Pinpoint Vaca Muerta

1. SPE-172724-MS
Conditioning Pre-existing Old Vertical Wells to Stimulate and Test Vaca
Muerta Shale Productivity through the Application of Pinpoint Completion
Techniques
Pablo Forni, CAPEX S.A.; Juan C. Bonapace, Federico Kovalenko, Mariano N. Garcia, and Federico Sorenson,
Halliburton
Copyright 2015, Society of Petroleum Engineers
This paper was prepared for presentation at the SPE Middle East Oil & Gas Show and Conference held in Manama, Bahrain, 8–11 March 2015.
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Abstract
One of the most promising targets for resource rock stimulation in South America is the Vaca Muerta
(VM) shale in western Argentina. Because of high initial costs and also the typical reservoir information
that must be acquired, it is common practice for operators to begin exploration projects with vertical wells.
This is also the case for unconventional reservoirs, so initial vertical wells are used for reservoir
characterization/initial comprehension and also to test the productivity of the different intervals.
Within the Neuquina basin, existing vertical wells were typically drilled to produce reservoirs below
the VM source rock. Presently, with these reservoirs depleted in many areas, existing wells are often a
great opportunity to investigate this upper unconventional target. Unfortunately, most of these wells are
not viable candidates because they were designed to be completed through tubing. Casings and wellheads,
in general, are not sufficiently strong to support pressure requirements for fracture stimulation of
unconventional reservoirs.
This paper discusses the preparation of a well originally drilled in 1974 to allow for the new objective
of hydraulic fracturing the VM shale to test the productivity of its different intervals. A coiled tubing (CT)
assisted pinpoint completion technique (hydrajet perforating and annulus fracturing) was used to inde-
pendently stimulate small intervals. To help assure that most of the reservoir was indeed stimulated, 12
single-zone fracturing stages were used for 130 meters of gross interval.
To isolate the upper (weakest) section of the wellbore, a 4 1/2-in. P-110 casing and swellable packer
were installed.
Introduction
The present work details operations performed for the intervention of the fourth well of a development
project in the unconventional VM formation in the area of Agua del Cajón, Neuquén basin of Argentina
(Fig. 1) within the framework of an agreement between the producer and service company. Efforts had
already been made to improve the economic performance of the well (increase production and/or reduce
costs). To understand the steps taken in the well, it is necessary to review previous experiences.

2. The operation described in this paper was designed and executed within the framework of an agreement
between the producing company and service company to share research and development of this
non-conventional reservoir in the Agua del Cajón area.
This field is located in Argentina in the province of Neuquén and is currently producing gas.
Essentially, there are three main formations—Los Molles, Tordillo, and Lajas (upper and lower)—in the
area known as El Salitral, and oil is produced in the northern part, known as Agua del Cajón, mainly from
the Tordillo, Lajas, and Quintuco formations (Fig. 2a).
Geologically, the Agua del Cajón area is located in the eastern center of the Neuquén basin, over the
northern flank of the Dorsal de Huincul. El Salitral field, a gas producer of the Cuyo group, is located over
a huge structural spur/nose of transgressive nature in the lower block and north of the Huincul fault. To
the east of the Agua de Cajón block, the structure closes ruggedly, losing the fault vertical throw, and this
Figure 1—Geographic location of the Agua de Cajón field.
Figure 2—(a) Stratigraphic column and (b) sub-areas of the Agua de Cajón field.
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3. change clashes with a transfer zone, forming a new structure in the eastern region of the block, which is
a distensive type and where the existing sand in the Los Molles formation is the main gas reservoir.
VM Formation (Agua de Cajón)
The sediments of the VM formation are Tithonian to early Valanginian. Fig. 2a shows a typical
stratigraphic column for the Agua de Cajón field. The genesis and characteristic of the VM formation have
been described in more detail by other authors (Legarreta and Uliana 1991; Kietzmann et al. 2011).
In the Agua de Cajón area, the VM formation consists of mudstones (very sparingly wackestones) with
between 20 to 80% calcite, 2 to 15% dolomite, 8 to 30% quartz, 0 to 5% potassium feldspar, 1 to 8%
plagioclase, and not more than 6% clay, mainly illite.
The dominant percentages of total organic content (TOC) vary between 2 and 5%. The kerogen is Type
II, with a variation between Type I/II. The maximum temperature and productivity index (PI) values
indicate that the thickness of the center and northern area (Agua de Cajón) are in an oil window, while
southward is an early oil window or an immature formation (Villar 2011).
Background and Studies
The Agua de Cajón should have two distinct areas for its history and development—a central zone gas,
which is currently in full production (El Salitral field) and a north zone (Agua de Cajón), whose drilling
and exploitation of petroleum were very active in the 1970s and 1980s and development was completed
with a secondary recovery operation in the 1990s (Fig. 2b). The latter zone had approximately 30 wells,
which exhausted their economic output from productive areas (lower levels under the VM formation). It
had vertical wells that crossed the VM during drilling, casing, and cementing, in general, with good
formation information available, which could be used to study unconventional shale resources in terms of
cost reduction and eliminating requirements to drill and complete new wells.
Phase 1—Study In mid-2011, the first phase of study began. This consisted of an analysis of the geology
and reservoir using three-dimensional (3D) seismic reprocessing (determination of the lateral continuity
and area, identification of faults, etc.), maps of maturity and TOC generation, trace elements studies,
calculations of average thicknesses, estimation of reservoir pressure, and reinterpretation of profiles to
open the well (Fig. 3a).
Toward the beginning of 2012, the second phase of the study continued, which consisted of the
evaluation and identification of potential wells to be operated, conditioned, and fracture stimulated.
Initially, of the 30 wells in the area, only 22 were able to be operated, and only 11 of those had good
Figure 3—(a) Hydrocarbon window map, Agua de Cajón; (b) well locations.
SPE-172724-MS 3

4. quality cement covering the VM formation. Some had existing perforations (open), both at lower levels
(Tordillo and Lajas) and upper levels in the Quintuco (even some Quintuco perforations that have been
squeeze cemented). One significant point is that these wells were not designed to withstand the pressure
rating requirements of a shale-type completion; they presented a variety of geometries and older
technology (Type 1: Csg 7 in., 26 lb/ft N-80; Type 2: Csg 5 1/2 in., 17 lb/ft N-80; Type 3: Csg 7 in., 23
lb/ft; K-55 x Csg 5 in., 18 lb/ft N-80) (Bonapace et al. 2013).
A pilot plan was initiated for the evaluation of three wells—Wells A, B, and C; candidates were
selected based on the conditions of reservoir, well, and logistics to be operated (Fig. 3b). These wells had
the following common characteristics:
● Good condition, according to the geology and reservoir evaluation.
● Complete set of openhole logs, in some cases.
● Preserved geologic control drill cuttings.
● Evidence and presence of oil in shale through the VM during drilling.
● Geometry - wells Type 1 (Csg 7 in.).
● Good cement quality in the VM (fully covered).
● Wellhead configured for production of oil (3,000 psi).
● Formation perforated below the VM (sometimes with perforations open at Quintuco).
● Wells located close to secondary injection systems (surface water lines available).
Phase 1—Pilot Plan A summary of each of the wells was established in which the main objectives and
results were stated, as well as the developed learning curve. For the execution of the work in each of the
wells, it was necessary to condition them (remove existing installations, isolate lower levels under the
VM, use a tubing and packer to stimulate and reconfigure the wellhead for 10,000 psi).
Well A. The recompletion of the well was performed in June 2012. In this well, the VM formation had
a total thickness of 160 m (2,600 to 2,440 m TVD), of which it was decided to stimulate only 100 m. Good
information was provided by the openhole log, the cement log was updated (good condition), and there
were perforations open in Quintuco (upper VM); additionally, very good logistics existed because it was
located in proximity to large pits used to store water for previous drilling reconditioning treatments.
The completion methodology proposed and used consisted of setting a plug in the casing under the
bottom of the VM and using a 4 1/2-in. tubing, 13.5 lb/ft - P110 with a mechanical packer to isolate all
of the interval of interest. Perforations were made through tubing, and after stimulating each zone, they
were isolated using sand plugs (Bonapace et al. 2013).
Only in the first zone, a diagnostic fracture injection test (DFIT) was performed (Fig. 4). It had a total
recorded time of nine days (216 hours), injecting a volume of 28 bbl of treated water at a flow rate of 7
bbl/min, obtaining a 0.96 psi/ft fracture gradient. For the analyzed time period, the formation closure
pressure was not identified. Three hydraulic fracturing treatments were performed in this well. More detail
of this process is shown in the first column of Table 1 and Fig. 5a.
4 SPE-172724-MS

5. Figure 4—DFIT (a) chart operation and (b) analysis “G Function.”
Table 1—Details of hydraulic fracturing treatments.
SPE-172724-MS 5

6. This first well objectives were achieved satisfactorily, with all stimulation treatments using the
proposed completion methodology (plug below, treat through 4 1/2-in. tubing with a packer), the well
responded positively during operations. Afterward, the well was producing oil naturally.
Well B. Recompletion of the well was performed in December 2012. In this well, the VM formation
had a total thickness of 150 m (2530 to 2380 m TVD), of which it was decided to stimulate only 115 m.
It had a very basic openhole log, in which was run a sonic log (to evaluate the mechanical properties of
the rock), the cement log was updated (good condition), and no perforations existed above the VM
formation. It was decided to record the microseismic data during fracture stimulation and possibly use a
nearby well as a monitor well (400 m away).
Based on the experience gained in Well A, it was decided to apply the same completion methodology
used previously. For Well B, again three stimulation treatments were performed with modifications to
their design. It was decided to not perform a DFIT in any zone and only use short pumping (minifrac test)
before each stimulation to assess the conditions of working pressure (Column 2 of Table 1 and Fig. 5b).
Once completed, a formation pressure buildup test was performed for each individual zone stimulated
(Fig. 5d).
The objectives of this second well were achieved satisfactorily, with all stimulation treatments
proposed with the completion methodology again completed. The well produced oil naturally and showed
good microseismic results (Fig. 6), which helped obtain a better understanding of the stimulation
treatments as well as allowing changes to be made. The pressure buildup test data of Well B yielded
valuable information about the stimulated levels (Fig. 5d).
Figure 5—Stimulation charts for (a) Well A, (b) Well B, and (c) Well C; (d) buildup of Well- B.
6 SPE-172724-MS

7. Well C. Recompletion of the well was performed in April 2013. In this well, the VM formation showed
a total thickness of 165 m (2445 to 2280 m TVD), of which it was decided to stimulate only 150 m. There
was not sufficient openhole log or well information, so it was decided to use a cased-hole log (pulsed
neutron ϩ gamma ray spectral) and a neural network, as presented by Buller et al. (2010). A nearby well
with sufficient openhole information was identified and used in training and to calibrate the well. Well C
was logged as a cased hole and the resulting information was processed. The cement log was updated
(good condition), and there were no perforations in the Quintuco (above the VM formation). It was
decided to again record microseismic but this time using two monitor wells because of the proximity of
a nearby well (400 to 500 m away).
Given the experience developed in previous wells, the same completion methodology was followed.
Three hydraulic fracturing treatments were completed, and substantial changes to the design were made
to develop more conductive fractures (Table 1 and Fig. 5c).
The objectives were successfully achieved. Once again, the well could be completed in its entirety
using the methodology of the proposed completion method. The well produced oil naturally after
stimulation and showed good microseismic results. Also, the neural network training/calibration and
application thereof was successful (discussed in more detail later).
Lessons Learned After the three pilot wells were realized, a review of the same wells was conducted
from an operational point of view. Valuable conclusions were obtained:
● All of the stimulated wells produced oil naturally.
● The completion technique proposed to stimulate VM formation older existing vertical wells was
proven and successful.
Figure 6—Microseismic of Well B. View on floor and section (one monitor well).
SPE-172724-MS 7

8. ● A registration methodology applied to the cased-hole log and neural network (well calibration)
allowed improving the interpretation of the VM formation for wells with reduced or non-existent
openhole information.
● A learning curve was developed in the stimulation designs for determining designs to create more
conductive fractures (Fig. 7).
● It was possible to adapt the logistics (old locations, dimensions) and water supply to perform this
pilot plan.
New Approach
Because of the positive results from the pilot project, it was decided to attempt to improve the
development of the VM formation by making older vertical wells economically viable. The first step was
to reach an economic and technical agreement between the operator and services companies for this work.
This allowed the integration of a group of multidisciplinary sectors (geology, reservoir, and well
completions), consisting of personnel from both companies.
Phase 2—Review of Pilot Plan The second phase of the project was initially a review of the pilot plan,
both from a technical and operational point of view. Some of the findings include the following:
● The VM formation presents different petrophysical properties along its vertical section (thickness)
(TOC, porosities, brittleness, mineralogy, maturity, etc.), which could be detrimental to the
productivity of the well.
● The responses of the pressure buildup showed different behaviors for each stimulated interval.
● The stimulated zones of the VM formation were selected according to certain similar properties,
which denotes a greater degree of heterogeneity. Evidence of this has been observed using
evaluation techniques such as
X Tagged proppant identified within a stimulated area. Some clusters accepted this proppant and
Figure 7—Fracture design evolution during pilot project.
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9. others did not, which demonstrates inefficiency of the stimulation treatments (service company
experience).
X Tracers in fracturing fluid. Zones were identified that had more recovery fluid injected
compared to other zones, even though similar treatments were performed in each (services
company experience).
X Production logging tool registration. Identified zones (including individual clusters) experi-
enced better production than others.
X Microseismic. This was used to identify zones in which fracturing activity was concentrated
and zones in which very low microseismic activity occurred.
Accordingly, the idea was proposed to stimulate an area of greater thickness, as well as perform the
stimulation treatments more selectively by focusing on the details of each section (heterogeneous) to
increase well productivity and improve the economics of the project. A process was designed to initiate
changes in the completion method that would be able to achieve the previously mentioned objectives
while complying with the following premises:
● More selective and effective stimulation in the VM formation.
● Equal or lower costs to those generated by completions tested in the pilot plan.
● Identified notable changes in production with respect to previous wells.
● Applied in wells having the same characteristics as previous ones to allow comparative analysis.
Phase 2—Pre-feasibility of New Completion Plan Perform a completion with a greater number of
fracture stages (more selective) as initially proposed, involving a greater number of perforations (wireline)
and operations as well as greater precision in the placement of the sand plugs according to the
methodology of completion used (Fig. 8a) in the pilot plan. This greater number of operations would
require longer operating times (wireline); thus, before any displacement (sand plug placed) could occur,
additional operations (wash CT) would be necessary, which would negatively impact the total costs of the
completion (Forni et al. 2014).
SPE-172724-MS 9

10. To achieve this, it was decided to use a pinpoint completion type called the hydrajet perforating,
annular-path treatment placement, and proppant plugs for diversion (HPAP-PPD). This process consists
of an abrasive perforating through CT and subsequent pumping of the treatment into a fracture through
the annular space (with CT still in the hole, but with the tool pulled above the perforated interval), and
then leaving a sand plug after the fracturing stage to isolate the stimulated zone. This provides the benefit
of selectively perforating desired zones to achieve a faster completion and to prevent unwanted sand stops
(wash CT). This technique was introduced to the industry in 2004 (Surjaatmadja et al. 2005) initially in
vertical wells and was quickly applied in horizontal wells (McDaniel et al. 2006). In Argentina, it has been
used since 2006 (Bonapace et al. 2009) and has been tested on a wide variety of conventional and tight
reservoir gas wells (37 wells, 336 fracturing stages) in the Golfo San Jorge and Neuquén basins.
A candidate well was then selected to evaluate the implementation of this new approach (Well D). This
well did not have a good set of openhole logs, so the approach was to apply the technique used in Well
C (which already had a well calibration). The well geometry was similar to previous ones (Type 1) and
had perforation openings in the Quintuco (above the VM formation). Additionally, pre-conditioning of the
location and wellhead was required.
The existence of open perforations in the Quintuco required preparing the well, placing a plug on the
bottom of the VM formation and using CT to set a packer at the bottom of the treatment tubing string to
Figure 8—(a) Completion methodology: pilot plan; (b) new completion approach: pinpoint with hydrajetted perforations.
10 SPE-172724-MS

11. achieve isolation below the Quintuco perforations. Analysis was performed by evaluating a number of
variables: well geometry, pumping flow rate, flow restrictions (diameters), abrasive perforation conditions
(hydrajet), and stimulation requirements and conditions. On the basis of the completion model used
previously (conditioning wells in the pilot plan), work proceeded to assess the different possible
configurations in which this methodology could be applied. It was considered to use 4 1/2- or 5-in. tubing
options, 1 3/4- or 2-in. CT, a hydrajet tool of different diameters (3.06 or 3.75 in.), and two or three jets,
as well as a packer for the tubing option chosen. It was important to select a packer that had a large internal
diameter (ID) to allow the passage of the CT bottomhole assembly (BHA); traditional high-pressure
packers do not have sufficient diameters. An alternative was to use a swell packer with the ability to
withstand the designed pressures and having a sufficient ID. The work flow for the new completion
concept is shown in Fig. 9.
Finally, based on analyses and the availability of pipes, the CT outside diameter (OD), packer, and
hydrajet tool available in the country were selected, and the configuration elements necessary to perform
the multistage completion with pinpoint technique (Fig. 8b) were determined as follows:
● Tubing: 4 1/2 in., 13.5 lb/ft, P110
● Packer: Swell packer 4 1/2 ϫ 7 in. (6.05-in. swell and 3.958-in. ID)
● CT: 95K unit, 1 3/4 in., QT 1000
● Hydrajet: TST two jets and 3/16-in. ID
This completion scheme had the following considerations and limitations:
● CT Max Pressure: 12,000 psi
● CT Max Flow Rate: 2.7 bbl/min (for hydrajetting)
● BHA: Two jets oriented at 180°
● Frac Max Pressure: 9,200 psi (swell packer)
Figure 9—Flow chart of assessment for application of new completion approach in the VM formation (hydrajet-pinpoint completion).
SPE-172724-MS 11

12. ● Frac Max Rate: 25 bbl/min (according to maximum erosion velocity limit)
Another important point was the selection/preparation of the wellhead. Because the CT was in the well
throughout all of the treating stages, it was necessary to modify the outline of lines and valves that were
placed against fracture flow currents to help prevent CT erosion as fracturing fluid entered the wellhead.
Finally, it was necessary to prepare the old well location, logistics, and infrastructure so that the fluids,
chemicals, and proppant necessary could be delivered in time to perform the work plan.
Phase 2—Swell Packer Design To condition the well, the use of a packer with a large ID was required
to allow the passage of the BHA on the CT. Existing technology (swell packer) was used to adapt the new
non-traditional application. Wellhoefer et al. (2012) document an example of the non-traditional appli-
cation of this technology.
The use of swell packers was analyzed because they had never been applied for this purpose; the seal
should support the high working pressure, temperature, as well as the cyclical effects of the successive
fracturing treatments while maintaining its anchor strength.
Given the pressure and temperature conditions and the application type, a series of simulation/modeling
was performed to help ensure the performance of the tool during the entire treatment. Multiple simulations
(tubing movement) were conducted for different scenarios of fracturing treatments, varying fracture flow
rate, working pressure, fluid density, proppant concentration, and even extreme conditions, such as a
screenout. A hydrocarbon sample (determination of viscosity) was taken to simulate swelling time. The
final design included a maximum pressure 10,000-psi difference, 120,000 lb of anchoring strength, and
a total swelling time of 10 days (Fig. 10). Once the swelling time was complete, it would be necessary
to apply 30,000 lb of weight (slack off).
Conditioning of Well and Preplanning
In this conditioning stage, the purpose was to prepare the final geometry for the pinpoint completion. A
workover rig was required because complications with some of the required tasks could cause major
changes in the plan (increments of time and cost) or even premature stoppage, forcing a new candidate
well to be used. Fig. 11 shows the actual timetable of tasks performed, which lasted 20 days.
Figure 10—Swell packer: requirement for design, results, swelling time, and differential pressure.
12 SPE-172724-MS

13. Some of the operations vital to performing the completion of the well are discussed in more detail in
the following sections.
Logging
Cement Bond Logging This allowed evaluating the cement quality of the existing well (old well),
which was determined to be sufficient in the entire section of the VM formation for stimulation. On the
other hand, it was not possible to assess the zone in which the swell packer would be set. It was decided
to place the swell packer 10 m below the existing perforation in Quintuco (2341.0 to 2345.0 m).
Cased-Hole Logging As mentioned previously, before the completion of Wells C and D, there was
a lack of complete openhole data to identify zones to stimulate. Because of this, cased-hole logging
methodologies, such as those presented by Pitcher et al. (2012) and Dingding et al. (2004) for the
generation of a set of curved-type triple combo synthetic from cased hole and a set of neural networks,
were applied to complete the set of necessary minimum curves for an evaluation of the reservoir and
selection of the zones to stimulate.
As stated, the area contains a large number of existing wells having the potential to be recompleted.
For this reason, and significantly before the intervention of these two wells, the opportunity existed to
apply the cased-hole methodology and neural networks to generate the reservoir information necessary for
the evaluation of the project.
Therefore, in wells without complete openhole logs, logging with pulsed neutron was performed, and
then a corresponding system of neural networks was assembled and trained. It is important to remember
that the vast majority of the wells in the area have the same mechanical configuration. This is valuable
because uncertainty is reduced when calibrating the neural networks system in new wells.
Initially, Well D (Fig. 12a) had only an openhole log of spontaneous potential, resistivity, and sonic
compression. For the purposes of applying the petrophysical model already adjusted for the VM
formation, it was necessary to continue with a triple combo. A spectral gamma ray and pulsed neutron log
was run. The spectral gamma ray is important for determining a better estimation of the volume of clay.
The triple combo is important for estimating reservoir properties and the mechanical properties of rock,
which are fundamental to the design of hydraulic fractures and the completion of the well. In the last two
tracks of Fig. 12c, the right curves show the neutron and density log of the open hole and overlap, which
were calculated from the pulsed neutron log and original neural networks system (PHIN_CH and
Figure 11—Workover operations: conditioning the well.
SPE-172724-MS 13

14. RHOB_CH). Fig. 12b shows the corresponding normalization process, which was important in this
workflow.
Plug and Integrity Test After running the cased-hole logs, tubing was run-in-hole (RIH) to set a plug
to isolate the perforations located below the VM formation, which were then placed by two dump bailers.
At a later time, integrity tests of the well (plug and tubing with packer) were performed to evaluate the
entire system at 9,500-psi pressure for 10 minutes. No leaks were observed in the system.
Swab Test (Quintuco Formation) Because of the existing perforations in the Quintuco formation, a
swab test was performed to determine whether the perforations contributed or received fluid, as well as
to evaluate the type of produced fluid. After recovering the column of fluid and for five hours longer, there
was a production flow rate of 0.5 m3
/hr of 90% water. Based on this result, the proximity between the
perforations and the location of the swell packer (10 m) was recommended as a precaution to displace all
of the fluid in the annular space with oil (to activate the swell packer, which was oil-swelling).
Swell Packer Operation The swell packer operation consisted of RIH, setting it at depth, allowing the
time stipulated for swelling (swelling time), and finally applying weight (set weight). Details of the
following operations are presented:
● RIH swell packer below the theoretical setting depth.
● Pump 35 m3
of a total of 48 m3
of oil by reverse (annulus) circulation. Some obstruction (pack)
was noted.
Figure 12—Cased-hole logging: (a) existing openhole logs, (b) normalization, and (c) synthetic curves.
14 SPE-172724-MS

15. ● Move swell packer to the final position (set depth) and pump through tubing to unpack the swell
packer.
● Set swell packer at 2357.2 to 2367.3 m.
● Test swell packer, apply 2,500-psi pressure through tubing, and record zero pressure at the
annulus.
● Leave well closed to allow for swelling (10 days).
When 80% of the swelling time elapsed, the following actions were performed:
● Open wellhead and check pressure through the tubing and annulus (zero pressure).
● Apply weight (82,000 lbf); effective 30,000 lbf.
Infrastructure (Wellsite and Logistics) Given the age of the well, it was necessary to condition the
location to be able to perform the intervention (Fig. 13a). This well surface location did not have the same
dimensions as those usually observed in new shale well locations, so it was necessary to make changes
to the location of trailer offices, chemical storage areas, proppant storage, returned fluid storage, and water
transfer systems (Fig. 13b).
The water source was fresh water from the Limay river. It was transported by trucks to a main storage
center (tank existing in the field) located approximately 800 m from Well D. From the center of the
storage, water was pumped through centrifugal pumps and 3 1/2-in. pipe to the wellsite. At the location,
13 mobile frac tanks (1050 m3
) were used, which contained a sufficient storage water volume for three
fracturing stages (Fig.14).
Figure 13—(a) Wellsite dimensions and (b) equipment layout.
SPE-172724-MS 15

16. At the wellsite, two workover pools were used to store fluid returned from the well and to pump fresh
water to refill the frac tanks. The field camp was located 500 m away, where the chemical and proppant
were also stored, as well as part of the required auxiliary equipment.
Stimulation Design The main objective for Well D was to achieve an increase in production through the
application of a new completion concept that is more focused and therefore selective for the placement
of stimulation treatments. Once the processed cased-hole log was obtained, the entire set of synthetic logs
and properties of the reservoir and rock mechanics were calculated to evaluate the well characteristics.
From right to left in Fig. 15, gamma ray, resistivity, porosities, brittleness, elastic properties, unconfined
compressive strength (UCS), total organic content (TOC), shale porosity, and volume of clay can be
observed.
Figure 14—Water management plan: field camp.
16 SPE-172724-MS

17. Twelve intervals were evaluated and selected in the VM formation for stimulation treatments (130 m)
based on the interpretations of TOC, brittleness, porosity, UCS, similar rock mechanical properties,
evidence of traces of petroleum, and natural fractures.
The stimulation designs used the following general guidelines:
● Hybrid Fracture: Slickwater 40% ϩ crosslinked gel 60%
● Crosslinked Fluid: Carboxy-Methyl-Hydroxy-Propyl guar (CMHPG), 20 lbm/1,000 gal, low pH,
lower residue
● Proppant: ISP; mesh: 30/60 (20%) to 20/40 (80%); average concentration: 1.5 lbm/gal
Based on experience developed in the VM formation (Garcia et al. 2013), an acid prepad (reactive fluid
of 6% HCl-1.5% HF acid) was used before each treatment, as well as a new clay stabilizer. A summary
of the main features and volumes of each of the treatments is shown in Table 2.
Figure 15—Zone to be stimulated and location of individual stages to be hydrajet perforated and stimulated.
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18. Operation of Well D
The following sections describe the pinpoint (HPAP-PPD) stimulation technique and the equipment used
to perform it (CT, BHA), and surface wellhead equipment), and a summary of the stimulation operations
performed is provided.
Pinpoint Technique The HPAP-PPD process in a vertical well is illustrated in Fig. 16. The jetting-tool
assembly is first positioned at the lower-most intended fracture position (Fig. 16a). An abrasive slurry is
then pumped into the CT and jetted out of the tool at high pressures to form perforations (Fig. 16b). At
this time, fracturing-pad fluid is pumped through the annulus, increasing pressure rapidly to cause a
fracture to be generated (Fig. 16c). This step is continued for several minutes to establish a good
extension, after which the flow rate is increased to the intended fracturing rate and later the proppant slurry
is started and the tool is pulled above the perforated interval. The CT tubing rate can then be reduced to
a minimum so that it can serve as a dead string in the well for pressure monitoring. This situation also
provides a means for rapid corrective action, should an unwanted situation develop. The proppant slurry
is then pumped into the fracture, and when the fracture is extended to satisfaction, an induced screenout
is attempted to form a solid pack in the fracture (Fig. 16d), and a “plug” of high-concentration proppant
in a viscous gel is left within the wellbore. In some situations, the tubing flow rate is required for fracture
development. In such cases, the tubing rate is maintained throughout the treatment and only reduced
during the tip screenout stage. The CT is then lowered down to the next perforating position while
reverse-cleaning (or vacuuming) the sand plug (Fig. 16e), and the process repeats (Figs. 16f through 16h).
After all planned stimulation stages, a final well cleanout is then performed to wash all of the sand from
the well.
Table 2—Summary of the main features and volumes of each of the treatments.
18 SPE-172724-MS

19. The equipment used for the completion of Well D using the pinpoint technique follows:
● CT Unit (Fig. 17a):
X Injector: 95K pool capacity
X CT: OD 1 3/4 in., QT 1000, 17,200 ft
● BHA (Fig. 17b):
X CT connector
X CT de-connector
X Hydrajet (two jets 3/16-in., 180°)
X Ball sub
X Mule shoe
● Surface Equipment—Wellhead (Fig. 17c):
X Side windows stripper
X Quad blowout preventer (BOP): 4 1/16 in., 10,000 psi
X Lubricator: 4 1/16 in., 10,000 psi
X Crossover: 7 1/16 to 4 1/16 in.
X Two flow crosses: 7 1/16 in., side inlet 4 1/16 in. 1502
Figure 16—HPAP-PPD technique steps illustrated.
Figure 17—(a) CT unit, (b) BHA during a pumping test, and (c) surface equipment—wellhead.
SPE-172724-MS 19

20. X One flow cross: 7 1/16 in., side inlet 2 1/16 in. 1502
X Dual combi BOP: 7 1/16 in., 10,000 psi
X Two valves: 7 1/16 in., 10,000 psi
For the design of the BHA, a new hydrajet tool was considered because of the amount of stimulation
and abrasive jets required. This new tool was designed to maximize its useful life, having improved
performance of 200 to 300% compared to previously existing tools, as well as reducing costs by
eliminating additional trips resulting from tool changes or jet erosion (Surjaatmadja et al. 2008).
Well Operation Initially, in the lower section of the well, there were problems with both the abrasive jet
perforations (had to be repeated or new ones added) and with the stimulation treatments (screenout). This
led to a series of changes in the fracturing treatment to allow adjustments to the well and formation
conditions. These modifications allowed the development of this lower part of the well during the rest of
the operations without problems. The first four operations are described in more detail later in this paper.
Initial Operation—CT Using CT, the BHA was RIH into the well. Once reaching the bottom, the depth
of the mechanical plug (2605 m) was checked. Then, the well fluid was changed to oil (to activate the
swell packer) by fluid completion (fresh water, clay, and surfactant inhibitor). The CT system’s depth was
adjusted using the depth plug measurement. Afterward, the BHA was positioned at the depth for the first
abrasive perforation.
Zone 1
Abrasive Perforation With CT at depth, an annular backpressure of 2,000 psi was applied. Pumping
began from the CT at a rate of 2.6 bbl/min and a pressure of 8,574 psi (abrasive perforation), pumping
1,600 gal of linear gel with a total of 16 sacks of sand (1.0 lbm/gal). Then, approximately 300 gal of 15%
HCl acid was pumped. When the HCl acid reached the BHA, the annulus was closed and flow was
decreased to 1.0 bbl/min. Breakdown was observed at 5,482 psi (clear connectivity to the well formation).
It should be noted that for all of the cuts (abrasive perforations) in the well, 40/70-mesh white sand was
used. One mesh size smaller than that traditionally used (20/40) was chosen to assess whether such cutting
sand could be forced into the formation ahead of the pad from the surface without requiring reverse
circulation to the surface, which would require more operational time.
Stimulation Pumping began through the annulus to create hydraulic fractures., starting with a pre-acid
(HCl-HF acid) at 5.0 bbl/min, achieving the same formation pressure response as previously observed.
The fracture rate was increased to 21.2 bbl/min with a wellhead pressure of 6,530 psi. The treatment was
pumped according to the program but ended suddenly because of increasing pressure and screenout. The
CT pressure (pseudo-dead string) showed a negative trend during pumping of the pad and the first
concentrations, then a flat pressure response was observed during 1 lbm/gal 30/60-mesh. An abrupt
pressure increase was observed when 2.5 lbm/gal 20/40-mesh hit the perforation and caused a screenout
(Fig. 18, Stage 1). After the screenout, reverse circulating the proppant was conducted (required 2 hours),
and two successful pressure tests on the sand plug were performed to help ensure the isolation of the first
fracturing stage.
20 SPE-172724-MS

21. Modifications Based on these observations and after an analysis of the operation, it was decided to
introduce the following changes to the next stage: increase the percentage of crosslinked fluid (change the
fluid, use crosslinked fluid as the entire volume of the pad instead of slickwater), evaluate the pumping
of a clean fluid sweep between the proppant mesh increases, and maximize the flow rate depending on
the pumping pressure.
Zone 2
Abrasive Perforation With the CT at depth and repeating the same sequence as described for Zone
1, a breakdown was observed at 6,120-psi pressure. During pumping of the stimulation treatment (pre-acid
pad), high pressure was observed, which made it impossible to achieve the designed flow rate. It was
decided to create a new perforation at 2547 m but batch pumping of acid (HCl acid) was removed from
the process. Once a displacement volume of 900 gal was in the annular space created by the abrasive
perforation, the annulus was closed and breakdown pressure (5,881 psi) was observed. Pumping of the
fracturing treatment was started to force the entry of cutting sand from the perforation process into the
formation.
Stimulation First stage alterations were introduced in the pumping schedule. Pumping began at an
annular flow rate of 24.3 bbl/min and 7,350-psi wellhead pressure. A sweep of clean fluid was pumped
between the two meshes of proppant, and the treatment ended suddenly (screenout). The CT pressure
(pseudo-dead string) showed a slightly negative trend during the pad and the first concentrations, so a
change was made to use 1.5 lbm/gal of 30/60-mesh proppant, which resulted in a positive increase. After
the sweep, the trend was stable until reaching 2.6 lbm/gal of 20/40-mesh at the formation, resulting in a
Figure 18—Treating charts for four of the 12 stages of the hydraulic fracturing treatments.
SPE-172724-MS 21

22. screenout. After the screenout, proppant was reverse circulated (required 2 hours) and a pressure test
(positive) was performed on the sand plug to help ensure isolation of this second stage.
Modifications Based on observations and analysis of the first two treatments, it was decided to
continue making changes to the design. The changes already made were combined with the following:
increase the gel loading from 20 to 25 lbm/1,000 gal (crosslinked fluid), make the proppant steps more
gradual (smaller step changes), and modify the percentage of proppant mesh sizes to 50% 30/60-mesh/
50% 20/40-mesh.
Zone 3
Abrasive Perforation With the CT at depth to pump the volume of abrasive sand, the same sequence
was followed as previously but without the HCl acid batch. A breakdown pressure of 6,415 psi was
observed. Attempting to force the perforation cutting sand into the formation resulted in a screenout.
Reverse circulation was performed for 1 hour, and an admission test was conducted. It was decided to
pump 400 gal of 15% HCl acid through the CT. On entering the formation, the HCl acid resulted in an
observed pressure reduction of 1,600 psi. It was finally decided to make an additional abrasive perforation
at 2534 m and again include the HCl acid in the cutting sequence. The new perforation resulted in a
breakdown pressure of 4,900 psi with good admission (connectivity).
Stimulation Modifications to the pre-acid (HCl-HF acid) stage were considered for the stimulation
treatment because expected results were not observed when it entered the formation (pressure drop). All
of the 30/60-mesh proppant was placed in the formation at a maximum concentration of 2.0 lbm/gal, and
then a sweep of clean fluid was pumped and the 20/40-mesh proppant was mixed with 30/60 mesh,
achieving a concentration of 2.0 lbm/gal, which caused the increased pressure observed in the CT
(pseudo-dead string). The motivation to pump a new sweep resulted from observing the same trend with
the proppant mixture as observed in Zone 2. A sand plug was mixed and the final flush began, but it could
not be completed because of a sudden increase in pressure (screenout). Even though the operation ended
in a screenout, 96% of the planned proppant was placed. After the screenout, reverse circulation of the
proppant was performed (required 2 hours), and a pressure test (positive) was conducted on the sand plug
to help ensure isolation of this third stage.
Modifications The principal objectives were achieved: place in the formation at least 80% of the
designed proppant; use crosslinked fluid in 90% of the treatment; keep the gel loading at 25 lbm/1,000
gal; use slightly increased concentrations (mixing); maintain a mixture of 50% 30/60-mesh and 50%
20/40-mesh proppant; and use a clean fluid sweep as a contingency.
Zone 4
Abrasive Perforation With CT at depth, the volume of perforating sand and acid for two sets of
perforations was pumped. Once acid was at the BHA, the annulus was closed and a marked increase in
pressure was observed, reaching maximum pressure. It was again attempted to perforate, without
favorable results. Reverse circulation to the surface of the perforating sand and acid was performed
(required 1 1/2 hours), and the perforations were left uncovered. A new perforation was created at 2516
m. For this additional perforation, the HCl acid was removed. Once a displacement volume of 900 gal was
in the annular space created by the perforation, the annulus was closed. A breakdown pressure of 9,000
psi was observed, and it was attempted to force the entry of sand into the formation, without good results.
Reverse circulating the perforation sand was performed (required 1 hour), leaving the perforations
uncovered. An admission test was performed through the CT, and then 500 gal of 15% HCl acid was
pumped. The return was closed, and with the acid in the BHA, the sand was forced into the formation,
resulting in a pressure reduction and admission with a lower breakdown pressure (6,750 psi).
Stimulation During the pad stage, pressure was high (8,100 psi). The 30/60-mesh proppant was mixed
gradually, and the pressure trend (pseudo-dead string) was negative until a concentration of 1.5 lbm/gal
was reached, at which point it stabilized. According to the pressure response, it was decided to continue
22 SPE-172724-MS

23. mixing 30/60-mesh up to 2.25 lbm/gal (more 30/60-mesh was mixed than the design required). Then,
20/40-mesh was mixed at a lower concentration of 1.75 lbm/gal; when 2.0 lbm/gal reached the perfora-
tions, a change in the pressure trend (positive) was observed, so it was decided to mix the sand plug at
3.0 lbm/gal and begin the final flush. The flow rate was decreased, inducing a screenout (Fig. 18, Stage
4). After the screenout, reverse circulating the proppant was performed (required 1 hour), and a successful
pressure test was conducted on the sand plug to help ensure isolation of this fourth stage.
After observation and analysis of the first four stages, it was determined to introduce the following
changes to the treatments for the rest of the operations in the well:
● Hydrajet: use volumes between 1,500 to 1,800 lbm of proppant (sand) for perforating, keep the
pumping of HCl acid in the procedure (300 gal), and assess in greater detail the locations of the
perforations (i.e., type of rock where perforating).
● Reactive Fluid (Pre-acid): remove the acid from the pumping schedule.
● Fracture Design:
X The main objective is to place at least 85% of the designed proppant into the formation (50%
30/60-mesh and 35% 20/40-mesh).
X A clean fluid sweep would be used as a contingency when necessary.
● Fracturing Fluid:
X Use crosslinked gel for 90% of the treatment.
X Keep the loading gel at 25 lbm/1,000 gal minimum.
● Fracture Flow Rates:
X Should be maximized, provided the wellhead pressure allows it.
● Proppant:
X Modify the mesh percentages to 50% 30/60-mesh and 50% 20/40-mesh.
X Perform gradual concentration increments of 0.5 lbm/gal between steps in the initial stages.
Tables 3 and 4 show the main variables involved with hydrajet perforating and fracturing treatments.
Table 3—Hydrajet process details.
SPE-172724-MS 23

24. All stimulation treatments were completed by applying these modifications and without encountering
significant problems (Fig. 18, Stage 8 and 12), except for sudden screenouts that occurred in Stages 5 and
9, which were below the proposed target (85% of proppant in the formation). Final results for the 12
stimulation treatments are shown in Fig. 19. The y-axis indicates the stage number.
Fracture gradient (FG) results registered from previous tests are shown in Fig. 19a, and Fig. 19b shows
the values post-fracture in operations that did not result in a screenout. In general, normal FGs of 0.98 to
Table 4—Fracturing treatment details.
Figure 19—(a) FG prefrac, (b) FG post-frac, (c) proppant in the formation, (d) % crosslinked fluid, (e) % 30/60-mesh proppant, and (f)
maximum proppant concentration.
24 SPE-172724-MS

25. 1.06 psi/ft were observed for the VM formation; however, previous stimulation treatments in this field
never recorded a FG greater than 1.0 psi/ft. For reference, both Figs. 19a and 19b indicate the value of
a 1.0 psi/ft FG with a dotted line.
Fig. 19C shows the percentage of proppant in the formation compared to the design, indicating two
lines of reference corresponding to 50 and 90%. Also, each stimulation treatment is shown, with the color
representing the degree of severity of the screenout, if one occurred. The circles correspond to normal
operation, blue crosses to slight screenouts (equal to or greater than 90% of proppant in the formation),
and red crosses to severe screenouts (50 to 80% of proppant in the formation).
Fig. 19D shows the percentage of crosslinked fluid designed (gray) versus the actual amount used (light
blue). It can be observed that the percentage from the treatment designs was 55%, but after the
modifications were applied, the average used was on the order of 85%. Only Stage 1 had a value similar
to that designed.
Fig. 19E shows the percentage of proppant mesh (30/60) designed versus that actually used; the design
was 20% (gray) but proppant actually used was on the order of 50% (green). The actual value used (green)
is based on the total of the proppant placed in the formation. The first three stages have values lower than
50% because for the first two stages, and as a result of the sudden screenout, the highest percentage of
proppant placed in the formation was 30/60-mesh. Stage 3 was the first in which the mesh-size
modification was introduced.
Fig. 19F shows the maximum proppant concentration (lbm/gal). The designed amount was, on average,
5.0 lbm/gal (gray), and the final value reached is shown in red. It can be observed that for the first five
stages, values reached an average of 2.5 lbm/gal, and subsequent stages approach the designed amount.
The first five stages had three of the four severe screenouts that occurred in the well (Fig. 19c, red
crosses).
Discussion
Additional Friction
In some of the operations, the estimated total values were on the order of 2,000 to 2,500 psi (near-
wellbore and/or perforation friction). One possible explanation is that the BHA (two holes, 180° phase)
was oriented in a plane with a high angle (Ͼ 45°) to the fracture plane, causing the observed excess
friction. An improved alternative would be to use a three-hole, 120° phase configuration; this would
require the use of 2-in. CT.
Hydrajet (Abrasive Perforation)
It was necessary to add additional perforations in four zones, three of which were placed in stages located
in the lower section of the VM formation (Stages 2, 3 and 4). The fourth was performed in Stage 10. More
detailed analysis of the perforations locations from the well log showed that Stages 2, 4, and 10 were
located in zones with high lamination in brittle sections and small thickness. Because of this, the locations
of the rest of the perforations were revised, changing the depth in Stages 5, 6, 11, and 12 (compare the
hydrajet proposed and performed depth in Tables 2 and 3).
Variation along the Well
There was a clear difference in the behavior of the abrasive perforation and stimulation treatments along
the verticality of the well. A lower section comprised the first five stages and an upper section comprised
the seven remaining stages, which were zones with more carbonate. This segmentation in the vertical well
showed that the lower stages had problems initiating the treatment (connectivity between the well and
formation), as well as a high sensitivity to the proppant mesh size and the maximum proppant concen-
tration placed in the formation. On the other hand, the zone with more carbonate did not experience
significant problems at the beginning of the stimulation treatment, even allowing placement of the
SPE-172724-MS 25

26. designed concentrations of proppant (4.0 lbm/gal). However, the FG values along the verticality of the
well were normal (0.98 to 1.06 psi/ft).
Conclusions
Completing old wells in the VM formation using a pinpoint stimulation technique was proposed. A work
flow of engineering solutions, existing technologies, and remediation of adverse operating conditions was
developed and executed. The main achievements and conclusions are summarized below:
● The use of a cased-hole logging methodology (pulsed neutron ϩ neural network) in old wells with
little openhole log information allowed synthetic curves to be generated that could be used to
perform a more consistent interpretation of the VM formation, allowing the identification of zones
with the greatest potential for stimulation, depending on their mechanical properties, brittleness,
UCS, TOC, etc.
● The isolation element (swell packer) used was an existing technology adapted for a new appli-
cation. The proposed design of the swell packer, after various simulations, successfully fulfilled
the requirements of flow rate and pressure necessary for the entire completion of the well (12
stages).
● It was demonstrated that the new hydrajet tool is a viable option to establish connectivity between
the well and formation for stimulating the VM formation with a single CT deployment. Proof of
this is that it allowed for 18 consecutive perforations and 12 stimulation treatments without
requiring a change out. This is a considerable improvement compared to previous older style tools
used in this type of operations, which require at least once change out during a well completion
operation of this magnitude.
● The completion technique (HJAF process) required a total of seven days (one day for assembly,
one day for final cleanup, and five days to complete 12 fracturing stages). It is important to
mention that once an understanding of the stimulation responses resulting from well and formation
conditions was obtained, three stages were performed every 24 hours (Stages 4 to 12).
● The VM formation can be stimulated using pinpoint techniques by adapting fracturing treatments
to this technology (modification of the type of fracture, gel loading, pumping schedule, and
percentage of mesh types used).
● The VM formation can be hydraulically fractured at a low flow rate (18 to 24 bbl/min) and normal
pressure (7,000 to 8,500 psi), consuming less horse power (on average between 3,450 to 4800
HHP) using less resources (pumping equipment).
● Previous perforation and sand plug completions (Wells A, B, and C) used an initial flow rate of
1.8 to 2.3 bbl/min per hole; Well D, completed using the HJAF technique, used a rate of 4 to 12
bbl/min per hole, which is a higher value and energy to initiate and propagate the hydraulic
fracture.
A correct evaluation of the infrastructure required for the execution of the project was necessary. A
detailed plan of work (with a large number of operations) was executed to prepare the well and leave it
in the condition required to further the completion. Proper coordination of the water logistics, proppant,
materials, resources, and equipment was scheduled to realize the completion in the shortest possible time,
preferring to not generate timing offsets that would negatively impact the project.
An excellent understanding of the working group (operations and technical staff) between two
companies (operator and services) was developed to meet the objectives and challenges, which not could
have been completely identified by working separately on an individual basis.
Finally, this paper does not publish production data of the discussed wells because, at the time of
writing this work, they were still being determined. The main objective was to demonstrate a working
methodology despite the particular outcome of each well.
26 SPE-172724-MS

27. Acknowledgements
The authors are grateful to the management of CAPEX and Halliburton for permission to publish this
work. They also thank all those who participated in the project and the preparation of this publication, in
particular
● CAPEX: Gabriel Irazuzta, Jorge Ferraris, Daniel Huenuhueque, Nicolas Fumagalli, and Marcelo
Belièra for effective work in the development and preparation of the well, and geologist Carlos
Gomez for contributions in the technical content of this publication.
● Halliburton: Matthew Sharp, Dustin Holden, William Harbolt, Germán Rimondi, and Esteban
Patch for operational support in the execution of the work.
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