With 70% of global oil production coming from fields past their prime, Shell takes a long-term, “life-of-field” approach to enhanced oil recovery (EOR) to squeeze the most hydrocarbons it can from the assets it manages. Shell pioneered two key techniques — steam and CO2 injection — in the 1960s and still profitably employs them today in the very fields where they were developed.

South Belridge
Using thermal steam injection techniques to enhance oil recovery, Shell developed the large, complex Tulare reservoir of the South Belridge field in California.

The South Belridge field ranks among the five largest producing fields in the United States. Since its discovery in 1911, more than a billion barrels of oil have been produced on Shell properties in this area. Heavy 13°-gravity API oil in the Tulare formation of the South Belridge field is suitable for thermal recovery because it is relatively shallow and has high initial oil viscosity, which declines dramatically when heated to higher temperatures.

Shell conducted a number of steam field trials in California in the 1960s, leading to field-scale

Figure 1. Steam floods start with cyclical injection and soak periods. (All graphics courtesy of Shell)
steam-drive developments from the 1970s. Success in this thermal technology development gave Shell the confidence to acquire Belridge in 1979. Based on lessons from these early pilots, the field was initially developed using cyclic steam stimulation. This process involves initial steam injection into the target heavy oil zone. After a soak period to heat the reservoir fluids, oil and some condensed steam are produced through the same well. The heated oil flows back at a dramatically reduced viscosity due to the added heat and thermally altered rock wettability. This cyclic steam stimulation is repeated several times until a large heated zone is established, after which the pattern is normally converted to continuous steam injection with separate dedicated producers and injectors to increase the recovery to very high levels.

Understand the reservoir
Steam injection profile monitoring and control are important factors for optimizing steam- flooding performance. Local vertical wellbore logging, including temperature surveys and neutron logs, are combined to provide an overall picture of steam-flood performance. This helps to identify bypassed oil for future production optimization. High-resolution 3-D seismic technology has improved understanding of undeveloped parts of the field. Very high recovery factors (around 80%) have been achieved in many parts of the field as a result of the rigorous surveillance efforts and very dense well spacing.

Belridge adds value through management as a manufacturing complex. The high recovery efficiencies and value maximization have been possible due to the conscious adoption of a three-point strategy:
1. Use of efficient and innovative EOR technologies and techniques to optimize production;
2. Aggressive and low-cost drilling campaigns to target parts of the field with thinner pay; and
3. Dedicated implementation of operational maintenance programs to minimize downtime and increase efficiencies.

Management techniques
The South Belridge field produces more than 140,000 b/d. Some 90,000 b/d of light oil is obtained from the Diatomite formation, but more than 50,000 b/d is heavy crude obtained from the Tulare reservoirs through approximately 900 producing wells and 400 steam injection wells spread across 66 sq miles (171 sq km) with 250 miles (402 km) of pipeline, 21 treating plants and two gas plants. As such, the Belridge Complex is one of the largest and most complex operations in the world.

The South Belridge Tulare field continues to provide thermal oil production and serves as a good example of how long-term continuous application of emerging technologies and operational efficiency can maintain profitable EOR production. So far, Shell has produced more than 50% of Tulare’s original oil and expects the field to be producing 50 years from now.

Deep in the heart of Texas
Another key EOR technique in wide use today was also pioneered by the company in the Permian Basin in West Texas. The company conducted the world’s first successful CO2
Figure 2. After initial cycling a steam sweep gathers more oil.
flooding field test there in the 1960s, followed by the first full-scale CO2 floods in 1972. The big prize, however, was the Wasson field’s Denver Unit and other large surrounding Permian Basin fields that could be developed only by also linking it to large naturally occurring CO2 sources Shell had found in southwest Colorado. Following a successful Denver Unit CO2 pilot in 1977, Shell moved ahead with development of the McElmo Dome CO2 source field, constructed the 500-mile (804-km) Cortez Pipeline capable of transporting 1.2 Bcf/d, and began field scale CO2 injection in 1983. From there, Shell expanded application of CO2 flooding technology to additional fields, achieving an incremental increase if recovery factor of up to 20% across the different reservoirs.

From 2 billion bbl initially in place, Shell’s strategy recovered an additional 120 million bbl of oil between 1985 and 2000 in the Denver Production Unit in the Wasson field of the Permian Basin alone.

Shell also recognized the improvement in sweep efficiency and gas breakthrough control that alternating periods of water injection and gas injection, or Water Alternating Gas (WAG), could provide.

Positively using CO2
To obtain the CO2 required for EOR, Shell developed three natural CO2 reservoirs and constructed large diameter pipelines to transport it 500 miles (804 km) to the field, reaching the full capacity of approximately 1.2 Bcf/d in only 3 years.

With more than 800 wells in the Denver Unit, the key to operational success was the surveillance program. Injection of more than 400 million scf/d of CO2 quickly arrested the oil rate decline, which stabilized at approximately 40,000 b/d.

The success of the project depended on gaining a thorough understanding of the reservoir, its geology and properties. Careful management of reservoir pressure was critical to ensure CO2 miscibility without causing the rock to fracture.

Fluid movement was monitored by measuring production and saturation in observation wells. The reservoir understanding developed through these monitoring activities allowed Shell to adjust the WAG injection scheme to maintain optimal injection and profile control to reduce CO2 breakthrough and increase oil recovery.

To increase the economic life, Shell focused on driving down operational costs and improving production efficiency. As gas/oil ratios increased, wells were converted from artificial lift to flowing wells. In 1997, a change of the well pattern and the flood scheme to optimize recovery resulted in a further incremental oil rate of approximately 4,000 b/d. The consequent incremental increase in recovery factors ranged from 20% to 40% across different fields.

Going global
This complex West Texas project required multidisciplinary integration and continuous innovation to ensure efficient recovery and safe operations both subsurface and surface for more than 20 years. The sheer scale of the project and the comprehensive nature of the EOR study have given Shell unique insight into miscible-gas EOR techniques.

Shell continues to develop this expertise in Oman, where the company is using a miscible-gas EOR scheme in the Harweel cluster to increase recovery from 10% to 33% of the original oil in place. Production levels are expected to increase from the current 15,000 b/d to 100,000 b/d when the EOR project is fully implemented.

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