Successful field waterflood is a crucial prerequisite for improving the performance before EOR methods, such as ASP, SP, and P flooding, are applied in the field. Excess water production is a major problem in mature waterflooded oil fields that leads to early well abandonment and unrecoverable hydrocarbon. Gel treatments at the injection and production wells to preferentially plug the thief zones are cost-effective methods to improve sweep efficiency in reservoirs and reduce excess water production during hydrocarbon recovery. There are extensive experimental studies performed by some researchers in the past to investigate the performance of gels in conformance control and decreasing water production in mature waterflooded reservoirs, but no substantial modeling work has been done to simulate these experiments and predict the results for large field cases.
We developed a novel, 3-dimensional chemical compositional and robust general reservoir simulator (UTGEL) to model gel treatment processes. The simulator has the capability to model different types of microgels, such as preformed particle gels (PPG), thermally active polymers (TAP), pH-sensitive microgels, and colloidal dispersion gels (CDG). The simulator has been validated for gel flooding using laboratory and field scale data. The simulator helps to design and optimize the flowing gel injection for conformance control processes in larger field cases.
The gel rheology, adsorption, resistance factor and residual resistance factor with salinity effect, gel viscosity, gel kinetics, and swelling ratio were implemented in UTGEL. Several simulation case studies in fractured and heterogeneous reservoirs were performed to illustrate the effect of gel on production behavior and water control. Laboratory results of homogeneous and heterogeneous sandpacks, and Berea sandstone corefloods were used to validate the PPG transport models. Simulations of different heterogeneous field cases were performed and the results showed that PPG can improve the oil recovery by 5-10% OOIP compared to waterflood.
For recovery from fractured reservoirs by waterflooding, injected water will flow easily through fractures and most part of reservoir oil will remain in matrix blocks unrecovered. Recovery from these reservoirs depends on matrix permeability, wettability, fracture intensity, temperature, pressure, and fluid properties. Chemical processes such as polymer flooding (P), surfactant/polymer (SP) flooding and alkali/surfactant/polymer (ASP) flooding are being used to enhance reservoir energy and increase the recovery. Chemical flooding has much broader range of applicability than in the past. These include high temperature reservoirs, formations with extreme salinity and hardness, naturally fractured carbonates, and sandstone reservoirs with heavy and viscous crude oils.
The recovery from fractured carbonate reservoirs is frequently considered to be dominated by spontaneous imbibition. Therefore, any chemical process which can enhance the rate of imbibition has to be studied carefully. Wettability alteration using chemicals such as surfactant and alkali has been studied by many researchers in the past years and is recognized as one of the most effective recovery methods in fractured carbonate reservoirs. Injected surfactant will alter the wettability of matrix blocks from oil-wet to water-wet and also reduce the interfacial tension to ultra-low values and consequently more oil will be recovered by spontaneous co-current or counter-current imbibition depending on the dominant recovery mechanism.
Accurate and reliable up-scaling of chemical enhanced oil recovery processes (CEOR) are among the most important issues in reservoir simulation. The important challenges in up-scaling CEOR processes are predictability of developed dimensionless numbers and also considering all the required mechanisms including wettability alteration and interfacial tension reduction. Thus, developing new dimensionless numbers with improved predictability at larger scales is of utmost importance in CEOR processes. There are some scaling groups developed in the past for either imbibition or coreflood experiments but none of them were predictive because all the physics related to chemical EOR processes (interfacial tension reduction and wettability alteration) were not included.
Furthermore, most of commercial reservoir simulators do not have the capability to model imbibition tests due to lack of some physics, such as surfactant molecular diffusion. The modeling of imbibition cell tests can aid to understand the mechanisms behind wettability alteration and consequently aid in up-scaling the process. Also, modeling coreflood experiments for fractured vuggy carbonates is challenging. Different approaches of random permeability distribution and explicit fractures were used to model the experiments which demonstrate the validity and ranges of applicability of upscaled procedures, and also indicate the importance of viscous and capillary forces in larger scales. The simulation models were then used to predict the recovery response times for larger cores.
| Identifer | oai:union.ndltd.org:UTEXAS/oai:repositories.lib.utexas.edu:2152/31338 |
| Date | 16 September 2015 |
| Creators | Goudarzi, Ali |
| Contributors | Johnston, Keith P., 1955-, Sepehrnoori, Kamy, 1951-, Delshad, Mojdeh |
| Source Sets | University of Texas |
| Language | English |
| Detected Language | English |
| Type | Thesis, text |
| Format | application/pdf |
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