Many laboratory coreflood studies have shown increased oil recovery is achieved by waterflooding using low salinity water, compared with injection of seawater or high salinity produced water. The reasons for this improved oil recovery are thought to be due to effective wettability changes and / or controlled removal of clay constituents. This paper describes a log-inject-log field test, designed to identify whether this phenomenon could be observed within the near well region of a reservoir. The log-inject-log test was meticulously designed and executed, to ensure that flow rates were maintained at low rates, and that cross flow was minimised, to ensure that the results were representative of bulk reservoir waterflood displacement. A producing well was selected for the test to ensure that all saturation changes occurred under stringently controlled test conditions and that the results would not be affected by previous high rate water injection. 10 - 15 ‘pore volumes’ of high salinity brine, were injected into the ‘volume of interest’, to obtain a baseline residual oil saturation. This was followed by sequences of more dilute brine followed by high salinity brine for calibration purposes. Multiple log passes were conducted during injection of each brine. At least three further passes were run to ensure that a stable saturation value had been established after injection of each brine. Extensive water sampling was conducted to confirm brine salinities and increase confidence in the quantitative saturation results. The results were in line with previous laboratory tests from other fields, and showed 25 – 50% reduction in residual oil saturation when waterflooding with low salinity brine. Introduction There is increasing evidence from laboratory corefloods, supported by some field evidence, that waterflood performance is highly dependent on salinity of the injection water1,2,3. Laboratory corefloods suggest that as much as 50% additional oil could be produced if low salinity water (<4000 ppm) is injected into the reservoir, opposed to sea water or higher salinity production water. To ascertain whether these benefits seen in the laboratory are also observed in a reservoir environment, a modified log inject log test was performed to determine Sorw to both high and low salinity injection waters. This paper describes the design, execution, and analyses of this single well test. The Log Inject Log Test Techniques for determining Sorw by performing log inject log tests are well publicised in the literature. The technique is based on running multiple passes of pulsed neutron capture (PNC) logs after injection of two or more different brines, which have measurable differences in capture cross section. Assuming that formation porosity and the injectant brine cross section are known accurately, water saturation can be deduced from :Equation 1 Where:St1 is the PNC log response after injecting the first brineSt2 is the PNC log response after injecting the second brineSw1 is the capture cross section of the first brineSw2 is the capture cross section of the second brinef is the porosity of the formation. Therefore, by modifying this general approach, and injecting different brines of at least three different capture cross sections, it is possible to determine the Sorw after base saline injection and after injection of low salinity water.

No abstract

Many laboratory coreflood studies have shown increased oil recovery is achieved by waterflooding using low salinity water, compared with injection of seawater or high salinity produced water. The reasons for this improved oil recovery are thought to be due to effective wettability changes and / or controlled removal of clay constituents. This paper describes a log-inject-log field test, designed to identify whether this phenomenon could be observed within the near well region of a reservoir. The log-inject-log test was meticulously designed and executed, to ensure that flow rates were maintained at low rates, and that cross flow was minimised, to ensure that the results were representative of bulk reservoir waterflood displacement. A producing well was selected for the test to ensure that all saturation changes occurred under stringently controlled test conditions and that the results would not be affected by previous high rate water injection. 10 - 15 ‘pore volumes’ of high salinity brine, were injected into the ‘volume of interest’, to obtain a baseline residual oil saturation. This was followed by sequences of more dilute brine followed by high salinity brine for calibration purposes. Multiple log passes were conducted during injection of each brine. At least three further passes were run to ensure that a stable saturation value had been established after injection of each brine. Extensive water sampling was conducted to confirm brine salinities and increase confidence in the quantitative saturation results. The results were in line with previous laboratory tests from other fields, and showed 25 - 50% reduction in residual oil saturation when waterflooding with low salinity brine. Introduction There is increasing evidence from laboratory corefloods, supported by some field evidence, that waterflood performance is highly dependent on salinity of the injection water1,2,3. Laboratory corefloods suggest that as much as 50% additional oil could be produced if low salinity water (<4000 ppm) is injected into the reservoir, opposed to sea water or higher salinity production water. To ascertain whether these benefits seen in the laboratory are also observed in a reservoir environment, a modified log inject log test was performed to determine Sorw to both high and low salinity injection waters. This paper describes the design, execution, and analyses of this single well test. The Log Inject Log Test Techniques for determining Sorw by performing log inject log tests are well publicised in the literature. The technique is based on running multiple passes of pulsed neutron capture (PNC) logs after injection of two or more different brines, which have measurable differences in capture cross section. Assuming that formation porosity and the injectant brine cross section are known accurately, water saturation can be deduced from :Equation 1 Where:St1 is the PNC log response after injecting the first brineSt2 is the PNC log response after injecting the second brineSw1 is the capture cross section of the first brineSw2 is the capture cross section of the second brinef is the porosity of the formation. Therefore, by modifying this general approach, and injecting different brines of at least three different capture cross sections, it is possible to determine the Sorw after base saline injection and after injection of low salinity water.

Prior coarse grid simulation models in the Greater Burgan field were unable to capture the stratigraphically diverse nature of the Wara reservoir, and accurately match the existing historical data, resulting in unrealistic predictions of fluid flow from individual reservoir layers. Most simulation failures are blamed on the inability to correctly model reservoir heterogeneity, rather than problems associated with the data it is trying to match. In reality it is probably a function of both. This paper emphasizes the importance of a systematic review of historical production data to assure the accurate initialization of a simulation model and to assess if a full history match should or should not be undertaken. Not only does there need to be sufficient geologic and engineering detail to accurately characterize the fluid and flow properties of the Wara reservoir, but more importantly issues involving the validity, accuracy, and lack of historic data need to be addressed, before deciding whether a reasonable reservoir model for history match could be developed. The reservoir size, long history, and high production rates of the Greater Burgan field magnify the impact, and highlight the importance of correcting data errors, and recognizing data uncertainty and gaps. Introduction A reservoir simulation model is only as good as the data going into it. Data review and validation is necessary to understand the accuracy and limitations of the data and should always be the first step toward developing a successful reservoir simulation model. Results from a simulation based on inaccurate data may be more damaging to the planning and economics of developing a reservoir than not having a predictive simulation model at all. A systematic review of the Wara production data in the Greater Burgan field identified data problems that have changed prior simulation assumptions about the reservoir character, flow characteristics, and reservoir drive mechanisms. These results will help improve the history match and therefore the accuracy of future development prediction cases. Previous simulation studies in the Greater Burgan field identified the need for more pressure support in the Wara reservoir than what the modeled aquifer could provide. The source of this pressure support has been modeled as fluid influx from the underlying Burgan formation through faults or vertical migration where shale and carbonate barriers between the Burgan and Wara reservoirs may be locally missing. The key to determining the need for this additional pressure support is the assumption that the reported historical production is correct and properly represents the actual volume of fluid produced from the Wara reservoir. Because production data is the primary factor influencing the fluid flow and pressure characteristics in a simulation model it is imperative that this data be reviewed, validated, and updated to be as accurate as possible. The aim of this paper is to show the impact to the initialization of a reservoir simulation model by using reported data without investigating it's accuracy or relationship to historical field practices. Companion papers highlight other aspects of the ongoing effort to characterize the Wara reservoir. Background of the Wara Formation The Burgan field was discovered in 1936 with drilling of the Burgan #1 well into the Wara formation. Several delineation wells were drilled prior to World War II but full scale field development did not occur until 1946 when the first production from the field was exported. Production from the Greater Burgan Field has been primarily from the Wara and Burgan (third & fourth sand) reservoirs. P. 565

No abstract