Abstract
In matrix stimulation and injection treatments for removing or preventing formation damage, correct placement of the injected fluids is essential. Throughout the years, several diversion and placement techniques have been applied to obtain a desired fluid placement. These techniques are needed to overcome natural or artificially created heterogeneities. One of these heterogeneities is reservoir pressure. When barriers between the formation layers exist, the layers can have significant pressure depletion caused by production or can be overpressurized because of water flooding. To treat the layers with elevated reservoir pressures is challenging; however, they are often the target areas of a treatment. Another challenge is that during the shut-in period following the treatment, crossflow in the wellbore can be expected, which can cause undesired fluid movement.
To understand and quantify the challenges related to pressure heterogeneities, the fluid placement and crossflow in the wellbore for treatments in formations with pressure heterogeneities have been modeled. A fluid-placement simulator that has the ability to include heterogeneities in pressure was used. In addition, the effect of fluid placement with the use of distributed temperature surveys (DTS) and single-point bottomhole pressure were measured. The advanced measurement techniques were used to both monitor the placement of the fluids during the treatment and identify the crossflow in the wellbore after the treatment was finished.
These measurements provided fascinating results and provided the insight that, in about 50% of the monitored wells, crossflow could be identified up to flow rates that exceeded 1 bbl/min. In addition, the pore pressure in the high-pressure zones could be determined by measuring the wellbore pressures when the crossflow started.
This paper discusses several case histories where the fluid placement during the treatment and the post-treatment shut-in were measured and modeled. Furthermore, techniques that can be used to optimize the fluid placement in formations with significant reservoir-pressure heterogeneities and which techniques are less useful are discussed.
