Oil field scales

Conventional polymer and phosphonate scale inhibitors may not be appropriate for application in high-pressure and high-temperature reservoirs. Only a limited range of commercially available oil field scale inhibitor chemicals are sufficiently thermally stable at temperatures above 150° C. These chemicals are homopolymers of vinyl sulfonate and copolymers of acrylic acid... 

The most common oil field scales are calcium carbonate, or calcite (CaCOj) calcium sulfate (CaSO and barium sulfate, or barite (BaSO. Calcite is the most common and the most easily treatable. Calcium sulfate scale is usually present in the... 

E. P. Katsanis, P. H. Kmmrine, and J. S. Ealcone, Jr., "Chemistry of Precipitation and Scale Formation in Geological Systems," SPE preprint 11802, National Symposium on Oil Field and Geothermal Chemisty, Denver, Colo., June 1, Society of Petroleum Engineers, 1983. 

Field desorption mass spectrometry [1606], C nuclear magnetic resonance, and fourier-transform infrared spectroscopy [1337] have been used to characterize oil field chemicals, among them, scale inhibitors. Ion... 

Particularly preferred bacteria are those of the genera Lactobacillus or Pediococcus. Lactic acid produced by bacteria may also be used for removal of carbonate or iron scale in oil field equipment [395],... 

Pressure management, where fluid is injected into oil fields in order to maintain adequate fluid pressure in reservoir rocks. Calcium carbonate may precipitate as mineral scale, for example, if pressure is allowed to deteriorate, especially in fields where formation fluids are rich in Ca++ and HCO3 and CO2 fugacity is high. 

Sulfate scaling poses a special problem in oil fields of the North Sea (e.g., Todd and Yuan, 1990, 1992 Yuan et al., 1994), where formation fluids are notably rich in barium and strontium. The scale can reduce permeability in the formation, clog the wellbore and production tubing, and cause safety equipment (such as pressure release valves) to malfunction. To try to prevent scale from forming, reservoir engineers use chemical inhibitors such as phosphonate (a family of organic phosphorus compounds) in squeeze treatments, as described in the introduction to this chapter. 

Table 30.1 shows the compositions of formation waters from three North Sea oil fields, and the composition of seawater (from Drever, 1988). The origin of the scaling problem is clear. Seawater contains more than 2500 mg kg-1 of sulfate but... 

Amy Berger helped me write Chapter 10 (Surface Complexation), and Chapter 31 (Acid Drainage) is derived in part from her work. Edward Warren and Richard Worden of British Petroleum s Sunbury lab contributed data for calculating scaling in North Sea oil fields, Richard Wendlandt first modeled the effects of alkali floods on clastic reservoirs, and Kenneth Sorbie helped write Chapter 30 (Petroleum Reservoirs). I borrowed from Elisabeth Rowan s study of the genesis of fluorite ores at the Albigeois district, Wendy Harrison s study of the Gippsland basin, and a number of other published studies, as referenced in the text. 

As a matter of example (a) In the United States no large (greater than 1 billion barrels) oil field has been discovered since 1960, and on a global scale, discoveries for the last 10 years of the 20111 century have been about 10 billion barrels per year in a world economy in which current consumption is about 27 billion barrels per year and (b) for... 

The U.S. Department of Energy s (DOE s) Los Alamos National Laboratory (LANE) conducted a cost analysis of the circulating fluidized-bed combustor based on the full-scale remediation of a former oil field on the Kenai Peninsula in Alaska. The LANE determined that the remediation cost ranged from 150 to 300 per ton when treating 20,000 to 50,000 tons of soil. For the treatment of 10,000 to 15,000 tons of contaminated soil, the cost ranged from 350 to 400 per ton. These estimates exclude the cost of excavation (D21225Z, p. 63). 

This Is the first In o series of articles covering the handling of oil field waters. Some fundamental principles and equipment (skim tanks and basins) are reviewed in this article. Subsequent presentations will focus on coalescers. flotation-equipment selection. steamfiood scale and corrosion, and steam quality. 

Li, P., Sun, T., Stagnitti, F. et al. (2002). Field-scale bioremediation of soil contaminated with crude oil. Environmental Engineering Science, 19, 277-89. 

For the field-scale projects that have been initiated, calculated optimum CO2 injection volumes ranged from 20 to 50 percent of the hydrocarbon pore volume. Predicted carbon dioxide utilization factors ranged from 5 to 15 Mcf C02/bbl of recovered oil. Projected ultimate enhanced oil recoveries ranged from 5 to 30 percent of the original oil-in-place (Soc. Petrol. Engrs. Forum Series, "Monitoring Performance of Full-Scale CO2 Projects," August 17-21, 1987). 

Within oil-field emulsion breaking, the economics usually favor minimal heat input because light ends are not lost to the gas phase and fuel-gas consumption is minimized. Other significant effects caused by the addition of heat are an increased tendency toward scale deposition on fire tubes, an increased potential for corrosion in treating vessels, and a tendency to render asphaltenes insoluble (because of loss of light aromatic components), which may produce an interface pad problem. 

CANMET has a pilot-scaled emulsion-treatment plant (Figure B.l) available to industry for pilot-scaled investigation of heavy-oil-bitumen separation from oil-field-produced waters. This facility is designed to process emulsions at a throughput between 130 L/h (20 barrels per day) and 460 L/h (70 barrels per day) for raw bitumen-oil of API gravity between 8 and 15 (i.e., density between 1014 and 966 kg/m, respectively). 

For baseline option as water drive By the scale of the pilot project in JiLin Oil Field, it is estimated that annual CO2 emission mitigation will reach 3.56 kt-C or 13.07 kt-C02, in which the net CO2 emission mitigation per unit oil production is 0.64 t-C02/t-oil. 

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