As indicated by the arrows, in addition to injector I1, producers P1 and P2 are closely connected with the I2 and I3 injectors. The pattern is limited by two faults trending northwest-to-southeast. The confined nine-well pattern chosen for the pilot is shown in panel A in Figure 1. This was expected to favor near-wellbore foam injectivity, followed by longer-range propagation at higher mobility reduction factors. The formulation also shows a classical shear thinning behavior, with mobility reductions above 20 at velocities of 25 feet/day down to 10 at high near-wellbore velocities of 150 feet/day. It foams well and gives a very stable, dense and long-life CO 2 foam. It is soluble at ambient temperature in salinities up to 1.5 times that of the injection water, and at reservoir temperature (150 degrees Fahrenheit with permeability and porosity averaging 300 millidarcy and 28 percent porosity, respectively) in injection water. The selected surfactant represents the best compromise between the lab-measured performance indicators. In preparing the formulation, the decision was made to mix the high-salinity, hard produced water in a one-to-one ratio with freshwater from a shallow well. Five formulations of hydrocarbon-based surfactants were studied to evaluate solubility in injection water at ambient and reservoir temperatures, CO 2 foam stability and life at reservoir pressure/temperature conditions, static adsorption and foam-induced mobility reduction in porous media.īesides the technical performance of the formulations, complementary data also were considered, including determining optimal blend concentration for easy handling, timing for blend dissolution in injection water at surface conditions, and blend emulsion risk assessment. A specific “fast-track” workflow combining simultaneous bulk and porous media measurements was applied. This challenge was overcome based on successive steps in laboratory experimentation, including automated solubility evaluating multicomponent formulations, adsorption measurements, foam stability evaluation and core floods under actual reservoir conditions. Extreme values correspond to saturated brine with possible salt precipitation at surface conditions. In addition, water salinity across the field varies depending on the configuration of producing wells. One of the main challenges to successfully implementing the pilot was designing an adapted foaming formulation using an extremely high-salinity and hard produced water for chemical injection (sodium concentrations as high as 78.6 grams per liter, and total dissolved solids to 317 grams/liter). The treatment was applied as three alternating slugs of aqueous foaming solution and CO 2 over a period of four months.
![geomodel solids geomodel solids](https://www.eaieducation.com//images/products/530166_S.jpg)
Compared with mechanical or gel treatments, foam is relatively inexpensive and easy to apply with minimal risk of reservoir damage.īecause the pilot targeted conformance rather than in-depth mobility control, a relatively low foam volume (1 percent of the pattern’s pore volume) was injected.
![geomodel solids geomodel solids](https://m.media-amazon.com/images/I/41t60hxVrmL._AC_.jpg)
Indeed, foam injection is a proven method to improve CO 2 flood conformance and increase CO 2 efficiency.
![geomodel solids geomodel solids](https://www.researchgate.net/profile/Philippe-Calcagno/publication/278736552/figure/fig1/AS:294294989623296@1447176801305/Workflow-is-the-classical-way-for-combining-data-The-3D-geomodel-is-the-final-result-of_Q320.jpg)
It was expected that this would result in more efficient CO 2 utilization and lower GORs (i.e., lower produced gas rates with stable or higher oil rates). The foam pilot sought to divert CO 2 from a “thief zone” to the other zones by generating stable CO 2 in water foam in the offending zone. The multilayered sandstone reservoirs are open in several sands in the injectors and producers, and are grossly divided in three main zones. This explains why the macroscopic efficiency of CO 2 injection was limited in the field, despite the excellent microscopic efficiency of CO 2 to unlock oil trapped by capillarity during waterflooding. Premature gas breakthrough and high GORs result in an inefficient flood and diminished oil recovery. However, a significant problem with continuous CO 2 injection is poor sweep efficiency when flooding multiple distinct sands with significant permeability variations. The goal of injecting surfactant was to generate foam in-situ in the near-wellbore area to optimize pattern performance.Ĭontinuous CO 2 injection has several advantages over CO 2 water-alternating-gas (WAG) injection, especially in strongly water-wet reservoirs. The foam injection pilot was carried out on an existing 40-acre pattern where premature breakthrough had resulted in high gas-to-oil ratios and reduced oil rates. HOUSTON–Using foam for conformance control in enhanced oil recovery projects has the potential to not only improve oil rates, but also to increase gas injection efficiency and reduce gas injection and cycling costs.Ī dedicated foaming formulation was developed for a Denbury Resources-operated Gulf Coast field undergoing continuous carbon dioxide injection.