In viscous oil reservoirs, Polymer flooding is often used to improve oil recovery either after a short period of waterflooding or as a tertiary recovery process following extensive period of waterflood. After six years of water flooding in a major reservoir in Sultanate of Oman having viscous oil (90cp), a field development plan was developed to implement polymer flooding in this reservoir with anticipated incremental oil recovery of around 10% over and above that of waterflood. Necessary facilities were constructed, injection and production wells were drilled, completed, converted and the polymer flood project was initiated and ongoing since the last three years through 27 polymer injectors. By implementing proactive Well and Reservoir Management (WRM) strategies, the actual oil recoveries have been better than predicted levels so far. It is demonstrated here that proactive well and reservoir management through proper well and reservoir surveillance and dynamic adjustment of injection and production rates play a very important role in improving the performance of polymer floods as in waterfloods. Well and Reservoir Management (WRM) principles in case of a polymer flood are similar to that of high mobility ratio waterfloods with some additional aspects that are specific to a polymer flood scenario. Polymer chemical costs, its higher viscosity and non Newtonian fluid flow behavior all create unique conditions that are nonexistent in normal waterfloods. This, in turn, dictates the strategies and methods employed to optimize polymer flood performance. This paper details successful implementation of proactive WRM strategy that has played a key role in sustaining production from this polymer flood field to date. It describes the pattern management processes to optimize pattern wise polymer injection and oil recoveries, conformance control measures implemented to increase sweep and oil recovery, innovative surveillance techniques to monitor fracture growth in polymer injection wells and for evaluation and optimization of production/injection profiles. Production wells and facilities issues arising from polymer breakthrough are being addressed to mitigate any adverse effects.

In heavy oil reservoirs, water flooding leaves behind unswept hydrocarbon volumes due to unfavourable mobility ratios resulting in low ultimate recoveries. Increasing the viscosity of the injected water using polymer improves the water-oil mobility ratio resulting in improved recovery factors. This paper discusses for a large field in South Oman the successful implementation of a polymer flood project, the early results of Phase I and the planned expansions to Phase II and Phase III. Following a number of field trials and a series of laboratory studies, a full-field polymer project was implemented in the field in 2010. One of the key risks identified prior to starting the project was poor polymer injectivity. However, initial field results showed better injectivity than expected. Surveillance efforts are in progress to understand the better injectivity. The data analysis so far indicate that wellbore clean up due to polymer injection, improved as a result of improved mobility ratio and small scale induced fractures in some injectors are contributing to the improved injectivity. These factors enabled injection of more volumes of polymer than planned resulting in improved volumetric sweep efficiency and producer response. Results to date are encouraging, as after over a year of polymer injection, the oil gain due to the polymer flood is higher than expectation. Based on the initial results of Phase I, expansion phases II and III are being planned. Phase II is based on utilizing the available ullage in the system to accelerate the oil gain from polymer; it requires a relatively small upgrade of the existing infrastructure and surface facilities. Phase III is a full-field polymer flooding expansion combined with an intense infill drilling. Currently, a study is in progress to optimize the development concept for the infill wells and polymer flooding of Phase III.

Many Enhanced Oil Recovery (EOR) applications involve injection of fluids into oil reservoirs to displace and recover as much of the remaining oil as possible. Typical maturation of (chemical) EOR involves phase and compatibility testing in the laboratory, displacement experiments in cores before single or multi-well pilot trials in the field, leading eventually to full field implementation. Recently, a new technique referred to as MicroPilot* has been introduced as an intermediate step to take laboratory results into the field, providing valuable data for pilot design and implementation.The MicroPilot* is a log-inject-log method executed under in-situ conditions downhole in a matter of hours. A suite of wireline openhole logs are utilized to determine the initial saturations. The test then continues with a formation tester string which can drill into open hole, cleanup and inject an EOR agent into the formation. Following injection, the suite of open hole logs are run again to evaluate the effectiveness of the flood by measuring the change in oil saturation and the dimensions of the flood.The world's first successful test has been run in a medium heavy-oil field in the Sultanate of Oman with Alkaline Surfactant Polymer (ASP) solution as the EOR agent. Post-injection formation image logs clearly show the swept zone and an oil bank.In this paper we take the analysis of the test a step further and present dynamic simulation modeling results using the acquired data as benchmark parameters for the history match. Grid verification using single-phase pressure transient analysis is discussed. Each phase of the test is modeled and history-matched to the acquired data. The electrical borehole image log response is matched together with the vertical saturation profile seen on the post injection NMR log. During the history match, formation parameters are fine tuned and some parameters describing the EOR displacement process in the simulator are studied in more detail. The history matching effort not only provided a consistency check for the field observed data but can also help determine a few key modeling parameters prior to possible field pilot planning.

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.

Laboratory and single well pilot nuclear magnetic resonance (NMR) logging results are obtained for an enhanced oil recovery (EOR) project using a common physics of measurement at both scales. Screening for chemical EOR efficacy usually begins in the laboratory before moving to single or multiple well field pilots. Laboratory experiments were conducted on a low-field bench-top NMR magnet with fluid injection protocols that matched the log-inject-log concept of the single-well in situ EOR evaluation (Arora et al. 2010). In situ measurements of the oil and brine saturations during the flood, by "diffusion-editing" protocols and by relaxation measurements alone, are shown to be in quantitative agreement with gravimetric assays of recovered oil. Spatially resolved T 2 analysis (the laboratory equivalent of a standard NMR well log) revealed non-uniform oil saturation during the EOR process in short core plugs. The final remaining oil distribution is confirmed by a reservoir simulation in a geometry identical to the NMR-compatible core holder. In a region of the core-plug not influenced by end effects, complete recovery of the oil was observed, consistent with the the single-well in situ EOR evaluation. The quantitative estimates of remaining oil, using a tool-equivalent NMR protocol, demonstrate the potential for NMR logging of remaining oil in monitoring wells completed with NMR-transparent casing.