Successful Stimulation of the Olmos Formation Using Oil-Base Fluids and High-Proppant Concentrations

Summary

Initial Olmos fracs with water based fluids and low proppant concentrations were not very successful, with short apparent fracture lengths and rapid decline.  Well #5:  Large refrac at 12 ppg provided 13-fold increase in oil rate, and 13-fold increase in 180 day cumulative production.

Abstact

Successful stimulation of the Olmos Formation in McMullen County, Texas, has proven to be challenging. Initial attempts at fracturing the Olmos using water-based fluids and low proppant concentrations did not prove to be very successful. Core studies have indicated this formation to have a fluid retention tendency. Gelled hydrocarbon fluids with high sand concentrations are now being used as a fracturing system with significantly improved success.

The transition to gelled oils capable of carrying high sand concentrations has presented some unique challenges to the industry because portions of the Olmos Formation are at depths approaching 10,000 ft (3050 m) with bottomhole temperatures to 259 degrees F (126 degrees C). The most successful fracturing treatments in the Olmos appear to result from long fractures propped with high concentrations of propping agent. The long fractures contact additional reserves and the high sand concentrations not only produce highly conductive fractures but also settled bank heights capable of filling the fracture below and through the Olmos zone. Fluid viscosities required for these treatments were based upon pre-fracturing analyses and computer evaluations, which determined fluid efficiency and fracture closure times. This posed a problem as the commonly available oil-based fracturing fluids either did not have sufficient fluid viscosity downhole over extended periods at high temperature (at least six hours at 259 F [126C]) or, if they did meet this requirement to place the proppant, were too viscous on the surface into which high concentrations of sand could be mixed or be easily handled with surface equipment.

To date, in excess of 60 wells in the Olmos have been treated successfully using high sand concentrations and a new method for gelation of oil-based fluids. This method involves use of enough gelling agent to gel the hydrocarbon for the required surface viscosity and downhole stability, and also provide the needed amount of activator for surface conditions. The activator concentration can be varied to produce a base gel which is easily pumped and into which the propping agent can be easily mixed. As this base gel is being pumped downhole, additional activator is added to produce a gelled fluid needed for downhole conditions. Treatments in the Olmos have evolved up to 1,800,000 pounds (816,500 Kg) of 20/40 mesh Ottawa sand and 250,000 gallons (946 m3) of gelled fluid. Jobs are pumped at 12 bbl/min (114 m3/sec) for up to 10 hours, averaging 12 lb of sand/gal of fluid (1400 Kg of sand/m3 of fluid) with a maximum concentration of 17 lb of sand/gal of fluid (2000 Kg of sand/m3 of fluid). The wells so treated have responded with more sustained production than wells treated with less temperature-stable fluids containing lower concentrations of sand.

Laboratory studies, treatment methods, completion and production data will be presented.

Author(s): R.W. Pauls, J. Venditto, P. Chisholm, M. Holtmyer, Halliburton Services; W. Gregorcyk, Royal Oil and Gas Corp.

Paper Number: SPE 13817

URL: https://www.onepetro.org/conference-paper/SPE-13817-MS

 

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