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Polymers exhibit non-Newtonian rheological behavior, such as in-situ shear-thinning and shear-thickening effects. This has a significant impact on pressure decline signature as exhibited during Pressure Fall-Off (PFO) tests. Therefore, applying a different PFO interpretation method, compared to conventional approaches for Newtonian fluids is required.This paper presents a simple and practical methodology to infer the in-situ polymer rheology from PFO tests performed during polymer injection. This is based on a combination of numerical flow simulations and analytical pressure transient calculations, resulting in generic type curves that are used to compute consistency index and flow behavior index, in addition to the usual reservoir parameters (kh, faulting, etc.) and parameters relating to (possible) induced fracturing during injection (fracture length and height). The tools and workflows are illustrated by a number of field examples of polymer PFO, which will also demonstrate how the polymer bank can be located from the data.

The objective of injecting polymer in brown fields is to increase recovery beyond primary and secondary recovery mechanisms. However, generally it is difficult to achieve adequate (viscous) polymer injectivity in depleted sandstone reservoirs without fracturing. Therefore, monitoring fracture propagation is required in order to control vertical conformance and areal sweep and avoid early polymer breakthrough. Different surveillance methods are used to identify the existence and properties of fractures in polymer injectors. Pressure Fall off (PFO) survey data in conjunction with time-lapse temperature surveys are extensively used to determine the fracture dimensions. PFO tests in Polymer injectors have particular characteristics since they are influenced by shear-dependent viscosity seen in non-Newtonian fluids. A specially developed Injection Fall-off (IFO) model was used to determine fracture dimensions which is based on exact semi-analytical solution to the fully transient elliptical fluid flow equation around a closing dynamic fracture developed by Shell, (Van den Hoek 2005), as static fracture models are inadequate. This paper presents different phenomena in polymer injection seen in PFO tests such as fracture closure, the effect in-situ polymer rheology and the detection of the polymer front. The paper demonstrates the effect of liquid-level drop observed in PFO survey in under-pressured reservoirs and its impact on determining fracture and some other reservoir properties. It also shows how plot-overlays of time lapse PFO's for a particular well can be used to track changes in fracture dimensions. All of these are illustrated by a number of field examples of polymer PFO which also demonstrate the calculated fracture dimensions from the data. Finally, some recommended best practices are suggested for fracture monitoring. IntroductionThe large sandstone brown field that the polymer injection is taking place in is located in the eastern side of the South Oman basin. The oil is heavy, 22 API and viscous, 90 cP. The field is highly heterogeneous with sand, diamictite and shale bodies. Nonetheless in the main reservoir units the Net Sand to Gross reservoir ratio approaches one and the permeability can range up many Darcies. The main objective of injecting polymer is to increase the recovery beyond the primary and secondary recovery mechanisms by improving the sweep efficiency (figure1). In such heterogeneous reservoir, it is difficult to achieve an adequate viscous fluid injection under matrix condition in depleted sandstone reservoir. Therefore, Polymer injection was designed to be injected under controlled fracture conditions where the fracture length should not exceed 1/3 of the distance between injector and producers over the life of the project. This requires intensive qualitative and quantitative monitoring of the fracture dimensions through different surveillance techniques to control the vertical conformance and avoid early breakthrough of the polymer.

In chemical Enhanced Oil Recovery surfactants, solvents or other water based additives are used to mobilize micro bubble size trapped oil. Under favorable physical, chemical and spatial conditions the mobilized oil collects in an oil bank that will be displaced to the producer. Our understanding of when, and under which conditions an oil bank is formed, is very limited. This is relevant when core flow experiments are interpreted and upscaled from centimeter scale to field scale in various steps. We built two experimental high precision setups for different volume scales to obtain reliable and accurate results. The first one is a Microfluidic setup, which visualizes and characterizes the dynamic of fluid flow at micrometer/pore scale. The second one is a high-end core flow setup which is used to study the dynamics of a mobilization process at meter/Darcy scale. These high-end development set-ups provide us with robust, accurate and repeatable experimental data for oil mobilization from micrometer/pore scale to one meter scale samples. We experimentally demonstrated the process of oil bank build up at two different pore framework scales. These experimental results provided a high degree of data integrity. In addition, results give direct evidence for the mechanism of oil bank build up and upscaling procedure. We ensured the repeatability, reproducibility and integrity of the experimental data. We visualized and explored semi-quantitatively the entire process from mobilizing residual oil to dispersed flow to oil bank formation using a micro-fluidic device and core flow tests using cores of different lengths (7 – 100 cm)