Fracturing for Sand Control: Screenless Completions in the Yegua Formation
- Dennis Denney (JPT Technology Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- March 2006
- Document Type
- Journal Paper
- 56 - 57
- 2006. Society of Petroleum Engineers
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- 75 since 2007
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This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 96289, "Fracturing for Sand Control: Screenless Completions in the Yegua Formation," by V.R. Ellis, SPE, and G. Cormier, SPE, Halliburton; G. Adams, SPE, Noble Energy Inc.; and F. Santos, SPE, Sanchez Oil & Gas, prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9-12 October.
Natural completions in the Yegua formation have resulted in failures caused by formation-sand production and wellbore collapse. In the past, a popular remedy was small fracturing treatments with gravel-pack screens to control the production of formation material. Designing the completions specifically for wellbore stabilization, sand control, and maximizing the conductivity endurance has resulted in techniques that eliminate the need for gravel-pack screens, helping to simplify completion operations and minimize cost.
The Yegua formation is a sand/shale depositional system that extends from south Texas to south-central Louisiana. Historically, the Yegua has been completed naturally, requiring periodic cleanout when formation sand accumulates in the wellbore. The typical solution for preventing the production of formation sand has been some form of mechanical remediation involving gravel packs or vent screens. In some areas, the Yegua will produce naturally without making formation sand; however, casing failures occur when the bottomhole flowing pressure is drawn down until a critical failure stress is reached and the rock fails.
The downdip Yegua, studied here, usually is an overpressured gas/condensate, pressure-depletion-type reservoir. Water production is relatively low in early stages of production and can vary greatly in later stages. The increased water production has been attributed to water coning from higher-permeability stringers.
Well 1. Well 1 production was severely restricted when a failure occurred. As the reservoir pressure depleted, fines migration and formation compaction reduced the near-wellbore permeability. As a result, the drawdown pressure increased, causing eventual failure of the formation rock. Formation sand filled the wellbore, halting production, which required a workover to clean out the wellbore. In several cases, the near-wellbore stresses increased to the point at which the casing either collapsed or was sheared, thereby losing the wellbore. Well 1 is an example of lost production because of formation failure that, eventually, led to collapsed casing.
The purpose of the work reported here was to maximize hydrocarbon recovery while minimizing casing failures and formation-sand production. The objective was accomplished by reducing the drawdown pressure near the wellbore by placing highly conductive proppant packs. The packs included curable, resin-coated proppant or proppant coated with a conductivity-endurance modifier (CEM) to help ensure that all perforations were packed with coated proppant.
Well 2 was completed with a 5-in., 18 lbm/ft, P-110 long string set at 13,730 ft measured depth (MD) and 2 7/8-in., 6.5 lbm/ft tubing set with a packer at 13,535 ft MD. The Yegua EY3 sand was perforated in three intervals: 13,588 to 13,592, 13,599 to 13,603, and 13,610 to 13,613 ft MD. The perforated zones then were fracture stimulated. The net pay interval was approximately 35 ft long with a porosity of 22%.
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