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Summary Methods that can monitor fluid changes in a carbonate reservoir with time have the potential to help improve oil recovery from Middle East producing fields. Results from an onshore 4D seismic pilot study have successfully demonstrated that if performed properly, fluid changes in a reservoir can produce detectable differences in seismic data collected before and after the fluid change. The 4D seismic results, which show where a fluid change has occurred in the reservoir are produced by subtracting the two seismic images collected at different times. The 4D seismic method is found to be a good match with current production challenges that impact oil recovery, which include water flood override and inverse cone development. The 4D results are providing the reservoir engineer with flood-front information away from well control that can be used to quantify flood front efficiency and locate by-passed reserves. The results from this 4D pilot successfully demonstrated that 4D responses can be observed in carbonate reservoirs where sufficient saturation changes have occurred. The 4D results showed that 3D seismic surveys can be repeated onshore with acceptable levels of background noise, if done in the correct manner. Model predictions from feasibility studies were found to be in agreement with the 4D results. 4D responses were found in the main reservoir layer in agreement with calibration wells. Detailed 4D validation showed the 4D results to be in agreement with available production logging tool (PLT) measurements. The 4D results also suggest that pressure changes may be contributing to some of the 4D responses. Based on the results of this pilot, it has been shown that 4D can monitor saturation changes in a carbonate reservoir. The 4D results are helping evaluate sweep efficiency and identify potential bypassed oil reserves. Introduction In order to evaluate the potential of the 4D seismic technology in carbonate reservoirs a pilot was performed on a giant Middle East oil field. Giant Middle East fields have considerable remaining oil potential, even after many years of production, which could amount to significant additional oil with only incremental increases in recovery. A technology such as 4D seismic that can help identify zones with higher remaining oil potential would be of great value in monitoring recovery. The field used in this pilot is located onshore Abu Dhabi and covers an area that is approximately 12 by 30 kilometers with 180 meters of relief. The approximate depth of the reservoirs is 2500 meters. These Upper Cretaceous carbonate reservoirs were formed in a carbonate ramp depositional environment and are highly layered. The production is from three main reservoir zones with zonal connections from fault juxtaposition. The middle zone is the main reservoir and is the focus of this 4D study. The main reservoir is divided into two parts that will be referred to as the upper and lower reservoir layers. The main reservoir, ranges in thickness from 48–58 meters. The porosity of both the upper and lower layers of the main reservoir ranges from 20 percent in the water leg on the flanks to as high as 35 percent in the oil-bearing crest of the field. The upper layer is composed of grainstone-supported limestone and the lower layer is matrix-supported limestone. Thin dense low porosity sub-layers are also present within the main reservoir zone. Figure 1 illustrates how the 4D seismic method was found to be a good match with current production challenges in the field. Due to differences in rock type and diagenesis, large permeability contrasts exist in the main reservoir zone and create many complex production challenges. The upper reservoir layer has better permeability in the Darcy range and the lower reservoir layer has permeability's in the tens of milliDarcy range. The pore pressure in the main reservoir is maintained by peripheral water injection. Due to the permeability differences, water injected in the lower reservoir layer has a tendency to rise quickly to the upper layer where it overrides the oil in the lower layer. When the water overrides the lower layer it does not sweep the lower layer oil to the production wells. The oil in the lower layer is effectively bypassed, sweeping of oil up-dip to producing wells near the crest of the field occurs only in the upper layer. Vertical wells when used to produce from the lower layer, with time, draw down an inverse water cone around the wellbore and the well eventually ceases to flow oil. In order to access lower layer reserves a program of horizontal infill producers was started. The horizontal wells take a longer time to develop water cones and drain oil from larger areas.
This paper presents a methodology and results of the integration of 3D seismic data with well log data and simulation model of a giant carbonate reservoir. The work highlights the vertical scale differences between seismic and reservoir models and brings forward a method to match the scale and resolution. Seismic reservoir characterisation of a field with a large number of wells with different vintage and quality data requires statistical methods to discriminate valid data to build AI-Porosity transforms. The method adopted for integration has allowed a better understanding of the complex wrench faulting, and improved the porosity description of the reservoir. 4D fluid effects have also been observed as a result of combining well and seismic with simulation data. Introduction The giant field discussed here is located in the onshore area of Abu Dhabi, United Arab Emirates. The Lower Cretaceous reservoir was discovered in 1960s, came on stream in 1970s and is currently producing on plateau from over 300 wells. The authors are part of an integrated asset team who are involved with continuation of development drilling and updating the reservoir model. A 3D seismic dataset was acquired from 1997–1999 over this field, some 25 years after first oil production, in order to improve its structural and reservoir definition. The seismic results are compared with a history matched reservoir model based on 240 wells. Conventional and attribute mapping from the seismic has revealed the structural detail of a complex wrench fault system, which improved reservoir simulation. Reservoir rock properties are predicted using seismic attributes. Amplitude and acoustic impedance (AI) show relationships at the gross reservoir scale with porosity and with fluid saturation. A shared earth model using the structural framework defined by the reservoir stratigraphy and seismic structure is built for integrating the seismic attibutes, property models and dynamic simulation results. Attempts to effectively use seismic data for reservoir characterization are carried out. A key factor in using seismic for reservoir characterisation modelling is the ability to keep the fine vertical layering detail from the wells, while using the coarser but better spatially sampled data from the seismic. This requires matching the different sampling characteristics and resolution of seismic with well data. A statistical methodology for scale matching, calibration and spatial modelling of the porosity from the seismic AI is developed. The fine division of AI, into layers correlated to reservoir subzonation, permits use of different AI to porosity transforms having more significant fit. The final reservoir porosity model uses the seismic porosity as a trend parameter for spatial estimation of well data. Comparison of the different porosity models against new well data provided insight into the statistical nature of the deviations. Using the good relationship of seismic porosity to wells, the secondary influence of the fluid change on the seismic has been observed in the data. Differences between the seismic and well based models are shown to be partly due to changes in reservoir fluids (4D), demonstrating that the seismic can be used for both rock and fluid property characterisation. Objectives and Scope of the work This work is driven by the need to integrate available seismic data in reservoir characterization. An understanding of the impact of faulting on the reservoir is required. A prime objective is to use seismic in porosity modeling at an appropriate reservoir scale. Recognition of the uncertainties and differences between geological and geophysical results by statistical methods is a goal. The ability to monitor fluid changes from seismic for 4D is also of interest. Objectives and Scope of the work This work is driven by the need to integrate available seismic data in reservoir characterization. An understanding of the impact of faulting on the reservoir is required. A prime objective is to use seismic in porosity modeling at an appropriate reservoir scale. Recognition of the uncertainties and differences between geological and geophysical results by statistical methods is a goal. The ability to monitor fluid changes from seismic for 4D is also of interest.
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