US20060131022A1

US20060131022A1 - Matrix treatment of damaged sandstone formations using buffered HF-acidizing solutions

Info

Publication number: US20060131022A1
Application number: US11/297,824
Authority: US
Inventors: Philip James Rae; Gino Di Lullo Arias; Atikah Jamilah Ahmad
Original assignee: BJ Services Co USA
Current assignee: Baker Hughes Holdings LLC
Priority date: 2004-12-17
Filing date: 2005-12-08
Publication date: 2006-06-22
Also published as: AU2005244586B9; AU2005244586A1; AU2005244586B2; CA2530325C; CA2530325A1

Abstract

Sandstone formations of oil and gas and geothermal wells are effectively stimulated when a buffered HF-sandstone acidizing solution is employed without the prior introduction of an acid containing preflush solution. By not using a preflush solution, buffered HF-sandstone acidizing solutions are highly effective in dissolving and removing siliceous material while minimizing the formation of calcium fluoride.

Description

This application claims the benefit of U.S. Patent Application Ser. No. 60/637,134, filed on Dec. 17, 2004.

FIELD OF THE INVENTION

The invention relates to a method of stimulating or remediating sandstone formations of oil and gas and geothermal wells without the use of preflush acidizing solutions.

BACKGROUND OF THE INVENTION

In the course of drilling, or during production or workover, the vast majority of oil and gas wells are exposed to conditions that ultimately lead to formation damage. Formation damage limits the productive (or injective) capacity of the well. The reduction in well performance is generally due to changes in near-wellbore permeability which may be caused by a number of factors, such as rock crushing, invasion of drill solids, swelling of pore-lining clays, migration of mobile fines and changes in wettability.
It is known that permeability impairment may be improved by injecting acid formulations containing HF into the formation. Such treatments are capable of attacking and dissolving those siliceous minerals, such as clays and quartz fines, that are commonly associated with plugging of formation pore spaces. Unfortunately, the process of dissolving siliceous minerals is not simple. Further, during the process, numerous chemical species are generated by the interactions between the initial reactants and first, second and third stage reaction products. Driven by the unstable nature of many of these chemical interactions, voluminous solid precipitates or colloidal amorphous gels are often generated in the reaction mixture. The generation timing of such secondary and/or tertiary precipitates as well as their placement in critical locations, such as the near wellbore, ultimately may cause further formation damage and negate the benefit of the acid treatment. In an effort to mitigate these problems, several different approaches have been adopted. These include the use of:
(a.) HF formulations containing excess HCl. Exemplary of such formulations are those having a combination of HCl:HF in a 4:1 weight ratio. Recently, formulations having ratios as high as 9:1 have been adopted. This methodology lowers the pH of the HF mixture to levels at which some reaction products exhibit higher solubility.
(b.) delayed acid formulations. Such formulations only generate HF slowly, generally due to hydrolysis of one or more components. Deeper penetration of HF into the formation is the resulting effect. This effectively dilutes the concentration of the reaction product which, in turn, minimizes precipitation. Such formulations include fluoroboric acid, HBF₄.
(c.) half-strength mud acids. This strategy dilutes the concentration of reaction products per unit volume of acid treating solution but, unfortunately, also reduces the total quantity of siliceous minerals that can be dissolved per unit volume of acid.
(d.) buffered acid systems. Such systems essentially limit the availability of hydrogen ions for generation of HF. They allow deeper penetration due to lower reactivity. However, since the pH of such systems is high, additional measures must be adopted to prevent the generation of precipitates. Such measures include the incorporation of materials, such as phosphonates, into the system. Such materials inhibit the generation of precipitates. Preferred buffered acid systems include those sandstone acidizing solutions set forth in U.S. patent application Ser. No. 10/624,185, filed Jul. 22, 2003, herein incorporated by reference and BJ Sandstone Acid (“BJSSA”), a product of BJ Services Company.
(e.) overflush fluids. Such fluids are typically dilute HCl or ammonium chloride brine. They serve to push HF-containing acid stages, along with the unstable, dissolved reaction products dissolved in such acid stages, away from the near-wellbore region prior to precipitation of unwanted materials.
(f.) rapid flowback techniques. Such techniques serve to bring the treating formulations out of the formation and the well as quickly as possible. This typically occurs while the systems are characterized by a low pH when unwanted precipitation is less likely to occur.
Unfortunately, the secondary and tertiary precipitates generated by the interaction of HF with siliceous minerals are not the only problematic byproducts encountered when acid formulations containing HF enter a sandstone rock matrix. Most sandstones contain varying quantities of carbonate minerals (calcite, dolomite, etc) along with quartz, clays and feldspars that usually form the bulk of the rock. In the presence of acids, the carbonate minerals dissolve and release calcium ions that, in turn, react with fluoride ions to produce highly insoluble calcium fluoride, CaF₂. Calcium fluoride precipitates quickly and, instead of stimulating the formation, causes formation damage by blockage. Production is therefore dramatically decreased.
For this reason, traditional mud acid matrix treatments in sandstone formations are preceded by a preflush, usually consisting of HCl or other non-fluoride containing acid, to dissolve the carbonates. The preflush is pumped in sufficient volume to theoretically remove all carbonates within a radius of two to three feet from the wellbore. This dramatically reduces the risk of the principal HF-containing acid stage from contacting carbonate minerals.
While theoretically sound, such preflushes are not always as successful as desired. Often, the highly reactive preflush opens up preferential flow paths into the rock, due to dissolution of carbonate. As a result, damaged zones of the formation may be bypassed. The HF-containing acid when subsequently introduced may therefore follow these flow paths and thus may not contact the plugging clays and other siliceous minerals which it is designed to dissolve. The most severe effects are often seen in multistage treatments, e.g., those featuring sequential diversion. Since treatments are very complex—involving many repeat stages of preflush, main HF-stage, overflush as well as diverter—it is often difficult to ensure that the acid stage is properly entering the desired zone and encountering the appropriate mineralogy. This may result in very poor zonal coverage, poor damage removal, creation of unexpected damage due to acid/rock incompatibilities and, ultimately, poor stimulation results. These problems are especially evident when the majority of commercial, HF-containing acid systems are employed.
Alternative procedures for dissolving siliceous material in formations are therefore desired.

SUMMARY OF THE INVENTION

Sandstone formations of oil and gas and geothermal wells are more effectively stimulated when a buffered HF-sandstone acidizing solution is employed without the prior introduction of an acid-containing preflush solution. Buffered HF-sandstone acidizing solutions are highly effective in dissolving and removing siliceous material while minimizing the formation of calcium fluoride.
In a preferred mode, the buffered HF-sandstone acidizing solution contains at least one organic acid and/or salts or esters thereof. Preferred are citric acid, formic acid and phosphonate acids or salts as well as esters thereof, such as those of the formula:

wherein R1, R2 and R3 may be hydrogen, alkyl, aryl, phosphonates, phosphates, acyl amine, hydroxy and carboxyl groups and R4 and R5 may consist of hydrogen, sodium, potassium, ammonium or an organic radical.
The acidizing solution may further be employed in the remediation of oil and gas and geothermal wells by the removal of unwanted deposits from the wellbore and production equipment.

BRIEF DESCRIPTION OF THE DRAWINGS

In order to more fully understand the drawings referred to in the detailed description of the present invention, a brief description of each drawing is presented, in which:
FIGS. 1 and 3 illustrate the effect on permeability of a sandstone acidizing solution when the acidizing solution is introduced into a core without a preflush solution.
FIGS. 2 and 4 illustrate the effect on permeability when a preflush solution is introduced into the core prior to the introduction of the sandstone acidizing solution.

DETAILED DESCRIPTION OF THE INVENTION

Sandstone formations of oil and gas and geothermal wells may be stimulated, without use of a preflush solution, with a buffered HF-acidizing solution. The buffered sandstone acidizing solution, highly effective in dissolving and removing siliceous material, typically exhibits a pH between from about 1.9 to about 4.8, more typically between from about 2.5 to about 4.5.
The amount of HF in the acidizing solution is generally between from about 0.5 to about 20.0 weight percent, preferably between from about 1.5 to about 6.0 weight percent. (HF acid is, by definition, a weak acid being only partially dissociated in water, pKa=3.19.) In a preferred mode, the acidizing solution further contains an organic acid which assists in delaying reaction on clay minerals, thereby significantly slowing the HF acid reaction rate.
Acidizing solutions may contain one or more phosphonate acids or salts as well as esters thereof. Such systems may contain phosphonate materials of the formula:

wherein R1, R2 and R3 may be hydrogen, alkyl, aryl, phosphonates, phosphates, acyl amine, hydroxy and carboxyl groups and R4 and R5 may consist of hydrogen, sodium, potassium, ammonium or an organic radical. The concentration of the phosphonate acid in the acidizing solution is generally between from about 0.25 to about 50.0, preferably from about 0.5 to about 6.0, more preferably about 3, percent by volume of the total solution without regard to the HF acid concentration.
Examples of these materials include aminotri (methylene phosphonic acid) and its pentasodium salt, 1-hydroxyethylidene-1,1-diphosphonic acid and its tetrasodium salt, hexamethylenediaminetetra (methylene phosphonic acid) and its hexapotassium salt, and diethylenetriaminepenta (methylene phosphonic acid) and its hexasodium salt. Among the commercial phosphonate materials, preferred are amino phosphonic acids, such as 1 hydroxyethylidene-1,1-diphosphonic acid, otherwise known as “HV acid,” available in 60% strength as “DEQUEST 2010” from Monsanto Co.
Further suitable acids for the acidizing solution are organic acids, such as citric acid, acetic acid, or formic acid as well as those set forth in U.S. Pat. No. 6,443,230, herein incorporated by reference. In a preferred mode, the acidizing solution contains both a phosphonate acid (set forth above) as well as the organic acid of this paragraph. The amount of organic acid in the acidizing solution is typically between from about 1 to about 50 weight percent.
Suitable as the sandstone acidizing solution are those acid systems known in the art for dissolving the silicate and clay formations of the sandstone to increase its permeability. Especially preferred are those acidizing solutions described in U.S. Pat. No. 5,529,125, herein incorporated by reference.
A particularly preferred sandstone acidizing solution for use in the invention is BJ Sandstone Acid, a product of BJ Services Company, since it attacks calcium carbonate slowly and therefore is much less prone to the release of calcium ions and subsequent precipitation of calcium fluoride. In addition to being non-reactive with carbonate minerals, BJSSA does not require clay dissolution for stimulation response and can be formulated to have high HF strength and activity.
By not requiring use of a preflush solution, the method of the invention is more environmentally friendly than the methods of the prior art.
In addition to not requiring a preflush solution, in a preferred embodiment of the invention, an overflush solution is further not required. Where desired, conventional overflush solutions, such as ammonium chloride based overflush solutions, may be used. The use of no preflush, and optionally no overflush, solution, allows for minimal risk of undesired reactions with the reservoir rock.
Matrix acidizing in sandstone reservoirs is therefore greatly simplified in accordance with the invention. The need to pump multiple fluids in a carefully choreographed sequence is eliminated. Further, the invention improves acid placement and distribution and reduces equipment requirements, e.g., in terms of tankage, etc. The invention improves logistics, reduces cost, along with improved results, while simultaneously rendering treatments which are easier to implement and control at the field level.
Further, the invention, by not requiring use of a preflush solution, reduces the generation of iron-based precipitates. Iron is ubiquitous in the oilfield due to the use of steel tanks, lines and well tubulars. While iron is often not a problem in HF-containing systems, due to the formation of soluble fluoroferrate complexes, it becomes a great concern when conventional HCl based preflush solutions are employed. It is widely recognized that iron-based precipitates are responsible for many problems associated with acid stimulation treatments. Steel, consisting mainly of iron, is readily dissolved by strong mineral acids to produce ferrous (Fe ²⁺) ions. Contact with atmospheric oxygen readily transforms these to ferric (Fe ³⁺) iron, which precipitates easily from acid solutions, even at low pH. Contact with steel reverses this oxidation effect, to some extent, reducing ferric iron back to the ferrous state.
However, depending on circumstances, the ferric iron concentration in HCl can be extremely high due to the dissolution of the ferric oxides (rust) that quickly form when steel is exposed to air. For this reason, it is very much preferred that the well tubulars be “pickled” with a suitable rust dissolver (e.g. dilute acid) and the string contents reversed out, ahead of any acid treatment on the formation. Failure to do so results in the injection of extremely high levels of (mainly) ferric iron into the formation with a very high probability of plugging the zone. Even when using pickled tubulars, however, the level of iron in a mineral acid preflush can still reach several thousand mg/liter, necessitating the incorporation of high levels of iron-control agents to avoid precipitation.
Thus, the invention minimizes the risk of iron formation and further minimizes the need for use of rust dissolvers. By eliminating the use of a mineral acid preflush and using a buffered HF-acidizing solution in accordance with the invention, problems associated with iron dissolution and its subsequent precipitation are largely mitigated. Such an approach, when coupled with a tubing pickle, such as a neutral chelant pickling agent, significantly improves acidizing in many formations. A particular advantage of the invention is the ability to inject a neutral chelant pickling agent, containing the dissolved and complexed iron, etc., directly into the formation without having to reverse it out ahead of the acid treatment. Suitable neutral chelant pickling agents include conventional inert water-soluble polymeric chelants known in the art which are capable of chelating a polyvalent metal ion. These include polymeric chelants having a molecular weight of between about 600 and about 1,000,000.
In addition to its use in matrix acidizing, the invention is applicable in remediation of oil and gas and geothermal wells by the removal of unwanted deposits from the wellbore and production equipment. Such unwanted deposits form and/or accumulate in the wellbore, production and recovery equipment and well casing. Such accumulated deposits affect productivity and are typically removed prior to cementing or the introduction of completion fluids into the wellbore. Remediation treatment fluids are further typically used to remove such undesired deposits prior to the introduction of stimulation fluids. In a preferred embodiment, the invention is used to remove siliceous deposits inside well tubulars.
In well remediation applications, the acidizing solution is preferably injected directly into the wellbore through the production tubing or through the use of coiled tubing or similar delivery mechanisms. Once downhole, the solution remedies damage caused during well treating such as, for instance, by stimulation fluids and drilling fluid muds, by dispersing and removing siliceous materials from the formation and wellbore.

EXAMPLES

The following examples are illustrative and should not be construed as limiting the scope of the invention or claims thereof.
Unless otherwise indicated, all percentages are expressed in terms of weight percent.
BJ Sandstone Acid (BJSSA), a product of BJ Services Company, was employed as the buffered HF-acidizing solution.
BJ HSSA refers to half-strength BJ Sandstone Acid.

Example 1

About 100 ml of BJSSA and mud acid containing 12% HCl and 3% HF was placed into separate beakers. Then 2 grams of carbonate chips was added into the acids, under static conditions, at room temperature and at 180° F. and left to stand for 24 hours. The solubility of calcium carbonate in the HF-based acids is set forth in Table I:

TABLE I


ACID
SYSTEMS	OBSERVATIONS

BJSSA	No effervescence or precipitation even after 24 hrs when
	examined at room temperature and at 180° F.
Mud Acid	Strong effervescence and formation of white precipitate
	after initial 15 minutes at room temperature as well as
	at 180° F.

Table I illustrates the low reactivity of buffered HF-containing acidizing solution versus the rapid reaction of mud acid with calcium carbonate and the subsequent precipitation of calcium fluoride. The solubility of calcium carbonate is limited partly by the higher-than-normal pH of the buffered HF-acidizing solution (which reduces acid attack on the carbonate) and partly by the low solubility of calcium fluoride that is formed as a surface reaction product from the reaction of HF with calcium carbonate.

Examples 2-5

These Examples illustrate the effect of core flow testing using BJSSA on sandstone cores. Four separate core flow tests were conducted using 1.5 inch diameter and 2 inches length sandstone Berea core plugs with and without a preflush solution.
Prior to analysis, plugs were seated in rubber sleeves at 1000 psi confining pressure and flow saturated with filtered 3% NH₄Cl containing a strongly water-wetting surfactant, NE-118 (a nonionic surfactant, a product of BJ Services Company) at 1 gpt. The surfactant was added to ensure that the sandstone was water wet and to avoid the formation of microemulsions.
The flow was established in an arbitrary formation to wellbore (production) direction with 3% NH₄Cl brine to establish initial permeability. The flow was continued until a stable flow rate and permeability was obtained.

1. When flowing preflush, it was injected at 50 pore volumes in the reverse (injection) direction at constant flow rate of about 1 ml/min. When not flowing preflush, step 2 below was not followed.
2. The Main HF-based Acid was injected at 50 pore volumes in the reverse direction at constant flow rate of about 1 ml/min.
3. The acid was then overdisplaced with 3% NH₄Cl with 1 gpt Ne-118 brine at 25 pore volumes.

4. Flow was re-established in the production direction with 3% NH₄Cl until a stable flow rate and effective permeability to brine following treatment was obtained. The results are set forth in Table II below:

TABLE II


#	CORE TYPE	ACID FLOWED

2	Berea Core	BJ HSSA
Comp. 3	Berea Core	HCl Preflush & BJ HSSA
4	Core 4	BJ HSSA
Comp. 5	Core 5	HCl Preflush & BJ HSSA

The mineralogy of the cores was determined prior to core flow analysis by x-ray diffraction analysis. X-ray powder diffraction (XRD) is an analytical technique that bombards a finely powdered rock sample with monochromatic Cu k radiation and measures intensity of the scattered beam versus 2-theta angle of the instrument. These data are used in the Bragg equation to calculate d-spacing of the material(s) present. Bulk XRD samples are prepared by mechanically grinding the sample to a fine powder and backpacking the powder into a hollow-cavity sample mount. The results are set forth in Table III below:

TABLE III


MINERALOGY	APPROXIMATE WEIGHT %

TEST #/CORES	Ex. 2	Ex. 3	Ex. 4	Ex. 5

QUARTZ	98%	98%	65%	66%
CALCITE
	2%	2%	—	—
DOLOMITE	—	—	18%	18%
SIDERITE	—	—	3%	1%
PLAGIOCLASE FELDS	—	—	2%	3%
ILLITE	—	—	5%	5%
KAOLINITE	TRACE	TRACE		6%	7%

The core flow analysis is set forth in Table IV below:

TABLE IV


			REGAIN
		INITIAL	PERM,
Example #	ACIDS	PERM, md	md	RESULTS

2	BJ HSSA	7.55	17.96	138% increase
	NO PREFLUSH
3	BJ HSSA	7.80	17.96	130% increase
	HCl PREFLUSH

4	BJ HSSA	2.69	4.73	76% increase
	NO PREFLUSH
5	BJ HSSA	3.01	—	Fines plugging
	HCl PREFLUSH

The results are further set forth in FIG. 1 (Ex. 2), FIG. 2 (Comp. Ex. 3), FIG. 3 (Ex. 4) and FIG. 4 (Comp. Ex. 5). As set forth in the FIGs., permeability falls to zero in the preflushed core containing high carbonate levels. Note, in particular, FIG. 4.

The data shows that buffered HF acidizing solution may be injected into a sandstone matrix containing carbonate minerals without the use of a preflush. Similar responses are obtained in terms of permeability improvement of cores with minor carbonate content, regardless if preflushes are or are not employed. In the case of cores containing substantial quantities of carbonate, the buffered HF-containing acidizing solution with no preflush demonstrated a slight permeability improvement. The use of a preflush actually caused a reduction in permeability due to dissolution of carbonate cementitious minerals and the release of fines due to deconsolidation of the rock. Thus, the buffered HF-acidizing solution can beneficially be used in such circumstances since it requires no preflush. Conventional mud acid formulations, which require a preflush, cause significant problems with such cores. If a preflush is used, core deconsolidation will occur, as above, but if mud acid is injected into such cores with no preflush, calcium fluoride precipitation results along with impairment of permeability.
While the invention may be adaptable to various modifications and alternative forms, specific embodiments have been shown by way of example and described herein. However, it should be understood that the invention is not intended to be limited to the particular forms disclosed. Rather, the invention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the invention.
From the foregoing, it will be observed that numerous variations and modifications may be effected without departing from the true spirit and scope of the novel concepts of the invention.

Claims

1. A method for dissolving acid-soluble siliceous material in a sandstone formation of an oil or gas or geothermal well which comprises introducing into the well, in the absence of a preflush solution, a buffered HF-sandstone acidizing solution.

2. The method of claim 1, wherein the pH of the acidizing solution is between from about 1.9 to about 4.8.

3. The method of claim 2, wherein the pH of the acidizing solution is between from about 2.5 to about 4.5.

4. The method of claim 1, wherein the acidizing solution further comprises a phosphonate of the formula:

wherein R1, R2 and R3 are independently selected from hydrogen, alkyl, aryl, phosphonates, phosphates, acyl, amine, hydroxy and carboxyl groups and R4 and R5 are independently selected from hydrogen, sodium, potassium, ammonium or an organic radical.

5. The method of claim 2, wherein the acidizing solution further comprises a phosphonate of the formula:

6. The method of claim 4, wherein the acidizing solution further comprises citric acid or formic acid.

7. The method of claim 6, wherein the acidizing solution comprises about 1 to about 50 weight percent citric acid, up to about 20 weight percent HF and from about 0.5 to about 50 weight percent phosphonate compound.

8. The method of claim 1, further comprising introducing into the well, subsequent to the introduction of the acidizing solution, an overflush solution.

9. The method of claim 1, which further comprises introducing into the well a neutral chelant pickling agent.

10. In a method of well remediation in which a wellbore fluid is employed, the improvement comprising using a wellbore fluid comprising a buffered HF-sandstone acidizing solution.

11. The method of claim 10, wherein the pH of the sandstone acidizing solution is between from about 1.9 to about 4.8.

12. The method of claim 10, wherein the sandstone acidizing solution further comprises a phosphonate of the formula:

13. The method of claim 12, wherein the sandstone acidizing solution further comprises citric acid or formic acid.

14. A method of stimulating or remediating a sandstone formation consisting essentially of introducing into the formation a buffered HF-acidizing solution.

15. The method of claim 14, wherein the pH of the acidizing solution is between from about 1.9 to about 4.8.

16. The method of claim 14, wherein the acidizing solution further comprises a phosphonate of the formula:

17. The method of claim 14, wherein the acidizing solution further comprises citric acid or formic acid.

18. A process for dissolving acid-soluble siliceous material in a sandstone formation of an oil or gas or geothermal well consisting essentially of introducing into the well a buffered HF-acidizing solution.

19. The method of claim 18, wherein the pH of the acidizing solution is between from about 1.9 to about 4.8.

20. The method of claim 18, wherein the acidizing solution further comprises at least one member selected from the group consisting of:

(a.) a phosphonate of the formula:

wherein R1, R2 and R3 are independently selected from hydrogen, alkyl, aryl, phosphonates, phosphates, acyl, amine, hydroxy and carboxyl groups and R4 and R5 are independently selected from hydrogen, sodium, potassium, ammonium or an organic radical; and

(b.) citric acid, formic acid and mixtures thereof.