Published: 10/10/2011
Published: 10/10/2011
Working in the Eagleville field in South Texas, a large Gulf Coast operator continually aims to improve production from the Eagle Ford shale. The formation mainly comprises limestones and shales with
Production from this area is driven by the effective stimulated rock volume (ESRV) and the reservoir connectivity with the wellbore that can be established via hydraulic fracturing. High fracturing gradients (typically 0.92 – 1.00 psi/ft) and bottomhole static temperatures (280 – 310 degF) at depths between 11,800 and 12,200 ft are challenging conditions for successful execution of fracturing treatments.
Logistics are also challenging for these operations. This section of the Eagle Ford Shale has generally been stimulated using multistage horizontal completions with high-rate slick-water treatments. Such treatments require millions of gallons of water and millions of pounds of proppant per well. The ongoing expansion of fracturing activity in the Eagle Ford shale further constrains the limited availability of water and proppant in the area. The need exists to increase operational efficiency by reducing the amount of materials used in these operations.
The HiWAY flow-channel fracturing technique was applied to address these challenges and improve well performance beyond conventional means.
This operator chose to evaluate the HiWAY flow-channel hydraulic fracturing technique from Schlumberger for the stimulation of wells in the Eagleville field in a four-well study. Two wells were stimulated with the HiWAY technique. The other two wells were stimulated simultaneously with the conventional method.
The landing of the wells was carefully planned to provide the best possible basis for comparison. The wells treated with the HiWAY technique had been drilled from a single pad, in opposite directions. The other two wells had also been drilled in opposite directions from a single pad located just 3,500 ft away and parallel to the first two wells. The average lateral length for each pair of wells differed by only 1%.
Rather than leaving fracture flow dependent on proppant pack conductivity, the HiWAY fracturing technique creates stable channels for oil and gas to flow through. These stable channels offer limitless conductivity, thus increasing flowback and reducing pressure drop across the fracture. These effects lead to greater ESRV and consequently, higher oil and gas production.
During the first 60 days after stimulation, the wells treated with the HiWAY technique produced an average of 26,535 barrels of condensate (bc) with 30.1 MMcf of associated gas. The wells treated conventionally produced an average of 18,555 bc with 18.7 MMcf of associated gas. Furthermore, the average wellhead flowing pressure for the wells treated with HiWAY channel fracturing was 2,156 psi versus 1,916 psi for the conventional wells. Therefore, the HiWAY technique increased condensate and gas production by 43% and 61% respectively while delivering higher flowing pressures.
Very importantly, these results were obtained while reducing the amount of water and proppant used per well by 58% and 35%, respectively. The operator saved more than 10,000,000 gal of water and 2,600,000 lbm of proppant in the two wells stimulated with HiWAY channel fracturing. The reduction in the amount of materials required to stimulate a well simplifies logistics, reduces completion costs and minimizes safety and environmental risks.
By virtue of these results, the energy company has requested the use of the HiWAY technology on future wells within its lease.
Challenge: Improve oil and gas production and operational efficiency in the competitive Eagle Ford shale.
Solution: Apply HiWAY flow-channel hydraulic fracturing technique in horizontal completions to increase the effective stimulated rock volume by creating stable, infinitively conductive channels within the proppant pack.
Results: The HiWAY fracturing technique increased 60-day cumulative oil production by 43% and 60-day cumulative gas production by 61% while reducing water and proppant consumption per well by 58% and 35%, respectively.
