Low salinity water flooding has been recognized as prominent enhanced oil recovery technique acting at microscopic scale by reducing residual oil saturation thanks to a combination of intertwined mechanisms. In the last ten years, several studies and applications have been performed by Academia and Oil Companies giving indication of the process potentialities to increase oil production both in clastic and carbonate reservoirs. Low salinity is considered by eni a key EOR method to improve recovery of both green and brown fields due to low capital and operational costs, leading to favorable economics compared to riskier and more expensive EOR techniques. This work presents the state of art and describes eni's experience on low salinity waterflooding. Beneficial combination of low salinity water with polymer is also discussed as efficient and cost-effective EOR process for viscous oil fields. Eni has covered the whole low salinity life-cycle since 2006, from field candidate screening, laboratory experiments, log-inject-log tests, single well chemical tracer tests (SWCTT), accurate 3D reservoir modeling, desalination technique studies up to inter-well pilot tests. Experimental investigation in eni laboratories is executed to understand low salinity basic mechanisms and assess main parameters affecting fluid/rock/low salinity water interactions. Tertiary corefloods at field conditions are the first step to obtain evidence of beneficial effects. Lab results are reproduced by means of core-scale models to define simulation parameters. Obtained values are then applied on well and sector scale models for injection optimization and pilot design. Subsequently, field pilots such as SWCTT are performed, giving additional information on low salinity effectiveness. If positive results are confirmed and supported by updated simulation model, the technology is extended at inter-well and full field scale. Eni has developed robust best practices leveraging on internal laboratory, modeling work and field experience which are crucial to boost recovery factors and extend fields life.
We present and test a new screening methodology to discriminate amongst alternative and competing Enhanced Oil Recovery (EOR) techniques to be considered for a given reservoir. Our work is motivated by the observation that, even if a considerable variety of EOR techniques have been successfully applied to extend oilfield production and lifetime, an EOR project requires extensive laboratory and pilot tests prior to field-wide implementation and preliminary assessment of EOR potential in a reservoir is critical in the decision-making process. Since similar EOR techniques may be successful in fields sharing some global features, as basic discrimination criteria we consider fluid (density and viscosity) and reservoir formation (porosity, permeability, depth and temperature) properties. Our approach is observation-driven and grounded on an exhaustive data-base which we compile upon considering worldwide EOR field experiences. A preliminary reduction of the dimensionality of the parameter space over which EOR projects are classified is accomplished through Principal Component Analysis (PCA). A screening of target analogs is then obtained by classification of documented EOR projects through a Bayesian clustering algorithm. Considering the cluster which comprises the EOR field under evaluation, an intercluster refinement is then accomplished by ordering cluster components on the basis of a weighted Euclidean distance from the target field in the (multidimensional) parameter space. Distinctive features of our methodology are that (a) all screening analyses are performed on the database projected onto the space of principal components, and (b) the fraction of variance associated with each principal component is taken as weight of the Euclidean distance we determine. As a test bed, we apply our approach on three fields operated by eni. These include light, medium and heavy-oil reservoirs, where Gas, Chemical and Thermal EOR projects have been respectively proposed. Our results are (a) conducive to the compilation of a broad and extensively usable data-base of EOR settings and (b) consistent with the field observations related to the three tested and already planned/implemented EOR methodologies, thus demonstrating the effectiveness of our approach.
Underground storage of carbon dioxide, CO2, is one way to reduce atmospheric releases of greenhouse gases. The sequestration of CO2 in a depleted gas reservoir is simulated, incorporating molecular diffusion between CO2 and the natural gas, dispersion, dissolution of CO2 in water, and chemical reactions of the CO2 with the aqueous phase and host rock. This study is applied to a depleted gas reservoir located in the North of Italy. Since the end of production the field has been used for gas storage, and in this work it has been considered for a pilot project of CO2 injection. The different physical and chemical phenomena acting in the reservoir are simulated to investigate their influence on the total storage capacity. The effect of injection rate, the point of injection and the purity of the injection fluid are analyzed. While molecular diffusion of CO2 in methane can be neglected, the dissolution of CO2 in water increases the maximum storage capacity. Both the pattern of reservoir heterogeneity and the degree of mechanical dispersion has a notable impact on the results. Particular attention should be given to the composition of the injection fluid, because the presence of impurities strongly affects the total stored mass. Low injection rates give a larger total stored mass, since gravitational forces act to transport the CO2 to the top of the aquifer, but only after long periods of injection. Near the gas/water contact, the residual gas saturation has a significant impact on storage.Precipitation reactions render the CO2 immobile in a solid phase, but over a very long timescale. Introduction A depleted gas reservoir represents an attractive target for carbon sequestration for several reasons. It contains a geological trap, and thanks to years of production, it has a transport and injection infrastructure. Although depleted, these reservoirs still contain natural gas: CO2 injection can be thought as a way to enhance gas production thanks to either reservoir repressurization or pressure maintenance. Many studies have already suggested that additional methane can be produced with CO2 injection[1]. Other work[2,3] has determined the optimal injection strategy, and has demonstrated that the best recoveries are obtained for the case of conventional depletion of the gas reservoir until abandonment with subsequent injection of CO2[2]. In order to evaluate the feasibility of CSEGR (Carbon Sequestration with Enhanced Gas Recovery) in geological formations it is essential to understand the physical and chemical phenomena acting in the reservoir. Pruess and co-workers[4,5] have performed extensive simulation studies of CO2 storage in saline aquifers with an emphasis on capturing details of geochemical reactions.Obi and Blunt6 used streamline-based simulation to capture the effects of aquifer heterogeneity on the flow, but used a very simple reaction model.Other authors have performed simulation studies of CO2 storage in gas fields, aquifers and oil fields[1,2,3,7,8,9,10,11,12,13], but have generally not considered the combined impacts of reservoir heterogeneity, dissolution and rate-limited reaction in detail. Once in the reservoir, CO2 will move due to the pressure gradient and gravitational effects[14]. CO2 is much denser than methane in both supercritical and gas conditions at all relevant pressures15, thus it will flow downwards through the gas reservoir, displacing the methane and repressurizing the reservoir. The displacement will be stable since CO2 is more viscous than CH4.
Low Salinity waterflooding is an emerging Enhanced Oil Recovery technique in which the salinity of the injected water is controlled to improve oil recovery vs. conventional, higher salinity waterflooding. The objective of this work is the evaluation of low salinity water injection as EOR process in an on-shore field in West Africa. The field is heavily faulted and highly heterogeneous. The reservoir fluid is light crude oil; very different productive behaviours are present in the field. An experimental work was performed to verify the effectiveness of the process and make deeper investigation about the chemical and physical mechanisms involved in low salinity water injection. Core flooding experiments on reservoir porous media were carried out, giving promising results in terms of matrix additional oil recovery with low salinity waterflood. Furthermore, a simulation work to predict the benefits in the field was executed. Core experiments were reproduced using a wettability change model to obtain low salinity water parameters, the salt-dependent relative permeability curves. The process was scaled up to a fine sector model, calibrated on historical production data, representing the area of interest for low salinity water pilot. Simulations of low salinity water injection were run in different forecast scenarios and additional recovery was compared with sea water injection. In order to evaluate the global effect of low salinity water injection as EOR process, all the aspects were taken into consideration, decrease in residual oil saturation, permeability reduction, expected sweep efficiency on effective reservoir matrix volume. The experimental and simulation results were used for an economical feasibility study for a desalination plant in the field to reduce the salinity of current injected sea water.
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