Real-Time Fluid Tracking Optimizes Treatment Design, Improves Strategy

Dan Gualtieri, Halliburton

Collecting complete wellbore-temperature profiles during the placement of stimulation and diversion fluids has opened a new window to understanding and modifying matrix-stimulation, fracturing, and conformance treatments. Rapidly collected temperature profiles can identify precisely where fluids are entering the formation, allowing real-time optimization of the treatment through on-the-fly modification of the planned program. Such knowledge is necessary to improve stimulation-fluid placement across the entire treatment interval.

The Halliburton StimWatch service identifies stimulation-fluid placement on the basis of changes in fluid properties that introduce variations in temperature gradients as the fluid moves inside the wellbore. This type of analysis provides a detailed understanding of the quality of treatment as applied to the designated intervals through a quantitative assessment of downhole flow rates.

Monitoring Benefits

Historically, it has been difficult to evaluate the placement of stimulation fluids during a multizone treatment in real time. As a result, the zonal volume of injected fluid is based completely on geological-data interpretation; prejob fluid-placement simulators provide only a theoretical prediction of the injection profile. Unknown and unpredictable downhole events occur during stimulation treatments and can have significant impact on treatment results. To achieve successful stimulation treatments, it is important to obtain the following information throughout the job:

Injection profile—which zones are being treated effectively and which zones are not being treated.
Effectiveness of a diversion process.
Status of squeezed zones.
Location of natural fractures.

Service Description

The StimWatch service follows the treatment as it progresses downhole, monitoring distributed temperature profiles obtained by use of the fiber-optic OptoLog Distributed Temperature Sensing (DTS) system. As changes in wellbore temperature are caused by the injection process, this information is converted into downhole injection profiles for a qualitative indicator of fluid distribution across the pay interval. This is performed without the need for shut-in periods or extensive preconditioning of the wellbore.

The DTS fiber-optic-cable assembly can be deployed in a permanent or retrievable configuration. The assembly can be strapped to the completion casing or production tubing as a permanent installation. For retrievable scenarios in horizontal wells, coiled tubing can be used to position the assembly across the perforated interval.

Complete wellbore-temperature profiles are analyzed to determine which perforations are being treated during a multizone stimulation treatment. Visualization and analysis software displays real-time temperature profiles and animated playback of historical data to visualize and interpret progressive downhole events. Commercial applications include

Near-wellbore matrix acidizing.
Determination of well inflow performance before stimulation activities.
Identification of the amount of fluid or proppant flowback.
Injection identification related to steamfloods, waterfloods, or CO2 floods.
Minifrac, acid-fracturing, and hydraulic-fracturing treatments.
Squeeze treatments of relative permeability modifiers, sand-control chemicals, and other fluids.
Identification of fracturing height.
Pre- and post-stimulation performance evaluation by means of flow-profile analysis techniques.

Case Study

A California operator planned a stimulation treatment for a well perforated in multiple sand and shale horizons. The upper formation was partially depleted; the lower, newly perforated formation was still at original reservoir pressure. A multistage sandstone acid treatment with diverter was designed, executed, and monitored with a retrievable OptoLog DTS system. The StimWatch service allowed the operator to view the placement of the acid treatment in real time, providing justification for instantaneous changes in the stage sequencing, job size, and pump rates. These details were used to visualize specific and unique aspects of the stimulation treatment, allowing treatment design to be modified for improved zonal coverage and allowing the effectiveness of the diversion process to be monitored as the job progressed.

Figs. 1 and 2 represent chronological temperature profiles throughout the stimulation treatment. Wellbore temperature is plotted as a function of depth along the entire wellbore. An initial temperature profile is collected (the pink curve), and the blue curves represent the active wellbore-temperature profile at the specified time during treatment. Fig. 1 shows wellbore cooling after the first diversion stage has been pumped downhole. As seen by the hot spot at the bottom of the wellbore, the lowermost set of perforations was not treated. A change in the diversion strategy was initiated on the basis of this observed result. The second diversion stage was successful, diverting treatment fluid to the lower interval. This is evident by monitoring a cooling in that region as seen from the final temperature profile shown in Fig. 2.

Fig. 1—Real-time visualization provided during stimulation activities. A second diversion stage was initiated on the basis of the bottomhole temperature profiles.

Fig. 2—Improved fluid placement is verified when second diversion attempt is successful.

Other cases have been observed showing that acid was being placed out of zone behind a leaking gas lift mandrel. Another job identified stimulation treatments being placed inside natural fractures. Without this type of monitoring capability, stimulation fluids would have been wasted by not treating the intended pay intervals. This would have been unknown to the operator and would have yielded poor production performance.