Pressure Differences Between Overpressured Sands and Bounding

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Pressure Differences Between Overpressured Sands and Bounding Shales ofgene Island 330 field (Offshore Louisiana, U.S.A.) with Implications for Fluid Floinduced by Sediment Loading

Beth B. Stump(1), Peter B. Flemings(1), Thomas Finkbeiner(2), Mark D. Zoback(2)

(1) Department of Geosciences, 436 Deike Building, The Pennsylvania State University, Usity Park, PA 16802(2) Department of Geophysics, Stanford University, Stanford, CA

AbstractWe document pressure differences between adjacent sands and shales in geopressured Ptocene strata of offshore Louisiana and we quantify a sediment loading model that describeorigin of these differences. The JD sand is in moderate geopressure (Pf/σl=0.6) and has a lowerpressure than its bounding shale. The L1 sand is severely overpressured (Pf/σl=0.9) and has a pres-sure greater than its bounding shale. Shales which are adjacent to the JD and L1 sands hasures (derived from a porosity-effective stress relationship) which follow a lithostatic gradientinterpret this behavior to result from rapid, spatially varying loading of permeable sand bodierelatively impermeable shales. Under these conditions, pore pressures at the peak of structusignificantly exceed the pore pressure of bounding shales. The L1 sand records this behavcontrast, the low relative pressures in the JD sand may record dissipation of pressure by flgration along permeable pathways. The sediment loading model predicts along-stratal flow wsands and cross-stratal flow at structural highs. In a companion paper, Finkbeiner et al. (thume) describe how sediment loading and the buoyant effect of hydrocarbons combine to drivepressures toward the minimum principal stress of bounding cap rocks, resulting in fluid migra

IntroductionShale porosity or some proxy of porosity (e.g. resistivity) has long been used to estimatein situfluid pressure (Athy, 1930; Rubey and Hubbert, 1959; Wallace, 1965; Hottman and Johnso1965). The typical approach is to examine the porosity profile in a zone of known fluid pres(i.e. the hydrostatic zone) and then use this empirical relationship to predict pressure wherunknown (i.e. the geopressured zone). The resulting predictions are then compared toin situmea-surements of fluid pressure. A difference between predicted and measured pressures was ined simply as a deficiency of the model.

More recently, differences between porosity-derived shale pressures andin situ sand pressureshave been interpreted as indicative of late-stage increases in fluid pressure which are not rein the shale porosity signature. This effect, termed 'unloading' because it results in a net dein effective stress, was developed by Bowers (1994) and further explored by Hart et al. (1995Gordon and Flemings (in press). These studies assumed,a priori, that sand pressures were equialent to shale pressures and interpreted any discrepancy to result from the inadequacy of theity-effective stress model. According to the unloading model, a late-stage decrease in effestress does not result in decompaction (i.e. porosity rebound) along the initial compaction (ity-effective stress) curve. As a result, the porosity-effective stress model does not successpredict fluid pressures in sediments with this unloaded deformation path.

This study continues to explore the differences between shale-predicted pore pressures andin situpressures in adjacent sands. Unlike previous work, we interpret the observed deviations bemeasurements and predictions as actual differences between sand and shale pressures. W

gene Is-ictsnt load-ssure

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document this behavior in moderate and severely overpressured sands and shales in the Euland 330 (E.I. 330) field (offshore Louisiana, U.S.A.). We then quantify a model which predpressure differences in sands and shales that result from the history and geometry of sedimeing. Lastly, we integrate the observations into the sediment loading model to predict the preevolution of two sands in the E.I. 330 area.

Estimating Shale PressuresWe employ a long-recognized technique for estimating fluid pressure from porosity. TerzaghPeck (1948) proposed a relationship between porosity and vertical effective stress, and a varapproaches have been developed to quantify this relationship (Athy, 1930; Terzaghi, 1943; Rand Hubbert, 1959; Palciauskas and Domenico, 1989). We combine the definition of effectstress (Equation 1) and the porosity-effective stress relationship developed by Rubey and H(1959) (Equation 2) to calculate fluid pressure from porosity in shales (Equation 3) (Hart etTable 1 describes all of the variables and constants used in this paper.(1)

(2)

(3)

Lithostatic stress (σl) is calculated by integrating the wireline bulk density log. Porosity is callated from the wireline sonic (travel time) log using an empirical relationship first developedRaymer et al. (1980) and then enhanced by Raiga-Clemenceau et al. (1986).

(4)

In Equation 4,∆tmais travel time for the matrix,∆t is log-derived travel time, and x is an acoustiformation factor. Issler (1992) determined∆tma to be 220µs/m and x to be 2.19 for non-calcareous, low total organic carbon shales. We took travel time measurements during deformationiments on shale core from E.I. 330 which indicate similar values for acoustic formation fact

We plot porosity versus vertical effective stress (Figure 2) in the hydrostatic zone to determinφ0andβ (Equation 2) and then apply these coefficients (Equation 3) to calculate fluid pressure ideeper, geopressured section of the well.

ResultsShale pressures were evaluated for ten wells in this study (Figure 1). We compare our predshale pressures with pressure measurements made in adjacent sands (Figure 3, points a ahydrocarbon-bearing sands the pressure of the hydrocarbon phase often exceeds the watepressure in the sand (due to fluid density differences). Since we assume that shales have a(near-zero) hydrocarbon saturation, we interpret the predicted shale pressure to be a watepressure (Pw) and calculate water phase pressure in the sand for comparison. Our results shoeven after removing the buoyant effect of the hydrocarbon column, pressure in geopressuredexceeds that in the bounding shales (Figure 3).

Figures 4a,b illustrate the general stratigraphy and pressure profile of the E.I. 330 area. Thisconsists of interbedded Plio-Pleistocene sands and shales. Pressures from measurements

σv Sv Pf–=

φ φ0eβσv–

=

Pf Sv1β---

φ0φ-----

ln –=

φ 1∆tma

∆t------------

1 x⁄

–=

hydro-rizon),

ings shal-s fors in the.

ts (Fig-

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weights, and porosity predictions reflect the same general pressure signature. This area isstatically pressured at shallow depth, moderately overpressured at intermediate depth (JD hoand severely overpressured at the depth of the L1 horizon. As explored in Gordon and Flem(in press), the depth at which geopressure is encountered in the upthrown (316 A-1) well islower (~1900 m) than in the downthrown (331 #1) well (~2400 m). We present detailed resultthe JD and L1 horizons. The key observation is that shale pressures exceed measurementJD sand (Figure 4a), but are less than observed sand pressures at the L1 level (Figure 4b)

A cross-plot of measured vs. predicted overpressures (P* = Pf - Ph) for all of the wells in this anal-ysis (Figure 5) shows that predicted shale pressures (Figure 3, point a) exceed measuremenure 3, point b) in moderately overpressured sands (e.g. less than 7 MPa), and consistentlyunderestimate measurements in severe overpressure (e.g. greater than 15 MPa). If the wirelationship accurately predicts shale pressure, then sand pressure is not equal to the pressurbounding shale.

Sediment Loading ModelIf a permeable sand is loaded asymmetrically by relatively impermeable shales, the conseqsand and shale pressures will differ (Dickinson, 1953; England, 1987; Traugott, 1994). Thewill maintain a hydrostatic pressure gradient while the shale maintains a nearly lithostatic pregradient. We illustrate this behavior for sands which are buried to form anticlinal, homoclinal,synclinal structures (Figures 6a,b,c). In all cases, the pressure gradient within the sand is hydic, and the overpressure (DP*) is the pressure necessary to support the total overburden lowe show in the Appendix, DP* is a function of the overburden, and the fluid and bulk compibility (Equation 5).

(5)

The pressure profile for the three structures (Figure 6d) shows that the amount of overpreswithin the sand (DP*) and the depth at which the sand and shale pressures are in equilibriumure 6d, triangles) are affected by sand geometry. A synclinal sand (Figure 6c) sustains a hamount of overpressure than an anticlinal sand (Figure 6a). This is logical, because the sysand is supporting a greater load of sediment. As a result, the depth at which the sand is in prequilibrium with the overlying shale (termed the centroid by Traugott, 1994) varies with structgeometry. Figure 6d also illustrates that the relationship between sand and shale pressure cwith position on relief. At the structural peak, sand pressures are greater than shale pressurestructural low, shale pressure exceeds sand pressure.

Case Study: The JD and L1 SandsWe explore the distribution of shale and sand pressures as a function of relief along two horin the E.I. 330 field: the moderately overpressured JD (Pf/σl=0.6) and the severely overpressureL1 (Pf/σl=0.9) (Figures 7a,b). The JD sand dips from ~1780 m (5850 ft) to ~2070 m (6800 ft)a total relief of 290 m. Fluid pressure (Pw) within the JD sand follows a hydrostatic gradient (Figure 7a). Pressures in the bounding shale follow a lithostatic gradient, and exceed sand presmost depths on structure. At the peak of structure, sand pressure exceeds shale pressure byimately 1.4 MPa (~200 psi); at the structural low, shale pressure is 4.7 MPa (676 psi) greatesand pressure. The sand and shale pressures are in equilibrium at 1836 m (6025 ft).

DP∗ ββ β f 1 φ–( )+---------------------------------

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L

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The water phase pressure in the L1 (Figure 7b) also follows the hydrostatic gradient while pressure follows the lithostatic gradient. The key distinction between this horizon and the amentioned JD is that sand pressures at the L1 horizon exceed shale pressures at all depthsture. At the structural peak (1950 m; 6400 ft), the sand pressure is nearly 4 MPa (574 psi) gthan that of the overlying shale. Sand and shale pressures converge at the base of the sanm; 7600 ft).

These observations support the sediment loading model presented above. However, not aobservations made in the JD and L1 sand are explained by the initial simple model. For exathe depth at which sand and shale pressures are in equilibrium is much lower on structure athorizon. As a result, the pressure difference between sand and shale is much larger at the topL1 than at the top of the JD (4 MPa vs. 1.4 MPa). In addition, while the shale pressures followlithostatic gradient, their absolute pressure values are different; the fluid pressure at the JD lelower than at the L1 level (Pf/σl = 0.6 and 0.9, respectively). Below we present a model to descrthe evolution of pressure and stress in the JD and L1 sands.

DiscussionOur modified sediment loading model is illustrated in Figure 8. Initially, as the sand is burieshale, both layers are able to expel their pore fluids and remain hydrostatically pressured (8a). This expulsion of fluid is possible because the sedimentation rate is slow (Alexander aFlemings, 1995), and the newly deposited material has sufficient permeability. Then, at a cdepth, the system becomes effectively sealed and ceases to expel fluids (Figure 8b). This tramay be caused by a sudden drop in the shale permeability as porosity drops beneath a critica(Mello et al., 1994; Gordon and Flemings, in press), or it may be due to an increase in sedition rate (Alexander and Flemings, 1995). Once the system becomes sealed, fluid pressurethe sand and bounding shale increases at a nearly lithostatic gradient (Figure 8b). Ultimatelyis a spatial variation in sedimentation and the consequent generation of structural relief (FigurFluid pressure within the permeable sand follows the hydrostatic gradient; shale fluid presstrack the lithostatic gradient. Therefore, as relief is generated, the pore pressures in the sandtop of structure begin to exceed pressures in the bounding shales. If the top of the sand is permand connected to other permeable layers (e.g. adjacent to a permeable fault zone) or if the pin the sand exceeds the minimum principal stress of the bounding shale, fluids will migrate othe sand, thereby decreasing the sand pressure. This effect of pressure bleed-off is shown in8d, as the line representing sand pressure shifts to the left and overpressure (DP*) decrea

Figures 9a and 9b illustrate our models for pressure evolution in the JD and L1 sands. FollHart et al. (1995), we present the simplest model in which sand pressure increases hydrosta(t1 to t2) until a depth at which it begins to increase at a nearly lithostatic gradient (t2 to t3). Theactual pressure path is unknown; pressure may have increased at a gradient between hydand lithostatic (Figure 9a, dashed lines).

Both the absolute sand pressure and the difference between sand and shale pressures at thstructure are lower at the JD level (Figure 9a) than at the L1 horizon (Figure 9b). The JD apto record a greater pressure bleed-off, even though pressures are well below the fracture gof the cap rock (Finkbeiner et al., this volume). This implies that fluid migration occurred alopermeable pathways (Alexander and Handschy, in press), rather than by hydrofracture. Thments which overlie the JD have a higher permeability than the stratigraphically deeper sedi(e.g. which directly overlie the L1), allowing more vertical fluid flow and greater pressure disstion.

wer one anyt fluid

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In contrast, at the L1 level, the depth at which sand and shale pressures are equal is much lostructure, indicating that pressure dissipation has been negligible. In Figure 8d, we do not sedecrease in overpressure through time. However, Finkbeiner et al. (this volume) suggest thapressure in the L1 sand is controlled by the minimum horizontal stress in the overlying shalepressure greater than the current level will bleed off by natural hydraulic fracture.

We emphasize that the sediment loading model relies heavily on at least three assumptionand foremost, shales are assumed to be relatively impermeable. By this we mean that shasures will not dissipate significantly over the time scales of sediment loading. In this regardreassuring that shale pressures record a lithostatic gradient. Second, we assume that sediming is the dominant source of overpressure. This was documented in detail by Gordon andings (in press) for the E.I. 330 area. However, we recognize that other pressure sources arpossible. All of these assumptions are most appropriate for young, rapidly loaded basins; itapparent to us if this model is appropriate in older basins. Our final assumption is that wirelinedictions of shale pressure are correct. For this to be true, compressibility must be constantdepth, effective stress must always increase (i.e. ignores unloading effect), and the sonic logbe an accurate measurement of porosity. In the latter regard, we emphasize that we have prsimilar results with the bulk density log. Hart et al. (1995) estimated that compressibility musgreater than twice the value calculated from the hydrostatic zone to replicate the severe ovsures observed at depth.

The integration of sand and shale pressure characterization into the sediment loading modvides insight into not only the present pressure state of sands and shales but also into the evof pressure, stress, and fluid flow through time. In particular, our results emphasize that crostratal flow (i.e. near vertical) is dominant at structural highs, where the difference betweenand shale pressures is a maximum. This cross-stratal flow is driven by the lateral flow as scompact in response to the applied overburden load. Furthermore, flow occurs most rapidly dsedimentation events.

ConclusionsDifferential sediment loading of a permeable sand can result in fluid pressures which differthose in overlying shales. These pressure differences are documented using porosity-derivepressures and measured sand pressures for ten wells in the E.I. 330 area. We present a quasediment loading model to explain the observed differences and provide a method of calcusand pressure as a function of structural geometry and total relief. This model allows us to insight into the evolution of pressure, stress, and fluid flow in the basin. This approach has thtential to provide insight into trap quality and the history of secondary migration.

AcknowledgmentsThis research is supported by the Gas Research Institute. We would like to thank Pennzoil,and Texaco for generously providing the data used in this analysis, as well as Martin Traug(Amoco) for his insight into the effect of structural relief on fluid pressure.

rained

iaus-d the

Table 1: Nomenclature

Appendix: Derivation of Undrained Sediment Loading ModelConsider a material element (contains a constant number of solid grains) which remains und(i.e. no fluids escape) that is loaded from above with a stress Dσl. This stress is balanced by anopposing stress which is the combination of change in fluid pressure (DPf) and the change in ver-tical effective stress (Dσv) in the material element.

(A1)

Equation A1 is derived in Gordon and Flemings (in press) who built on the derivation of Palckas and Domenico (1989). Equation A1 assumes: 1) the solid grains are incompressible anfluid and matrix are linearly compressible {(1/ρf)Dρf = βfDPf; Dφ=-βφDσv}; 2) strain is uniaxial;and 3) there are no temperature effects.

Name Value Description

g 9.8 gravitational acceleration (m/s2)

P* variable overpressure (MPa)

Pf variable fluid pressure (MPa)

Ph 0.0105*depth(m) hydrostatic fluid pressure (MPa)

Pw variable water phase pressure (MPa)

x 2.19 acoustic formation factor

β 3.13E-2 matrix compressibility (MPa-1)

βf 4.88E-4 fluid compressibility (MPa-1)

∆tma 220 matrix travel time (µs/m)

∆t variable log-derived travel time (µs/m)

φ variable wireline-derived porosity

φ0 0.386 reference porosity

ρb variable bulk density (kg/m3)

ρf 1070 fluid density (kg/m3)

σl variable lithostatic stress (MPa)

σv variable vertical effective stress (MPa)

β1 φ–( )

---------------- β f– DSvβ

1 φ–---------DPf β f βs–( )Dσv–=

ure,

y ands,

pth z,sumer

ody

Consider the same material element buried a depth dz:

(A2)

(A3)

(A4)

Substituting Equations A2, A3, A4 into Equation A1, and solving for the change in fluid presswe find:

(A5)

In our work in Plio-Pleistocene strata of the Eugene Island area, typical bulk compressibilitporosity values are 3.13E-2 MPa-1 and 0.3, respectively (Hart et al., 1995, Gordon and Flemingin press), while fluid compressibility is 4.88E-4 MPa-1 (de Marsily, 1986). Using these values,Equation A5 reduces to:

(A6)

Thus, the change in fluid pressure (DPf) supports ~99% of the change in the overburden load(Dσl).

Consider next the problem of a sand body of length L that has been buried to a variable dewhere z = f(x) (Figure A1). The sand is composed of material elements of length dx. We asthat the fluid can be displaced within the sand (qw), but that no fluid leaves the sand body. Undethis constraint, balance of stress requires:

(A7)

In this case, the changes in fluid pressure, overburden, and effective stress are:

(A8)

(A9)

(A10)

Substituting Equations A8-A10 into Equation A7 and integrating over the length of the sand b

DSv ρbgdz=

DPf ρ f gdz x( ) P∗+=

Dσv ρbgz ρ f gdz DP∗+( )–=

DPfβ

β f 1 φ–( ) β+---------------------------------ρbgdz=

DPf 0.989ρbgdz=

β1 φ–( )

---------------- β f– DSv x( ) β1 φ–------------DP x( ) β f Dσv x( )–

1ρ f------ ρ f q x( )∇+=

DSv ρbgdz x( )=

DPf ρ f gdz x( ) DP∗+=

Dσv ρbgdz x( ) ρ f gdz x( ) DP∗+( )–=

ual toelief,

DP*)e func-

ith-12,

ault

tion

ure15-529.

ca-

iana:

en-144,

ssure,

L, we find:

(A11)

overburden load fluid pressure effective stress flow term

Because we assume that the entire sand body is undrained, the integral of the flow term is eqzero. Upon integration, and solving for the change in overpressure resulting from structural rwe find:

(A12)

Equation A12 can be solved for any load geometry (z(x) = f(x)) to estimate the overpressure (added to the system. For example, in the main body of this paper, we describe three possibltions for z(x): linear, hyperbolic, and parabolic (Figure 6).

ReferencesAlexander, L.L., and P.B. Flemings, 1995, Geologic Evolution of a Plio-Pleistocene Salt-Wdrawal Minibasin: Eugene Island Block 330, Offshore Louisiana: AAPG Bulletin, v. 79, no. pp. 1737-1756.

Alexander, L.L., and J.W. Handschy, in press, Fluid Flow in a Faulted Reservoir System: FTrap Analysis for the Block 330 Field in Eugene Island South Addition, Offshore Louisiana:American Association of Petroleum Geologists Bulletin, v. 82.

Athy, L.F., 1930, Density, porosity, and compaction of sedimentary rocks: American Associaof Petroleum Geologists Bulletin, v. 14, no. 1, p. 1-22.

Bowers, G.L., 1994, Pore pressure estimation from velocity data: Accounting for overpressmechanisms besides undercompaction: Society of Petroleum Engineers Paper 27488, p. 5

de Marsily, G., 1986, Quantitative Hydrogeology: Groundwater Hydrology for Engineers, Ademic Press, Inc., 592 pp.

Dickinson, G., 1953, Geological aspects of abnormal reservoir pressures in Gulf Coast LouisAAPG Bulletin, v. 37, no. 1, pp. 410-432.

England, W.A., A.S. MacKenzie, D.M. Mann, and T.M. Quigley, 1987, The movement and trapment of petroleum fluids in the subsurface: Journal of the Geological Society, London, pp. 327-347.

Finkbeiner, T., M.D. Zoback, B.B. Stump, and P.B. Flemings, 1998, In situ stress, pore preand hydrocarbon migration in the South Eugene Island Field, Gulf of Mexico: this volume.

β1 φ–( )

---------------- β f– DSv x( )0

L

∫ β1 φ–( )

---------------- DPf x( ) β f Dσv x( ) 1ρ f------ ρ f q x( )∇

0

L

∫–

0

L

∫–

0

L

∫=

DP∗ ββ β f 1 φ–( )+---------------------------------

ρb ρ f– g z x( ) xd

0

L

∫=

riveniana:

on dis-v. 23,

A.,nd

shale

fort-leum

g ofUnited

ater

n fac-ual

rans-

inging:

iley

t ofe-

tivity

Gordon, D.S. and P.B. Flemings, in press, Generation of Overpressure and Compaction-DFluid Flow in a Plio-Pleistocene Growth-Faulted Basin, Eugene Island 330, Offshore LouisBasin Research.

Hart, B.S., P.B. Flemings, and A. Deshpande, 1995, Porosity and pressure: Role of compactiequilibrium in the development of geopressures in a Gulf Coast Pleistocene basin: Geology,no. 1, pp. 45-48.

Holland, D.S., W.E. Nunan, and D.R. Lammlein, 1990, Eugene Island Block 330 field- U.S.offshore Louisiana,in E.A. Beaumont and N.H. Foster, eds. Structural traps III, tectonic fold afault traps: AAPG Treatise of Petroleum Geology, Atlas of Oil and Gas Fields, p. 103-143.

Hottman, C.E. and R.K. Johnson, 1965, Estimation of formation pressure from log-derived properties: Journal of Petroleum Technology, v. 17, 717-722.

Issler, D.R., 1992, A new approach to shale compaction and stratigraphic restoration, BeauMackenzie basin and Mackenzie Corridor, northern Canada: American Association of PetroGeologists Bulletin, v. 76, no. 8, p. 1170-1189.

Mello, U.T., G.D. Karner, and R.N. Anderson, 1994, A physical explanation for the positioninthe depth to the top of overpressure in shale-dominated sequences in the Gulf Coast basin,States: Journal of Geophysical Research, v. 99, no. B2, pp. 2775-2789.

Palciauskas, V.V., and P.A. Domenico, 1989, Fluid pressures in deforming porous rocks: WResources Research, v. 25, no. 2,. pp. 203-213

Raiga-Clemenceau, J., J.P. Martin, and S. Nicoletis, 1986, The concept of acoustic formatiotor for more accurate porosity determination from sonic transit time data: SPWLA 27th AnnLogging Symposium Transactions, Paper G.

Raymer, L.L., E.R. Hunt, and J.S. Gardner, 1980, An improved sonic transit time-to-porosity tform: SPWLA 21th Annual Logging Symposium Transactions, Paper P.

Rubey, W.W. and M.K. Hubbert, 1959, Overthrust belt in geosynclinal area of western Wyomin light of fluid pressure hypothesis, 2: Role of fluid pressure in mechanics of overthrust faultGeological Society of America Bulletin, v. 70, p. 167-205.

Terzaghi, 1943, Theoretical Soil Mechanics: New York, John Wiley and Sons, Inc., 510 p.

Terzaghi, K. and R.B. Peck, 1948, Soil mechanics in engineering practice: New York, John Wand Sons, Inc., 566 p.

Traugott, M.O., 1994, Prediction of pore pressure before and after drilling-- taking the risk oudrilling overpressured prospects: American Association of Petroleum Geologists Hedberg Rsearch Conference, Denver.

Wallace, W.E., 1965, Abnormal surface pressure measurements from conductivity or resislogs: Oil & Gas Journal, v. 63, pp. 102-106.

fromaths;

MPa/

phasebuoyant

n Fig-d outs of an.t L1staticicted

the

ands arele pres-

effect ofession

fepen-mount465 psi/top of

presentsand

(solid)greater

ly pres-gradientvel,and and

Figure CaptionsFigure 1: The E.I. 330 field is in the Gulf of Mexico, 272 km southwest of New Orleans, LA,U.S.A. at a water depth of ~77 m (Holland et al., 1990). We use wireline and pressure data10 wells in this field. Plus symbols indicate straight holes; solid lines represent deviated well pfilled circles show the bottom hole locations of deviated wells.

Figure 2: Log-linear plot of sonic-derived porosity (φ) versus vertical effective stress (σv) in thehydrostatic zone for the 331 #1 well (located in Figure 1). Lithostatic stress (σl) is calculated byintegrating the bulk density log; hydrostatic pressure is calculated from a gradient of 0.0105m (0.465 psi/ft) for sea water. Solid line represents the regression fit to the data.

Figure 3: In this study we compare porosity-predicted shale pressures (point a) with water pressures (point b) in adjacent sands. Water phase pressures are used in order to negate theeffect of the hydrocarbon column.

Figure 4a,b: Gamma ray log and pressure profiles for the 331 #1 and 316 A-1 wells (located iure 1). The JD and L1 sands are interpreted in both wells. In the 331 #1 well, the L1 is faulteand the approximate location of the L1 horizon is shown. These wells are on opposite sidelarge growth fault; the #1 well is on the downthrown side of the fault, while the A-1 is upthrowThis explains the offset between the horizons at the two wells (~560 m at JD level; ~980 m alevel). On the pressure track, bounding lines are hydrostatic pressure (0.465 psi/ft) and lithostress (calculated by integrating the bulk density log). Plus symbols represent porosity-predshale pore pressures; filled circles represent measuredin situ pressures in adjacent sands. Over-pressure calculated from drilling mud weights is shown by white fill; vertical effective stress islight gray area.

Figure 5: Cross plot of sand and shale overpressures shows that in severe overpressure smore highly pressured than shales, but at shallow depths (low values of overpressure) shasures exceed sand pressures. All sand overpressures are calculated in the water phase (Pw), so thesand pressures in excess of adjacent shale pressures can not be attributed to the buoyanta hydrocarbon column. Dashed line represents a one-to-one correlation; solid line is a regrfit for these data (y = 0.673x + 369.4, R2 = 0.94).

Figure 6: Pressure evolution in three different sand structures: a) anticlinal (z(x) = x2/30000), b)homoclinal, c) synclinal (z(x) = (200/3)x1/2). d) Pressure profile resulting from 10,000' of relieon three different structures. The amount of overpressure generated by structure (DP*) is ddent on the overburden load; synclinal structure supports the most sediment, therefore the aof overpressure is greatest. Dashed lines represent hydrostatic pressure (0.0105 MPa/m; 0.ft) and lithostatic stress (0.021 MPa/m; 0.94 psi/ft). Points 4,6,8 represent sand pressures atstructure; points 5,7,9 represent sand pressures at the base of structure. Points 2 and 3 reshale pressure at top and bottom of structure, respectively. Triangles highlight depth at whichand shale pressure are in equilibrium ("centroid"). The line representing the shale pressurenearly overlies the lithostatic stress line (dashed), but the difference can be seen at depthsthan 13,000 feet.

Figure 7: Pressure plots for sands and shales at the JD and L1 horizons. a) At the moderatesured JD sand, shale pressure exceeds sand pressure at most points on structure. Pressurewithin sand is hydrostatic; shale pressure gradient is approximately lithostatic. b) At the L1 lesand pressure is greater than shale pressure; pressures converge at the base of structure. S

y filledwn for

shaleures ins caus-d; sand

pres-

es repre-

).

est of

shale pressure gradients are similar to those at JD horizon. Shale pressure is represented bcircles; plus symbols represent sand pressure. The lithostatic gradient (0.021 MPa/m) is shoreference.

Figure 8: Schematic of pressure evolution in sand and bounding shale. a) At time 1, sand andare hydrostatically pressured at some depth, z1. b) Sand layer is buried from z1 to z2; pressboth sand and shale increase at lithostatic gradient. c) Lateral variation in sedimentation ratees sand to dip; sand and shale pressures at top of structure diverge. d) Fluid bleeds out of sanpressure decreases and converges on shale pressure at the top of structure.

Figure 9: Model for pressure evolution in the JD and L1 sands shows a hydrostatic increase insure from t1 to t2, and a nearly lithostatic increase in pressure from t2 to t3. Following t3, as structureis generated in the sands, sand fluid pressure begins to exceed shale pressure. Dashed linsent alternative pressure paths. a) Sand pressure in the JD decreases as fluid is bled off (t3 to t4). b)Sand pressure remains greater than pressure in overlying shale (no dissipation is observed

A1: Two-dimensional model in which the sand parcel has pressure communication with the rthe layer.

Figure 1

Figure 2

LOUISIANA

MISSISSIPPI

New Orleans

N

Eug

ene

Isla

nd

316314 315

331

337

330

338

329

339

3 miles(4.8 km)

B-1 A-20ST2

B-13

#5

A-1 A-12

A-22A-4 #1

A-6

0

500

1000

1500

2000

2500

Shale Porosity

Ver

tical

Effe

ctiv

e S

tres

s (p

si)

0.1 0.2 0.3 0.4

φ =

0.38

6e-(3

.13x

10

σ)-2

Vertical E

ffective Stress (M

Pa)

5

10

15

Figure 3

Figure 4

3500 3600 3700 3800

6300

6400

6500

6600

6700

6800

6900

Pressure (psi)D

epth

(ft)

Pressure (MPa)25 26

1950

2000

2050

Depth (m

)

2100water

shale gas

▲a P g

P = 3756G/O contact

o

P = 3763O/W contact

w

P o

PcogPcow

oil

▲ab b

P w

a) b)

Gamma Ray Pressure(MPa)

0

1000

2000

3000

4000

5000

6000

7000Sub

sea

Tru

e V

ertic

al D

epth

(fe

et)

0 200

316 A-1

0 50

L1

Predicted from φMeasured in situ

JD

500

1000

1500

2000

Subsea T

rue Vertical D

epth (meters)

Gamma Ray

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

Sub

sea

True

Ver

tical

Dep

th (f

eet)

0 200

Pressure(MPa)

0 70

Predicted from φMeasured in situ

331 #1

JD

L1

500

1000

1500

2000

2500

3000

Subsea True V

ertical Depth (m

eters)

Figure 5

Figure 6

0 500 1000 1500 2000 2500 30000

500

1000

1500

2000

2500

3000

Measured Sand Overpressure (psi)

shale pressures lowerthan sand pressures

Cal

cula

ted

Sha

le O

verp

ress

ure

(psi

)

shale pressures higherthan sand pressures

Measured Sand Overpressure (MPa)

Calculated S

hale Overpressure (M

Pa)

5 10 15 20

5

10

15

20

a) b) c)

Tim

e 1

Tim

e 2

shale

land surface

8

9

1

▲3

land surface

sandshale

1

▲2

▲3

6

7

land surface

4

5

1

▲2 ▲2

▲3

0

2000

4000

6000

8000

10000

12000

14000

16000

Dep

th (

ft)

0 2000 4000 6000 8000 10000 12000 14000 16000Pressure (psi)

Pressure (MPa)20 40 60 80 100

Depth (m

)

1000

2000

3000

4000

▲1

4

5

6

7

8

9

hydrostatic pressure lithostatic stress

DP*

DP*

DP*

a

b

c

▲2

▲3

Figure 7

Figure 8

Sand and Shale Pressuresat the JD Horizon

Su

bse

a T

VD

(m)

3000 3500 4000 4500

5500

6000

6500

7000

Fluid Pressure (psi)

Su

bse

a T

VD

(ft

)

+

+

+++

hydrostatic gradient

+ SandShale

JD SandToplithostatic gradient (0.021 MPa/m)

gradient = 0.03 MPa/m

Pressure diff. at top =1.36MPa (198 psi)

Fluid Pressure (MPa)

1800

1900

2000

2100

22 24 26 28 30

1700

a) b)

Fluid Pressure (psi)4500 5000 5500 6000

6000

6500

7000

7500

Su

bse

a T

VD

(ft

)

Sand and Shale Pressuresat the L1 Horizon

lithostatic gradient (0.021 MPa/m)

hydrostatic gradient

+ SandShale

++

+

L1 SandTop

gradient = 0.021 MPa/m

Pressure diff. at top =3.96 MPa (574 psi)


Su

bse

a T

VD

(m)

1900

2000

2100

2200

32 34 36 38 40

Time 3 (t )3

Pressure

Dep

th lithostatic stress

hydrostatic pressure

▲

▲ shale pressuresand pressure

t1z1

Time 1 (t )1 Time 2 (t )2Pressure

Dep

th lithostatic stress


▲


▲

t 1

t2

z1

z2

added sediment thickness

z1

z2

z3

addedsedimentthickness

Pressure

Dep

th

lithostatic stress


▲


▲

▲

t 1

t2

t3sandDP*

Time 4 (t )4Pressure

Dep

th

lithostatic stress


▲


▲

▲

t 1

t 3t 4

z1

z2

z3

a) b)

c) d)

sandDP*

Figure 9

Figure A1

0 1000 2000 3000 4000 5000 6000

0

1000

2000

3000

4000

5000

6000

7000

Sub

sea

TV

D (

ft)


Evolution of Pressurein the JD SandFluid Pressure (MPa)

Subsea T

VD

(m)

500

1000

1500

2000

10 20 30 40t 1▲

t 2t3

t4▲

▲

▲


Evolution of Pressurein the L1 Sand

0 1000 2000 3000 4000 5000 6000 7000

0

1000

2000

3000

4000

5000

6000

7000

8000

Su

bse

a T

VD

(ft)


t 1

t2


▲t 3

▲


Su

bse

a T

VD

(m)

500

1000

1500

2000

10 20 30 40 50▲

▲

a) b)

land surface

x

z

L

qw

qw

dxno

flow

noflow

Sv

Documents

Pressure Differences Between Overpressured Sands and Bounding