Liquid purification or separation – Processes – Liquid/liquid solvent or colloidal extraction or diffusing...
Reexamination Certificate
2002-03-08
2003-12-16
Walker, W. L. (Department: 1723)
Liquid purification or separation
Processes
Liquid/liquid solvent or colloidal extraction or diffusing...
C210S641000, C210S729000, C210S806000, C210S912000
Reexamination Certificate
active
06663778
ABSTRACT:
BACKGROUND OF THE INVENTION
Formation waters are often produced concurrently with oil and/or gas. Higher amounts of produced waters occur during the middle or later stage of the primary production after water breakthrough. A further increase in the amounts of such waters also occurs during the secondary treatment, in which large amounts of waters are injected from the surface into the reservoir formation to sustain oil and/or gas production. In some cases, the amounts of produced waters could reach 90% or more of the total fluids produced.
Chloride is the dominant anion in most produced waters, with the exception of a few cases where sulfate and bicarbonate exceed chloride by weight. Chloride-rich produced waters that are high in calcium (in larger portions than in seawater) are generally high in alkaline cations such as strontium, barium, and in some cases radium. The availability of radium in produced waters suggests that the decay chain of radium, referred to as Naturally Occurring Radioactive Materials (NORM), are common and thus such waters can become radioactive.
Factors such as: (1) changes in pressure or temperature or pH or combinations of these parameters; (2) variations in flow rates, impurities, additives, fluid expansion, and gas evaporation; and (3) mixing of incompatible waters cause scale formation (mainly strontium and barium in the form of sulfate). However, the mixing of incompatible waters is the primary reason for scale formation. The formation of scale salts can lead to production problems in primary oil wells, secondary oil wells, injection wells, disposal wells, pipelines, and process equipment. In addition, external radiation (near any processing equipment) and internal radioactive hazards (during maintenance or workover) could exist due to NORM buildup during processing, referred to as Technologically Enhanced Naturally Occurring Radioactive Materials (TENORM).
In offshore oil and gas reservoirs (e.g., Gulf of Mexico, North Sea, etc.), pressure maintenance with water injection is required over the reservoir life to maintain oil and/or gas production. The salinity of seawater is to a large extent compatible with the salinity of produced waters in most reservoirs. Table 1 presents the concentrations of inorganics in seawater and samples of produced waters (Hardy, J. A. and Simm, I., “Low Sulfate Seawater Mitigates Barite Scale” Oil & Gas J. (1996) Dec. 9: 64-67). Barium and strontium in produced waters are typically in the form of chloride. However, direct injection of seawater, with about 2,700 ppm of sulfate ion, would react with barium and strontium in the reservoirs, to form sulfate scales. This would lead to flow problems and subsequent plugging in producing wells as well as possible formation of a significant radioactive scale. In spite of a large number of proprietary chemicals in blends available as scale inhibitors and dissolvers, scale prevention with such chemicals has proved difficult, very expensive, and of limited value for solving the scale problem or protecting the reservoir formation matrix. Injection of potable water (although it's an expensive option in offshore fields) could damage the formation by causing clays in the reservoir matrix to swell and block pores (incompatible salinity). Nearly-sulfate free seawater would be acceptable for injection into offshore and some onshore reservoirs. This would also prevent the reservoir from souring (due to sulfate conversion to hydrogen sulfide via thermophilic sulfate reducing bacteria). However, the nearly-sulfate free seawater substantially minimizes but not entirely eliminates scale formation (due to the very low aqueous solubilities of barium and strontium sulfate).
Another example of incompatible waters is the mixing of produced waters from different production zones. It is not uncommon that the chemistry of produced waters differs considerably from zone to zone within the same processing facilities. The mixing of incompatible waters causes almost immediate scale build-up, which leads to expensive problems (e.g., stuck downhole pumps, plugged perforations and tubing strings, choked flowlines, frozen valves, equipment damage, and downtime during maintenance).
A further example of mixing incompatible waters is that nearly all onshore oil-field produced waters are injected into subsurface formation through injection wells. In addition to the possible formation of scale and NORM hazards, two further problems are of major concern. The first problem is the seepage of the disposed produced waters to contaminate (mainly salinity and possibly radioactivity) sources of potable waters such as near by rivers, lakes, and shallow groundwater. The second problem is the incompatibility between the injected produced waters and the existed formation water in the disposal wells that could lead to destroy the injectivity by plugging the pores of the permeable zone in the disposal wells.
These two problems can be illustrated in the natural brine seepage into the Dolores River in Paradox Valley (Colorado), which increases the dissolved solids of the Colorado River annually by about 200 million kilograms. The Colorado River is a major source of water for both the United States and the Republic of Mexico. To solve this problem, about 3540 cubic meters per day of brine needs to be pumped from shallow brine wells (TDS: 250,000 ppm) located along the Dolores River into a very deep injection well (Mississippian Leadville Limestone). This volume of continuous pumping is needed to create a cone of depression in the brine field near the river that should fill with freshwater and stop brine seepage. Table 2 presents the concentrations of inorganic species from several brine wells and the injection well (Kharaka, Y. K., et al., “Deep Well Injection from Paradox Valley, Colo.: Potential Major Precipitation Problems Remediated by Nanofiltration”, Water Resour. Res. (1997) 33: 1013-1020). The injection of such brine waters into the formation water of the injection well clearly will lead to the formation of a huge mass of calcium sulfate in conjunction with barium and strontium sulfate at downhole. This would plug the permeable zone of the injection well.
The pressure-driven nanofiltration (NF) membrane process is a potential technology for solving such sulfate scale problems. NF organic membranes are capable of efficiently rejecting divalent ions while retaining monovalent ions.
FIG. 1
depicts the rejection of magnesium sulfate and sodium chloride by NF (Davis, R., et al., “Membranes Solve North Sea Waterflood Sulfate Problems” Oil & Gas J. (1996) Nov. 25: 59-64). The rejection of sulfate is constantly very high (about 98%) regardless of the operating pressures, while the rejection of chloride is relatively low and increases with the increase of the operating pressures. However, several problems are associated with the use of NF.
First, extensive pretreatment is essential for reliable NF system, particularly in the case of treating seawater. Chemical coagulation (polyelectrolyte) and pre-filtration are needed to coagulate suspended particles to sufficient sizes so that they can be removed via filtration. Bacteria remediation (adding sodium hypochlorite or free chlorine to seawater) is also needed to prevent bacteria growth (plugs the pores of the organic membrane) and subsequent biofilm formation resulting in biological membrane fouling. This would, in turn, require: (1) the addition of sodium metabisulfate to remove the added chlorine, and thus to prevent it from oxidizing the membrane; and (2) placement of a de-oxygenation or a de-aerator system (to reduce oxygen content).
Second, NF membranes recover at best 75% of the feed stream. The remaining 25% (concentrate stream) represents one-fourth of the feed stream and thus contains roughly four-times the initial concentrations of the feed species. For instance, the high rejection of 2,700 ppm of sulfate (about 98%) from seawater roughly translates to 11,000 ppm in the concentrate stream. About one-third of calcium is simultaneously rejected with sulfate. The combine
Fellers Snider Blankenship Bailey & Tippens, P.C.
Menon K S
Walker W. L.
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