SPE-172724-MS

Conditioning Pre-existing Old Vertical Wells to Stimulate and Test VacaMuerta Shale Productivity through the Application of Pinpoint CompletionTechniques

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.

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.

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 informationthat 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 reservoircharacterization/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 belowthe VM source rock. Presently, with these reservoirs depleted in many areas, existing wells are often agreat opportunity to investigate this upper unconventional target. Unfortunately, most of these wells arenot 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 ofunconventional reservoirs.

This paper discusses the preparation of a well originally drilled in 1974 to allow for the new objectiveof 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, 12single-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 packerwere installed.

IntroductionThe present work details operations performed for the intervention of the fourth well of a developmentproject 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 hadalready been made to improve the economic performance of the well (increase production and/or reducecosts). To understand the steps taken in the well, it is necessary to review previous experiences.

The operation described in this paper was designed and executed within the framework of an agreementbetween the producing company and service company to share research and development of thisnon-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 thearea known as El Salitral, and oil is produced in the northern part, known as Agua del Cajón, mainly fromthe Tordillo, Lajas, and Quintuco formations (Fig. 2a).

Geologically, the Agua del Cajón area is located in the eastern center of the Neuquén basin, over thenorthern flank of the Dorsal de Huincul. El Salitral field, a gas producer of the Cuyo group, is located overa huge structural spur/nose of transgressive nature in the lower block and north of the Huincul fault. Tothe 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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change clashes with a transfer zone, forming a new structure in the eastern region of the block, which isa 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 typicalstratigraphic column for the Agua de Cajón field. The genesis and characteristic of the VM formation havebeen 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) withbetween 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 TypeII, with a variation between Type I/II. The maximum temperature and productivity index (PI) valuesindicate that the thickness of the center and northern area (Agua de Cajón) are in an oil window, whilesouthward is an early oil window or an immature formation (Villar 2011).

Background and StudiesThe 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 drillingand exploitation of petroleum were very active in the 1970s and 1980s and development was completedwith 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). Ithad vertical wells that crossed the VM during drilling, casing, and cementing, in general, with goodformation information available, which could be used to study unconventional shale resources in terms ofcost 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 geologyand reservoir using three-dimensional (3D) seismic reprocessing (determination of the lateral continuityand 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 toopen the well (Fig. 3a).

Toward the beginning of 2012, the second phase of the study continued, which consisted of theevaluation 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.

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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 beensqueeze cemented). One significant point is that these wells were not designed to withstand the pressurerating requirements of a shale-type completion; they presented a variety of geometries and oldertechnology (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., 23lb/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 wereselected based on the conditions of reservoir, well, and logistics to be operated (Fig. 3b). These wells hadthe 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 andresults were stated, as well as the developed learning curve. For the execution of the work in each of thewells, it was necessary to condition them (remove existing installations, isolate lower levels under theVM, 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 hada total thickness of 160 m (2,600 to 2,440 m TVD), of which it was decided to stimulate only 100 m. Goodinformation was provided by the openhole log, the cement log was updated (good condition), and therewere perforations open in Quintuco (upper VM); additionally, very good logistics existed because it waslocated 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 thebottom of the VM and using a 4 1/2-in. tubing, 13.5 lb/ft - P110 with a mechanical packer to isolate allof the interval of interest. Perforations were made through tubing, and after stimulating each zone, theywere 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 totalrecorded time of nine days (216 hours), injecting a volume of 28 bbl of treated water at a flow rate of 7bbl/min, obtaining a 0.96 psi/ft fracture gradient. For the analyzed time period, the formation closurepressure was not identified. Three hydraulic fracturing treatments were performed in this well. More detailof this process is shown in the first column of Table 1 and Fig. 5a.

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Figure 4—DFIT (a) chart operation and (b) analysis “G Function.”

Table 1—Details of hydraulic fracturing treatments.

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This first well objectives were achieved satisfactorily, with all stimulation treatments using theproposed completion methodology (plug below, treat through 4 1/2-in. tubing with a packer), the wellresponded 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 formationhad 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 ofthe rock), the cement log was updated (good condition), and no perforations existed above the VMformation. It was decided to record the microseismic data during fracture stimulation and possibly use anearby well as a monitor well (400 m away).

Based on the experience gained in Well A, it was decided to apply the same completion methodologyused previously. For Well B, again three stimulation treatments were performed with modifications totheir 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 treatmentsproposed with the completion methodology again completed. The well produced oil naturally and showedgood microseismic results (Fig. 6), which helped obtain a better understanding of the stimulationtreatments as well as allowing changes to be made. The pressure buildup test data of Well B yieldedvaluable 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.

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Well C. Recompletion of the well was performed in April 2013. In this well, the VM formation showeda total thickness of 165 m (2445 to 2280 m TVD), of which it was decided to stimulate only 150 m. Therewas not sufficient openhole log or well information, so it was decided to use a cased-hole log (pulsedneutron � gamma ray spectral) and a neural network, as presented by Buller et al. (2010). A nearby wellwith sufficient openhole information was identified and used in training and to calibrate the well. Well Cwas 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 wasdecided to again record microseismic but this time using two monitor wells because of the proximity ofa 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 madeto develop more conductive fractures (Table 1 and Fig. 5c).

The objectives were successfully achieved. Once again, the well could be completed in its entiretyusing the methodology of the proposed completion method. The well produced oil naturally afterstimulation and showed good microseismic results. Also, the neural network training/calibration andapplication thereof was successful (discussed in more detail later).

Lessons Learned After the three pilot wells were realized, a review of the same wells was conductedfrom 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).

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● 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-existentopenhole information.

● A learning curve was developed in the stimulation designs for determining designs to create moreconductive fractures (Fig. 7).

● It was possible to adapt the logistics (old locations, dimensions) and water supply to perform thispilot plan.

New Approach

Because of the positive results from the pilot project, it was decided to attempt to improve thedevelopment of the VM formation by making older vertical wells economically viable. The first step wasto 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 wellcompletions), 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 theproductivity 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 usingevaluation 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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others did not, which demonstrates inefficiency of the stimulation treatments (service companyexperience).

X Tracers in fracturing fluid. Zones were identified that had more recovery fluid injectedcompared to other zones, even though similar treatments were performed in each (servicescompany 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 concentratedand zones in which very low microseismic activity occurred.

Accordingly, the idea was proposed to stimulate an area of greater thickness, as well as perform thestimulation treatments more selectively by focusing on the details of each section (heterogeneous) toincrease well productivity and improve the economics of the project. A process was designed to initiatechanges in the completion method that would be able to achieve the previously mentioned objectiveswhile 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 offracture 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 themethodology of completion used (Fig. 8a) in the pilot plan. This greater number of operations wouldrequire 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 thecompletion (Forni et al. 2014).

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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 consistsof an abrasive perforating through CT and subsequent pumping of the treatment into a fracture throughthe annular space (with CT still in the hole, but with the tool pulled above the perforated interval), andthen leaving a sand plug after the fracturing stage to isolate the stimulated zone. This provides the benefitof 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 invertical wells and was quickly applied in horizontal wells (McDaniel et al. 2006). In Argentina, it has beenused since 2006 (Bonapace et al. 2009) and has been tested on a wide variety of conventional and tightreservoir 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). Thiswell did not have a good set of openhole logs, so the approach was to apply the technique used in WellC (which already had a well calibration). The well geometry was similar to previous ones (Type 1) andhad perforation openings in the Quintuco (above the VM formation). Additionally, pre-conditioning of thelocation and wellhead was required.

The existence of open perforations in the Quintuco required preparing the well, placing a plug on thebottom 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.

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achieve isolation below the Quintuco perforations. Analysis was performed by evaluating a number ofvariables: well geometry, pumping flow rate, flow restrictions (diameters), abrasive perforation conditions(hydrajet), and stimulation requirements and conditions. On the basis of the completion model usedpreviously (conditioning wells in the pilot plan), work proceeded to assess the different possibleconfigurations in which this methodology could be applied. It was considered to use 4 1/2- or 5-in. tubingoptions, 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 internaldiameter (ID) to allow the passage of the CT bottomhole assembly (BHA); traditional high-pressurepackers do not have sufficient diameters. An alternative was to use a swell packer with the ability towithstand the designed pressures and having a sufficient ID. The work flow for the new completionconcept is shown in Fig. 9.

Finally, based on analyses and the availability of pipes, the CT outside diameter (OD), packer, andhydrajet tool available in the country were selected, and the configuration elements necessary to performthe 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 � 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).

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● 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 wellthroughout all of the treating stages, it was necessary to modify the outline of lines and valves that wereplaced 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 requiredto allow the passage of the BHA on the CT. Existing technology (swell packer) was used to adapt the newnon-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 sealshould support the high working pressure, temperature, as well as the cyclical effects of the successivefracturing treatments while maintaining its anchor strength.

Given the pressure and temperature conditions and the application type, a series of simulation/modelingwas 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 flowrate, working pressure, fluid density, proppant concentration, and even extreme conditions, such as ascreenout. A hydrocarbon sample (determination of viscosity) was taken to simulate swelling time. Thefinal design included a maximum pressure 10,000-psi difference, 120,000 lb of anchoring strength, anda total swelling time of 10 days (Fig. 10). Once the swelling time was complete, it would be necessaryto apply 30,000 lb of weight (slack off).

Conditioning of Well and PreplanningIn this conditioning stage, the purpose was to prepare the final geometry for the pinpoint completion. Aworkover rig was required because complications with some of the required tasks could cause majorchanges in the plan (increments of time and cost) or even premature stoppage, forcing a new candidatewell 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.

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Some of the operations vital to performing the completion of the well are discussed in more detail inthe following sections.

LoggingCement 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 theother hand, it was not possible to assess the zone in which the swell packer would be set. It was decidedto 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 wasa lack of complete openhole data to identify zones to stimulate. Because of this, cased-hole loggingmethodologies, such as those presented by Pitcher et al. (2012) and Dingding et al. (2004) for thegeneration 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 andselection 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 toapply the cased-hole methodology and neural networks to generate the reservoir information necessary forthe evaluation of the project.

Therefore, in wells without complete openhole logs, logging with pulsed neutron was performed, andthen a corresponding system of neural networks was assembled and trained. It is important to rememberthat the vast majority of the wells in the area have the same mechanical configuration. This is valuablebecause 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 soniccompression. For the purposes of applying the petrophysical model already adjusted for the VMformation, it was necessary to continue with a triple combo. A spectral gamma ray and pulsed neutron logwas 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 twotracks of Fig. 12c, the right curves show the neutron and density log of the open hole and overlap, whichwere calculated from the pulsed neutron log and original neural networks system (PHIN_CH and

Figure 11—Workover operations: conditioning the well.

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RHOB_CH). Fig. 12b shows the corresponding normalization process, which was important in thisworkflow.

Plug and Integrity Test After running the cased-hole logs, tubing was run-in-hole (RIH) to set a plugto 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 theentire 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, aswab test was performed to determine whether the perforations contributed or received fluid, as well asto evaluate the type of produced fluid. After recovering the column of fluid and for five hours longer, therewas a production flow rate of 0.5 m3/hr of 90% water. Based on this result, the proximity between theperforations and the location of the swell packer (10 m) was recommended as a precaution to displace allof 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 thetime stipulated for swelling (swelling time), and finally applying weight (set weight). Details of thefollowing 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.

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● Move swell packer to the final position (set depth) and pump through tubing to unpack the swellpacker.

● 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 thelocation to be able to perform the intervention (Fig. 13a). This well surface location did not have the samedimensions as those usually observed in new shale well locations, so it was necessary to make changesto the location of trailer offices, chemical storage areas, proppant storage, returned fluid storage, and watertransfer systems (Fig. 13b).

The water source was fresh water from the Limay river. It was transported by trucks to a main storagecenter (tank existing in the field) located approximately 800 m from Well D. From the center of thestorage, 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 threefracturing stages (Fig.14).

Figure 13—(a) Wellsite dimensions and (b) equipment layout.

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At the wellsite, two workover pools were used to store fluid returned from the well and to pump freshwater to refill the frac tanks. The field camp was located 500 m away, where the chemical and proppantwere 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 theapplication of a new completion concept that is more focused and therefore selective for the placementof stimulation treatments. Once the processed cased-hole log was obtained, the entire set of synthetic logsand 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, unconfinedcompressive strength (UCS), total organic content (TOC), shale porosity, and volume of clay can beobserved.

Figure 14—Water management plan: field camp.

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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% � 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 fluidof 6% HCl-1.5% HF acid) was used before each treatment, as well as a new clay stabilizer. A summaryof 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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Operation of Well DThe following sections describe the pinpoint (HPAP-PPD) stimulation technique and the equipment usedto perform it (CT, BHA), and surface wellhead equipment), and a summary of the stimulation operationsperformed is provided.

Pinpoint Technique The HPAP-PPD process in a vertical well is illustrated in Fig. 16. The jetting-toolassembly is first positioned at the lower-most intended fracture position (Fig. 16a). An abrasive slurry isthen pumped into the CT and jetted out of the tool at high pressures to form perforations (Fig. 16b). Atthis time, fracturing-pad fluid is pumped through the annulus, increasing pressure rapidly to cause afracture to be generated (Fig. 16c). This step is continued for several minutes to establish a goodextension, after which the flow rate is increased to the intended fracturing rate and later the proppant slurryis started and the tool is pulled above the perforated interval. The CT tubing rate can then be reduced toa minimum so that it can serve as a dead string in the well for pressure monitoring. This situation alsoprovides a means for rapid corrective action, should an unwanted situation develop. The proppant slurryis then pumped into the fracture, and when the fracture is extended to satisfaction, an induced screenoutis attempted to form a solid pack in the fracture (Fig. 16d), and a “plug” of high-concentration proppantin a viscous gel is left within the wellbore. In some situations, the tubing flow rate is required for fracturedevelopment. In such cases, the tubing rate is maintained throughout the treatment and only reducedduring the tip screenout stage. The CT is then lowered down to the next perforating position whilereverse-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 fromthe well.

Table 2—Summary of the main features and volumes of each of the treatments.

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The equipment used for the completion of Well D using the pinpoint technique follows:

● CT Unit (Fig. 17a):

X Injector: 95K pool capacityX CT: OD 1 3/4 in., QT 1000, 17,200 ft

● BHA (Fig. 17b):

X CT connectorX CT de-connectorX Hydrajet (two jets 3/16-in., 180°)X Ball subX Mule shoe

● Surface Equipment—Wellhead (Fig. 17c):

X Side windows stripperX Quad blowout preventer (BOP): 4 1/16 in., 10,000 psiX Lubricator: 4 1/16 in., 10,000 psiX 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.

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X One flow cross: 7 1/16 in., side inlet 2 1/16 in. 1502X Dual combi BOP: 7 1/16 in., 10,000 psiX 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 stimulationand abrasive jets required. This new tool was designed to maximize its useful life, having improvedperformance of 200 to 300% compared to previously existing tools, as well as reducing costs byeliminating 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 jetperforations (had to be repeated or new ones added) and with the stimulation treatments (screenout). Thisled to a series of changes in the fracturing treatment to allow adjustments to the well and formationconditions. These modifications allowed the development of this lower part of the well during the rest ofthe 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 depthof the mechanical plug (2605 m) was checked. Then, the well fluid was changed to oil (to activate theswell packer) by fluid completion (fresh water, clay, and surfactant inhibitor). The CT system’s depth wasadjusted using the depth plug measurement. Afterward, the BHA was positioned at the depth for the firstabrasive perforation.

Zone 1Abrasive 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), pumping1,600 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 wasdecreased 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 wasused. One mesh size smaller than that traditionally used (20/40) was chosen to assess whether such cuttingsand could be forced into the formation ahead of the pad from the surface without requiring reversecirculation 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 waspumped according to the program but ended suddenly because of increasing pressure and screenout. TheCT pressure (pseudo-dead string) showed a negative trend during pumping of the pad and the firstconcentrations, then a flat pressure response was observed during 1 lbm/gal 30/60-mesh. An abruptpressure 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 firstfracturing stage.

20 SPE-172724-MS

Modifications Based on these observations and after an analysis of the operation, it was decided tointroduce the following changes to the next stage: increase the percentage of crosslinked fluid (change thefluid, use crosslinked fluid as the entire volume of the pad instead of slickwater), evaluate the pumpingof a clean fluid sweep between the proppant mesh increases, and maximize the flow rate depending onthe pumping pressure.

Zone 2Abrasive 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-acidpad), high pressure was observed, which made it impossible to achieve the designed flow rate. It wasdecided to create a new perforation at 2547 m but batch pumping of acid (HCl acid) was removed fromthe process. Once a displacement volume of 900 gal was in the annular space created by the abrasiveperforation, the annulus was closed and breakdown pressure (5,881 psi) was observed. Pumping of thefracturing treatment was started to force the entry of cutting sand from the perforation process into theformation.

Stimulation First stage alterations were introduced in the pumping schedule. Pumping began at anannular flow rate of 24.3 bbl/min and 7,350-psi wellhead pressure. A sweep of clean fluid was pumpedbetween 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 achange was made to use 1.5 lbm/gal of 30/60-mesh proppant, which resulted in a positive increase. Afterthe 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

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 tocontinue 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 moregradual (smaller step changes), and modify the percentage of proppant mesh sizes to 50% 30/60-mesh/50% 20/40-mesh.

Zone 3Abrasive 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 wasobserved. 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 topump 400 gal of 15% HCl acid through the CT. On entering the formation, the HCl acid resulted in anobserved pressure reduction of 1,600 psi. It was finally decided to make an additional abrasive perforationat 2534 m and again include the HCl acid in the cutting sequence. The new perforation resulted in abreakdown pressure of 4,900 psi with good admission (connectivity).

Stimulation Modifications to the pre-acid (HCl-HF acid) stage were considered for the stimulationtreatment because expected results were not observed when it entered the formation (pressure drop). Allof the 30/60-mesh proppant was placed in the formation at a maximum concentration of 2.0 lbm/gal, andthen 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 withthe proppant mixture as observed in Zone 2. A sand plug was mixed and the final flush began, but it couldnot be completed because of a sudden increase in pressure (screenout). Even though the operation endedin a screenout, 96% of the planned proppant was placed. After the screenout, reverse circulation of theproppant was performed (required 2 hours), and a pressure test (positive) was conducted on the sand plugto help ensure isolation of this third stage.

Modifications The principal objectives were achieved: place in the formation at least 80% of thedesigned proppant; use crosslinked fluid in 90% of the treatment; keep the gel loading at 25 lbm/1,000gal; 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 4Abrasive 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 inpressure was observed, reaching maximum pressure. It was again attempted to perforate, withoutfavorable 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 2516m. For this additional perforation, the HCl acid was removed. Once a displacement volume of 900 gal wasin the annular space created by the perforation, the annulus was closed. A breakdown pressure of 9,000psi 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 perforationsuncovered. An admission test was performed through the CT, and then 500 gal of 15% HCl acid waspumped. 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 mixedgradually, and the pressure trend (pseudo-dead string) was negative until a concentration of 1.5 lbm/galwas reached, at which point it stabilized. According to the pressure response, it was decided to continue

22 SPE-172724-MS

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 at3.0 lbm/gal and begin the final flush. The flow rate was decreased, inducing a screenout (Fig. 18, Stage4). After the screenout, reverse circulating the proppant was performed (required 1 hour), and a successfulpressure 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 followingchanges 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 thepumping of HCl acid in the procedure (300 gal), and assess in greater detail the locations of theperforations (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

All stimulation treatments were completed by applying these modifications and without encounteringsignificant problems (Fig. 18, Stage 8 and 12), except for sudden screenouts that occurred in Stages 5 and9, which were below the proposed target (85% of proppant in the formation). Final results for the 12stimulation 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 showsthe 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

1.06 psi/ft were observed for the VM formation; however, previous stimulation treatments in this fieldnever recorded a FG greater than 1.0 psi/ft. For reference, both Figs. 19a and 19b indicate the value ofa 1.0 psi/ft FG with a dotted line.

Fig. 19C shows the percentage of proppant in the formation compared to the design, indicating twolines of reference corresponding to 50 and 90%. Also, each stimulation treatment is shown, with the colorrepresenting the degree of severity of the screenout, if one occurred. The circles correspond to normaloperation, 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 (lightblue). It can be observed that the percentage from the treatment designs was 55%, but after themodifications were applied, the average used was on the order of 85%. Only Stage 1 had a value similarto that designed.

Fig. 19E shows the percentage of proppant mesh (30/60) designed versus that actually used; the designwas 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 than50% because for the first two stages, and as a result of the sudden screenout, the highest percentage ofproppant placed in the formation was 30/60-mesh. Stage 3 was the first in which the mesh-sizemodification 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 fivestages, 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, redcrosses).

Discussion

Additional FrictionIn 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 (� 45°) to the fracture plane, causing the observed excessfriction. An improved alternative would be to use a three-hole, 120° phase configuration; this wouldrequire 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 locatedin the lower section of the VM formation (Stages 2, 3 and 4). The fourth was performed in Stage 10. Moredetailed analysis of the perforations locations from the well log showed that Stages 2, 4, and 10 werelocated in zones with high lamination in brittle sections and small thickness. Because of this, the locationsof the rest of the perforations were revised, changing the depth in Stages 5, 6, 11, and 12 (compare thehydrajet proposed and performed depth in Tables 2 and 3).

Variation along the WellThere was a clear difference in the behavior of the abrasive perforation and stimulation treatments alongthe verticality of the well. A lower section comprised the first five stages and an upper section comprisedthe seven remaining stages, which were zones with more carbonate. This segmentation in the vertical wellshowed that the lower stages had problems initiating the treatment (connectivity between the well andformation), 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 experiencesignificant problems at the beginning of the stimulation treatment, even allowing placement of the

SPE-172724-MS 25

designed concentrations of proppant (4.0 lbm/gal). However, the FG values along the verticality of thewell were normal (0.98 to 1.06 psi/ft).

ConclusionsCompleting old wells in the VM formation using a pinpoint stimulation technique was proposed. A workflow of engineering solutions, existing technologies, and remediation of adverse operating conditions wasdeveloped and executed. The main achievements and conclusions are summarized below:

● The use of a cased-hole logging methodology (pulsed neutron � neural network) in old wells withlittle openhole log information allowed synthetic curves to be generated that could be used toperform a more consistent interpretation of the VM formation, allowing the identification of zoneswith 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 fulfilledthe requirements of flow rate and pressure necessary for the entire completion of the well (12stages).

● It was demonstrated that the new hydrajet tool is a viable option to establish connectivity betweenthe well and formation for stimulating the VM formation with a single CT deployment. Proof ofthis is that it allowed for 18 consecutive perforations and 12 stimulation treatments withoutrequiring a change out. This is a considerable improvement compared to previous older style toolsused in this type of operations, which require at least once change out during a well completionoperation 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 tomention that once an understanding of the stimulation responses resulting from well and formationconditions 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 treatmentsto this technology (modification of the type of fracture, gel loading, pumping schedule, andpercentage of mesh types used).

● The VM formation can be hydraulically fractured at a low flow rate (18 to 24 bbl/min) and normalpressure (7,000 to 8,500 psi), consuming less horse power (on average between 3,450 to 4800HHP) using less resources (pumping equipment).

● Previous perforation and sand plug completions (Wells A, B, and C) used an initial flow rate of1.8 to 2.3 bbl/min per hole; Well D, completed using the HJAF technique, used a rate of 4 to 12bbl/min per hole, which is a higher value and energy to initiate and propagate the hydraulicfracture.

A correct evaluation of the infrastructure required for the execution of the project was necessary. Adetailed plan of work (with a large number of operations) was executed to prepare the well and leave itin 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 twocompanies (operator and services) was developed to meet the objectives and challenges, which not couldhave 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 ofwriting this work, they were still being determined. The main objective was to demonstrate a workingmethodology despite the particular outcome of each well.

26 SPE-172724-MS

AcknowledgementsThe authors are grateful to the management of CAPEX and Halliburton for permission to publish thiswork. They also thank all those who participated in the project and the preparation of this publication, inparticular

● CAPEX: Gabriel Irazuzta, Jorge Ferraris, Daniel Huenuhueque, Nicolas Fumagalli, and MarceloBelièra for effective work in the development and preparation of the well, and geologist CarlosGomez for contributions in the technical content of this publication.

● Halliburton: Matthew Sharp, Dustin Holden, William Harbolt, Germán Rimondi, and EstebanPatch for operational support in the execution of the work.

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