Elastic impedance for reservoir fluid discrimination, prospect definition and risk assessment: a North Sea case history

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1 first break volume 25, February 2007 technical article Elastic impedance for reservoir fluid discrimination, prospect definition and risk assessment: a North Sea case history James Storey, 1 John Luchford, 2 and Jamie Haynes 3 Introduction Block 15/18a, operated by Petro-Canada, lies approximately 210 km north-east of Aberdeen (Figure 1) situated in the Outer Moray Firth. Recent technical work has focused on a complex Tertiary channel within which a prominent seismic anomaly exists. This channel system also contains the Macculloch and Brenda fields further to the southeast (Jones et al.) 2004). The channel system exhibits strong seismic reflection character due to significant contrasts in acoustic properties between the reservoirs (Forties and Balmoral sands) and the shale envelope (principally Sele Formation claystones). It is clear from the number of hydrocarbon bearing intervals penetrated by various wells along this Paleocene fairway, both within the channel and on its margins, that the channel system acts as a migration conduit for both oil and gas. Consequently, within the fairway there exists both strong lithology related anomalies and direct hydrocarbon indicating anomalies (DHIs), some of which underpin key exploration targets in the licence. The high quality seismic attributes serve to reduce pre-drill technical risk and allow assignment of high probabilities of success for individual prospects. However, key commercial risk is assigned to accurately predicting the hydrocarbon phase with different development models affecting the perceived value for oil versus gas. This paper seeks to document an experience with elastic impedance inversion, which is aimed at distinguishing between the complex range of possible lithology and fluid effects. Figure 1 Location map (study area highlighted by red box). 1 Petro-Canada, 1 London Bridge, London, SE1 9BG. 2 BG Group, 100 Thames Valley Park, Reading, Berkshire, RG6 1PT. 3 Ikon Science (Current address: Revus Energy, Bjergstedveien 1, PO Box 230 Sentrum 4001, Stavanger, Norway) EAGE 33

2 technical article first break volume 25, February 2007 Figure 2 Geological setting of the study area channel based on a horizon slice from the reflectivity volume. The stronger colours show a complex channel system that transported sand basinward across the contemporaneous slope. The results have enabled a clearer ranking of candidate prospects for consideration within a future exploration drilling programme. Geological setting The Late Paleocene succession in the study area lies within a transitional slope setting. To the northwest are situated the shallow water shelfal and deltaic complexes of a major Late Paleocene delta system. Deepwater environments lie to the southeast. Basinal sequences typically comprise pelagic claystones and channelized basin floor fan sandstones of the Forties Sandstone Member (contained within the Sele Formation) and Balmoral Sandstone Member (contained within the Lista Formation). The Forties unit in the study area is deposited within a slope environment with turbidite and other mass flow sands being point sourced from an incised entry point on the shelf. This mud-rich turbidite system crosses the block in a north-west to south-easterly direction and forms isolated ribbon- or pod-like sandstone bodies within the channel complex. The geometry and setting of the channel is summarized by a seismic horizon slice (Figure 2). This slice, taken from a short distance below the top channel envelope marker, demonstrates both channel form and the local reflection character of the section. The amplitudes arise as a product of the acoustic contrasts between the low impedance soft sands (red) and higher impedance hard shales (blue). The sands are modelled as AVO class 3, being soft and bright with brine and becoming increasingly brighter with oil and gas. The Forties Sandstone Member locally comprises two main parasequences which are, informally, described as the Upper and Lower Forties Sandstone units. The Lower Forties Sandstone unit forms the principal exploration objective targeted by this inversion study. Exploration well 15/18a-8 tested a prospect centrallylocated within this Paleocene channel. It reached TD in the Balmoral section having encountered gas shows in a thin (ca. 20ft) Upper Forties sand unit and a thin (ca. 9 ft) oil column in a thicker good quality Lower Forties sand unit (ca. 77ft). It is the only well to encounter significant Lower Forties sandstones in the study area. Formation pressures were acquired but no drill stem tests were run and the well was abandoned with oil and gas shows. The implications of the shows encountered were subsequently largely overlooked. Typically within such a slope environment, sedimentary processes can develop mounded channel features, i.e. flowstripping processes or lateral accretion, (Timbrell, 1993), and this character is reflected in the variable Lower Forties unit isochore (Figure 3). In this setting, sand continuity is also a concern, impacting on connected volume estimates for individual prospect compartments. Seismic geometries also identify a number of discrete subsidiary channel units within the fairway, notably the 15/18-2A, gas-bearing Upper Forties sand unit (Figure 2). This well provides an important calibration reference point for gas-saturated Forties sandstones. Elastic impedance: an introduction The use of seismic inversion techniques is now commonplace to the point where it is effectively an integrated part of a normal work flow. Where the data availability and quality allow, the application of elastic impedance (EI) inversion provides a method to utilize AVO effects seen in the pre-stack domain to generate EI attribute volumes, (Hilterman, 1990, Figure 3 Thickness in feet of the Lower Forties Sandstone member. The isochore was derived from interpretation of attribute volumes EAGE

3 first break volume 25, February 2007 technical article Figure 4 NW-SE line from an absolute acoustic impedance volume longitudinal through the core of the channel illustrated in Figure 2. Goodway et al., 1997, Gray and Anderson, 2000, Soldo et al., 2001, Lu and McMechan, 2004, and Neves et al., 2004). The study area benefits from full block coverage with modern 3D seismic reflectivity data, acoustic impedance volumes, and AVO products. In this case history the EI inversion process allows a unique insight into the selection of an appropriate EI attribute product and also a locally robust calibration method to address aspects of both technical and commercial risk reduction, including prediction of hydrocarbon phase. The interpretation stage addresses the critical risk in resolving the internal geometry of a slope channel system, within which a number of hydrocarbon-charged compartments are interpreted and, most significantly, results in a revised ranking of key prospects on the licence. Figure 4 shows a seismic transect running along the channel axis from northwest to southeast. This section is taken from an absolute acoustic impedance volume (sparse spike model), and demonstrates the contrast between very low impedance (Lower Forties) sands, which in several locations are interpreted to contain hydrocarbons, and high impedance shales. Previous interpretations had linked the anomalously soft unit in the Stratigraphic Extension area to the anomaly in the Dip-closed Area, placing significant focus on apparent stratigraphically trapped hydrocarbon volumes located within the updip portion of the channel. However, doubts had always remained over the exact geometries and sizes of the individual compartments within the channel complex, axial continuity of the sands, and also uncertainty over the volumetric split in hydrocarbon phase (gas versus oil) of the feature which, collectively, comprised the Maria prospect. (Candidate exploration well target locations are indicated on Figure 6). EI inversion In order to successfully promote the Maria prospect as a viable candidate for drilling, further technical work was recommended to quantify the exploration expectation. A targeted cube of 3D seismic data was reprocessed to condition the data for inversion (the study area ). The volume covers the best of the identified prospectivity in the north-western part of the Tertiary channel. Typical NMO corrected gathers at the target horizon are illustrated (Figure 5) with substacks of and offset being selected for EI inversion. Reflectivity data were converted to approximate zero phase by the application of a 125 degree phase rotation during processing. Rp and Rs volumes (P and S wave reflectivity) were generated from the weighted stack approach (Smith and Gidlow, 1987). Figure 5 Typical NMO corrected gathers from the reprocessed reflectivity data EAGE 35

4 technical article first break volume 25, February 2007 Figure 6 Key well distribution around the channel trend. Colour fill shows average amplitude extraction from the fluid cube (AI-SI projection). Amplitude ranges calibrated to red (gas), green (oil), blue (brine), and brown (shale). Open circles denote candidate exploration well target locations. The P and S reflectivity were inverted to Ip and Is (acoustic and shear impedance respectively) through a model based inversion. Conversion to the Lame elastic constants, and μ followed, and these represent the key products from the inversion process. Inversion calibration: modelling Prior to detailed evaluation of the seismic inversion products, the well data in and around the channel were extensively modelled to ensure that the seismic observations could be reasonably calibrated. The key well, 15/18a-8, is located within the channel core, and close to the southeastern edge of an important seismic anomaly. This well has excellent quality wire line log data, but is the only calibration well to have acquired shear data. The distribution of key wells around the channel trend and locations of significant hydrocarbon occurrences are illustrated (Figure 6). Well data were treated through fluid substitutions, assuming Gassman s relations, (Gassman, 1951). Following initial invasion correction, fluid substitution to brine was carried out and a Vp-Vs crossplot indicated that both shales and sands lie on their respective Castagna trend lines (Greenberg and Castagna, 1992). The shear data from 15/18a-8 was used to validate the prediction for shear in the other key calibration wells. Good relationships were established between Vp, Vs, and lithology. This consistency gave confidence to apply these relations to the other wells but remained a minor source of uncertainty within the study. The next step in the modelling study involved a crossplot of and μ of the shales and the sandstones from the 15/18a-8 well, with the sandstones having been fluid substituted to brine, oil and gas respectively. This crossplot, and also that of acoustic impedance (AI) vs shear impedance (SI) for the same units, are illustrated in the two panels shown in Figure 7. Both plots clearly showed that there was quite good separation between (substituted) gas, oil, and brine sands, but relatively poor separation between brine sands and shales. Also it was noted that the AI vs. SI crossplot appeared to give slightly clearer separation between brine sandstones and shales leading to better linear discrimination between the different lithologies and fluid classes. In Figure 8 the left hand panel illustrates only the sandstones (Forties and Balmoral units) from the 15/18a-8 well. Significantly, in calibration terms, these sandstones have very similar acoustic properties. In the right hand panel, the crossplot includes all the shale data from the three key wells within and around the main channel axis. A strong correlation is evident for the collective sands and the shale envelope represented in the different wells. The lithologies in the target zone from all the wells tend to lie along their single trend line for sand and shale regardless of their age. These observations from the modelling study indicate the potential for appropriately calibrated EI properties from the seismic volume to discriminate for both lithology and hydrocarbon phase. An important calibration reference point is available with gas being present in the 15/18-2A well. Uncertainty over any associated interpretation is attached to the seismic bandwidth and quality of the calibration in regard to actual risk reduction. Inversion results: seismic data The absolute values for both AI and SI derived from the elastic impedance inversion results over the target interval showed a good correlation with the band-limited values derived from the well modelling exercise. However, the SI data proved to be noisier. As with the well data, the extracted AI-SI crossplots appeared to give better linear discrimination compared to the and μ data. Furthermore, synthetic seismograms generated from the well data showed similar characteristics to the real seismic data. The models showed that there was a brightening at the top of the Lower Forties sandstone when oil-bearing which increased in the presence of gas. There was also an increase in positive AVO at the top of the Lower Forties sand in the presence of hydrocarbon. All this evidence suggested that the inversion results could be compared directly to the modelled responses generated from the well data. In conclusion, the modelling study demonstrated that although the sandstones and shales within the target zone had different absolute values they tended to lie on the same parallel trends in the AI-SI domain. Simm et al, 2002, document a straightforward approach to combine AI and SI into a single projected property that should allow discrimination between lithology and fluid. Following this logic, a fluid factor cube was calculated as a weighted combination of AI and SI values, with weights EAGE

5 first break volume 25, February 2007 technical article chosen to project the data parallel to a best-fit trend line. The best discrimination in the real seismic data was obtained with a trend line slightly steeper than that suggested by the well data. This steepening may be due to the systematic effects of noise, analogous to the gradient steepening observed in AVO intercept-gradient cross-plots (Simm et al., 2000), or may be due to smoothing and scale change effects in the inversion. The final projected crossplot from the 15/18a-8 well at 2 ms sampling with the data coloured by lithology and fluid phase is illustrated (Figure 9). The raw crossplot and projection line are shown in the right panel of the display with the left panel illustrating class discrimination boundaries derived from the post projection cross plot. These thresholds were used in the interpretation phase to define seismic classification boundaries between gas, oil, brine and shale domains. Modelling of AI-SI response was carried out to investigate the effect of layer thickness on fluid factor response. As the layer became thinner, an oil sand could mimic a brine sand and a gas sand could look like an oil sand. This happened at a thickness of 23 ft if the maximum frequency present was 80 Hz, and 33 ft if it was 40 Hz. These estimates should bracket the actual range present in the inversion cube. Inversion results: evaluation The EI product volumes were reviewed in a workstation environment, both with traditional views and in the visualization domain. Initially, attention focused on the and μ volumes and adequate results were attained from voxel picks and amplitude extractions in terms of prospect definition and geometry. However, the anomalies proved to be noisy and without sufficient internal range to allow satisfactory discrimination. The noise issue was treated through the application of a median-dip-filter to enhance coherent data and suppress random noise. The search radius of the filter, in this instance, was designed to follow the local dip direction and retain maximum coherent data. Results from the median filtering (Figure 10) demonstrate the lack of distinction between the gas filled channel penetrated by well 15/18-2A (gas sand coloured red) and the low anomaly within the main channel (also coloured red). Subsequently, the interpretation focused on the projected AI-SI volume (fluid factor cube) as providing the best discrimination, with the class boundaries derived from the calibration stage, (Figure 9), being applied to the fluid factor amplitude map extracted from the real seismic (Figure 6). In crossplot space the effect of the projection and the use of the AI-SI projected volume can be appreciated by analysis of the data around the gas sand penetrated by well 15/18-2A (Figure 11). Though still imperfectly calibrated, the known gas channel has generally more negative values than the AI-SI anomaly in the main channel trend. The most likely model to explain this observation is that the main channel anomaly represents principally an oil effect, with any gas cap, if present, being of limited gross thickness. Figure 7 Left panel: 15/18a-8 crossplot. Right panel: 15/18a-8 AI SI crossplot. In both plots the blue, green and red points are the sandstones (U Forties, L Forties and Balmoral) substituted to water, oil and gas respectively. The black points are the shales. Figure 8 Left panel: 15/18a-8 AI-SI crossplot. The blue, green and red points are the sandstones (U Forties, L Forties, and Balmoral) substituted to water, oil and gas respectively. The different symbols are for U Forties (cross), L Forties (square) and Balmoral (circle.) Right panel: wells 15/18a-8, 15/18a-7 & 15/18-2A AI-SI crossplot. Shales only from SELE S3 to Base Balmoral SST. The data is coloured by well. Figure 9 15/18a-8 AI-SI projected crossplot coloured by lithology (data in 2 ms sampling). Projection line based on inversion results attempting to better discriminate between brine-saturated and hydrocarbon-bearing sandstones, (Final projection = 0.83AI-SI-2200). With the most appropriate and model controlled volume in place and a calibration methodology determined, the interpretation phase moved on to mapping and prospect delineation. Fluid factor amplitude maps were displayed in the visualization domain and prospectivity evaluated by 2007 EAGE 37

6 technical article first break volume 25, February 2007 Figure 10 SW-NE dip oriented vertical slice transverse to channel from volume. A) Bottom panel is raw data and B) top panel is following application of median dip filtering. Zones of low (i.e. low incompressibility) are shown in red. two methods. Within the visualization domain it was a relatively trivial exercise to organize a rendered volume display (Figure 12). By careful selection of the appropriate calibrated fluid factor range, amplitudes relating only to hydrocarbon bearing sands were easily displayed (see also Luchford et al., 2002). Secondly, automatic voxel connection picking was applied, again restricting the window size or gate of amplitude values to those corresponding to hydrocarbon bearing sands. The voxel picks quickly captured the area and thickness of the low projected AI-SI anomalies. The voxel picks also acted as a good verification of anomaly continuity. Many different displays were generated in the visualization domain and had the benefit of being relatively independent from interpreter input/ bias. In the 2D map view domain, the classical display was derived from an amplitude extraction within interpreted upper and lower boundaries to the anomaly. The distribution of average amplitude from the fluid factor cube within the Lower Forties Sandstone unit highlights some clear trends (Figure 6). Superimposed on this display is a windowed extraction for the small subsidiary Upper Forties Sandstone channel unit around the 15/18-2A region. The amplitude values are colour coded to represent fluid type and lithology, gas sand - oil sand - brine sand - shale by reference to the defined divisions (Figure 6 and 9). A number of prospective bodies are clearly defined within the channel. Definition of the shape and geometries appears very clear. Furthermore, of particular significance in calibration terms is the independent gas channel tested by the 15/18-2A well. This region exhibits high negative values of fluid factor amplitude (-750 to -2000) and acts to discriminate the gas sand domain. The oil sands are located in the range of values -750 to -200, once again calibrated according to the model. This argument seems valid based on the observed tendency for all the local sandstones (and shales) to lie along a single trend line in AI-SI space (Figure 9). The implication from this interpretation is that the oil sand trend contains prospects with very small gas caps (or possibly no gas at all). To complete the map view, the depth contours to the top of the Lower Forties channel sand have been added to the display (Figure 13). It also illustrates average amplitude extracted from the fluid factor cube for the Lower Forties sandstone unit. However, in this display, the 15/18-2A Upper Forties gas channel response has been removed as it lies at a slightly shallower stratigraphic level. Addition of structure allows the focus provided by the presence of an obvious anomaly to be checked for amplitude fit to structure relationships which are desirable in the risk assessment of prospective structures. It also provides information regarding the likely trapping mechanism. These relationships show that within the channel setting seen in block 15/18a, structural traps through simple dip closure Figure 11 XL2011 AI-SI projection - AI crossplot (close to 15/18a-8). The gas-filled channel in the Upper Forties unit (right) has generally more negative values than the main Maria prospect (left). (Projection = 0.83AI-SI-2200) EAGE

7 first break volume 25, February 2007 technical article Figure 12 Windowed amplitude display of fluid factor (projected AI-SI) amplitudes calibrated to represent only hydrocarbon bearing sands. can be interpreted, as well as different combinations of stratigraphic trap. In conclusion, this interpretation has significantly changed the risking and overall perception of the Maria prospect compartments. It shows that the previous associations interpreted between the updip stratigraphic trap (Stratigraphic Extension) and the structurally closed region updip from well 15/18a-8 (Dip Area) was probably erroneous. Subsequently, the focus for future exploration activity on the block has changed to target the structurally defined part of the prospect trend. However, at some stage this model will need to be tested by a future exploration well. Conclusions The measurable impact (cost versus benefit) of this exercise is seen in the substantially changed view of the shape, style, fluid content, and risk of a group of prospects. Prospect definition by use of calibrated fluid factor cube anomalies is a powerful tool. In this study, detailed modelling took advantage of the presence of several wells within the prospect area to demonstrate that the local lithologies have similar rock properties and lie along unique trend lines, both in μ space and AI-SI space. Furthermore, since the sandstones and shales have different absolute values but occupy parallel trends in the AI-SI domain, the logical conclusion is to combine AI and SI to form a single projected property, (fluid factor cube), which potentially allows differentiation of lithology and fluid effects. Modelling clearly demonstrates the reduced noise effects with the projected AI-SI data. Additionally, the presence of a proven gas-bearing sand within the trend envelope allows Figure 13 Average amplitude from Lower Forties sandstone, (Fluid Cube, projected AI-SI volume) with overlay of depth structure contours (refer to figure 7 for amplitude scaling). quantitative calibration for gas, oil, brine and shale. This factor provides a highly significant contribution to understanding some of the risks within the prospect trend. The Maria (Dip) prospect is supported by an interesting seismic DHI. The results of this study predict the presence of a small gas cap overlying a material oil rim. However, it is worth noting that the interpretation represents a perceived understanding of the geological play. Inevitably, this remains a model until tested by the drilling of an exploration well or wells. Acknowledgements The authors wish to thank the management of Petro-Canada and Eni for their permission to publish the results. References Gassmann, F. [1951] Elastic waves through a packing of spheres. Geophysics, 16, Goodway, W., Chen, T., and Downton, J. [1997] Improved AVO fluid detection and lithology determination using Lame s petrophysical parameters: LambdaRho, MuRho and LambdaMu fluid stack from P and S inversions. Canadian Society of Exploration Geophysicists, Abstracts, Gray, F. D. and Anderson, E.C. [2000] Case histories: inversion for rock properties. EAGE Annual Meeting, Expanded abstract. Greenberg, M. L. and Castagna, J. P. [1992] Shear wave velocity estimation in porous rocks: Theoretical formulation, preliminary verification and applications. Geophysical Prospecting, 40, Hilterman, F. [1990] Is AVO the seismic signature of lithology? A case history of Ship Shoal South Addition. The Leading Edge, 9, 6, EAGE 39

8 technical article first break volume 25, February 2007 Jones, I.F., Christensen, R., Haynes, J., Faragher, J., Novianti, I., Morris, H., and Pickering, G. [2004] The Brenda field development: a multi-disciplinary approach, First Break, 22, 3, Luchford, J., Gras, R., and Fakorede, D. [2002] Reducing exploration and production risk by visualization and seismic classification: a case study from the North Sea. First Break, 20, 11, Lu, S. and McMechan, A. [2004] Elastic impedance inversion of multichannel seismic data from unconsolidated sediments containing gas hydrate and free gas. Geophysics, 69, Neves, F.A., Mustafa, H.M., and Rutty, P.M. [2004] Pseudo-gamma ray volume from extended elastic impedance inversion for gas exploration. The Leading Edge, 23, Simm, R.W., White, R., and Uden, R., [2000] The anatomy of AVO crossplots. The Leading Edge, 19, Simm, R.W., Kemper, M., and Deo, J. [2002] AVOImpedance: A new attribute for Fluid and Lithology Discrimination, Petex Conference, London. Smith, G.C. and Gidlow, P.M. [1987] Weighted stacking for rock property estimation and detection of gas. Geophysical Prospecting, 35, Soldo, J. Lenge, D., Sigismondi, M., Telles, A.S., Sena,A. G. and Smith, T. [2001] 3D AVO and seismic inversion in Maria Ines Field, Santa Cruz, Argentina; a case study. SEG Annual Meeting. Expanded abstract. Timbrell, G. [1993] Sandstone architecture of the Balder Formation depositional system, UK Quadrant 9 and adjacent areas. In Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference, Wavefield Inseis AS The new wave in seismic acquisition We are a Norwegian company providing proprietary and non-exclusive geophysical services using highly specified vessels and the latest seismic equipment. These services include long offset 2D, high capacity 3D, 4D, Multi-azimuth and Wide-azimuth surface seismic data plus complete permanent 4D seismic reservoir monitoring solutions from initial feasibility through to the system installation and 4D acquisition. We are committed to bringing new technologies to market to further accelerate and de-risk the replenishment of our clients reserves. Wavefield Inseis - innovating as we grow. Pacific Ocean COLOMBIA Isla T E info@wavefield-inseis.com Visit JOB CENTRE EAGE