Time-lapse simulator-to-seismic study - Forties field, North Sea. Christophe Ribeiro *, Cyrille Reiser, Philippe Doyen, CGGeritas, London, UK August Lau, Apache Corp., Houston, US, Steve Adiletta, Apache North Sea Ltd, Aberdeen, UK Summary A Simulator-to-Seismic (S-to-S) study is conducted over the Forties field, North Sea, by combining petrophysical, engineering and geophysical data into an integrated workf. Based on a calibrated rock physics model, static and dynamic properties from a reservoir model are converted into time-lapse synthetic seismic attributes that can be used in conjunction with conventional seismic attributes to get more insights into the interpreted 4D anomalies. The aim of the study is to better understand the drainage patterns of the reservoir and help validate the planned position of additional producer wells to ultimately reduce drilling risks. Introduction The Forties field is located in blocks 21/1 and 22/6a of the North Sea, nearly 18km east-northeast of Aberdeen, Scotland. The field which was discovered in October 197 in the Paleocene sandstones of the Forties formation, was the first major oil discovery in the UK sector of the North Sea (Hill and Wood, 198). The reservoir pay consists of submarine fan sandstones deposited by density turbidites. The Forties field can be separated into four main channel complex, the Alpha, Bravo, Delta-Echo and Charlie (Figure 1) where porosity averaged 27% and permeability 7 md. Hydrocarbons production is completed by waterflooding with pressure support provided by an active aquifer and sea-water injectors (Brand et al., 1996). Reservoir pressure is reasonably constant and in the region of 29 psi. This study focuses on the south-east Forties (Figure 1 rectangular area). F simulation outputs corresponding to available base (i.e. 2) and monitor (i.e. 25) seismic vintages are forward modeled in order to assist in the interpretation of observed time-lapse effect. The integrated S-to-S workf presented in this paper also offers the possibility of fast turn-around modeling once customized; and access to calibrated rock physics templates for quantitative time-lapse interpretation. Integrated Simulator-to-Seismic workf A 4D earth model conforms to the main geological horizons and geometry of the f simulation model is created in order to store all static (i.e. porosity and volume of shale) and dynamic properties (i.e. fluid saturation and reservoir pressure) from the f simulator in a detailed stratigraphic grid. The stratigraphic model is updated temporally with the predictions from the fluid f simulator at each time-steps. The P-wave velocity ( p ), S- wave velocity ( s ) and density (ρ) are fluid and pressure substituted within the model in order to estimate elastic property changes and compute time-lapse synthetic seismic. Figure 1: Distribution of the different channel complexes within the Forties field (brown outline). The A, B, C, D and E letters stand for the Alpha, Bravo, Charlie, Delta and Echo channels. The S-to-S study is carried out on the South-east Forties (rectangular area). Calibrated rock physics modeling The pressure-sensitivity models for P and S-wave velocities are derived from ultrasonic laboratory measurements as a function of confining pressure carried out on 12 drained sandstone core plugs from various wells. The pressure velocity models used take the foling form: where N Pdry ( Pc ) = 1 a Pdry Sdry ( Pc ) = 1 a Sdry Pdry, C B D P S Pc exp bp Pc exp bs 5.1 5.2 Sdry are the -pressure velocity asymptotes, a and b are the stress-sensitivity parameters, P c is the confining pressure, and the subscript p and s denote compressional and shear-wave, respectively. The stresssensitivity parameters and -pressure asymptotes are derived by least-squares fitting of equations 5.1 and 5.2 to the laboratory measurements. The average pressure A E 2944
velocity models for P and S-wave velocities show that variations of less than 1% in velocities are observed over the field pressure history meaning that the effect of pressure is negligible in the Forties field. However, pressure velocity asymptotes exhibit a first order dependence with porosity and second order with volume of shale (Ribeiro, 26). To include these two variables into the rock physics models, P and S-wave sonic measurements at in-situ pressure and saturation conditions are converted to -pressure and dry conditions. Then, a linear leastsquares regression is applied between -pressure velocities (at dry conditions), the porosity and the volume of shale logs. The resulting models take the foling form: = a b. φ c. 5.3 P or S dry c where Φ, c stand for the porosity and volume of shale. The validation of the rock physics models is made by comparing the modeled and measured P and S-wave velocities at various well locations. Figure 2 shows the accurate estimation obtained from the calibrated rock physics models for P and S-wave velocities; that will be used in the petro-elastic transformation in order to take into account for the effect of porosity and clay content on the elastic properties. Furthermore, from these calibrated velocity models, rock physics templates are derived in order to study the effect of saturation changes and also assist in the quatitative interpretation of time-lapse seismic inversion attributes. Figure 3 presents 4D rock physics templates describing the effect of water saturation on Ip, Is and p/s ratio. Acoustic impedance changes up to 4.5% are expected from oil to brine bearing sands. 4D earth model building A stratigraphic model is built by duplicating the reservoir f simulation grid after aerial downscaling, and storing all static (i.e. porosity and volume of shale) and dynamic properties (i.e. fluid saturation). The stratigraphic grid is made of cells of 5*5 metres horizontally and from 1 to 3 meters vertically. The porosity is on average close to 27% in the f simulation model. The Net-to-Gross (NTG) is binary meaning that and 1 values stand for shale (i.e nonnet cells) and sand (i.e net cells) lithologies, respectively. To build a realistic volume of shale (sh) model, close to hundred sh logs from the Forties field are interpolated within the stratigraphic grid. The interpolation of the logs is performed using the binary NTG as constrained, meaning that sh logs going through the net cells were interpolated within the net cells only and vice-versa. Furthermore, two horizons are added in order to create the overburden and underburden necessary to obtain realistic reflection at the top and base of the reservoir. Figure 2: Rock physics models calibration at well location. Estimated P and S-wave velocities (green curves) accurately match measured logs data (black curves). Is and p/s changes (%) -5-4 -3-2 -1 Is p/s Water sand Sw=.8 Ip changes (%) Oil sand, Sw=.2 Sw=.6 Sw=.4 IpIs Ipps Figure 3: Time-lapse rock physics templates for P-impedance (Ip), S-impedance (Is) and p/s ratio. Elastic property variations are computed between oil and water sands. Petroelastic transformation & synthetic modeling Within the 4D earth model, the P-wave velocity ( p ), S- wave velocity ( s ) and density (ρ) are computed as a function of pressure and fluid saturation changes that are induced by hydrocarbon-production for the different time- -1-2 -3-4 2945
steps of the f simulator. Since pressure effect is negligible in the Forties field, a constant effective pressure of 37 psi is used. Petro-elastic transformation is performed through the calibrated rock physics models for all net cells using the fluid properties presented in Table 1. Salinity (ppm) 8 GOR (L/L) 54 API 36 Reservoir temperature ( C) 96 Gas gravity 1.11 Table 1: Oil and brine properties The velocities and density in the non-net cells and overburden/underburden areas are obtained by using interpolated P-wave velocity and density logs. For the shear-wave velocity a velocity ratio of 2.17 derived from well data is used. Figure 4 presents forward modeled P- wave velocities for the base survey (i.e. 2) with evaluation at two well locations. Depth-time conversion of the stratigraphic grid is then performed and QC extensively to tie the interpreted time intra-channel horizons. Compressional time-lapse seismic are synthesized from the Aki and Richards (198) approximation at different timesteps from the f simulation model using the forward modeled elastic properties. To increase the accuracy of the synthetic data a wavelet representative of the seismic data is extracted for the convolution and random noise added to the synthetic data, based on Signal-to-Noise ratio derived from the real seismic data. Well A 2 p (m/s) 36 Well B Figure 4: Forward modeled P-wave velocity for the base survey (i.e. 2) with correlation at two well locations. and stand for the top reservoir and top Sele horizons. Overburden/underburden velocities are interpolated from logs only while the calibrated rock physics models are used within the reservoir. Time-lapse seismic interpretation A comparison between time-lapse modeled and measured seismic is presented on Figure 5 for the south-east Forties field. The movement of the oil-water contact is clearly modeled from the f simulator predictions and is overall in agreement with the contact observed on the far angle stack difference, being sensitive to fluid saturation effect. However, on the north-west of well C, the time-lapse synthetic changes are overestimated suggesting possible updates to the reservoir model. The addition of a transmissibility barrier or reduction of production rate in nearby producers could assist in improving the accuracy of the forward modeled products. An inline passing through well C is shown on Figure 6 for time-lapse water saturation, synthetic and real far angle stacks. The characteristic through-peak doublet of the oil-water contact exhibits a degree of correlation between modeled and measured seismic just be the top reservoir horizon. The timing of the MOWC and OOWC is similar on both seismic demonstrating the accuracy of the forward modeled elastic properties and depth-to-time conversion process. Towards the north-west, smaller time-lapse anomalies seem to emerge deeper in the reservoir. However, these anomalies are more difficult to detect due to the magnitude of the saturation changes (i.e. 15%). In this Simulator-to- Seismic study, saturation changes down to 15% for pay thickness down to 7 meters appear to be detectable on far angle synthetic seismic. Conclusions The conversion of f simulation predictions to the seismic domain via an integrated Simulator-to-Seismic workf offers another perspective into the interpretation of time-lapse seismic data. A detailed rock physics analysis is carried out in order to derive suitable pressure-sensitivity velocity models from ultrasonic measurements; and the effect of porosity and clay content are taken into account in the calibration step. Forward modeled seismic can be combined with AO analysis, simultaneous inversion seismic attributes in order to cross-validate new targets or give additional insights to clarify complex seismic response. Acknowledgements The authors would like to thank Owen aughan, Donald Keir, Richard Jones, Ken MacAllister from Apache North Sea. Finally, the authors acknowledge CGGeritas, Apache Corporation and partners Shell, ExxonMobil for granting permission to publish this paper. 2946
(a) (a).3.3 (b) (b) MOWC OOWC (c) (c) MOWC OOWC Figure 6: Time-lapse (a) water saturation, (b) synthetic and (c) real far angle stacks difference cross-sections between monitor and base vintages. MOWC and OOWC stand for the Moved Oil-Water Contact and the Original Oil-Water Contact. Figure 5: Average Time-lapse (a) water saturation, (b) synthetic and (c) real far angle stacks difference maps between monitor and base vintages. Maps are computed between the interval and +2ms. 2947
EDITED REFERENCES Note: This reference list is a copy-edited version of the reference list submitted by the author. Reference lists for the 27 SEG Technical Program Expanded Abstracts have been copy edited so that references provided with the online metadata for each paper will achieve a degree of linking to cited sources that appear on the Web. REFERENCES Aki, A., and P. G. Richards, 198, Quantitative seismology: Theory and methods: W. H. Freeman and Company. Brand, P. J., P. A. Clyne, F. G. Kirkwood, and P. W. Williams, 1995, The forties field: 2 years young: Proceedings of the Offshore Europe Conference, SPE, 695 74. Hill, P. J., and G.. Wood, 198, Geology of the forties Field, U. K. continental shelf, North Sea, in M. T. Halbouty, ed., Giant oil and gas fields of the decade 1968-1978: American Association of Petroleum Geologists, Memoir 3, 81 93. Ribeiro, C., 26, Time-lapse inversion for pressure and saturation in clastic reservoirs: Ph.D. thesis, Heriot-Watt University. 2948