Chemical enhanced oil recovery (CEOR) of heavy oils is growing in volume and scope due to advances in the technology and field experience. This work describes a new methodology to select a CEOR strategy in a heavy oil reservoir when several viable options exist. We applied this methodology to the Pelican Lake field in Alberta. We evaluated water flooding, polymer flooding, alkaline-surfactant-polymer (ASP) flooding, alkaline-co-solvent-polymer (ACP) flooding and polymer flooding followed by ASP flooding in laboratory tests. We executed new experiments including microemulsion phase behavior, polymer rheology and corefloods representing these various strategies. These experiments were designed to help understand the role of mobility control in chemical flooding of heavy oils. UTCHEM, the University of Texas Chemical Flooding Simulator, was used to model experimental results, and to scale them up in pilot simulations using heterogeneous geological models representative of Pelican Lake. We report results for the selection of promising CEOR strategies for implementation in Pelican Lake based on the new laboratory experiments, reservoir simulations and our qualitative understanding of their various advantages and disadvantages. We present simulation results of a pilot using horizontal wells in a heterogeneous geological model representative of the reservoir. We simulated the various chemical EOR processes using the matched experimental data and evaluated them in terms of total oil production, time to completion and complexity. In-situ oil viscosity and operational injection limits were evaluated as crucial sensitivities. We make recommendations for CEOR implementation based on simulation study results and our understanding of relative process risks and costs.

Microemulsion properties significantly impact any EOR process that relies on surfactants or soaps to generate ultralow interfacial tension to displace trapped oil. Unfavorable microemulsion viscosity can lead to high chemical retention, low oil recovery, and overall unfavorable performance across all modes. Controlling microemulsion properties is important in conventional approaches like surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP) flooding, in addition to new applications like gravity stable displacements, spontaneous imbibition in fractured carbonates and unstable floods of viscous oil. Despite the central importance, microemulsion viscosity and rheology remain poorly understood. This paper describes the results of an extensive experimental microemulsion study. We evaluated the effect of polymer on microemulsion viscosity in different microemulsion phase types (i.e. oil in water, bi-continuous, water in oil emulsions). We measured microemulsion viscosities across a broad salinity range for several crudes from light (API >30°) to heavy oils (API<14°) and observed Newtonian rheology for all phase types. The effect of cosolvents on microemulsion viscosity was also evaluated. Finally, we evaluated microemulsions with and without alkali to help understand potential differences between ASP and SP microemulsions. We include many observations consistent with earlier literature using recently developed surfactants and report the microemulsion viscosity details for many high performance surfactant formulations across a wide range of conditions. We have also describe several observations, including polymer decreasing the required time to achieve equilibrium in microemulsion pipettes and the qualitative change in microemulsion behavior with and without polymer in Windsor Type III microemulsions.

Waterflood oil recovery in many carbonate oil reservoirs is low due to both high residual oil saturations and low sweep efficiency because of high heterogeneity. An example is the Sabriyah Mauddud reservoir in Kuwait. Alkaline-surfactant polymer flooding (ASP) has great potential for enhanced oil recovery both because ASP flooding reduces residual oil saturation and because of the polymer improves sweep efficiency. Unfortunately, the initial ASP coreflood experiments using conventional alkali showed unacceptably high surfactant retention in the reservoir cores. Several approaches to reducing surfactant retention were tested. Numerous strategies such as the use of chelating agents, sacrificial agents and chemical gradients were tested to reduce retention. The most effective strategy used a hybrid-alkali (NaOH + Na2CO3) in addition to a hydrophilic polymer drive containing a novel co-solvent. In this approach injection pH was increased to 12.5, compared to 10.5 using only Na2CO3. Such high pH is undesirable in sandstones because of reactions with silica minerals, but theexperimental results described here suggest the process is suitable for carbonate reservoirs. With this approach, both low surfactant retention and high oil recovery were achieved in very tight reservoir cores (8-35 mD). This novel approach was validated in a live oil coreflood using preserved cores to represent the reservoir material in the most rigorous way possible. This significant decrease in surfactant retention makes ASP flooding in the Sabriyah Mauddud reservoir viable.

Single-well-partitioning-tracer tests (SWTTs) are used to measure the saturation of oil or water near a wellbore. If used before and after injection of enhanced-oil-recovery (EOR) fluids, they can evaluate EOR flood performance in a so-called one-spot pilot. Four alkaline/surfactant/polymer (ASP) one-spot pilots were recently completed in Kuwait's Sabriyah-Mauddud (SAMA) reservoir, a thick, heterogeneous carbonate operated by Kuwait Oil Company (KOC). UTCHEM (Delshad et al. 2013), the University of Texas chemical-flooding reservoir simulator, was used to interpret results of two of these one-spot pilots performed in an unconfined zone within the thick SAMA formation. These simulations were used to design a new method for injecting partitioning tracers for one-spot pilots. The recommended practice is to inject the tracers into a relatively uniform confined zone, but, as seen in this work, that is not always possible, so an alternative design was needed to improve the accuracy of the test.The simulations showed that there was a flow-conformance problem when the partitioning tracers were injected into a perforated zone without confinement after the viscous ASP and polymer-drive solutions. The water-conveyed-tracer solutions were being partially diverted outside of the ASP-swept zone where they contacted unswept oil. Because of this problem, the initial interpretation of the performance of the chemicals was pessimistic, overestimating the chemical residual oil saturation (ROS) by up to 12 saturation units. Additional simulations indicated that the oil saturation in the ASP-swept zone could be properly estimated by avoiding the post-ASP waterflood and injecting the post-ASP tracers in a viscous polymer solution rather than in water. An ASP one-spot pilot using the new SWTT design resulted in an estimated ROS of only 0.06 after injection of chemicals (Carlisle et al. 2014). These saturation values were obtained by history matching tracer-production data by use of both traditional continuously-stirred-tank (CSTR) models and compositional, reactivetransport reservoir models.The ability of the simulator to model every phase of the onespot pilot operation was crucial to the insight of modified SWTT design. The waterflood, first SWTT, ASP flood, and the final SWTT were simulated using a heterogeneous permeability field representative of the Mauddud formation. Laboratory data, field-ASP quality-control information, and injection strategy were all accounted for in these simulations. We describe the models, how they were used, and how the results were used to modify the SWTT design. We further discuss the implications for other SWTTs.The advantage of mechanistic simulation of multiple aspects of a one-spot pilot is an important theme of this study. Because the pore space investigated by the SWTTs can be affected by the previously injected EOR fluids (and vice versa), these interactions should be accounted for. This simulation approach can be used to identify and mitigate design problems during each phase of a challenging one-s...

Our team has developed a new simulation model for an upcoming 5-spot Alkaline-Surfactant-Polymer (ASP) pilot in the Sabriyah Mauddud reservoir in Kuwait. We present new pilot simulation results based on new data from pilot wells and an updated geocelluar reservoir model. New cores and well logs were used to update the geocellular model, including initial fluid distributions, permeability and layer flow allocation. From the updated geocellular model a smaller dynamic sector model was extracted to history match field performance of a waterflood pattern. From the dynamic model a yet smaller pilot model was extracted and refined to simulate the 5-spot ASP pilot. We used this pilot model to evaluate injection composition, zonal completions, observation well locations, interwell tracer test design and predicted performance of ASP flooding. A sensitivity analysis for some important design variables and pilot performance benchmarks is also included. We used multiple interwell tracer test simulations to estimate reservoir sweep efficiency for both water and ASP fluids, and to help us understand how well operations will affect this unconfined ASP pilot. This work details some crucial aspects of pre-ASP pilot design and implementation.