US20140345868A1

US20140345868A1 - Method of maintaining oil reservoir pressure

Info

Publication number: US20140345868A1
Application number: US13/899,508
Authority: US
Inventors: Mohamed Ahmed Nasr El-Din Mahmoud; Mohammed Attia Gadallah
Original assignee: King Fahd University of Petroleum and Minerals
Current assignee: King Fahd University of Petroleum and Minerals
Priority date: 2013-05-21
Filing date: 2013-05-21
Publication date: 2014-11-27

Abstract

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.

Description

BACKGROUND OF THE INVENTION

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 BaSO₄precipitation. After mixing of the two waters, the solubility product of BaSO₄(K_s) is exceeded and precipitation of BaSO₄crystals 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.

SUMMARY OF THE INVENTION

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.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a graph showing a computed tomography (CT) scan number profile along a Berea sandstone core sample axis before flooding and after flooding by a seawater control sample.

FIG. 2 is a graph showing a computed tomography (CT) scan number profile along a Berea sandstone core sample axis before flooding and after flooding by a hydroxyethyl ethylenediaminetriacetic acid (HEDTA)/seawater chelating fluid according to the present invention.

FIG. 3 is a graph comparing improvements in Berea sandstone core permeability for ethylenediaminetetraacetic acid (EDTA)/seawater chelating fluids according to the present invention at varying concentrations of EDTA.

FIG. 4 is a graph comparing improvements in Berea sandstone core permeability for hydroxyethyl ethylenediaminetriacetic acid (HEDTA)/seawater chelating fluids according to the present invention at varying concentrations of HEDTA.

FIG. 5 is a graph comparing improvements in Berea sandstone core permeability for hydroxyethyliminodiacetic acid (HEIDA)/seawater chelating fluids at varying concentrations of HEIDA.

FIG. 6 is a graph comparing improvements in Indiana limestone core permeability for ethylenediaminetetraacetic acid (EDTA)/seawater chelating fluids according to the present invention at varying concentrations of EDTA.

FIG. 7 is a graph comparing improvements in Indiana limestone core permeability for hydroxyethyl ethylenediaminetriacetic acid (HEDTA)/seawater chelating fluids according to the present invention at varying concentrations of HEDTA.

FIG. 8 is a graph comparing improvements in Indiana limestone core permeability for hydroxyethyliminodiacetic acid (HEIDA)/seawater chelating fluids at varying concentrations of HEIDA.

FIG. 9 is a graph comparing improvements of core permeability in both Berea sandstone and Indiana limestone core samples for ethylenediaminetetraacetic acid (EDTA)/seawater chelating fluids according to the present invention at varying concentrations of EDTA.

FIG. 10 is a graph comparing improvements in Indiana limestone core permeability for hydroxyethyl ethylenediaminetriacetic acid (HEDTA)/seawater chelating fluids according to the present invention at varying concentrations of HEDTA using low salinity water injection.

Similar reference characters denote corresponding features consistently throughout the attached drawings.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

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.

TABLE 1

Composition of High and Low Salinity Water and Formation Brine

	Connate	Low Salinity	High Salinity
Ions	Water (ppm)	Water (ppm)	Water (ppm)

Sodium	59,491	4,575	18,300
Calcium	19,040	163	650
Magnesium	2,439	528	2,110
Sulfate	350	1,073	4,290
Chloride	132,060	8,050	32,200
Bicarbonate	354	30	120
TDS	213,734	14,418	57,670

FIG. 1 shows the computed tomography (CT) scan number profile along the core axis before flooding and after flooding by seawater. The average CT number of the Berea sandstone core saturated with formation brine (the connate water composition shown in Table 1) was around 1,750. After injecting the seawater (the high salinity composition in Table 1) into the core, calcium sulfate precipitated, and the CT number profile shows peaks at certain locations in the core. The CT number in these peaks approaches 2,800, which indicates calcium sulfate mineral deposits. The permeability of the sandstone cores before seawater injection was 80 mD, and the permeability after injecting two pore volumes of seawater (60 mL) was 63 mD. There was almost 20% loss in permeability due to sulfate precipitation in the core.
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 FIG. 2, confirms the efficiency of the HEDTA solution, and the CT number is almost the same before and after the HEDTA/seawater injection (approximately 1,750, as shown in FIG. 2). A hydroxyethyliminodiacetic acid (HEIDA) chelating agent was also tested for prevention of sulfate precipitation. The HEIDA solution was found to be effective in prevention scaling, but did not affect core permeability, since HEIDA is only a weak calcium chelant. In the experiment illustrated in FIG. 2, the solution was injected at a rate of 0.5 mL/min at a temperature of 100° C.
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.

TABLE 2

Effect of Adding 1 wt % EDTA/Seawater on Core Permeability

		1 wt %
	Seawater	EDTA/
	Injection	Seawater

Initial permeability (mD)	34	57
Final permeability (mD)	29	57
Permeability loss %	15	0

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 3

Effect of Adding HEDTA on Core Permeability

	5 wt %	1 wt %
Seawater	HEDTA/	HEDTA/
Injection	Seawater	Seawater

Initial permeability (mD)	34	53	61
Final permeability (mD)	29	61	62
Permeability loss %	15	No loss	No loss

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.

TABLE 4

Effect of Adding HEIDA on Core Permeability

		5 wt %
	Seawater	HEIDA/
	Injection	Seawater

Initial permeability (mD)	34	54
Final permeability (mD)	29	54
Permeability loss %	15	0

FIG. 3 shows the effect of EDTA concentration on the permeability of Berea sandstone cores. A low concentration of EDTA (1 wt %) was only able to prevent the sulfate precipitation and did not chelate any cations from the core. Thus, the permeability of the core was almost the same before and after seawater injection. The initial permeability of the core was 80 mD and the final permeability after seawater injection was 79 mD. Increasing the concentration of EDTA to 5 wt % resulted in the prevention of sulfate precipitation by chelating all calcium in solution, in addition to enhancing the core permeability from 73 to 82 mD (K_finalK_initial=1.125). The 5 wt % concentration of EDTA was able to chelate other cations, such as Mg²⁺ and Fe³⁺, from the core. Increasing the concentration to 10 wt % enhanced the permeability even further, as more cations were chelated from the core (Ca²⁺ from calcite and dolomite, Mg²⁺ from dolomite, and Fe³⁺ from chlorite). The permeability improvement ratio was 1.3.
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 FIG. 4, the performance of HEDTA was almost the same as EDTA in preventing sulfate scale precipitation and enhancing the sandstone core permeability. Multiple experiments confirmed the performance of EDTA and HEDTA in stimulating Berea sandstone cores, the overall performance being approximately the same for both. Both EDTA and HEDTA have the ability to chelate calcium, magnesium, aluminum, and iron from Berea sandstone cores. The iron can be chelated from chlorite mineral, calcium and magnesium can be chelated from calcite and dolomite, and aluminum can be chelated from other clay minerals, such as illite and kaolinite.
FIG. 5 shows the effect of using a HEIDA chelating agent on sulfate scale formation and on the enhancement of core permeability. As shown in FIG. 5, HEIDA at 1 wt % concentration was not able to prevent the damage due to calcium sulfate precipitation (permeability ratio=0.8).
FIGS. 6, 7 and 8 show the effectiveness of using EDTA, HEDTA and HEIDA chelating agents, respectively, in preventing sulfate scale precipitation, and in the enhancement of core permeability in Indiana limestone cores. EDTA was found to be the best chelating agent in preventing precipitation damage and enhancing the core permeability, and HEIDA was found to be the weakest chelate among the three chelates used in the experiment. Generally, EDTA, HEDTA and HEIDA chelating agents at high concentrations (10 wt %) performed better in carbonate cores, due to their high chelation ability of calcium. HEIDA chelating agents at low concentrations were not found to be effective in carbonate cores and did not prevent precipitation damage.
FIG. 9 shows a comparison between the performance of EDTA chelating agents at pH=11 in Berea and Indiana limestone cores. EDTA at 1 wt % concentration performed the same in sandstone and carbonate, and was only able to chelate the calcium from the formation brine and the seawater. Increasing the concentration to 5 wt % and then 10 wt % made the EDTA chelating agents more powerful, and the 10 wt % solution was able to dissolve calcite in carbonate cores more effectively than in sandstone cores (a low carbonate concentration of 2 wt %).
FIG. 10 shows the effect of using the HEDTA solution to prevent calcium sulfate scale precipitation in Indiana limestone cores when low salinity seawater injection was used. The final concentration of HEDTA was obtained from an initial concentration of 40 wt % and it was diluted to 20 wt % using low salinity seawater having the composition shown in Table 1. The calcium sulfate precipitation greatly damaged the core during seawater injection because of the high sulfate content. Diluting the seawater reduced the sulfate concentration from 4,290 ppm to 1,073 ppm. Comparing the ratio of calcium sulfate in the low salinity and high salinity water from 4,290 to 1,073, the factor of dilution for sulfate is 4, which is the main source of damage.
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.

Claims

We claim:

1. A method of maintaining oil reservoir pressure, comprising the step of injecting untreated seawater containing an effective amount of a polyamino carboxylic acid or salt thereof as a chelating agent into the water zone of an oil reservoir to prevent scaling caused by precipitation of sulfates.

2. The method of maintaining oil reservoir pressure according to claim 1, wherein said effective amount of a polyamino carboxylic acid or salt thereof comprises about 1 wt % ethylenediaminetetraacetic acid (EDTA) or salt thereof.

3. The method of maintaining oil reservoir pressure according to claim 2, wherein said solution of EDTA in untreated seawater has a pH of about 11.

4. The method of maintaining oil reservoir pressure according to claim 1, wherein said effective amount of a polyamino carboxylic acid or salt thereof comprises about 1 wt % hydroxyethyl ethylenediaminetriacetic acid (HEDTA) or salt thereof.

5. The method of maintaining oil reservoir pressure according to claim 4, wherein said solution of HEDTA in untreated seawater has a pH of about 11.

6. The method of maintaining oil reservoir pressure according to claim 1, wherein said effective amount of a polyamino carboxylic acid or salt thereof comprises about 5 wt % hydroxyethyliminodiacetic acid (HEIDA) or salt thereof.

7. The method of maintaining oil reservoir pressure according to claim 2, wherein said solution of HEIDA in untreated seawater has a pH of about 11.

8. The method of maintaining oil reservoir pressure according to claim 1, wherein said effective amount of a polyamino carboxylic acid or salt thereof comprises between 5 wt % and 10 wt % ethylenediaminetetraacetic acid (EDTA) or salt thereof, whereby the oil reservoir core permeability is increased.

9. The method of maintaining oil reservoir pressure according to claim 8, wherein said solution of EDTA in untreated seawater has a pH of about 11.

10. The method of maintaining oil reservoir pressure according to claim 1, wherein said effective amount of a polyamino carboxylic acid or salt thereof comprises between 5 wt % and 10 wt % hydroxyethyl ethylenediaminetriacetic acid (HEDTA) or salt thereof, whereby the oil reservoir core permeability is increased.

11. The method of maintaining oil reservoir pressure according to claim 10, wherein said solution of HEDTA in untreated seawater has a pH of about 11.

12. The method of maintaining oil reservoir pressure according to claim 1, wherein said effective amount of a polyamino carboxylic acid or salt thereof comprises about 10 wt % hydroxyethyliminodiacetic acid (HEIDA) or salt thereof, whereby the oil reservoir core permeability is increased.

13. The method of maintaining oil reservoir pressure according to claim 12, wherein said solution of HEIDA in untreated seawater has a pH of about 11.

14. A method of increasing core permeability of an oil reservoir, comprising the step of flooding the core with untreated seawater containing an effective amount of a polyamino carboxylic acid or salt thereof as a chelating agent to chelate metals in mineral formations in the core.

15. The method of increasing core permeability of an oil reservoir according to claim 14, wherein said effective amount of a polyamino carboxylic acid or salt thereof comprises between 5 wt % and 10 wt % ethylenediaminetetraacetic acid (EDTA) or salt thereof.

16. The method of increasing core permeability of an oil reservoir according to claim 15, wherein said solution of EDTA in untreated seawater has a pH of about 11.

17. The method of increasing core permeability of an oil reservoir according to claim 14, wherein said effective amount of a polyamino carboxylic acid or salt thereof comprises between 5 wt % and 10 wt % hydroxyethyl ethylenediaminetriacetic acid (HEDTA) or salt thereof.

18. The method of increasing core permeability of an oil reservoir according to claim 17, wherein said solution of HEDTA in untreated seawater has a pH of about 11.

19. The method of increasing core permeability of an oil reservoir according to claim 14, wherein said effective amount of a polyamino carboxylic acid or salt thereof comprises about 10 wt % hydroxyethyliminodiacetic acid (HEIDA) or salt thereof.

20. The method of increasing core permeability of an oil reservoir according to claim 19, wherein said solution of HEIDA in untreated seawater has a pH of about 11.