The availability of ~ 7 years of actual performance data for the ongoing field-scale polymer flood in South of the Sultanate of Oman provides ample opportunities to reveal the reservoir dynamics and its interplay with induced EOR mechanism. The paper focusses on analysis of the polymer pattern behaviour, underlying reasons for such response and key indicators to characterize pattern performance. Upsets in surface polymer injection facility leading to the phenomenon of WAP (Water-Alternating-Polymer) and it's impact on recovery is also assessed in context of actual field examples. The paper then illustrates how this information could be exploited to counter challenges faced in the field, enhance polymer pattern performance, optimize it's further expansion and de-risk any other future EOR development. A nested modelling approach has been employed, wherein models at different scales are generated, tailored to meet the objectives. High resolution 3D conceptual models are built in Shell proprietary tool PolyMoReS to calibrate the model response against the actual polymer pattern behaviour in the field, study the impact of mixing between polymer and water slugs in WAP type of recovery, and affirm the correct polymer rheology. Three segment models covering the field are created and history matched with the use of Stochastic Uncertainty Management. Attempts have been made to obtain history match (HM) on segment, pattern and well levels, with greater emphasis on polymer patterns capturing polymer oil response, water-cut reversals and polymer breakthroughs. Models are then complemented by Pressure Fall-Offs, tracer tests and PLTs to capture uncertainties in fracture growth and areal and vertical conformance. The HM model is then used to predict polymer performance. Significant insights into waterflood and polymer flood performance are gained, which help improve the pattern performances. Assessment of WAP with both conceptual Physics and field segment models demonstrate considerable deferment of oil. Capturing injector – producer connectivity has proven the most pivotal element in explaining polymer oil response and breakthrough. Models indicate that lower than expected incremental recovery and sharper decline of oil response in some patterns are related to the lower polymer mass injected, which in-turn could be attributed to many operational factors (e.g., polymer injection uptime, injection rate, low injection viscosity, WAP), and the presence of natural fractures or uncontrolled growth of induced fractures. The study also reveals optimization opportunity to reduce the volumes of back produced water. The paper presents a comprehensive multi-scale reservoir modelling study for a field with significant historical data of large scale polymer flood. Impact of WAP injection, reflecting the reality of interruptions in polymer flood due to operational upsets, on medium to long term polymer flood value is presented. Analysis of polymer patterns in the field demonstrates how different key indicators e.g., PUF (Polymer Utilization Factor) can characterize pattern performance throughout its life-cycle and answers questions, e.g., why some patterns behaved well, while others not.

Numerous studies have been done on the design and analysis of hydraulic fractures. However, the study of induced fractures is still a maturing subject especially, with regards to the predictive capabilities of the fracture simulators and, it soon becomes a challenge when it comes to the acquisition of meaningful field data and their interpretations to validate the forward modelling results of the fracture simulators. The paper is a step forward to fill the gap between the model predictions and the field observations for water injectors in the context of induced fracture propagation. The study was done for a field, located offshore South-East Asia. The content of this study will be presented in two papers based on the key domains stated above – "field observations" and "model predictions". The current paper (Part 1) addresses the first subject where field data have been analyzed to get an understanding of the induced fracture growth in the water injectors. This comprises of "Pressure Transient Analysis (PTA)" of "Pressure Fall-Off (PFO)" tests done on the water injectors. The paper will present a workflow to interpret a PFO for fracture analysis using two approaches. The first approach is based on the standard PTA models where no explicit fracture mechanism has been invoked. We will introduce an analytical technique which uses the compliance value obtained from the standard model analysis to determine the fracture size. The second approach is based on the "Injection Fall-Off (IFO)" model, a dedicated Shell plug-in to Ecrin, used for fracture characterization. The workflow will be first illustrated elaborately through a stepwise interpretation of an example PFO test. We will demonstrate, afterwards, the application of the above methodology for analysis of a number of field tests using both approaches. The paper will conclude with a consistent picture of fracture growth interpreted from both techniques. Significance of geological set-up wrt the fracture growth will also be highlighted. We will also highlight some limitations with the modelling and ways around it.

Efficient production of heavy oil from the reservoirs with strong bottom aquifer has proven to be a challenge. While providing enough energy to produce the field under the primary depletion, the strong bottom aquifer in combination with unfavorable oil/water mobility contrast leads to rapid development of water coning thereby limiting oil recovery. Drilling of long horizontal producing wells in the upper part of the oil column maximizes the distance from the aquifer and allows relatively high production rates. This slows down the water cone development and increases primary recovery. Even with further optimization of the primary production, the recovery factor remains relatively low and consequently application of Enhanced Oil Recovery (EOR) techniques is required to increase the recovery. Сrude oil from Nimr-E field is medium-heavy with the viscosity of 250-700cP under reservoir conditions. The field has been developed with mostly horizontal producing wells with relatively short inter-well distance. Due to strong bottom aquifer the reservoir pressure is maintained at the initial level despite the production under primary depletion. To increase the recovery factor polymer flooding was selected with expectation to increase the recovery by 5-10%. A field trial was conducted to understand the influence of polymer injection on oil recovery and address major uncertainties identified as key enablers for the full-field project. The pilot surveillance program, the surface facilities and the subsurface configurations were specifically designed to meet these objectives. The paper presents field data of polymer injection trial in Nimr field and focuses on the performance results and principal operational challenges. The injection of polymer resulted in the incremental oil production that was assessed using field data and simulations. A significant increase of initial oil production and clear watercut reversal due to polymer injection was observed and incremental recovery reached approximately 7% of the initial oil in place. Injectivity issues encountered in the pilot wells were mitigated by the techniques and chemicals developed to solve the issues. The results prove the subsurface and operational success of polymer field trial that leads the way to a commercial development.

This paper is a continuation of the paper 1 (SPE-171882-MS, ADIPEC 2014) and addresses the second aspect of the study: "forward fracture modelling". The paper demonstrates the integration between the Pressure Transient Analysis (PTA) of the field data discussed in paper 1 and the fracture simulation to validate the forward fracture modelling results.Fracture modelling work performed pre-dominantly in two Shell in-house fracture simulatorsstandalone pseudo-three-dimensional fracture simulator and coupled reservoir-fracture simulator (also referred as dynamic fracture simulator in this paper), for a horizontal water injector in an offshore field in South-East Asia will be presented. A methodology will be discussed for setting-up a relatively simple fracture model in the standalone simulator as well as a sophisticated 3D model in the dynamic fracture simulator. Fracture prediction runs from the two simulators will be discussed with an emphasis on the consistency of results between them. Further, uncertainties in fracture growth have been characterized in this study with an extensive list of parameters pertaining to three major domains -reservoir properties, geomechanical properties and operating conditions. We will discuss these uncertainty/design parameters and their impact on the fracture growth using the two simulators. We will also illustrate the approach of "Design of Experiments" for fracture growth sensitivity analysis with the help of the dynamic fracture simulator coupled with an in-house stochastic uncertainty management tool. Finally, probability distribution function for the fracture dimensions will be shown as an outcome of the sensitivity analysis.The paper will conclude with the significance of forward fracture modelling, its validation with the PTA, and the contributions it can make in understanding the waterflood performance in the field. The paper will demonstrate how the study can benefit an asset team in identifying the reasons behind pre-matured water breakthrough in producers, understanding the impact of operating variables on fracture growth and hence, sweep, redesigning water injection operating envelopes, and addressing the field issues which altogether lead to the top quartile performance of the waterflood in the field.

A long term polymer injectivity trial has been conducted in a medium-high oil viscosity field in Oman, with a suite of objectives to assess the feasibility of the high viscosity polymer concept, evaluate alternative polymers and de-risk the low-salinity polymer hybrid for field implementation. An integrated analysis of this injectivity trial is presented. Performance in the field during injection of low and high molecular weight (MW) polymer in hybrid with low salinity water is analysed along with interpretations of the intermediate water injection, shut-ins, pressure fall-off and step rate test at the end. The analysis is based on simulation models to history match the pressure response in the injector during the polymer trial. Key realizations focusing on two aspects – polymer rheology and wellbore/reservoir fluid propagation mechanism – are presented that were used to history match baseline water injection, low and high MW polymer injection, low salinity water injection and polymer low salinity water hybrid. Other sources of information – step rate test and pressure fall-off tests conducted during the trial – were interpreted to validate the conclusions from the HM model. The study highlighted the risks of either inducing fractures or reactivating an existing fracture network in the reservoir during the polymer injection. Different sources of data indicated fracture pressure lower than anticipated. The dynamic characterization of the fractures – propagation and shrinkage – depending on the injection rate, injection fluid type and viscosity are found critical to explain the entire polymer trial response. The study also highlighted that capturing the polymer rheology adequately in the model, based on laboratory data, helps to explain the trial response. Changing well conformance has been found another important parameter in explaining the trial response. Finally, using the baseline water injection to ensure the permeability field is adequately modelled constitutes another step in understanding the polymer trial.