The Loma Alta Sur Field is a mature waterflood in the Neuquén Basin of Argentina. The productive formation (Grupo Neuquen) consists of numerous fluvial, multi-layer sandstone packages. Extensive diagnostics, including tracers, injection profiles, review of historical production and reservoir fluid analysis corroborated the combined effect of reservoir heterogeneity and an adverse mobility ratio. High concentration polymer gels, sometimes called "bulk gels", can be effective in reducing water channeling in naturally fractured formations or in reservoirs with multi-darcy permeability anomalies. However, the Loma Alta Sur Field produces from a multi-layer unfractured matrix rock reservoir and is not a candidate for traditional bulk gel treatments. Uncrosslinked polymer is an alternative for improving an adverse mobility ratio, but is most effective in relatively homogeneous reservoirs in order to minimize polymer breakthrough in offset producing wells. The primary objective of the the operator in this pilot was to improve volumetric sweep efficiency. CDG's were selected for the Loma Alta Field for several reasons:CDG's offer significantly higher adsorption and residual resistance factors than uncrosslinked polymerCDG's can be injected in matrix rock andfresh water was not required for gel formation at low polymer concentrations. Extensive diagnostics were applied before and after the CDG injection, including tracers, injection profiles and analysis of historical production data. Post treatment analysis of the CDG treatments indicate positive oil and water trends in the pilot area. Introduction The Loma Alta Sur field is located in the province of Mendoza in the Neuquén Basin of Argentina (Figure 1). The productive reservoir is the Grupo Neuquen Formation, which is characterized as heterogeneous multi-layer sandstone. In an effort to control the vertical distribution of injected water, injection wells are completed with downhole selective injection mandrels. However, the combined effects of heterogeneity within the individual layers and the extremely adverse mobility ratio motivated the operator to evaluate techniques for in-depth volumetric sweep improvement. Polymer is a traditional alternative for viscosifying water and lowering the mobility ratio. However, relatively homogeneous reservoirs are preferred in order to avoid polymer breakthrough in offset producing wells. The objective of the operator was to apply a staged chemical injection program that would reduce water channeling in the highest permeability layers and, as a secondary benefit, improve the oil-water mobility ratio.

A considerable portion of current world oil production comes from mature fields and the rate of replacement of the produced reserves by new discoveries has been declining steadily over the last few decades. To meet the growing need for economical energy throughout the world, the recoverable oil resources in known reservoirs that can be produced economically by applying advanced IOR and EOR technologies will play a key role in meeting the energy demand in years to come. This paper presents a comprehensive review of EOR projects. Specifically, the paper presents an overview of EOR field projects by reservoir lithology (sandstone, carbonate, and turbidite formations) and offshore versus onshore fields. More than 1,500 field projects are reviewed and summarized to evaluate feasibility of EOR technologies. Another area of growing interest is the combination of near-well-bore and in-depth conformance technologies with chemical EOR technologies such as SP and ASP. However, these are in early stages of evaluation. Examples of numerical simulations combining chemical conformance and EOR technologies are presented showing the potential of this recovery strategy in waterflooded reservoirs. Impacts of carbon capture cost and volatility of oil and carbon-credit markets on CO2-EOR projects based on anthropogenic sources is also addressed. Based on this review, it is evident that thermal and chemical EOR projects dominate in sandstone formations while gas and water-based recovery methods dominate carbonate, turbidite, and offshore fields. The review also shows the growing trend of CO2 (from natural sources), high-pressure air injection (HPAI), and chemical flooding including in-depth conformance field projects in the U.S. and abroad. CO2-EOR / sequestration in offshore fields and chemical EOR processes offshore (e.g., polymer-based methods) and onshore, including heavy crude oil reservoirs, are some of the opportunities identified for the next decade based on preliminary evaluations and proposed or ongoing pilot projects. The critical review will help to identify the next challenges and opportunities in EOR. Hybrid schemes combining IOR/EOR as well as CO2-EOR/sequestration can be ranked on the basis of adequate simulation procedures.

Layered hydrotalcite materials containing redox active components activate two uptake mechanisms driven by ion exchange and the redox reactions, greatly enhancing affinity and selectivity toward anions of iodine.

A common problem in many waterflooded oil reservoirs is early water breakthrough with high water cut through highly conductive thief zones. Thermally active polymer (TAP), which is an expandable submicron particulate of low viscosity, has been successfully used as an in-depth conformance to improve sweep efficiency of waterfloods.This paper describes the workflow to evaluate technical feasibility of this conformance technology for proper pilot-project designs supported with detailed simulation studies. Two simulation approaches have been developed to model properties of this polymer and its interaction with reservoir rock. Both methods include temperature-triggered viscosification and adsorption/retention effects. Temperature profile in the reservoir is modeled by energy balance to accurately place this polymer at the optimum location in the thief zone. The first method considers a single chemical component in the water phase. The second method is based on chemical reactions of multiple chemical components. Both simulation approaches are compared and discussed.Results show that temperature-triggered polymers can increase oil recovery by viscosification and chemical adsorption/retention, which reduces thief-zone permeability and diverts flow into unswept zones. Sensitivity analyses suggest that ultimate oil recovery and conformance control depend on the thief-zone temperature, vertical-to the horizontal-permeability ratio (K v /K h ), thief-zone vertical location, injection concentration and slug size, oil viscosity, and chemical adsorption and its reversibility, among other factors. For high-flow-capacity thief zones and mobility ratios higher than 10, oil recoveries can be improved by increasing chemical concentration or slug size of treatments, or both. Reservoirs with low K v /K h (< 0.1) and high permeability contrast generally shows faster incremental recoveries than reservoirs with high K v /K h and strong water segregation.The presented workflow is currently used to perform in-depth conformance treatment designs in onshore and offshore fields and can be used as a reference tool to evaluate benefits of the TAP in waterflooded oil reservoirs.Gholamreza Garmeh is a Reservoir Engineer at TIORCO. He is responsible for modeling and design of chemical-flooding and conformance-improvement projects. His research interests are chemical and miscible gas EOR techniques and numerical reservoir simulation. He holds a BS degree from the Petroleum University of Technology in Iran and MS and PhD degrees from the University of Texas at Austin, all in petroleum engineering. He serves as peer-reviewer for SPEREE and SPE Journal.Mehdi Izadi is a Senior Reservoir Engineer at TIORCO. He has more than 9 years of experience in reservoir simulation and EOR techniques. He is responsible for modeling and design of chemical-flooding projects and support of post-treatment

Multifunctional Sn(ii/iv) based composite for highly selective reductive separation of Tc(vii) that undergo phase changes to accommodate the reduced Tc(iv).

The Golfo San Jorge (GSJ) is located in the southern Argentina provinces of Santa Cruz and Chubut. This hydrocarbon basin occupies a surface area of approximately 170,000 km2, approximately 1/3 of which is offshore. Waterflood oil recovery in many GSJ reservoirs does not exceed 10% OOIP due to the combined effects of reservoir heterogeneity and, in many fields, an adverse mobility ratio. The most significant hydrocarbon accumulations of the basin occur in a series of fluvial and shallow lacustrine reservoirs with significant tuffaceous content. A typical GSJ hydrocarbon reservoir includes a series of relatively thin sandstone packages that are not believed to be naturally fractured. In an effort to distribute water injection more uniformly, most injection wells are equipped with injection mandrels. However, heterogeneity within the productive layers limits the effectiveness of near wellbore selective injection. A recent field pilot combining two types of gel technologies in the Comodoro Rivadavia Formation, one of the most prolific GSJ reservoirs, is encouraging. Based on tracer studies, historical production data and reservoir characterization, approximately 15,000 barrels of MarcitSM gels were injected in each of two adjacent injection wells. Seven months after the Marcit gel treatments, the operator began a colloidal dispersion gel (CDG) pilot in the same two patterns, injecting a total CDG pore volume of approximately 18% in certain layers of the Comodoro Rivadavia Formation. A chemical injection plant was connected at a point upstream of the two injectors so that both wells could be treated simultaneously, with the flexibility to vary the rate and polymer gel concentration in each well. A discussion of the reservoir characterization will be presented as well as the chemical treatment designs, subsequent modifications in the course of the pilot, and recommendations. Introduction Reservoir heterogeneity is the biggest challenge to oil recovery in waterfloods. Heterogenity is essentially any nonuniformity in the productive reservoir, including, but not limited to variablilty in permeability and porosity, anisotrophy, fractures, faults and compartmentalization. Anyone who has studied the classic theories of Buckley and Leverett (1942), Stiles (1949), and Dyktra-Parsons (1950) among others appreciates the dramatic effect of heterogeneity on ultimate oil recovery. In the GSJ of Argentina, injection wells are typically completed with downhole selective injection installations (mandrels) designed to improve vertical distribution of water injection. However, near wellbore mechanical configurations do not address in-depth reservoir heterogeneities. Polymer gels are designed to reduce the effects of reservoir heterogeneity beyond the near wellbore area. The basic premise of any gel technology is that the pre-gel solution, or gelant, will preferentially enter high permeability anomalies responsible for low volumetric sweep efficiency. The theory is that once the gels reduce the flow capacity in the "thief zones", areal and vertical sweep efficiency will be improved. This project describes the pilot area evaluation, gel design and field implementation of two polymer gel technologies: Marcit gels (Sydansk 1938) and colloidal dispersion gels (CDG) (Mack 1994). Marcit gels are high polymer concentration gels designed for application in reservoirs with extreme heterogeneities such as natural or induced fractures, fissures and other multi-darcy permeability anomalies. CDG's are typically large volume, low polymer concentration gels designed to improve sweep efficiency in unfractured matrix reservoirs that exhibit poor waterflood performance. Many waterfloods exhibit both types of heterogeneities.

Colloidal Dispersion Gels (CDG's) have been successfully tested in Argentina, China, USA, and recently in Colombia. However, questions remain whether CDG's can be injected in large volumes and propagate deep into the formation without reducing injectivity and also improve sweep efficiency. This paper summarizes 31 implemented and ongoing CDG projects in Argentina, Colombia and the U.S. since 2005. Project summary review includes main reservoir properties, operating conditions, pore volume of chemical injected, general project performance, and especially, a detailed analysis of injection logs addressing the injectivity of CDG. Additionally, a general approach for history matching CDG floods is described. CDG injection volumes in projects reviewed vary from a few thousand barrels to hundreds of thousands of barrels. Projects evaluated did not show injectivity reduction even after more than 600,000 barrels injected in one well. Polymer concentration and polymer: crosslinker ratios ranged from 250 to 1,200 ppm and 20:1 to 80:1, respectively. Aluminum citrate is the most common crosslinker used in field projects. However, chromium triacetate has been used in high salinity and hardness conditions. Key variables to sustain the injection of large volumes of CDG below maximum operating pressure are polymer: crosslinker ratios, polymer concentration, and injection rates to a lesser extent. CDG projects have evolved from small to large treatment volumes showing a positive impact on oil recoveries. Despite large volumes of CDG injected production of polymer in offset producers has rarely been detected. Wellhead pressure response, CDG viscosity, and adsorption/retention (RRF) represents the most important variables needed to match CDG floods. This study provides the status of the technology and field evidence that CDG's can be injected in large volumes and can propagate into the reservoir without injectivity constraints. This review will also provide guidance to successfully design and evaluate CDG pilot projects. Lessons learned from operating and modeling CDG projects will also be presented.

A common problem in many waterflooded oil reservoirs is early water breakthrough with high water cut through highly conductive thief zones. Thermally active polymer, which is an expandable sub-micron particulate of low viscosity, has been successfully used as an in-depth conformance to improve sweep efficiency of waterfloods. This paper describes the workflow to evaluate technical feasibility of this conformance technology for proper pilot project designs supported with detailed simulation studies. Two simulation approaches have been developed to model properties of this polymer and its interaction with reservoir rock. Both methods include temperature triggered viscosification and adsorption/retention effects. Temperature profile in the reservoir is modeled by energy balance to accurately place this polymer at the optimum location in the thief zone. The first method considers a single chemical component in the water phase. The second method is based on chemical reactions of multiple chemical components. Both simulation approaches are compared and discussed. Results show that temperature-triggered polymers can increase oil recovery by viscosification and chemical adsorption/retention, which reduces thief zone permeability diverting flow into unswept zones. Sensitivity analyses suggest that ultimate oil recovery and conformance control depends on the thief zone temperature, vertical to horizontal permeability ratio (Kv/Kh), thief zone vertical location, injection concentration and slug size, oil viscosity, chemical adsorption, and its reversibility, among others. For high flow capacity thief zones and mobility ratios higher than 10, oil recoveries can be improved by increasing chemical concentration or slug size of treatments, or both. Low Kv/Kh (&lt; 0.1) and high permeability contrast generally shows faster incremental recoveries than high Kv/Kh with strong water segregation reservoirs. The presented workflow is currently used to perform in-depth conformance treatment designs in on-shore and off-shore fields and can be used as a reference tool to evaluate benefits of the thermally active polymer in waterflooded oil reservoirs.