Hydraulic Fracturing Hot, High Pressure Oil and Gas Wells in Tectonically Active Fields in Eastern Venezuela (SPE 38991)


In eastern Venezuela, production benefits of 100 to 200% were achieved with TSO HSP fractures containing 20/40, 16/20, and even 8/16 tail-ins as documented by Vega, et al. High conductivity fractures increased production, and eliminated formation sanding and asphaltene plugging.  When TSO behavior was not indicated during the stimulation treatment, higher proppant concentrations and reduced injection rates were specified to insure fully packed fractures were achieved.


The exploitation of the prolific North Monagas reservoirs discovered in 1989 has been hindered by sand production and by asphaltene depositions in the production strings. Wells in these fields have been completed at depths ranging from 14000 to 17000 feet at, original reservoir pressures of 7500- 11200 psi. Bottom hale temperatures range from 180 to 307 F and wellhead pressures have reached 7000 psi in the early stages of production. Reservoir fluids have asphaltene concentrations of 5 to 8%, with 200 ppm of H2S and 6 to 10% of CO2. These characteristics of the reservoir and the reservoir fluids represent high risk conditions which have required exercising extreme care in handling the large volumes of crude produced from some 150 active zones.

As early as 1991, sand production and asphaltene depositions combined to cause severe well plugging in the Carito Field, making it necessary to start a cleaning program using snubbing units to return production to well potential. In 1994, alter analyzing rock mechanics data acquired in North Monagas, establishing the causes of the sand failure mechanisms and evaluating well production performance under the existing pressure and production rate conditions, it was decided to hydraulically fracture those wells with the most severe sand production problems to improve bottomhole and production tubing flowing conditions. Appropriate hydraulic fracture designs allowed the wells to maintain economically attractive sand free well production rates and higher pressure levels in the system well above bubble point conditions to ensure asphaltene dispersion in the liquid phase and decrease the occurrence of asphaltene plugging. Flow conditions at the flowline wellhead and bottomhole perforation conditions were simulated through the use of commercially available programs versed in nodal analysis.

The work presented herein describes how the application of thermodynamic concepts and the hydraulic fracture programs were used to design and select the high pressure, high temperature treating equipment and fluids programs to control sand production and asphaltene depositions as well as maintain economically attractive oil and gas production rates, thus increasing the physical integrity of the wells.

Author(s): Halliburton Services, G. Vega, E. Negron-Perez, S.A. Corpoven, H. Abass

Paper Number: SPE 38991

URL: https://www.onepetro.org/conference-paper/SPE-38991-MS


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