Pressure gradients 0.374 g/cm3


X,X68.2 X,Y75.1 X,Z85.6


0.599 g/cm3


Y,X00.0 Y,Y06.3


0.982 g/cm3 Increasing pressure


> Vertical compositional gradient in a discovery well. Pressure data and fluid analysis (left) show a transition from water (blue) to oil (green) to gas (red), indicated by changes in the slope of the line. Fluid analysis (center) from DFA data shows a gradient with increasing GOR (higher concentration of C1 and C2-5 gas versus C6+ liquids) from the bottom to the top of the reservoir section. This was confirmed by laboratory GOR measurements (right). DFA measurements indicate a compositional gradient in the oil that was not apparent in the pressure data. An equation of state (EOS) was developed from these data to predict the response in subsequent development wells.


Discovery Well


665 670


675 680 685


690 695


700 705


0 Well 10 20


C1 calculated C2-5 calculated C6+ calculated C1 C2-5 C6+


(DFA)


(DFA) (DFA)


30 40 50 Composition, weight %


Oilfield Review Autumn 09 FluidsLab Fig. 19 ORWIN09/10-FluidsLab Fig. 19


Development Well


C1 calculated C2-5 calculated C6+ calculated C1 C2-5 C6+


(DFA)


(DFA) (DFA)


20 30 40 50 Composition, weight % 60 70


–75 –50 –25 0


25 50


0 10 20 30 40 50 Composition, weight %


> Equation of state model. Engineers developed an EOS model from the discovery well data (top). The calculated values (blue, red and black curves) were compared with the DFA tool’s C1, C2-5 and C6+ response (blue, red and black symbols). The model was then used to predict fluid composition for the injector well (bottom). Although the C1 and C2-5 data agree with the model, the DFA C6+ data (green circles) are considerably different from model predictions above the GOC. Slugging was determined to be the cause of the discrepancy, and the data were later reprocessed and corrected for this effect.


60 70 80


C1 predicted C2-5 predicted C6+ predicted


C2-5 (DFA) C1 (DFA)


GOC C6+ (DFA) 60 70


–75 –50 –25 0


25 50


10 20 30 40 50 Composition, weight % Development Well


320 270


284 265


C1


Composition, weight % C2-5


Tool GOR


1,410 450 360


Laboratory GOR


C6+ Water m3/m3 m3/m3


1,085 336 312


(OWC) lower than originally modeled (left). The result was an increased reserves estimate. An EOS fluid model was later developed from the DFA data. In 2008 the operator drilled an injector well


in the field. Reservoir engineers used the EOS model from the discovery well to predict pres- sures, fluid gradients, fluid contacts and DFA log response for the new well. Engineers developed a predictive modeling workflow that integrated reservoir, EOS and fluid models (next page, top right). Both fluid equilibrium and flow connectiv- ity were assumed. When the measured data from the new well were compared with those from the model, an outlier near the GOC did not match. An extra station was selected, validating the original fluid model and allowing the erroneous data point to be discarded. However, even with this correction, the second well encountered the GOC at a depth that was 18 m [59 ft] higher than predicted, which required further refinement of the reservoir model. There were also significant differences


between the predicted composition and the DFA measurements (left). Analysis of DFA data from a point just above the GOC indicated that slugging during pumpout was affecting the measurement. A spike in the fluorescence measurement caused by this two-phase flow was not being accounted for in the model. Correcting the model for this condition improved the correlation with mea- sured data but a discrepancy remained. Geologists believed that the two wells had


C1 predicted C2-5 predicted C6+ predicted


C2-5 (DFA) C1 (DFA)


GOC C6+ (DFA) 60


their own separate gas caps but assumed they shared a common oil reservoir with flow and pressure communication. The unexpected 18-m difference can be explained by two scenarios: lateral disequilibrium or compartmentalization. To distinguish between these two possibilities,


70 80


a color analysis of the heavy ends, or heavy compo- nents, of the fluids was performed. The heavy ends would be mostly unaffected by two different GOCs; there is no heavy-end component in the gas. If the sand is in a single compartment, then the heavy ends should grade continuously across the reservoir; if the sand is compartmentalized, the heavy ends should show a discontinuous change. Data show that the color is generally con- tinuous (next page, bottom right). In addition, the EOS data suggest equilibrated heavy ends, indi- cating connectivity. This has since been con- firmed by production data.


52


Oilfield Review Autumn 09 FluidsLab Fig. 20 ORWIN09/10-FluidsLab Fig. 20


Oilfield Review


Depth, m


Depth, m


Depth relative to GOC, m


Depth relative to GOC, m


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