DTS Technology: Improving Acid Placement

Abstract

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 145055, ’DTS Sensing: An Emerging Technology Offers Fluid Placement for Acid,’ by Robert Reyes, SPE, Gerard Glasbergen, SPE, and Valerie Yeager, SPE, Halliburton, and Joseph Parrish, Occidental Petroleum, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed. Distributed-temperature sensing (DTS) is used in wells to determine the effectiveness of acid treatments. Concerns include where the acid was placed in the well, if the acid went where it was supposed to go, and if the acid went into the first least-resistive zone while subsequent zones went untreated. By use of DTS, it was determined that information seen at the surface can be misleading. Surface pressure can be masked by friction and is, therefore, not a valid indictor for what occurred downhole, and diversion can take place without surface indication. DTS enables practical real-time adjustment to the diversion strategy. Introduction As fluid flows in or out of the wellbore, it creates a characteristic thermal-gradient signature. DTS technology uses a fiber-optic cable to read temperature in real time, enabling validation of fluid placement. During production, reservoir fluid flows from the high-pressure reservoir into the low-pressure wellbore. Liquid recovery will result in a warming trend in the wellbore, while gas recovery will result in a cooling effect. These basic characteristics help determine liquid and gas movement. Effective fluid placement in the wellbore is critical for an optimized acid-treatment design. When determining fluid flow inside the wellbore, an understanding of the geothermal gradient and the internal Joule-Thomson effect is necessary. Fluid placement and zonal cover age are important for matrix-acidizing treatments, scale-inhibitor squeeze treatments, water-control treatments, water injection for enhanced recovery, and hydraulic-fracturing treatments. Case studies in this paper concentrate on matrix acidizing and production profiling. During these acid treatments, running a diverter involved the use of surface-pressure response, and the post-treatment-production improvement was used to determine if the treatment was effective. If effectiveness was questioned, design changes were tried, such as increasing or decreasing the rate, changing the percent of acid, and drop-ping diverters. Use of surface pressure to determine design changes for the current well and for the next well was not sufficiently accurate to make these determinations effectively. Fluid-friction pressures in the tubulars are not always known accurately, and they can affect the surface pressure, yielding erroneous bottomhole-pressure calculations. Case studies revealed that, during the diverter stages, the surface pressure might indicate diversion even though DTS data showed no diversion had occurred. Surface indicators falsely reported a downhole phenomenon because of fluid-friction pressure. In other case studies, the diverter was dropped and no surface indicators of effectiveness were detected. Again, downhole DTS data revealed the opposite: Diversion did occur.