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  • SPE 126719

    Matrix Acid Systems for Formations With High Clay Content O.J. Jaramillo, SPE, R. Romero, SPE, Petrobras; A. Ortega, SPE, A. Milne, SPE, M. Lastre, SPE, Schlumberger Copyright 2010, Society of Petroleum Engineers This paper was prepared for presentation at the 2010 SPE International Symposium and Exhibition on Formation Damage Control held in Lafayette, Louisiana, USA, 1012 February 2010. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

    Abstract There are a number of sandstone reservoirs in which more than 50% of the matrix is composed of clay and feldspar minerals. Typically, these reservoirs are subject to fines migration and respond poorly to conventional matrix acid stimulation treatments. There are numerous challenges when treating these formations: the removal and/or stabilization of the mobile fines in the pore spaces without destabilizing the clays in the matrix or the matrix itself; the need to stimulate the formation some distance away from the wellbore, and, equally importantly, to minimize reaction products precipitating in the matrix; and the very low critical velocities that can lead to plugging while injecting the treatment. In many conventional acid treatments, after an initially good response to the treatment, the production falls to levels similar to or lower than before the treatment. A common compromise is to empirically adjust the strength of a HF/HCl acid system used to treat a particular formation, so as to delay the onset of renewed fines migration after the treatment for as long as possible, at the expense of optimizing productivity. In many cases this results in making the treatments uneconomic. To meet theses challenges a new fluoroboric acid system has been developed. The basic chemistry used is similar to that of a retarded HF acid previously described in the literature as clay acid (Thomas and Crowe 1978).. However, unlike the retarded HF acid, the new fluid uses organic acid as a chelant and is effectively a blend of organic/fluoroboric acid and hence an organic clay acid. The fluoroboric acid is generated by the addition of hydrofluoric and boric acid. By adjusting the initial concentration and ratio of hydrofluoric and boric acid, it is possible to optimize the stimulation effect of the treatment in a particular formation and prevent future fines migration. A key is the initial concentration of free hydrofluoric acid and the available hydrofluoric acid from hydrolysis of the fluoroboric acid with respect to the clay mineralogy and temperature. The concentration of the organic acid, the chelant, is also adjusted based on an analysis of the effluent during core flow testing, to minimize precipitation. Prior to customizing the organic clay acid system, treatments were performed in low temperature (< 140oF) reservoirs, with 30% kaolinite along with zeolite and chlorite present in the formation matrix. While there was a noted stimulation effect and fines stabilization, the initial post-treatment productivity fell short of that seen using an organic mud acid. In the case of organic mud acid, however, the production declined rapidly, indicating renewed fines migration. This led to a reformulation of the organic clay acid for use as the main treating fluid, eliminating the need for HF preflushes. The initial productivity of wells treated using the reformulated organic clay acid were higher than that obtained using an organic mud acid and remained stable, indicating effective fines migration control. In contrast to what might be expected it has been observed during the testing that it is not always the weakest treating fluids that are the least damaging, especially in formations with low critical velocities. There is an apparent balance between the tendency for a fluid to move fines in the matrix and to dissolve them, with very low dissolution rates increasing the probability of plugging the formation. Since 2003, more than 120 successful treatments have been performed using a customized organic clay acid as the main treating fluid to stimulate a variety of reservoirs previously considered untreatable or difficult to treat. The temperature of these reservoirs ranges from as low as 105oF to as high as 250oF, and the clay/feldspar content in the matrix often exceeded 40%. The treatments were greatly helped by the use of a geochemical simulator with which to optimize the acid formulations, with respect to both clay content and temperature.

  • 2 SPE 126719

    Background Matrix stimulation treatments of siliceous clay-containing formations to remove formation damage or improve productivity have been common practice in the oilfield for many years. The most commonly used treating fluids being mud acids composed of a blend of hydrofluoric acid (HF) and hydrochloric acid (HCl), acetic acid (C2H402), or formic acid (CH202). However, these conventional treatments have generally proven effective for a relative short period of time, in both consolidated and unconsolidated formations, with the subsequent production decline usually attributed to plugging by migratory clays and fines. A number of different explanations have been put forward to explain this phenomenon. Testing shows that the mud acid reacts rapidly with the formation in close proximity to the wellbore, often only a few inches around the wellbore, and so spends rapidly. Subsequently, formation fines migrate into the acidized near-wellbore area and replug the formation. Another possible contributing factor is that the mud acid actually weakens the structure of clays in the formation matrix and so generates additional fines. The rapid decline in productivity seen after many conventional mud acid treatments has led to the development of numerous fluid systems to improve post-treatment productivity. The objective of many of these fluids was to achieve deeper live-acid penetration into the formation by using a retarded acid, with a controlled release of HF into solution. An early example of this was the use of a solution of ammonium fluoride and methyl formate to enable the treating fluid to be injected into the formation before a significant amount of HF is generated (Templeton et al. 1975). Upon injection into the formation the methyl formate hydrolyzes to produce formic acid that converts the ammonium fluoride to hydrofluoric acid. Meanwhile, boric acid has been included in aqueous HCl-HF fluids in an effort to avoid the precipitation of insoluble fluoride salts and fluorosilicic acid. The need to minimize fluorosilicates or silica precipitates when using conventional mud acids is well documented. Hydrated silica, Si(OH)4 , is formed during the secondary and tertiary reactions of HF with feldspar and clay as shown in Eqs. 1 and 2, respectively (Gdanski 1994; Nasr-El-Din et al. 1998; Shuchart 1995; Crowe 1986). The secondary reaction is (X/5) HSiF5 + K-Al-Si + (3-x+1) H+ + H2O ===> AlFx(3-x)+ + K+ + Si(OH)4 (1) Silica gel, aluminum fluoride complexes (AlFx(3-x)+), and potassium (K) cations are formed during the secondary reaction (Eq. 1) by the reaction of pentafluorosilicic acid with feldspar/clay. In most sandstone acidizing treatments this goes to completion before the treatment is flowed back (Gdanski 1994; Crowe 1986; Thomas and Crowe 1981). The tertiary reaction shown in Eq. 2 occurs when aluminum fluoride complexes produced in the secondary reaction react with clays resulting in more hydrated silica. Potassium cations released during the secondary and tertiary reactions may precipitate as the fluosilicate (Gdanski 1994; Nasr-El-Din 1998; Thomas et al. 2002). Additionally, aluminum fluoride precipitation can occur. The tertiary reaction is AlF2+ + K-Al-Si + 4H+ + H2O ===> 2AlF 2+ + K+ + Si(OH)4 (2) Higher HCl to HF ratios, most commonly 9% HCl/1% HF, are primarily used as a means to minimize fluosilicate precipitation (Gdanksi 1994). As the secondary reactions consume a large amount of HCl, the concentration of HCl must be sufficient to ensure there remains an excess of unspent HCl in solution. For example, during the secondary reaction 6.4 wt% HCl is consumed when 1.5 wt% HF completely spends on illite (Gdanski 1994). The spending of the HCl may also possibly result in precipitation of aluminum silicate scales (Labrid 1970). Subsequent work has shown that the use of higher HCl to HF ratios will under certain conditions reduce the volume of hydrated silica gel deposited in a core (Thomas et al. 2002). The use of mud acid in formations with high clay content is also problematical. In the case of formations that are composed of or contain HCl-sensitive minerals such as zeolite and chlorite, the HCl spends quickly and generates a large quantity of Al3+ ions, extracting F- ions from the SiF62- , so causing Si(OH)4 to precipitate while an increase in pH can cause Al(OH)3 precipitation. Additionally, fluoride in the mud acid is believed to bind with aluminum in the formation and promote the deposition of hydrated silica, causing plugging in the formation. While a damaging precipitation of aluminum fluorides may occur with formic/HF and acetic/HF acids (Shuchart and Gdanski 1996).. To address this, a mixture of citric/HF acid has been proposed, the citric acid acting as a chelating agent for aluminum to prevent the deposition of or formation of hydrated silica gel (Rogers et al. 1998). However, the use of HF acid alone is limited to removing damage or scaling in the first few inches of the formation around the wellbore, as previously discussed. Formation integrity is another concern when using mud acid in formations with high clay content or in particular when the clays are the cementing material in the matrix. The use of HF acid is known to significantly reduce the compressive strength of the rock and in core flow testing can lead to the complete disintegration of the core (Thomas and Crowe 1981). This has

  • SPE 126719 3

    also been observed in the field when repeatedly acidizing formations with high clay content. This is in marked contrast to the use of fluoroboric acid (Thomas and Crowe 1981).

    While deeper live-acid penetration away from the wellbore and limiting possible reaction product precipitates will enhance the effectiveness of stimulation treatments, the issue of clay and fines stabilization must also be addressed. Retardation and fines stabilization can be achieved very effectively using fluoroboric acid (HBF4) (Thomas and Crowe 1978, 1981). The fluoroboric hydrolyzes to a limited extent in an aqueous solution:

    HBF4 + H20 => HBF3 OH + HF (3)

    When in the presence of clays or siliceous material the HF spends, moving the equilibrium to the right and the hydrolysis of HBF4 continues to form more HF. The equilibrium conditions dictate that there is only a limited amount of HF that can be present at any given time in solution. For example, at 212oF only 0.15% HF is present in solution. With only a limited amount of the total available HF in the system in solution at any given time, the acid is effectively retarded. This is reflected in that at 150F an 8 % HBF4 solution will dissolve in 2 hours the same quantity of kaolinite as a 12% HCl/3% HF acid in 20 minutes at 75F (Thomas and Crowe 1981). It also greatly reduces the potential risk of fluosilicates or silica precipitates. The advantages of fluoroboric acid over conventional HF acid systems to control fines migration and stabilize clays are well documented in the literature (McBride et al. 1979; Svendsen et al. 1990, 1992). One mechanism by which fluoroboric acid controls fines migration and stabilizes clays, reducing their cation exchange capacity (CEC) by up to 95%, is considered to be due to ion exchange. The reaction products from the hydrolysis of HBF4 react with the clays, extracting aluminum and replacing it with boron to form a borosilicate, which effectively renders the surface of the clays impermeable and, to some degree, welds the clays to surface of the pore spaces (Thomas and Crowe 1978, 1981).. Another mechanism that has been proposed in the past is that the spending of the HF acid results in the precipitation of silicic salts as fluorosilicic acid spends (Labrid 1970).. However, as the temperature decreases, the time increases for these reactions to go to completion, which requires that, a well is shut-in after the treatment. Hence, when treating a formation using fluoroboric acid as with any acid system, there is a need to avoid the potential for secondary and tertiary precipitates. A potential solution to obtaining deep live-acid penetration away from the wellbore and clay/fines stabilization while minimizing secondary and tertiary precipitates associated with the use of HCl in HCl-sensitive formations is the use of a mixture of organic acid(s) and HBF4 acid. The organic acid acts to chelate Al3+ ions, keeping the silica in solution and so preventing the precipitation of silica gel (Figs. 1 and 2). The acid also maintains a low pH and so prevents the possible precipitation of Al(OH)3.

    Fig. 1 Silica in solution Fig. 2 Continued dissolution with time

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    Organic Clay Acid9/1 Mud Acid3/1 Mud AcidClay Acid

    However, the amount of damage removed and/or matrix stimulation obtained using this acid is very dependent on the rate of hydrolysis of the HBF4. The rate of hydrolysis is primarily a function of temperature but is also influenced by the mineralogy and the surface area of the minerals in contact with the acid. Although an organic/HBF4 acid system in many respects meets the requirements for use in formations with high clay content or in formations for which there is very little information available with respect to the mineralogy, it is not without its limitations. Conventionally, the organic clay acid is formulated so that initially there is a negligible or low concentration of free (excess) HF in the solution, in addition to the HF from the hydrolysis of the HBF4. The limited hydrolysis of HBF4, particularly at low temperatures is the reason why, in many of the cases documented in the literature, a preflush of a more reactive fluid with HF is used ahead of the HBF4 acid to obtain the expected production increase after the treatment in addition to fines stabilization.

  • 4 SPE 126719

    While in formations with high clay content (> 20 %), in which fines migration commonly occurs, critical velocities of less than 1 ml/min are not uncommon, especially in cases of low matrix permeability. In these cases, core flow tests with a weak or highly retarded acid system may plug the core or generate fines, while a more reactive fluid may effectively stimulate the core. This may go some way to explain the unusual pressure responseflat or increasingseen when using weak acids to treat clay-rich formations with formation damage due to fines migration. These observations, together with the known issues with HCl/HF acid systems, led to a study of how an organic clay acid could be customized to be used as the principle treating fluid in reservoirs with low temperatures and high clay content, which, in some cases, exceeds 50% of the formation matrix. Low-Temperature Optimization Some early field trials using organic clay acid at low temperatures (< 140F) in formations with a high clay content (Table 1) showed that while the system was capable of controlling fines migration, the initial productivity increase after the treatment was less than when using a weak organic mud acid (9% formic acid/1.5% HF) or half-strength mud acid (6% HCl/1.5% HF); however, the production of the wells treated with the organic clay acid remained stable while those treated with an HF acid dropped substantially over a one to two month period (Fig. 3). In Fig. 3 the black line is an average for 15 wells treated with mud acid systems and the coloured bars are the average of 18 wells treated with organic clay acid.

    Production - Organic clay acid vs. Mud Acid

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    Table 1 RESERVOIR DATA Depth 2900 - 4200 ft. BHST 140 F Pressure 950 - 1400 psi. Permeability 100 - 300 mD Lithology Quartz 48%-56% Mica 3%-11% K-Feldespar 1%-3% Kaolinite 28%-36% Smectite 1.4%-2.3% Illite 1%-2.5% Chlorite 1.1%-3% Zeolites 1.2% - 2%

    Fig. 3 Production vs. time

    The production response of the wells treated with organic clay acid was attributed to the limited dissolution of the clays at low temperatures due to the slower hydrolysis of the fluoroboric acid. This was also evident from the treating pressures which, at a constant injection rate, decreased slowly when pumping the organic clay acid, while with organic mud acid there was a substantial pressure drop when the acid reached the formation. The substantially lower hydrolysis rate of HBF4 acid at temperatures below 150oF is well documented (Thomas and Crowe, 1981), taking over 10 times longer at 100oF than at 150oF to dissolve the same weight of montmorillonite clay. From this it was concluded that to effectively combine the benefits of stimulation and fines migration control in low temperature reservoirs it was necessary to increase the reactivity of the organic clay system without destabilizing clays, causing the formation of precipitates, or decreasing the ability of the fluid to control fines migration. The approach taken was to optimize the free HF and total HBF4 acid available in the system. To determine the best initial concentrations of HF and HBF4 acid a geochemical simulator was used. The acid systems used in the initial testing are shown in Table 2. Subsequently, a geochemical simulator was calibrated with core flow testing, and further fine tuning was done to optimize the acid concentration, including the organic acid(s) used. The new acid system is organic clay acid low temperature (LT).

    Table 2 ACID COMPOSITION Active Components wt%

    Fluid System HF

    Initial HF

    Total* HCl

    HBF4

    Formic Acid

    Organic Acid(s)

    NH4Cl

    RMA (12:3) 3 12 - - - RMA (6:2) 2 6 Spacer - - - - 3% OMA (9:3) 3 9 OMA (1.5) 1.5 9 Clay Acid 0.6 2.2 0.3 7.8 - - - OCA - Organic Clay Acid 0 0.5 1 1.5 1 - 2 2 - 5 11 - 13 5% OCA LT Organic Clay Acid LT 0.5 - 3 1 - 3 < 3 2 - 5 13 - 15 7%

    * The HF from the complete hydrolysis of HBF4

  • SPE 126719 5

    X-ray diffraction, acid solubility testing, and core flow testing (including effluent analysis) were used to evaluate the potential of the new organic clay acid formulation as well as compare it to existing acid systems. The X-ray diffraction analysis provided semi-quantitative mineralogical information. Analysis of bulk powders: One portion of each sample is ground to a fine powder. Ground samples are back-loaded in an aluminum sample holder and scanned from 2 to 75 degrees two theta with a Philips Pw-17p, X-ray diffractometer. The diffractometer scans for these samples were made at a speed of 2 degrees per minute. The diffractometer employs an automatic divergence (theta compensating) slit and a silicon diode array solid-state detector. The receiving slit width (detector aperture) is 0.3 mm, chosen to give maximum intensity. Fine fraction samples: An oriented fine-fraction mount is prepared for each sample. Samples are crushed in a mortar until the entire volume can pass trough a 200-mesh screen. This is suspended in distilled water in a beaker, placed in an ultrasonic disaggregator for 2 minutes, to obtain a < 2-m size separation. The fine-fraction sample is oven dried at 50C for 4 minutes. Samples are analyzed with the Philips X-ray diffractometer using the experimental parameters outlined in the previous paragraph. This form of analysis yields semiquantitative information concerning the composition and relative abundance of fine-grained rock constituents (particularly clay minerals). Fine-fraction samples are first analyzed in the air-dried state. Subsequently, each sample is solvated in an ethylene glycol bath for 24 hours and immediately analyzed. This form of analysis is useful in identifying mixed layer or other expandable clays. All the selected samples are heat treated, to aid in the distinction of kaolinite and chlorite clay. A muffle furnace is used for heat treatment. Solubility Testing The starting point to evaluate the new acid formulation was to perform a series of solubility tests using a series of different acid systems designed to treat clay-rich formations. The results have been grouped based on the substrate usedkaolin, cores taken from two difficult-to treat-formations (reservoirs AY1 and BC2), and a reference sample with a known composition. Kaolinite substrate (Table 3) At both 120F and 150F the solubility in acetic acid was low, although with 15% HCl the solubility was +/- 8%, which is possibly a result of impurities present in the sample. The solubility in organic clay acid LT at both 120F and 150F was higher than for the conventional organic clay acid and clay acid systems, reflecting the increased concentration of free HF in the system. The solubility values obtained using organic clay acid LT are comparable with the results obtained using 15% HCl with RMA (6:2). Although the solubility in organic clay acid was very low at 120F, it increased sevenfold at 150F, which is line for the increased reactivity of HBF4 with temperature previously reported in the literature. X-ray diffraction detected no precipitates when reacting the kaolinite with a combination of organic clay acid LT and OMA (9:3) and/or RMA (12:3). Table 4 AYI SOLUBILITY

    Mineralogical Composition AY1 (XRD): Quartz: 90% Kaolinite: 4% Microcline: 1% Albite: 2% Chlorite: 1% Muscovite : 2% Solubility (%)

    Fluid System(s) 120F 150F Acetic Acid 10% 0.7 1.0 Hydrochloric Acid (HCl) 15% 2.5 2.8 HCl 15% + RMA (12-3) 8.5 8.6 HCl 15% + RMA (6-2) 5.5 7.2 RMA (6:2) 7.2 7.7 OMA (9:3) 8.6 9.0 Organic Clay Acid 0.9 2.7 Clay Acid 1.6 4.6 Organic Clay Acid LT 6.1 7.0 HCl 15% + Clay Acid 2.4 6.4 Acetic 10% + Organic Clay Acid 2.5 3.7 Acetic 10% + Organic Clay Acid LT 6.7 7.4 RMA (6:2) + Spacer + Organic Retarded Acid 6.2 8.5 RMA (6:2) + Spacer + Organic Clay Acid 7.5 8.8 RMA (6:2) + Spacer+ Organic Clay Acid LT 8.3 8.4 OMA (9:3) + Organic Clay Acid 6.8 7.7 OMA (9:3) + Organic Clay Acid LT 7.8 8.2

    Table 3 KAOLINITE SOLUBILITY Composition (XRD): 83% Kaolin + 17% Mica Solubility (%)

    Fluid System(s) 120F 150F Acetic Acid 10% 0.5 2.6 Hydrochloric Acid (HCl) 15% 7.7 8.5 HCl 15% + RMA (12-3) 52 60 HCl 15% + RMA (6-2) 38 44 HCl 15% + OMA (1.5 HF) 38 43.7 RMA (6:2) 47.3 50 OMA (9:3) 58 60 Organic Clay Acid 2.9 23 Clay Acid 35 36 Organic Clay Acid LT 37 45 HCl 15% + Clay Acid 35 37 Acetic 10% + Organic Clay Acid 14.4 27 Acetic 10% + Organic Clay Acid LT 50 51 RMA (6:2) + Spacer + Clay Acid 58 63 RMA (6:2) + Spacer + Organic Clay Acid 56 66 RMA (6:2)+Spacer+Organic Clay Acid LT 62 64 OMA (9:3) + Organic Clay Acid 56 58 OMA (9:3) + Organic Clay Acid LT 65 65

  • 6 SPE 126719

    Reservoir AY1 (Table 4) This formation typically has very low carbonate content with a number of HF-soluble clays present. In this particular sample, no carbonate was detected using X-ray diffraction. For this reason the highest solubility values were obtained using RMA (12-3) and OMA (9:3), while the solubility in organic clay acid LT was higher than the other retarded acid systems at both 120oF and 150F, indicating that the new low-temperature formulation is capable of dissolving clays at low temperatures. No significant difference was noted in the solubility using retarded organic acids with and without acetic acid, which can be attributed to the fact that no carbonate material is present.

    Table 5 BC2 SOLUBILITY Mineralogical Composition (XRD) BC2: Quartz: 77% Muscovite: 5% Kaolinite: 14% Illite: 2% Others: 2% Solubility (%)

    Fluid System(s) 120F 150F Acetic Acid 10% 1 3 Hydrochloric Acid (HCl) 15% 0.9 3.8 RMA (12: 3) 15.8 19 RMA (6:2) 11.8 16 OMA (9:3) 16 18.6 HCl 15% + RMA (12:3) 15 20 HCl 15% + RMA (6:2) 11 17.9 Organic Clay Acid 4.6 8.9 Clay Acid 7 12.3 Organic Clay Acid LT 12.4 15 HCl 15% + Clay Acid 11.5 11.7 Acetic 10% + Organic Clay Acid 5.6 9.5 Acetic 10% + Organic Clay Acid LT 13.4 14 Acetic Acid 10% + Organic Clay Acid 5.6 9.5 Acetic Acid 10% + Organic Clay Acid LT 13.4 14

    Table 6 REFERENCE SOLUBILITY Mineralogical Composition (XRD) Reference: Quartz: 74% Microcline: 5% Kaolinite: 10% Chlorite: 5% Calcite: 6% Solubility (%)

    Fluid System(s) 120F 150F Acetic Acid 10% 11.8 12 Hydrochloric Acid (HCl) 15% 9.2 12 HCl 15% + RMA (12-3) 29.7 30 HCl 15% + RMA (6-2) 25.7 27 HCl 15% + OMA (9 - 3) 25 30 HCl 15% + Clay Acid 17 21 HCl 15% + Organic Clay Acid 17 19.2 HCl 15% + Organic Clay Acid LT 22 25 Acetic Acid 10% + Organic Clay Acid 16.8 18 Acetic Acid 10% + Organic Clay Acid LT 25 25

    Reservoir BC2 (Table 5) This formation is characterized by high clay content, mainly kaolinite. The solubility in 10% and 15% HCl was low, 1% and 3%, respectively, reflecting the low carbonate content. The solubility obtained using organic clay acid LT (12.4% and 15%) was higher than obtained when using clay acid (HBF4), 7% and 12.3%, respectively, or organic clay acid, 4.6% and 8.9% at 120oF and 150oF respectively. This test is evidence of the reactivity of the organic clay acid LT with clay minerals not only at 150F, but also at 120F. The solubility with organic clay acid LT at 120F is only 16% less than the maximum reported value, which was obtained using RMA (12-3). There is, however, a marked difference in the solubility when using organic clay acids with and without acetic acid. Reference Sample (Table 6) This sample was prepared using pure mineral species. The objective of these tests was to evaluate the dissolution capacity of acetic acid at low temperatures in the presence of calcium carbonate and the possibility of precipitates forming with organic clay acid LT if the reactivity of the acetic acid were not sufficient to remove all the CaCO3 present. The dissolution of 10% acetic acid at 120F was sufficient to dissolve not only the CaCO3 present but also the ferric chlorite. Meanwhile, the combination of 10% acetic acid with organic clay acid LT dissolved the majority of the calcite, clays, and feldspars at 120F (25% solubility). This is equivalent to the values obtained with 15% HCl + OMA (9:3) or 15% HCl + RMA (6:2). Core Flow Testing Comparative core flow testing was then performed to compare the stimulation effect of the organic clay acid LT and RMA (12:3) treating fluids and to measure the ions present in the effluent so as to calibrate a geochemical simulator. Two cores were taken from the same depth in the BC2 reservoir (Table 7). In the case of the organic clay acid LT a four shut-in period was included in the pump schedule to allow for the hydrolysis and the reaction of the HBF4 acid to go to completion. The tests were run at a bottomhole temperature of 125F with 1000 psi overburden pressure and 500 psi back pressure. A flow rate (2.0 cc/min.) was selected to ensure that the injection of the fluids had a minimal effect on the movement of fines contained within the pore structure.

  • SPE 126719 7

    Table 7 CORE MINERALOGY Core

    Mineral B08 OCA LT B30 RMA Quartz 92% 89% Microcline 1% 1% Others - - Clays Kaolinite 6% 8% Illite - - Chlorite 1% 2% Acid Solubility (%) HCl 15% 0.1% 0.1% HCl + RMA (12: 3) 8% 10% Porosity and Perm Porosity (%) 26.8 26.7 Permeability (mD) with N2 1977 1810

    In an attempt to make a direct comparison of the stimulation effect obtained using the two acid systems, the permeability changes during the simulated treatment were plotted for both systems (Fig. 4). The results show that, although there is a higher initial increase in the permeability after treating with RMA (12:3), the final stabilized permeability is almost identical for both acid systems. The flow test with RMA (12:3) also shows some indications of fines destabilization/movement, reflected in the high initial permeability which rapidly decreases when flowing crude in the producing direction after completion of the treatment. This is not the case with organic clay acid LT, an indication of fines stabilization. An analysis of the effluent taken during the core flow tests showed in both cases a high concentration of aluminum (Al3+), silica (Si4+), magnesium (Mg2+) and iron (Fe2+). A higher concentration of aluminum (Al3+) was present in the organic clay acid LT effluent; and a markedly higher concentration of iron (Fe 2+) in the RMA (12:3) effluent.

    Fig. 4Core flow tests RMA vs. organic clay acid LT. Applying lessons learnt The initial testing showed that by increasing the free HF in an organic clay acid it is possible to adjust the reactivity of the fluid making it effective at lower temperatures. The next step was to run a series of core flow tests using cores from low-temperature reservoirs with a high concentration of HCl-sensitive minerals and/or high clay content. During this testing it was possible to further refine the free HF content as a function of the temperature, mineralogy, and, to some degree, the porosity of the formation. An important element in this testing was the use of inductively coupled plasma (ICP) to measure

    Core Flow Testing- Comparison RMA vs OCA HP - Well: BN-713 - Sample No. 430 (RMA) and No.408 (OCAHP)

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  • 8 SPE 126719

    the ions present in the effluent from the core flow testing. Besides using the information to optimize the concentration of free HF and organic acid(s), it also was used to calibrate a geochemical simulator. The simulator makes it possible to evaluate the ability of different acid systems to stimulate a formation without the need to run additional core flow tests. Examples are shown of simulations run for two different formations at 135 F (Fig.5) and 180 F (Fig. 6).

    RMA 12:1.5OCAOCA/Acetic

    RMA 12:1.5OCAOCA/Acetic

    OMA 9:1RMA 12:1.5OCA OCA/Acetic

    OMA 9:1RMA 12:1.5OCA OCA/Acetic

    Fig. 5 Geochemical simulation at 135oF Fig. 6 Geochemical simulation at 180oF Case study The field produces oil and gas from fluvial shaly sandstones of Early Miocene age, and a typical well has a number of distinct sands, which may contain light oil, medium oil, or mobile water. The depositional environment of the main reservoir is continental, with meandering shallow channels. The low-temperature (140F) reservoirs are shaly sandstones composed mainly of quartz, feldspars, clays, and lithic fragments. Porosity varies from 14% to 22%, but can decrease significantly through cementation.

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    The field was first put on production in 1989 and in 1999 water injection at the perimeter of the field was started followed in 2004 with in-field water injection. Although, originally considered as being an unfractured reservoir, the onset of water injection has shown there to be complex system of fissures / high conductivity channels in the field. This is the reason for the wide variation in injection rates/ pressures when treating these wells and the increased water production after the treatments. Some of the wells are in direct communication with one or more injection well. Therefore, in an attempt to compare the effectiveness of different matrix treatments, these wet producers are excluded (Fig. 7). Fig. 7 Average BS&W of wells included and excluded from study Mineralogy A thin-section study showed angular quartz grains of average size with an abundance of volcanic fragments and very little calcareous cement. There is little diagenesis because of the low overburden pressure, and the formation is friable. In the absence of calcareous cement, the quartz grains are free. The low compaction also gives rise to a highly porous matrix (> 20%) shown in blue in Fig. 8. In many cases the primary and secondary porosity (moldic) are covered with chlorite, limiting the deposition of other cementitious material (Fig. 9). Despite the high porosity, the permeability in general is low (1 to 20 mD) in part due to the calcium present in the volcanic fragments (Fig. 10) of epidote, plagioclase, smectite, and actinolite being leached out by the relatively fresh formation water and depositing a calcareous cement plugging the pore throats

  • SPE 126719 9

    Fig. 8Porosity Fig. 9Chlorite deposition Fig. 10Volcanic fragments (V) The total clay and feldspar content as measured by X-ray diffraction varies between 20% and 40%, while the volume of smectite clay is often sufficient for resistivity logs to respond more to the volume of clay than to the difference between oil and water. A scanning electron microscope (SEM) image shows the smectite clays lining the pore spaces and partially blocking the pore throats (Fig. 11).

    Fig. 11SEM image (IS, ilite/smectite; CL, Chlorite) The mineralogy of cores taken from a number of different sands in two wells in the field is shown in Table 8. The high concentration of smectite means great care must be taken not to destabilize the clay by changes in salinity. The significant percentage of zeolite and chlorite means that the formation is HCl sensitive. When carbonate is present, it is considered to be the cementing material and so when acidizing there is a risk of further deconsolidating an already friable formation, resulting in the possibility of collapsing the formation, as is thought to have happened in more than one case in the past.

    Table 8 MINERALOGY

    HF stimulation treatments The first matrix treatments performed with the objective of removing formation damage due to scaling, organic deposits and fines while preventing future fines migration in the matrix (Table 9). The scaling and fines migration attributed to the onset of in-field water injection and the organic deposits to declining reservoir pressure. The parameters used for the treatments being:

    Temperature 120 to 140oF Permeability 5 to 400 mD

  • 10 SPE 126719

    Porosity 17 to 20% Water saturation 40% Reservoir pressure 800 to 1500 psi Radial treatment penetration 3 ft. Maximum surface pressure 2000 psi Maximum pump rate 2 BPM

    With the treatments performed in two stages using straddle packers, due to the number of producing sands and the need to ensure complete coverage. With the objective of optimizing the treatments, a number of HF acid systems from different service companies were used (Table 9). The acid systems being selected based on either core flow testing or through the use of design software.

    Table 9 TREATMENT DESIGN Well #

    Stage 1 2 3 4 5 6

    Preflush#1 Xylene Organic solvent Organic Solvent Organic solvent Organic Solvent Organic solvent

    Preflush#2 Clay Stabilizer NH4Cl - NH4Cl NH4Cl NH4Cl

    Acid Preflush 10% Acetic acid Acetic acid + HCl - Acetic acid + HCl 10% Acetic acid Acetic acid + HCl

    Main Acid 10% Acetic acid + 1.5% HF HCl:HF 10% Acetic acid + 1.5% HF HCl:HF HCl:HF HCl:HF

    Acid Overflush - Retarded HF 10% Acetic acid Retarded HF Retarded HF Retarded HF

    Overflush NH4Cl Acetic acid + HCl -

    Acetic acid + HCl 10% Acetic acid Acetic acid + HCl

    There was an average 2.9 fold increase in the initial production after these treatments, indicating that in most cases the damage was removed (Fig. 12). However, the results varied greatly from well to well. However, the production results of Wells #1 and #3 would indicate that the use of a 10% Acetic acid preflush is beneficial; primarily to remove calcium carbonate and so prevent the HF acid from prematurely spending on the carbonate and possibly precipitating calcium fluoride. The treating pressure in the case of Well #3 actually showed a marginal increase , unlike Well #1 where the pressure decreased.

    0.01.02.03.04.05.06.07.08.09.0

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    HF Acid SystemsPost Treatment Normalized Production Increase - BOPD

    Fig. 12 Normalized post-treatment production increase

    The improved production in wells #4 and #6 is attributed to the use of an Acetic acid / HCl preflush along with an HCl/HF acid. There being a signifantly greater pressure drop 800 psi vs. 200 psi-during the treatment in Well #4 than in the case of Well #1. While the extremely good response of Well #6 may be attributed in part to higher matrix permeability and/or fissures reflected in a higher than normal pump rate during the treatment, 4 bbl/min. vs. 2 bbl/min..

  • SPE 126719 11

    Despite an initial increase in production, the production of all the wells declined rapidly (Fig. 13). In all but well #6 the production dropped to less than pretreatment levels in less than three months. This would indicate continued fines migration. The production of solids monitored in Well #4 increased rapidly within 30 days of the treatment with an associated loss of production (Fig. 14).

    Fig. 13 Normalized production vs. time

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    HF Acid Systems

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    The conclusion drawn from these treatments was that the use of HF acid systems removes the formation damage and initially stimulates production, while the use of an Acetic acid preflush is beneficial. However, the post treatment production declines rapidly indicating renewed fines migration. Organic clay acid treatments The evaluation of the HF acid treatments concluded that fines migration control is essential if the treatments are to be economically viable. While, there was also a need to simplify the treatments in terms of the fluid trains used. Not only to reduce the cost but also the logistics and the very real risk that all the stages of the treatment are not injected uniformly into what is a heterogeneous formation. These considerations led to an evaluation of the organic clay acid treating fluid for this application. It was recognized that there would very likely be a need to optimize the fluid with respect to the specific mineralogy and treating temperature (

  • 12 SPE 126719

    working on the organic clay acid LT formulation. However, as only a very limited number of cores were available the optimization had to rely on geochemical simulations. For this reason, the decision was made to perform a series of jobs with which to fine-tune the fluid in the field and validate the geochemical simulator. For the first well - Well A, the decision was made to use what would be considered the best acid formulation, following conventional guidelines with respect to the mineralogy. An Acetic acid preflush followed by an organic clay acid, having virtually no free HF and a high concentration of organic acid (Table 9).

    Table 9 TREATMENT DESIGN FOR OCA TREATMENTS Well #

    Stage A - 1st stage A - 2nd stage B C D E

    Preflush#1 Organic Solvent Organic solvent Organic Solvent Organic solvent Organic solvent Organic solvent

    Preflush#2 - - - - -

    Acid Preflush 10% Acetic acid 10% Acetic acid 10% Acetic acid Organic mud acid Organic mud acid 10% Acetic acid

    Main Acid Organic clay acid (0.3% HF) Organic clay acid

    (1.1% HF) Organic clay acid

    (2.1% HF) Organic clay acid

    (2.1% HF) Organic clay acid

    (2.1% HF) Organic clay acid

    (HF varying) Acid

    Overflush - - - - - -

    Overflush - - - - - -

    The treatment was planned to be performed in two stages using straddle packers to selectively isolate the upper and lower sands. When pumping the first stage no decrease in the surface pressure was seen when injecting the organic clay acid. This would indicate very limited clay dissolution by the fluoboric acid. For this reason the second stage was performed using an organic clay acid with a higher concentration of HF acid. However, this did not result in a substantial pressure drop during the injection of the acid. Although, the production after the treatment would indicate (1.5 fold increase) the majority of the damage had been removed (Fig. 15).

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    Fig. 15 Post treatment normalized production increase Based on the experience in Well A an optimized organic clay acid formulation, from the previous study, was proposed for Well B. Effectively increasing the HF acid concentration and adjusting the organic acid concentration accordingly (Table 9) using a geochemical simulator. The acid volumes were also increased to have 4ft. of radial penetration away from the wellbore, instead of the 3ft. used for the previous treatments. During the treatment the surface pressure dropped by more than 1000 psi at the end of the acid stage, indicating dissolution of clays and fines. The post treatment production (2.4 fold increase) would also indicate that the formation had been effectively stimulated (Fig. 15). This confirmed the validity of the previous laboratory study as well the calibration of the geochemical model, for this particular formation.

  • SPE 126719 13

    The positive result of the treatment in Well B gave rise the idea of using a similar acid system to stimulate wells which were not considered to be severely damaged. The treating schedule modified to include a stage of organic mud acid ahead of the organic clay acid (Table 9). This was used to selectively treat Well C with treating volumes similar those of Well B. Although, the treating pressure only decreased +/- 200 psi during the treatment, the increase in the production was impressive, reaching a level not previously seen in this field (Fig. 15). A similar treatment performed on Well D, gave very similar results. With the performance of the optimized organic clay acid system meeting expectation and the knowledge gained from the previous treatments the focus was on improving the economics of the treatments. This entailed a renewed effort to correctly determine the damage mechanism in candidate wells and so tailor the treatments in terms of fluid selection and volumes reduced volumes and fewer stages. However as fines migration was recognized as a common problem throughout the field the stages used for subsequent wells were similar to those used for Well E. The only changes being the free HF concentration in the organic clay acid as a function of the suspected damage mechanism. Although, the initial production after the treatments is similar to those using conventional HF acid systems a striking difference is seen in the production with respect to time, which remains stable in the case of organic clay acid (Fig. 16). The production history of the high productivity wells is shown separately (Fig. 17). This is very different from the tendency when using HF based fluids (Fig. 13) where in most cases after 3 months the production has fallen to below pre-treatment levels.

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    Organic Clay Acid Normalized Production with Time - BOPD

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  • 14 SPE 126719

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    Fig 17 - Normalized production vs. time for high productivity wells

    The unexpected production decline in Well D (Fig. 17) is due to depletion and water breakthrough as the water cut increased from less than 50% to more than 80% in the 6 month period following the treatment. Conclusions An organic clay acid provides effective fines and clay stabilization at all temperatures. Fines migration control often being more important than the initial post-treatment production increase if the net present value of a treatment is to be maximized. An organic clay acid is a simple, versatile acid system that can be used as the main treating fluid in low-temperature reservoirs, in many cases using an acetic acid preflush. The increase in post-treatment productivity is equivalent to using a half -strength mud acid, without the characteristic rapid decline in production due to renewed fines migration. The concentration of free HF in an acid system must be optimized with respect to the mineralogy and surface area of the clays in a specific reservoir. A general observation is that too low a concentration may lead to physical plugging of the pore throats by migrating fines and lead to a treatment being aborted. Too high a concentration will lead to deconsolidation of the clays in the matrix and precipitation. The use of organic acid(s) or chelant to chelate AlF3+ is essential. There must always be an excess of organic acid or chelant in the system, to ensure this requires the use of inductively coupled plasma (ICP) to measure ion concentration in the effluent when running core flow tests. In formations with high clay content there is no substitute for a good knowledge of the mineralogy and mineral species when trying to optimize matrix stimulation treatments. A successful treatment is engineered and the fluids selection made based on this knowledge. Experience shows that it is very important to calibrate the treatments when starting to perform matrix treatments in a given field, closely monitoring the production of treated wells. This may also mean a willingness to experiment by making design changes. Acknowledgements The authors would like to thank Petrobras Colombia and Schlumberger for permission to publish this paper. References Crowe, C.W. 1986. Precipitation of Hydrated Silica from Spent Hydrofluoric Acid How Much of a Problem is it? JPT 1234 - 1244. Gdanski, R.D. 1994. Fluosilicate Solubilities Affect HF Acid Compositions. Paper SPE 27404 presented at the International Symposium on Formation Damage Control held in Lafayette, LA, February 7-10.

    Labrid, L. 1970. Thermodynamic and Linetic Aspects of Argillaceous Sandstone Acidizing. J. Pet. Tech, (June) 693 700. McBride,J.R., Rathbore,M.J., and Thomas, R.L. 1979. Evaluation of Fluoroboric Acid Treatment in the Grand Isle Offshore Area Using Multiple Rate Flow Test, Paper SPE 8399 presented at the SPE Annual Technical Conference and Exhibition, Las Vegas, 23-26 Sept.

  • SPE 126719 15

    Nasr-El-Din, H.A., Hopkins, J.A., Shuchart, C.E., and Wilkinson, T. 1998. Aluminum Scaling and Formation Damage due to Regular Mud Acid Treatment. Paper SPE 39483 presented at the International Symposium on Formation Damage Control held in Lafayette, LA, February 18-19. Rogers, B.A., Burk, M.K., Stonecipher, S.A. 1998. Designing a Remedial Acid Treatment for Gulf of Mexico Deepwater Turbidite Sands Containing Zeolite Cement. Paper SPE 39595 presented at the Formation Damage Control Conference, Lafayette, Louisiana, 18-19 February Shuchart, C.E. 1995. Determination of the Chemistry of HF Acidizing with the Use of 19F NMR Spectroscopy. Paper SPE 28975 presented at the SPE International Symposium on Oilfield Chemistry, San Antonio, TX, February 14-17.

    Shuchart, C.E., Gdanski, R.D. 1996. Improved Success in Acid Stimulations with a New Organic-HF System. Paper SPE 36907 presented at European Petroleum Conference, Milan, Italy, 22-24 October

    Svendsen, O.B., Kleven, R., Aksnes, N., Hartley, I.P.R. 1992. Stimulation of High-Rate Gravel-Packed Oil Wells Damaged by Clay and Fines Migration: A Case Study, Gullfaks Field, North Sea. SPE paper 24991 presented at the European Petroleum Conference held in Cannas. France, 16-18 Nov.

    Svendsen, O.B., Kleven, R., Aksnes, N., Hartley, I.P.R. 1990. Advances in Matrix Stimulation Technology. Paper SPE 20623 presented at the SPE Annual Technical Conference and Exhibition held in New Orleans, USA, 23-26 Sept. Templeton, C.C., Richardson, E.A., Karnes, G.T., and Lybarger, J.D. Self Generating Mud Acid. J. Pet. Tech (Oct. 1975) 1199 1203. Thomas, R. L., and Crowe, C.W. 1978. Single-stage Chemical Treatment Provides Stimulation and Clay Control in Sandstone Formations. Presented at the SPE California Regional Meeting, San Francisco, California, 12-14 April. SPE 7124 Thomas, R.L., Crowe, C.W. 1981. Matrix Treatment Employs New Acid System for Stimulation and Control of Fines Migration in Sandstone Formations. J. Pet. Tech (Aug.) 1491-1500. Thomas, R.L., Nasr-El-Din, H.A., Mehta, S., Hilab, V., and Lynn, J.D. 2002. The Impact of HCl to HF Ratio on Hydrated Silica Formation During the Acidizing of a High Temperature Sandstone Gas Reservoir in Saudi Arabia. Paper SPE 77370 presented at the SPE Annual Technical Conference and Exhibition held in San Antonio, Texas, 29 Sept. - 2 Oct. SI Metric Conversion Factors bbl 1.589 873 E-01 = m3 ft 3.048* E-01 = m F (F-32)/1.8 = C in. 2.54* E+0 = cm Cp x 1.0*E-03 = Pa.s gal x 3.785 412E-03 = m3

    md x 9.869 233E-04 = m2 psi 6.894 757 E+00 = kPa *Conversion factor is exact.

    Table 4 AYI SOLUBILITYMineralogical Composition AY1 (XRD): Fluid System(s)Organic Clay Acid

    Fluid System(s)Organic Clay Acid

    Table 5 BC2 SOLUBILITYMineralogical Composition (XRD) BC2: Fluid System(s)Organic Clay Acid

    Table 6 REFERENCE SOLUBILITYMineralogical Composition (XRD) Reference: Fluid System(s)ClaysPorosity and Perm