| Popis: |
In this study, various upscaling techniques and their effects on Barik tight gas Formation simulation modelling results were investigated. The intent of this upscaling study is to recommend coarse models that provide approximately the same flow behavior or well performance as the fine grid model. The study will help to develop an awareness of the range of applicability for the upscaled coarse models. It will also allow coarse grid models to be used appropriately and with greater confidence in production optimization. These techniques comprised several alternative ways of grouping reservoir data, with respect to petrophysical rock types (herein referred to as RT). This scheme defines 5 individual rock types, with RTs 1 to 4 broadly defining pay and RT 5 defining non-pay. The layers in the simulation models are made up of single or multiple grouped RTs from the same zone. Keeping each layer in the model, ordered as it was in the well log, resulted in 85 simulation layers for the fine grid model. The upscaled or coarse models have 16 to 35 simulation layers, with the smallest being the model where RTs 1 to 4 are grouped together. Different RTs sorting were tested in each of the upscaled models. The results of this study suggest that re-ordering the log information so that all of the rock for each rock type was grouped together inside each stratigraphic unit appears to be an acceptable upscaling technique that gives reasonable efficiency and accuracy. This type of upscaling was required since the study showed that any upscaling method that averaged the properties of RT 1 with the properties of other rock types within the same simulation layer could result in optimistic EUR estimates of up to 30% relative absolute error when compared to a fine grid model. The choice of upscaling method is particularly significant in a low Kv/Kh ratio environment, but less so within environments with a high Kv/Kh ratio. The upscaling technique has only been tested for the Barik formation and should not be used elsewhere without proper testing. The upscaling technique works for the Barik formation because of several distinctive features of the reservoir and the wells. In applying this upscaling technique we assume that: The wells are all hydraulically fractured and thus the flow is generally horizontal into the fractures and from the fractures into the well.The fracture extends from the top to the bottom of each stratigraphic unit that the fracture encounters. If a fracture only partially penetrates a stratigraphic unit, this method may not work.The gas is relatively dry and thus the flow is less affected by gravity than for reservoirs containg flowing liquids.The reservoir is made up of rock with a wide range of permeability, but the flow is dominated by the well connected, higher permeability rocks (RT 1).The reservoir is very stratified, and the correlation length of the rock types has to be very much greater than the well spacing. Re-ordering of the RTs in a given upscaling method will result in acceptable accurate estimates of hydrocarbon recovery, compared to the fine grid model. It showed that the order of layering did not matter for the area studied, because a conductive fracture connects all the layers. This method probably really is only applicable for dry gas reservoirs (where gravity is not important) and in fractured wells (where horizontal flow into the fractures and into wells dominates). In oil reservoirs and rich condensate reservoirs where gravity is an important factor, the ordering of the rock types within the simulation layer may matter. It will also be shown that an approximately 90% reduction in the simulation modelling computing time could be achieved if the appropriate upscaling technique is used. To achieve this reduction in computing time, some compromises were made, including assuming RT 4 is non-pay in upscaled models where RTs 4 & 5 are grouped together in the same simulation layers, resulting in reduction of HCPV. It is important to mention that some RT 5 zones in the log have thin instances of other rock types, which are not accounted for in the upscaled models and could result in an error in average pore volume preservation. |
