SPE WVS-593.

Vertical Wells Completion in Multilayer Reservoirs. A Decade of Technologies Implemented in Argentina

SPE-WVPS-593J.C. Bonapace & G. PerazzoHalliburton

Abstract

Many fields in Argentina have multilayer reservoirs that require various stimulation techniques, mainly hydraulic fracturing. A variety of formations and types of reservoirs, such as conventional (mature fields) and unconventional (tight gas and shale), are present in the Golfo San Jorge and Neuquen basin. The hydraulic fractures created in these basins present a variety of conditions and challenges related to depth, well architecture design, bottomhole temperature (BHT), reservoir pressure, and formation permeability.

In the last decade, new technologies were introduced and developed to help achieve greater efficiency and reduce time and costs associated with completions for these fields. This paper presents experiences gained using two types of technologies.

First, a new conventional straddle-packer system (SPS) was used in conjunction with a workover unit, which was part of a technological collaboration agreement between an operator and service company. It was mainly applied in conventional reservoirs, mature fields, in wells with up to seven fracture stages, and in new or recompletion wells. Second, a pinpoint technique was used, called hydrajet perforating annular-path treatment placement and proppant plugs for diversion (HPAP-PPD). This technique was applied in new wells (rigless completion) and all types of reservoirs, both conventional and unconventional (tight gas and shale), and allowed performing up to 30 separate fracture stages in a single well, with three stages completed in a 12-hr operation.

These completion methods allowed operators to focus treatments in desired zones with specific treatment designs based on reservoir characteristics. Several case histories are presented for different basins, formations, and reservoirs types, as well as lessons learned and completion time reductions.

Introduction

Hydraulic fracturing is one of the most-widely used stimulation techniques. First application of this stimulation technique dates back to October 31, 1960 in Argentina. Since then, this type of treatment has been performed in five producing basins in the country (Fig. 1).

Throughout the years, constant changes have been made to treatment fluid systems used in these operations, moving from petroleum-based fluids, methanol, CO2 and nitrogen foams, nitrogen-assisted and water-based systems.

These types of stimulation treatments have a variety of requirements for use in this productive basin, which presents a wide range:

• Depths: 300 to 4500 m• BHTs: 100 to 350°F• Reservoir Pressures (subnormal to overpressured)• Permeabilities (high, medium, low, and ultralow)• Types of complex formations, also different types of reservoir

problems (proppant flowback, production of high levels of water).• Reservois as monolayer or multilayer • Wells types as multitarget

This paper documents the experiences, lessons learned, and results achieved with two new completion systems used in the last decade in Argentina for oil or gas reservoirs in mature fields and tight formations in the Golfo San Jorge and Neuquen basin.

Fig. 1—Argentina production basin.

Straddle-Packer System (SPS)

Golfo San Jorge Basin—Operator A. This completion system was developed because the operator needed to improve completion times of its wells. A SPS was developed to test the reservoir before a stimulation treatment (multireservoir layer) that also could be used later for hydraulic fracturing operations.

Thus, a significant reduction in required operation hours could be achieved compared with traditional systems used for the plug-and-packer method. Greater detail on the scope of the project, descriptions of the tool, and the operating sequence are provided by Velasquez et al. (2009).

•The standard well geometry for this operator consisted of vertical wells with 5 1/2-in. casing, K-55, 15.5 lb/ft using 2 7/8-in. tubing, J-55, 6.5 lb/ft for completion activities.

•The best progress in this project was achieved when using the tool for fracturing execution. Initial analysis showed that an average of 15 hr was required to complete the full cycle of performing hydraulic fracturing using the plug-and-packer methodology.

Once development of the tool was completed, a field test period was initiated consisting of three progressive stages (2007–2009). During this period, some modifications and adjustment were made to the tool. The field tests consisted of 55 stages of fracturing performed in 13 wells using different packer spacing (8 to 30 m) and different types of proppants (RCP and white sand) (Arze et al. 2010).


Implementation Phase. Implementation of this tool as part of completion activities for this operator began in mid-2009 to late 2013. In late 2009, a comparative analysis was made to evaluate the tool performance and the new completion methodology. As part of the evaluation process, five fields were selected in which wells were completed using a traditional plug-and-packer system in a total of seven wells. In addition, nine wells were completed using the new SPS completion system. Wells using both applications should meet the following conditions: have the same number of stages or a minimum difference and be completed almost simultaneously to avoid delays caused by climatic variables or weather conditions, as wind and/or snow are typical of the area where the wells exist.In Fig. 2, the wells are grouped by field (Field A to E). The bars show the number of fracturing stages performed by well (left axis), where the black color indicates traditional plug-and-packer completions while red illustrates the new SPS completion system.

The marked points referenced in the right axis show the average time (hours) required per fracturing stage, where blue marks indicate plug-and-packer completions and red marks reference SPS completions. It can clearly be observed that an average of 10 to 16 hr per fracturing stage was required for the traditional completions, whereas the new methodology required between 4 and 8 hr.

This reduction in time for each fracturing stage represents an average decrease on the order of 40 to 63%.

Fig. 2—Wells grouped by field.


A summary of the historical development of using this completion methodology, from the field test phase to implementation to its current use in well completion operations. Throughout the current year, 93 wells have been completed for this operator using this methodology, performing a total of 366 fracturing.Several characteristics about the stimulations treatments and completions are presented in Fig. 3 and Fig. 4:

• Historical Evolution• Number Stages per well• Frac Stages size (proppant lbm)• Maximun proppant concentracion pumped (lbm/gal)• Number of zone treated by Frac Stage• Spacing between packers• Distance between successive Stimulations• Type of proppant pumped

Fig. 3—(a) Historical evolution; (b) fracturing stages per well; (c) fracture size; (d) maximum proppant concentration.

Fig. 4—(a) Number of stimulated zones per fracturing stage; (b) packer spacing; (c) spacing between successive fractures; (d) proppant type.


A summary per year from 2009 to 2013 is presented in Table 1, which details the operating performance. The main variables of each well, including operation times achieved, are shown.

Year 2009 2010 2011 2012 2013

Basin Golfo San Jorge Golfo San Jorge Golfo San Jorge Golfo San Jorge Golfo San Jorge

Formation Mina El Carmen

Comodoro Rivadavia

Mina El Carmen Comodoro Rivadavia


Comodoro Rivadavia


Reservoir Type Sandstone - oil Sandstone - oil Sandstone – oil Sandstone - oil Sandstone – oil Stages per Well 5 5 5 4 7

Depth (m) 2300.0 to 2072.5 2790.0 to 1716.5 2528.5 to 2035.0 1212.5 to 1042.5 2346 to 1726

Packer Spacing (m) 25.6 21.7 24.8 31.5 31.6 and 25.4

Injection Test – Diagnostic Fracture Injection Test (DFIT) No No Yes Yes Yes

Fluid Volume Stage (gal) 6,400 to 10,600 8,200 to 10,700 8,000 to 22,600 9,100 to 16,100 6,900 to 13,000

Amount of Proppant Stage (lbm) 7,500 to 20,600 16,300 to 25,800 18,900 to 60,400 16,100 to 46,600 13,400 to 33,300

Total Fluid Pumped (psi) 36,590 48,740 70,850 44,350 76,120

Total Amount of Proppant (lbm) 70,100 107,300 179,100 118,900 185,500

Type of Proppant RCP RCP RCP RCP RCP

Proppant Mesh 20/40 20/40 20/40 12/20 20/40

Max Prop Concen (lbm/gal) 6 to 7 7 to 8 7 to 8.2 6 to 8.2 6 to 8

Slurry Rate (bbl/min) 15 to 16 14 to 14.5 15.4 to 16 13.5 to 14.8 14 to 16

Wellhead Pressure (psi) 3,150 to 2,950 3,420 to 2,640 4,100 to 3,100 2,570 to 2,200 4,040 to 3,110

Fracture Gradient (psi/ft) 0.55 to 0.63 0.66 to 0.69 0.62 to 0.69 0.66 to 0.69 0.60 to 0.70

Well Control after Fracturing Forced closure Forced closure Forced closure Forced closure Forced closure

Screenout No (1) - Third stage No (1) - Third stage No

Comments — After fourth

stage, rest crew 4 1/2 hr

DFIT: 60 min for pressure decline

and analysis


and analysis


and analysis After fourth

stage, change spacing tool [pull

out of hole (POOH) and run in hole (RIH)] 12

hr Fracturing Time per Stage (hr:min) 24:30 18:55 32:00 24:45 33:30

Time (min/stage) 294 227 384 371 287

Time (hr/stage) 5 3 3/4 6 2/4 6 1/4 4 3/4

(Table -1)

Hydrajet Perforating Annular-Path Treatment Placement and Proppant Plug

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

Fig. 6—(a) Wells completed by basin; (b) wells completed by operator; (c) wells completed by reservoir type; (d) wells

completed by well geometry.

Fig. 7—(a) Conventional gas well completion; (b) conventional oilwell completion; (c) tight gas well

completion; (d) shale oilwell completion


for Diversion (HPAP-PPD)Neuquen Basin—Operator B. The HPAP-PPD technique has been used by this operating company since 2007 in a total of 13 wells (124 fracturing stages), mostly in conventional gas wells.A multitarget well for this operator was evaluated and developed without using standard completion techniques. Over the years, the operator included new reservoirs to be stimulated, thereby generating multitarget wells. Usually, the following zones are considered for stimulation: Quintuco and Lajas (oil and gas producers), and the upper section of Los Molles (dry gas producer). Los Molles formation is exclusively a dry gas producer, where its basal section is a reservoir with very low permeability (tight gas) and is highly sensitive to damage during well construction. As such, the basal section can experience damage during completion operations into the upper reservoirs, so the completion strategy used is important.The operator proposed the goal of completing all zones in the wells—Los Molles (tight and conventional), Lajas, and Quintuco. These zones would be stimulated selectively, allowing the application of the new technique.A total of 30 fracturing stages were selected to be performed:

a) basal Los Molles formation—tight: eight fracturing stages (F1 to F8); b) middle-upper Molles formation: 10 fracturing stages (F9 to F18); c) Lajas formation: five fracturing stages (F 19 to F23); d) Quintuco formation: seven fracturing stages (F24 to F30).

The completion strategy consisted of performing well operations in three phases, corresponding to each of the formations being stimulated. Based on this, once operations for each formation were completed, a wellbore cleanout and mechanical plug setting operation was conducted using a wireline unit. Afterward, the same strategy and procedure was followed as for the previous formations.


for Diversion (HPAP-PPD)

Fig. 8—(a) Fracture gradient; (b) total proppant in formation.

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

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



Fig. 9—Completion times (those shown in black were aborted).

Summary. A total of 30 days was required to perform treatments in these formations (Fig. 9):

•Rigup and rigdown: 4 days•Wellbore cleanout and mechanical plug millout: 7 days (five days for Los Molles and two days for Lajas)•Nonworking days ( holidays): 2 days (Christmas)•Fracturing operations: 16 days (10 days for Los Molles, three days for Lajas, and three days for Quintuco)

It is important to clarify that a unit time of “day” corresponds to operative day of 12 hr. The times achieved showed that for the basal Los Molles formation, one stage per day could be performed, and in some cases, two stages per day. Two stages per day were achieved in Los Molles, and three stages per day were conducted in Lajas and Quintuco.


for Diversion (HPAP-PPD)Neuquen Basin—Operator C. This completion technique was introduced for Operator C in 2008. To date, nine tight gas wells and 84 separate fracturing stages have been completed using the pinpoint technique (Fig. 7c).

The zones stimulated for this operator are the Lajas and Punta Rosada formations. Both have common characteristics, such as low permeability, in the range of 0.01 to 0.001 md, and overpressured zones, which have a pore pressure gradient from 0.65 to 0.70 psi/ft. Nevertheless, their thickness and distribution are different. Lajas has a hydrocarbon thickness on the order of 20 to 45 m, while Punta Rosada is more likely composed of lenticular sands being close to one other with a thickness of 2 to 10 m.

Barbalace et al. (2012) document the completion performed by this operator, which has been called a hybrid completion because the stimulation treatments of the formations (Lajas and Punta Rosada) used both plug-and-perf and pinpoint techniques.

In the Punta Rosada formation, a well was completed that required 16 fracturing stages. The completion program included a BHA modification for Stages 10 and 11. In addition, a pumping diagnostic test was planned to obtain information about excessive friction pressure in the fractures, perforating and near wellbore friction, fracture gradients, and estimated closure stress. This type of injection added one additional hour to each fracturing stage, except for the first stage in which an extended pressure decline period for 12 hr was managed.

Fig. 10a shows the fracture gradient values observed during these tests. All zones clearly show values above 0.80 psi/ft, including some cases with values higher than 0.90 psi/ft. Fig. 10b indicates the amount of proppant agent placed into the formation. Treatment proppant volumes varied from 30,000 to 155,000 lbm. A unique screenout occurred in fracturing Stage 8, allowing only 92% of the total treatment to be pumped into the formation.

Stage 8 presented higher operative complexity, which caused delays in the completion times. Once fracturing Stage 7 was complete, operations moved to the next zone, performing an abrasive perforation and later a calibration injection test. Higher friction values were observed in the NWB region. To mitigate this elevated friction pressure, a proppant sand slug was placed into the treatment. Once this proppant slug reached the perforations, a sudden screenout occurred. The operator decided to perform wellbore cleanout using CT, and an insubstantial reservoir admission was observed, reaching the maximum working pressure allowable in the system.



Fig. 10—(a) Fracture gradient; (b) total proppant placed in formation.

A 15% hydrochloric (HCl) acid system was pumped through the CT, with no indication of improvement. CT was POOH to determine the BHA condition; a new one was installed, and CT was RIH again to perform a new abrasive perforation, which allowed pumping a treatment until screenout occurred at the end of the flush.


for Diversion (HPAP-PPD)Summary. The well completion time required using this technique was consistent with that documented by Barbalace et al. (2012). To perform a total of 16 fracturing stages, eight days were required (Fig. 11):

•Rigup and rigdown: 4 days•Wellbore cleanout: 1 day•Fracturing operations: 7 days•Changes in BHA and reservoir conditions: 1 day

Approximately three fracturing stages per day were possible in the Punta Rosada formation.

Fig. 11—Completion times for Operator C.

Conclusions

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

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

Acknowledgements

The authors thank Halliburton for permission to publish this work and all staff of the Production Enhancement and Production Solutions PSL for their efforts over the years to implement these technologies.

Special thanks is offered to Federico Kovalenko, German Rimondi, Mariano Garcia, and Federico Sorenson

Thanks you !!!

SPE WVS-593.

Engineering

Transcript of SPE WVS-593.