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Abstract

The evaluation of complex carbonate reservoirs is a challenging task for petrophysicists and reservoir engineers, and a detailed understanding of reservoir heterogeneity and its relation to wettability, fluid distribution and flow properties is still lacking.

In previous publications we investigated the effect of sample sizes on poroperm variations and cementation factors derived from resistivity measurements. Whole cores were essential in capturing representative data in heterogeneous carbonates. In this study the effect of static rock type and sample size (i.e. plugs versus whole cores) was investigated on SCAL data derived from capillary pressure and resistivity index experiments at reservoir temperature and net confining stress. The plugs and whole cores were initially selected according to static rock types comprising lithofacies classification and petrophysical grouping.

The obtained SCAL data from plugs and whole cores in each rock type grouping were studied in light of the initial static rock type. Data variations within the same rock type were detected among the plugs and between the plugs and the whole cores. Those variations were investigated in details to understand the degree of local heterogeneity and its effect on static and dynamic SCAL data. Data variations between the different static rock types were also investigated and assessed on the basis of dynamic imbibition data. Whole cores were generally found to yield different capillary pressure and saturation exponents that may not be possible to derive from average plug data. Those petrophysical variations will have large impact on reservoir rock types and saturation functions for optimum reservoir performance predictions.
 
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Abstract

An Alkaline-Surfactant-Polymer / Surfactant-Polymer (ASP/SP) design study generally includes intensive work. Hundreds formulations have to be tested to screen phase behavior and typically a dozen of corefloods are performed to select the best formulation and further optimize the injection strategy/slugs design to match economic criteria.
 
To be extrapolated to the field, it is critical to perform these tests in conditions as close as possible to real reservoir conditions: reservoir temperature, injection brine, reservoir pressure and reservoir oil. Specifically, dissolved gas and high-pressure tend to significantly impact crude oil properties, and subsequently formulation behavior and performance, even when limited amount of gas is present. Ideally, this parameter should be considered from the beginning of the formulation design. However, considering the high number of tests to perform, as well as the relatively high cost and technical challenges associated with live oil experiments, it is unrealistic to routinely perform all the required experiments in high-pressure environment.
 
We will present here the methodology developed to design surfactant based process by mimicking the impact of reservoir gas and pressure on the reservoir stock-tank oil.
 
First a thermodynamic model based on an equation of state is fitted to reservoir PVT data (Gas/Oil Ratio or GOR, stock-tank oil and associated gas composition analysis, bubble pressure and volumetric factor Bo) to predict consistent thermodynamic behavior and properties of the live oil. This step allows us to validate the reservoir conditions. A recombination of stock-tank oil with gas should be then performed to obtain the fluid in the reservoir conditions. Then we will illustrate through illustrative case studies how to combine a high-throughput robotic platform and a high-pressure/high-temperature cell to determine a representative crude oil matching live oil main properties, namely viscosity and Equivalent Alkane Carbon Number (EACN). This representative crude oil is obtained from the reservoir stock-tank oil which has been adjusted, using solvents or alkanes, to present the same characteristics as the reservoir live oil. This oil will therefore be used for an exhaustive formulation design and process optimization. Finally, we will compare oil recovery performances with the representative crude oil and with the reservoir live oil.
 
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Abstract

Miscibility with oil lies among the main advantages of dense CO2 injection for pore scale oil displacement during tertiary recovery. At reservoir scale, injecting dense CO2 in the form of foam can also improve its sweep efficiency. However, although the use of such miscible dense CO2 foams has been considered in over twenty pilots since the 1980’s, only few lab studies have considered foams formed with CO2 in this particular thermodynamical state. Indeed, dense CO2 has solvation properties and a viscosity higher than that of a gas. Although the generic term of foam is used, dense CO2 actually has liquid-like properties, and dense CO2 foams should be coined emulsions. This impacts several attributes of these dispersions in porous media, such as Mobility Reduction Factors (MRF) and behavior in presence of oil.
 
We present new results demonstrating that classical foamers are not effective in improving mobility control of dense CO2 in porous media. However, relatively high MRF can be achieved using carefully formulated surfactants. Based on these findings, we study the impact of foam on miscible flooding efficiency in coreflood experiments. Reversely, we also evaluate how miscibility of CO2 with oil impacts foam MRF. Our approach is based on multiple corefloods experiments, with different formulations, at various oil saturations. Additionally, physical-chemistry measurements such as interfacial tension estimations and foam stability monitoring are performed in reservoir conditions (pressure and temperature). This set of experiments shows that besides ability to reduce dense CO2 mobility in porous media, a balance must be found between maximizing MRF and minimizing the risk of emulsion formation in porous media.
 
This paper brings new insights on the interpretation of CO2 foams coreflood results, based on the thermodynamical properties (solvation power, density, viscosity) of the CO2 phase. In particular, it provides the reader with a clearer view of gas properties that must be considered when analyzing results of dense CO2 foams corefloods. This can help reconcile seemingly contradictory results appearing in the literature, particularly regarding the values of MRF obtained with CO2 foams as a function of pressure and in the presence of oil.
 
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Abstract

As a result of the recent increases in crude oil prices, a number of chemically-based enhanced recovery methods are being reconsidered by companies around the globe. But one important aspect that is generally neglected in chemically-based enhanced recovery technology concerns the impact of the EOR chemicals on the produced water cycle.
 
This includes the compatibility of EOR chemicals with the additives used to pre-treat the injected and to process the produced oil/water mixture after EOR chemical breakthrough. Some chemicals themselves, like surfactants and mechanically degraded polymers, may as well produce stable W/O or O/W emulsions and induce strong impact of produced water treatments, that ask for specific additives and equipment in order to keep the topside processing efficient. All these problems may seriously impact the forecast economical performance of EOR projects.
 
In this paper we will describe in more detail some specific constraints in terms of water management linked to chemical EOR and what are the challenges associated with backproduced chemicals (polymers & surfactants) on topside surface processes. Results will be described using a specific laboratory methodology designed to study the impact of ASP-type chemicals on water treatment efficiency, mimicing actual surface processes, that includes bottle test, centrifugation, gas flotation using an induced gas flotation lab column and membrane filtration. Influence of back produced polymer and surfactants is evaluated by monitoring the turbidity of the water and concentration of oil in water as a function of time.
 
As the present trend is to increase the use of enhanced recovery methods, among them the chemically-based ones, the industry urges for viable solutions to implement those methods while accomplishing the strict process and environmental constraints that nowadays exist. Water management is an important challenge for chemical EOR that needs an integrated approach and should be studied upfront.
 

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