One of the most promising targets for resource-rock stimulation in South America is the Vaca Muerta (VM) shale in western Argentina. It is common practice for operators to begin exploration projects with vertical wells; however, in the Neuquina basin, most already-existing vertical wells are not viable candidates to assess the VM because they were not designed as shale-type completions. This paper discusses the preparation of a well originally drilled in 1974 to allow for the new objective of hydraulic fracturing the VM shale, to test the productivity of its different intervals.
Introduction
This field consists of three main formations—Los Molles, Tordillo, and Lajas—and oil is produced in the northern part, known as Agua del Cajón. In the Agua del Cajón area, the VM formation consists of mudstones and, very sparingly,wackestones.
The maximum temperature and productivity-index (PI) values indicate that the thickness of the center and northern area is in an oil window, while southward is an early oil window or an immature formation. The Agua del Cajón has two distinct areas for its history and development—a central zone gas, currently in full production (El Salitral field) and a north zone (Agua del Cajón), the drilling and exploitation of which were very active in the 1970s and 1980. Development was completed with a secondary-recovery operation in the 1990s. The latter zone had approximately 30 wells, which had exhausted their economic output from productive areas.
Phase 1—Study.
Initially, of the 30 wells in the area, only 22 were able to be operated, and only 11 of those had goodquality cement covering the VM formation. One significant point is that these wells were not designed to meet the pressure-rating requirements of a shaletype completion; they presented a variety of geometries and older technology. A pilot plan was initiated for the evaluation of three wells—Wells A, B, and C. Candidates were selected on the basis of the reservoir and well conditions and the logistics to be operated.
Phase 1—Pilot Plan.
A summary of each of the wells was established in which the main objectives and results were stated, as well as the developed learning curve. For the execution of the work in each of the wells, it was necessary to condition them. Details of the pilot plan for each well, and of the good results experienced for each, are provided in the complete paper. Because of the positive results from the pilot project, it was decided to attempt to improve the development of the VM formation by making older vertical wells economically viable.
Phase 2—Feasibility of New Completion Plan.
To achieve the goals of the new completion plan, it was decided to use a pinpoint completion type called the hydrajet-perforating, annular-path treatment placement with proppant plugs for diversion (HPAP-PPD). A candidate well was then selected to evaluate the implementation of this new approach (Well D). This well did not have a good set of openhole logs, so the approach was to apply the technique used in Well C (which already had a well calibration). The well geometry was similar to previous instances and had perforation openings in the Quintuco (above the VM formation). Additionally, preconditioning of the location and wellhead was required; details of this process are provided in the complete paper.
Phase 2—Swell-Packer Design.
To condition the well, the use of a packer with a large internal diameter was required to allow the passage of the bottomhole assembly (BHA) on coiled tubing (CT). Existing technology (swellpacker) was used to adapt the new nontraditional application.
Conditioning of Well and Preplanning.
In the conditioning stage, the purpose was to prepare the final geometry for the pinpoint completion. Details of logging and other types of testing for this step are provided in the complete paper.
Operation of Well D
Pinpoint Technique.
The HPAP-PPD process in a vertical well is illustrated in Fig. 1. The jetting-tool assembly is first positioned at the lowermost intended fracture position (Fig. 1a). An abrasive slurry is then pumped into the CT and jetted out of the tool at high pressures to form perforations (Fig. 1b). At this time, fracturing-pad fluid is pumped through the annulus, increasing pressure rapidly to cause a fracture to be generated (Fig.. 1c). The proppant slurry is then pumped into the fracture, and when the fracture is extended satisfactorily, an induced screenout is attempted to form a solid pack in the fracture (Fig. 1d), and a“plug” of high-concentration proppant in a viscous gel is left within the wellbore. The CT is then lowered to the next perforating position while reverse cleaning (or vacuuming) the sand plug (Fig. 1e), and the process repeats (Figs. 1f and 1g).
Well Operation.
Initially, in the lower section of the well, there were problems with the abrasive-jet perforations (had to be repeated or new ones added) and with the stimulation treatments (screen out). This led to a series of changes in the fracturing treatment, to allow adjustments to well and formation conditions. These modifications allowed the development of the lower part of the well during the rest of the operations without problems.
Initial Operation—CT.
By use of CT, the BHA was run into the well. Once reaching the bottom, the depth of the mechanical plug (2605 m) was checked. Then, the well fluid was changed to oil to activate the swell packer. The CT system’s depth was adjusted because of the plug-depth measurement. Then, the BHA was positioned at the depth for the first abrasive perforation.
Zone 1. Abrasive Perforation.
With CT at depth, an annular backpressure of 2,000 psi was applied. Pumping began from the CT at a rate of 2.6 bbl/min and a pressure of 8,574 psi (abrasive perforation), pumping 1,600 gal of linear gel with a total of 16 sacks of sand (1.0 lbm/gal). Then, approximately 300.gal of 15% hydrochloric acid (HCl) was pumped. When the HCl reached the BHA, the annulus was closed and flow was decreased to 1.0 bbl/min. Breakdown was observed at 5,482 psi (clear connectivity to the well formation).
Stimulation.
Pumping began through the annulus to create hydraulic fractures, starting with a preacid pad at 5.0. bbl/min, achieving the same formation pressure response as observed previously. The fracture rate was increased to 21.2 bbl/min with a wellhead pressure of6,530 psi. The treatment was pumped according to the program but ended suddenly because of increasing pressure and screenout. The CT pressure (pseudodead string) showed a negative trend during pumping of the pad and the first concentrations, then a flat pressure response was observed while pumping 1 lbm/gal of 30/60-mesh proppant. An abrupt pressure increase was observed when 2.5 lbm/ gal of 20/40-mesh proppant hit the perforation and caused a screenout. After the screenout, reverse circulating the proppant was conducted (requiring 2 hours), and two successful pressure tests on the
sand plug were performed to help ensure the isolation of the first fracturing stage.
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 (preacid pad), high pressure was observed, which made it impossible to achieve the designed flow rate. It was decided to create a new perforation at 2547.m, but batch pumping of HCl was removed from the process. Once a displacement volume of 900 gal was in the annular space created by the abrasive perforation, the annulus was closed and breakdown pressure (5,881 psi) was observed.
Stimulation.
First-stage alterations were introduced in the pumping schedule. Pumping began at an annular flow rate of 24.3 bbl/min and 7,350-psi wellhead pressure. A sweep of clean fluid was pumped between the two sizes of proppant, and the treatment ended suddenly (screenout). The CT pressure (pseudodead string) showed a slightly negative trend during the pad and the first concentrations, so a change was made to use 1.5 lbm/gal of 30/60-mesh proppant, which resulted in a positive increase. After the sweep, the trend was stable until reaching 2.6 lbm/gal of 20/40-mesh proppant at the formation, resulting in a screenout. After the screenout, proppant was reverse circulated (requiring 2 hours) and a pressure test (positive) was performed on the sand plug to help ensure isolation of this second stage. Results for Zones 3 and 4 are provided in the complete paper, as are final results for the 12 stimulation treatments.
Conclusions
The use of a cased-hole-logging methodology (pulsed neutron plus neural network) in old wells with little openhole-log information allowed synthetic curves to be generated that could be used to perform a more consistent interpretation of the VM formation.
The isolation element (swell packer) used was an existing technology adapted for a new application.
The completion technique [hydrajet-assisted fracturing (HJAF) process] required a total of 7 days (1 day for assembly, 1 day for final cleanup, and 5 days to complete 12 fracturing stages).
The VM formation can be stimulated using pinpoint techniques by adapting fracturing treatments to this technology.
Previous perforation/sand-plug completions (Wells A, B, and C) used an initial flow rate of 1.8 to 2.3.bbl/min per hole; Well D, completed using the HJAF technique, used a rate of 4 to 12.bbl/min per hole, which is a higher value and imparts greater energy to initiate and propagate the hydraulic fracture.
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