Time filter

Source Type

United States

SPE - DOE Improved Oil Recovery Symposium Proceedings | Year: 2012

The objective of the work detailed was to develop an alkaline-surfactant-polymer (ASP) and achieve good oil recovery at low surfactant concentrations. A combination of phase behavior tests, interfacial tension (IFT) measurements (by spinning drop tensiometer) and coreflood tests were used to develop a solution for an oil that had an API gravity of 15 and viscosity of 2,000 cP. The percentage of heavy oil in world oil production continues to rise as more light oil reservoirs have either depleted or reached their economic limit. However, the recovery factor from heavy oil reservoirs by both primary and secondary production is low, making these reservoirs candidates for chemical EOR technologies. Phase behavior tests were used as the primary screening method to identify surfactant formulations qualitatively and the promising candidates were validated by IFT measurements (between the surfactant solution and oil) at different salinities to identify the lowest IFT formulation. Static adsorption tests with reservoir core material were used as a further screening step to ensure formulation was a viable option. Finally, linear coreflood tests were performed at reservoir temperature to validate the formulation and optimize chemical concentration. In one coreflood, 80% of waterflood residual oil was recovered using only 0.15% total surfactants and 2,000 ppm polymer. The success of the ASP coreflood validates the ASP design for this heavy oil. Typically, heavy oil reservoirs may require lower surfactant concentrations due to higher permeability. As a result, such projects could potentially have a higher reward-risk ratio than ASP projects in conventional oil reservoirs.

Kazempour M.,University of Wyoming | Kazempour M.,TIORCO LLC | Gregersen C.S.,University of Wyoming | Alvarado V.,University of Wyoming
Fuel | Year: 2013

Chemical enhanced oil recovery projects occasionally introduce an alkali agent to meet design requirements. The alkali agent reacts with reservoir rock components upon injection in reservoirs. It has been reported that the interaction of the injected alkali with some minerals in the rock assemblage, particularly anhydrite, is responsible for the very large alkali consumption, formation of secondary minerals, and regulates water chemistry. These effects, when unanticipated, can jeopardize the success of a chemical flooding project. In this study, single and two-phase flow flooding tests were carried out using rock samples from a sandstone reservoir in Wyoming to investigate the impact of multiphase flow on anhydrite dissolution at high-pH conditions. Effluent water chemistry was analyzed to investigate rock-fluid interactions taking place during an alkaline flood. Rock samples were CT-scanned to find out anhydrite distribution. Mitigation of harmful effects of rock-fluid interactions under alkaline flooding has been proposed through the addition of ethylenediaminetetraacetic acid (EDTA) to act as a calcium chelating agent. The effectiveness of EDTA was tested in single- and two-phase flow experiments. An alternative approach to mitigate damaging effects of alkali injection in anhydrite-containing rock, based on conditioning of injection water, was tested in this work. Results show that anhydrite dissolution diminishes when crude oil is present, but the effect depends on rock exposure time to oil (aging). In spite of the apparent decreased reactivity, anhydrite dissolution is still very pronounced in two-phase flow experiments. Results also show conclusively that water conditioning intended to diminish anhydrite dissolution chemical driving force is a more effective strategy to attain sustainable flooding conditions. © 2012 Elsevier Ltd. All rights reserved.

Kazempour M.,TIORCO LLC | Alvarado V.,University of Wyoming | Manrique E.J.,TIORCO LLC | Izadi M.,TIORCO LLC
Society of Petroleum Engineers - SPE Heavy and Extra Heavy Oil Conference - Latin America 2014, LAHO 2014 | Year: 2014

Alkali-surfactant-polymer (ASP) flooding is a commercially viable enhanced oil recovery method. The complexity of chemical interactions, multi-phase flow, emulsification, capillary number changes and upscaling issues, especially in highly heterogeneous reservoir, make field designs difficult to extrapolate from coreflood measurements. In this work, two representaions of low interfacial tension conditions in chemical flooding were evaluated to determine the impact of model formulation on scaling-up from lab data to field situations. The first one is a mechanistic model based on interpolation of relative permeability curves parametrized with respect to the local capillary number. The second model requires tracking a thermodynamically stable phase known to exist at water-oil ultralow interfacial tension, namely a microemulsion. To perform this analysis, two sets of chemical coreflooding results were history matched and then the tuned models were utilized for field-scale predictions. For ASP flooding, a sensitivity analysis was implemented to show the importance of microemulsion phase on ASP upscaled (field scale) forecast. In this study, coreflooding experiments were performed using three different crude oils, case I: heavy oil with high acid number, case II: medium oil with high acid number and finally, case III: light oil with very low acid number. Predictions between the two modeling approaches are shown to diverge from each other upon upscaling of core-scale history matched models. This discrepancy is mostly attributed to the need to track a microemulsion phase behavior as well as its properties. Effects are more pronounced for heavier oil with high acid number. The results of this analysis should be useful to constrain field projections of any field design of surfactant-assisted EOR projects. Additionally, this study provides guidelines to understand existing uncertainties in current chemical flooding simulation regarding our ability to accurately predict the results of such a chemical flood design. Copyright 2014, Society of Petroleum Engineers.

Proceedings - SPE Symposium on Improved Oil Recovery | Year: 2014

Poor conformance is a problem that has plagued most operators of water and enhanced oil recovery (EOR) floods. Conformance improvement has been shown to significantly improve oil recovery;however ,effectively selecting and implementing the correct conformance improvement technique still remains a complicated proposition. The selection of the correct technique is only becoming even more important as the industry advances EOR floods where it is critical in these capital intensive projects to effectively sweep the reservoir. Traditionally many operators have relied on mechanical or cement solutions to deal with poor conformance. Although these methods certainly have their place in conformance engineering they deal more with wellbore issues rather than reservoir flow dominated situations. The latter situation can be characterized as flow through highly conductive reservoir features such as fractures or highly permeable thief zones. In such situations it is advantageous to use a technology that can penetrate into the offending feature providing sustainable results. In water or EOR floods,the treatment of injection wells with polymer gels has been shown to be an effective technology in addressing such reservoir conformance issues. Extensive research has gone into characterizing polymer gels and numerous field case studies have been published. However ,few references aid in understanding when polymer gels should be used and the critical aspects of designing and implementing such treatments. This paper will focus on diagnosing those conformance issues where it is most appropriate to use polymer gels. Further,it will explain how reservoir characterization should drive the design and implementation of this technology. Four injection well case studies will be used to develop a Polymer Gel Conformance Improvement Matrix that will provide heuristics for designing a polymer gel treatment. Finally,lessons learned from the case studies will be presented to give guidance on diagnosing conformance issue along with the design and implementation of conformance improvement polymer gel treatments. Copyright 2014,Society of Petroleum Engineers.

Salehi M.,University of Kansas | Salehi M.,TIORCO LLC | Johnson S.J.,University of Kansas | Liang J.-T.,University of Kansas
Journal of Surfactants and Detergents | Year: 2010

The main production mechanism during water flooding of naturally fractured oil reservoirs is the spontaneous imbibition of water into matrix blocks and resultant displacement of oil into the fracture system. This is an efficient recovery process when the matrix is strongly water-wet. However, in mixed- to oil-wet reservoirs, secondary recovery from water flooding is often poor. Oil production can be improved by dissolving low concentrations of surfactants in the injected water. The surfactant alters the wettability of the reservoir rock, enhancing the spontaneous imbibition process. Our previous study revealed that the two main mechanisms responsible for the wettability alteration are ion-pair formation and adsorption of surfactant molecules through interactions with the adsorbed crude oil components on the rock surface. Based on the superior performance of surfactin, an anionic biosurfactant with two charged groups on the hydrophilic head, it was hypothesized that the wettability alteration process might be further improved through the use of dimeric or gemini surfactants, which have two hydrophilic head groups and two hydro-phobic tails. We believe that when ion-pair formation is the dominant wettability alteration mechanism, wettability alteration in oil-wet cores can be improved by increasing the charge density on the head group(s) of the surfactant molecule since the ion-pair formation is driven by electrostatic interactions. At a concentration of 1.0 mmol L-1 a representative anionic gemini surfactant showed oil recoveries of up to 49% original oil-in-place (OOIP) from oil-wet sandstone cores, compared to 6 and 27% for sodium laureth sulfate and surfactin, respectively. These observations are consistent with our hypothesis. © AOCS 2010.

Discover hidden collaborations