New polymer gel systems are improving waterflood economics and reducing produced water volumes from China to South America.

During the past 25 years, technology has been developed to increase conformance in waterfloods and reduce water production in producing wells. Companies like Marathon, Unocal, Tiorco and others have contributed to new technology for making the oil recovery process more efficient.

Most of the new technology involves polymer additives and various crosslinkers to form a gel to preferentially reduce water flow in high permeability matrix intervals or fractured flow paths. Such chemical systems can range in strength from viscous polymers to rigid gels, with the specific reservoir problem dictating the choice of gel system used to maximize flood efficiency. Most technology currently in use was invented during the mid-80s with some subsequent improvements. Many examples in the United States have demonstrated that the technology can be a prudent investment if applied to the right kind of reservoir at the right time in its life.

During the past 10 years, the technology has been exported to a number of reservoirs around the world. Reservoir characteristics and conformance problems are common regardless of the location of the producing field. The physics governing oil recovery limitations in China are the same in Argentina, the United States or Venezuela. Several international projects that highlight the technologies used and the benefits that can be gained are summarized here.

Entre Lomas Block, Neuquen Basin of Argentina

The Entre Lomas Block includes two large anticlinal structures, Charco Bayo (CB) and Piedras Blancas (PB). These are productive from the Tordillio formation, composed of sandstone and conglomerate units. In 1975, secondary recovery operations began in the Charco Bayo structure. Due to reservoir heterogeneity and low permeability, cumulative oil production as of December 2001 was about 13.5% of original oil in place (OOIP). Water channeling was severe in most areas of the field.

A polymer gel treatment strategy was implemented in 1999/2000 in a group of injection wells to reduce water channeling, reduce water-oil ratio at the producers, and increase oil reserves. The technology chosen was the Marcit system developed by Marathon.

Intermediate concentration gels (< 2500 mg/l) were used to provide in-depth penetration of the gel to improve the conformance to water injection. Through November 2001, it was estimated that 585,800 bbl of incremental oil had been produced at a cumulative cost of $2.22 per bbl. As of November 2002, the operator reports that the cumulative incremental cost has dropped to slightly more than $1.00 per bbl as incremental costs continue to decline with further oil response. As a result, the injection well gel treatment program was expanded with more treatments planned for 2003.

Lagomar Field, Lake Maracaibo, Venezuela

The Lagomar Field produces from a highly heterogeneous, layered sandstone reservoir that has been under waterflood for more than 4 decades. The reservoir permeability ranges from 58 to 800 millidarcies, with a Dykstra-Parsons coefficient of 0.82. The 32° API oil has a viscosity of 3.1 cp at 181°F.

Currently, high water cuts are forcing the operator to shut in wells. It was determined that water channeling through high permeability thief zones had limited oil recovery to under 30% of OOIP. Several injection patterns were analyzed, and a single injection pilot was conducted to test the effects of a polymer system.

Strong Marcit gels (3,000 to 7,500 mg/l of polymer) were selected for the pilot test conducted in December 2001. A total of 3,700 bbl of gel were injected, in step increments of polymer concentration and gel strength. Positive results were observed in the two offset producers within 5 months, with an average 30% reduction in water-cut. Incremental oil production attributed to the gel so far is 26,850 bbl. The positive results from the first treatment led to the recent extension of the pilot to three other injection wells in October 2002.

Several other reservoirs in the Lake Maracaibo area have implemented or plan gel treatments utilizing the Unogel technology designed for high-temperature reservoirs. The gel quality is similar to the Marcit gel system, but can be used at temperatures up to 300°F.

Daqing Oilfield, Heilongjiang Province, China

The Daqing field produces from several distinct layers of sandstone, but the degree of heterogeneity varies greatly from one layer to another and throughout the field. This heterogeneity, combined with an adverse mobility ratio, has played a role in limiting oil production from secondary waterflooding to about 33% of OOIP. In 1997, the Daqing Petroleum Administrative Bureau conducted a study to evaluate Tiorco's Colloidal Dispersion Gel (CDG) technology and design a pilot test for improving oil recovery. CDGs are characterized by low polymer concentrations (150 to 1,200 mg/l) giving a flowing gel with injectivity similar to polymer.

A CDG pilot was started in May 1999 in a 0.75 km2 area that includes six injectors and 12 producers (double 5 spot). The process to-date included, 0.179 pore volume (PV) of CDG injection, 0.155 PV of polymer injection and >0.82 PV of CDG injection. The central producer, B1-7-P124, has seen excellent results. Water-cut has been reduced from 93% to 73%, while oil production has increased from 30 b/d to more than 200 b/d of oil.

Incremental oil produced as of May 2002 (after 3 years) is estimated at 8.32% of OOIP, at a cost of less than $3.25 per bbl (Figure 1).

The Daqing pilot also has shown that CDGs develop more resistance to flow than straight polymer, can be used as a drive fluid after polymer and give better incremental economics than straight polymer.

Arbuckle Reservoirs, Kansas, USA

The Arbuckle formation is a sandy, crystalline, cherty Ordovician dolomite, and Arbuckle reservoirs often experience a strong natural waterdrive that can lead to early water channeling from the underlying aquifer. Water cut increases early with wells rapidly reaching water cuts of greater than 99%. Many Arbuckle wells were drilled in the 1940s and 1950s, and water-shutoff technology has been applied since the late 1960s with marginal success.

But since early 2000, more than 60 wells treated with Marcit treatments have posted a 100% economic success rate, with payout of total costs in less than 6 months. Much of the success is attributed to the robust chemistry of the Marcit gel process and the large volume gel treatments. Studies of large scale Marcit treatments compared to small-size treatments show better payouts and ongoing results from the larger treatments (Figure 2).

On average, 20,000 to 50,000 bbl of additional oil are produced as the result of a single treatment, at costs ranging from less than $0.50 per bbl to $2.00 per incremental bbl, even without accounting for the reduced operating expenses associated with producing less water. For example, a recently treated Arbuckle well was producing 36 b/d of oil and 4,400 b/d of water by means of a submersible pump. Fluid levels were 750 to 1,000 ft above the pump. After the treatment, it produced 286 b/d of oil and no b/d of water. The operator was able to convert the well to a beam pump, saving thousands of dollars in operating expenses.

International outlook

The success of polymer gel treatments has spurred renewed interest in the application of these systems to both waterflood and natural water-drive formations. Formations throughout the world with similar production characteristics may be excellent candidates for this technology.

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