Historical Highlight: Nelson Field

An ‘Enterprising’ North Sea Discovery

In 1973 British Gas discovered the Wytch Farm oilfield in Dorset, England, which, with its offshore extension, became Europe’s biggest “onshore” oilfield.

Then-Prime Minister Margaret Thatcher asked her energy secretary, Peter Walker, what state-owned British Gas was doing with an oilfield, and said that it must be sold to the private sector, which they did. Soon after she found out that British Gas also had some oil interests in the North Sea, operated by Amoco – and she said they also should be sold.

Walker then bravely suggested that these North Sea interests, which included minority stakes in five commercial oilfields and a small stake in 19 other northern and central North Sea blocks, might form the basis for a new British oil company.

“Jolly good idea!” Mrs. Thatcher reportedly said, “and it shall be called Enterprise Oil.”

Thus in 1983 was born a remarkably successful company that its employees proudly dubbed “the world’s greatest independent oil company.”

AAPG member J. Myles Bowen , who in April will receive AAPG’s Pioneer Award at the Annual Convention and Exhibition in Houston, was Enterprise’s second employee – and on April 1, 1984, he was appointed exploration director.

Bowen quickly set about staffing his department and designing a daring and aggressive exploration-intensive business strategy. The company’s activities began in the British sector of the North Sea and later were expanded to Norway, Vietnam, Italy, Malaysia, Brazil, the Gulf of Mexico and six other countries.

Enterprise’s successful first two years of farm-ins and small company acquisitions were to be topped by a venture that became headline news: the Nelson discovery in North Sea Block 22/11.

Four Duds …

UK North Sea Block 22/11, on the Forties Montrose High in the Central Graben area about 200 kilometers east of Aberdeen, Scotland, had seen a history of unsuccessful exploration involving five companies drilling four inconclusive wells over two decades.

♦The first well, 22/11-1, was drilled by Gulf in 1967 and had the Permian Rotliegendes Formation as its objective – which was found wet. Electric logs, however, indicated a “ratty” hydrocarbon-bearing uppermost Paleocene sandy interval with a gross column of 178 feet that on an open-hole drill stem test produced only water and oil-cut mud.

The well was not tested further.

♦Some five years later, in 1972, Conoco drilled a second well in the block that only found oil shows in the “ratty” Upper Paleocene sands.

♦Eleven years later Conoco drilled a third well that was also abandoned as a dry hole.

The chain of events that led to the discovery of the Nelson Field started in 1985, when Enterprise Oil and its partners carried out a detailed seismic survey over the Montrose Field and its undeveloped neighbor Arbroath in the block immediately south of Block 22/11, with the objective of convincing the authorities that the latter was a separate field, because that had important consequent tax benefits.

The resulting interpretation proved conclusively the two fields were separate Upper Paleocene Forties Formation accumulations, restricted laterally within NNW-SSE trending sand lobes and separated from each other by shaly “inter-channel” zones.

In 1985, as these studies continued, Enterprise entered into discussions with the Conoco/Chevron/Britoil group with a view to earn farm-in equity by drilling wells in nine of their blocks.

One of the blocks that Enterprise Oil had insisted be in the deal was 22/11.

The only data available to Enterprise Oil on the block was the Gulf well 22/11-1, plus a very old regional seismic well-tie line running from the UK coast to Norway passing across Gulf’s well. Geophysicist Dave Rhodes and geologist (and AAPG member) Mike Whyatt, working on the Montrose/Arbroath field separation issue, studied it, immediately saw the similarity and concluded that Gulf’s well 22/11-1 had penetrated a shaly Upper Paleocene “inter-channel” sequence – with good seismic evidence of thick channel sands immediately to the east and west.

The farm-in agreement for Block 22/11 dictated that Enterprise drill a well in the block’s southwest corner to test a decent Jurassic Fulmar Formation prospect. The well, the fourth in the block, was abandoned, as the objective was wet – but it did find a well-developed, yet wet, Upper Paleocene sand section.

… And a Gusher

Having drilled this commitment well, Enterprise then gained access to all the existing data – including a 3-D survey shot by Shell over the prospect, which reinforced its concept of a major Upper Paleocene exploration objective in the northeast corner of Block 22/11.

Enterprise, now with a 30 percent stake, informed the partners of its ideas about the first well on the block and proposed that the partnership re-drill the closure first tested by well 22/11-1 – but this was rejected by the partners.

It was at this moment that Enterprise made the strategic decision to concentrate its efforts on Block 22/11, and Bowen initiated a complex series of individual and discreet acreage swap negotiations with the other three companies. By early December 1987 Enterprise had executed all the necessary swaps and achieved its objective of controlling 100 percent of Block 22/11.

Enterprise Oil was so certain they would have a commercial discovery that they constructed a four-well template for the drilling of one deviated well each into each of two sand lobes, plus the option of drilling two further wells from the same location.

Well 22/11-5 was spudded on Dec. 19, 1987; well 22/11-6 was spudded three days later.

Both wells found the Forties Formation oil bearing, and the geoseismic model was borne out when well 22/11-5 came in at 6,720 bopd of 40.1 degree API oil and well 22/11-6 tested 10,224 bopd.

The field’s discovery was announced in March 1988, and a month later the Shell/Esso partnership proved the extension of the accumulation into adjoining Block 22/6a.

After Enterprise’s successful production tests the question arose as to what to name the new field. Bowen was in the office of CEO Graham Hearne, overlooking Trafalgar Square with Admiral Horatio Nelson’s statue in its center, and posed the question.

Graham just pointed out the window and said, “Look no further!”

Thus was named a field of about half a billion barrels of oil, one of the largest discoveries of the decade – an effort that capped a complicated series of business maneuvers that the UK daily newspaper Independent later described as “little short of brilliant.”

In 2002 Enterprise Oil was acquired by Royal Dutch Shell for $6.2 billion – a bid that its board of directors decided represented good value and recommended the shareholders to accept, which they did.

It marked the end of an independent operator that had shown a smaller company could have – and creatively apply – the technical and managerial expertise to outwit major ones.

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Historical Highlights

Historical Highlights - Hans Krause

Hans Krause is an AAPG Honorary Member, Distinguished Service Award winner and former chair of the AAPG History of Petroleum Geology Committee.

Historical Highlights

A History-Based Series, Historical Highlights is an ongoing EXPLORER series that celebrates the "eureka" moments of petroleum geology, the rise of key concepts, the discoveries that made a difference, the perseverance and ingenuity of our colleagues – and/or their luck! – through stories that emphasize the anecdotes, the good yarns and the human interest side of our E&P profession. If you have such a story – and who doesn't? – and you'd like to share it with your fellow AAPG members, contact the editor.

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A History-Based Series

This Historical Highlights article is the first of an EXPLORER series that tells the stories of how specific discovery wells came about, and key concepts and technology events that shaped the science and profession.

The series celebrates human ingenuity, cleverness and perseverance – or simply, luck – and emphasizes anecdotes and the human-interest side of the E&P profession.

The series is the brainchild of Hans Krause, a consultant in Caracas, Venezuela, and formerly of PDVSA and vice president of Shell Venezuela. Krause is an AAPG Honorary Member, Distinguished Service Award winner and chairman of the AAPG History of Petroleum Geology Committee.

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We describe the structure, microstructure, and petrophysical properties of fault rocks from two normal fault zones formed in low-porosity turbiditic arkosic sandstones, in deep diagenesis conditions similar to those of deeply buried reservoirs. These fault rocks are characterized by a foliated fabric and quartz-calcite sealed veins, which formation resulted from the combination of the (1) pressure solution of quartz, (2) intense fracturing sealed by quartz and calcite cements, and (3) neoformation of synkinematic white micas derived from the alteration of feldspars and chlorite. Fluid inclusion microthermometry in quartz and calcite cements demonstrates fault activity at temperatures of 195degC to 268degC. Permeability measurements on plugs oriented parallel with the principal axes of the finite strain ellipsoid show that the Y axis (parallel with the foliation and veins) is the direction of highest permeability in the foliated sandstone (10–2 md for Y against 10–3 md for X, Z, and the protolith, measured at a confining pressure of 20 bars). Microstructural observations document the localization of the preferential fluid path between the phyllosilicate particles forming the foliation. Hence, the direction of highest permeability in these fault rocks would be parallel with the fault and subhorizontal, that is, perpendicular to the slickenlines representing the local slip direction on the fault surface. We suggest that a similar relationship between kinematic markers and fault rock permeability anisotropy may be found in other fault zone types (reverse or strike-slip) affecting feldspar-rich lithologies in deep diagenesis conditions.
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We reviewed the tectonostratigraphic evolution of the Jurassic–Cenozoic collision between the North American and the Caribbean plate using more than 30,000 km (18,641 mi) of regional two-dimensional (2-D) academic seismic lines and Deep Sea Drilling Project wells of Leg 77. The main objective is to perform one-dimensional subsidence analysis and 2-D flexural modeling to better understand how the Caribbean collision may have controlled the stratigraphic evolution of the offshore Cuba region.

Five main tectonic phases previously proposed were recognized: (1) Late Triassic–Jurassic rifting between South and North America that led to the formation of the proto-Caribbean plate; this event is interpreted as half grabens controlled by fault family 1 as the east-northeast–south-southwest–striking faults; (2) Middle–Late Jurassic anticlockwise rotation of the Yucatan block and formation of the Gulf of Mexico; this event resulted in north-northwest–south-southeast–striking faults of fault family 2 controlling half-graben structures; (3) Early Cretaceous passive margin development characterized by carbonate sedimentation; sedimentation was controlled by normal subsidence and eustatic changes, and because of high eustatic seas during the Late Cretaceous, the carbonate platform drowned; (4) Late Cretaceous–Paleogene collision between the Caribbean plate, resulting in the Cuban fold and thrust belt province, the foreland basin province, and the platform margin province; the platform margin province represents the submerged paleoforebulge, which was formed as a flexural response to the tectonic load of the Great Arc of the Caribbean during initial Late Cretaceous–Paleocene collision and foreland basin development that was subsequently submerged during the Eocene to the present water depths as the arc tectonic load reached the maximum collision; and (5) Late Cenozoic large deep-sea erosional features and constructional sediment drifts related to the formation of the Oligocene–Holocene Loop Current–Gulf Stream that flows from the northern Caribbean into the Straits of Florida and to the north Atlantic.

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This three-day field trip will examine examples of tight-oil reservoirs (Cretaceous Niobrara Formation, Codell member of Carlile Formation from the Denver and North Park basins), tight-gas reservoirs (Cretaceous J Sandstone, Codell and Williams Fork Sandstone, from both the Denver and Piceance basins), CBM reservoirs (Cretaceous Cameo Coals from the Piceance Basin) and potential oil shale resources (Green River Formation of the Piceance Basin).
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