Environmental And Cost Benefits Result From Controlling Water

(Tech Connections Column, February 2003, American Oil and Gas Reporter)

It is sometimes joked that oil and gas operators are in the water business, and only coincidentally produce oil and gas. Nearly nine barrels of water are produced for every barrel of oil in the United States. Managing produced water properly gives the industry an opportunity to decrease environmental impact, lower operating costs, and improve energy efficiency.

A new resource is PTTC’s produced water manual referenced in the December 2002 Tech Connections (now available online at www.pttc.org). The manual, developed in a DOE-supported project, addresses key questions:

• Do you know if you are producing more water than you have to?

• Do you know accepted techniques for reducing water production?

• If you must lift a lot of water, are you satisfied that you are adequately controlling costs?

Another resource that describes a strategy for attacking excess water production is SPE paper No. 70067 by Seright et al.

Given appropriate reservoir conditions, polymer gel treatments are one effective option for reducing water. Treatments can be performed in either production or injection wells, and in sandstone or carbonate reservoirs. In primary operations, treatments are most often in wells completed in water-drive reservoirs.

Reservoirs have some factor other than structural position alone that contributes to excessive water production. Common geological factors in addition to fractures are karst intervals, high perm streaks, or highly stratified reservoirs. Some of the best candidates are producing wells at or near their economic limits that have high fluid volumes, and high water-oil ratios.

In flooding operations, polymer gel treatments can be performed in both injectors and producers. Injection-well treatments address sweep efficiency. In some cases, producing wells are also treated to reduce water production and improve drawdown. To improve sweep, operators look for patterns or areas of the field with poor secondary-to-primary recovery ratios. In cases where regional experience or preflooding reservoir characterization indicate that poor sweep will be a problem, starting with injection-well treatments has benefits. For example, early injection-well treatments are common in Minnelusa waterfloods in the Rockies.

Historically, there has been a steep learning curve for applying polymer gel treatments, but industry is shortening that by learning more from initial treatments and working together. In a PTTC workshop, polymer expert Bob Sydansk noted that an experienced operator in a field where treatments had been previously applied could achieve a 90 percent-plus success rate.

Cooperative effort to accelerate learning is illustrated by work in Kansas, where operators have been performing larger volume MARCIT-CT^SM CC/AP treatments in the Arbuckle. Most operators are reporting good success (www.pttc.org/case_studies/Ptdigest6-02.htm), although experience has been mixed for some. The Tertiary Oil Recovery Project at the University of Kansas is working with operators and the two polymer gel service providers prominent in the region to share experience, develop a database, analyze some treatments in detail, and develop consensus lessons learned. Pre- and post-treatment pressure buildup tests are being taken to provide critical information about flow capacity, skin and flow conditions (linear through fractures or radial through matrix).

The question is how one determines in advance how much gel he will be able to inject and at what polymer concentration before reaching predetermined pressure constraints. PTTC’s North Mid-Continent Region is supporting TORP in this effort.

California producers are also plagued with excessive water production, but there are differences in that state’s reservoir/well environment. California reservoirs are thought to be dominated more by matrix flow, although some data does indicate that Kansas’ Arbuckle may not be as dominated by large fractures as was previously thought. Regardless of differences, polymer gels are not as widely applied in California, and the experience database needs to be expanded.

The California Energy Commission has awarded $300,000 to PTTC to study the underlying causes of excessive water production, determine appropriate technologies, and develop templates to help producers apply them. Funding does allow for limited field demonstration. The effort is inspired by California’s drive to reduce electric consumption.

Polymer gel technology continues to evolve. At the Petroleum Recovery Research Center at New Mexico Tech, Sydansk is conducting R&D focused on improving the performance and strength of polymer gels applied to multi-darcy fracture-like flow channels that are conduits for excessive water production. Another research interest is combining gel with stimulation operations. In some Rockies reservoirs (SPE No. 38789, Embar carbonate in Wyoming), this combination approach has been very profitable.

Striving to reduce produced water is important across the country. Utilizing polymer gels is one way operators can reduce the amount of water brought to surface. Accomplishing this would reduce energy consumption, lessen environmental impact related to disposal, and allow for greater production throughput on existing infrastructure.