In acid matrix stimulation, the correct placement of the injected fluids is essential. Several diversion and placement techniques are often applied to obtain the desired fluid placement (Glasbergen and Yeager 2010). Distributed temperature sensing (DTS) and coiled tubing (CT) pressure, temperature, and collar locator tools were used to monitor the fluid placement and effectiveness of the diversion process.Real-time monitoring was required as part of the overall reservoir management strategy for the Tecominoacán 705 well. The CT service provided ideal conveyance for DTS in this highly deviated and depleted well. In a distributed-temperature survey, the fiber optic served as the sensing element, and combined with CT conveyance and pressure/temperature/collar locator tools, enabled continuous wellbore temperature monitoring across the entire horizontal while pumping a stimulation treatment through an annular space consisting of acids and diverters. It also allowed real-time decision making based on the actual measured injection profiles.This well was highly deviated in a carbonate reservoir, completed with 675 m of 4 1/2-in., 12.7 lb/ft liner and swell packers, with 150 m of tubing conveyed perforating (TCP) perforations distributed in six intervals. The DTS combined with CT tools provided accurate monitoring of the stimulation treatment, which was pumped through the annulus between the production tubing and CT. With the DTS service, it was observed that the stimulation fluids were injected only at the heel of the well, which was acting as a thief zone as a result of the presence of highly conductive natural fractures. Several stages of diverters were pumped to attempt to divert acid from the heel to the tip of the well, without success. The decision to cancel the final acid stages saved USD thousands in fluid costs. Mixing the acid on-the-fly using special blending equipment allowed the optimization of resources based on real-time decisions influenced by the DTS injection analysis.

Carbonate formations in southern Mexico are commonly stimulated using matrix acidizing treatments to increase well productivity by removing near-wellbore (NWB) damage. Such damage can be attributed to accumulation of paraffin and asphaltene deposits during the productive life of the well and, in other scenarios, to fluid invasion while performing workover activities. A high perforation length across the reservoir to increase production from this highly natural-fractured carbonate has been the completion option for several years. The use of diverters is a common practice in the Bellota-Jujo field when multiple intervals are open. However, the effectiveness of the diversion had not been evaluated in real-time. A distributed temperature sensing (DTS) option was deployed to measure temperature profiles along coiled tubing (CT) equipped with an internal fiber-optic cable and a modular bottomhole assembly (BHA) consisting of pressure, temperature, and depth correlation sensors. This option was selected to monitor the treatment and help make real-time decisions. This real-time fiber-optic (RTFO) integrated system used during the stimulation allowed identification of zones with higher and lower admission. Based on this information, decisions were made during the pumping schedule, modifying volumes and rates of diverting agents and stimulation fluids being pumped through the annular space between production tubing and CT, also pumping through CT using a fluidic oscillating tool optimizing the diversion process during different stages of the intervention. This system enabled the operator to correlate depth and continuously monitor the temperature changes across the producing zone of the well. The findings and results of the stimulation treatment with this technique used in the well, Bricol 2DL, are presented in addition to the thermal analysis of the DTS profiles. The use of the RTFO integrated system during a matrix stimulation treatment in a carbonate formation with high permeability contributed to successfully evaluating the effectiveness of the fluids and mechanical diversion resulting in a well productivity increase of 60%, thus keeping the well in production since the treatment was performed.

Producing well conditions in the southern region of Mexico present challenges that can benefit from the use of a newly developed intervention technology. This paper describes the development of this real-time fiber-optic (RTFO) integrated system. RTFO is used for depth correlation and real-time pressure and temperature monitoring inside the coiled tubing (CT) and the outer annulus. Additionally, distributed temperature sensing (DTS) survey capabilities can provide instantaneous evaluation of downhole treatments in real-time. The data is transmitted by means of a 4-mm fiber-optic (FO) capillary to surface data acquisition equipment, allowing both monitoring and job execution changes in real-time. This technology allows operators to make immediate treatment decisions to help achieve the best results possible. Additional sensor expansion is possible because of the modular design of the bottomhole assembly (BHA). This paper discusses the fast-track developmental process of the RTFO system as well as quantitative lab and full-scale yard testing. Case histories from three high-temperature deep candidate wells in the Latin American region are presented. Lessons learned from the initial field trials and the resulting next-generation design enhancements and sensor expansion capability of the tool are also highlighted. The synergy of the CT RTFO system, cleaning nozzle selection, and a tailored fluid program proved to be a successful combination for effective cleaning of the case history wells discussed.

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Fluid allocation is a common challenge in the stimulation of naturally fractured reservoirs in offshore Mexico. Multiple or large pay zones with thief intervals can cause preferable fluid admission to such zones. Using distributed temperature sensing (DTS), fluid-treatment distribution can be monitored in real time for this type of reservoir, and modifications can be made on the fly to improve fluid coverage. Monitoring with DTS can help optimize treatment economics and improve productivity. A reintervention to increase production in naturally fractured reservoirs involves improved stimulation schedules and the use of diverters to achieve fluid distribution across perforated intervals. Variable permeability and a potential for heterogeneous zones in the reservoir are a challenge for these types of wells. This document discusses a treatment performed to successfully stimulate a four-interval well using DTS measurements to monitor placement in real time. A gas-lift test was also performed during the monitoring operation to help identify the producing zone before the main stimulation began. The information gathered during the treatment helped the operator understand the production behavior of the well and acquire additional information for upcoming treatments. During the well intervention, the following information was obtained to help determine the success of the treatment: Fluid allocation was verified during and after injectivity testing (including differential temperature gradient) to help determine initial admission zones. This information enabled an appropriate schedule to be designed for the acid treatment.A gas-lift mandrel was used, and the zone contribution was qualitatively evaluated during this test.The stimulation treatment and the diverter stages were monitored in real time. The percentage of admission was calculated for each open interval, and a correlation using previous production-logging-tool data was performed.Early flowback of the well was observed. The production expected from the treatment was 800 BOPD. The stimulation treatment was considered successful, with an initial production of 1,050 BOPD (a 31% increase from the target). The information gathered during this treatment can also help modify upcoming treatments in the wells of this field with similar characteristics. Combined pre-treatment production monitoring and monitoring stimulation treatments in naturally fractured reservoirs using DTS helps identify the main producing zones and improves stimulation fluid distribution into lower-permeability intervals. This technique allows for performing treatment changes on the fly to attempt to achieve better zonal distribution and increase the productivity index in the wells.