quantitative fault seal prediction_a case study from oseberg syd.pdf

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Quantitative fault seal prediction: a case study from Oseberg Syd

T. Fristad, A. Groth, G. Yielding and B. Freeman

We describe a case study from Oseberg Syd where fault-seal behaviour has been predicted from analysis of a detailed depth model in conjunc-

tion with detailed lithological control.

Juxtaposition seal of reservoir against non-reservoir can be assessed by fault-plane diagrams. Additional seal may be developed (at reservoir

juxtapositions) if fault-plane processes increase the capillary entry pressure. In Oseberg Syd, clay smearing is considered to be dominant because of

the relatively shaly nature of the Brent Group and the shallow burial depths during faulting (

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Table 1

Simplified stratigraphy of the Brent Group

Formation Depositional environment Permeability characteristics Sand quality

Draupne Shale Offshore Draupne Sand Turbidite fan Heather shale Offshore Heather 2 Lower to upper shoreface

Heather 1

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Middle Tarbert 2

Middle Tarbert 1 Lower Tarbert Upper Ness Middle Ness

Lower Ness Lower Ness sand

Oseberg/Rannoch/Etive

Lower shoreface to offshore transition zone

Lower to upper shoreface

Coastal lagoon, barriers, inlet channels

Coastal lagoon, swamp Lower shoreface to foreshore Upper to lower delta plain Upper delta plain (abandoned lobe, lacustrine, swamp) Upper delta plain Fluvial channel

Marginal marine delta deposits

Non-reservoir Strongly heterogeneous Non-reservoir Strongly layered, partly calcite cemented, moderate to poor permeability Strongly layered, partly calcite cemented, poor reservoir quality Strongly layered, moderate to poor permeability Strongly heterogeneous but many high permeable intercalations

Strongly heterogeneous Low to very high permeability Strongly heterogeneous, clay-rich Reservoir quality poor to absent

Strongly heterogeneous, clay-rich Stacked channel sand with high permeability Not significant reservoir unit

Mudstone Whole range Mudstone Fine to medium

Very fine to fine sand

Fine to medium sand

Whole range, medium to coarse sand forms an important component Whole range Very fine to coarse sand Whole range Predominantly fine grained components Whole range Coarse to medium grained sand Whole range

study area is presented in Table 1. A more compre- hensive description of the sequence stratigraphy within Block 30/9 can be found in MOiler and Van der Wel (1997).

Oseberg Syd- structural setting

The Oseberg/Oseberg Syd area lies between the Horda Platform and the Viking Graben, an area of Mesozoic extension. The study area comprises some 15-20 elongated fault blocks. Most faults within the Oseberg/Oseberg Syd region strike N-S to NNW- SSE, subparallel to the Viking Graben, in an anasto- mosing pattern. The areal extent of each fault block ranges from 250 km 2 to less than 10 km 2. An attempt to subdivide the area into structural sub-units outlined by major faults with offsets in the range 200-1000 m, is shown in Fig. 2.

Recent improvements in the seismic database in the Oseberg/Oseberg Syd region provided a significantly improved seismic interpretability, and a more confident fault interpretation has greatly enhanced the understanding of the structural framework. Local areas of excellent seismic data allow for interpretation of a comparatively large number of seismic reflectors within the Jurassic succession (Fig. 4). This facilitates a confident mapping of thickness variations across faults. Even without correction for differential com- paction, the section demonstrates a spectacular thickness increase of nearly 100% within the Brent, Dunlin and Statfjord Formations across the major fault between the Gamma and Omega structures. Similar thickness changes are mapped across several

major faults in the area, with a stepwise thickness increase across each of the major faults. There are fairly constant interval thicknesses within each main fault-bounded compartment (cf. Yielding et al., 1992).

Tectonic development

The spatial distribution of fault-related growth in the Oseberg Syd region is shown in Fig. 2. It can be concluded that most of the main faults (i.e., those that outline the key structural elements) were subject to substantial differential subsidence even prior to the main Late Jurassic rifting event. This indicates the existence of an early Viking Graben, exerting a strong influence on the Early to Middle Jurassic depositional systems. Furthermore, these faults were subject to accelerated differential subsidence in the Late Jurassic, recorded by substantial ex- pansion of the Viking Group (Heather/Draupne Fms). This Late Jurassic phase of extension and block rotation caused a collapse along the crests of the major fault blocks already established in the Lower/Middle Jurassic. A series of minor fault blocks was thus formed in the Oseberg Syd region during the Late Jurassic, possibly extending into the Creta- ceous.

In conclusion, the local thickness variations imply a relatively shallow depth of burial during the fault activity (below ca. 500m). Basin modelling and backstripping across the Oseberg area supports this statement (Roberts et al., 1993, 1995).

The Brent Group in general is quite shaly and,

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therefore, we might expect any observed sealing behaviour to be a consequence either of juxtaposition or of some mechanism of clay smearing. Because of the shallow depth of burial during faulting, the shales would be expected to be ductile. Thin sections and core fractures from C and J areas show clear indica- tions of smearing along small-scale faults in shaly sand intervals (Fig. 5). In more sandy intervals, fracture zones are observed where the fracture porosity is filled with fine-grained material. However, increased fault throw would probably smear clay along the entire fault surface.

Fault seal mechanisms

Most seals in clastic sequences are membrane seals (Watts, 1987). The dominant control on seal failure is the capillary entry pressure of the seal-rock, that is, the pressure required for hydrocarbons to enter the largest interconnected pore throat of the seal. A number of mechanisms have been recognised whereby fault planes can act as a membrane seal (e.g., Watts, 1987; Knipe, 1992): (i) Juxtaposition. Reservoir sands are juxtaposed

against a low permeability unit with a high entry pressure (e.g., shale).

(ii) Clay smear. Entrainment of clay or shale into the fault plane, thereby giving the fault itself a high entry pressure.

(iii) Cataclasis. Crushing of sand grains to produce a fault gouge of finer-grained material, again giving the fault a high capillary entry pressure.

(iv) Diagenesis. Preferential cementation along an originally permeable fault plane significantly increases the entry pressure.

Juxtaposition seals can be recognised explicitly by mapping the juxtaposition of units across the fault plane. To identify or predict sealing by clay smear, cataclasis or diagenesis requires an ability to relate these mechanisms to measurable properties of the subsurface (such as lithology and fault displacement), so that deterministic estimates of seal potential can be made. These different mechanisms and methods are discussed below. At present, significant success has been achieved in developing algorithms for prediction of seal capacity by clay smear (Fulljames et al., 1997; Yielding et al., 1997). It seems likely that seal by cataclasis may be similarly understood in the near future (Fulljames et al., 1997). Seal by diagenesis, however, will probably be much less amenable to prediction by simple algorithms.

Clay smear

The classic study of clay smear in a production en-

vironment is that by Bouvier et al. (1989), describing the Nun River Field in the Niger Delta. They present a predictive method of assessing whether clay smear is likely to be sufficient to form a membrane seal along the fault zone. A "clay smear potential" (CSP) is stated to represent the "relative amount of clay that has been smeared from individual shale source beds at a certain point along a fault plane". CSP is not defined explicitly by Bouvier et al., but is stated to: (i) increase with shale source bed thickness, (ii) increase with the number of source beds displac-

ed past a particular point along a fault plane, and (iii) decrease with increased fault throw.

Fulljames et al. (1997) give the algorithm for CSP as

T 2 (1)

where T is the thickness of the source bed, and D is the distance from the source bed.

Bouvier et al. calibrated their CSP calculations against known sealing and non-sealing faults, and divided the observed range into high, medium and low CSP. Low CSP represents little chance for the presence of continuous clay smear seals that can trap hydrocarbons.

Lindsay et al. (1993) describe outcrop studies of shale smears in a carboniferous fluvio-deltaic sequence in northern England. As in the study described above, Lindsay et al. concentrated on the ef- fects of individual shale beds in the sequence rather than the bulk properties of the sequence. Smear is observed to be thickest when derived from thicker source layers and with small fault throw values; smear thicknesses commonly decrease with distance from the shale source bed. From a study of 80 faults they conclude that shale smears may become incom- plete when the ratio of fault throw to shale layer thickness exceeds 7. Smaller ratios are more likely to correspond to continuous smears and therefore to a sealing layer on the fault surface.

Gibson (1994) presents observations from the Ter- tiary sand-shale sequence of the Columbus Basin, offshore Trinidad. From an analysis of fault-sealed hydrocarbon columns, he concludes that the more significant seals are developed where the ratio of fault throw to shale layer thickness is less than 4 (i.e., the shale bed is >25% of the displaced section).

The above studies suggest that sealing by clay smear may be predicted deterministically from a consideration of the thickness and offset of individual shale beds. However, such an approach is difficult to apply directly in the Brent Group because of the het- erogeneity of the sequence. It is not feasible to map

112 T. Fristad, A. Groth, G. Yielding and B. Freeman

Fig. 5. Thin-section taken from the Ness Fm (2408 m MD) in the 30/9-9 well (J structure). Note the concentration of clay minerals in the small fault.

Fig. 6. Diagram illustrating the calculation of SGR at a point on a fault surface. The throw (t) at the point is defined from the offset horizons. The "throw window" in the hangingwall represents the thickness of the rock that has slipped past the point. The SGR at the point is equal to the percentage of shale in the throw window. For units composed of "pure" shale and non-shale, SGR is the sum of the shale thicknesses divided by the throw. For units of given shale fraction, these fractions are used as weighting factors in the summation such that the result is the net shale percentage within all units in the window.


every shale bed and consider its effect at the fault surface. Therefore, we take here a simpler approach of considering only the bulk properties of the sequence at the scale of the reservoir mapping (later we show the equivalence of the two approaches by sensitivity analysis). We define a fault-surface attribute called the shale gouge ratio (SGR) which is simply the percentage of shale or clay in the slipped interval. Fig. 6 illustrates how this would be calculated at a point on a fault surface:

SGR - E (V~l Az) t

x 100% (2)

Vc~ is the clay or shale volume fraction in each interval of thickness Az and t is the fault throw at that point. The interval thicknesses are measured in a "window" with a height equal to the throw; this window therefore represents the column of rock that has slid past this point on the fault. The SGR represents, in a general way, the proportion of shale that might be entrained in the fault zone. The more shaly the wall rocks, the greater the proportion of shale in the fault zone and therefore the higher the capillary entry pressure. Whilst this is undoubtedly an oversimplifi- cation of the detailed processes occurring in the fault zone, it represents a tractable "up-scaling" of the lithological diversity at the fault surface; the required information is simply fault displacement and shale fraction through the sequence. SGR is approximately the reciprocal of "shale smear factor" (SSF) defined by Lindsay et al. (1993).

Direct observations of sub-surface pressure allow a calibration to be made between the SGR and seal capacity. Ideally, an in situ measurement of the pore- pressure in the reservoir and that inside the fault zone would allow the capillary entry pressure of the fault to be calculated. However, fault-zone pressures are rarely available. Instead, the pressure difference between the two walls of the fault is a more general parameter that can be derived from pressure measurements in pairs of wells across the fault. Fig. 7a shows one such calibration, based on the Nun River dataset of Bouvier et al. (1989). From their strike projections of Fault "K", values of SGR have been calculated on a dense grid across the fault surface. On the same grid, minimum across-fault pressure differences have also been derived, using the proven distribution of hydrocarbons in the footwall sands to calculate buoyancy pressures. Fig. 7a shows a cross-plot of these two parameters for the areas of sand-sand contact at the fault surface. The dashed line indicates the inferred relationship between SGR and seal capacity. At SGR < 20%, no fault-sealed hydrocarbons are observed; the shale content of the slipped interval

is too low. Above 20%, the maximum observed pressure difference progressively increases, reaching ca. 7 bars at a SGR of ca. 60% (for gas). The large cloud of points lying below the dashed line indicates that many points on the fault do not achieve their full seal capacity, because they lie at lower elevations in the structurally-controlled hydrocarbon columns. The line is important as a calibration in describing the maximum pressure difference supportable by that part of the fault, if other factors are favourable.

Interfacial tension (and, therefore, the entry pressure) for the gas-water system is typically as much as twice that for the oil-water system over a wide range of conditions (Schowalter, 1979). This suggests that the likelihood for seal is greater for gas than for oil. Therefore a given SGR value might be expected to sustain a greater pressure difference for gas than for oil. In Fig. 7a, the higher values of pressure difference (> 1 bar) are from gas caps, whereas the smaller pressure differences are generated by oil.

Fig. 7b shows a similar cross-plot, using data provided by Gibson (1994; his Fig. 8) from the Colum- bus Basin. In this plot, each data-point represents one reservoir top, with observations from many different faults. All reservoirs contain oil, and no gas. The distribution of points is similar to that in Fig. 7a, al- though with a slightly different position for the bounding line. The similarity of the plots is encour- aging, in that they represent data from different sequences in different areas. This implies that the SGR might be a useful predictive attribute across a range of environments. Detailed differences in the calibra- tions in different areas might possibly be due to factors such as shale lithology, degree of consolidation, fluid type, etc.

Cataclasis

Cataclasis is the brittle deformation of material in a fault zone, and typically involves grain breakage and comminution (often associated with improved pack- ing). This results in a significantly reduced grain size in the fault zone which can therefore support a pressure difference because of the increased capillary entry pressure. Knipe (1992) reviews microstructural studies of fault-zone rocks and notes that cataclastic fault gouge may have pore throat radii of


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gouge should be more likely at greater depth, and during reverse and strike-slip faulting rather than ex- tensional faulting. However, experimental studies (Mandl et al., 1977) show that some grain breakage

can occur at low overburden pressures, corresponding to only 100 m of burial.

Knipe (1992) makes the pertinent point that the nature of a fault zone will vary across the fault surface, depending on which lithotypes are being displaced. Clay smear may be significant over some parts of the fault surface, but cataclastic gouge may be developed where shale beds are absent. We should expect that the sealing capacity of a fault will often be highly variable over different parts of its surface, and simple whole-fault descriptions such as "sealing" and "non-sealing" may often be misleading. Any pressure difference across the fault would have to be supported by its weakest point.

Fault-seal methodology

Our approach in this paper has been to examine juxtaposition relationships and compute fault seal attributes on strike projections of fault surfaces. The analysis was carried out using FAPS software (Freeman et al., 1989; Needham et al., 1996).

The overall procedure was as follows: (i) produce depth cross-sections from mapped hori-

zon depth grids, incorporating reconstructed fault "sticks";

(ii) generate gridded representations of the individual fault surfaces, modelling their three-dimensional shape, displacement variation and horizon intersections;

(iii) construct a simplified geological layer model for the Brent Group, and interpolate this zonation into the mapped horizon intervals at the fault surfaces;

(iv) establish shale-volume fractions within each of the layers (reservoir zones) at each fault;

(v) calculate values of SGR over each fault surface, using fault displacement and layer shale-volume fractions;

(vi) compare SGR with pressure (RFT) data where available for well pairs across a fault.

Each of these steps is described in more detail below.

Depth sections All fault and fault-seal analysis was performed in

the depth domain, since this allows: (a) direct comparison with fluid contact levels, and (b) incorporation of additional geological informa-

tion such as zone isochores. Primary mapping of the subsurface, however, was performed on seismic data, in the time domain. The seismic interpretation was depth-converted by applying appropriate velocity models to the TWT grids. The faults are now represented as polygons on each


Horizon grids with fault polygons Cross-sections with reconstructed fault segments Fig. 8. Diagram illustrating how vertical depth sections of a fault can be reconstructed from fault polygons and horizon grids. The points defining the fault segments on the sections correspond to the centre-lines of the polygons on the depth grids.

of the horizon surfaces, and information about the vertical correlation of faults between horizons is lost. An important part of the analysis was therefore the reconstruction of the fault planes in depth. Depth grids for the primary mapped horizons (Base Creta- ceous, Top Lower Tarbert, Base Brent, Top Cook and Top Statfjord) were available at a 50 x 50 m grid node spacing. Most of the faults in the study area trend approximately N-S and therefore the strategy adopted was to sample the depth grids on E-W rows to create a suite of sections at 50 m spacing (486 in total). Taking each horizon grid in turn, in conjunc- tion with its fault-polygon file, an automated search of the grid rows was made in order to locate the posi- tions of the horizon cutoffs at the faults. Fault "sticks" on the cross-sections were generated by joining the centre-line points of corresponding fault polygons on successive horizons: the position of each point is defined by the x,y information from the polygon and the z data from the grid (see Fig. 8). These fault segments were then labelled according to the fault surface to which they belong.

Gridded fault surfaces The x,y,z information of a group of fault segments

is used to construct a grid that accurately matches the three-dimensional shape of the fault plane. This grid is the base on which all the calculations of fault attributes are performed. In this study, the larger faults were gridded at 100 x 100 m, the smaller faults at 50 x 50 m. The primary information for displacement and stratigraphic computations is the geometry of the horizon/fault intersections. Gaps between horizons and faults are corrected for by applying a "snapping" procedure (see Needham et al. (1996) for further dis- cussion). Taking the depth difference between the upthrown and downthrown cutoffs of the same horizon gives the throw at that point on the fault. These measurements are used as the control points for pro-

ducing a grid of throw variation over the entire fault surface.

Geological layer model In addition to the mapped horizons (i.e., those im-

ported from the grids), additional horizons such as the intra-Brent zonation were interpolated into the fault models by reference to the primary, mapped horizons. Detailed isochore maps for the study area were constructed on the basis of well data and seismic charac- ter mapping. Five to seven zones were recognised within the Brent Group, with an additional overlying sand in the Heather Formation. The additional horizons are posted onto each fault grid in one of two ways: firstly, as a fixed distance (thickness) above or below a primary horizon, or secondly, at a fixed percentage of the interval between two primary horizons. Posting of these horizons for both the footwall and hangingwall side of the fault results in a detailed and geometrically-robust juxtaposition plot.

Shale-volume data Petrophysical analysis of the well data was used to

define the shale fraction in each stratigraphic unit. CPI logs were used to derive explicit shale percent- ages within both "sandstone" units (e.g., 5% shale in the Lower Ness Sandstone) and "shale" units (e.g., 65% shale in the upper part of the Dunlin Group). This information was then compiled geographically to estimate likely compositions between the wells, i.e., at the fault locations. Example profiles of shale- volume fractions are shown in Fig. 9.

Shale gouge ratio Having constructed the fault grid, with detailed

juxtapositions and compositional data for all layers, we calculate a SGR. It was stated earlier that the fault surfaces were gridded at 100 x 100m or 50 x 50 m. Whilst this is adequate for analysis of displacement

1 16 T. Fristad, A. Groth, G. Yielding and B. Freeman

(a) (b) Fig. 9. Schematic illustration of the shale-fractions for (a) Fault 1 (G structures) and (b) Fault 9 (J structures). Note that the lowest fraction of shale for Fault 1 is within the upper part of the interval (Tarbert Fm), whereas for Fault 9 it is found in the lower half. The total Brent thickness in (a) is approximately four times the thickness in (b).

variation, it cannot capture the detailed stratigraphic variation that affects the SGR calculation. A grid re- finement was therefore applied when calculating SGR, replacing each original grid node by 5 x 5 new nodes. At each node, the local throw value defines the height of a "search window" in the hangingwall (cf. Fig. 6). Within the search window, the program measures the thickness of each unit (down the fault plane) and combines these with the units' shale fractions to calculate the net shale percentage in the search window. By definition (Eq. (2)) this is equal to the local SGR at that point on the fault.

The window over which shale values are summed could be in the footwall or hangingwall. In the ab- sence of sedimentary growth across the fault these will be identical. If growth has occurred then an aver- age of the two is more appropriate. In the Oseberg Syd dataset there is some growth across some of the faults; however it is often not possible to use data from the footwall "window" because there has been erosion. Therefore, SGR has always been calculated using the hangingwall "window".

ment is static (pre-production) it is possible to project these pressure profiles to adjacent faults. With a cross-fault well pair, the pressure profile can be constructed in both the footwall and hangingwall of the fault, on the same refined grid as that used for the SGR calculation. Comparison of across-fault pressure differences with SGR at every point on the fault allows any relationship between the two to be exam- ined. This relationship can then be extrapolated to those faults where well control is lacking, i.e., SGR can be used to constrain predictions of potential pressures (and hence hydrocarbon columns) in untested compartments.

Fault descriptions

The poor seismic data quality in the C and J structures limits the reliability of the fault seal analysis in these areas. Consequently, the description below is focused upon the good quality seismic of the western area of Block 30/9 (Omega, B and G). The eastern area is covered in more general terms.

Comparison with pressure data Where wells are present on both sides of a fault,

we calibrate the SGR attribute with pressure data. Detailed RFT data permit the construction of pressure profiles at the wells, and since the pressure environ-

Fault I

Fault 1 is located in the south-west part of the study area in the G area (see Fig. 3). The maximum throw observed on this fault is about 175 m, dimin-


a

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Fig. 10. Strike projections of Fault 1, viewed from the downthrown (west) side; vertical exaggeration x5. (a) Juxtaposition plot. Upthrown Brent zones are shown with coloured fill (see legend); downthrown zones are shown in black outline, labelled at each end of the fault. Footwall hydrocarbon contacts are shown in black, hangingwall contacts in blue. (b) SGR for the area of Brent-Brent overlap. Upthrown zones outlined in blue, downthrown zones in black; contacts as in (a). SGR is colour-coded in the ranges 0-15%, 15-20%, 20-30% and >30%. Note the area of slightly lower SGR on the upper part of the overlap zone; this is the critical area for fault seal.

ishing to zero displacement towards the south. The G East and G Central aquifers are therefore in communication around the southern end of the fault. The pattern of juxtaposed Brent zones on the fault is shown in Fig. 10a. Note the considerable area of Brent-Brent overlap: maximum fault offset is about half the Brent thickness. Wells are located both in the

footwall (30/9-13S) and hangingwall (30/9-14) and have different hydrocarbon columns, and so this fault provides a good calibration point with respect to the SGR calculation. The hangingwall oil-water contact is probably controlled by a structural spill-point (saddle) along the southern part of the fault. The fault is therefore probably not at seal capacity, and the

1 18 T Fristad, A. Groth, G. Yielding and B. Freeman

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calibration below represents a minimum potential for seal on this fault surface.

The display of SGR on the fault surface (Fig. 10b) uses the shale fractions observed in the ad jacent wells. Since the fault displacements are generally greater than the zone thicknesses, the calculated SGR values are relatively homogeneous. However, a significant point is the area of lower values (in yellow,


Brent overlap zone. For fault seal, the significant question here is: which points on the fault are capable of holding back a large pressure difference for a relatively small SGR? Such points represent the critical areas for seal, and in Fig. 12 they will lie to the upper left of the cross-plot. A SGR of ca. 18% is capable of sustaining a pressure difference of almost 8 bar, and slightly higher SGRs (23%) can sustain 9.5 bar. These points correspond to the uppermost part of the reservoir-reservoir overlap zone: in Fig. 10b they occur at and just above the yellow area ca. 1 km from the north end of the fault. This part of the fault is holding back the higher-pressured gas column in the hangingwall.

As with Fig. 7, Fig. 12a shows many data points that represent smaller pressure differences than the maximum, for a given SGR. These points correspond to structurally lower parts of the fault surface, for example near the hangingwall fluid contacts. Here seal is probably well-developed, but the in situ pressure difference is small.

To test the sensitivity of the analysis a detailed template consisting of 65 layers within the Heather Fm and the Brent Gp was generated (Fig. 13a). The resulting SGR plot (Fig. 13b), shows only minor differences compared to the coarse model (Fig. 10b). This is because Eq. (2) tends to reduce the effect of stratigraphic complexity as the throw increases. As a rule of thumb, the detail of the stratigraphic template needs to be at the same order of scale as the minimum throw in the area of interest. The plot of pressure differences versus SGR (Fig. 12b) reveals more or less the same trend as observed in Fig. 12a, but with a SGR of 17% sustaining an 8.3 bar pressure difference.

The fault demonstrates static sealing since it sepa- rates two hydrocarbon columns with a maximum pressure difference of 9.5 bar. Accordingly, this fault can be used for calibration of the calculated SGR values. The lowest calculated SGR value above the HC contacts is slightly below 20% (ca. 18%), indicating that for other faults having a SGR value in the same range, static sealing up to ca. 8 bar differential pressure could be anticipated (for gas as the high pressure phase). Eight bars differential pressure corresponds to about 240 m difference in OWC or 106 m difference in GWC, for single-phase hydrocarbon columns and typical densities (gas 0.25 g/cm 3, oil 0.66 g/cm 3, water 1 g/cm3).

Fault 2

Prior to the drilling of well 30/9-14, the ca. E-W fault located 350-450 m to the south was regarded as a block-bounding fault (see Fig. 3 for location). The

fault has a minimum displacement of about 15-20 m at its centre and consequently the different units within the Tarbert Fm are juxtaposed against themselves (self-juxtaposed) (Fig. 14a).

The SGR values within the Tarbert Fm juxtaposition are close to 15% (Fig. 14b). DST testing of well 30/9-14 indicated the fault to be open, as the closest barrier to flow was interpreted to be 810 m away.

Implications from this fault and Fault 1 therefore suggest that a SGR below or close to 15% corresponds to no seal and SGR above-18-20% corresponds to significant seal. This is a very tight range, but it remains quite consistent throughout the dataset.

Fault 3

This fault was selected to investigate the segmentation of the B structures and for calibration purposes with respect to Fault 1 (see Fig. 3 for location).

The maximum displacement lies between the branch lines with Faults 1 and 7, and the displacement decreases southwards. Just north of the southern branch with Fault 4, the uppermost part of the Tarbert and Heather Fms (oil and gas) are juxtaposed against the lower parts of the Tarbert Fm (water), with about 2 bar pressure difference. In addition, the SGR values are just below 20% or higher, indicating by analogy that the observations from Fault 1 can be applied to this fault as well.

Between B South and B North, the SGR is above 20%, which agrees well with the different fluid contacts and pressure regimes observed in wells 30/9-7 and 30/9-4S (ca. 5 bar pressure difference). In the central part of the fault (between G Central and B South), over 8 bar pressure difference is observed, at a SGR of ca. 28%.

Fault 4

Just north of the southern branch line with Fault 3, the displacement on Fault 4 is at a minimum (Fig. 3). The throw is in the order of 15-30 m, and a large area with SGR of 15-20% is observed, implying that there is a likelihood of having no seal, or a slight static seal across the fault. In the area of low SGR values, the Tarbert Fm is juxtaposed above the OWC in a re- stricted area only. This could explain the slight differences in OWC between the two compartments (B South and Omega South). With respect to the aquifer, it is likely that the B structure is in communication with the Omega South structure, because the area of juxtaposition is increased. The water gradient in well 30/9-7 is almost equal to the gradients in well 30/9-8 and 30/9-10.

The gas in the B North compartment is separated


El

b

Fig. 13. Strike projections of Fault 1, using a detailed (65-layer) stratigraphic template (cf. Fig. 10). (a) Juxtapositions. Upthrown units are colour- filled, downthrown units shown outlined. The colour-coding is: yellow, 40% shale. (b) SGR. In comparison with Fig. 10b, note low values on upper part of fault, and increased variability at south (fight) end of the fault where the throw decreases to zero.

from the Omega North structure by a 5 bar pressure difference, and on this part of the fault the SGR is about 24%.

Fault zone 5 and 6

This fault zone most likely explains a difference in OWC of about 30 m between Omega North and

Omega South (Fig. 3). Unfortunately the seismic data quality is poor, and the definition of the details of the zone is difficult to elaborate. Consequently the two mapped faults separating the structures were analysed together. Where the throw on one fault decreases, the throw on the other increases accordingly. This obser- vation strongly suggests that this pair of faults developed simultaneously and partitioned the displacement


between them. It might therefore be expected that the overlap zone has distributed strain, and may have unresolved small faults linking the two main faults.

The SGR variations along-strike where units within Tarbert Fm overlap are between 15 and 20% and minor faults linking the two main faults can be expected to have a SGR profile similar to that seen in the tip regions of the mapped faults (between 15 and 17%). The observed kinematic linkage of the large faults, in combination with a consideration of the SGR, therefore leads to an interpretation of the fault zone as being able to support a small differential pressure (less than 1 bar) in the area of Tarbert juxtaposition. This is sufficient to explain the differences in OWC observed in wells 30/9-8 and 30/9-10.

The faults described above all have wells located on either side of the fault. In Fig. 15, a summary of the SGR versus across-fault pressure difference is plotted for critical oil and gas values along the different analysed faults. One fault can have several values depending on how many compartments are present on each side of the fault. For example the points for Fault 4 represent the segments where Omega North is juxtaposed against B North and B South, respectively. The purpose of compiling this essential infor-

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Fault 1. G-Central (30/9-14) against G-East (30/9-13S) Fault 2. intra-G-Central (-14 DST) Fault 3. B-North (-4S) against B-South (7) Fault 3m. G-Central (-14) against B-South (7) Fault 3s. G-East (-13S) against B-South (7) Fault 4. B-North (-4S) against Omega North (-3,-3A) Fault 4s. B-South (-7) against Omega North (-3,-3A) Faults 5/6. Omega North (-8) against Omega South (-10)

Fig. 15. Summary diagram indicating the observed relationship between SGR and across-fault pressure difference for all analysed faults in the study area. Each point represents the "critical" part of the fault surface, i.e., maximum pressure difference for small SGR values.

mation in one figure is to make predictions for faults where sufficient well control points are lacking. For the faults described below, SGR distributions were used to predict likely seal capacities and therefore constrain the occurrence of hydrocarbons in undrilled compartments.

Fault 7

An E-W syncline defines a separate closure north of the 30/9-14 well. Analysis of Fault 7 was consequently performed in order to conclude whether a HC-column could be trapped in the hangingwall to the B West structure or not (Fig. 3).

The fault has its minimum displacement (ca. 75 m) where it branches with Fault 3. In this area the SGR is just below 20% or higher, and by analogy with Fault 1, the potential for having a trapped HC-column at the extension of G Central is good. In addition, a gas column is more likely to be present rather than an oil column, increasing the possibilities for a static seal.

The B West structure itself has not been tested by wells, but by analogy with Fault 3 (separating wells 30/9-4S and 30/9-7), a differential pressure across the fault between B West and B North could be anticipated as the throw is of the same order of magnitude.

Fault 8

This fault is an example of a number of cross- faults intersecting Omega South (Fig. 3). The throw decreases towards the NW, and along-strike the different units within the Tarbert Fm, except Lower Tarbert Fm, are self-juxtaposed. Where Middle Tar- bert 2 and Upper Tarbert Fms are juxtaposed, the SGR varies between 15 and 20% possibly introducing small pressure differences across the fault. Because the area south of well 30/9-10 is intersected by several of these NW-SE striking faults, it is likely that different HC-contacts could be present. The difference in OWC across each separate fault, however, is probably not more than 10-15 m (or about 0.5 bar).

Fault 9

In light of the poor seismic data quality on the C and J structures the SGR calculations in these areas should be treated as guidelines rather than an exact definition of the individual faults. Fault 9 was selected in order to focus upon internal segmentation in the J structures (Fig. 3).

The R2A unit of the Lower Ness Fm consists of a sheet of relatively homogeneous and clean channel sands. The thickness variation of the sheet is around


Fig. 14. (a) The juxtaposition profile of Fault 2 (upper left) shows that the lowest value of throw is located at the centre of the fault (ca. 15 m). (b) SGR (lower fight) below 15% are found where the Middle Tarbert 2 unit is self-juxtaposed. This area of low SGR is not likely to behave as a pressure barrier. Note that the low SGR is found in the upper part of the interval as illustrated in Fig. 9a.

Fig. 16. The SGR for Fault 9 reveals that the lowest values are found in the lower part of the Brent Group. The weakest point with respect to leak would consequently be expected to be found in the lower one third of the Brent Gp, whereas the upper two thirds would be expected to seal well.


10-20 m where present. In addition, the shale percentage is as low as 8%. Consequently, where the sands are juxtaposed against themselves, clay smearing is probably absent and here, cataclasis is more likely than in the western area.

The calculated SGR is generally above 20%, except for the R2A unit, where it is less than 15% in areas of small throw. If the SGR thresholds that we have obtained on the G structures are representative for the C structure, the upper two-thirds of the Brent Group juxtaposition are expected to seal well, and the lower part would be open to flow (Fig. 16). Note that this is in contrast with the faults in the western area, where seal is poorest on the upper parts of the faults (Tarbert Fro).

Conclusions

A fault-surface attribute called the shale gouge ratio (SGR) has been defined for calculation of clay smearing in the heterogeneous Brent Group sequence. The attribute corresponds simply to the percentage of shale in the slipped interval. Furthermore a methodology for incorporating this fault related attribute into the evaluation of sealing properties has been imple- mented in the Oseberg Syd area. The SGR is variable over the fault surface, varying as the displacement changes and depending on the lithology of the wall rocks. Therefore the predicted sealing properties vary over the fault surface. The following observations are seen.

Western area

Throughout the western part of Block 30/9, clay smearing and sealing by juxtaposition seem to be the main contributors to static seal. In light of the growth observed across most of the faults in this region, such a conclusion seems appropriate. However, the observed range of SGR, from non-seal to considerable static seal, is extremely tight, but remains quite consistent in light of the fluid contacts and pressure data in the 30/9 wells. Seal capacities for the individual faults are plotted in Fig. 15. Note that the highest seal capacities are observed where the gas is the higher pressure phase. The following is observed:

SGR < 15% 15% < SGR < 18%

SGR > 18%

no seal expected slight seal expected (


terpretation and fault sealing investigations, Nun River Field, Ni- geria. Am. Assoc. Pet. Geol. Bull., 73: 1397-1414.

Engelder, J.T. 1974. Cataclasis and the generation of fault gouge. Geol. Soc. Am. Bull., 85: 1515-1522.

Freeman, B., Yielding, G. and Badley, M.E. 1989. Fault correlation during seismic interpretation. First Break, 8: 87-95.

Fulljames, J.R., Zijerveld, L.J.J., Franssen, R.C.M.W., Ingram, G.M. and Richard, P.D. 1997. Fault seal processes. In: P. M~ller- Pedersen and A.G. Koeslter (Editors), Hydrocarbon Seals: Im- portance for Exploration and Production, NPF Special Publication 7. Elsevier, Singapore, pp. 51-59.

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from the southern Oseberg area. In: K.O. Sandvik, F. Gradstein and N. Milton (Editors), Predictive High Resolution Sequence Stratigraphy, NPF Special Publication, in press.

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Roberts, A.M., Yielding, G., Kusznir, N.J., Walker, I. and Dorn- Lopez, D. 1993. Mesozoic extension in the North Sea: constraints from flexural backstripping, forward modelling and fault popula- tions. In: J.R. Parker (Editor), Petroleum Geology of Northwest Europe: Proc. 4th Conf., Geol. Soc. London, pp. 1123-1136.

Roberts, A.M., Yielding, G., Kusznir, N.J., Walker, I. and Dorn- Lopez, D. 1995. Quantitative analysis of Triassic extension in the northern Viking Graben. J. Geol. Soc., 152: 15-26.

Schowalter, T.T. 1979. Mechanics of secondary hydrocarbon migra- tion and entrapment. Am. Assoc. Pet. Geol. Bull., 63: 723-760.

Watts, N. 1987. Theoretical aspects of cap-rock and fault seals for single- and two-phase hydrocarbon columns. Mar. Pet. Geol., 4: 274-307.

Yielding, G., Badley, M.E. and Roberts, A.M. 1992. The structural evolution of the Brent province. In: A.C. Morton, R.S. Haszeldine, M.R. Giles and S. Brown (Editors), Geology of the Brent Group. Geol. Soc. Special Publication 61. pp. 27-43.

Yielding, G., Freeman, B. and Needham, D.T. 1997. Quantitative fault seal prediction. Am. Assoc. Pet. Geol. Bull., 81:897-917.

T. FRISTAD A. GROTH G. YIELDING B. FREEMAN

Norsk Hydro, P.O. Box 200, N-1321 Stabekk, Norway Norsk Hydro, P.O. Box 200, N-1321 Stabekk, Norway Badley Earth Sciences Ltd., North Beck House, North Beck Lane, Hundleby, Spilsby, Lincolnshire, PE23 5NB, UK Badley Earth Sciences Ltd., North Beck House, North Beck Lane, Hundleby, Spilsby, Lincolnshire, PE23 5NB, UK

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