Coiled Tubing With Real-Time-Measurement Tools Helps Overcome Stimulation Problems

Abstract

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 184753, “Overcoming Challenges of Stimulating a Deepwater, Frac-Pack-Completed Well in the Gulf of Mexico Using Coiled Tubing With Real-Time Downhole Measurements,” by Eric J. Gagen, SPE, Schlumberger, Alex D. Menkhaus, Kellogg School of Management, prepared for the 2017 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, Houston, 21–22 March. The paper has not been peer reviewed. The treatment in a deepwater, frac-packed well with fiber-optic-equipped coiled tubing (CT) and a rotating, hydraulic high-pressure jetting tool achieved successful stimulation of a 500-ft-long frac-packed zone after several previous failures using different techniques. By using CT equipped with fiber optics and downhole measurement tools, engineers were able to perform a data-driven operation based on real-time bottomhole measurements and distributed-temperature surveys. This successful treatment improved productivity by 75% compared to the well before treatment. Introduction Diagnostic work indicated that a well had considerable skin and flow impairment. Several acid treatments had been bullheaded into the well since initial completion. The treatments were ineffective, either producing no material results or producing only short-lived improvements with a quick return to original conditions. Slickline diagnostic work conducted on the well indicated the possible presence of a mechanical obstruction or fish of some sort near the bottom of the lower lobe of a sand package in the well. However, lacking correlated depth measurements, it was unclear whether this obstruction was below the entire producing zone or high enough to obstruct some of the lower screen section. The formation consists of two lobes of one sand package at an approximate angle of 33°. On the basis of log data and core samples, the permeability of the formation across these lobes was highly variable. On the basis of that variability, it was believed that the most likely scenario was that the upper portion of the lower lobe was the highest-conductivity region of the completion and that the previous acid treatments had mostly been stimulating that portion of the well to the detriment of other areas. It was believed that the more-laminated-looking pay in the upper lobe, in particular, was underperforming. Several problems had to be overcome to make another stimulation successful: There was uncertainty about exactly what the production problem was with the well. Conducting the stimulations would incur high cost. Excessive interruptions of new well-drilling operations would threaten to put production from new wells behind schedule. The fracture pressure of the zone was 12,700 psi, but the pore pressure was 12,100 psi, leaving only a small pressure margin to perform an operation at matrix injection rates.