California's continued reserve replacement success comes from applying tried-and-true practices to an elite group of older fields.

Although very old, California's highly productive oil fields, often characterized by shallow, thick, multi-zone producing horizons, continue to provide operators with profitable reserve additions. Some of the oldest fields are responsible for most of the reserve additions that have replaced recent production.
California produced 2.88 billion bbl of oil from state onshore and offshore properties (excluding Federal OCS) from 1991 through 2000. Net reserve revisions replaced 2.32 billion bbl of oil (80% of the production) during those same years. Since year-end 1995, reported net reserve additions of 1.69 billion bbl actually exceeded production of 1.40 billion bbl by 20%.

In California, it is relatively simple to review public domain production, injection and interpretative data provided by the state's Department of Natural Resources, Division of Oil, Gas and Geothermal Resources (DOGGR) in its annual reports. Data are also available on the Internet from the division's main search page. The annual reports provide detailed field-by-field production statistics and reserve estimates and are compiled and approved for publication by Oct. 1 of each year with production data through the preceding year. These reports also provide a field breakdown of each operator's production data.
Field-by-field reserve-to-production (R/P) ratios are assessed annually by the DOGGR and revised up or down as appropriate. As a rule of thumb, fields with R/P ratios of less than 5 are considered for possible upward revisions, whereas fields with R/P ratios greater than 15 are considered for possible negative revisions. Revisions are based on performance history and draw on the knowledge of the DOGGR's local staff. An analysis of DOGGR data can identify the oil fields and industry participants with the greatest contribution to performance and provides some insight into the reasons behind it. In the case of the reserve replacement performance cited above, the greatest contribution comes from nine older fields where tried-and-true practices are being applied.

Nine old giants

California operators currently produce from 207 active oil fields, and it is estimated that 51 of these fields each will ultimately recover more than 100 million bbl of oil. At year-end 2000, 49 fields already had exceeded that hurdle. Of all California's oil fields, nine account for 75% of total production and 98% of net reserve additions during 1996 through 2000. These nine are all "old giants," which together account for cumulative production of more than 8.9 billion bbl of oil. But despite their age, there is plenty of life left in these old fields; DOGGR estimated remaining reserves for the nine was nearly 2.5 billion bbl at year-end 2000.

A look at total California onshore and offshore production from 1977 through 2001 reveals that the contribution of these nine fields is an increasingly important one and, as of 2001, accounts for nearly 75% of oil produced in California (Figure 1).

The youngest field, Inglewood, in the LA Basin, was discovered in 1924 (Table 1). The oldest, Coalinga, in the northern San Joaquin Valley, was discovered in 1890. The rest are located in the southern portion of the San Joaquin Valley and were discovered from 1894 through 1911.

For eight of the nine, DOGGR recognized significant positive net reserve revisions since 1995. The only field with negative revisions was Elk Hills; from January 1991 through January 2001, oil production declined at a steady 4.2% annual rate from 75,000 b/d to 49,000 b/d. This prompted a series of negative revisions by the DOGGR in 1994, 1995 and 1998. Since early 2001 however, production has been on the upswing, averaging 54,700 b/d for the first 5 months of 2002.

Major operators still major players

Although it is common to say that the major operators have left California, in truth, eight of the top 20 reported producers in 2000 were majors or operating companies owned by majors. Since the eight included subsidiary companies, there are in fact only five separate controlling entities, four if Chevron and Texaco are combined. For example, Texaco Exploration and Production Inc. and Texaco California Inc. are reported separately but part of the same controlling entity. Three other producers were Occidental of Elk Hills Inc., THUMS Long Beach (Occidental) and Oxy Resources California LLC, all part of Occidental. Aera Energy LLC, operating since 1997, is considered a major as it was formed by Shell and Mobil. The other two majors in the top 20 are Chevron USA Inc. and ExxonMobil Corp.

A look at the production performance of major operators' California properties (excluding Federal OCS) reveals that although production levels are relatively flat from 1989 through 1998, they have lost ground since 1999.

While major operators have disposed of almost all their former California coastal properties, they hold by far the largest positions in the nine fields responsible for the majority of the reserve additions since 1995 (Table 2).

Independent producers

Independent producers are taking an increasingly important position in California operations; as of 2000, 12 of the top 20 producers were independents. This can be compared to 1990, when only four of the top 20 were independents. Five of the independents hold acreage in the nine "old giant" fields, and one, Stocker Resources, is the dominant producer in the Inglewood Field (Table 2).

As a group, the independent producers have improved recovery overall in fields that they operate (Figure 2). The settled production decline apparent in mid-1986 was arrested by mid-1995 and has remained basically flat since then. Although the majority of the properties held by independents were acquired since 1990, DOGGR operator production data includes production from the previous owner. This readily facilitates a comparison of operating results before and after an ownership change.

Ownership transfers

Since 1990, properties have been actively transferred from operator to operator. One result is that ownership has been consolidated, with majors improving dominant positions in core fields. This has eliminated competitive lease-by-lease practices common in the past. A second result is that independent operators also have picked up significant positions in the nine major fields. Independent operators also consolidated ownership in smaller fields. This consolidation focused operator thinking on field-specific solutions, catalyzed new ideas and investment money, and resulted in better operating and development practices.

New wells and workovers

At year-end 2000, California's total active well count was 46,453 oil wells. This compares with year-end 1995 when the active well count was 43,818. During the 5-year period up to 2000, nearly 9,300 wells had been abandoned. New completions in California over that 5-year period are therefore estimated at about 11,900 wells. Also during the same 5-year period, 13,500 permits to work over existing wells (including recompletions) were issued. While there is no reporting of the actual number of recompletions performed, the number of permits issued is indicative of the activity level.

For the nine giant fields, total active well count increased from 29,937 in 1996 to 33,165 in 2000. The majority of the wells drilled are less than 2,000 ft (610 m) deep. Fast drilling, repetitive completions and large program groups have minimized costs and lowered economic thresholds, leading to improved field recovery and significant reserve additions.

Role of EOR

Enhanced oil recovery (EOR) historically has been important to California's productivity. Since 1995, approximately 70% of total production is attributed to thermal, water and gas injection projects. Because California oil is generally viscous and located in shallow, high-permeability reservoirs, steam injection has been the dominant EOR method and accounts for more than half of all oil produced since 1995.
DOGGR reports that seven of the nine giant fields contain active thermal recovery projects. The only two that do not are Inglewood and Elk Hills. The seven thermal recovery projects produce at an average depth of 1,100 ft (336 m) and on average are drilled on 1-acre spacing. The top three producers and contributors to reserve additions - South Belridge, Kern River and Midway-Sunset - are California's dominant thermal projects. Production for these fields clearly shows a recent downturn in productivity (Figure 3). This is due to California's 2001 energy crisis, when steam generation and injection was cut back by nearly 17% compared to 2000 levels in all three fields, immediately affecting production. Steam injection is returning to pre-crisis levels, but formations have cooled, and recovery to former production levels will take some time.

Recent productivity trends

Compared to 2000, California's daily average production in 2001 dropped from 743,900 b/d 715,100 b/d. This loss can be attributed entirely to the 2001 energy crisis, which affected oil productivity in two ways: high fuel costs and power curtailments. High fuel costs resulted in reduced steam injection, which translated into an immediate loss in productivity. Anecdotally, during 2001, California fields also were affected by rolling power cutbacks imposed by suppliers. The shortage of electric power resulted in mandatory field shut-ins, causing additional productivity losses from fields entirely dependent on artificial lift. In addition, higher power costs most certainly caused marginal wells to be shut in. The loss in production from power curtailment cannot be quantified from the data reviewed, but is undoubtedly important.

California produced 261 million bbl of oil in 2001. Analysis of 2000 reported reserves and production for California's giant oil fields shows that it is unlikely that reserve additions will replace this production. Opportunities continue to exist, however, for important and profitable reserve additions by operators applying new practices that reduce investment for new wells and reduce costs in existing operations.

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