Summary The ability of foam to divert gas flow during a long period of gas injection in a surfactant-alternating-gas (SAG) foam process is important for the economics of foam-diversion processes for enhanced oil recovery (EOR). Here, we interpret field data from the foam test in the Cusiana field in Colombia (Ocampo et al. 2013). In this test, surfactant was injected into a single layer that had been taking approximately half the injected gas before the test; then, gas injection resumed into all layers. On the basis of the size of the surfactant slug injected and estimates of adsorption and of water saturation in the foam in situ, we estimate that the treated region extended approximately 5.3 m from the injection well; fortunately, the results to follow are not sensitive to this estimate. On the basis of the change in injection logs before the test and at Day 5 of the test, when approximately 30 pore volumes (PVs) of gas (relative to the volume of the treated zone) had been injected, foam still reduced gas mobility in the treated layer to approximately 11% of its pretrial value. We base this estimate on the decrease of injection into the treated layer and the increase of injection into the other layers; the results are consistent among the layers. After 35 and 152 days of injection (220 and 1,250 treatment PV of gas injected), foam reduced gas mobility in the treated zone to approximately 26 and 50% of its value before the test, respectively. This result indicates that foam continued to reduce mobility by a modest amount even after long injection of gas. On the other hand, foam did weaken progressively as it dried out. Foam models in which foam remains strong at irreducible water saturation would greatly overestimate foam effectiveness at long times in this test. In this test, the large volume of gas had quickly penetrated far beyond the edge of the surfactant bank. Mobility in the foam-treated region in this test, after passage of many treatment PVs of gas injection, mimics that very near the injection well in a process with a larger slug of surfactant.

Well stimulation for production or injection enhancement in mature fields is a key and challenging task. Loss of reservoir energy due to pressure depletion coupled with complex damage scenarios existing in adverse petro physical environments can become restrictive factors for the proper performance of conventional liquid based chemical stimulation systems. Main limitations are normally related to high interfacial tensions preventing optimal well´s clean up and cost-effective achievable penetrations. This work presents a new well stimulation concept in which the carrying system is gas instead of liquid. The overall study will be presented in 2 parts. Part I will discuss basic physical questions related to treatment durability as a function of deployment method (continuous dispersion vs liquid batch gas displacement) for at least two damage scenarios of particular interest: asphaltene deposition and condensate blockage. A basic mechanistic simulation is also presented for benefit estimations at well scale. Part II will focus on field trials design and execution using micellar and/or fluoropolymer type of chemistries that exhibited the best performance when tested under laboratory conditions. Experiments herein presented were done in formation sandstone cores simulating reservoir conditions. It is shown that natural gas when used as the carrying system to deploy conventional asphaltene dissolution and condensate removal chemistries enhances both Ko re-establishment and treatment durability as compared to equivalent liquid-based applications. Additional studies are being performed to maximize the effectiveness of the GaStim concept. Sensibilities to gas type (N2, CO2), added chemical and dosages as long as field trial documentation will be presented in part II of the present work.GaStim concept is presented as a novel chemical stimulation technique potentially allowing deeper penetrations and better chemical adsorptions. Its potential, although still not fully undiscovered, is certainly supported by higher Ko reestablishment values and longer treatment durabilities observed.

The ability of foam to divert gas flow over a long period of gas injection in a Surfactant Alternating Gas (SAG) foam process is important for the economics of foam-diversion processes for enhanced oil recovery. Here we interpret field data from the foam test in the Cusiana field in Colombia, South America (Ocampo et al., 2013). In this test surfactant was injected into a single layer that had been taking about half the injected gas before the test; then gas injection resumed into all layers. Based on the size of the surfactant slug injected and estimates of adsorption and of water saturation in the foam in situ, we estimate that the treated region extended about 5.3 m from the injection well: fortunately the results to follow are not sensitive to this estimate. Based on the change in injection logs before the test and at day 5 of the test, when approximately 30 pore volumes of gas has been injected, foam still reduced gas mobility in the treated layer by about a factor of 9. We base this estimate on the decrease of injection into the treated layer and the increase into the other layers; the results are consistent among the layers. After 35 and 152 days of injection (220 and 1250 pore volumes gas injected), foam reduced gas mobility in the treated zone by about a factor of 4 and 2, respectively. This result suggests that foam continued to reduce mobility by a modest amount even after long injection of gas. In this test, the large volume of gas had quickly penetrated far beyond the edge of the surfactant bank. In a design where a larger bank of surfactant were injected, a much greater and longer diversion of gas would be expected. On the other hand, foam did weaken progressively as it dried out. Foam models where foam remains strong at irreducible water saturation would greatly overestimate foam effectiveness at long times in this test.

No abstract