TECHNOLOGY AT WORK

Three independents improve mature-field operations

Lance Cole, National Project Manager, Petroleum Technology Transfer Council

To maintain profitability in mature reservoirs, independents must optimally apply newer techniques such as horizontal well technology and 3-D visualization. Often it is multiple technologies that must be applied. To overcome hesitance that they can profitably apply newer technologies, independents rely heavily on others’ experiences or case studies to develop the confidence they need to implement technologies. In the following summaries, three major California independents – Oxy USA in Thums Long Beach Unit, Nuevo Energy Co. and Berry Petroleum Co. – share their experiences in revitalizing leases through applying a mix of technologies.

Thums Long Beach Unit. Drilling began at this property in 1965, reaching a peak rate of 150,000 bopd in 1969. The Unit has undergone extensive waterflooding. In the late 1980s, Arco (operator at the time) implemented a $100-million waterflood optimization plan. This plan focused on redeveloping less-mature areas within the established waterflood. The optimization effort, which employed several technologies, increased production and is moderating decline. The Unit is now struggling to maintain 37,000 bopd (with 700,000 bwpd) from 700 producers and 375 injectors.

During the recent period of reduced oil prices, drastic cost-cutting measures were taken to maintain profitability. Economic analysis indicates that present worth is maximized when activity levels are stabilized – i.e., don’t slow down or ramp up activities depending on oil price – so Oxy is trying not to over-react to current higher oil prices.

Quality reservoir characterization is the key to success at Thums, and experience indicates the complexity of the description continually increases as more data become available. Established technologies that have made a difference at Thums include: 1) hydraulic fracturing of unconsolidated sands (incremental oil at $3.25/bbl); 2) extended-reach and horizontal drilling; 3) ultra-slim (1.9-in. inner liners for well repair; 4) logging while drilling; and 5) gravel packing for sand control. Newer technologies now being implemented include: 1) bi-center reaming while drilling, to incrementally reduce drilling cost; 2) hot water stimulation; 3) cavity completion, 4) re-shooting 3-D seismic (to replace known, poor-quality initial survey); and 5) facility automation.

Increased automation allows real-time knowledge of well status – which will reduce lost production from unknown well shut-ins – and improves safety, compensating for reduced manning for cost control. Technologies being considered for future application include: 1) downhole oil / water separation; 2) profile control, 3) behind-pipe oil detection; 4) artificial lift improvements; 5) lower-cost drilling, and 6) improved corrosion / scale control. Some, like downhole oil / water separation, are newer technologies that are not proven today – but will be some day, with evolution – while others, like improved corrosion / scale control, are areas needing constant attention.

Nuevo’s operations in California. Since being founded in 1990, Nuevo Energy has grown over 10-fold – from 23 MMboe reserves in 1990, to 289 MMboe in 1999. Nuevo is the largest independent in California, producing about 46,000 bopd from the state. Its exploitation strategy is to take "under-loved" properties and focus on rapidly increasing production in these assets by using technologies that help produce reserves faster, such as horizontal drilling and unique or proprietary completion techniques.

When production is accelerated, experience confirms that reserve recovery also increases. Integral to this philosophy, Nuevo strives to maintain and operate its facilities at or above the highest regulatory standards for health, safety and the environment and, as a result, has won several safety / environmental awards for its offshore operations.

Technical competencies central to Nuevo’s exploitation strategy include: 1) infill / horizontal drilling; 2) extended-reach drilling; 3) fracture stimulation; 4) proprietary production technology; 5) secondary recovery; 6) tertiary recovery; and 7) reservoir simulation. As an indication of how central these technologies are, in 1996, Nuevo had only one horizontal well – the company plans to drill 20 such wells in 2001.

Four examples of how Nuevo has applied its technical competencies and other technologies are described here. In its Star Fee lease in Cymric field, production was 400 bopd in June 1999, when it acquired the acreage. In less than 18 months, the company drilled 103 multiple completion wells, employing new proprietary completion technology. Production is now about 6,500 bopd from 90 wells. In Nuevo’s Hopkins Fee lease in its Belridge field, there was no production when it acquired the lease in 1996. Since then, it has drilled 21 horizontal wells to a 10 – 25-ft Tulare sand zone, extending the productive field limits. Current production in Hopkins Fee is about 2,100 bopd, and another 30 horizontal well locations have been identified.

In the offshore Pitas Point field, pulsed neutron logs have helped the company identify behind-pipe zones for recompletions. For instance, in one well, a recompletion in May 2000 boosted production to 7.9 MMcfd from 2.4 MMcfd. A second recompletion in November 2000 also had good results. And in the Brea Olinda field, a gas turbine for power generation was installed in June 2000, creating value from previously flared natural gas. Payout on this turbine occurred within four months, and a second turbine was installed in November. The two turbines currently convert a total of 2 MMcfd of previously flared gas into electricity.

Berry Petroleum’s California operations. Berry Petroleum is a core niche player in California’s heavy oil production, producing about 17,000 bopd, much of that from thermal operations. Its main producing properties are in Midway-Sunset, Montalvo and Placerita. Three co-generation plants produce 98 megawatts of electric power and 43,000 bpd of steam; about two-thirds of Berry’s steam demand is utilized in enhanced recovery operations. The company’s acquisition efforts during the past five years have increased its proved reserves by over 55 MMbbl at a cost of $1.59 /bbl.

Specific production targets are set when properties are acquired and results are reviewed one year later. Adjusted to a "months since acquisition" basis, Berry’s acquisition program has a track record of achieving a 40% increase in production within 10 to 12 months. Essential technologies for realizing increases of this magnitude are: 1) advanced reservoir characterization using 3-D visualization; 2) horizontal drilling; 3) 3-D seismic; and 4) advanced completion / fracturing technology.

With a steam-to-oil ratio of over 3:1, minimizing steam cost is essential. Cogeneration facilities provide a significant cost advantage – as much as 2.5:1 depending on gas price – over conventional steam generation facilities. This savings is even greater when gas prices rise. Even with this cost advantage, the recent upward spikes in gas price have required the company to shut-in some conventional steam generation, representing about 25 % of its total steam capacity. In addition, some development plans have been put on temporary hold. Active management of Berry’s cogeneration facilities becomes even more critical with high gas prices and the deregulation of California’s electric industry.

Although the company believes that the increased differential between Henry Hub and the current price California is paying for gas is temporary, Berry has learned that managing the total energy complex – oil, gas and electric power – not just oil production, is the key to success. With evolving electric deregulation and the recent spikes in natural gas prices, there is intense political pressure, which results in a very dynamic situation. Involvement and interaction through trade associations for the transfer of information and technology become important for achieving successful outcomes.