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.

A multistage fracturing treatment was performed in two adjacent horizontal wells (Escobal 197 and Escobal 195) in Chicontepec basin. The alternating sequential hydraulic multifrac in two parallel horizontal wells was planned and performed to create a high-density system of low-complexity planar fractures between the horizontal wells, to maximize the contact area with the reservoir and increase the stimulated reservoir volume (SRV). The wells were drilled perpendicularly to the expected fracture azimuth in Pechi-B formation and were completed as openhole using a ball-and-sleeve completion strategy. Thirty-two fracturing stages (16 stages per well) were selected based on an integral analysis of geological, petrophysical, and geomechanical disciplines. This completion technique has been the first stimulation treatment of its kind in Mexico. The fracturing entails adjacent wells in sequence, enabling one well to hold fracture pressure while the adjacent well is being fractured and it also maximizes the exposure of new reservoir rock. The fractures then avoid each other because of the stress pattern set up in the pressured well. The two adjacent horizontal wells were successfully stimulated in 108 hours of continuous work, pumping 95,000 bbl of fracturing fluid and 8.6 million lb of ceramic proppants. The stimulation technique reduced the stimulation cycle time to just four days, and the initial production of the two wells was more than 8,320 B/D, which was more than 10 times the average initial production in the area. The production later stabilized at 2,517 and 1,011 BOPD, respectively. The two horizontal wells produced 240,000 barrels in 90 days of cumulative production, which exceeds 14 times the average of cumulative production from the conventional wells in the field. The application of this completion technology was considered successful, and now it is extending to other fields located in the basin of Chicontepec.

Unconventional reservoirs, such as the Chicontepec basin in Mexico, require the stimulation of large volumes of reservoir rock to improve production results. A second horizontal well was completed successfully using multistage fracturing with an unconventional method in the basin. This well will be referred here as Coyotes 2H. Five fracturing stages were performed over the 900 m of lateral, each one using three spaced clusters of hydrajetted perforations. The first two stages were monitored using downhole microseismic monitoring. A 40% increase in production was achieved compared to the first lateral well completed in this field, which will be referred to as Coyotes 1H.As the design changed from the first horizontal well, the second lateral used three times the number of perforation clusters, but the same number of fluid entry points (perforations) compared to the first completed lateral well. Five fracturing stages were pumped at 60 bbl/min placing a total of 3.2 million lbm of sand white and using 26,000 bbl of fluid; these volumes of proppant and fluid were similar to the first horizontal well. The treatment fluid was designed to improve the coverage of the reservoir using hybrid fluids consisting of linear and crosslinked gel to achieve a better stimulated reservoir volume (SRV). The first lateral was completed using crosslinked gel as the primary fracturing fluid.Microseismic downhole monitoring allowed measuring the fracture geometry and verifying that the objectives were achieved. The main objectives were to determine if the fracturing treatments would generate upward fracture height growth into the Z-100 formation and compare the SRV measurement of Coyotes 2H to the results of the previously mapped Coyotes 1H lateral. The objectives were achieved during the treatment, and the production results were favorable because of the improvements in the completion process.