Patent Application
20140345868
1. Field of the Invention
The present invention relates to the prevention of scale formation and enhancement of core permeability in oil reservoirs, and particularly to a method of maintaining oil reservoir pressure in order to keep the production rate constant.
2. Description of the Related Art
Subterranean oil reservoirs, whether below dry land or below the sea, typically involve deposits of oil formed in a matrix of porous rocks, often called the core. A portion of the oil may collect in an underground pool or zone. Water that may have been present during the formation of the oil or that drains through the geological strata is denser than oil, and therefore collects in a water zone below the zone of oil. Various minerals that may be present in the core or rock formation may leach into the water zone, so that the waters that collect in the water zone are often referred to as the formation brine. Any gases that may be present or formed in the reservoir are usually above the zone of oil. The weight of the geological strata above the oil reservoir causes the oil reservoir to be under pressure. Often, this natural pressure of the oil reservoir is sufficient to result in the spontaneous release or gushing of oil when the oil reservoir is first tapped by drilling an oil well. However, after sufficient oil has been released from the reservoir, the pressure drops, and it becomes necessary to find some means of increasing the pressure of the oil reservoir, or to find some other means of extracting oil from the reservoir, sometimes referred to as enhanced oil recovery (EOR).
One way to increase the pressure of the oil reservoir is to inject water into the water zone below the pool of oil. This requires a large quantity of water. In many locations, the largest and most convenient source of water is seawater. However, seawater often contains sulfates, carbonates, and other free ions. The formation brine in the water zone below the zone of oil frequently contains mineral salts or metal ions, such as calcium, strontium, magnesium, barium, and the like. The solubility product of some salts, such as barium sulfate, calcium carbonate, etc., is so low that injecting seawater into the formation brine and mixing the two incompatible fluids results in the precipitation of these salts, which form scale deposits in the water injection pipes and equipment, as well as in the oil drilling equipment. The formation of scale in the water injection equipment and in the drilling, pumping, and other well equipment may become so bad that it may shut down oil production completely until the scale can be removed, when that is possible.
Scale deposition is one of the most serious concerns in oil reservoirs, particularly in water injection systems therefor. Scale problems are particularly prevalent in systems which combine two incompatible types of water, such as seawater and formation brines. Two types of water are considered to be incompatible if they interact chemically and precipitate minerals when mixed. Typical examples include seawater with high concentrations of sulfate ions (at least 4,000 ppm) and formation waters, with high concentrations of calcium, barium and strontium ions (often more than 30,000 ppm). Mixing of these waters may cause precipitation of calcium sulfate, barium sulfate and/or strontium sulfate.
Scale formation in surface and subsurface oil and gas production equipment is not only a major operational problem, but also a major cause of formation damage in both injection and production wells. Scale formation may cause equipment wear and corrosion, along with flow restriction which results in a decrease in oil and gas production due to the excessive pressure drop. Scale deposition further restricts the oil and gas flow by decreasing the area available for flow (by a decrease of the flow pipe's diameter), which, in turn, causes an increase in the friction pressure losses. The latter consideration affects the flowing bottom hole pressure, and consequently the outflow performance of the well. The lowered outflow performance lowers the well's draw down and decreases the overall deliverability of the well. Scale deposits often form at the tops of wells, requiring removal of the associated pipes and tubing, which generates high operational costs and temporary work stoppages.
Scale control is typically performed as a two-step treatment involving first removal of the precipitated scale, and then prevention of its reformation by chemical inhibitors. At present, there is no effective single-stage treatment that will both remove and inhibit scale precipitation in oil and gas reservoirs during the process of water injection in enhanced oil recovery or pressure maintenance processes.
Typical scales formed in such environments include calcium sulfate and calcium carbonate. These deposits can typically be removed chemically. However, scale composition frequently changes during the production history of the well, causing many scales that are initially subject to chemical removal treatments to become very difficult to be removed by subsequent chemical treatment. There are many chemicals available that will prevent scale deposition. However, most of these chemicals will not remain in the formation long enough to make them economically feasible as inhibitors.
The major components of most oil field scale precipitates are calcium carbonate, calcium sulfate and barium sulfate. Other components that are occasionally found include strontium sulfate, strontium carbonate, barium carbonate and magnesium carbonate. Additional corrosion precipitates may also be found, such as iron oxide, iron sulfide and pyrite. Further, bacterial residues are also frequently found along with inorganic scale in water injectors. Oil field scales are rarely found to be pure calcium sulfate or calcium carbonate. Rather, they are usually a mixture of one or more of the major inorganic components in addition to corrosion products, etc. Many oil wells suffer from flow restriction because of scale deposition within the oil producing formation matrix and the downhole equipment, generally in primary, secondary and tertiary oil recovery operations, as well as scale deposits in the surface production equipment. Although there are a wide variety of reasons that scale may form, supersaturation is the most prevalent reason for scale mineral deposition.
A supersaturation condition occurs when a solution contains dissolved materials that are at larger concentrations than their equilibrium concentration. The degree of supersaturation, also known as the scaling index, is the main driving force for the deposition reaction. Thus, a high supersaturation condition implies an increased chance for mineral scale precipitation. Scale can occur at any point in the production system in which a supersaturation condition exists. Supersaturation can be generated in a single water by changing the pressure and temperature conditions, or in a mixture by mixing two incompatible waters. Changes in temperature, pressure, pH, and CO2/H2S partial pressure may also contribute to scale formation and deposition.
Barium sulfate (BaSO4) scale is one of the most dangerous scales found in oil field operations. Mixing of two incompatible waters (one containing an excess of sulfate ions and the other containing an excess of barium ions) is the most common origin of BaSO4 precipitation. After mixing of the two waters, the solubility product of BaSO4 (Ks) is exceeded and precipitation of BaSO4 crystals occurs.
The injection of seawater into oil field reservoirs to maintain reservoir pressure and improve secondary recovery is a well-established operation in oil production. Deposition of mineral scales in the seawater injection system is one of the most serious oil field problems. As noted above, scale deposition is particularly prevalent when two incompatible waters are involved. In order to avoid such scaling, it is often necessary to pre-treat the seawater with scale inhibitors, or by dilution to reduce the concentration of sulfates and carbonates in the seawater, or by other methods that are commercially very expensive. In addition, pre-treatment may be used to remove bacteria that might otherwise produce precipitates that contribute to scaling.
Thus, a method for maintaining oil reservoir pressure solving the aforementioned problems is desired.
The method of maintaining oil reservoir pressure involves injecting seawater having a concentration of about 1 wt % of a polyamino carboxylic acid or salt thereof as a chelating agent into the water zone of an oil reservoir, which reduces the formation of scale, thereby maintaining oil reservoir pressure. The polyamino carboxylic acid may be ethylenediaminetetraacetic acid (EDTA), hydroxyethyl ethylenediaminetriacetic acid (HEDTA), or hydroxyethyliminodiacetic acid (HEIDA). When used in larger concentrations, e.g., between 5 to 10 wt %, flooding the core with seawater containing the polyamino carboxylic acids not only prevents scale formation, but also improves core permeability. Instead of seawater, low salinity water may be used for the latter purpose.
These and other features of the present invention will become readily apparent upon further review of the following specification.
Similar reference characters denote corresponding features consistently throughout the attached drawings.
The method of maintaining oil reservoir pressure involves injecting seawater having a concentration of about 1 wt % of a polyamino carboxylic acid or salt thereof as a chelating agent into the water zone of an oil reservoir, which reduces the formation of scale, thereby maintaining oil reservoir pressure. The polyamino carboxylic acid may be ethylenediaminetetraacetic acid (EDTA), acid (HEDTA), or hydroxyethyliminodiacetic acid (HEIDA). When used in larger concentrations, e.g., between 5 to 10 wt %, flooding the core with seawater containing the polyamino carboxylic acids not only prevents scale formation, but also improves core permeability. Instead of seawater, low salinity water may be used for the latter purpose. The polyamino carboxylic acid chelating agents essentially form a ring of organic ligands around and mineral or metal ions (calcium, barium, magnesium, etc.) in the formation brine, precluding the formation of scales. The principles of the method will now be illustrated by the following examples.
As a control, untreated seawater with a high sulfate content (shown in Table 1) was injected into a Berea sandstone core that was initially saturated with brine having the composition summarized in Table 1. The contents of the seawater (with both high and low salinities) and the connate water (formation waters or brine that is trapped in the pores of sedimentary rocks) are shown below in Table 1. Calcium sulfate in mineral form was found to have precipitated in the sandstone core, as expected.
A acid (HEDTA) chelating agent was added to the seawater in a 5 wt % concentration at a pH of 11. Following this addition, 100% of the calcium in solution was chelated and no sulfate precipitation occurred. The core permeability was 80 mD before the flooding and was 86 mD after the flooding with the HEDTA solution. The increase in permeability was due to some of the cations chelated from the Berea sandstone cores dissolving in the solution, and this dissolution improved the core permeability. The CT number profile, shown in
In addition to HEIDA, ethylenediaminetetraacetic acid (EDTA) was also tested. At 1 wt % in seawater, EDTA was found to be an effective chelant in inhibiting the precipitation of calcium sulfate scale during seawater injection, while showing no loss in core permeability, as shown below in Table 2.
Two core flood experiments were also conducted using HEDTA at two different concentrations, as shown below in Table 3. In addition to preventing scale formation, the 5 wt % HEDTA/seawater improved the core permeability by 15%. The 1 wt % HEDTA was found to be effective in prevention of scale precipitation, but did not significantly increase core permeability.
Table 4, below, shows the effect of adding the HEIDA chelating agent to the seawater. A 5 wt % HEIDA solution was found to prevent calcium sulfate precipitation, but no improvement in the core permeability was observed. HEIDA is a weak calcium chelant, compared to HEDTA and EDTA. Thus, it needs to be used at high concentrations (at least 5 wt %). All of the core flood experiments were performed at 100° C. using 5-inch Berea sandstone cores.
The same set of experiments was performed using varying concentrations of HEDTA chelating agents under the same conditions used above for EDTA. As shown in
We had expected the same for calcium sulfate precipitation reduction, but this was not the case. The sulfate concentration of 4,290 ppm caused 28% loss in the core permeability, so that reducing the sulfate concentration to 25% of its original concentration should reduce the damage from 28% to 7%. However, the damage in the low salinity, low sulfate content seawater was 13%, which was almost half that of the high sulfate content seawater. Diluting the seawater affected the solubility of calcium sulfate, and decreasing sodium chloride concentration decreased the solubility of calcium sulfate, so that more sulfate will be precipitated at a higher rate than that of the high salinity seawater. Reducing sodium concentration enhanced the performance of HEDTA in preventing calcium sulfate precipitation than in seawater. This can be attributed to the high stability of HEDTA in low salinity water, along with the effect of sodium chloride decreasing the chelating ability of HEDTA/EDTA solution. Reducing sodium chloride concentration allowed the HEDTA to chelate more calcium from the solution and from the rock. Thus, the permeability enhancement was greater in the case of HEDTA diluted with low salinity water than that diluted with high salinity seawater.
It is to be understood that the present invention is not limited to the embodiments described above, but encompasses any and all embodiments within the scope of the following claims.
