Integration of data allows predictive testing
of the reservoir to establish connectivity and fluid equilibrium. Fluids experts developed a sampling program beforehand from EOS fluid models and were able to validate results when data initially deviated from the model. The ability to adjust the program in real time provides the reservoir engi- neer with a diagnostic tool for data quality con- trol. In this case, revisiting an anomalous data point confirmed the original model. Similarly, analysis of color and asphaltene gradients con- firmed reservoir connectivity when initial test results were inconclusive.
Resolving Deepwater Uncertainties Deepwater plays are becoming more common and fields are being discovered in areas whose water depths made them unreachable not long ago. The risk-reward scenario in deepwater E&P goes beyond the potential for finding large accu- mulations of untapped hydrocarbons; it encom- passes development decisions that must be made with limited datasets. Reservoir connectivity is often the largest uncertainty, and no single mea- surement can provide a complete solution.40 Pressure gradients have traditionally been
used to confirm connectivity, as well as to com- pute fluid density and detect fluid contacts. The success of this technique depends on the number of data points as well as their locations within the reservoir column. Discontinuous reservoir sec- tions, thinly laminated sands and supercharging can distort or confound the interpretation. Abrupt changes in fluid density within a fluid column are expected at the OWC and GOC, but when detected within the oil column, they indi- cate the potential for compartmentalization. A new sensor that measures live-fluid density
was employed in an offshore West Africa stacked- sand reservoir. The deepwater vertical appraisal well was drilled in a water depth of 1,000 m [3,280 ft]. The objectives of the well were to assess hydrocarbon potential, evaluate fluid properties, determine fluid contacts and identify the presence of compositional grading.41
Data
were acquired from an MDT tool equipped with two InSitu Family sensors. One sensor was located in the focused-probe assembly and a sec- ond was in the InSitu Fluid Analyzer module.
40. Elshahawi et al, reference 33. 41. O’Keefe et al, reference 23.
1 5 2 3 4
Measured Compositions On
Extra Off On On
Model output
Temperature, K EOS Modeling
DFA and Sample Analysis Results
DFA Equivalent
Modeled Compositions
DFA Equivalent
Fluid Model
Injector Well B
Discovery Well A
> DFA predictive modeling. Data acquired in the discovery well (bottom right) are combined with reservoir and EOS models to predict DFA measurements in an injector well drilled at a later date (top). Because Station 2 did not match the prediction, a fifth station was taken, which matched the predicted response and confirmed the original model. The off-trend station was judged to be erroneous and discarded. This is an example of real-time observations suggesting retesting. Without the predictive model, the erroneous data could have resulted in an incorrect conclusion, such as compartmentalization.
3,660 3,670
3,680 3,690 Optical density, model
3,700 3,710
Oilfield Review Autumn 09
0 0.5
FluidsLab Fig. 21 1.0
Well A Well B
ORWIN09/10-FluidsLab Fig. 21 Optical density
1.5
2.0
2.5
> Color analysis between wells. Well A color data from DFA measurements (blue dots) follow a consistent trend, although the deeper points have more color than modeled data predictions (red curve). The model assumes a fixed asphaltene particle size and outputs color based on asphaltene concentration. Data from DFA measurements taken from Well B (green) plot on the model trend line at the top of the reservoir but the deeper data points are above the line. The observation from Well A data, that fluids in the lower part of the reservoir have more color than expected, is reflected in Well B data. Although this could be an indication of compartmentalization, it could also be explained by disequilibrium of the fluids in the reservoir. From production data engineers concluded that the two wells were not in separate compartments.
Winter 2009/2010
53
True vertical depth, m Station 2 off-trend
Measured
Pressure, psi
Page 1 |
Page 2 |
Page 3 |
Page 4 |
Page 5 |
Page 6 |
Page 7 |
Page 8 |
Page 9 |
Page 10 |
Page 11 |
Page 12 |
Page 13 |
Page 14 |
Page 15 |
Page 16 |
Page 17 |
Page 18 |
Page 19 |
Page 20 |
Page 21 |
Page 22 |
Page 23 |
Page 24 |
Page 25 |
Page 26 |
Page 27 |
Page 28 |
Page 29 |
Page 30 |
Page 31 |
Page 32 |
Page 33 |
Page 34 |
Page 35 |
Page 36 |
Page 37 |
Page 38 |
Page 39 |
Page 40 |
Page 41 |
Page 42 |
Page 43 |
Page 44 |
Page 45 |
Page 46 |
Page 47 |
Page 48 |
Page 49 |
Page 50 |
Page 51 |
Page 52 |
Page 53 |
Page 54 |
Page 55 |
Page 56 |
Page 57 |
Page 58 |
Page 59 |
Page 60 |
Page 61 |
Page 62 |
Page 63 |
Page 64