Fact Sheet - Water Shut-Off Chemicals
Some wells generate much more water than anticipated. In other cases, the rate of water production suddenly increases. Two primary technologies can be used to restrict water from entering the well bore: (1) mechanical blocking devices; and (2) chemicals that shut off water-bearing channels or fractures within the formation, and prevent water from making its way to the well. This fact sheet introduces the types of chemical products that are injected into formations to block the flow of water while still permitting oil to flow to the well. Mechanical blocking devices and technologies are described in a separate fact sheet.
The process of waste minimization does not generally call for the introduction of new chemicals into the ground. In this case, however, the chemicals are introduced deep in the earth where they are unlikely to affect the biosphere. Moreover, they have a net beneficial impact. Therefore, this avenue is described as a water management option.
Most of water shut-off chemicals are polymer gels or their pre-gel forms (gelants). In the process of selectively entering the cracks and pathways that water follows, gel solutions displace the water. Once the gels set up in the cracks, they block most of the water movement to the well while allowing oil to flow to the well. The specifics of gel selection and deployment will be driven by the type of water flow being targeted. Some of the key factors recommended for consideration with respect to gel treatment designs and operations include the following.
- Type of gel polymer (in most cases a polyacrylamide polymer; microbial products and lignosulfonate have also been applied)
- Type of crosslinking agent (metal ion or organic)
- Fluid used to mix the gel (fresh water or produced water)
Properties of the gel (subject to variation in different stages throughout gel treatment):
- Concentration of polymer
- Molecular weight of polymer
- Degree of crosslinking
- Viscosity (affects the size of cracks or fractures that can be penetrated at a given pressure; can inject as pre-mixed gel or as gelant)
- Density (if too dense, gel can sink too far into the water layer and lose effectiveness)
- Set-up time (influences how far into the cracks or fractures the gel will penetrate)
- Preparation of well before treatment
- Volume of gel used
- Injection pressure
- Injection rate
Reynolds et al. (2002) suggest using the following criteria for selecting candidate wells for gel-treatment.
- Wells already shut-in or near the end of their economic life
- Significant remaining mobile oil in place
- High water-oil ratio
- High producing fluid level
- Declining oil and flat water production
- Wells associated with active natural water drive,
- High-permeability contrast between oil- and water-saturated rock
The results of many successful gel treatment jobs have been reported in the literature. Seright et al. (2001) describe 274 gel treatments conducted in naturally fractured carbonate formations. The median water-to-oil ratio (WOR) was 82 before the treatment, then fell to 7 shortly after the treatment, and stabilized at 20 a year or two after treatment. On average, those wells produced much less water after the treatment. Following gel treatment, the oil production increased and remained above pretreatment levels for 1 to 2 years. Thomas et al. (2000) report that an initial investment of $231,000 for gel treatments resulted in incremental profits of $1.7-2.3 million over a two-year period. Green et al. (2001) discuss a series of gel treatments at four Kansas wells. These cost $14,000 to $18,000 per well, including polymer and well servicing. In the wake of the treatments, total oil production increased by about 30 bbl/d, while water production dropped by about 1,000 bbl/d. Lifting costs associated with the lower fluid volume were reduced by about $300/month/well. Due to reduced stress on the lifting equipment, well-servicing costs dropped about $2,400/year/well. Through mid-2000, about 37,500 bbl of incremental oil were economically recovered, representing about $1.60 per incremental bbl to date. Several years of production are still anticipated. The gel polymer treatments extended the economic life of the lease by at least seven years.
Green, J., R. Prater, and D. McCune, 2001, "Gel Polymer Treatment Provide Lasting Production, Economic Benefits," World Oil, March supplement of online version at WorldOil.com.
Reynolds, R.R., and R.D. Kiker, 2003, "Produced Water and Associated Issues — A Manual for the Independent Operator," Oklahoma Geological Survey Open File Report 6-2003, prepared for the South Midcontinent Region of the Petroleum Technology Transfer Council.
Seright, R.S., R.H. Lane, and R.D. Sydansk, 2001, "A Strategy for Attacking Excess Water Production," SPE 70067, presented at the SPE Permian Basin Oil and Gas Recovery Conference, Midland, TX, May 15-16. [Note that this paper contains a detailed reference list that can point readers to a wealth of relevant literature.]
Thomas, F.B., D.B. Bennion, G.E. Anderson, B.T. Meldrum, and W.J. Heaven, 2000, "Water Shut-Off Treatments - Reduce Water and Accelerate Oil Production," Journal of Canadian Petroleum Technology 39(4):25-29, April.
Veil, J.A., M.G. Puder, D. Elcock, and R.J. Redweik, Jr., 2004, "A White Paper Describing Produced Water from Production of Crude Oil, Natural Gas, and Coal Bed Methane," prepared by Argonne National Laboratory for the U.S. Department of Energy, National Energy Technology Laboratory, Jan. Available at http://www.evs.anl.gov/pub/dsp_detail.cfm?PubID=1715.