This paper discusses a unique system that combines a fiber-optic distributed temperature system (DTS) to measure the distributed temperature across the entire wellbore and a molecular telemetry transmission system that provides a single-point determination of bottomhole pressure. The system has been used to perform real-time downhole monitoring of multi-stage acid-stimulation treatments performed on wells that contain multiple non-isolated pay intervals. The fiber-optic for the DTS is contained inside a length of capillary tubing, which is placed concentrically inside a larger size capillary tubing. The created annulus between these two strings of capillary comprises the molecular transmission system for determining the bottomhole pressure.
Real-time-distributed temperature data and single-point bottomhole pressure data are provided on location. In the case history presented, the temperature profile across the multiple pay intervals yielded valuable information for identifying which zones were "taking" the acid, allocating how much acid these zones were taking (relative to one another), and identifying the zones not taking acid. This allowed on-the-fly changes to be made on-site in real-time regarding the make-up of the acid treatment, the pumping rates, and when and where to apply diversion processes.
This system enabled the operator to continuously monitor the wellbore temperature across the interval that was being stimulated as well as from a single-point bottomhole pressure below the lowest perforation. In this case, the system was deployed inside the work string used for the acid stimulation, but the system can also be permanently deployed.
The nominal ratings for this monitoring system are 250°C and 10,000-psi. This allows the system to be applied in a large number of wells, either onshore or offshore. Furthermore, there are no downhole electronics and no moving parts, making the system extremely well suited for harsh environments.
Introduction
The 1000-ft-thick shales in the Elk Hills area pose a major challenge in developing a successful treatment design strategy.1 These formations include many natural fractures or thief zones, which provide significant problems for spreading treatment across the targeted pay intervals. Because of this, it is difficult to know if the formation will be tight? or worse? be on a vacuum due to thief zones.
Large-volume acid stimulations are required to remove drilling-mud damage and fines from these types of fractures. Matrix acidizing has been used successfully to re-establish productivity in these tight-shale formations, however, the results can be unpredictable. In the past, it has been impossible to know where the treatment fluid was being placed, the amount of fluid coverage that had been attained, and the effectiveness of the diverter stages during the treatment process. To address these challenges, it was important to develop solutions that would have the capabilities to provide answers for these unknowns. With this knowledge, it would be possible to develop a systematic approach to improve treatment predictability with an increasing productivity index (PI) and production rate.
To understand the dynamics involved in near wellbore stimulation, fiber-optic-distributed temperature sensing technology and visualization tools were applied. Notably, this technology is well suited for steam-flood management, leak detection, injector shut-in, gas entry and production-flow-allocation surveys.2,3 DTS technology may offer significant untapped potential when used to analyze transient wellbore temperature profiles. Applying this technology to matrix acidizing can provide qualitative knowledge of the fluid injection rates, cumulative distribution, diversion placement, and effectiveness. Diversion schemes can be changed to optimize fluid placement in real time based on DTS profiles. Comparison of injection profiles before and during stimulation allows limited stage modifications to avoid pumping unnecessary fluids, thereby reducing health, safety and environmental impact.
