Gas reserves growth boosts Sacramento basin

Nat H. MacKevett
Consulting Geologist
Bakersfield, Calif.

Operators have discovered 153 gas fields in the Sacramento basin of northern California (Fig. 1 [203,575 bytes]). This study includes data from 114 fields; gas fields with less than 1 bcf of cumulative recovery were eliminated from the tabulations.

These 114 fields have a combined probable ultimate recovery of 9,546.3 bcf of gas. The fields produced a combined 75.5 bcf in 1996. Cumulative production to Jan. 1, 1997, is 9,027.2 bcf, and remaining reserves are estimated at 519.1 bcf. Including fields with less than 1 bcf of gas adds only 10 bcf to the cumulative.

Some 95% of the cumulative production is from the 46 fields that have a field size greater than 25 bcf. Rio Vista is by far the largest gas field in the Sacramento basin, with just over 3.5 tcf of gas. This one field accounts for 37% of the ultimate recovery.

Six fields are larger than 250 bcf, and these account for 58%. The six fields are Rio Vista, Grimes, Willows-Beehive Bend, Lathrop, Lindsey Slough, and Union Island. There are 20 gas fields with potential ultimate gas production of over 100 bcf, and these fields account for 77.3% of the ultimate production. In addition, 46 fields are larger than 25 bcf that have 94% of the total EUR for the basin gas fields and provide a basis for meaningful analysis.

Recent performance

Here are recent Sacramento basin highlights:

The last significant new field wildcat discovery was in 1972 at Union Island.
Gas production is about 75 bcf/year, down from 176 bcf 10 years earlier.
Total ultimate gas production projections are informative from 1951 (3,621 bcf from 27 fields) to 1976 (7,970 bcf from 103 fields) to 1986 (8,776 bcf from 131 fields) and 1996 (9,546 bcf from 153 fields).

Translated to an annual basis, this can be restated as follows:

A. From 1951-76 some 76 new fields were discovered at an average rate of three new fields discoveries per year, and 4,349 bcf of new ultimate gas was added (both from old and new fields) or an average rate of 174 bcf/year, and
B. From 1976-86 some 28 fields were discovered at an average rate of 2.8 discoveries per year, and 806 bcf of new gas was added at an average rate of 81 bcf/year.

During 1987-96, some 15 new fields were discovered at an average rate of 1.5 discoveries per year; however, none of these has added significant reserves. The main source of added new reserves has come from additions in existing fields.

From yearend 1986 through 1996, data indicate there are some 771 bcf of gas added to the ultimate production, or 77 bcf/year. Most of these reserves have come from new pool discoveries.

The significant reduction in added reserves occurred in the early 1970s, and during 1976-96 the annual production rates declined markedly. Reserves additions averaged as follows: 1951-76, 176 bcf/ year; 1977-86, 81 bcf/year; and 1987-96, 77 bcf/year. This 77 bcf/year average barely offsets 1996 production of 75.5 bcf.

Liquids production

Mention should be made of the minor amounts of oil and condensate produced from wells in the southern part of the basin.

The largest oil production was from Brentwood oil and gas field (9.3 million bbl cumulative). Other fields that have produced more than 1 million bbl of oil or condensate include Livermore 1.7 million, Rio Vista 1.6 million, and Lindsey Slough 1.3 million.

This oil and condensate are produced mainly from Upper Cretaceous sandstones, with lesser amounts from Lower Eocene sandstones. The main oil source rock for these Lower Eocene and Upper Cretaceous objectives is considered to be Upper Cretaceous Moreno shale.

If oil and condensate were added as gas equivalents at a 1:6 ratio, 93.6 bcf of gas equivalent would be added to the totals. This conversion was purposely omitted from the tables and figures.

Drilling upturn

Northern California drilling has taken an upturn recently.

Roland J. Bain, a consulting geologist, reported 86 holes drilled in 1996 with 47 completed for a 55% completion record. Sale of producing properties by majors has made the area more of an independent's arena, Bain noted.

The use of 3D seismic is quite popular, with Slawson Exploration leading the way by completing 11 of the 14 wells drilled in the high risk Forbes formation near Grimes.

Other operators are also compiling excellent completion records. Although most of the successes are in and adjoining existing fields, some of the more recent new pool and wildcat discoveries may have significance.

The impact of gas price on drilling tracks quite well. The gas price averaged $1.83/MMcf at the wellhead in 1996.

New production at French Camp by Enron with six wells from thick Lathrop sands has added 20-50 bcf of reserves. Some geologists think new reserves at Dutch Slough field will be in the 20-50 bcf range. Deeper pool production from the Winters formation in Bunker field totals about 85 bcf. Other encouragement at Grimes, West Grimes, and Denverton Creek may prove rewarding.

Deeper drilling for Lower Eocene and Upper Cretaceous sandstones already established as good gas objectives and the exploration of nearshore Guinda (Upper Cretaceous) sandstones will occur soon. Reports suggest that 1,000-1,500 sq miles of 3D seismic data have been shot in the basin with more planned. Low contrast, low resistivity sands may also contribute to new gas finds.

Other nearby basins and adjoining areas may warrant the gas prospector's attention. Several geologists point out that there are equally good gas prospects in the northern San Joaquin basin and the Eel River basin. Others consider that the northernmost extension of the Sacramento basin and parts of the eastern and western areas of the basin merit a closer look.

What the data show

A distribution of gas fields larger than 25 bcf, based on 1986 ultimate gas production, shows that the past 10 years accounts for an increase of about 1 percentage point each in the two categories of Upper Cretaceous formations (Fig. 2 [76,736 bytes]).

The most notable upward revisions of ultimates occur in these fields: Bunker, Grimes, Willows-Beehive Bend, Lindsey Slough, Union Island, Millar, and Malton-Black Butte.

Another revealing chart is the ultimate volume of gas discovered by year and age, with new development additions shown in red (Fig. 3 [56,804 bytes]). Willlows-Beehive Bend field, discovered in 1938 but not developed until 1953, has been credited to 1938 instead of 1953 as in the author's 1986 study.

Increments in ultimate growth for 28 gas fields reflect some significant changes with time, attributable to field development drilling, gas economics, and improvements in reporting and tracking of estimated ultimate reserves (Fig. 4 [62,606 bytes]).

The 1986-96 period reflects some changes, but the overall difference is less than 5%. Some of that change is a function of recent new pool development and can exceed 10% with the largest change almost 17%.

When the current cumulative production approaches the estimated ultimate recovery, and the most recent annual production is still fairly strong, more upward revisions are likely. This is still happening at Sutter Buttes, the basin's oldest field.

Fig. 5 [68,585 bytes] was revised in 1997. A major change in the cumulative production plot occurred when Willows-Beehive Bend field was moved to 1938 from its former position in 1953. Most publications credit 1938 as the discovery year.

Only 12 fields in the Sacramento basin had reserves greater than 10 bcf as of yearend 1996 (Table 1 [188,373 bytes]).

The total reserves for all fields, 519.1 bcf, amounts to 5.4% of the total ultimate.

The figures also show that the 12 fields with reserves greater than 10 bcf/field hold a total of 319.7 bcf of reserves. Divided geographically, six fields (mostly producing from Forbes) have 177.3 bcf of reserves in the northern half of the basin, and six fields (producing mostly from Lathrop, Winters, and Younger) have 142.4 bcf of reserves in the south half.

The payoff

It is reasonable to expect another 500 bcf of new ultimate production from Sacramento basin fields. This would hike the current ultimate recovery for all fields to about 10 tcf.

New field discoveries and deeper pool tests could easily boost the maximum forecasted ultimate recovery to 11 tcf. The author in 1988 forecast the addition of 2 to 3.5 tcf.

Reasons for the reduction are lack of significant new field wildcat discoveries the past 20 years, significant annual production decline since 1985, and lack of major reserves added.

Some 1997 wells suggest that positive changes will occur, and several geologists consider this new forecast too conservative.

Acknowledgment

Thanks to Dale Hankins and Rich Boyd for providing information for this article.

Bibliography

Beyer, Larry A., Summary of geology and petroleum plays used to assess undiscovered recoverable petroleum resources of the Sacramento basin province, California, USGS Open File Report 88-450-O, 1988, 64 p.
Montgomery, Scott L., Sacramento basin-A second look, Petroleum Frontiers, Petroleum Information Corp., Vol. 5, No. 3, 1988.
California Department of Conservation, Division of Oil & Gas, Publication No. PR-06, 1986-96.

The Author

Nat H. MacKevett has more than 50 years' experience as a petroleum geologist, with some 30 years as an exploration geologist for Shell Oil Co. and almost 7 years as chief geologist for Hershey Oil Corp. Most recently he is a consulting geologist working on exploration projects in the Sacramento basin. He has worked most western U.S. basins and has been directly involved in 15 new field and/or new pool discoveries and the purchase of 20 heavy oil properties in the Sacramento, San Joaquin, Uinta, and East Texas basins. He holds a geology degree from UCLA.