SPE-185478-MS

Multipay Well Completion in Argentina: A Versatile Pinpoint CompletionTechnology Applied through Several Conventional, Tight, and ShaleReservoirs

J. C. Bonapace and F. Kovalenko, Halliburton; F. Sorenson, Pan American Energy; P. Forni, Grupo Capsa, and F.Barbalace, Pampa Energía

Copyright 2017, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Latin America and Caribbean Petroleum Engineering Conference held in Buenos Aires, Argentina, 18-19 May 2017.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contentsof 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 reflectany position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the writtenconsent 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 maynot be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

AbstractMany fields in Argentina have multilayer reservoirs that require various stimulation techniques, primarilyhydraulic fracturing. A variety of formations and types of reservoirs, such as conventional (mature fields)and unconventional (tight gas and shale), are the main focus in the Golfo San Jorge and Neuquén basin. Thehydraulic 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 2006, a pinpoint completion technique was introduced to help achieve greater efficiency and reducetime and costs associated with completions. This paper presents experiences gained using this technologyand proving such versatility in different types of reservoirs.

The pinpoint technique, called hydrajet perforating annular-path treatment placement and proppant plugsfor diversion (HPAP-PPD), was applied in new wells at different reservoir conditions. The history andevolution of this technique in Argentina was initiated in conventional oil reservoirs (mature fields in GolfoSan Jorge) and then was introduced in the Neuquén basin in gas well completions. Throughout the lastseven years, this technique has been tested and implemented in tight gas wells. More recently, it was usedto improve a completion technique in a shale oil well.

This completion method allowed operators to focus treatments in desired zones using specific treatmentdesigns based on reservoir characteristics. Several case histories are presented for different basins,formations, and reservoirs types, highlighting lessons learned and reduced completion time.

IntroductionHydraulic fracturing is one of the most widely used stimulation techniques. It is intended to increase theproduction of reservoir fluids by applying hydraulic pressure to a fluid pumped with proppant material thatfills created fractures.

In Argentina, the application of this stimulation technique dates back to October of 1960 in the PuestoLopez field in the Sierras Blancas formation. Since then, this type of treatment has been performed in five

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producing basins in the country (Fig. 1) as well as in a variety of formations, including conventional andunconventional reservoirs.

Figure 1—Argentina producting basins.

Throughout the years, constant changes have been made to treatment fluid systems used during hydraulicfracturing operations, moving from petroleum-based fluids, methanol (Hernandez et al. 1994; Antoci et al.2001), CO2 and nitrogen foams, nitrogen-assisted systems (Alvarez et al. 2012), and water-based systems(Powell et al. 1997; Fontana et al. 2007).

These types of stimulation treatments have a variety of requirements for use in this productive basin,which presents a wide range of depths from 300 to 4500 m, BHTs from 100 to 350°F (Ramallo et al. 2002;Powell et al. 1997), various reservoir pressures (subnormal to overpressured) and permeabilities (high,medium, low, and ultralow) (Schnaidler et al. 2013; Castellarini et al. 2015), and different types of complexformations (D'Huteau et al. 2001, 2007; Porollan and Yochcaff 2012). Also, various types of reservoirproblems can be associated with these stimulation treatments, such as proppant flowback (Daparo et al.2009; Nguyen et al. 2013) and the production of high levels of water (Brocco et al. 2000; Dos Santos etal. 2005; Diaz et al. 2009).

Because of the characteristics of these basins, productive fields were developed in monolayer ormultilayer reservoirs, as well as with multitarget well types. Completions in these types of reservoirs(multilayer or multitarget wells) require a detailed evaluation of technical, operational, and economicalaspects to apply the best methodology (Scianca and Gimenez 2002).

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This paper documents experiences, lessons learned, and results achieved using a versatile pinpointcompletion technique in Argentina for conventional oil and gas, tight gas, and shale oil reservoirs in theGolfo San Jorge and Neuquén basins.

Completion TechniquesGenerally, achieving success in multilayer completion wells requires combining reservoir understanding,the types of stimulation necessary, and appropriate completion techniques. McDaniel (2005) presents areview of several fracture stimulation techniques to achieve the best economics in multilayer reservoirs.His work documents a scorecard to be used by the operator to identify the best completion option based onthe reservoir (or well) characteristics and limitations (or benefits) of the completion technique. Operatorsmay have to execute a "balancing act" with the need to maximize return on investment (ROI) while tryingto complete as many contributing zones as possible. This usually drives a well operator toward methodsto minimize the number of separate well interventions while maximizing the number of zones that canbe effectively stimulated. There are several multizone fracturing methods available with respect to wellcompletions, the most cost-effective method dependent on reservoir properties and characteristics.

An important group of fields along various basins in Argentina comprise multilayer reservoirs; thiscondition is generated in some cases by formations with small lenticular lenses or by the existence ofdifferent formation targets in the same well. Based on such conditions, operators evaluate and select themost appropriate completion technique. The most common completion methodologies applied in Argentinafor these wells are as follows:

• Workover unit operations

◦ Tubing string with a set of packers and mechanical plugs

◦ Tubing string with a set of straddle packer systems (Velasquez et al. 2009)

• Rigless operations (plug-and-perf)

◦ Through casing, applying limited-entry perforating, isolating by bridge plugs

◦ Through casing, applying limited-entry perforating, isolating by sand plugs

For conventional oil wells, workover options are employed; for tight gas, and shale oil, the alternativeof rigless operations are preferred.

HPAP-PPDThe HPAP-PPD completion technique, referred to as a pinpoint stimulation method, was introduced to theindustry in 2004 (Surjaatmadja et al. 2005) in vertical wells initially and was soon also applied in horizontalwells (McDaniel et al. 2006). It consists of abrasive hydrajet perforating deployed on coiled tubing (CT)and subsequent fracturing treatment pumping through the annulus between the CT and casing, resulting ina fracturing stage which was then isolated with a sand plug so the perforating/fracturing processes couldimmediately be repeated on another zone above.

This technique provides the benefit of allowing selective zones to be stimulated, encouraging fastercompletions, and has the jetting tool has the versatility to allow clean out of sand plugs (washed with CT)after all desired stages have been fracture stimulated. In Argentina, it was introduced in 2006 in the GolfoSan Jorge for conventional oil reservoirs (Bonapace et al. 2009); it was then used in the Neuquén basins forconventional oil and gas (Folmer et al. 2008; Favoretti and Ferrer 2008; Kovalenko 2009), unconventionalreservoirs, tight gas (Barbalace et al. 2012), and shale oil (Forni et al. 2014, 2015) (Fig. 2). Throughout

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the years, this technique proved its versatility, being introduced and applied in various reservoirs based ontheir requirements (Fig. 3).

Figure 2—(a) Conventional gas well completion; (b) conventional oil wellcompletion; (c) tight gas well completion; (d) shale oil well completion.

Figure 3—Historical evolution of pinpoint technique application in Argentina.

In Argentina, this completion technique has been successfully applied in a wide variety of formations,such as the Comodoro Rivadavia and Mina del Carmen in the Golfo San Jorge basin and Lotena, Quintuco,Tordillo, Lajas, Los Molles, Punta Rosada, Precuyo, and Vaca Muerta in the Neuquén basin. Table 1 andFig. 4 present the primary properties of these formations wherein HPAP-PPD was applied.

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Table 1—Summary of the main characteristics for each formation.

Basin FormationReservoir fluidReservoir type

GSJ ComodoroRivadavia OilConventional

GSJ Mina delCarmen Oil

Conventional

NeuquénLotena Oil

Conventional

NeuquénLajas Gas

Conventional

Neuquén LosMolles Gas

Conventional/tight

Neuquén VacaMuerta Oil

and gas Shale

NeuquénPunta Rosada

Gas Tight

Depth (m) 1000 to 2250 2250 to 3000 1400 to 2000 1600 to 2400 2350 to 3200 2400 to 3000 3200 to 3900

BHT (°F) 120 to 190 190 to 230 135 to 165 145 to 180 180 to 220 185 to 215 225 to 255

Porosity (%) 12 to 18 14 to 19 12 to 17 8 to 12 6 to 12 2 to 9 4 to 12

Permeability (md) 10 to 50 5 to 25 10 to 45 0.2 to 0.65 0.08 to 0.2 0.00001to 0.0001 0.001 to 0.01

Reservoirpressure (psi/ft) 0.28 to 0.35 0.37 to 0.40 0.32 to 0.38 0.23 to 0.35 0.35 to 0.65 0.75 to 0.90 0.55 to 0.7

Young'smodulus (Mpsi) 1.3 to 2.2 1.5 to 2.6 1.1 to 2.3 1.8 to 3.0 2.8 to 5.5 3.5 to 6.0 3.8 to 6.3

Figure 4—(a) Fracture gradient (psi/ft); (b) minimum horizontal stress (psi) for different formation and type of reservoirs.

To date, 37 wells have been completed with a total of 336 fracturing stages for six different operators.Fig. 5 shows the distribution of wells completed with this technique in terms of basins, operators, reservoirtype, and well geometry. Table 2 presents a summary of the main characteristics in terms of well geometry,pinpoint technique, and fracture treatments performed for each reservoir type.

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Figure 5—(a) Wells completed by basin; (b) wells completed by operator;(c) wells completed by reservoir type; (d) wells completed by well geometry.

Table 2—Summary of primary characteristics for each type of reservoir wherein HPAP-PPD was applied.

Data/Type Reservoir Conventional Oil Conventional Gas Tight Gas Shale Oil

Avg. fracture stages 9 9 11 12

Well geometry (in.) 5 1/2 5 1/2 4 1/2 7 + 4 1/2

Max. pressure (psi) 10,000 10,000 10,000 10,000

CT unit (injector) 60K 60K 60 to 95K 95K

CT outer diameter (OD) (in.) 1 3/4 1 3/4 1 3/4 1 3/4

Hydrajet tool Old tool Old tool Old tool / new tool New tool

BHA - N° hole 3 3 2 2

Working time (hours) 12 12 12 / 24 24

Fracture depth (m) 1050 to 2500 1400 to 2800 2900 to 3800 2350 to 2900

BHST (°F) 120 to 205 135 to 200 210 to 250 180 to 210

Fracture gradient (psi/ft) 0.53 to 0.85 0.55 to 0.80 0.75 to 0.95 0.93 to 1.05

Pump rate (bbl/min) 16 to 19 18 to 24 16 to 20 15 to 23

Wellhead pressure (psi) 1,100 to 4,300 2,250 to 5,700 6,800 to 9,300 6,500 to 8,500

Fracture fluid (gal/1,000 gal) Guar-borate (25) CMHPG-Zr (25) CMHPG-Zr (25) CMHPG-Zr (25)

Total well fluid (m3) 500 1,510 2,475 4,800

Total well proppant (lbm) 230,000 585,000 970,000 1,045,000

Type of proppant Sand - RCP - ISP Sand - ISP ISP ISP

Type of mesh proppant 12/20, 16/30, 20/40 16/30, 20/40 30/60, 20/40 30/60, 20/40

Hydraulic horsepower (HHP) 550 to 2,000 1,300 to 2,850 3,000 to 4,350 3,400 to 4,600

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This completion technique has proven its versatility over the years. Several authors have documentedcases applying this technique in vertical wells in various reservoir conditions globally:

• Gilbert et al. (2005). Australia, Cooper basin, in sandstone, normal pressure, and in some caseswith overpressure; with fracture gradient between 0.85 and 1.15 psi/ft and minimum horizontalstress between 5,300 and 8,800 psi.

• Hejl et al. (2006). USA, California, Lost Hills field, at the upper Belridge Diatomite of theMonterey formation. This section is combined diatomaceous mudstones (0.1 to 1.0 md) anddiatomaceous sandstones (0.1 to 100 md).

• Mohsen et al. (2010). Egypt, El Fadl field, at the Bahareya sandstone oil producer with lowreservoir pressure.

• Chellani et al. (2012). India, West Bengal field in a coalbed methane reservoir.

Additionally, application examples of hydrajet abrasive perforation in hard formations have beenpublished, indicating the benefits of this type of perforation. In some cases, modifications of HPAP-PPDwere introduced as an alternative completion methodology, performing the abrasive perforation and thenpulling the tool out of the well, and finally executing the hydraulic fracture. Examples include Argentina(Schnaidler et al. 2013 in a tight gas Mulichinco formation), India (Aora et al. 2011 in the Raageshwarireservoir, gas and condensate tight volcanic rock), Algeria (Kritsanaphak et al. 2010 in the Hamra formation,oil tight quartzite sandstone), and Mexico (Lopez-Bonetti et al. 2014 in shale gas Eagle Ford), the latter ofwhich documents the application of HPAP-PPD in a horizontal well in the Pimienta formation (shale oil).

Case Histories

Conventional OilSeveral conventional oil wells were completed from 2006 to 2007 applying the HPAP-PPD technique.Initially, the first campaign of wells was in the Golfo San Jorge basin for Operator A (Fig. 3b). The maintarget for this operator was to reduce completion time using an alternative completion technique. The wellscompleted with this technique required up to nine fracture stages at the Comodoro Rivadavia and Mina delCarmen formations (Bonapace et al. 2009). In the Neuquén basin, Operator B completed up to five fracturestages in the Lajas and Lotena formations with the same objective, improving completion time (Favorettiand Ferrer 2008).

Operator A. The regular well geometry for this well consisted of 5 1/2-in. 15.5-lb/ft, K-55 casing and astandard completion developed through 2 7/8-in. 6.5 lb/ft, J-55 tubing. This operator performed the wellcompletion according to the following procedure:

• Perforate all of the zones.

• Perform several swabbing tests for individual zones using mechanical plugs and packers.

• Select the zone to be stimulated.

• Perform hydraulic fracturing with plugs and packers.

• Evaluate post-fracture by means of swab testing.

• Place the well into production.

In some situations, it was necessary to use double packers because of the proximity of the zone to bestimulated. This introduced longer completion times because of a large number of round trips of tubings.

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The HPAP-PPD completion technique was applied in two fields in nine wells with 90 total fracture stages.A 60K CT injector unit and 1 3/4-in. outside diameter (OD) CT were used. The casing type was modified(5 1/2-in. OD 17.0-lb/ft, N-80) to obtain a higher yield pressure. A cement bond log (CBL) acoustic imagelog was run in the 5 1/2-in. casing in the first well to verify the quality of the perforation. The boreholeimages in Fig. 6a clearly show three hole perforations as expected. Fig. 6b presents a comparative imagefrom conventional explosive perforations in an offset well.

Figure 6—(a) Hydrajet perforation, three holes in the same plane at120°; (b) conventional shape charge perforation [6 shots per foot (spf)].

In all of the wells, an initial bridge plug was placed below the lowest zone to be used in the depthcorrelation and reference. In some wells, because of the great distance between the first and last zone tobe stimulated, it was necessary to place a second bridge plug to minimize the amount of proppant usedto fill and isolate the previous zone stimulated. Table 1 presents a summary of the main characteristicsof this completion type for this operator. Fig. 7 shows examples illustrating that five days were necessaryto complete all of the operations proposed, considering a working day equal to 12 operative hours. Twodays were necessary for the rigup and rigdown of all of the equipment for each well; planning and logisticswere of extreme importance for both operations. Bonapace et al. (2009) documented the requirement ofperforming at least three fracture stages within 12 operative hours in each well. The best result obtainedwas completion of nine fracture stages in 19 operative hours.

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Figure 7—Completion time for conventional oil well in Golfo San Jorge basin, Operator A.

Folmer et al. (2008) presented results for conventional oil wells in the Neuquén basin, where three dayswere necessary to perform five fracture stages in six zones using HPAP-PPD compared to four days tocomplete three fracture stages with the same number of zones using a conventional completion (tubing-packer-mechanical plug). Additionally, Favoretti and Ferrer (2008) document comparative productionresults from wells completed using both methodologies in two wells. The first well used five fracturingstages compared to an offset well that was stimulated with a rigless completion (fracturing treatment bymeans of casing). The same intervals were targeted in both wells and were stimulated using the samedesign criteria (same amount of proppant). Production results showed a higher initial production as well asstabilized production for the well in which HPAP-PPD was employed, indicative of a more selective andeffective stimulation. For the second well, stimulation criteria were modified such that a lower amount ofproppant agent was used for the well completed using HPAP-PPD, which provided a production responsesimilar to an offset well in which the fracturing criteria were not changed.

Conventional GasHPAP-PPD was applied in this type of well only in the Neuquén basin from 2006 to 2010. The first wellwhere this technique was used was for Operator E. These hydraulic fractures were performed using afoam fracturing fluid, which was an operational challenge. Forni (2008) present comparative productionresults from one offset well completed using plug & perf by casing completion (4 fracture stages) versusthe well completed by pinpoint stimulation technique (7 fracture stages). The same intervals were targetedin both wells and were stimulated using the same design criteria, fracture fluid and equivalent amount ofproppant. Production results showed a higher initial production as well as stabilized production for thewell in which HPAP-PPD was employed, indicative of a more selective and effective stimulation. Thiscomparative evaluation was performed for a period of time of one year production. Afterward, this techniquewas evaluated and accepted by Operator B (Fig. 3b) and primarily used in the Neuquén basin. For thisoperator, a total of nine fracture stages were executed during regular completion, and the main objectivewas to reduce the completion time.

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Operator B. Historically, this reservoir was completed by fracturing several zones together. The wellcompletion for this wells consisted of 5 1/2-in. 17.0-lb/ft, N-80 casing. The field is located next to an urbanarea, which limits the work schedule to fracturing only during daylight. Selected zones are fractured as aunit using a pseudo limited-entry technique; the isolating method was alternated between mechanical plugsplaced with cable and sand plugs, depending on distances between fractures. After completing each fracturestage, well cleaning was performed and the stages were isolated with a mechanical plug to help prevent apossible crossflow produced by pressure differences among the formations, whether in the completion ofthe superior zones or during the final well-cleaning process; Scianca and Gimenez (2002) document severaltypes of evaluated completions.

The HPAP-PPD completion technique was applied in conventional gas or gas-condensate reservoirs; atotal of 13 wells where a total of 124 fracturing stages were performed. A 60K CT injector unit and 1 3/4-in.OD CT were used. The main objective for this operator was to reduce completion time in wells located inurban/rural areas where operations must be performed under strict environmental controls. Several authors(Favoretti and Ferrer 2008; Kovalenko 2009) conclude that the pinpoint technique generated a considerabledecrease in operational costs and reduced execution time for fracturing and completing wells. Additionally,it was possible to decrease the generation of formation damage in this type of reservoir, either resulting froma shorter residence time of fluid in the formation or avoiding the drowning of stimulated areas, comparedto using the rigless fracture technique by means of casing. A summary of the main characteristics of thiscompletion type for this operator is presented in Table 1.

The result obtained with this technique motivated this operator to stimulate a new reservoir, therebygenerating multi-target wells. Historically, Quintuco, Lajas (oil and gas producers), and the upper section ofthe Los Molles formations (dry gas producer) were stimulated. The basal section of the Los Molles formationis considered to be low permeability (tight gas) and highly sensitive to damage during well construction.The operator proposed the goal of completing all zones in one well—Los Molles (tight and conventional),Lajas, and Quintuco. These zones would be stimulated selectively, allowing the application of the HPAP-PPD technique.

A total of 30 fracturing stages were selected to be performed: a) basal Los Molles formation—tight: eightfracturing stages (F1 to F8); b) middle-upper Molles formation: 10 fracturing stages (F9 to F18); c) Lajasformation: five fracturing stages (F 19 to F23); and d) Quintuco formation: seven fracturing stages (F24 toF30). The completion strategy consisted of performing well operations in three phases, corresponding toeach of the formations being stimulated. Based on this, once operations for each formation were completed,a wellbore cleanout and mechanical plug setting operation were conducted using a wireline unit. Afterward,the same strategy and procedure was followed as for the previous formations.

A total of 30 days was necessary to perform all treatments in these formations (Fig. 8):

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Figure 8—Completion time for conventional gas well in the Neuquén basin, Operator B (those shown in black were aborted).

• Rigup and rigdown: four days

• Wellbore cleanout and mechanical plug millout: seven days (five days for Los Molles and twodays for Lajas)

• Nonworking days (holidays): two days (Christmas)

• Fracturing operations: 16 days (10 days for Los Molles, three days for Lajas, and three days forQuintuco)

It is important to clarify that a unit time of "day" corresponds to 12 operative hours. The times achievedshowed 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 the Los Molles, and three stages per day wereconducted in Lajas and Quintuco. More details can be found in Bonapace and Perazzo (2016).

Tight GasFrom 2007 to 2013, a pinpoint technique was applied in tight gas wells in the Neuquén basin. OperatorD performed this technique on three wells with an average of five fracture stages. The main activity wasdevelopment by Operator C (Fig. 3b), completing a total of nine wells and 84 fracturing stages in the PuntaRosada formation. The objectives for this operator was to improve completion time in this type of reservoir,achieve a focalized stimulation, and obtain higher production.

Operator C. Historically, this reservoir is completed by fracturing several zones together. During thebeginning of the development of this reservoir, operations were performed using workover units withtubing-packer and mechanical plugs, conventional perforations, and by completing only four fracture stages(Sarmiento 2008). During development, the well geometry was changed, consisting of 4 1/2-in. 13.5-lb/ft,P-110 casing. The next step of the completion was to move into a plug-and-perf completion using limited-entry perforation and a sand plug or flow through composite bridge plug (FTCBP) (Alfaro 2008, 2010).

The unit required application of the HPAP-PPD technique using a 1 3/4-in. CT 60 and 95 K unit. Becauseof overpressure reservoir conditions, it was necessary to perform only two holes per abrasive perforation toachieve the delta pressure required. Throughout the years, problems with the bottomhole assembly (BHA)

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(erosion) were identified. This situation required an additional CT trip to change the BHA after eight to10 hydrajetting trips. Because of this, a new hydrajet tool was introduced. This new tool was designedto maximize its useful life, having a performance improvement of 200 to 300% compared to previouslyexisting tools, as well as reducing costs by eliminating additional trips resulting from tool changes or jeterosion, as documented by Surjaatmadja et al. (2008). Fig. 9 presents comparative images of old and newtools before and after operations performed by this operator. The implementation of this new tool helpedreduce the additional CT trips necessary to change the BHA.

Figure 9—Old hydrajet tool before and after performing 10 abrasive perforations; new hydrajet toolsbefore and after performing 21 abrasive perforations (it was not necessary to change the tool).

The zones stimulated for this operator were the Lajas and Punta Rosada formations. Both have commoncharacteristics, such as low permeability and overpressured zones, which have a pore pressure gradient of0.65 to 0.70 psi/ft. Nevertheless, their thickness and distribution differ. Lajas has a hydrocarbon thicknesson the order of 20 to 45 m, while the Punta Rosada is more likely composed of lenticular sands being closeto one another, with a thickness of 2 to 10 m.

Barbalace et al. (2012) document the completion performed by this operator, which has been calleda hybrid completion because the stimulation treatments of the formations (Lajas and Punta Rosada)used both plug-and-perf and pinpoint techniques. Their work discusses the characteristics of this type ofhybrid completion, the types of stimulations performed for each formation, the operative sequence, andconsiderations during flowback operations and well testing. Seven fracturing stages were performed in 35hours in the Punta Rosada formation with the HPAP-PPD technique, which means one fracturing stage wasperformed every five hours, compared to the 72 hours necessary to perform the same number of stagesusing other completion techniques. Additional benefits included minimizing the contact time of the fluid

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injected into the formation, being able to begin flowback operations faster, cost savings for well completionoperations, and early well production.

The case presented here involves a well in which only the Punta Rosada formation was completed; forthis well, it was necessary to perform 16 fracturing stages. The completion program included a BHA (olderstyle hydrajet tool) modification for Stages 10 and 11. In addition, a pumping diagnostic test was planned toobtain information about excessive friction pressure in the fractures, perforating and near-wellbore (NWB)friction, fracture gradients, and estimated closure stress. This type of injection added one additional hour toeach fracturing stage, except for the first stage in which an extended pressure decline period for 12 hourswas desired.

The well completion time required using this technique was consistent with that documented by Barbalaceet al. (2012). To perform a total of 16 fracturing stages, eight days were necessary (Fig. 10).

• Rigup and rigdown: four days

• Wellbore cleanout: one day

• Fracturing operations: seven days

• Changes in BHA and reservoir conditions: one day (during Stage 8, NWB problems wereidentified, generating additional actions and delay)

Approximately three fracturing stages per day were possible in the Punta Rosada formation. More detailscan be found in Bonapace and Perazzo (2016). A summary of the main characteristics of this completiontype for this operator is presented in Table 1 and 2.

Figure 10—Completion time for tight well gas in Neuquén basin, Operator C.

Shale OilThroughout the past five years, the Vaca Muerta formation was evaluated and developed. It is well knownthat the main completion technique applied in these types of reservoirs (sources rock) is plug-and-perf.Most operators working in this shale formation began evaluating the formation with vertical wells and then

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moved to horizontal wells. In 2013, Operator E decided to evaluate this formation by applying the HPAP-PPD completion technique in a total of 12 fracture stages in a vertical well (Forni et al. 2014).

Operator E. Initially, this operator decided to evaluate the potential of the Vaca Muerta in its area usingexisting wells. After several studies were performed, a group of candidate wells to be used was identified,and a detailed planning of technical and operational aspects was executed (Forni et al. 2015). The firstthree vertical wells were completed using a plug-and-perf technique (sand plug) (Bonapace 2013). The wellgeometry for these wells consisted of 4 1/2-in. 13.5-lb/ft P-110 casing with packers and mechanical plugsin 7-in., 26 lb/ft N-80 casing. Three fracture stages per well were completed using a pseudo limited-entryperforation technique.

The HPAP-PPD completion technique was applied in the Vaca Muerta formation in a shale oil verticalwell with a total of 12 fracturing stages. A 95K CT injector unit, 1 3/4-in. OD CT, and a new stylehydrajet tool were used. The main objective for this operator was to reduce completion time and developan engineering solution to be applied to evaluate this formation in comparison to existing wells.

The case presented (Forni et al. 2015) documented the work flow, engineering solutions, and technologiesapplied to complete this well. Throughout execution of the operation, several changes were necessary:

• Hydrajetting: use volumes between 1,500 to 1,800 lbm of proppant (sand) for perforating, keepthe pumping of 15% hydrochloric (HCl) acid in the procedure (300 gal), and assess in greater detailthe locations of the perforations (i.e., type of rock where perforating).

• Fracture design: the main objective was to place at least 85% of the designed proppant into theformation and use a clean fluid sweep as a contingency when necessary.

• Fracturing fluid: used crosslinked gel for 90% of the treatment and keep the loading gel at 25lbm/1,000 gal minimum.

• Fracturing pump rates: should be maximized, provided the wellhead pressure allows it.

• Proppant: modify the mesh percentages to 50% 30/60-mesh and 50% 20/40-mesh, and performgradual concentration increments of 0.5 lbm/gal in the initial stages.

It was demonstrated that the new hydrajet tool was a viable option to establish connectivity between thewell and formation for stimulating the entire well with a single CT deployment. This was validated because18 consecutive perforations and 12 stimulation treatments were performed without requiring a change out.This was a considerable improvement compared to previous older style tools used in conventional oil, gas,and tight gas well operations, which require at least one change out during a well completion operation ofthis magnitude.

The completion technique (HPAP-PPD) required a total of seven days (one day for rig-up, one day forfinal cleanup, and five days for completion of 12 fracturing stages). It is important to mention that, oncean understanding of the stimulation responses resulting from well and formation conditions was obtained,three stages were performed every 24 hours (Stages 4 to 12) (Fig. 11). It was proven that an unconventionalreservoir, such as the Vaca Muerta formation, can be stimulated using pinpoint techniques by adaptingseveral aspects. A summary of the main characteristics of this completion type for this operator is presentedin Table 1 and 2.

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Figure 11—Completion time for shale oil well in Neuquén basin, Operator E.

Looking ForwardThroughout the past 15 years, a group of pinpoint family of technologies has been developed, covering awide range of reservoir completion conditions. Several authors document these techniques, such as Stanojcicet al. (2009), East et al. (2010), Lindsay et al. (2012), Hartley and Holden (2013), McDaniel (2014), andPawar et al. (2015).

The HPAP-PPD technique was proven in Argentina to be flexible and adaptable to different types offormations and reservoir conditions, providing economic benefits to these applications. Looking forward,this completion methodology has been identified to be used in other conditions or scenarios to providesimilar benefits.

This technique can be used in the following areas:

• Geographic areas without workover units or with increased costs associated with this type of unit.

• Operators with experience, availability, and rigless completion models.

• Projects under development where it is necessary to optimize completion time and costs.

• Development of reservoirs (fields) that do not require evaluation testing by zone beforehand tobe stimulated.

• Well or reservoir revitalization (mature fields or Brownfield)—preconditioning old wells to beapplicable to this technology.

• Nontraditional applications—wells with no nominal internal diameters to create obstruction,restriction, or deformation. Particular cases in Argentina have been evaluated and completionproposals have been presented that apply HPAP-PPD in wells with similar problems to the VacaMuerta formation.

The following benefits can be obtained:

• It has been documented in several publications that HPAP-PPD is a completion alternative withlower costs, less risk, and faster operating times.

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• This technique can help prevent treatment overdisplacement of proppant, which could contributeto achieving higher conductivity in the NWB region.

• CT hydrajetting could be a successful alternative for remedial applications when fracturingtreatments using plug-and-perf or sliding sleeves cannot be performed because of mechanicalissues. New style hydrajetting tools help enhance this benefit.

• Reservoirs that require effectively treating multiple closely spaced entry points but where limited-entry techniques are not working efficiently.

ConclusionsDuring the last decade in Argentina, the implementation of a hydrajet perforating pinpoint stimulationtechnique for well completion has allowed achieving considerable improvements in terms of reducingoperating times and associated costs. This technique has proved its versatility in different reservoir typesand formations. Several lesson learned and improvements have been observed to achieve this success:

• Adaptability: one of the main learnings was introducing changes to account for different typesof reservoirs. Modifications to the type of CT unit (60 to 95K), well geometry, type of rock tostimulate, and fracture design were the main challenges resolved.

• Logistics and planning: continuous learning was maintained over the years with differentoperators for proper coordination of water logistics, proppant, materials, resources, and equipmentto realize completion in the shortest time, preferring to not generate timing offsets that couldnegatively impact the projects.

• Hydrajet tool: the initial tool used (old style hydrajet) in conventional oil, gas, and some groups oftight wells exhibited some erosion (mainly in the last reservoir in harsh conditions). This situationinvolved additional CT trips to change the BHA, increasing the total completion time. A new designhydrajet tool with longer working life was implemented for applications in tight gas and shale oil,which considerably improved completion time.

• Reduced completion time: completion time in conventional oil mature reservoirs has beenreduced up to 65% compared to standard completions (workover unit, tubing-packer-mechanicalplugs). For conventional gas completions, a 40 to 50% reduction was obtained compared to thetraditional plug-and-perf technique. Tight gas wells required only five hours to complete one stage(from one hydrajet to the next hydrajet operation) and eight hours for the shale oil well.

• Production increase: several authors (Forni 2008; Folmer et al. 2008; Favoretti and Ferrer 2008)have documented production increases and higher initial production rates compared to offsetswhere other completion techniques were applied. The results obtained with this technique havebeen attributed to a combination of effects and benefits, such as a) the elimination of the damagedregion (stress cage) in the perforation tunnel, b) creation of a high-conductivity cavity just at theperforation tunnel, c) shorter residence time of the fluid in the formation, d) focalized stimulation,e) high conductivity in the NWB area, and f) strong connectivity well-formation (no overflush).

AcknowledgementsThe authors thank Pan American Energy, Pampa Energía, and Halliburton for permission to publish thiswork. Additional thanks are extended to the staff of the Production Enhancement, Production Solutions PSL,and Global Pinpoint Stimulation Group; Mariano Garcia, Leonardo Canini, Juan Martin Szklarz, and formerHalliburton employee Diego Duran (Pluspetrol) and German Rimondi (Calfrac); for their efforts throughoutthe years to implement this technology. Finally, our gratitude to Buddy McDaniel for his guidance and thevery helpful comments that helped to improve the present and previous work along the last years.

SPE-185478-MS 17

NomenclatureCMHPG : carboxymethyl hydroxypropyl

ISP : intermediate-strength proppantRCP : resin-coated proppant

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