Application of Partitioning Tracers for Remaining Oil Saturation Estimation: An Experimental and Numerical Study

2000 ◽  
Author(s):  
C. Chatzichristos ◽  
Ø. Dugstad ◽  
A. Haugan ◽  
J. Sagen ◽  
J. Muller
Keyword(s):  
Numerical Study ◽  
Oil Saturation ◽  
Remaining Oil ◽  
Partitioning Tracers

Laboratory Evaluation of Inter-Well Partitioning Tracers for the Determination of Remaining Oil Saturation after ASP Flooding

2015 ◽  
Author(s):  
J. Austine ◽  
D. W. van Batenburg ◽  
J. G. Southwick ◽  
M. A. Zarubinska ◽  
S. Paramanathan ◽  
...  
Keyword(s):  
Laboratory Evaluation ◽  
Oil Saturation ◽  
Asp Flooding ◽  
Remaining Oil ◽  
Partitioning Tracers

Oil Saturation Log Prediction Using Neural Network in New Steamflood Area

2020 ◽  
Author(s):  
A. Syahputra
Keyword(s):  
Neural Network ◽  
Water Saturation ◽  
Prediction Method ◽  
Neural Model ◽  
Training Model ◽  
Acquisition Time ◽  
Oil Saturation ◽  
Full Field ◽  
Remaining Oil ◽  
Observation Wells

Surveillance is very important in managing a steamflood project. On the current surveillance plan, Temperature and steam ID logs are acquired on observation wells at least every year while CO log (oil saturation log or SO log) every 3 years. Based on those surveillance logs, a dynamic full field reservoir model is updated quarterly. Typically, a high depletion rate happens in a new steamflood area as a function of drainage activities and steamflood injection. Due to different acquisition time, there is a possibility of misalignment or information gaps between remaining oil maps (ie: net pay, average oil saturation or hydrocarbon pore thickness map) with steam chest map, for example a case of high remaining oil on high steam saturation interval. The methodology that is used to predict oil saturation log is neural network. In this neural network method, open hole observation wells logs (static reservoir log) such as vshale, porosity, water saturation effective, and pay non pay interval), dynamic reservoir logs as temperature, steam saturation, oil saturation, and acquisition time are used as input. A study case of a new steamflood area with 16 patterns of single reservoir target used 6 active observation wells and 15 complete logs sets (temperature, steam ID, and CO log), 19 incomplete logs sets (only temperature and steam ID) since 2014 to 2019. Those data were divided as follows ~80% of completed log set data for neural network training model and ~20% of completed log set data for testing the model. As the result of neural model testing, R2 is score 0.86 with RMS 5% oil saturation. In this testing step, oil saturation log prediction is compared to actual data. Only minor data that shows different oil saturation value and overall shape of oil saturation logs are match. This neural network model is then used for oil saturation log prediction in 19 incomplete log set. The oil saturation log prediction method can fill the gap of data to better describe the depletion process in a new steamflood area. This method also helps to align steam map and remaining oil to support reservoir management in a steamflood project.

Toward Quantitative Remaining Oil Saturation (ROS): Determination Challenges and Techniques

2011 ◽  
Author(s):  
Ahmed A. Al-harbi ◽  
Denis Philippe Schmitt ◽  
Shouxiang Mark Ma
Keyword(s):  
Oil Saturation ◽  
Remaining Oil

Potential Benefits of Fluid Optimization for Combined Smart-Water and Polymer Flooding: Impact on Remaining Oil Saturation

2019 ◽  
Author(s):  
Muhammad Tahir ◽  
Rafael E. Hincapie ◽  
Hendrik Foedisch ◽  
Gion-Joèl Strobel ◽  
Leonhard Ganzer
Keyword(s):  
Polymer Flooding ◽  
Oil Saturation ◽  
Smart Water ◽  
Remaining Oil ◽  
Potential Benefits ◽  
Fluid Optimization

scholarly journals Impact of Brine Composition and Concentration on Capillary Pressure and Residual Oil Saturation in Limestone Core Samples

2019 ◽  
Vol 89 ◽  
pp. 02006
Author(s):  
F. Feldmann ◽  
A. M. AlSumaiti ◽  
S. K. Masalmeh ◽  
W. S. AlAmeri ◽  
S. Oedai
Keyword(s):  
Oil Recovery ◽  
Sea Water ◽  
Spontaneous Imbibition ◽  
Oil Saturation ◽  
Salinity Effect ◽  
Connate Water ◽  
Low Salinity ◽  
Remaining Oil ◽  
The Impact ◽  
Secondary Mode

Low salinity water flooding (LSF) is a relatively simple and cheap EOR technique in which the salinit y of the injected water is optimized (by desalination and/or modification) to improve oil recovery over conventional waterflooding. Extensive laboratory experiments investigating the effect of LSF are available in the literature. Sulfate-rich as well as diluted brines have shown promising potential to increase oil production in limestone core samples. To quantify the low salinity effect, spontaneous imbibition and/or tertiary waterflooding experiments have been reported. For the first time in literature, this paper presents a comprehensive study of the centrifuge technique to investigate low salinity effect in carbonate samples. The study is divided into three parts. At first, a comprehensive screening was performed on the impact of different connate water and imbibition brine compositions/combinations on the spontaneous imbibition behavior. Second, the subsequent forced imbibition of the samples using the centrifuge method to investigate the impact of brine compositions on residual saturations and capillary pressure. Finally, three unsteady-state (USS) core floodings were conducted in order to examine the potential of the different brines to increase oil recovery in secondary mode (brine injection at connate water saturation) and tertiary mode (exchange of injection brine at mature recovery stage). The experiments were performed using Indiana limestone outcrops. The main conclusions of the study are spontaneous imbibition experiments only showed oil recovery in case the salinity of the imbibing water (IW) is lower than the salinity of the connate water (CW). No oil production was observed when the imbibing water had a higher salinity than the connate water or the salinity of the connate water and imbibing brine were identical. Moreover, the spontaneous imbibition experiments indicated that diluting the salinity of the imbibing water has a larger potential to spontaneously recover oil than the introduction of sulfate-rich sea water. The centrifuge experiments confirmed a connection between the overall salinity and oil recovery. As the salinity of the imbibing brines decreases, the capillary imbibition pressure curves showed an increasing water-wetting tendency and simultaneous reduction of the remaining oil saturation. The lowest remaining oil saturation was obtained for diluted sea water as CW and IW. The core flooding experiments reflected the results of the spontaneous imbibition and centrifuge experiments. Injecting brine at a rate of 0.05 cc/min, sea water and especially diluted sea water resulted in a significant higher oil recovery compared to formation brine. Moreover, when comparing secondary mode experiments, the remaining oil saturation after flooding by diluted sea water, sea water and formation water was 30.6 %, 35.5 % and 37.4 %, respectively. In tertiary injection mode, sea water did not lead to extra oil recovery while diluted sea water led to an additional oil recovery of 5.6 % in one out of two tertiary injection applications.

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