Use Of Seal, Structural, and Centroid Information in Pore Pressure PredictionPhilip D. Heppard and Martin O. Traugott

Amoco Exploration and Production Technology Group, Houston, Texas

INTRODUCTION

This report describes the effect of geologic structure and lateral continuity on pore pressure in overpressuredenvironments. It sets out three main points: 1) pore pressure in shales, in general, is not equal to pore pressure inadjacent sandstones, 2) pore pressure in sandstones can be sharply higher than that in the bounding shale - for structureswith large vertical amplitude, and 3) a well drilled directly at the crest of a large overpressured structure is at considerablerisk of mechanical failure because there is no kick tolerance i.e. because the pore pressure in the reservoir is nearly equal tothe fracture pressure in the shale.

CENTROID CONCEPT

The centroid is the depth where the pore pressure in a reservoir and the bounding shale are in equilibrium, asillustrated in Figure 1. Above the centroid, the pore pressure in a reservoir is higher than that in the bounding shale.Below the centroid, the reservoir pressure is less than in the shale.

The centroid concept, developed by Amoco (Traugott and Heppard, 1994), is an extension of work by Shell(Dickinson, 1953) and is sometimes referred to as a lateral pressure transfer effect (Swarbrick, 1998). The centroid effect hasbeen modeled at the Gas Research Institute (Stump et al., 1998) and has been applied to exploration problems by Arco (Kanand Kilsdonk, 1998).

As shown in Figure 1, the pore pressure in an overpressured cell or compartment decreases at a hydrostatic ratewith decreasing depth while that in the shale pressure decreases at a overburden rate. The net effect is that the pressure inshales is about 50 psi lower than the pressure in the juxtaposed reservoir for each 100 feet above the centroid. The effect islarger if hydrocarbons are present because of buoyancy.

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Figure 1 - A pressure plot of depth versus pressure illustrating terminology.

Another effect illustrated in the figure is that the equivalent mud weight increases toward the crest in each cellwhile it decreases in the bounding shales which therefore also has a corresponding decrease in hydraulic fracture pressure.It is not uncommon to have a pore pressure in the reservoir at the crest equal to the fracture pressure of the overlyingshale. A well drilled directly at the structural crest of a trap can lose returns into the seal with the mud pumps on and haveflow from the reservoirs with the pumps off (Traugott, 1997).

FIELD EXAMPLES

Two examples illustrate some of the implications of the centroid concept in conjunction with log and seismicderived calculations of pore pressure for successful exploration and drilling. The first example is from Samaan field,offshore Trinidad. Samaan field is a large, northeast-southwest trending anticlinal structure 22 miles off the southeastcoast of the island of Trinidad (Heppard et al., 1998). The field has produced over 200 million barrels of oil and 636 billionft3 of natural gas from normally pressured and mildly overpressured, Pliocene sandstone reservoirs. Very highoverpressure is present in the deepest sandstones in the field below 12,000 feet (Figure 2).

The deepest sandstones within Samaan field have very high pore pressures which are essentially at the hydraulicfracture gradient of the overlying shale at the structural crest of the field. These sandstone pressure compartments are attheir maximum pore pressure which is limited by the hydraulic fracture gradient of the overlying shale seal which acts as apressure release valve. Under these conditions only very small hydrocarbon columns can exist at the crest of the trap.Also, from log calculations and from evidence of overpressure noted during drilling, the interstratified shale beds aresignificantly lower in pressure than these sandstone beds; on the order of 3 PPG less in the shale above the 13 Sandpressure compartment at about 12,000 feet (Figure 2).

Figure 2 - A pressure profile of Samaan field illustrates that most of the sandstone pressure compartments at the crest arehigher in pressure than the bounding shales, indicative of laterally and vertically continuous pressure compartments in alarge structure (after Heppard et al., 1998).

The deepest, highly overpressured sandstone beds at Samaan field are good examples of the results of thisproposed origin of overpressure and the centroid or structural affect of overpressure within sandstones relative to shale.At Samaan the Pliocene shallow marine sandstone beds are continuous over miles extending to the nearest fields such asTeak 12 miles to the south. The top of overpressure is at a relatively consistent depth in the Samaan field area at about10,000 feet stepping up stratigraphy away from the field (Figure 3). The centroid depth of the overpressured sandstones isvery deep off down the flank of the anticline and the pore pressure exerted by the shale over the entire surface of the

sandstone body has been redistributed along a water gradient throughout the sandstone bed. At the crest therefore thepore pressure in the sandstones can be very much greater than in the bounding shale which has only built up pressurefrom taking on the overburden stress from much less burial. As illustrated in Figure 2 the overpressure in the shale is muchless than that in the sandstone beds at the crest of Samaan field. We would also emphasize that we do not believe that thisis a systematic error in our estimation of the pore pressure of the shale beds. In highly overpressured wells more to thecenter of the basin the same techniques used to estimate shale pore pressure show consistently similar or higher pressurein shale relative to measured pressures in the sandstone.

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Figure 3 - A geologic cross section from Samaan field and to wells to the northeast illustrates the complex faulting andstructure of the area. The top of overpressure at about 10,000 feet steps up stratigraphy away from the field and becomesgreater in the shale section with depth such that normally pressured and overpressured sands within the field dip into avery overpressured section. Modified from T. Pish and J. Sharp, Amoco Trinidad Oil Company (1996).

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Figure 4 - A pressure depth plot illustrates that by drilling 600 feet off the crest a 0.5 PPG kick tolerance can be achieved.

An implications of this concept is that very highly pressured compartments can not be safely or efficiently drilledat the crest, but can be drilled safely a few hundreds of feet off the crest. Figure 4 illustrates that at the crest of the Samaan

field the very highly pressured 13 Sand is within 200 psi of the calculated hydraulic fracture gradient of the overlying shaleseal. Therefore at the crest only a static mud weight is stable which almost exactly balances the pore pressure of thesandstone and the hydraulic fracture gradient of the overlying shale. If the mud pumps are turned on to establishcirculation for drilling ahead then the additional pressure will fracture the shale and circulation will be lost. Three earlyattempts to drill through the 13 Sand near the crest failed. In 1993 we recommended drilling at least 300 feet off the crest ofthe structure to increase the kick tolerance while drilling this sand and the well was drilled successfully (Figure 4).

A second example this time from the Nile Delta, offshore Egypt, illustrates several other implications of thecentroid concept. Recent exploration drilling has been largely successful at discovering gas and condensate reserves inPliocene and Miocene sandstones in the Nile Delta. Significant volumes of hydrocarbons are trapped within overpressure.Overpressure begins within the Pliocene Kafr el Sheikh formation at about 1500 m and increases in steps to about 16 PPG atabout 3600 m (Figure 5). Like at Samaan field, at the crest of structures the pore pressure of the sands is higher than thebounding shales. Within the Miocene section the level of overpressure within the shale is remarkably consistent acrossthe eastern Nile Delta increasing from about 15 PPG to over 16 PPG at about 4200m. However the principal sandstonereservoir within the Serravallian age section is often lower in pore pressure than the bounding shale. Rarely a much higherpressure sand is found within the Miocene Serravallian section. We interpret these pressure differences as due to theorigin of the overpressure which is similar to that described for the Samaan field example but is also affected by leak points.

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Figure 5 - A pressure versus depth plot of the Osiris East #1 well from the Nile Delta of Egypt. Overpressure begins in thePliocene Kafr el Sheikh formation at 1780 m and builds in a step-wise fashion through the Miocene section to total depth.Through most of the section pore pressure in the sandstone is higher than the bounding shale as is expected at the crestof large structures.

The example well shown in Figure 5, the Osiris East #1 encountered two overpressured sands within the Miocenesection below 3500 m. The NN6 sand at about 3800 m is at 5578 psi above normal near and over 17 PPG. A sand just a few10’s of meters deeper, the NN5, is much lower in overpressure at about 3800 psi above normal. The very high pressure ofthe NN6 Sand is greater than the bounding shale at the Osiris East #1 well indicating that the sand was penetrated at adepth above the centroid. This indicates that the sand extends well down into increasingly overpressured shale. At thecrest of the structure just above the Osiris East #1 penetration the sand pressure approaches the hydraulic fracture

gradient of the overlying shale suggesting that gas may have leaked out of the sandstone due to hydraulic fractureexplaining why it is wet. The pore pressure of the deeper, gas filled NN5 Sand however is much lower than the boundingshale suggesting that the well penetrated the sandstone well below the centroid, that is well down from the highest pointof the vertical extent of the sandstones distribution. Applying the centroid principle then the NN5 Sand has at least 800 mof vertical relief being about 400 m below the it’s centroid or greater relief while the NN6 may have a much less verticalrelief. However an alternative interpretation for the relatively lower pressure of the NN5 Sand seems more viable. Aninterpretation of available seismic lines in the area as illustrated in Figure 6 suggests that the NN5 sandstone is truncatedby a major unconformity at a depth below the implied crest. Pliocene beds onlap the unconformable surface and likelyprovide a fluid leak point allowing overpressure fluids to escape.

Pressure prediction for deep, Miocene exploration wells in the eastern Nile Delta is conducted using intervalvelocity derived from surface seismic and geologic interpretations. Within the area of the Osiris East #1 well seismicinterval velocity reflects the overall velocity of the shale dominated section but does not reflect velocity variations fromthe relatively thin sandstone beds that might suggest their pressure state. Therefore we can only estimate the averageshale pressure state and must use structure maps and geologic interpretation to predict overpressure in sandstone beds.We can not indirectly measure some property such as velocity to predict overpressure in non-shale formations. In theeastern Nile Delta and elsewhere we use the structural relief and to some degree the shape of sandstone beds to correct forthe redistribution of overpressure within the unit using the centroid concept. This must be modified where well data andgeologic interpretations suggest that the system may be ‘leaky’.

Figure 6 - A geologic model of the distribution of overpressure and hydrocarbon migration in the Ha’py Graben where theOsiris East #1 well was drilled. The NN6 Sand is very overpressured approaching the hydraulic fracture gradient of theoverlying shale suggesting that gas has been released from the crest of the structure through pressure induced fracturefeeding into shallower Pliocene sandstones. The relatively lower pressure of the NN5 Sand however indicates that laterallythere is a pressure and fluid leak point which is suggested to be across the Messinian unconformity into onlappingPliocene sandstone beds (after Heppard and Albertin, 1998).

CONCLUSIONS

Pore pressure prediction should take into account that most pressure estimation and prediction methods whetherlog or seismic velocity based estimate the pore pressure in the shale only. The pore pressure of shale can be muchdifferent from the adjacent sandstone due to the relative impermeability of shale and the redistribution of overpressurewithin the pore system of porous and permeable rocks. The centroid principle can be used to predict overpressure in non-shale units such as sandstone. At the crest of large structures we should expect the pressure in the sandstone beds to besignificantly higher relative to the bounding shale due to the redistribution of overpressure throughout the entire volumeof the sandstone along a water gradient. Where long hydrocarbon columns are present the pressure gradient can besharply increased at the crest due also to the buoyancy of the gas or oil. Where very high pore pressure is expected a wellshould be located at least 300 feet off the crest of the structure to allow a manageable kick tolerance to exist. Directly at thecrest of structures the pore pressure in sandstone beds may be very close to the hydraulic fracture gradient of theoverlying shale which is a safety hazard, a pressure condition where economic hydrocarbon columns are unlikely to exist,and often leads to the abandonment of the well since there is too little kick tolerance.

REFERENCES

Dickinson, G., 1953, Geological Aspects of Abnormal Reservoir Pressures in Gulf Coast Louisiana, AAPG Bulletin, 37, 410-432.

Heppard, P. D., Cander, H. S., and Eggertson, E. B., 1998, Abnormal pressure and the occurrence of hydrocarbons in offshore eastern Trinidad, West Indies, in Law, B. E., Ulmishek, G. F., and Slavin, V. I., eds., Abnormal pressures in hydrocarbon environments: AAPG Memoir 70, 215-246.

Heppard, P. D., and Albertin, M. L., 1998, Abnormal pressure evaluation of the recent Pliocene and Miocene gas discoveries from the eastern Nile Delta, Egypt, using 2D and 3D seismic data: 1998 AAPG Annual Convention, Salt Lake City, Utah, expanded abstract.

Kan, T.K., and Kilsdonk, W., 1998, Geopresure prediction from 3d data: case studies from the Gulf of Mexico, Workshop on Overpressures in Petroleum Exploration, April 7 and 8, Pau, France.

Stump, B.T., Flemings, P.B., Finkbeiner, T., Zoback, M.D., 1998, Pressures differences between sands and bounding shales for fluid flow induced by sediment loading, Workshop on Overpressures in Petroleum Exploration, April 7 and 8, Pau, France.

Swarbrick, R.E., Osborne, M.J., Yardley, G.S., Macleod, G., Bigge, A, Grunberger, D., Aplin, A., and Larter, S., 1998, Bean Field - Integrated study of an overpressured Central North Sea oil and gas field, Workshop on Overpressures in Petroleum Exploration, April 7 and 8, Pau, France.

Traugott, M. O., and Heppard, P. D., 1994, Prediction of pore pressure before and after drilling - taking the risk out of drilling overpressured prospects: AAPG Hedberg Research Conference Abnormal Pressures in Hydrocarbon Environments, Golden Colorado, June 8-10, 1994, abstract.

Traugott, M.O., 1997, Pore/fracture pressure determinations in deep water, Deepwater Supplement to World Oil, August,1997.