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The Impact of Declining Major North Sea Oil Fields Upon

Norwegian and United Kingdom Oil Production

Roger D. Blanchard

Department of Chemistry

Northern Kentucky University

Highland Heights, KY 41099-1905

Phone: (606) 572-6552

FAX: (606) 572-5162

e-mail: blanchard@nku.edu


There has been a growing debate concerning the direction of future global oil production.  Several prominent international petroleum geologists have written numerous papers expressing the view that world oil production will peak in the not too distant future, possibly before 2010.1,2,3  They base their assessment on a 1956 model developed by the petroleum geoscientist M. King Hubbert.  The Hubbert model assumes that if oil production is unrestrained in a very large producing region, it will follow a bell-shaped curve with peak production occurring when approximately 1/2 of the ultimately recoverable amount of oil is extracted.  Figure 1 is a graph of oil production versus time for the U.S. lower 48 states.  For this paper, oil is considered crude oil plus condensate.  Historical oil production in the U.S. lower 48 states approximates a bell-shaped curve with peak production occurring in 1971 and a decline after the peak of approximately 4.5 million barrels/day (mb/d) by 1999 (~ 48%).

Figure 1: Historical Oil Production

For the U.S. Lower 48 States

The opposing view that oil production will increase far into the future is expressed by organizations such as the U.S. Department of Energy/Energy Information Administration (U.S. DOE/EIA) and the American Petroleum Institute (API).4,5,6  These organizations project a significant expansion of world oil production in the future due to the application of advanced oil production technology.  Matthew Simmons, in a February 1999 World Oil article, introduced another factor to the debate.7  He discussed the problem of declining oil fields in many producing basins around the world and the impact of these declining fields on global oil production.  He wondered what the average depletion rate may be for declining oil fields and how that will influence long-term supply.  This paper provides data for net depletion rates, after efforts to enhance production, in one important oil production region of the world. 

The North Sea has been a major oil production province since its first significant production in the middle 1970s.  In 1998, North Sea oil production represented nearly 9% of world oil production.8  North Sea fields were selected for this analysis because high quality data are available for individual oil fields, because the North Sea has been a key factor in increasing non-OPEC oil production over the last 20 years, and because the best available technology is used in the North Sea.  Norway and the United Kingdom (U.K.) are the main oil producing countries in the North Sea and major oil fields within these two countries will be analyzed.  In this paper, a major field is considered one with an estimated ultimate recovery (EUR) of greater than 100 million barrels oil (mbo).  There are approximately 35 major Norwegian oil fields and 55 major U.K. oil fields in the North Sea.  Masters et al. (1994) assessed the total EUR (all fields) for Norway at approximately 30 billion barrels oil (bbo) and the U. K. at approximately 36 bbo.9  U.K. field data from 1976 through 1997 were obtained from Oil & Gas Journal.  Field data for Norway from 1978 through 1997 are from Oil & Gas Journal and 1998 field data from the Norwegian Petroleum Directorate (NPD).

Seven major Norwegian fields peaked prior to 1995 and 29 major U.K. fields peaked prior to 1994.  Table 1 provides data for the Norwegian major oil fields in decline.

Table 1

Norwegian Major Oil Fields in Decline with Maximum Production Levels Prior to 1995

Fields

Estimated Ultimate Recovery

(mbo)a

Maximum Production Year

Maximum Production

(b/d)10

1998 Production

(b/d)11

Decline from Maximum Prod. to 1998 Prod. (b/d)

% Decline from Maxi-mum Prod. to 1998 Prod.

Tor

>130

1979

80,361

5,981b

74,380b

92.6b

Eldfisk

>450

1980

118,166

40,570b

77,596b

65.7b

Statfjord

4,500

1991

741,532c

315,145d

426,387

57.5

Ula

420

1992

133,000

29,256

103,744

78.0

Gyda

230

1992

68,000

32,198

35,802

52.6

Gullfaks

2,500

1994

530,000

338,846

191,154

36.1

Oseberg

2,800

1994

502,644

415,467

87,177

17.3

a Values were determined by plotting annual production versus cumulative production and extrapolating to the x-axis for data after the maximum production level

Using 1997 production figures from Oil & Gas Journal.  The Norwegian Petroleum Directorate does not have individual field data for Tor and Eldfisk in 1998

c Sum for Norway plus the U.K.  Norway has an 85.5% share and the U.K. a 14.5% share of Statfjord

d U.K. 1998 production for Statfjord was obtained from Statoil 


Table 2 provides data for the U.K.'s major oil fields in decline.

Table 2

U.K. Major Oil Fields in Decline with Maximum Production Levels Prior to 199410

Fields

Estimated Ultimate Recovery (mbo)a

Maximum Production Year

Maximum Production

(b/d)

1997 Production

(b/d)

Decline from Maximum Prod. to 1997 Prod. (b/d)

% Decline from Maximum Prod. to 1997 Prod.

Auk

>120

1977

58,690

13,301

45,389

77.3

Piper

1,100

1979

276,758

49,334

227,424

82.2

Forties

2,700

1980

523,000

85,660

437,340

83.6

Thistle

420

1982

129,662

8,868

120,794

93.2

Ninian

1,200

1982

304,806

48,323

256,483

84.1

Heather

110

1982

37,767

4,948

32,819

86.9

Maureen

230

1984

85,374

9,044

76,330

89.4

Claymore

650

1984

103,600

40,529

63,071

60.9

Murchisonb

390

1984

109,145

22,753

86,488

79.2

Brent

2,400

1985

439,843

132,751

307,092

69.8

Beatrice A&B

>160

1985

57,649

9,334

48,315

83.8

Buchan

>120

1985

39,000

9,123

29,877

76.6

South Brae

270

1986

97,879

8,962

88,917

90.8

Fulmar

550

1986

156,962

11,474

145,488

92.7

North Cormorant

>250

1986

100,998

30,170

70,828

70.1

N.W. Hutton

140

1986

52,785

6,318

46,467

88.0

Dunlin

390

1987

103,273

16,315

86,958

84.2

Tartan

140

1987

35,110

6,775

28,335

80.7

Clyde

140

1988

51,443

14,337

37,106

72.1

Hutton

210

1988

63,012

15,959

47,053

74.7

S & C Cormorant

300

1988

122,400

20,775

101,625

83.0

Eider

120

1990

40,548

13,381

27,167

67.0

North Brae

145

1990

80,400

7,690

72,710

90.4

North Alwyn

250

1991

92,058

18,304

73,754

80.1

Balmoral

120

1992

28,050

9,756

18,294

65.2

Arbroath

280

1992

35,478

23,600

11,878

33.5

Scapa

140

1992

28,128

18,247

9,881

35.1

Magnus

800

1992

155,400

64,644

90,756

58.4

Beryl

1,100

1993

110,849

77,260

33,589

30.2

a Values were determined by plotting annual production versus cumulative production and extrapolating to the x-axis for data after the maximum production level

b Production figures for Murchison are the sum of production for the U.K. plus Norway.  The U.K. has a 77.8% share and Norway has a 22.2% share of Murchison

The 7 major oil fields in Table 1 constitute approximately 37% of Norway's total EUR and the 29 major oil fields in Table 2 constitute approximately 42% of the U.K.'s total EUR based upon Masters' EUR values.  Several aspects of the data in Tables 1 and 2 are worth noting.  First, the application of modern technology in the extraction of oil has not prevented rapid production declines in major North Sea oil fields.  It actually contributes to the high rates of decline by accelerating the rates of extraction and the subsequent rates of decline.  Second, not all oil fields decline at the same rate due to a variety of factors, but all fields in Tables 1 and 2 that have been in decline for at least 6 years have total declines of more than 50% from their maximum production levels. 


Figures 2-7 are graphs of field production versus year for the 3 Norwegian and 3 U.K. oil fields that achieved the highest production rates.  For the 3 Norwegian fields, the last data point is the average production rate for the first 9 months of 1999.  The substantial drop off in production for the Ninian field in 1984 and Brent field in 1990 are indicative of technical difficulties that occasionally led to extended shutdowns and reduced production rates in oil fields.

Figure 2


 

Figure 3


Figure 4

 

Figure 5


Figure 6

 

Figure 7

Figure 8 shows the summed oil production versus time for Norwegian oil fields in Table 1.  The decline in summed oil production for these fields has been 675,492 b/d  (36.1%) since 1994. 



Figure 8: Summed Production for Norwegian Oil Fields

In Table 1

Figure 9 shows the summed oil production versus time for U.K. oil fields in Table 2.  The decline in summed oil production for these fields has been 1,482,064 b/d  (65.0 %) since 1988.


 

Figure 9: Summed Production for U.K. Oil Fields

In Table 2

Many of the major fields in the North Sea are now in decline.  To counteract the rapid decline of mature fields, new but smaller fields are being brought on-line at an accelerated rate.  As an example, in Norway 23 out of 34 fields (67 %) listed in the Sept. 1999 Field Data Press Release by the NPD have start-up dates after January 1, 1993.  In the U.K. sector of the North Sea, the 200th oil and gas field was recently brought on-line.12  It took 25 years for the first 100 fields to be brought on-line but only 6 years to bring the second 100 fields on-line.  According to the U.S. DOE/EIA, the average EUR of new U.K. oil fields is approximately 50 million barrels.13  That is small compared to the large early U.K. fields (see Table 2).  The fields that are now being brought on-line in both the U.K. and Norway are coming on-line at or near maximum production and many will have lifetimes of 10 years or less.  In an extreme example, the Durward and Dauntless fields were brought on-line in August 1997 and were terminated in April 1999. 


As an oil province becomes more extensively explored, there are fewer places to search for new fields.  The North Sea has been extensively explored and consequently the oil discovery rate has been declining.  This is illustrated in Figures 10 and 11.  Figure 10 is a graph of cumulative oil discovery versus the cumulative number of wildcat oil wells for Norway.

Figure 10: Cumulative Discovery versus

Cumulative Wildcats for Norway

Figure 11 is a graph of cumulative oil discovery versus the cumulative number of wildcat oil wells for the U.K. sector of the North Sea.


Figure 11: Cumulative discovery versus cumulative wildcats

for the U.K. sector of the North Sea

The curves in Figures 10 and 11 suggest that the EUR values for Norway and the U.K., estimated by Masters et al., are not unrealistic.  Virtually all of Norway's oil is located in the North Sea but the U.K. has oil in areas other than the North Sea.


            At the end of 1998, 11.7 bbo had been produced in Norway and 16.8 bbo had been produced in the U.K.  Based upon Hubbert's model, the current rates of oil production, and the EUR values from Masters et al., Norway's total oil production, for all fields, would peak in approximately 2001 and the U.K.'s total oil production, for all fields, would peak in approximately 1999.  Figure 12 is a plausible oil production curve for Norway based upon Masters' EUR value for Norway.  Oil production through 1998 represents historical data and production after 1998 represents projected production. The total area under the curve represents 30 bbo and the decline rate after the peak is

7.2 %/year.

Figure 12: Historical and Projected Production for Norway

Figure 13 is a plausible oil production curve for the U.K. based upon Masters' EUR value for the U.K.  Oil production through 1998 represents historical data and production after 1998 represents projected production.  The total area under the curve represents 36 bbo and the decline rate after the peak is 5.0 %/year.  A 1995 report by the U.K. Offshore Operator's Association projected a similar 5%/year decline rate after peak production to 2020 for U.K. offshore production.14


Figure 13: Historical and projected production for the U.K.

            The U.S. DOE/EIA has been very optimistic concerning the impact of technology on future oil production.  In their 1999 International Energy Outlook, they project that oil production from the North Sea, mainly the U.K. and Norway, will increase significantly in coming years from 6.2 mb/d in 1998 to a peak in 2006 above 8 mb/d (includes natural gas liquids, NGL's, and processor gain).4  They also project a decline rate of about 2% per year, after the peak, to 2020.  Table 5 shows a comparison of the author's projections of Norwegian and U.K. oil production versus the U.S. DOE/EIA's projections.

Table 5

Author's and U.S. DOE/EIA's

Projections of Norwegian and U.K. Oil Production to 2020

Author's Projections

Peak Year

Peak Oil Production (mb/d)

2010 Oil Production (mb/d)

2020 Oil Production (mb/d)

Norway

2001

3.2

1.6

0.77

U.K.

1999

2.7

1.5

0.92

U.S. DOE/EIA's Projections4

       

Norway

2005

3.9a

-

3.2a

U.K.

~2006

3.3a

-

2.2a

a Excludes NGL's and processor gain.  From 1995 through 1998 crude + condensate made up 90% of U.K.'s total oil production and 96% of Norway's total oil production.  It's assumed that these percentages won't change in the future.


Based upon the U.S. DOE/EIA's projections, both Norway and the U.K. would have cumulative oil production values of approximately 40 bbo by 2020 (excluding NGL's and processor gain).  This would by approximately 10 bbo more than the EUR for Norway and 4 bbo more than the EUR for the U.K. based upon the estimates by Masters et al.  There would also be considerable production in both countries after 2020 to add to those cumulative production values because oil production wouldn't end abruptly at 2020.  Figure 14 is a graph of historical and projected oil production for Norway based upon the U.S. DOE/EIA's projections (excluding NGL's and processor gain).

Figure 14: Historical and Projected Production for Norway based

upon U.S. DOE/EIA's projection for Norway


The area under the curve to 2020, in Figure 14, represents a cumulative production of approximately 40 bbo.  Figure 15 is a graph of the U.K.'s historical and projected oil production based upon the U.S. DOE/EIA's projections (excluding NGL's and processor gain).

Figure 15: Historical and Projected Production for the U.K.

based upon U.S. DOE/EIA's projection for the U.K.

The area under the curve to 2020, in Figure 15, represents a cumulative production of approximately 40 bbo.

It doesn't appear that the U.S. DOE/EIA is considering the high decline rates of major North Sea oil fields or the EUR values from the U.S. Geological Survey9 when making projections of future production in the U.K. and Norway, or for that matter, in their global assessment. The rapid decline of major fields appears to exist in many producing basins around the world and must be considered in long-term supply forecasts.  If this situation isn't recognized by national and international organizations that make projections of long-term supply, the future may present some unpleasant surprises. 

References:

  1. L.F. Ivanhoe, "Updated Hubbert Curves analyze world oil supply," World Oil, November 1996, pp. 91-94.
  2. C.J. Campbell and J.H. Laherrere, "The End of Cheap Oil," Scientific American, March 1998, pp. 78-83.
  3. J.H. Laherrere, "World oil supply-what goes up must come down, but when will it peak?," Oil & Gas Journal, February 1, 1999, pp. 57-64.
  4. International Energy Outlook 1999, Energy Information Administration, U.S. Department of Energy, April, 1999.
  5. "The New Economics of Oil," Business Week, Nov. 3, 1997.
  6. E.D. Porter, "Are We Running Out of Oil?," Issues and Research Papers, American Petroleum Institute, December 1995.
  7. M.R. Simmons, "1998: A year of infamy," World Oil, February 1999.
  8. http://www.eia.doe.gov/emeu/international/contents.html, Energy Information Administration, U.S. Department of Energy.

9.    C.D. Masters, E.D. Attanasi, and D.H. Root, U.S. Geological Survey, "World Petroleum Assessment and Analysis," 14th World Petroleum Congress, 1994.

  1. Worldwide Production, Oil & Gas Journal, December issues, 1976-1998.
  2. Field Production Press Release, Norwegian Petroleum Directorate, December 1998.
  3. R.E. Snyder, What's happening offshore, World Oil, Vol. 220, No. 3, March 1999.
  4. http://www.eia.doe.gov/emeu/cabs/northsea.html#UK, Energy Information Administration, U.S. Department of Energy.     
  5. "Toward 2020-A Study to Assess the Potential Oil and Gas Production from the U.K. Offshore," U.K. Offshore Operators Association Limited, 1995.