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University of Aberdeen

Interpreting the Subsurface.

GL4529

Producing 3D models for a better understanding of

structural interpretations and assessment of potential

reservoirs of the Gullfaks Field, northern North Sea.

Andrew Moyle

51228528

BSc Geology & Petroleum Geology (2016)

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Table of Contents: Page

Abstract……………………………………………………………………………………………………………………………3

1.) Introduction ……………………………………………………………………………………………………………. ….4

1.1.) Regional Setting…………………………………………………………………………………………….4

1.2) Stratigraphy…………………………………………………………………………………….……………..4

1.3) Tectonic Setting…………………………………………………………………………………………..…4

2.) Methodology………………………………………………………………………………………………………..……..5

2.1.) Petrel…………………………………………………………………………………………………………….5

2.1.1) Interpreting Top Cretaceous and Bottom Cretaceous………………………..5

2.1.2) Creating a 3D surface…………………………………………………………………......6

2.1.3) Interpreting Faults…………………………………………………………………………..7

2.1.4) Interpreting Tarbert 1……………………………………………………………….…….8

2.2 Move………………………………………………………………………………………………………….…..9

3.) Results…………………………………………………………………………………………………………………….....10

3.1.) Fault Interpretation…………………………………………………………………………………...…10

3.2.) Brief Tectonic History of the Faults………………………………………………………….…….11

4.) Discussion – Location of a potential reservoir …………………………………………………………...12

5.) Conclusion …………………………………………………………………………………………………………………13

6.) References………………………………………………………………………………………………………………...

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Abstract

The Gullfaks Field is located on the western flank of the Viking Graben, where it occupies the eastern half of a 10-25km wide, NNE-SSW-trending fault block. The Gullfaks Field has been under production since 1986, covering an area of ±75km2 and developed by 3 concrete platforms under Statoil, Norsk Hydro and Saga Petroleum. Total recoverable reserves are located in the Jurassic Brent Group, Cook Formation and Statfjord Formation. By making use of Petrel software, the user can produce 3D models to help visualise and better understand subsurface structures. By incorporating Move software and making use of the block restoration model tools, one can test the validity of the fault and horizon geometry interpreted in Petrel. It is observed that the block-bounding faults in this area have unusually low dips (25-30 degrees to the East) whereas the sedimentary strata dip gently (typically about 15 degrees) to the West. Variation in dip between different stratigraphical units suggests that there is internal ductile deformation present within individual fault blocks. This may be due to the heterogeneity of the internal deformation within the blocks, allowing differences in movement of the faults. Grain reorganisation processes are also thought to constitute an important part of the internal block deformation. By making use of the seismic and wireline data in Petrel, potential reservoir units in the Etive, Ness and Tarbert Formations were assessed. Taking the thickness and the reservoir quality into consideration, the Intermediate Top Ness- Ness 1 Unit (44.76m thick) in Well C1 could potentially be a good reservoir. This reservoir could be taken into consideration despite of its lower quality, in comparison to the better, but thinner Tarbert reservoirs. By making use of RMS amplitudes, bright reflectors can be observed under the Top Ness- Ness 1 horizon, indicating the possible presence of hydrocarbons in the unit. This bright reflector continues across the field, suggesting that hydrocarbons could be present in all of the Ness- Ness 1 units.

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1.) Introduction

1.1.) Regional Setting

The Gullfaks Field is located on the western flank of the Viking Graben, where it occupies the eastern half of a 10-25km wide, NNE-SSW-trending fault block. The extensional history of the North Sea dates back to the Devonian extensional phase shortly after the Caledonian collision (McClay et al. 1986).

The main subsequent rifting phases are commonly referred to as the Permo-Triassic and late Jurassic phases

(Badley et al. 1988). Whereas the extension in the Permo-Triassic event is significant (Roberts et al. 1995),

the late Jurassic deformation of the Jurassic sequence is more obvious on commercial seismic lines, and best

known from well data. This study is concerned with deformation of Late Triassic-Jurassic layers in the Gullfaks

area, and therefore with the late Jurassic extension phase.

1.2) Stratigraphy

The deepest well was drilled to about 3350m depth and penetrated 1340m of Triassic sands and shales of

the Lunde and Lomvi Formations (Hegere Group). The base of the Triassic has never been reached in this part

of the northern North Sea, and little is therefore known about early and pre-Triassic strata. (Fossen, 1998)

The 370-420m thick Dunlin Group is subdivided into the Amundsen, Burton, Cook and Drake Formations.

Amundsen and Burton Formations consist 170-180m of marine claystones and siltstones overlain by the

regressive, marine, silty claystones of the lower part of the 110-160m thick Cook Formation, and in turn by

muddy sandstones, sands and shales of the upper part of the Cook Formation. The 75-120m thick Drake

Formation comprises marine shales with varying amounts of silt. (Fossen, 1998)

The Brent Group are mainly of Bajocian-Early Bathonian age. It is sub-divided into the Broom (8-12m),

Rannoch (50-90m), Etive (15-40m), Ness (85-110m) and Tarbert (75-105m) Formations, all deposited in a

deltaic environment. A broad lithological sub-division can be made between the shaly Ness Formation and

the sandy intervals below and above. (Fossen, 1998)

The major time gap (up to 100Ma) is represented by the base Cretaceous unconformity on the Gullfaks Field,

separating Upper Cretaceous sediments from Jurassic or Triassic sediments, and post-dating the major part

of the faulting history of the area. (Fossen, 1998)

1.3) Tectonic Setting

Two structurally distinct sub-areas are observed: a major domino system and an eastern horst complex

(fig.1.1). The western domino region constitutes the main part of the Gullfaks Field. The deformation in this

part of the field has resulted in a series of generally N-S-trending fault blocks. They have displacement in the

range 50-500m (Fossen, 1998). The Main faults in the domino system have very low dips 25-30 degrees; in

horst complex 65 degrees. Most minor faults are steep in all parts

of the field. The Domino area underwent significant internal

deformation (drag) resulting in low acute angle between bedding

and faults, and non-planar bedding geometries. Much of the shear

deformation occurred by strain-dependent grain reorganization in

the poorly consolidated Jurassic sediments, which led to decrease

in porosity.

Fig.1.1.) The areal distribution of the domino system, the horst complex and the

accommodation zone on the top Statfjord fault map (Fossen, 1998).

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2.)Methodology

2.1.) Petrel

2.1.1) Interpreting Top Cretaceous and Bottom Cretaceous

The Top Cretaceous was mapped on an Inline shot on every 10th seismic interval and used as a reference horizon line (fig 2.1). This horizon line was chosen as the brightest blue reflector above the Base Cretaceous identified in the well (C4).

Fig.2.1) Top Cretaceous horizon line mapped on Inline (light blue line)

The Top Cretaceous was then mapped on the X-Line shot on every 10th seismic interval, using points generated from the Inline horizon line as a reference (fig.2.2).

Fig.2.2) Top Cretaceous horizon line mapped on X-Line

(light blue line)

An Arbitrary line was then created to ensure that the Top Cretaceous horizon lines drawn on Inline and X-Line Shots were in the correct place (2.3). This arbitrary line makes use of more wells to cross reference drawn horizon lines

Fig.2.3) Top Cretaceous horizon line mapped on X-Line (light blue line

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To further ensure that the horizon lines are drawn accurately, the cosine of the phase was used. This method was used to map reflectors with major amplitude discontinuity (see fig. 2.4 & 2.5 for an example)

Fig.2.4) Top Cretaceous horizon line adjusted on normal inline after using the cosine of the phase. A- Before, B - After

Fig.2.5) Top Cretaceous horizon line adjusted using the cosine of the phase. A- Before, B - After

2.1.2) Creating a 3D surface

Once the horizon lines of the Top Cretaceous have been mapped, the lines form a mesh-like structure of lines in 2D. The polygon is then created and acts as the boundary for the surface of the Top Cretaceous. A surface can then be constructed using the newly created polygon and existing horizon mesh (Fig 2.6). A 3D view surface can be viewed in a 3D window (fig 2.7).

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Fig.2.6) Polygon, horizon line mesh, and arbitrary lines; B- Top Cretaceous surface in 2D

The same process as above was used for creating horizon lines and a 3D surface of the bottom cretaceous.

Fig.2.7) Final 3D surface of the Top Cretaceous (A) and Bottom Cretaceous (B) (after smoothing).

Polygon Horizon mesh Arbitrary Line Top Cretaceous Surface

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2.1.3) Interpreting Faults

Faults were identified by the displacement of major reflectors (Fig 2.8). The displacements of reflectors were only visible in the Inline seismic images. The Faults were mapped in using the same method as horizon line mapping and on every 10th seismic interval (Fig.2.9).

Fig.2.8) Displacement of major reflectors are identified (Black Arrows) and then interpreted (Yellow Line)

Fig.2.9) Major faults identified along an Inline Shot Polygons and surfaces are then created of every individual fault using the same process as used for horizon surfaces (fig 2.10)

Fig.2.10) Final 2D (A) and 3D (B)

surface of the of the faults

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The variance volume attribute was used to see if it improves the mapping of the faults (fig.2.11). The bright red lines appear to be discontinuous when they reach a fault that is drawn in. This could indicate where the fault blocks are, but would not entirely rely on this method as the red lines appear to be scattered and not entirely related to faults.

Fig.2.11) Variance volume attribute shows that red lines either stop at fault boundaries (Black Ring) or are scattered elsewhere.

2.1.4) Interpreting Tarbert 1

The Tarbert 1 horizon was identified using the well horizon data (fig.2.12). Due to the faults present, there are many discontinuities in this horizon. By making use of the arbitrary line method as mentioned above, the Tarbert 1 horizon lines were drawn in more accurately. As the horizon lines for Tarbert 1 are discontinuous, individual polygons were created to allow the creation of Tarbert 1 surfaces (fig 2.13)

Fig.2.12) Tarbert 1 Horizon line mapped (yellow). Discontinuities in horizon due to faults.

Fig.2.13) Individual polygons in 2D of Tarbert 1 created around faults (A); 3D Surface of Tarbert 1 and associated faults (B)

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2.2 Move

Move (v.2015.1) software was used for block restoration of the interpretations made using Petrel Software. By doing a block restoration, the validity of a structural interpretation of faulted stratigraphy can be determined.In order to test the validity of the fault and horizon geometry, the model needs to be decompacted and each fault block needs to be restored and balanced independently. Space problems (such as mismatches) identified in the restored section are used to improve the interpretation. Line 726 was extracted to Move from Petrel. Horizons and Fault lines were then interpreted and polygons were created (fig.2.14).

Fig.2.14) Interpretation of Horizons and Fault lines (A) and Polygons of stratigraphy (B)

The model was then decompacted by using the decompaction module (post-fault sedimentation removed) and restored to represent original deposition state (By using block restoration module and unfolding module). Tarbert 1 was used as a reference line (fig.2.15).

Fig.1.14) Block restoration of model

Fig.2.15) Present structures and stratigraphy (A) and final block restoration model (B)

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One particular Top Etive horizon did not match up in the block restoration model (fig.2.16). This indicates that either the Tarbert 1 reference line or the Top Etive Horizon line was interpreted wrong. Large gaps in between the fault blocks could either indicate erosion around fault planes, or poorly interpreted faults.

Fig.2.16) Top Etive horizon did not match up with Top Etive horizon to the left (black box)

3.) Results

3.1.) Fault Interpretation

The fault geometry observed in the Petrel seismics indicate that the faults are perpendicular to beds (or

stratigraphy). The fault blocks are trending in a N-S direction (see Fig.2.12). The faults appear to be steeply

dipping and are slightly curved. According to Fossen (1998), the block-bounding faults in this area have

unusually low dips (25-30 degrees to the east) whereas the sedimentary strata dip gently (typically about

15 degrees) to the west. The reason as to why the faults interpreted on Petrel appear to dip steeply could

possibly be that the seismics observed are focused only on the Brent Group rather than the older

sedimentary rocks (as described by Fossen, 1998. See fig.3.1.).

The presence of 1.) Normal faults that curve, 2.) Steep fault planes at the top of the structures (and

potentially shallow dipping overall), and 3.) Many repetitive fault blocks could indicate a major domino system present.

Fig. 3.1 also shows the variation in dip between

different stratigraphical units (not observed on

Petrel). This observation suggests that there is

internal ductile deformation present within individual

fault blocks. Additional deformation of sediment units

can be the result of minor faulting (observed but not

interpreted). Fossen (1998) suggested that grain

reorganization processes (rotation and sliding) played

an important part in the internal fault block

deformations, resulting in possible deformation

bands.

3.2.) Brief Tectonic History of the Faults

The Jurassic Brent group was deposited, followed by a series of normal faults forming simultaneously due to an extensional regime. Fault blocks began to rotate due to the deformation within the fault blocks. The fault blocks may have possibly moved at different times relative to each other. This may be due to the heterogeneity of the internal deformation within the blocks, allowing differences in movement of the faults. Fossen (1998) suggests that there are six main faults present. These faults initiated the deformation of the area and formed further minor faulting.

Fig.3.1.) Seismic line showing the difference in dip between

the Brent Group and the Statfjord Formation (fossen, 1998)

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4.) Discussion – Location of a potential reservoir

Line 726 containing Well B8 and an arbitrary line created between wells C1 C4 B9 and B4 was used to assess potential reservoirs in the Gullfaks Field. Wells B2, C1, C4 and B8 were focused on (Fig 4.1).

Reservoir quality was assessed using 5 main factors: Permeability, Gamma, Porosity, Net-Gross, and reservoir thickness. A good reservoir would ideally have high permeability and porosity values, low gamma values, a high Net-Gross (very sandy as opposed to muddy), and large thick unit of the potential reservoir. In this case, reservoir quality can omit the presence of seals. An intermediate reservoir has fluctuating factors that would not be as good as ‘good reservoir quality ‘. A poor reservoir has the worst factors compared that of a good or intermediate reservoir, but not as low to be considered a seal. Units with the worst factors (e.g. N/G = 0, or Gamma= 150gAPI) are considered as seals. Unit thicknesses were measured using the wireline logs. The check shot depths give the thickness of a formation as a whole (Tarbert being between 80.96m – 96.85m), whereas thicknesses of individual units (reservoirs of different qualities) within a formation can be calculated using wireline log depths.

The following tables assess reservoir qualities in Well B2, C1, C4, B8 (using wireline logs in fig.4.1 and wireline log data from the Petrel program).

TABLE 1 - WELL B2

Reservoir Interval Notes

Base Cretaceous – Ness 1

Very thin reservoir with intermediate quality.

Top Etive - Top part of the unit is intermediate in quality. Higher porosity: 20% and permeability: 150mD. Good Net-Gross, though still a high frequency of interbedded muds.

TABLE 2 - WELL C1

Reservoir Interval Notes

Top Tarbert - Tarbert 2 Very good reservoir quality. High permeability: 550mD, Low gamma 45gAPI, good porosity: 15% .High net-gross, though has thin interbedded mudstones. Thickness: 18.65m

Tarbert 2 – Tarbert 1 Poor reservoir, low Net-Gross (Thick interbedded mudstone), Relatively high gamma: 85gAPI, Relatively low porosity: 10%.

Top Ness- Ness 1 Intermediate reservoir quality, High Permeability: 300mD, Relatively low Gamma: 60gAPI, relatively good porosity: 14%, Net-Gross fluctuates but mainly good with a lot of thin interbedded muds. Large reservoir, Thickness: 44.76m

Top Etive - Intermediate reservoir quality. Permeability, Porosity and Gamma better than Top Ness- Ness 1. Net-Gross poor, thick interbedded mudstones.

TABLE 3 - WELL C4

Reservoir Interval Notes

Top Tarbert - Tarbert 2 Very good reservoir quality. High permeability: 320mD, Low gamma: 42gAPI, Relatively high porosity: 15%. Net-Gross: Has thin interbedded mudstones. Thickness: 19.1m. Similar to Top Tarbet - Tarbet 2 in Well C1.

Tarbert 2 – Tarbert 1 Reservoir quality changes from poor (top of unit) to intermediate quality (bottom of unit)

Top Ness- Ness 1 Intermediate reservoir quality. High permeability: 200mD, Low Gamma: 65gAPI, Relatively high Porosity: 16%. Net-Gross fluctuates. Similar to Top Ness- Ness 1 in Well C1, but thicker interbedded muds.

Top Etive - Intermediate reservoir quality, relatively good permeability: 150mD, Low Gamma: 60gAPI, Relatively high Porosity: 18%. Net-Gross fluctuates, thick interbedded muds.

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5.) Conclusion

The use of Petrel extensively assisted in the interpretation of the horizons and faults present in the Gullfaks Field. The use of a multitude of seismics and available well data (such as wireline logs) on Petrel allows the user to produce 3D models of geological structures. This aids in a better visualisation and a better understanding of the structures observed. By incorporating a second software (Move) and making use of the block restoration model tools, the validity of the fault and horizon geometry interpreted in Petrel can be tested. Petrel gives the option of mapping after a certain number of line intervals (e.g. every 1, 2, 5, 10 or 100 etc.). The smaller the interval, the more accurate the horizon lines and structures can be mapped. The software (Petrel and Move) also do not do correct adjustments to lines, leaving interpretations entirely to the user. The leads to question the reliability in the accuracy of the software as they cannot fix human error.

By making use of the seismic and wireline data in Petrel, potential reservoir units were identified. The best reservoirs were identified in the Top Tarbert –Tarbert 2 Units in Well C2, C4, and B8, all having high porosity, high permeability, low gamma ray response, and a good Net-Gross with thin interbedded mudstones present. All of these good reservoirs are relatively thin (12.41m – 19.1m). The good reservoir in B8 does not have a seal present, which could prevent potential hydrocarbon trapping.

Taking the thickness of a reservoir into consideration, the Top Ness- Ness 1 Unit in Well C1 could potentially be a good reservoir. This unit is intermediate in quality (see Table 2) but rather large in thickness (44.76m). This could suggest a large accommodation space for hydrocarbons. This reservoir could be taken into consideration as good potential reservoir despite its lower quality in comparison to the better, but thinner Tarbert reservoirs in Well C2, C4, and B8. By making use of RMS amplitudes (fig.4.2), bright reflectors can be observed under the Top Ness- Ness 1 horizon, indicating the possible presence of hydrocarbons in the unit. This bright reflector continues across the field, suggesting that hydrocarbons could be present in all of the Ness- Ness 1 units.

6.) References

Badley, M. E., Price, J. D., Dahl, C. R. & Agdestein, T. 1988. The structural evolution of the northern Viking Graben and its bearing upon extensional modes of basin formation. Journal of Geological Society, London, 145, 455 472. Fossen, H., Hesthammer, J. (1998) ‘Structural geology of the Gullfaks Field, northern North Sea’, in Coward, M.P., Daltaban, T.S. and Johnson, H. (eds.), Structural Geology in Reservoir Characterization. Geological Society, London, Special Publications, 127, pp. 231-261.

Mcclay, K. R., Norton, M. G., Coney, P. & Davis, G. H. 1986. Collapse of the Caledonian orogen and the Old Red Sandstone. Nature, 323, 147-149.

Roberts, A. M., Kusznir, N. J., Walker, I, M. & Dorn-Lopez, D. 1995. Quantitative analysis of Triassic extension in the northern Viking Graben. Journal of the Geological Society, London, 152, 15-26.

TABLE 4 - WELL B8

Reservoir Interval Notes

Top Tarbert - Tarbert 2 Very good reservoir quality. Permeability: 300mD, Gamma: 65gAPI, Porosity: 30%. Net-Gross: Has thin interbedded mudstones. Thickness: 12.41m (thin in comparison to other reservoirs in C1 and C4)

Tarbert 2 – Tarbert 1 Intermediate reservoir quality. Good Permeability: 130mD, relatively high gamma: 75gAPI, Relatively high Porosity: 25% Net-Gross fluctuates, a lot of thin interbedded muds.

Top Etive - Very thin reservoir of good quality found at the top of Top Etive, Thickness: 10.86m. The reservoir decreases in quality (intermediate) moving deeper down the Etive unit. Low porosity and thick interbedded muds (poor Net-Gross).

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