seven fracturing
stages planned in this formation were completed, a
wellbore cleanout operation was performed.

Fig. 9—Completion times (those shown in black were aborted).
Summary. A total of 30 days was required to perform treatments in these formations (Fig. 9):
•Rigup and rigdown: 4 days
•Wellbore cleanout and mechanical plug millout: 7 days (five days for Los Molles and two days for Lajas)
•Nonworking days ( holidays): 2 days (Christmas)
•Fracturing operations: 16 days (10 days for Los Molles, three days for Lajas, and three days for Quintuco)
It is important to clarify that a unit time of “day” corresponds to operative day of 12 hr. The times achieved
showed that for the basal Los Molles formation, one stage per day could be performed, and in some cases,
two stages per day. Two stages per day were achieved in Los Molles, and three stages per day were
conducted in Lajas and Quintuco.

Neuquen Basin—Operator C. This completion technique was introduced for Operator C in 2008. To
date, nine tight gas wells and 84 separate fracturing stages have been completed using the pinpoint
technique (Fig. 7c).
The zones stimulated for this operator are the Lajas and Punta Rosada formations. Both have common
characteristics, such as low permeability, in the range of 0.01 to 0.001 md, and overpressured zones,
which have a pore pressure gradient from 0.65 to 0.70 psi/ft. Nevertheless, their thickness and distribution
are different. Lajas has a hydrocarbon thickness on the order of 20 to 45 m, while Punta Rosada is more
likely composed of lenticular sands being close to one other with a thickness of 2 to 10 m.
Barbalace et al. (2012) document the completion performed by this operator, which has been called a
hybrid completion because the stimulation treatments of the formations (Lajas and Punta Rosada) used
both plug-and-perf and pinpoint techniques.
In the Punta Rosada formation, a well was completed that required 16 fracturing stages. The completion
program included a BHA modification for Stages 10 and 11. In addition, a pumping diagnostic test was
planned to obtain information about excessive friction pressure in the fractures, perforating and near
wellbore friction, fracture gradients, and estimated closure stress. This type of injection added one
additional hour to each fracturing stage, except for the first stage in which an extended pressure decline
period for 12 hr was managed.

Fig. 10a shows the fracture gradient values observed during these tests. All zones clearly show values
above 0.80 psi/ft, including some cases with values higher than 0.90 psi/ft. Fig. 10b indicates the amount of
proppant agent placed into the formation. Treatment proppant volumes varied from 30,000 to 155,000 lbm.
A unique screenout occurred in fracturing Stage 8, allowing only 92% of the total treatment to be pumped
into the formation.
Stage 8 presented higher operative complexity, which caused delays in the completion times. Once
fracturing Stage 7 was complete, operations moved to the next zone, performing an abrasive perforation
and later a calibration injection test. Higher friction values were observed in the NWB region. To mitigate
this elevated friction pressure, a proppant sand slug was placed into the treatment. Once this proppant slug
reached the perforations, a sudden screenout occurred. The operator decided to perform wellbore cleanout
using CT, and an insubstantial reservoir admission was observed, reaching the maximum working pressure
allowable in the system.
Fig. 10—(a) Fracture gradient; (b) total proppant placed in formation.
A 15% hydrochloric (HCl) acid system was
pumped through the CT, with no indication of
improvement. CT was POOH to determine
the BHA condition; a new one was installed,
and CT was RIH again to perform a new
abrasive perforation, which allowed pumping
a treatment until screenout occurred at the
end of the flush.

Summary. The well completion time required using this technique was consistent with that documented by
Barbalace et al. (2012). To perform a total of 16 fracturing stages, eight days were required (Fig. 11):
•Rigup and rigdown: 4 days
•Wellbore cleanout: 1 day
•Fracturing operations: 7 days
•Changes in BHA and reservoir conditions: 1 day

Approximately three fracturing stages per day were possible in the Punta Rosada formation.
Fig. 11—Completion times for Operator C.

Conclusions
SPS was developed, field-tested, and used in well stimulation stages, achieving a significant reduction in
execution times for hydraulic fracturing and well completion operations.
•Time required to perform a complete fracturing cycle (pumping diagnosis - fracturing - forced closure – tool release - sand washing -
moving and positioning to the next zone) was reduced to 3 3/4 to 6 1/4 hr.
•A time reduction of 40 to 63% for performing all fracturing processes in a well was achieved using this system compared to traditional
plug-and-packer systems.
•An 18% reduction in hours required for workover equipment was documented, allowing use of such equipment in other operations.
•Good preplanning involving the workover company (equipment and personnel), service company (tool, fracturing set, and personnel), and
operating company (logistic and supervising) helps minimize NPT.

HPAP-PPD has been evaluated in a wide variety of formations and reservoir tests, proving its versatility.
It helps achieve significant reductions in completion time, optimizing costs and resulting higher returns on
projects.
•In conventional gas reservoirs, completion time to perform hydraulic fracturing was reduced from 40 to 50%.
•It is possible to complete up to three fracturing stages in a period 9 1/4 to 13 3/4 hr.
•It allows selectively targeting zones for stimulation, which reduces the residence time of the fracturing fluid in the formation, thereby
helping to minimize damage, and offers improvements in production compared to wells completed using other techniques.
•Proper logistics preplanning is required to minimize NPT, which can negatively impact the economics of the well.

Acknowledgements
The authors thank Halliburton for permission to publish this work and all staff of the Production
Enhancement and Production Solutions PSL for their efforts over the years to implement these
technologies.
Special thanks is offered to Federico Kovalenko, German Rimondi, Mariano Garcia, and Federico
Sorenson
Thanks you !!!

SPE WVS-593.

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