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We present the results of a paleoseismic trench investigation of an 8-m scarp at the mouth of Marbang Korong Creek (27°58'26.0700" N 95°13'42.3000" E) within the meizoseismal area of the 1950 Assam earthquake along the northeast Himalayan Frontal Thrust (HFT) of India. Structural, stratigraphic, and growthstratigraphy relations observed in the trench are interpreted to indicate that expression of the scarp is due to uplift and folding of near surface sediments in response to HFT displacement that reaches near the surface yet below the 5-m depth of the trench exposure. The most recent contribution to scarp growth dates to fault displacement post 2009 cal yr B.P. It remains a matter of speculation whether or not the most recent event deformation is a result of the great 1950 Assam earthquake that is reported on the basis of intensity data.

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.

A field scale polymer flood has been in operation since early 2010 in a major oil field of the Sultanate of Oman. The project comprises 27 patterns where water flood was on-going prior to initiation of Polymer flood in 2010. A polymer flood project has high chemical operating expenditure (Opex). Thus, optimization of a polymer flood requires continuous tracking of mass of polymer injected per unit volume of incremental oil produced for individual polymer flood patterns and then polymer throughput in individual patterns needs to be dynamically altered. To meet this objective, a full-field streamline simulation model has been built, history matched and is being used for optimizing the polymer-flood. Full-field simulation allows the proper modeling of each pattern and their interactions with off-set patterns, and these simulations can be performed in a reasonable computation time because of the efficiency of streamline modeling. Computational efficiency of streamline simulation has facilitated use of the model for routine well and reservoir management decisions. This would not have been possible with a finite difference model because of excessive run time and inability to clearly establish injection-production relationship as in a streamline model. The model has facilitated optimization of polymer flood patterns, specifically when to stop polymer injection, slug size, and slug concentration. Individual pattern performance can be visualized effectively and their efficiency can be compared. The model is also being used for ranking the existing water-flood patterns for the next phase of polymer-flood implementation and carrying out short term production forecast.

A field-scale polymer flood has been in operation since early 2010 in a major oil field of the Sultanate of Oman. The project is composed of 27 mature waterflood patterns that were converted to polymer flood in 2010. Because a polymer-flood project has high chemical operating expenditure, optimization of a polymer flood requires continuous tracking of the mass of polymer injected per unit volume of incremental oil produced (relative to waterflood) for each polymer-flood pattern. To meet these objectives, a fullfield streamline simulation model was built, was history matched, and is being used for optimizing the polymer flood. Full-field simulation allows the proper modeling of each pattern and their interactions with offset patterns. However, full-field simulations can be expensive, so we use a streamline-based simulator to run forecast scenarios in a reasonable computation time on reasonable hardware. Streamlines have the added benefit of determining the time-varying well-rate allocation factors per pattern, meaning that pattern-level diagnostics are relatively easy to compute and are based on the dynamic flow characteristics of the model. Computational efficiency and quantification of patterns have facilitated use of the model for routine well and reservoir-management decisions. We show that one can determine the effectiveness of the polymer flood on a pattern-by-pattern basis over the historical polymer-injection period with a standard oil-produced vs. polymer-injected ranking. In forecasting, we show how to quantify the incremental recovery caused by polymer, above base waterflood, on a pattern-by-pattern basis to facilitate optimization of polymer-flood patterns and more specifically to determine when to stop polymer injection and which new patterns to move polymer injection to.

Summary This paper presents the success story of waterflooding in a geologically complex reservoir that contains high-viscosity (90 cp) oil. This reservoir is part of a large brownfield in south Oman and has been on production for more than 25 years. The reservoir comprises glacial sandstones of Palaeozoic age and is highly heterogeneous, with wide variation in reservoir characteristics at scales smaller than well spacing. The reservoir geology is complicated because of the presence of faults and fractures. The reservoir has been subdivided into different areas that we call "catchments," characterized by their geological setting and dynamic reservoir behavior. Full-field water injection was started in the field after approximately 18 years of primary depletion. Different water-injection philosophies for different areas of the field have been adopted with consideration to factors such as primary drive mechanism operative in the reservoir, presence or absence of vertical-flow barriers; pre-existing field-development pattern; and more importantly, future development beyond waterflood to maximize the value of the reservoir in its entire life cycle. The paper illustrates that the success of a waterflood in a complex reservoir relies on the implementation of a tailor-made development plan with flexibility to be changed on the basis of data from reservoir surveillance. The importance of well and reservoir management (WRM) to improve the value of waterflood is emphasized.

The first field scale Polymer flood project in the Middle East region is under operation in an oil field of The Sultanate of Oman since early 2010. The oil field discussed here contains viscous oil (90 cp) was discovered in 1956 and is located in eastern part of South Oman Salt basin. First commercial production started in 1980 from this field. The field has gone through different development phases in its 30 years of history prior starting tertiary recovery phase by polymer flooding. This Polymer flood project comprises of 27 patterns coversing about one third of the total field IOIP (initial oil in place). It is worth mentioning that whole field is under water flooding and water injection was going on prior to initiation of Polymer flood in 27 injectors. So far, this project has been running successfully with good performance contributing to significant oil gain. During this successful journey of about 4 years, the project has passed through many expected and unexpected challenges. The well and reservoir management team has been working actively in all those challenges with novel approaches to increase efficiency of this project. One of the key challenges encountered is reduction in productivity of producer wells in comparison to earlier water flood with same injection volume. In a few polymer wells production rates even dropped by more than 50%. The main challenges for these wells seeing higher drop in liquid rate is that there is no or minimal oil gain in-spite of reduction in water cut due to disproportionate decline in liquid rate. This reduction in production rate smay be attributed to decrease in producible fluid mobility, high fluid density with polymer slug and skin formation near wellbore. At the same pressure drawdown of the artificial lift pump withdraws less fluid due to increase in fluid density with polymer breakthrough. There are also possibilities of plugging as a result of moving solid fines from the more viscous fluids near the well bore. These caused more drawdown and less fluid produced and resulted in high gross reduction in some wells. In order to overcome these gross decline, chemical treatment using mutual solvent has been carried out in a few wells as trial and has given good result. A detailed analysis is going on to investigate possible causes and accordingly design suitable remedial actions. This paper describes briefly about the principles involved in this solvent stimulation jobs and results of field implementation with real field examples.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA major reservoir in a large brown field in South Oman has been on production for more than 25 years. The reservoir comprises glacial sandstones of Palaeozoic age and is highly heterogeneous with wide variation in reservoir characteristics at scales smaller than well spacing. These variations include impermeable diamictite and shale beds and multi-Darcy gravel or conglomerate beds. The reservoir geology is further complicated due to the presence of faults and fractures that often provide highly conductive vertical pathways to the aquifer. The reservoir crude has high viscosity (90 cp) and moderate to low API gravity (22 deg API oil). The field has been developed using vertical and horizontal wells in different phases of development. Water-flooding is in operation in the reservoir for more than 6 years. Injectors comprise vertical injectors in five spot pattern, horizontal injectors and inclined aquifer injectors in the flanks. Different water injection philosophy for different areas of the field has been adopted considering factors like primary drive mechanism operative in the reservoir, presence or absence of vertical barriers to flow, pre-existing field development pattern and more importantly future development for maximizing recovery from the reservoir over the entire life cycle. Despite the geological complexity of the field and adverse mobility ratio conditions under which water-flooding is being carried out, the reservoir has responded very favourably to water flooding. The production decline trend from the reservoir has been arrested and reservoir pressure has increased in most areas of the field after initiation of water injection. The paper presents the success story of water-flooding in a geologically complex reservoir containing high viscosity oil. The paper clearly illustrates that the success of a water-flood in a complex reservoir rests on implementation of a tailormade development plan with flexibility to make changes to the same based on data from reservoir surveillance. The importance of well and reservoir management to maximize the value of waterflood is clearly brought out.