IPTC 16849

Pore Pressure Prediction in Unconventional Resources B.A. Couzens-Schultz, Shell International Exploration and Production; A. Axon, Shell China Exploration and Production Co. Ltd.; K. Azbel, K.S. Hansen, M. Haugland, R. Sarker, Shell International Exploration and Production; B. Tichelaar, Shell Egypt N.V.; J.B. Wieseneck, R. Wilhelm, Shell Exploration and Production; J. Zhang, Shell Exploration and Production; Z. Zhang, Shell International Ltd

Copyright 2013, International Petroleum Technology Conference This paper was prepared for presentation at the International Petroleum Technology Conference held in Beijing, China, 26–28 March 2013. This paper was selected for presentation by an IPTC Programme Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the International Petroleum Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the International Petroleum Technology Conference, its officers, or members. Papers presented at IPTC are subject to publication review by Sponsor Society Committees of IPTC. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the International Petroleum Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, IPTC, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax +1-972-952-9435

Abstract Understanding pore pressure prediction in unconventional plays is important for executing a safe drilling strategy and for accurate production modeling. Experience from several unconventional plays highlights key aspects of pore pressure prediction work that are different from conventional exploration settings. In conventional exploration, the most common source of overpressure is disequilibrium compaction, where porosity is preserved in mudrocks as pore fluids take on additional overburden load. Traditional petrophysical methods use resistivity, sonic and density data to measure porosity and associate it with vertical effective stress (VES), which is overburden minus pore pressure. In unconventional plays, secondary pressure mechanisms and uplift require other methods because of two influences on pore pressure: (1) hydrocarbon generation and (2) variations in burial and uplift history. Both of these situations mean that the relationships between vertical effective stress (VES), velocity, density and resistivity will follow unloading paths, not compaction trends. The unloading paths vary depending on the amount of hydrocarbon generated and the amount of uplift. In organic-rich sections, an additional complication arises because pore pressure cannot be de-convolved from total organic carbon (TOC) and gas effects on shale compressional velocity and resistivity. In conventional settings, fluid gradients and contacts are used to translate measured pressure data from one location to another. In unconventional tight reservoirs, the fluids are not connected and this method will not work. Pressure data must be inferred from drilling event and diagnostic fracture injection test interpretations, and a different way to translate data between locations is required. The majority of pressure data in unconventional reservoirs shows that often, the way to translate pressure information from one location to another in the same tight rocks is to use a constant VES. This method combined with understanding variations in uplift history and hydrocarbon generation has been used to successfully predict pressure ranges in multiple unconventional plays. Introduction Unconventional resources plays in shale and tight rocks have become a substantial resource in North America. They are now rapidly being explored and developed outside the United States and Canada in a trend that will likely continue to grow. To economically develop these plays, wells must be drilled as cost effective as possible. To produce from these plays and forecast production, the mechanical properties of the rocks and their stress conditions need to be understood to best stimulate and complete the wells. Pore pressure prediction is integral to both of these activities. In many ways pore pressure prediction for resource plays is similar to that for conventional plays, however, common assumptions and techniques that are used in conventional settings generally are not applicable to resource plays. In most conventional plays, pore pressure prediction relies on the concept that overpressure development arrests compaction in low permeability rocks and thus preserves porosity (Figure 1). This mechanism is known as disequilibrium compaction (Osborne and Swarbrick, 1997; Swarbrick et al., 2002). Because porosity is preserved during overpressure development by disequilibrium compaction, rock properties that reflect porosity, such as resistivity, sonic or seismic velocity can be used to predict overpressures. The most common methods in industry, Eaton (1975) and Bowers (1995), rely on this connection between rock properties, porosity and overpressure. These methods assume that vertical effective stress (VES), which is the difference between the overburden pressure and the pore pressure, controls the compaction state and hence the porosity. The second most common mechanism in conventional plays is lateral transfer of pore pressure from basinal to crestal locations in sands or other permeable rocks (Yardley and Swarbrick, 2000). Other pressure mechanisms besides disequilibrium

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compaction may be present in conventional plays and they may have complex burial and pore pressure histories, but these issues are less common. In contrast, for unconventional resource plays, disequilibrium compaction and lateral transfer of pressures may occur, but the dominating factors in pore pressure distribution are related to other pressure generation mechanisms and to complex burial histories. Most commonly, pore pressure related to hydrocarbon generation needs to be considered. In these cases, pore pressure is increased after the rock is buried and compacted. Therefore, the assumption of a connection between porosity and overpressure is violated. As pore pressures increase due to hydrocarbon generation, the rocks do not uncompact. Instead, the porosity and density remain approximately constant (e.g. Hunt et al., 1994). This condition is commonly known as unloading or late geopressures. Since most resource plays are onshore and in basins with more complex tectonic and uplift histories, it is also common that the rocks are not at their maximum burial stress state. Overburden has been removed during uplift and erosion. In this situation, similar to the unloading or late geopressures described above, the rock does not uncompact; porosities for a given stress state are thus lower than expected. This condition is also considered unloading. In unloading situations, normal compaction trend methods such as Eaton (1975) cannot be used to predict pressures because the assumption that VES relates to porosity has been broken. Unloading does however affect velocity data because the reduced stress across grain boundaries and microfractures causes the rock to be acoustically slower than it would be if it was not unloaded. This effect is used by Bowers (1995) to relate acoustic velocity to VES in unloading conditions, but the methods can be complex if the type and amount of unloading is variable across a resource play.

Figure 1. Relationships between depth, porosity, vertical effective stress, pore pressure, resistivity and sonic for mudrocks (silts, shales and claystones) that develop and retain overpressures by disequilibrium compaction. D = depth in rock column, Ø = porosity, = vertical effective stress, P = pressure, Res = resistivity, DT = compressional sonic. Sources of Pressure Data In conventional plays, we directly measure pore pressure in permeable reservoirs with wireline tools such as MDT and RCI. In these tools, packers isolate the probe from the well bore fluids. Formation fluids are then collected in small chambers. A pressure gauge records the inflow into two pre-test chambers and the subsequent pressure build-up, which is used to determine the formation pore pressure. In unconventional resource plays, we cannot directly measure pressures with these tools because the rocks are too impermeable to flow. Instead, pore pressures are estimated via a number of means (Figure 2). The first line of data comes from drilling events. The best of these data include kicks, influxes and connection or pumps-off gas events. For kicks and influxes, pore pressure is constrained using the shut-in standpipe pressure and mud density in the drillpipe. The equivalent circulating and static mud densities are used to constrain the pore pressure where pumps-off or connection gas is observed. After drilling, for completions, a diagnostic fracture injection test (DFIT) may be performed. The test is a small volume, low rate injection test followed by an extended shut-in period. The pressure decline curve during shut-in is extrapolated to estimate pore pressure. Data quality depends on shut-in time and the rock permeability. Similarly, a pressure build-up curve from a production test can be used to estimate pore pressure. Pressure Prediction Approach in Resource Plays Our approach to pressure prediction in unconventional resource plays has four main components: (1) constructing a pore pressure database, (2) building petrophysical relationships between pore pressure and resistivity, shear and compressional velocity, (3) relating observed pore pressures and pore pressures predicted from log data to the geology by examining stratigraphic relationships, variations in burial history, charge timing and organic content variations, (4) translating known pressure data and trends predicted from log data at existing wells to new drillsite locations using the geologic observations.

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Figure 2. Pressure data sources in an unconventional resource play. Red and orange squares represent observed influxes or kicks. Green circles are from connection and pumps–off gas peak analysis. Black circles are from DFIT tests. Blue triangles are from production tests. The blue line is the hydrostatic pore pressure. The green line is the overburden pressure. Various fits to the data are shown with the trend lines, which are discussed in the text. First, we construct a pressure database for the play or area of interest (e.g. Figure 2). This is often the most time consuming part of the effort. It requires going back to daily drilling reports and extracting constraints on the pore pressure from the drilling history and mudlog data. Mudweight alone cannot be reliably used as an indicator of pore pressure in resource plays. Because the rocks are tight, low permeability and well indurated, they can be drilled significantly underbalanced without well control incident. Furthermore, common practice is to drill resource plays underbalanced to increase the rate of penetration. However, drilling operations and events provide a wealth of indirect information on pore pressure when combined with the mudweight data (Fertl et al., 2002). The best indication of pore pressure comes from kicks, where a zone of permeability was penetrated and an influx occurred. While these events are not desired, they occasionally occur during underbalanced drilling. The shut-in standpipe or casing pressures are used in conjunction with the mudweight data to determine the downhole formation pore pressure where the kick occurred. Connection gas and pumps-off gas peaks can also be used to determine if the well is being drilled near balance or significantly underbalanced. Other indicators of underbalance, such as splintery cavings, tight spots, etc. can be incorporated. The data from drilling are then combined with DFIT data or production test data. Systematic variations are often seen between the pressure data types. Kicks and connection gases often indicate a lower pore pressure (solid black or gray trend lines in Figure 2) than the DFIT and production test data (dashed black line in Figure 2), but the overall trend of the pressure data is consistent no matter the data type. Though less common, gas or oil gradients reflecting the buoyancy effects of HC columns may be present locally if a connected fracture system or other permeable pathway is present (red line in Figure 2). Once a pressure database is built, we then look for a petrophysical signature to overpressure using log data. During this step, we may identify if disequilibrium compaction is important, but in general we are attempting to construct an unloading trend (Bowers, 1995), which can then be used to fill in the pressure profile between discrete pressure data points collected above.

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If possible, we examine the density, resistivity, compressional sonic and shear sonic for a relationship to overpressure. However, the use of sonic log data or seismic velocity data to determine overpressures is complicated in unconventional resource plays. Compressional velocity data generally do not show a good relationship with VES, especially in the gas-prone target stratigraphy (Figure 3). The stratigraphy in a shale-gas play for instance tends to be slower than shales outside of the play (e.g. red and pink data on Figure 3). However, when shear velocity data is available, a good relationship can be constructed that includes both shales in the shale-gas play and outside of it (Figure 3). This is because the acoustic shear velocity is insensitive to fluids such as gas. The shear velocity trend shown in Figure 3 is an unloading trend, which is much less sensitive to changes in VES than a normal compaction trend would be, but it can still be used to make an estimate of the pore pressure profile in a well (Figure 4). Generally, density trends are flat and cannot be used because density does not respond much to pressure changes due to unloading mechanisms such as hydrocarbon generation or uplift and removal of overburden.

Figure 3. Compressional velocity and Shear velocity vs. vertical effective stress (VES) colored by stratigraphy. Next, we examine the pore pressure data and log-base pressure estimations or pore pressure for relationships to geology such as changes across formation boundaries, variations in uplift, variations in the timing of HC generation, variations in organic content, etc. Understanding the geologic context is critical to getting the pore pressure prediction correct. In areas where uplift and erosion have occurred, data will lie on different unloading trends if the amount of missing overburden is variable. One way to compare data across a region is to plot it with the VES at maximum burial (Figure 5). The assumption is that since the rocks are very impermeable, pore pressure will remain nearly constant during uplift, unless fracture gradient is reached. A simple cross check is to plot a map of erosion and overlay the pore pressure gradient or the VES on top of it to identify a spatial correlation. If erosion is variable and post-dates pressure generation, then areas with more erosion will see lower VES (higher pore pressure gradients). If data still sits off trend possible explanations include (a) a second pressure mechanism not present, (b) variable pressure due to source richness, (c) incorrect amount of missing overburden, or (d) the rocks have leaked off pressures as they were uplifted. Permeable zones may strongly influence the pore pressure patterns (Yardley and Swarbrick, 2000). As in conventional settings, a permeable zone such as a reservoir is a fluid pathway and the pressures in that zone should sit on a single fluid gradient, which is typically a brine gradient. Under such conditions, the overpressure is constant in the permeable zone. Dynamic fluid flow over large areas will cause slight lateral overpressure gradients (e.g. Tozer and Borthwick, 2010).

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Figure 4. Pore pressure profile predicted from shear velocity data at a well. The tracks from left to right show: Gamma-ray; volume fraction of shale (brown), carbonate (blue) and sand (yellow); Compressional velocity (blue) and shale compressional velocity calculated from shale shear velocity (black); Shear velocity (light blue) and shale shear velocity (black); Pressure profile for hydrostatic (light blue), pore pressure from shear velocity (blue), lithostatic pressure (green) and kick pressures (red and orange squares); and Pressure gradient colored as the Pressure profile with the drilling mudweight (magenta).

Figure 5. Data for shale plotted as compressional velocity vs present-day VES and paleo-VES. Paleo-VES represents the VES at maximum burial based on information about the amount of erosion at each location. All the data except one well (green) appear to follow a compaction trend similar to the regional compaction trend (green line) when plotted at their expected maximum burial.

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The distribution of permeable sands and silt layers within a region will strongly influence the distribution of pore pressures in an area regardless of the source of overpressures. For example in the Bossier shale in NW Louisiana, the transition from a conventional overpressure area to an unconventional resource pore pressure profile depends on the distribution of silts and sands within the upper Bossier (Figure 6). To the north, sands and silts are prevalent in the upper Bossier and they interfinger with shales in the upper Bossier to the south. Where the sands and silts are absent, the pressure profile in the upper Bossier is approximately a constant VES profile, similar to the lower Bossier. This pressure profile reflects a similar amount of overburden erosion and hydrocarbon generation in the tight shales. To the north however, the upper Bossier remains at lower overpressures and the pore pressure profile is not constant VES. The northern pore pressure profile results from the sands and silts draining off any overpressures generated in the upper Bossier shale. In addition to local permeable sandstone layers within a tight resource play, fault zones in well indurated rocks can develop porosity and permeability during the deformation process. As a result, the fault zones can act as fluid pathways similar to a sand body and these zones may transmit pressures from deeper areas to shallower areas and may be potential drilling hazards. In Figure 7, we show an example where the unconventional resource target rocks are overpressured and faulted into horst and grabens. Above the resource target rocks, the formations are hydrostatic. However, wells drilling through those rocks with low mudweight occasionally saw kicks when they intersected a fault. In this case, it appears that the faults act as permeable conduits that transmit overpressure from the overpressured resource play rocks to shallower depths. In this example, the pressure transmission was observed when the distance along the fault was less than 1,000 meters from the overpressured resource rocks. Finally, we use all of our observations to translate pore pressure information to a new location and predict pore pressures at that location. For translating pore pressures multiple options are available. Pressure data can be translated to a new location using constant overpressure, constant VES or a constant pressure gradient (Figure 8). Data can be displayed at the depth from sea level that it was observed or moved to a different depth based on changes in ground elevation (or mudline elevation) or based on location within the stratigraphic column. In conventional settings for reservoirs or other permeable units, the pressure profile in those units follows a brine gradient, which is generally parallel to the hydrostatic gradient. Therefore, it is appropriate to use constant overpressure to translate data from one location to another in these settings. We occasionally observe this in resource plays, either along permeable fault zones (e.g. Figure 7) or a more permeable bed that is surrounded by tight gas. However, overall examination of the pressure data profiles from multiple resource plays shows that pressure increases with depth parallel to the overburden gradient and therefore formation pressure remains at a constant VES with depth. The magnitude of the constant VES may change across stratigraphic boundaries and this can be captured for use in predicting pressures (Figure 9).

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Figure 6. Stratigraphic cross-section of the gas resource play in northern Louisiana Bossier and Haynesville shale. Influx of coarser clastic sediments from the north in the upper Bossier determines the location of the transition from low overpressures (OP) in the sediments above the resource play to high OP in the resource play. LS = limestone, CVS = Cotton Valley Sands, NLA = North Louisiana, AMI = area of main interest for resource play.

Figure 7. Cross-section of the a resource play that is faulted into horst and graben structures. Overpressures of about 3000 psi are seen in the target shale gas (pink formation). Above the resource target, the rocks are hydrostatic (blue and yellow formations). The faults (thick grey lines) that penetrate the overpressured target rocks transmit pressures upwards. In general, wells that penetrated these faults observed fluid influxes if the distance along the fault to the overpressured target rocks was less than 1,000 meters. Wells that penetrated faults further than 1,000 meters away from the overpressures did not observe influxes.

Overpressured tight rock

Hydrostatic rockProximal Fault Penetration:Well kicked to 3000 psi overpressure

Distal Fault Penetration:Well hydrostatic

Wellpath

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Figure 8. Options for translating pressure data from one location to another. To plot pressure data from one location at another location and preserve the same depth from ground level (or mudline) or to plot the data at the same stratigraphic interval, the pressure data may need to be depth shifted. If the depths are changed significantly and the pressure is plotted as measured, it will not plot correctly and may even plot at sub-hydrostatic pressures or supra-lithostatic pressures depending on the changes in depth. To avoid this problem, several options are available for determining the pressure value to plot. The pressure can be plotted at the new depth based on: (1) the same pressure gradient as it was measured, (2) the same overpressure as it was measured, or (3) the same VES as it was measured.

Discussion We observe that kicks and connection gas events provide good pressure data, but give lower pore pressure estimates than DFIT or production test data. We interpret the difference between pressures inferred from kick data and pressures inferred from production tests or DFIT data to relate to the volumes of flowable fluid and time. Kicks in resource plays are most often low volume fluid influxes that can be circulated out of the wellbore mud system. Due to the low volume, it is possible that the influx itself depletes the pressure in the unit that is flowing, which is most often a silt or fracture. Thus, pressures from this data source may represent a lower bound for pore pressure. A DFIT injects fluid into the formation. A pressure decline curve is then extrapolated to determine background pore pressure. Similarly, an extrapolated pressure build up curve is interpreted from production tests to estimate pore pressure. Because the rocks are very tight, data for these curves may not be collected for a long enough time to properly extrapolate the curve and interpret pore pressure. Thus, pressures from these data sources may be considered an upper bound on pore pressure. Actual pore pressure probably lies somewhere between these two datasets. No matter the data type, we repeatedly observe that the pressure profile in the tight rocks of resource plays parallels the overburden trend and is therefore following a constant VES. The VES magnitude may change across stratigraphic boundaries (e.g. Figure 9). Petrophysical analysis shows that most resource plays are on one or more unloading trends on velocity-VES crossplots, but interpretation can be complicated by gas and TOC effects on the compressional velocity data. Normally, a constant VES pore pressure profile develops in tight rocks because any additional overburden pressure is taken up by fluids. However, in resource plays, the pore pressure develops due to secondary pressure mechanisms rather than by addition of overburden weight and arrested compaction.

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Figure 9. Example pore pressure prediction using offset well data information to control the potential pore pressure ranges that might be encountered. Constant overpressure was used to move pressure data to this location in the more permeable stratigraphy above the unconventional resource play. Constant VES was used in the tight stratigraphy of the resource play to plot pressure data from other locations in the same stratigraphy. We propose two alternative explanations for the constant VES profiles we observe in unconventional resource plays:

(1) The approximately constant VES profile develops due to reaching fracture gradient during gas generation and then subsequent burial. Variations in the VES may result from different units having different fracture gradients (Figure 10).

(2) Alternately, the constant VES profile develops because pore pressure due to hydrocarbon generation cannot escape and thus takes on some of the weight of the overburden. In this case, variations in VES may develop if different layers have different capacity to generate hydrocarbons. Or more generally, the steps in VES depend on different amounts of fluid pressure being generated.

Either way, geologic context is important. To be predictive, variations in the amount of erosion and missing section need to be understood. Similarly, variations in TOC and maturity need to be understood. Finally, as for all pore pressure prediction work, the distribution of permeable zones, including sand, silt and faults will control the pressure profile seen (e.g. Figures 6 and 7).

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Figure 10. A hypothetical cartoon showing the development of a pore pressure profile in an unconventional resource play. First, pore pressure is developed as hydrocarbons are generated in place. The amount of overpressure in various layers may relate to the organic richness of those layers and the local permeability present to drain off overpressure. In the main phase of gas generation pore pressures will reach the fracture gradient, and gas will begin to leak to shallower levels. At this stage the pressure profile is forced to be parallel to the fracture gradient, which is almost parallel to overburden. This may be how a VES parallel profile is established. Later burial of the resource play, after gas generation, moves the pressure profile away from the fracture gradient, but maintaining the overburden-parallel gradient. Summary The traditional porosity-based methods for predicting overpressures, such as Eaton (1975), are restricted in effectiveness in unconventional resource plays for several reasons: (1) pore pressures are generated by mechanisms other than disequilibrium compaction, (2) pore pressures develop after the rocks are buried and compacted, (3) gas and TOC effects on sonic and resistivity data obscure any existing pore pressure imprint on those data, and (4) variable burial and erosion histories make comparison of multiple locations more difficult. Direct formation pressure data in unconventional resource plays is not readily available. Standard tools for measuring pore pressure rely on permeable formations, which are often not present in resource plays. It is common to drill resource plays underbalanced with respect to formation pressure, so drilling mudweight alone cannot be assumed to represent the pressure profile in a well. Instead, we rely on drilling events such as kicks and pumps-off gas to build a pressure dataset. These data are compared with sparser production test and DFIT data, which generally give slightly higher formation pressure as compared to the kick data. In resource plays, we see that pressure variations with depth and stratigraphy are best mapped along constant VES trends by stratigraphic interval. However, local permeable pathways and hydrocarbon gradients may modify that trend. As with all pore pressure prediction work, understanding the permeable plumbing is important. Tight formation is relative, and small amounts of permeability can redistribute formation pressure along faults and up to local crests. Finally, the magnitude of the VES observed relates to hydrocarbon generation capacity and the subsequent burial and/or erosion history. If overburden is removed by erosion, pressures may be preserved in tight rocks as they are brought closer to the surface, leading to higher pressure gradients and lower VES. If overburden is added by burial, pressures may be preserved and taken deeper, leading to lower pressure gradients and higher VES. These trends can be modified by additional pressure generated from disequilibrium compaction depending on the rate of burial and the permeability of the rocks in the resource play. References Bowers, G.L., 1995. Pore pressure estimation from velocity data: Accounting for overpressure mechanisms besides undercompaction.

SPE Drilling & Completion, June, p. 89-95. Eaton, B.A., 1975. The equation for geopressure prediction from well logs. SPE 50th annual fall meeting, Dallas TX Sept 28 – Oct 1,

1975. SPE paper #5544, 11 p. Fertl, W.H., Chilingar, G.V., and Robertson, J.O., 2002. Chapter 6. Drilling Parameters. In G.V. Chilingar, V.A. Serebryakov and J.O.

Robertson, 2002, Origin and Prediction of Abnormal Formation Pressures, Developments in Petroleum Science, v. 50, p. 151-167.

Hunt, J.M., Whelan, J.K., Eglinton, L.B., and Cathles, L.M. III, 1994. Gas generation - A major cause of deep Gulf Coast overpressures:

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Oil and Gas Journal, July 18, 1994, p. 59-63. Osborne, M.J. and Swarbrick, R.E., 1997. Mechanisms for generating overpressure in sedimentary basins: a re-evaluation. AAPG Bulletin,

v. 81, p. 1023-1041. Swarbrick, R.E., Osborne, M.J. and Yardley, G.S., 2002. Chapter 1. Comparison of overpressure magnitude resulting from the main

generating mechanisms. In: Pressure regimes in sedimentary basins. AAPG Memoir, v. 76, p. 1-12. Tozer, R.S.J. and Borthwick, A.M., 2010. Variation in fluid contacts in the Azeri field, Azerbaijan: sealing faults or hydrodynamic

aquifer? Geological Society, London, Special Publications, January 2010, v. 347, p. 103-112. Yardley, G.S. and Swarbrick, R.E., 2000. Lateral transfer: a source of extreme overpressure? Marine and Petroleum Geology, v. 17, p.

523-537.