WATER CUT CONTROL METHODS

Based on a workshop sponsored by PTTC’s West Coast Region on February 25, 1999, in Long Beach, CA.

BOTTOM LINE

Water production, with its associated costs, can be minimized by using the proper drilling techniques, using the proper logging and perforation techniques, chemically or mechanically closing down high-permeability streaks, or separating the water from the oil downhole.

PROBLEM ADDRESSED

In 1998, California oil wells produced nearly 5.8 million barrels of water per day (bwpd), representing a composite water cut of 88%. This high water production ratio increases both lifting and water disposal costs, adds environmental concerns, and reduces oil production. It also necessitates additional maintenance for production equipment and downhole treating for corrosion, bacteria, scale, and naturally occuring radioactive material (NORM). The total cost for these treatments is $0.75 to $2 per barrel onshore and $1 to $3 per barrel offshore.

KEY WORDS:

Water Production, Water Breakthrough, Horizontal Drilling, Electric Log, Gel Polymer, Liner, Downhole Oil-Water Separator

SPEAKERS

Well Logging:
Dennis Wyatt, Halliburton Energy Services Inc.

Gel Polymers:
Julie Smith, TIORCO, Inc.

Conformance Control Technologies:
Jerry Berensen, BJ Services

Downhole Oil-Water Separators:
Paul Tubel, Baker Hughes

In-Situ Polymerization:
Ray Ambros, Schlumberger

Horizontal Producers/Injectors:
Sada Joshi, Joshi Technologies International, Inc.

Profile Control Experience in Wilmington:
Jeff Blesener, City of Long Beach Oil Properties

TECHNOLOGY OVERVIEW

Logging is important not only for identifying water zones before drilling, but also after production has matured, and for understanding borehole problems. Open and cased hole logs can determine fluid saturations, identify water zones and water entry points, measure flow rates, and evaluate cement bond, downhole tubulars, and casing. Logging costs can be justified, by avoiding water-handling costs.

When producers know which zones produce water, they can use mechanical, gravel-packed slotted liners to selectively produce certain zones. When the water-producing zone is not known, or when there are breakthrough or operating difficulties, chemical methods can be used (gels, catalyzed silicate injection, or MicroMatrix cement). Chemical methods may have to be repeated as the profile changes or breaks down with time.

In-situ polymerization (such as PatchFlex or TexFlex) is a mechanical method in which a flexible composite cylinder is lowered by wireline, inflated, and set flush against the pipe. Heat polymerizes the resins leaving a hard, inner liner that, if needed, can be selectively perforated. When inflated, there is minimal diameter loss. PatchFlex is available for 4-1/2-through 7-in tubulars for well conditions up to 4000 psi and 180º F. Up to 50 ft of patch can be run at a single time. In the Forties field in the North Sea, a PatchFlex assembly was used in a 4½-inch, 12.6-lb. liner to shut off water. Where a prior squeeze had been unsuccessful, the treatment increased oil production by 84% while decreasing the water cut from 83 to 60%.

In the Wilmington Field, mechanical methods are generally preferred, because chemical methods ended up reducing oil (as well as water) production. Chemical methods work best when followed by Micro Matrix cement squeezes. Injection wells are more amenable to chemical treatments, usually lasting one to two years before profiles deteriorate. 

Horizontal Wells. One application is to reduce water production by drilling only in the oil leg to minimize water coning. Two horizontal wells (a production and an injection well) were drilled in the New Hope Shallow Unit in Texas. The waterflood was extremely mature, having begun in 1943. When the wells were drilled, the field was producing 250 barrels of oil per day (bopd) with 400 bwpd injection. The best vertical well produced 100 bopd and the new horizontal well produced 400 bopd. The two horizontal wells extended the life of the unit by 10 to 15 years. Economics indicate that they could replace 6 vertical wells at a cost of $2 to 3 per barrel of added reserves—or half of the cost.

Gel Treatments. Bulk gel and colloidal dispersion gel treatments, which travel preferentially through and plug higher permeability zones, can be used in injection or production wells. Gels, which are injected as an aqueous solution of polymer and crosslinker, combine after injection. Wells that produce water from channels or fractures are good candidates, as are reservoirs that produce at high water-to-oil ratios (WORs). Gels, which are often used in waterfloods with evident channeling, may work best when applied field wide.

Gel treatments have been very successful in the Minnelusa Sandstone in the Powder River Basin. In the Indian Tree Minnelusa Unit, waterflood response was positive when water breakthrough occured. An injection-side gel treatment filled the thief channel and reduced the WOR, ultimately recovering an additional 110,000 bbl of oil at an incremental cost of $0.62 per barrel. In the Winter Draw Minnelusa Unit, where similar water breakthrough occurred, an injection-side gel treatment reduced the WOR, recovering an additional 124,000 bbls of oil at an incremental cost of $0.61 per barrel. In a field in the Big Horn Basin producing from the Tensleep and Embar formations, 13 production wells were treated. Oil production increased from 643 to 698 bopd and the producing WOR dropped from a ratio of 121 to 30 bwpd.

Downhole Water Separation. Another option is to separate the oil and water downhole, then the water is injected into an isolated injection zone. The process requires a 60% WOR (for two-stage separation) and 80% water cut (for single-stage separation). There must be a minimum differential density between water and oil of 0.05 specific gravity units. Separator efficiency decreases with increasing viscosity, rises with temperature, and works best if fluid viscosity is less than 5 centipoise. Free gas must be less than 5%. Hardware, requiring a minimum 5½-in casing, is available to handle flows of 500 to 20,000 bopd, with hydrocyclone technology applicable to the higher flow rates. This process provides a clean water stream for downhole injection, and an oil stream with a low WOR. Since the technology is still evolving, risk can be high—but there are notable successes.

CONNECTIONS:

Downhole Water Separation Technology
Argonne National Lab report available on website: www.ead.anl.gov

Dennis Wyatt, Halliburton Energy Services
Inc. PO Box 42800, Houston, TX 77242,
Phone 713-596-5548, Fax 713-596-5436, E-mail dwyatt@halnet.com

Julie Smith, TIORCO, Inc.
1795 West Warren Ave., Englewood, CO 80110
Phone 303-935-0046, Fax 303-935-1514 E-mail jesmith@tiorco.com

Jerry Berensen, BJ Services Company
301 E. Ocean Blvd., Long Beach, CA 90802 
Phone 562-495-9371, Fax 562-437-7339

Paul Tubel, Baker Hughes
PO Box 3048, Houston, TX 77253
Phone 713-923-9636, Fax 713-923-9620

Ray Ambros, Schlumberger
2841 Pegasus Dr., Bakersfield, CA 93308
Phone 805-745-7710

Sada Joshi, Joshi Technologies International
5801 E. 41st St., Suite 603, Tulsa, OK 74135
Phone 918-665-6419, Fax 918-665-0807

Jeff Blesener, City of Long Beach Oil Properties
211 E. Ocean Blvd., #500, Long Beach, CA 90802
Phone 310-570-3905, Fax 310-570-3922

For information on PTTC’s West Coast Region and its activities contact:
Iraj Ershaghi, Director, Petroleum Engineering Program, HEDCO-316
University of Southern California, Los Angeles, CA 90089-1211
Phone 213-740-8076, Fax 213-740-7982, E-mail ershaghi@archie.usc.edu

Disclaimer: No specific application of products or services is endorsed by PTTC. Reasonable steps are taken to ensure the reliability of sources for information that PTTC disseminates; individuals and institutions are solely responsible for the consequences of its use.

The not-for-profit Petroleum Technology Transfer Council is funded primarily by the US Department of Energy’s Office of Fossil Energy, with additional funding from universities, state geological surveys, several state governments, and industry donations.

Petroleum Technology Transfer Council, 2916 West T. C. Jester, Suite 103, Houston, TX 77018
Toll-free 1-888-THE-PTTC; Fax 713-688-0935; E-mail hq@pttc.org; web www.pttc.org