Deepwater Frac-Pack Maximum Treating Pressure Limits, An Examination Using Bottom-Hole Pressure Gauges
Authors: Lizak Kenneth F. , Hinnant Charles 
Published: July 2010

Abstract
During frac-pack treatments, completion hardware is often subject to extreme differential pressures. This is especially true during early screenouts where the large hydrostatic differentials can suddenly be placed on the completion components, resulting in a high risk of collapse. Deep wells and completion tool configuration can limit supporting pressures for these tools.
To prevent damage to completion hardware such as crossover tools, fluid loss devices, and blank pipe, the maximum surface treating pressure has been limited to a calculated Pmax.1 Conventionally; the reservoir pressure was used as the internal supporting pressure in these calculations. Using the reservoir pressure to calculate the Pmax results in a " worst case?? pressure limit that prevents collapse in virtually any job. However, today many frac-pack treatments are being performed in low-pressure, sub-hydrostatic reservoirs. Many of these jobs could not be placed using just reservoir pressure for support, even when utilizing high-strength, completion hardware materials.
By analyzing a significant number of actual jobs, it was determined that the current standard equations are overly conservative when compared to actual treating results. By using less conservative, modified equations, numerous additional wells have been completed with frac-pack technology. This paper studies a number of these successful frac-pack jobs that could not have been performed using the standard Pmax equation and safety factors. Post-job bottom-hole gauge data is examined to determine the true differential pressures and verify the accuracy of the assumptions that are used in the modified Pmax calculation, which provides valuable insight and recommendations for tool design, fluid properties and maximum pressure limitations for frac-pack completions.

Introduction
As many fields are depleting and reservoir pressures falling, there has been an increase in interest in extending field life by the introduction of injection wells. This is especially true in deepwater fields where the cost of infrastructure is high. Although drilling and completing these depleted formations poses many risks, this paper will focus on surface pressure limits when placing frac-pack completions into these depleted formations.
In the unconsolidated GOM sand completions studied, a tool string with a crossover service tool is used to place frac-pack completions. Typically, the maximum surface pressure is limited not by the surface iron or workstring burst ratings, but by the lowest collapse pressure rating in the gravel pack assembly below the crossover and above the top of the screen. This area may consist of crossovers, pups, fluid-loss devices, shear subs, blank pipes and similar types of hardware. In the event of a screenout, the gravel in the annulus above the screen forms a semi-impermeable plug, and pressure applied to the tubing string is directly transmitted to this annular area. This pressures attempts to collapse these gravel pack assembly components. When a " hard?? screenout occurs, the flow rate stops while the injection pressure spikes. Friction pressure is suddenly lost, applying full surface pressure and tubing hydrostatic to the annulus area before the pumps can be shut down.