Ocean Bottom Seismic could discover new oilfields in North Sea

Using Ocean-Bottom Seismic (OBS) Surveys to Evaluate the Remaining Potential of the North Sea

Cost reductions from operational and technological improvements will make exploration shear wave 3D seismic surveys an economic reality

by Brendan J Keating,  Geophysics Consultant advising OPC

In 1984, whilst drilling UK North Sea Britannia Field appraisal Well 16/26-5 (which was targeting Lower Cretaceous sands), Chevron and partners made a chance discovery of oil within the overlying Middle Eocene sands. The structure was difficult to map using the available 2D seismic lines but a NW-SE trending elongate feature could be determined. Later appraisal wells (including Well 16/26-7 which found 300 feet of oil-bearing sands) proved the presence of a large oil accumulation with a STOOIP of 900 million barrels. The discovery was subsequently named Alba Field.

A high-quality marine streamer 3D seismic survey was acquired over the field in 1991. The data showed the presence of a strong seismic event at the oil-water contact. However the top of the Middle Eocene sandstone reservoir (the Nauchlan Sandstone Member of the Alba Formation) was imaged poorly, presenting challenges in locating the early production wells. But analysis of shear wave sonic logs recorded in the wells (Moore, 2015 & MacLeod et al., 1999) indicated that there were large contrasts in shear wave velocities at the top and base of the Nauchlan Sandstone (Figure 1.)

This raised the possibility that a shear wave 3D seismic survey might improve the reservoir imaging greatly. An ocean-bottom cable (OBC) 3D seismic survey was acquired in 1998 with the aim of recording both P-wave and mode-converted shear wave (PS) data. This shear wave 3D seismic survey provided a dramatic uplift in imaging the Nauchlan Sandstone reservoir and proved to be a “step change” in the development of Alba Field.

Figure 1. Dipole sonic log from a single well (A05) showing a large contrast in S-wave velocity at the top and base of the Alba Sands, with small contrast in corresponding P-wave (Moore 2015 & Macleod et al. 1999.)

Figure 2 shows an example of the huge improvement in the imaging of the top reservoir seismic event on the converted shear wave data (and shear impedance data) compared to the P-wave data (Moore, 2015.)

Figure 2. Seismic depth sections across Alba Field, (a) P-wave seismic (b) Converted shear wave data (c) Shear impedance data (Moore 2015.)

Two years after the discovery of Alba Field UK North Sea Well 22/2a-5, which was targeting a Forties Sandstone prospect, also made a chance find of oil in the Middle Eocene Nauchlan Sandstone. The discovery, named Chestnut Field, was located SE of Alba Field along the same structural trend. However with a STOOIP of around 40 to 60 million barrels it was much smaller than Alba Field. It too was difficult to map on the seismic data due to the lack of acoustic impedance contrast between the oil-bearing Nauchlan Sandstone and the enveloping shales.

Figure 3. Comparison of P-wave and shear wave 3D seismic data over Chestnut Field. (Wood & Moore 2009.)

P-wave and mode converted (PS) shear waves were recorded over the field in a non-exclusive OBC 3D seismic survey acquired by WesternGeco in 1999/2000. This survey enhanced the illumination of the Top Nauchlan Sandstone in the same way as Alba Field (Figure 3) and helped to optimize the locations of the production wells (Wood & Moore, 2009.) Chestnut Field was brought onstream in 2008.

Missing Oil Fields?

Therefore in 34 years there have been just two commercial discoveries (one large and one small) within the Middle Eocene Nauchlan Sandstone of the UK North Sea. Are these the only two fields to be found in the Middle Eocene?

It’s geologically possible but seems unlikely. There are plenty of commercial fields within the underlying Lower Eocene and Palaeocene sandstones. Given the large area of the North Sea it would not be unreasonable to expect the existence of at least one or two further Middle Eocene fields in the 300 to 600 million STOOIP range, with an outside chance of finding a field larger than Alba. The main limiting factors would include the extent of the Middle Eocene sands, the extent and integrity of the shale seals and the locations of the oil migration routes through the Palaeocene/Eocene shales.

Are we missing some Middle Eocene fields simply because the rock physics of the sandstone reservoirs makes them difficult to image on conventional P-wave seismic data? If so, how do we find them?

There is an argument that a Middle Eocene oil field the size of Alba would be visible on P-wave data because of the strong amplitude response at the oil-water contact. However the Alba Field flat spot was not recognised as such until the P-wave 3D seismic survey was acquired, seven years after the field discovery. Furthermore the Chestnut Field is very difficult to image on the P-wave 3D seismic data.

The obvious solution might be to shoot exploration shear wave 3D seismic surveys in the North Sea. But the big problem here has been the huge cost of acquiring shear wave surveys. As every geophysicist knows shear waves are dependent upon the rigidity of the rocks for their transmission and therefore do not travel through water. Hence it’s impossible to record shear wave data with conventional P-wave marine streamer acquisition methods. But shear waves are generated from P-waves by mode conversion within the rock layers and it is these PS waves (sometimes called C-waves) which are recorded by receivers resting on the sea bed.

The laying out of cable-connected receivers on the sea bed in the OBC acquisition method is a much slower and more difficult process than towing marine streamers behind a boat. Therefore OBC acquisition costs have historically been very high, typically in excess of US$100,000 per sq. km. In comparison a narrow azimuth marine 3D streamer survey could be acquired for significantly less than US$10,000 per sq. km.

The high cost of OBC surveys has forced Operators to restrict them to the evaluation of producing fields where it could be demonstrated that shear wave data would add real value to the development. But in doing so it was also noticed that the quality of the P-wave seismic data acquired using OBC methods was often far superior to that obtained from marine streamer surveys. Much of this superiority stemmed from the better signal-to-noise ratios, wider bandwidths, longer offsets and full azimuth capabilities of OBC surveys. Furthermore the shear wave 3D surveys were found to be excellent at imaging reservoirs which had been obscured by gas clouds within the overburden.

Over the last 25 years Operators have increasingly become more willing to spend money on acquiring OBC surveys Worldwide. In addition many producing fields now have permanent ocean-bottom receivers to enable seismic monitoring of reservoir fluid movements over time (4D seismic.) And because the airgun source boat does not have any streamers in tow, the OBC method is ideal for acquiring 3D seismic data in areas crowded with platform obstructions.

The Gulf of Mexico has been in the forefront of the development of ocean-bottom seismic (OBS) acquisition methods. But the deep water of the Gulf of Mexico placed limits on the ability to acquire shear wave seismic data using the OBC method. A better OBS acquisition method was needed.

Research and development throughout the 1990s and early 2000s led to improvements in the ocean-bottom node (OBN) method of seismic acquisition. This method, which had previously been limited to scientific seismic surveys, uses “nodes” which are small battery-powered integrated 4-component receiving and recording devices. They are placed on the sea bed by remote operating vehicles (ROVs) at the required receiver intervals. The airgun source boat can then shoot in any desired direction, shotpoint interval or distance (free from attachment to the nodes) to provide full azimuth, high fold and long offset seismic data.

The first oil-industry OBN 3D seismic survey was acquired in 2004 over Pemex’s Cantarell Field in the Gulf of Mexico. Further developments since then have included node-on-a-wire (NOAW) and Marine Autonomous Seismic Systems (MASS) aimed at improving the operational efficiency of node deployment. Node-based acquisition methods have been so successful that the OBC system is now virtually obsolete. OBS systems can now be used to acquire 3D seismic surveys in water depths up to 3000 m.

OBS Cost Reductions

The continued investment in technologies and operational methods by OBS acquisition companies have led to costs coming down. For example in 2017 it was announced that Petrobras had awarded a contract to Seabed Geosolutions (a Fugro/CGG JV) to acquire 1,600 sq. km. of 3D seismic data in the Santos Basin, offshore Brazil, using the OBN method. The contract was valued at US$90 million giving a cost rate of approximately US$56,250 per sq. km.

This is still a high rate compared to conventional marine streamer acquisition costs. But the OBS companies believe there is scope for further cost reductions in the near-term. Improvements in operational methods have the potential to make deployment efficiency 30% better. And tests have shown that very high-quality P-wave and shear wave 3D seismic data can be acquired with sparse-spaced nodes. Translated into money these improvements will bring down OBS acquisition costs to under US$40,000 per sq. km., putting them on a par with conventional full azimuth marine 3D seismic surveys.

At first glance an Exploration Manager working in the North Sea might think this was still too high to justify acquiring an exploration shear wave 3D seismic survey. But even at this rate a typical UK Central or Northern North Sea block (area = 254 sq. km.) could be covered completely with a high-quality shear wave 3D seismic survey (plus an equally high-quality P-wave 3D seismic survey) for around US$10 million. This is considerably less than the dry hole cost of a well to a Tertiary target. Cost reductions from operational and technological improvements in OBS will make exploration shear wave 3D seismic surveys an economic reality.

Where should we look?

When exploration shear wave 3D seismic surveys become economic in the North Sea where should we look for the missing Middle Eocene oil fields?

Figure 4 (Mudge & Bujak, 1996) shows the distribution of Middle Eocene (Alba) and Upper Eocene (Grid) Sequences in the North Sea. I’ve added the Quadrant numbers and the locations of Alba and Chestnut Fields. The maps suggest that the initial areas of focus should be the southern parts of UK Quadrant 16 and Norwegian Quadrant 15 (to the East of Alba and Chestnut Fields) where the Alba Sequence is most likely to be sealed by shales from the Horda Formation.

Figure 4. Distribution of Middle and Upper Eocene Sands in the North Sea (Mudge & Bujak 1996.)

However the Alba Sequence sands are distributed across at least six quadrants in the UK and Norwegian North Sea. We can use this information to make a guesstimate of the number of Middle Eocene fields yet to be found. The six quadrants contain 180 blocks. If we assume that a quarter of these blocks contain one drillable Middle Eocene prospect each, and that the average chance of success of the combined Central and Northern North Sea is about 1 in 6, then there should be about 7 or 8 fields in total. As two have already been discovered then there should be 5 or 6 Middle Eocene fields yet to be found in the Central and Northern North Sea.

..there should be 5 or 6 Middle Eocene fields yet to be found in the Central and Northern North Sea.”

Much of the acreage within these six Quadrants is held under licence. Therefore geoscientists and Exploration Managers working in these areas may wish to consider evaluating their acreage for the possibility of Middle Eocene prospects and leads. This would be a relatively low-cost step. An evaluation strategy might include the following:

  • Updates to the regional Middle and Upper Eocene sand distribution maps using data from recent wells.
  • Generation of Horda Formation (shale seal) distribution maps.
  • Interpretation of the existing P-wave 3D seismic surveys to generate isochrons of the Eocene units to highlight possible sand fairways and leads.
  • Search for possible oil migration routes (including sand injectites) through the shales at the Palaeocene/Eocene boundary.

In addition it would still be worthwhile examining the existing P-wave 3D seismic data for flat (or flattish) spots and other direct hydrocarbon indicators that might point to possible fields.

Once the Middle Eocene leads and prospects have been identified then outline plans for 3D shear wave surveys could be generated and costed. The surveys need not cover the entire block but could be focussed on the leads and prospects, thereby reducing costs further.

In this report I’ve focussed on the application of exploration shear wave 3D seismic surveys to the specific problem of searching for Middle Eocene prospects in the North Sea. But cost reductions will lead to exploration shear wave 3D seismic surveys being acquired elsewhere in the North Sea, in the West of Shetlands and in many more marine locations Worldwide. Their full potential is not yet known. What new field discoveries will they lead us to?


Brendan J Keating,
Consultant Geophysicist
October 2018

BRENDAN_KEATINGBrendan Keating is an Interpretation Geophysicist who has worked on assets in over 60 countries Worldwide including the UK, Dutch and Norwegian North Sea, Russia, Kazakhstan, China, SE Asia, North, Sub-Saharan and West Africa, South America and New Zealand. He has worked for a range of companies from start-ups to majors (including ARCO and Conoco) and spent five years in investment banking at Jefferies Randall & Dewey in London. He is now a geophysics consultant advising OPC in the further development of the geophysics services

Contact Brendan on +44 20 7428 1111 or by email .


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