Pump-in/Shutdown Tests Key to Finding Near-WelIbore Restrictions

Hyden, Ron; Stegent, Neil

doi:10.2118/35194-ms

Cited by 13 publications

(1 citation statement)

References 6 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…The initial injection rate in the Eagle Ford formation is sometimes less than designed, and NWB friction heavily contributes to hamper injection during the frac. NWB friction had been measured with step-down injection tests (Hyden and Stegent 1996) on other Eagle Ford stimulation treatments in the area that showed high NWB friction. Fig 11 illustrates the severity of tortuosity from lab experiments.…”

Section: Completion Strategy and Designmentioning

confidence: 99%

Cement Technology Improves Fracture Initiation and Leads to Successful Treatments in the Eagle Ford Shale

et al. 2010

View full text Add to dashboard Cite

Stimulation-design considerations usually include things like formation-fracture gradient, reservoir pressure, stress, casing size, perforation schemes, etc. The type of cement that fills the annular space between the openhole lateral and the casing is not typically considered with regards to its impact on the execution of the frac treatment.Early horizontal-well completions observed much higher injection pressures than those observed in vertical wellbores in the same formation. Research identified the effects caused by transverse, oblique, or longitudinal fractures from horizontal wellbores, which were usually nonissues in vertical completions. Near-wellbore (NWB) friction (tortuosity) is a component that is common to both vertical and horizontal wellbores but seems to be ignored in horizontal completions. When proppant cannot be placed during a horizontal frac, it is usually blamed on formation-fracture width (or lack of it) and proppant size (mesh size is too large). These are the typical reasons used to explain early screenouts and have become commonplace in the industry. The authors of this paper believe NWB tortuosity issues have a much larger impact than most think and will show how a properly engineered production casing cement, in conjunction with the stimulation design, allows the placement of large-mesh proppant at high concentrations in the Eagle Ford shale. High conductivity is essential for maintaining liquid-rich production.Fracture initiation in a horizontal well, especially at the toe, can sometimes be very difficult. To minimize injection issues, acid-soluble cement (ASC) was placed in the lateral of several Eagle Ford-shale wells in Karnes County, Texas. Hybrid stimulation treatments were used to place 20/40-mesh proppant at concentrations up to 4 lbm/gal, most without issue. Proper engineering was used to successfully fracture stimulate all the intended intervals (including the first stage at the toe).Utilization of ASC for horizontal completions can help improve stimulation efficiency and allow alternate onsite frac options that can turn an otherwise-abandoned completion interval into a successfully stimulated section of the reservoir.

show abstract

Section: Completion Strategy and Designmentioning

confidence: 99%