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2D modeling of overpressure in a salt withdrawal basin, Gulf of Mexico, USA
Marine and Petroleum Geology 26 (2009) 464–473
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Marine and Petroleum Geology journal homepage: www.elsevier.com/locate/marpetgeo
2D modeling of overpressure in a salt withdrawal basin, Gulf of Mexico, USA Jeffrey R. Allwardt*, G. Eric Michael, Chuck R. Shearer, Philip D. Heppard, Hongxing Ge ConocoPhillips Company, 600 North Dairy Ashford, Houston, TX 77079-1175, USA
a r t i c l e i n f o
a b s t r a c t
Article history: Received 15 September 2007 Received in revised form 1 April 2008 Accepted 6 January 2009 Available online 15 January 2009
This study demonstrates the utilization of 2D basin models to address overpressure development due to compaction disequilibrium in supra-allochthonous salt mini-basins with very high sedimentation rates in the Gulf of Mexico. By properly selecting 2D line sections with moderate stratigraphic resolution, it is possible to predict timing of overpressure development and approximate present-day overpressure distributions in the mini-basin. This study shows that even low resolution models with approximate information on the net-to-gross (sand:shale ratio) can average 0.4 ppg with a maximum error of 1.0 ppg relative to pressure measurements in sandstones. The models based on age, depth, approximate lithology and an interpretation of complicated salt movement are adequate to evaluate pressure to address issues around trap containment and may be used for preliminary well planning. This study tested the results of overpressure prediction utilizing different stratigraphic resolutions and shows the sensitivity of overpressure modeling to 2D line selection. Also, three models were built to investigate how the permeability of salt welds affects overpressure development in an adjacent salt mini-basin. These results indicate that even a salt weld permeability reduction of 1.5 log mD results in a pressure difference between neighboring mini-basins. Additionally, these models qualitatively reproduced the seismic velocity volume which is supporting evidence that the salt welds in this mini-basin are at least partially sealing. Ó 2009 Elsevier Ltd. All rights reserved.
Keywords: Basin modeling Pore pressure Gulf of Mexico Pressure prediction Salt reconstruction
1. Introduction Pressure prediction is critical for hydrocarbon trap evaluation and well planning. Basin modeling can be used to forward model pore pressure and provides information on the timing of overpressure development (Giles et al., 1999; Throndsen and Wangen, 1998; Yardley and Swarbrick, 2000; Yardley et al., 2004). Models are typically calibrated to pressure measurements in sandstones and increasingly other well information such as log data, mud weights, seismic velocities and velocity based pore pressure calculations. Processes that result in overpressure that are commonly modeled are compaction disequilibrium, lateral pressure transfer, hydrocarbon generation, and oil to gas cracking. Of these processes, only compaction disequilibrium is addressed here. The primary factors affecting this process are sedimentation rate, shale permeability evolution, sediment compaction, and basin geometry. Generally, basin modeling for pore pressure prediction is used to investigate past and present reservoir quality, hydrocarbon migration and containment (e.g. shale and fault seal behavior) and * Corresponding author. Tel.: þ1 713 624 9448; fax: þ1 713 624 3722. E-mail address: [email protected] (J.R. Allwardt). 0264-8172/$ – see front matter Ó 2009 Elsevier Ltd. All rights reserved. doi:10.1016/j.marpetgeo.2009.01.009
porosity evolution for thermal and charge modeling. Additionally, it can be useful in drilling programs to predict overpressure where seismic based methods or projections from well information may be difficult such as subsalt areas or uplifted terrains. This study utilizes 2D basin modeling to assess pore pressure distribution and evolution along two intersecting lines. These sections transect three mini-basins with allochthonous salt canopy bodies and are separated by salt welds in the offshore Gulf of Mexico. The mini-basins received up to 25,000 feet (7600 m) of sediments in the last 2.75 million years and are associated with and affected by mobile salt which has moved into shallow diapirs. The modeling is aimed at assessing the relative importance of basin geometry, lithology, model resolution, and the sealing effectiveness of salt welds on pore pressure prediction. Three-dimensional basin models have been shown to be more robust than 1D and 2D models for pore pressure prediction since they can more accurately portray the 3D nature of fluid flow (Giles et al., 1999; Throndsen and Wangen, 1998; Yardley et al., 2004). This study used two intersecting 2D basin models due to the lack of knowledge about past salt movements and the time necessary to properly constrain a palinspastic 3D reconstruction of a basin that includes significant salt movement.
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2. Methodology 2.1. Selection of model sections
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Fig. 1a shows the depth to the top of the salt in the study area. The canopy consists of three allochthonous salt sheets that are mostly welded (Fig. 2a–d). The western salt sheet is a salt-stock sheet (Jackson et al., 1990; Rowan, 1995). The central sheet is a counterregional salt system (Diegel et al., 1995; Schuster, 1995), and the eastern sheet extends beyond the study area and thus cannot be classified. Three mini-basins developed in the area corresponding to the three salt sheets. Shallow edge domes (Handschy et al., 1998) formed at the eastern flank of the western sheet and at the western flank of the eastern sheet (Figs. 1 and 2d). A pronounced expulsion salt rollover (Ge et al., 1997) formed as a part of the counterregional system in the central mini-basin (Fig. 2c), where sedimentary strata predominantly dip to the south shown in depth sections as well as in the depth structure map of the top Pleistocene horizon (Fig. 1b). Eastern and western flanks of the central mini-basin are buried below the edge domes (Fig. 2d). Mini-basins are separated from each other by lateral salt welds. Rapid sedimentation occurred in the mini-basins in response to the withdrawal of the allochthonous salt in the recent past, where, up to 25,000 feet (7600 m) of sediments have accumulated during the last 2.8 Ma. Such a rapid and thick
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Fig. 1. Depth to (a) top salt in the study area and depth to the (b) top Pleistocene surface. Darker shades are structurally deep and lighter shades represent structural highs. The green line swamps in b represent the flow lines that reveal the actual dip of the system. Locations of the sections and wells are shown. The red curve represents the location of the primary salt weld of interest.
sedimentation has likely led to the extreme overpressures in the system and predicting the magnitude and history of this overpressure is the primary focus of our study. Two sections have been selected for our 2D basin models. The north–south (NS) section bisects the central mini-basin and was chosen in an attempt to accurately portray the true dip of the sediments (Fig. 1b). The east–west (EW) section intersects all three mini-basins and passes through wells 1–3 as well as the prospect region (Figs. 1 and 2). The NS model passes through well #1, where it also intersects the EW model. The purpose of modeling intersecting lines is to assess the effect of basin geometry and the magnitude of the differences created by not having a true 3D geometry. Fig. 2a–d shows the seismic lines for the two crosssections. The prospect lies against one of these welds where the
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Fig. 3. Restored structural evolution of the salt emplacement and mini-basin development for the EW section.
overlying sediment is in the western mini-basin and the prospect is in the central mini-basin (Fig. 2d). The prospective trap in the area is a three-way closure where the salt weld is required to seal. The weld is a critical element to the prospect. 2.2. Reconstruction of salt geometry through time In order to appropriately model the pressure evolution, the basin geometry, especially the salt kinematics, needs to be reconstructed. Salt movement and the resulting large salt bodies play
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Fig. 4. The present geometry of the two sections where the labels correspond to ages determined from a biostratigraphic analysis of well #1 (Table 1). The cross-hatched pattern is the salt.
a primary role in the geothermic history of the basins and maturation of oil and gas source rocks in the region (Mello et al., 1995; Yu et al., 1992). Because of the paucity of large faults, we structurally restored the model sections by sequentially backstripping the topmost layer and unfolding successive sedimentary strata with vertical shear. The base of the allochthonous salt remained unchanged during the restoration of the suprasalt mini-basin strata. Any space created during the restoration was then filled by salt (Schultz-Ela, 1992; Worrall and Snelson, 1989). During the restorations, layer thickness was adjusted for decompaction by using commonly accepted compaction curves. Paleobathymetry was reconstructed with biostratigraphic data and isostacy was not corrected during our restoration. The intersecting dip and strike lines were used to cross-check the salt thicknesses at different stages. This method may be considered to produce minimum salt thicknesses similar to those by Rowan (1995) and McBride et al. (1998). Both NS and EW sections were restored (Figs. 3 and 4). Only the structural evolution of the east–west section, which cuts through three mini-basins above the canopy, is discussed in the following paragraph (Fig. 3). The EW section consists of three allochthonous salt bodies (Fig. 2b and d). Section reconstruction suggests that the salt canopy formed around 11 Ma by coalescing three allochthonous salt sheets. The top of salt was either exposed at water bottom as a salt glacier or covered by a veneer of hemipelagic sediments. By around 9.1 Ma, the central salt sheet was partially loaded by sediments on the flanks, whereas the western salt sheet and middle of the central sheet were still emerged at the water bottom (Fig. 3e). By around 4.0 Ma, the central salt sheet is completely covered by sediments at this location. Overall, the sheet thinned and a residual salt body was trapped in the middle of the basin (Fig. 3d). The western and eastern salt sheets were greatly inflated during this time, probably through feeders that are outside of the section. They expanded toward the center of the section and overlie the margins of the central minibasin. By around 2.8 Ma, more salt was expelled out of the section by sedimentary loading in the central mini-basin, where salt welds began to form on the flanks (Fig. 3c). Sediments also began to load the western and eastern salt sheets to form mini-basins, probably
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Fig. 6. The (a) porosity and (b) pressure calibration curves at well location #1. The results for the north–south (NS) and east–west models (EW). The circles represent (a) ShaleQuant porosity predictions for the shale and (b) wireline pressure measurements in the sands.
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due to diminishing salt source from the feeders. Only the flanks of the sheets may remain open at the water bottom and continued sedimentation from 2.8 Ma to 1.8 Ma further enhanced the minibasins above the western and eastern salt sheets (Fig. 3b). Edge domes from these basins were well developed during this time. The salt weld at the base of the central mini-basin was well formed by 1.8 Ma. From 1.8 Ma to the present time, salt was further removed from the current section, probably by salt expulsion (Ge et al., 1997), salt dissolution, and salt feeding to the shallower salt systems.
Extensive salt welds formed across the section (Fig. 3a). The edge domes are now buried below the sediments that are being cut by the many shallow faults (Figs. 2d and 4). 2.3. Model specifics and calibration The 2D basin model simulations have been performed using the PetroMod 9.0 software package, where the 2D sections were selected from a 3D seismic volume. As an additional calibration tool, the time dependence of salt movement and the resulting structures (Fig. 3) were interpreted using the ‘‘paleothickness’’ tool available in PetroMod. The rock properties of the initial model used commonly accepted values for the basement, Jurassic–Cretaceous limestone, salt, and clastics (Wygrala and Hantschel, 1996). The base case models used rock properties for a mixture of sand and
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3. Results and discussion
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Table 2 The average and maximum errors for pressure prediction of the EW and NS models.
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Fig. 7. Plot of pressure vs. depth for the 3 EW models with different shale:sand ratios. The 50:50, 70:30, and 100:0 models have permeability values (at 20% porosity) of approximately –4.6, –3.5, and –2.5 log mD, respectively. Wireline pressure measurements in the sands are represented by circles.
shale that approximates the net sand ratio of 30% indicated by the well logs. Boundary conditions were set to open flow on the sides of model with no flow conditions at the base of the model. The simulator grid cells above the PL1 horizon are approximately 400 feet thick while the nodes below this horizon are roughly 1200 feet thick. This was done to yield better model resolution in the more recent, overpressured sediments. Calibration of the basin models consisted of adjusting the rock properties until the model outputs matched the available data for well #1, which were defined using the following information: Shale porosity and permeability derived from wireline log analysis using ShaleQuant (Yang and Aplin, 1998, 2004; Yang et al., 2004). Wireline pressure measurements of the reservoir rocks. Bottom hole temperature (BHT) measurements corrected for time since circulation. Nearby surface heat flow measurements from comparable salt environments. The NS model did not require any adjustments to the rock properties to fit the available calibration data. To satisfactorily calibrate the EW model to the available well data, the compaction of the shale–sand mixture required a small modification (Fig. 5a). The compaction and porosity–permeability relationships for the shale–sand mixture used in the models are shown in Fig. 5a and b. Porosity and pressure calibrations for the EW and NS models are shown for well #1 (Fig. 6). A potential problem may result from using pure shale porosities to calibrate a model that uses a shale:sand mixture.
Table 1 Stratigraphic ages used to constrain the burial history in this study. Horizon
Age (Ma)
Pleistocene 1 (P1) Pleistocene 3 (P3) Pliocene (PL1) Pliocene (PL3) Pliocene (PL5) Miocene 1 (M1) Late Miocene 1 (LM1) Late Miocene 2 (LM2) T. Oligocene (T Olig) T. Cretaceous (T Cret)
0.75 1.75 2.76 4.04 5 5.8 8.2 9.1 23.7 65.6
To determine how lithologic uncertainty might affect overpressure, this study designed three EW models with different shale:sand percentages (50:50, 70:30, and 100:0). These three cases used only commonly accepted rock properties (Wygrala and Hantschel, 1996) and no calibration step so permeability, compressibility, and all the other rock properties are related to the ratio of shale to sand. Fig. 7 shows the results of the pressure prediction for the three models at well #1. Not surprisingly for a simple, bulk lithology model, pressure increases approximately linearly with depth and greater amounts of overpressure are generated for the more shale rich, lower permeability systems. However, while there is a relatively small difference between the pressures generated in the 70:30 and 100:0 cases, the comparable permeability difference (approximately 1 log mD) between the 70:30 and 50:50 models yields a pressure difference that is greater by about a factor of 4 (Fig. 7). In other words, knowing or estimating the net-to-gross of a basin to within w25% and knowledge of the sedimentation rates gives some understanding of the approximate pressure state, but more reliable pressure estimates can come from more accurate rock descriptions. 3.2. Geometric effects of overpressure The choice of modeling intersecting 2D sections allows an opportunity to independently assess the magnitudes of the potential error due to poor choice of section. This study has kept sedimentation rates, ages, and lithologies uniform between the NS and EW models. Results shown in Table 2 and Fig. 8a and b indicate that the geometric effect represented by the two sections amounts to about a 1 ppg difference at the common point of well #1. Comparison of Fig. 8c–h suggests that this difference between the predictions of the EW and NS models was significantly larger (up to w5 ppg for a common depth–time) for well #1 at earlier geologic time steps. The two most likely reasons for the inconsistency between models are that the large salt bodies compartmentalize the mini-basins for much of the recent past and the EW section does not accurately portray the true dip of the basin. In a full 3D model, fluid would be allowed to flow north and south as more sediment was deposited down the sand fairway of the central minibasin bounded by the two large salt bodies (e.g. Fig. 8g). This fluid flow would likely be capable of dissipating some of the overpressure. Additionally, Fig. 1b indicates that the majority of the EW section is roughly perpendicular to the primary flow directions, which could possibly inhibit the effective modeling of the dewatering process. These shallower apparent dips result in a greater vertical migration component to the fluid flow, which is the direction of the lowest shale permeability, thus creating additional overpressure that is the direct result of modeling a 3D process in 2D. For these two reasons it appears that the EW model should be considered an upper limit for overpressure. On the other hand, since the NS model does not observe any of the salt bodies that act as barriers to fluid flow, the results of the NS model should likely be
J.R. Allwardt et al. / Marine and Petroleum Geology 26 (2009) 464–473
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Fig. 8. Model results (a–h) showing the pressure evolution of the NS and EW sections for the last 2 Ma. The two sections intersect at well #1 and the green bodies are salt.
considered a lower limit for overpressure. Fig. 6b indicates that the two models bracket the wireline pressure measurements of well #1. This also shows that the NS model more adequately reproduces the pressure than the EW model (Table 2), but a slight modification of the compaction parameters for the EW model (Fig. 5) during calibration brings these pressure predictions into more satisfactory agreement with the data (Table 2). The average error between the predicted pressure and wireline pressure measurements for the NS
and calibrated EW (EW-cal) models are 0.36 and 0.65 ppg, respectively. This suggests that results from a low resolution model that has a reasonable palinspastic structural restoration and a proper calibration to well data should be adequate as inputs in other applications that require knowledge of the local pressure history (e.g. trap containment, porosity preservation, first-pass well planning, etc.). However, these results also suggest that modeling multiple, intersecting sections in structurally complex areas is
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a good methodology for understanding the magnitude of the potential geometric effects for the basin. 3.3. Model resolution effects on pressure prediction Obviously, sedimentary basins do not consist of one lithology that exists uniformly throughout the basin, but how much detail is required to adequately describe a basin for pressure prediction? To investigate this question, we have chosen to build three models with different levels of stratigraphic detail to investigate how model resolution and upscaling affects the quality of the pressure predictions. Fig. 9 illustrates how these three models relate to a 4800 foot (1580 m) section of well #1. The low resolution model is the calibrated EW model described in Section 3.2 where the entire lithologic package above the basal salt is a 70:30 mixture of shale:sand. The depth and thickness of the primary shale layers for the medium and high-resolution cases are derived using a ShaleQuant analysis of wireline logs which calculates the fraction of clay used in this study as well as other clay rock properties (Yang and Aplin, 1998, 2004; Yang et al., 2004). The high-resolution model consists of 14 discreet shale layers at depths between 10,500 and 15,400 feet (3200 and 4700 m) (true vertical depth-subsea) where most of these shales are separated by thin layers. The medium resolution model lumps these shale layers into the two primary seals (Fig. 9). Due to the lack of facies information elsewhere in the basin, we assumed no lateral facies variability. In both the high and medium resolution cases, the shale–sand mixture is still used between the shale layers. In other words, the additional resolution models do not contain sandier layers that would enhance lateral fluid transfer. However, since the shale layers only constitute about a tenth of the 30,000 foot (9000 m) clastic section, the shale:sand ratio among the low-, medium-, and high-resolution cases remains relatively constant (70:30, 75:25, and 75:25, respectively). The properties of the shale–sand mixture for the three models were calibrated independently to match the available porosity (not shown) and pressure (Fig. 10a) data from well #1. Each model required a slightly different porosity–permeability relationship (Fig. 5b). The two primary shale layers (medium resolution) appear to provide adequate resolution to recreate the pressure data (Fig. 10a) and this model actually reproduced the pressure data better than the high-resolution model. This may suggest that in a data-poor environment, too much detail concentrated in one area of the model might have a detrimental effect on the quality of the results (Table 3). Data for wells #2 and #3 were intentionally held out of the calibration step to allow an independent test to assess the quality of the pressure predictions. Well #3 is in the neighboring salt mini-basin and well #2 is a subsalt case similar in style to the prospect area (Fig. 2d). The drilling mud weight for wells #2 and #3 are used as a general proxy for formation pressure (Fig. 10b and c) and generally agree with the predicted pressures. This implies that the simple models presented here are adequately describing the overpressure of the mini-basin. Additionally, these findings show that additional accuracy can be attained through higher resolution models, but the addition of a few of the primary seals may be adequate to approximate formation pressure.
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3.4. Effect of salt weld permeability We built three models to investigate how salt weld permeability affects pressure distributions in the different mini-basins. The first model is the same as the base case example of Section 3.2 where the weld has no effect on modeled permeability (Fig. 11a). The second is meant to approximate the weld as a fault gouge that restricts fluid flow across the weld where the permeability has been reduced by 1.5 log mD relative to the first model (Fig. 11b). The permeabilities are dependent on porosity, but as an example, the permeability of the western salt weld region for the first and second models at 21,000 feet (6400 m) are 4.0 and 5.5 log mD, respectively. The fault gouge of the second model was implemented by creating a new lithology in the salt weld region that consists of all the rock properties of the shale–sand mixture, except with a reduced permeability (Fig. 5b). Also, to only model the weld and
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Table 3 The average and maximum errors for pressure prediction of the low, medium, and high-resolution models for the EW section.
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481 939 0.65 1.06
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Fig. 11. Effect of salt weld permeability on basin pressure. The three models are (a) ignored weld, (b) fault gouge, and (c) remaining salt. Discussion of the specifics of these models can be found in Section 3.3 of the text.
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not the pre-existing salt structures, the salt was switched to the fault gouge lithology at the timing of welding (e.g. 1 Ma according to our reconstructions). The third case (Fig. 11c) assumes that the welds are no flow barriers, perhaps as a result of residual salt remaining in the weld. This was modeled using salt in the weld region with a uniform permeability of 16 log mD. As shown in Fig. 11a, the lack of a permeability barrier in the first model yields no pressure differences between the outer and central sub-basins. However, the plot of the second model shows that the 1.5 log mD permeability reduction creates a significant pressure difference (up to 2 or 3 ppg) between neighboring mini-basins and concentrates pressure in the central basin. The results of the third model indicate that the presence of subseismic salt in the weld region may have large implications for the pressure state of the mini-basins. A partial test of the observations of these models was conducted by comparing the modeling results with seismic velocities for the western and central mini-basins which reflect the pore pressure and lithology of the adjacent mini-basins (Fig. 12a). The seismic velocities of the three mini-basins for the models were calculated using the Eberhardt-Phillips et al. equation (1989). The velocity model and all three basin models show slower seismic velocities
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directly beneath the salt due to overpressure. For areas not directly below salt, the first model calculates that there is little difference in the seismic velocity–depth relationship among mini-basins (Fig. 12b), while the second and third models have slower seismic velocity–depth relationships in the central basin as a product of the increased porosity and overpressure (Fig. 12c and d). The velocity interpretation from the 3D seismic data indicates that the velocities are slower in the central basin than the western basin for nonsubsalt regions (Fig. 12a). This may suggest that the salt weld is at least partially restricting fluid flow, but this observation could also be explained by significant changes in lithology, sediment age, or seismic velocity uncertainties.
4. Conclusions Based on the results presented in this study, we conclude that: 3D basin models are preferred for many situations, but properly oriented 2D models are capable of adequately approximating formation pressure. Also, these results suggest that modeling multiple, intersecting sections in structurally complex areas is a valuable exercise, which allows one to assess the relative importance that geometric effects have on the overpressure predictions. Knowledge of the age, depths, and approximate lithology (bulk shale:sand ratio for the basin) may be sufficient to estimate the overpressure history of a basin adequately enough to use as inputs to first-pass studies that assess containment and reservoir quality uncertainties. Medium resolution models can successfully predict the primary pressure seals and reproduce the pressure measurements in sandstones. Comparison of model predictions with an available seismic velocity interpretation are consistent with, at least partially sealing salt welds, but alternative explanations for this observation also exist.
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Acknowledgements
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The authors would like to thank Olufemi Jokanola for the ShaleQuant analysis, Steve Whitney for the seismic velocity modeling results, Ron Waszcak for the biostratigraphic analysis, and Michael Faust and Kathleen McColgin for business unit support throughout the project. In addition, we would like to thank CGG Geophysical Services for allowing the seismic data to be shown. Finally, the authors would like to thank Gareth Yardley and an anonymous reviewer for helpful comments on the original manuscript.
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Fig. 12. The (a) velocity interpretation based on 3D seismic. Results of the velocity calculations for the (b) ignored weld, (c) fault gouge, and (d) remaining salt models. The horizontal lines are meant to guide the eye to the velocity differences among the different mini-basins.
Diegel, F.A., Karlo, J.F., Schuster, D.C., Shoup, R.C., Tauvers, P.R., 1995. Cenozoic structural evolution and tectono-stratigraphic framework of the northern Gulf coast continental margin. In: Jackson, M.P.A., Roberts, D.G., Snelson, S. (Eds.), Salt Tectonics: a Global Perspective, vol. 65. American Association of Petroleum Geologists Memoir, pp. 109–151. Ge, H., Jackson, M.P.A., Vendeville, B.C., 1997. Kinematics and dynamics of salt tectonics driven by progradation. American Association of Petroleum Geologists Bulletin 81, 398–423. Giles, M.R., Indrelid, S.L., Kusznir, N.J., Loopik, A., Meijerink, J.A., McNutt, J., Dijkstra, P., Heidug, W., Toth, J., Willis, M., Rutten, K., Elsinga, B., Huysse, P., Riviere, P., Burgisser, H., Rowley, E., 1999. Charge and overpressure modeling in the North Sea: multi-dimensional modeling and uncertainty analysis. In: Fleet, A.J., Boldy, S.A.R. (Eds.), Petroleum Geology of Northwest Europe: Proceeding of the 5th Conference, pp. 1313–1324. Handschy, J.W., van den Beukel, P.J., Ge, H., Diegel, F.A., 1998. Salt dome geometries, Gulf of Mexico Shelf. American Association of Petroleum Geologists Annual Convention Extended Abstracts, A269.
J.R. Allwardt et al. / Marine and Petroleum Geology 26 (2009) 464–473 Jackson, M.P.A., Cornelius, R.R., Craig, C.H., Gansser, A., Sto¨cklin, J., Talbot, C.J., 1990. Salt diapir of the Great Kavir, Central Iran. Geological Society of America Memoir 177, 139. McBride, B.C., Rowan, M.G., Weimer, P., 1998. The evolution of allochthonous salt systems, Northern Green Canyon and Ewing Bank (Offshore Louisiana), Northern Gulf of Mexico. American Association of Petroleum Geologists Bulletin 82, 1013–1036. Mello, U.T., Karner, G.D., Anderson, R.N., 1995. Role of salt in restraining the maturation of subsalt source rocks. Marine and Petroleum Geology 12, 697–716. Rowan, M.G., 1995. Structural styles and evolution of allochthonous salt, central Louisiana outer shelf and upper slope. In: Jackson, M.P.A., Roberts, D.G., Snelson, S. (Eds.), Salt Tectonics: a Global Perspective, vol. 65. American Association of Petroleum Geologists Memoir, pp. 199–228. Schultz-Ela, D.D., 1992. Restoration of cross-sections to constrain deformation processes of extensional terranes. Marine and Petroleum Geology 9, 372–388. Schuster, D.C., 1995. Deformation of allochthonous salt and evolution of related saltstructural systems, eastern Louisiana Gulf Coast. In: Jackson, M.P.A., Roberts, D.G., Snelson, S. (Eds.), Salt Tectonics: a Global Perspective, vol. 65. American Association of Petroleum Geologists Memoir, pp. 177–198. Throndsen, T., Wangen, M., 1998. A comparison between 1-D, 2-D and 3-D basin simulation of compaction, water flow and temperature evolution. In:
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Duppenbecker, S.J., Iliffe, J.E. (Eds.), Basin Modeling: Practice and Progress, vol. 141. Geologic Society, London, pp. 109–116. Special Publications. Worrall, D.M., Snelson, S., 1989. Evolution of northern Gulf of Mexico, with emphasis on Cenozoic growth faulting and role of salt. In: Bally, A.W., Palmer, A.W. (Eds.), The Geology of North America–an Overview. Geological Society of America, pp. 97–138. Wygrala, B., Hantschel, T., 1996. IES PetroMod Release 4.0, PetroGen/PetroFlow – Theoretical Aspects. Yang, Y., Aplin, A.C., 1998. Influence of lithology and effective stress on the pore size distribution and modeled permeability of some mudstones from the Norwegian margin. Marine and Petroleum Geology 15, 163–175. Yang, Y., Aplin, A.C., 2004. Definition and practical application of mudstone porosity–effective stress relationships. Petroleum Geoscience 10, 153–162. Yang, Y., Aplin, A.C., Larter, S.R., 2004. Quantitative assessment of mudstone lithology using geophysical wireline logs and artificial neural networks. Petroleum Geoscience 10, 141–151. Yardley, G.S., Swarbrick, R.E., 2000. Lateral transfer: a source of additional pressure? Marine and Petroleum Geology 17, 523–537. Yardley, G., Couples, G., Aplin, A., Yang, Y., Swarbrick, R.E., 2004. Lithology-based pore pressure prediction success: example from a Gulf of Mexico mini-basin. AAPG-SEPM Convention Proceedings A152, 2004. Yu, Z., Lerche, I., Lowrie, A., 1992. Thermal impact of salt: simulation of thermal anomalies in the Gulf of Mexico. Pure and Applied Geophysics 138, 181–192.
Contents lists available at ScienceDirect
Marine and Petroleum Geology journal homepage: www.elsevier.com/locate/marpetgeo
2D modeling of overpressure in a salt withdrawal basin, Gulf of Mexico, USA Jeffrey R. Allwardt*, G. Eric Michael, Chuck R. Shearer, Philip D. Heppard, Hongxing Ge ConocoPhillips Company, 600 North Dairy Ashford, Houston, TX 77079-1175, USA
a r t i c l e i n f o
a b s t r a c t
Article history: Received 15 September 2007 Received in revised form 1 April 2008 Accepted 6 January 2009 Available online 15 January 2009
This study demonstrates the utilization of 2D basin models to address overpressure development due to compaction disequilibrium in supra-allochthonous salt mini-basins with very high sedimentation rates in the Gulf of Mexico. By properly selecting 2D line sections with moderate stratigraphic resolution, it is possible to predict timing of overpressure development and approximate present-day overpressure distributions in the mini-basin. This study shows that even low resolution models with approximate information on the net-to-gross (sand:shale ratio) can average 0.4 ppg with a maximum error of 1.0 ppg relative to pressure measurements in sandstones. The models based on age, depth, approximate lithology and an interpretation of complicated salt movement are adequate to evaluate pressure to address issues around trap containment and may be used for preliminary well planning. This study tested the results of overpressure prediction utilizing different stratigraphic resolutions and shows the sensitivity of overpressure modeling to 2D line selection. Also, three models were built to investigate how the permeability of salt welds affects overpressure development in an adjacent salt mini-basin. These results indicate that even a salt weld permeability reduction of 1.5 log mD results in a pressure difference between neighboring mini-basins. Additionally, these models qualitatively reproduced the seismic velocity volume which is supporting evidence that the salt welds in this mini-basin are at least partially sealing. Ó 2009 Elsevier Ltd. All rights reserved.
Keywords: Basin modeling Pore pressure Gulf of Mexico Pressure prediction Salt reconstruction
1. Introduction Pressure prediction is critical for hydrocarbon trap evaluation and well planning. Basin modeling can be used to forward model pore pressure and provides information on the timing of overpressure development (Giles et al., 1999; Throndsen and Wangen, 1998; Yardley and Swarbrick, 2000; Yardley et al., 2004). Models are typically calibrated to pressure measurements in sandstones and increasingly other well information such as log data, mud weights, seismic velocities and velocity based pore pressure calculations. Processes that result in overpressure that are commonly modeled are compaction disequilibrium, lateral pressure transfer, hydrocarbon generation, and oil to gas cracking. Of these processes, only compaction disequilibrium is addressed here. The primary factors affecting this process are sedimentation rate, shale permeability evolution, sediment compaction, and basin geometry. Generally, basin modeling for pore pressure prediction is used to investigate past and present reservoir quality, hydrocarbon migration and containment (e.g. shale and fault seal behavior) and * Corresponding author. Tel.: þ1 713 624 9448; fax: þ1 713 624 3722. E-mail address: [email protected] (J.R. Allwardt). 0264-8172/$ – see front matter Ó 2009 Elsevier Ltd. All rights reserved. doi:10.1016/j.marpetgeo.2009.01.009
porosity evolution for thermal and charge modeling. Additionally, it can be useful in drilling programs to predict overpressure where seismic based methods or projections from well information may be difficult such as subsalt areas or uplifted terrains. This study utilizes 2D basin modeling to assess pore pressure distribution and evolution along two intersecting lines. These sections transect three mini-basins with allochthonous salt canopy bodies and are separated by salt welds in the offshore Gulf of Mexico. The mini-basins received up to 25,000 feet (7600 m) of sediments in the last 2.75 million years and are associated with and affected by mobile salt which has moved into shallow diapirs. The modeling is aimed at assessing the relative importance of basin geometry, lithology, model resolution, and the sealing effectiveness of salt welds on pore pressure prediction. Three-dimensional basin models have been shown to be more robust than 1D and 2D models for pore pressure prediction since they can more accurately portray the 3D nature of fluid flow (Giles et al., 1999; Throndsen and Wangen, 1998; Yardley et al., 2004). This study used two intersecting 2D basin models due to the lack of knowledge about past salt movements and the time necessary to properly constrain a palinspastic 3D reconstruction of a basin that includes significant salt movement.
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2. Methodology 2.1. Selection of model sections
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Fig. 1a shows the depth to the top of the salt in the study area. The canopy consists of three allochthonous salt sheets that are mostly welded (Fig. 2a–d). The western salt sheet is a salt-stock sheet (Jackson et al., 1990; Rowan, 1995). The central sheet is a counterregional salt system (Diegel et al., 1995; Schuster, 1995), and the eastern sheet extends beyond the study area and thus cannot be classified. Three mini-basins developed in the area corresponding to the three salt sheets. Shallow edge domes (Handschy et al., 1998) formed at the eastern flank of the western sheet and at the western flank of the eastern sheet (Figs. 1 and 2d). A pronounced expulsion salt rollover (Ge et al., 1997) formed as a part of the counterregional system in the central mini-basin (Fig. 2c), where sedimentary strata predominantly dip to the south shown in depth sections as well as in the depth structure map of the top Pleistocene horizon (Fig. 1b). Eastern and western flanks of the central mini-basin are buried below the edge domes (Fig. 2d). Mini-basins are separated from each other by lateral salt welds. Rapid sedimentation occurred in the mini-basins in response to the withdrawal of the allochthonous salt in the recent past, where, up to 25,000 feet (7600 m) of sediments have accumulated during the last 2.8 Ma. Such a rapid and thick
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Fig. 1. Depth to (a) top salt in the study area and depth to the (b) top Pleistocene surface. Darker shades are structurally deep and lighter shades represent structural highs. The green line swamps in b represent the flow lines that reveal the actual dip of the system. Locations of the sections and wells are shown. The red curve represents the location of the primary salt weld of interest.
sedimentation has likely led to the extreme overpressures in the system and predicting the magnitude and history of this overpressure is the primary focus of our study. Two sections have been selected for our 2D basin models. The north–south (NS) section bisects the central mini-basin and was chosen in an attempt to accurately portray the true dip of the sediments (Fig. 1b). The east–west (EW) section intersects all three mini-basins and passes through wells 1–3 as well as the prospect region (Figs. 1 and 2). The NS model passes through well #1, where it also intersects the EW model. The purpose of modeling intersecting lines is to assess the effect of basin geometry and the magnitude of the differences created by not having a true 3D geometry. Fig. 2a–d shows the seismic lines for the two crosssections. The prospect lies against one of these welds where the
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overlying sediment is in the western mini-basin and the prospect is in the central mini-basin (Fig. 2d). The prospective trap in the area is a three-way closure where the salt weld is required to seal. The weld is a critical element to the prospect. 2.2. Reconstruction of salt geometry through time In order to appropriately model the pressure evolution, the basin geometry, especially the salt kinematics, needs to be reconstructed. Salt movement and the resulting large salt bodies play
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Fig. 4. The present geometry of the two sections where the labels correspond to ages determined from a biostratigraphic analysis of well #1 (Table 1). The cross-hatched pattern is the salt.
a primary role in the geothermic history of the basins and maturation of oil and gas source rocks in the region (Mello et al., 1995; Yu et al., 1992). Because of the paucity of large faults, we structurally restored the model sections by sequentially backstripping the topmost layer and unfolding successive sedimentary strata with vertical shear. The base of the allochthonous salt remained unchanged during the restoration of the suprasalt mini-basin strata. Any space created during the restoration was then filled by salt (Schultz-Ela, 1992; Worrall and Snelson, 1989). During the restorations, layer thickness was adjusted for decompaction by using commonly accepted compaction curves. Paleobathymetry was reconstructed with biostratigraphic data and isostacy was not corrected during our restoration. The intersecting dip and strike lines were used to cross-check the salt thicknesses at different stages. This method may be considered to produce minimum salt thicknesses similar to those by Rowan (1995) and McBride et al. (1998). Both NS and EW sections were restored (Figs. 3 and 4). Only the structural evolution of the east–west section, which cuts through three mini-basins above the canopy, is discussed in the following paragraph (Fig. 3). The EW section consists of three allochthonous salt bodies (Fig. 2b and d). Section reconstruction suggests that the salt canopy formed around 11 Ma by coalescing three allochthonous salt sheets. The top of salt was either exposed at water bottom as a salt glacier or covered by a veneer of hemipelagic sediments. By around 9.1 Ma, the central salt sheet was partially loaded by sediments on the flanks, whereas the western salt sheet and middle of the central sheet were still emerged at the water bottom (Fig. 3e). By around 4.0 Ma, the central salt sheet is completely covered by sediments at this location. Overall, the sheet thinned and a residual salt body was trapped in the middle of the basin (Fig. 3d). The western and eastern salt sheets were greatly inflated during this time, probably through feeders that are outside of the section. They expanded toward the center of the section and overlie the margins of the central minibasin. By around 2.8 Ma, more salt was expelled out of the section by sedimentary loading in the central mini-basin, where salt welds began to form on the flanks (Fig. 3c). Sediments also began to load the western and eastern salt sheets to form mini-basins, probably
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due to diminishing salt source from the feeders. Only the flanks of the sheets may remain open at the water bottom and continued sedimentation from 2.8 Ma to 1.8 Ma further enhanced the minibasins above the western and eastern salt sheets (Fig. 3b). Edge domes from these basins were well developed during this time. The salt weld at the base of the central mini-basin was well formed by 1.8 Ma. From 1.8 Ma to the present time, salt was further removed from the current section, probably by salt expulsion (Ge et al., 1997), salt dissolution, and salt feeding to the shallower salt systems.
Extensive salt welds formed across the section (Fig. 3a). The edge domes are now buried below the sediments that are being cut by the many shallow faults (Figs. 2d and 4). 2.3. Model specifics and calibration The 2D basin model simulations have been performed using the PetroMod 9.0 software package, where the 2D sections were selected from a 3D seismic volume. As an additional calibration tool, the time dependence of salt movement and the resulting structures (Fig. 3) were interpreted using the ‘‘paleothickness’’ tool available in PetroMod. The rock properties of the initial model used commonly accepted values for the basement, Jurassic–Cretaceous limestone, salt, and clastics (Wygrala and Hantschel, 1996). The base case models used rock properties for a mixture of sand and
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shale that approximates the net sand ratio of 30% indicated by the well logs. Boundary conditions were set to open flow on the sides of model with no flow conditions at the base of the model. The simulator grid cells above the PL1 horizon are approximately 400 feet thick while the nodes below this horizon are roughly 1200 feet thick. This was done to yield better model resolution in the more recent, overpressured sediments. Calibration of the basin models consisted of adjusting the rock properties until the model outputs matched the available data for well #1, which were defined using the following information: Shale porosity and permeability derived from wireline log analysis using ShaleQuant (Yang and Aplin, 1998, 2004; Yang et al., 2004). Wireline pressure measurements of the reservoir rocks. Bottom hole temperature (BHT) measurements corrected for time since circulation. Nearby surface heat flow measurements from comparable salt environments. The NS model did not require any adjustments to the rock properties to fit the available calibration data. To satisfactorily calibrate the EW model to the available well data, the compaction of the shale–sand mixture required a small modification (Fig. 5a). The compaction and porosity–permeability relationships for the shale–sand mixture used in the models are shown in Fig. 5a and b. Porosity and pressure calibrations for the EW and NS models are shown for well #1 (Fig. 6). A potential problem may result from using pure shale porosities to calibrate a model that uses a shale:sand mixture.
Table 1 Stratigraphic ages used to constrain the burial history in this study. Horizon
Age (Ma)
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0.75 1.75 2.76 4.04 5 5.8 8.2 9.1 23.7 65.6
To determine how lithologic uncertainty might affect overpressure, this study designed three EW models with different shale:sand percentages (50:50, 70:30, and 100:0). These three cases used only commonly accepted rock properties (Wygrala and Hantschel, 1996) and no calibration step so permeability, compressibility, and all the other rock properties are related to the ratio of shale to sand. Fig. 7 shows the results of the pressure prediction for the three models at well #1. Not surprisingly for a simple, bulk lithology model, pressure increases approximately linearly with depth and greater amounts of overpressure are generated for the more shale rich, lower permeability systems. However, while there is a relatively small difference between the pressures generated in the 70:30 and 100:0 cases, the comparable permeability difference (approximately 1 log mD) between the 70:30 and 50:50 models yields a pressure difference that is greater by about a factor of 4 (Fig. 7). In other words, knowing or estimating the net-to-gross of a basin to within w25% and knowledge of the sedimentation rates gives some understanding of the approximate pressure state, but more reliable pressure estimates can come from more accurate rock descriptions. 3.2. Geometric effects of overpressure The choice of modeling intersecting 2D sections allows an opportunity to independently assess the magnitudes of the potential error due to poor choice of section. This study has kept sedimentation rates, ages, and lithologies uniform between the NS and EW models. Results shown in Table 2 and Fig. 8a and b indicate that the geometric effect represented by the two sections amounts to about a 1 ppg difference at the common point of well #1. Comparison of Fig. 8c–h suggests that this difference between the predictions of the EW and NS models was significantly larger (up to w5 ppg for a common depth–time) for well #1 at earlier geologic time steps. The two most likely reasons for the inconsistency between models are that the large salt bodies compartmentalize the mini-basins for much of the recent past and the EW section does not accurately portray the true dip of the basin. In a full 3D model, fluid would be allowed to flow north and south as more sediment was deposited down the sand fairway of the central minibasin bounded by the two large salt bodies (e.g. Fig. 8g). This fluid flow would likely be capable of dissipating some of the overpressure. Additionally, Fig. 1b indicates that the majority of the EW section is roughly perpendicular to the primary flow directions, which could possibly inhibit the effective modeling of the dewatering process. These shallower apparent dips result in a greater vertical migration component to the fluid flow, which is the direction of the lowest shale permeability, thus creating additional overpressure that is the direct result of modeling a 3D process in 2D. For these two reasons it appears that the EW model should be considered an upper limit for overpressure. On the other hand, since the NS model does not observe any of the salt bodies that act as barriers to fluid flow, the results of the NS model should likely be
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Fig. 8. Model results (a–h) showing the pressure evolution of the NS and EW sections for the last 2 Ma. The two sections intersect at well #1 and the green bodies are salt.
considered a lower limit for overpressure. Fig. 6b indicates that the two models bracket the wireline pressure measurements of well #1. This also shows that the NS model more adequately reproduces the pressure than the EW model (Table 2), but a slight modification of the compaction parameters for the EW model (Fig. 5) during calibration brings these pressure predictions into more satisfactory agreement with the data (Table 2). The average error between the predicted pressure and wireline pressure measurements for the NS
and calibrated EW (EW-cal) models are 0.36 and 0.65 ppg, respectively. This suggests that results from a low resolution model that has a reasonable palinspastic structural restoration and a proper calibration to well data should be adequate as inputs in other applications that require knowledge of the local pressure history (e.g. trap containment, porosity preservation, first-pass well planning, etc.). However, these results also suggest that modeling multiple, intersecting sections in structurally complex areas is
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Fig. 10. Pressure–depth plots for the three resolution models. The results at (a) well #1 display the low (LR), medium (MR) and high (HR) resolution models with the RFT measurements (circles). Also, the log inset indicates where the resolution changes have been added to the model. Pressure predictions for wells (b) #2 and (c) #3 contain results for the same three models, but have been converted to ppg to better accommodate the mud weight data (pluses). The brown circles for well #2 represent MDT pressure measurements.
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a good methodology for understanding the magnitude of the potential geometric effects for the basin. 3.3. Model resolution effects on pressure prediction Obviously, sedimentary basins do not consist of one lithology that exists uniformly throughout the basin, but how much detail is required to adequately describe a basin for pressure prediction? To investigate this question, we have chosen to build three models with different levels of stratigraphic detail to investigate how model resolution and upscaling affects the quality of the pressure predictions. Fig. 9 illustrates how these three models relate to a 4800 foot (1580 m) section of well #1. The low resolution model is the calibrated EW model described in Section 3.2 where the entire lithologic package above the basal salt is a 70:30 mixture of shale:sand. The depth and thickness of the primary shale layers for the medium and high-resolution cases are derived using a ShaleQuant analysis of wireline logs which calculates the fraction of clay used in this study as well as other clay rock properties (Yang and Aplin, 1998, 2004; Yang et al., 2004). The high-resolution model consists of 14 discreet shale layers at depths between 10,500 and 15,400 feet (3200 and 4700 m) (true vertical depth-subsea) where most of these shales are separated by thin layers. The medium resolution model lumps these shale layers into the two primary seals (Fig. 9). Due to the lack of facies information elsewhere in the basin, we assumed no lateral facies variability. In both the high and medium resolution cases, the shale–sand mixture is still used between the shale layers. In other words, the additional resolution models do not contain sandier layers that would enhance lateral fluid transfer. However, since the shale layers only constitute about a tenth of the 30,000 foot (9000 m) clastic section, the shale:sand ratio among the low-, medium-, and high-resolution cases remains relatively constant (70:30, 75:25, and 75:25, respectively). The properties of the shale–sand mixture for the three models were calibrated independently to match the available porosity (not shown) and pressure (Fig. 10a) data from well #1. Each model required a slightly different porosity–permeability relationship (Fig. 5b). The two primary shale layers (medium resolution) appear to provide adequate resolution to recreate the pressure data (Fig. 10a) and this model actually reproduced the pressure data better than the high-resolution model. This may suggest that in a data-poor environment, too much detail concentrated in one area of the model might have a detrimental effect on the quality of the results (Table 3). Data for wells #2 and #3 were intentionally held out of the calibration step to allow an independent test to assess the quality of the pressure predictions. Well #3 is in the neighboring salt mini-basin and well #2 is a subsalt case similar in style to the prospect area (Fig. 2d). The drilling mud weight for wells #2 and #3 are used as a general proxy for formation pressure (Fig. 10b and c) and generally agree with the predicted pressures. This implies that the simple models presented here are adequately describing the overpressure of the mini-basin. Additionally, these findings show that additional accuracy can be attained through higher resolution models, but the addition of a few of the primary seals may be adequate to approximate formation pressure.
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3.4. Effect of salt weld permeability We built three models to investigate how salt weld permeability affects pressure distributions in the different mini-basins. The first model is the same as the base case example of Section 3.2 where the weld has no effect on modeled permeability (Fig. 11a). The second is meant to approximate the weld as a fault gouge that restricts fluid flow across the weld where the permeability has been reduced by 1.5 log mD relative to the first model (Fig. 11b). The permeabilities are dependent on porosity, but as an example, the permeability of the western salt weld region for the first and second models at 21,000 feet (6400 m) are 4.0 and 5.5 log mD, respectively. The fault gouge of the second model was implemented by creating a new lithology in the salt weld region that consists of all the rock properties of the shale–sand mixture, except with a reduced permeability (Fig. 5b). Also, to only model the weld and
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Fig. 11. Effect of salt weld permeability on basin pressure. The three models are (a) ignored weld, (b) fault gouge, and (c) remaining salt. Discussion of the specifics of these models can be found in Section 3.3 of the text.
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not the pre-existing salt structures, the salt was switched to the fault gouge lithology at the timing of welding (e.g. 1 Ma according to our reconstructions). The third case (Fig. 11c) assumes that the welds are no flow barriers, perhaps as a result of residual salt remaining in the weld. This was modeled using salt in the weld region with a uniform permeability of 16 log mD. As shown in Fig. 11a, the lack of a permeability barrier in the first model yields no pressure differences between the outer and central sub-basins. However, the plot of the second model shows that the 1.5 log mD permeability reduction creates a significant pressure difference (up to 2 or 3 ppg) between neighboring mini-basins and concentrates pressure in the central basin. The results of the third model indicate that the presence of subseismic salt in the weld region may have large implications for the pressure state of the mini-basins. A partial test of the observations of these models was conducted by comparing the modeling results with seismic velocities for the western and central mini-basins which reflect the pore pressure and lithology of the adjacent mini-basins (Fig. 12a). The seismic velocities of the three mini-basins for the models were calculated using the Eberhardt-Phillips et al. equation (1989). The velocity model and all three basin models show slower seismic velocities
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directly beneath the salt due to overpressure. For areas not directly below salt, the first model calculates that there is little difference in the seismic velocity–depth relationship among mini-basins (Fig. 12b), while the second and third models have slower seismic velocity–depth relationships in the central basin as a product of the increased porosity and overpressure (Fig. 12c and d). The velocity interpretation from the 3D seismic data indicates that the velocities are slower in the central basin than the western basin for nonsubsalt regions (Fig. 12a). This may suggest that the salt weld is at least partially restricting fluid flow, but this observation could also be explained by significant changes in lithology, sediment age, or seismic velocity uncertainties.
4. Conclusions Based on the results presented in this study, we conclude that: 3D basin models are preferred for many situations, but properly oriented 2D models are capable of adequately approximating formation pressure. Also, these results suggest that modeling multiple, intersecting sections in structurally complex areas is a valuable exercise, which allows one to assess the relative importance that geometric effects have on the overpressure predictions. Knowledge of the age, depths, and approximate lithology (bulk shale:sand ratio for the basin) may be sufficient to estimate the overpressure history of a basin adequately enough to use as inputs to first-pass studies that assess containment and reservoir quality uncertainties. Medium resolution models can successfully predict the primary pressure seals and reproduce the pressure measurements in sandstones. Comparison of model predictions with an available seismic velocity interpretation are consistent with, at least partially sealing salt welds, but alternative explanations for this observation also exist.
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The authors would like to thank Olufemi Jokanola for the ShaleQuant analysis, Steve Whitney for the seismic velocity modeling results, Ron Waszcak for the biostratigraphic analysis, and Michael Faust and Kathleen McColgin for business unit support throughout the project. In addition, we would like to thank CGG Geophysical Services for allowing the seismic data to be shown. Finally, the authors would like to thank Gareth Yardley and an anonymous reviewer for helpful comments on the original manuscript.
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Fig. 12. The (a) velocity interpretation based on 3D seismic. Results of the velocity calculations for the (b) ignored weld, (c) fault gouge, and (d) remaining salt models. The horizontal lines are meant to guide the eye to the velocity differences among the different mini-basins.
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