Matrix acidizing treatments are conventionally performed to increase permeability of oil and gas formations, dissolve mineral deposits and to remove various types of damage therein. Mineral acids, such as hydrochloric acid (HCl), hydrofluoric acid (HF) and mixtures thereof called Mud Acid, and organic acids, such as acetic acid, have been used. The major function of an acidizing formulation is to remove damage by dissolving scale and formation fines and to stimulate the formation.
Due to the highly corrosive nature of the acids used in the acidizing treatment, anti-corrosive additives are typically added to the fluid to protect metal surfaces of wellbore tubulars and other equipment from corrosive attack.
Further, other additives may be added to the acidizing formulation to improve injectivity and return of the stimulation fluids. Other additives may include wetting agents, foaming agents, silt-suspending agents, anti-sludging agents, iron-control additives such as reducing or chelating agents, non-emulsifiers or emulsifiers depending upon the formulation and small amounts of mutual solvents.
Additives may be more or less soluble or dispersible in the aqueous acid solutions used for acidizing and thus may precipitate out or phase separate into an oil phase in the formation. Further, the products of the acidizing treatment may precipitate out or form sludges in the formation creating additional formation damage. Little specific literature is found regarding the stability of the formulations once mixed together prior to injection into the formation. Applicant however is aware that it is a standard industry practice to mix the formulation ingredients together immediately prior to injection or within 24-48 hours prior to injection due to the industry recognized instability of conventional acidizing formulations. So unstable are the formulations considered to be that in some cases Applicant is aware that formulations prepared only hours in advance of an expected use and which have been shipped only a few miles by truck to wellsites are discarded if the intended use does not occur as scheduled. Most often separate ingredients are shipped to the wellsite and the ingredients mixed together only as required and at the time required.
A significant amount of literature is found directed toward the use of mutual solvents in formation stimulation. Solvents such as ethylene glycol monobutyl ether (EGMBE) or commercial preparations of mixtures of alcohols such as A-SOL™ and SUPER A-SOL™ (available from Baker-Petrolite, Calgary, Alberta, Canada) have been used to assist in the removal or stripping of oil or hydrocarbon which coats scale or other deposits to be dissolved which prevent the acid from acting thereon or to retard the functionality of the acid so that it can be displaced further into the formation before the acid becomes spent. Typically, mutual solvents are used as a pre-flush or an after-flush alone or in combination with brine, acid or the like. While the mutual solvent may be combined with the acid or other fluids, preparation is typically on site immediately prior to injection and concentrations are reported to be typically about 3-10% (Dayvault et al., “Solvent and Acid Stimulation Increase Production in Los Angeles Basin Waterflood”, SPE 18816 April 1989).
Aromatic solvents, typically used to strip hydrocarbons, are highly immiscible in aqueous solutions and therefore attempts to add aromatic solvents to aqueous acid solutions for this purpose would result in highly phase separated fluids, additives and the like partitioning between the phases and reducing the effectiveness of the acid treatment fluid.
Historically, mutual solvents, particularly EGMBE, have been used alone or in combination with a mud acid to increase permeability and leave the formation water-wet. It has also been reported that fines are thus prevented from moving back to the wellbore. Further, mutual solvents have been credited with deterring the formation of sludges and emulsions.
As reported by Dabbousi et al. in “Influence of Oilfield Chemicals on the Surface Tension of Stimulating Fluids”, SPE 50732, February 1999, mutual solvents such as EGMBE at concentrations of 10% by weight or lower act to reduce the surface tension of organic acids, however concentrations above 10 wt % appeared to have no effect. G. E. King reported in “Evaluation of Mutual Solvents used in Acidizing” May 2, 1983 in Amoco report F83-P-26 that mutual solvents such as A-SOL™ may be used at 5% by volume in 15% HCl and at 10% by volume in 28% HCl. EGMBE and A-SOL™ were tested at 10% and 35% respectively in 15% HCL and 80% SUPER A-SOL™ in 15% HCl were also tested. In some cases the increased amounts of mutual solvent resulted in longer emulsion break times.
Additives are typically added to acidizing formulations to prevent unwanted damage to the formation or to the equipment used for the acidizing process, such as tubulars. As previously stated, corrosion inhibitors are added to acidizing formulations to assist in mitigation of corrosion of carbon steel tubing and casing found in wellbores. Typically, the industry standard for corrosion of carbon steel in contact with mineral acids such as HCl is below 0.05 pounds per square foot. The inhibitors chosen to prevent corrosion must dissolve and remain compatible with the acid and other additives to provide the standard level of protection at various temperatures, typically from ambient temperature to elevated downhole temperatures, to at least 150° C. A diverse number of chemicals have been used historically to prevent corrosion. Acetylenic alcohols, such as propargyl alcohol are the most widely reported. Other corrosion inhibitors used and reported are organic amines, dimer/trimer acids derived from tall oil or other bases, quaternary amines derived from coconut, canola, tallow, tall oil or other bases, fatty alcohols, derivatized quinolines, alkyl pyridines and oxyalkylated resin amines.
The presence of iron, particularly in the ferric form rather than the ferrous form, may increase the likelihood of an asphaltene sludge forming when the acid comes into contact with native oil. Should iron sludge form, the permeability of the formation may be severely impaired. Typically, as the acid spends, the pH begins to rise. Ferric sludge begins to form at pH above about 1.9, while ferrous sludge does not begin until a pH well above 5. Historically, acidizing treatments typically result in pH no higher than about 3.5 in the fluid returns after treatment and thus, it is of greater interest to prevent the formation of ferric sludge. Many types of iron control additives are known, particularly reducing additives and chelating additives. Historically additives have included erythorbic acid, citric acid, nitrilioacetic acid (NTA), ethylenediamine tetraaceteic acid (EDTA), glycolic acid, thioglycolic acid, 2-mercaptoethanol, thioglycerol, hypophosphorous acid, inorganics such as copper, antimony, bismuth, iodide and the like in combination with organics such as quaternary ammonium compounds and reducing agents, such as 2-mercaptoethanol and stannous chloride.
Sludge generally refers to any solids which are generated when the acid comes into contact with virgin oil in the subterranean formation. The sludge is typically formed by precipitation of wax/paraffins or asphaltenes due to destabilization or emulsions that occur, often as a result of intimate contact between aqueous and non-aqueous fluids. Many chemistries have been employed in acidizing formulations to prevent sludge formation. A primary characteristic of anti-sludge agents is that they act as dispersants. One such dispersant noted in the literature is dodecyl benzene sulphonic acid (DDBSA), which is dispersible in mineral acids rather than being soluble. DDBSA readily separates from acidizing formulations upon standing unless blended immediately prior to use on site. Instability of formulations containing DDBSA is particularly problematic at elevated temperatures such as are found in many formations.
Optionally, demuslifiers are added to acidizing formulations to prevent formation of emulsions when the aqueous acid comes into contact with hydrocarbons in the formation. The formation of emulsions is typically very detrimental to acidizing treatments. Even more problematic, emulsions may be stabilized by solids such as paraffins, asphaltenes, corrosion by-products and undissolved minerals from the formation. Conventional demulsifiers may include amine oxyalkalates, alkyl polyols, resin oxyalkalates, glycol esters, poly glycol derivatives and diepoxides. An API industry standard (API RP 42) requires that acidizing formulations exhibit a maximum emulsion break time of 15 minutes in the acid returns.
The addition of additives to an acidizing formulation must be carefully designed so to as to prevent precipitation of the additives in the fluid which may be detrimental and cause damage to the formation. Further, phase separation may result in additives partitioning between an aqueous and an oily phase and therefore being incapable of acting efficiently, if at all, for the purposes for which they are added.
Clearly what is desired is an acidizing and stripping formulation which can be premixed as a single fluid to reduce costs and hazards resulting from on-site preparation and which is stable for relatively long periods of time to reduce waste and costs related to disposal of unused, unstable formulations. Ideally, fluids used are miscible and the additives either soluble or stably dispersed therein.