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Aguada Pichana Gas Field Development: Key Parameters for a Successful Well Design (SPE 36847)


Despite modest closure stress of 3500 psi, wells were stimulated with ceramic proppant to maximize conductivity and durability of the fractures.  To avoid underlying water zone, small treatments (<35,000 lbs) were designed, but slurry concentrations were quickly ramped to 11 ppg to maximize conductivity.   Nine existing but non-producing wells were worked over, and 18 new vertical wells were fracture stimulated providing initial rates exceeding 10 MMCFD per well, with stabilized rates exceeding 8 MMCFD (70% more than projected).  In one well, additional perforations were added post-frac, increasing production by a remarkable 8 MMCFD!  A well without a water contact received a massive re-fracture treatment, increasing rate by 12 MMCFD.


The development of the Aguada Pichana gas field in the west of Argentina, required a drastic reduction in drilling costs as well as effective hydraulic fracture stimulation to increase well productivity. Local drilling and stimulation practices had to be rethought and innovative solutions found for the project to be economically successful. This paper focuses on the following aspects:

Drilling and Completion: Cost economies achieved by using a reduced diameter (6 1/8") well design, use of a compact wellhead, bit optimisation and reduction of drilling time by maximising rigless operations.

Stimulation: The impact of changing the conventional fracture fluid used by other operators in the region in order to allow higher proppant concentrations to be pumped and allow fracturing through the 2 7/8"completion. Fracture design in order to avoid fracture growth into a water zone is also discussed.

Horizontal Wells: 2 horizontal wells and 23 vertical wells were drilled. 18 of the vertical wells were hydraulically fractured. The relative merits of a horizontal versus a fractured vertical well design are highlighted.

The first phase of the field development took just over 1 year to complete, using 2 drilling rigs and 1 workover rig. Gas production from the 34 wells (25 new wells and 9 workovers) began in January 1996 and currently stands at 5 Mm3/day.

The positive results of the combined operations meant that a stabilised gas potential much higher (+70%) than anticipated was achieved along with cost savings for the project.

The Aguada Pichana gas field was discovered in December 1970. It is located in the Neuquen basin in the north-west part of Patagonia, Argentina, not far from the foothills of the Andes. When TOTAL AUSTRAL took over operatorship of the field, in the early part of 1994, 33 wells (22 gas producers and 11 abandoned) had been drilled but none put into production. The first development phase of the field began in December 1994 with a contractual agreement to reach a gas production rate of 5 Mm3/d by January 1996.

Field Development Strategy. A relatively low gas price (approximately half of the USA or UK gas price), high development costs and low productivity of wells mean that project economics in Argentina are particularly difficult. Investments in new wells have to be minimised and well productivity maximised.

Within this economic context, the following field development was envisaged:

  1. Drill new vertical wells and stimulate them by hydraulic fracturing to optimise well productivity.
  2. Drill horizontal re-entries in existing wells where fracturing a vertical well was impossible due to the close proximity of a water zone.
  3. Complete workovers on the existing wells with a high gas potential to put them in a safe operating condition. Reservoir Description

The sandstone reservoir is located at a depth of 1600 - 1800m. As can be seen in Figure 1, reservoir characteristics vary according to field location.

In the north part of the field, the gas reservoir height is typically 70m with permeabilities varying from 1-5 mD. Reservoir height in the west part of the field is typically 65m and permeability <1 mD. Higher permeabilities of between 5- 30 mD exist in the south part of the field but with a reduced gas reservoir height of only 25m.

In each case a 10-15m water zone is identified in the lower part of the sandstone reservoir. P. 285

Author(s): K. Hannaford, Ph. Le Guludec, R. Vighetto, TOTAL AUSTRAL

Paper Number: SPE 36847

URL: https://www.onepetro.org/conference-paper/SPE-36847-MS


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