SPE 144007

Acidizing Induced-Damage in Sandstone Injector Wells: Lab Testing and a Case History A.M. Al-Mohammad, SPE; M.H. Al-Khaldi, SPE; S.H. Al-Mutairi, SPE; and A.A. Al-Zahrani, SPE, Saudi Aramco

Copyright 2011, Society of Petroleum Engineers This paper was prepared for presentation at the SPE European Formation Damage Conference held in Noordwijk, The Netherlands, 7–10 June 2011. 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 Throughout well lifetime, formation damage can occur during the activities of drilling, completion, injection, or well stimulation treatments. Typically, remedial treatments to restore the well performance involve injection of reactive fluids capable of removing such damage. Therefore, understanding damage mechanism and type is critical for fluid selection and effective treatment design. Without this knowledge, the conducted stimulation treatment could cause a more severe form of formation damage.

This report discusses the improper use of mud acid at (9 wt% HCl/1 wt% HF) in restoring the injectivity of N-510. The subject well was stimulated with two acid stimulation treatments as an attempt to improve the poor results of a previous clean-out job, conducted to remove mud filter cake. These treatments were designed to remove the damage that has been limiting the well injectivity. However, it was found that these acidizing treatments created a new formation damage which resulted in severe decline in the well injectivity.

Integration of chemical analysis techniques of return fluids and core-flood experiments was used to assess the effectiveness of all conducted treatments. This report demonstrates the techniques used to identify the source and type of formation damage mechanism that occurred during each treatment. Based on these studies, it was found that the poor results of clean-out job were due to precipitation of calcium sulfate. This precipitation was a result of the mixing between spent cleanout acid, having a high amount of calcium, and the high-content sulfate water. Most of this precipitation occurred in the well-bore vicinity during the last stages of the well flow-back.

Calcium sulfate precipitation had a negative impact on the performance of the conducted acid stimulation treatments. In the presence of this precipitation, the two successive mud acid stimulation treatments created another form of damage, i.e. in-situ fluoride-based scale. Initially, the fresh injected mud acid dissolved most of the calcium sulfate scale and as a result it contained high amount of dissolved calcium ions. However, upon the spending of injected mud acid in the formation, calcium fluoride precipitated as a result of the increase of solution pH value.

The interactions between different acid systems and the constituent of down-hole environment, resulting in the precipitation of calcium sulfate and calcium fluoride, are discussed. In addition, this report provides recommended modifications to future stimulation treatments, conducted under similar conditions so as to prevent the formation of these scales. Introduction Field “N” is a sandstone reservoir, which consists of two bodies: Unayzah-A (top layer) and Unayzah-B (bottom layer), separated by a siltstone section. Unayzah-A is a wet eolian depositional system having average porosity and permeability values of 19% and 65 mD, respectively, while Unayzah-B is a fluvial depositional system with an average porosity and permeability values of 16% and 600 mD, respectively. The reservoir has a static bottom-hole temperature of 186ºF. Static bottom-hole pressure is approximately 3,800 psi at 6750 ft. This reservoir pressure is maintained by injecting Jilah water, obtained from a shallow aquifer. Table 1 gives the chemical analysis of the injected water.

The “N” field water injection system consists of eighteen wells. Most of these injectors were drilled as horizontal wells, and completed as an open hole. Few of these injection wells were drilled recently into Unayzah-A formation, using water-based mud, Table 2. The average open hole length is 3,000 ft, completed with 4 ½” sand screen. Following drilling operations, wash acid treatments, using HCl or HCl/formic mixture, were conducted to remove drilling mud damage. Typically, wash acid of 7.5 wt% or

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5 wt% HCl + 5 wt% formic was used to remove filter-cake built on the face of drilled formation and near wellbore plugging caused by mud filtrate or particulates invasion.

Pressure response of several wells, following clean-out treatments, indicated that the acid system was effective in removing the filter cake around the wellbore. Injectivity tests performed in few wells showed that typical injection rate is nearly 15 MBD at 900 psi, which meets the expected rate. However, the results of clean-out treatment, conducted in N-510, were below expectation, Figure 1. Therefore, this treatment was followed with two acid stimulation treatments to restore the well injectivity. However, these treatments not only were unsuccessful, but they even resulted in additional decrease in the well injectivity.

It is clear that application of clean-out treatment in N-510 was not completely successful in restoring the well injectivity since the two mud acid stimulation treatments created severe formation damage. However, the interaction between different acid systems, wash/mud acids, and the constituents of down-hole environment were not fully known. Therefore, the objectives of this study are: 1) integrate flow-back returns analysis with lab testing to assess different treatments conducted in N-510, 2) use this integration to identify the damage type and mechanism that restricted the well injectivity, and 3) to recommend modifications to current clean-out treatments so as to minimize potential formation damage due to these jobs. Well description and history N-510 is one of several power water injectors (PWI) drilled to provide pressure support for Unayzah-A reservoir in “N” field. It was drilled with WBM DIF (KCl/CaCO3/XC-Polymer mud) and completed as an open-hole horizontal well in Unayzah-A formation, with a total depth of nearly 13,332 ft. The well completion includes 9-5/8” casing and a 7” liner at 5,110 ft and 11,490 ft, respectively. The formation is poorly consolidated; therefore, 4-1/2” wire wrapped screens were used in the lateral open-hole for sand control.

X-Ray Powder Diffraction (XRD) analysis of different field core plugs showed that the major minerals in this sandstone formation are quartz, clay minerals (illite, chlorite & kaolinite), feldspar (potassium feldspar), and trace amounts of calcite are also present. The well has static bottom hole temperature of 186°F and static bottom hole pressure of 3,860 at 9,058 ft. Latest analysis of the injected water showed that it contained high concentration of sulfate ion (approximately 4,000 ppm). This high sulfate concentration had a great impact on the nature of the damage noticed in N-510, as will be explained later.

After drilling and completion operations, an acid wash/clean-out treatment to remove the drilling fluids filter cake was applied in N-510. This treatment included injection of 5 wt% HCl and 5 wt% formic acid (15 gal/ft). The post-clean-out job injectivity test showed that a maximum injection rate (IR) of 20 MBWD at 1,500 psi, as against expected IR of 30 MBWD at the same pressure. Compared to IR of nearby/offset wells such as N-503, the injectivity results of N-510 were below expectation.

Following this limited success of the clean-out job, a matrix acid stimulation treatment was conducted in N-510. It involved injection of mud acid (HCl/HF) at 9 wt% and 1 wt%, respectively. This treatment was conducted to remove any damage limiting the well injectivity. However, instead of removing the existing damage, it created a severe formation damage, Figure 1. This is evident from the well injectivity which decreased from 15 to 5 MBWD at 1,000 psi, following the acid stimulation treatment. Another acid stimulation treatment using mud acid (9 wt% HCl/1 wt% HF) was applied in a second attempt to restore the well injectivty. However, this treatment was also not effective and the well injectivity remained at 5 MBD at 1,000 psi.

Calcium sulfate precipitation Precipitation of insoluble reaction products during acid treatments of injection wells has long been known. The formation of different precipitations such as iron hydroxide and calcium sulfate affects the treatment outcome and can decrease the well injectivity. This decrease is mainly due to the non-permeable nature of these precipitations (Delorey and McMaster 1996, Crowe 1985, Allaga et al. 1992, Crowe 1986, Smith et al. 1968, Raju et al. 2005, Leal et al. 2007, Nasr-El-Din et al. 2006, Raju and Nasr-El-Din 2004, Moghadasi 2003).

Considering the chemical composition of the injected water, and the nature of acids used to stimulate N-510, it is important to discuss the process of calcium sulfate precipitation before the analysis of lab and field results. This scale forms when its solubility limit is reached, therefore, understanding the factors that affect its solubility will help in predicting its precipitation.

There are three crystal forms of calcium sulfate: gypsum, hemi-hydrate, and anhydrite. Hemi-hydrate calcium sulfate is an unstable solid form which changes to anhydrite at high temperature values, above 98°C. At lower temperature values, (i.e. T < 98°C), hemi-hydrate changes to gypsum. Generally, calcium sulfate has two stable solid forms: gypsum (CaSO4.2H2O) and anhydrite (CaSO4) with a transition temperature of 98°C (Ramsdell and Partridge 1929). The reservoir temperature in N-510 is nearly 85°C (186°F); therefore any precipitation of calcium sulfate will be in the form of gypsum.

Calcium sulfate, gypsum, has relatively low solubility limits in water. At 25°C, the solubility value of calcium sulfate is almost 2.36 kg in 1 m3 of water. At higher temperatures, calcium sulfate becomes more in-soluble in water as low as 1.69 kg in 1 m3 of water at 90°C. Besides temperature, pH value also has a great impact on calcium sulfate solubility. In general, calcium sulfate is more soluble in low pH solutions where its solubility in 1 m3 of 5 wt% HCl is 16.9 kg compared to only 2.36 kg in 1 m3 of water (Silcock 1979, Delorey and McMaster 1996, Carlberg and Matthews 1973).

SPE 144007 3

Experimental Procedure Filter-cake removal To assess the effectiveness of N-510 clean-out treatment, solubility experiments were conducted to remove the drill-in fluids (DIF) filter cake using acid blend of 5 wt% HCl + 5 wt% formic. These experiments were performed using high pressure-high temperature filter press cell with the following procedure. Approximately 200 ml representative sample of water-based DIF, used during N-510 drilling operations, Table 2, was introduced into the fluid loss cell. Using 5 µm ceramic disk as a medium, filtration process was initiated by applying a differential pressure of 300 psi. This filtration process was continued at 186°F until the fluid loss reached a constant rate, indicating that the mud filter cake was built on top of the used ceramic disk. The weight of the formed mudcake was measured before and after it was soaked in clean-out acid, at 186°F and 300 psi differential pressure. The recorded values were used to calculate the loss percent in the cake weight due to its interaction with acid wash fluid.

In another set of solubility experiments, the efficiency of mudcake removal with wash acid was examined in the presence of the formation rock cuttings. Different weight percents of rock cuttings at 2, 8, and 25 wt% were mixed with various mudcakes formed at 186°F and 300 psi differential pressure. At these temperature and differential pressure values, each generated mudcake-rock cuttings mixture was left to react with fresh wash acid sample. Loss percent in mudcake weight was calculated from its initial and final weight values before and after acid reaction, respectively.

Acid compatibility tests Acid compatibility testing was determined with Jilah water. Representative field samples of Jilah water were obtained and used in all lab experiments, Table 1. Wash acid sample was neutralized with calcium carbonate powder while stirring until the reaction solution pH value reached approximately 3-4. This procedure represents the reaction of clean-out acid with mud filter cake, mainly composed of calcium carbonate. The partially spent acid was then mixed at 1:1 weight ratio with Jilah water. Mixed spent acid-Jilah water was heated up to almost 80°C. Any solid precipitation in the mixture solution was collected using 1.2 µm filter paper for Environmental Scanning Electron Microscopy (ESEM) analysis.

Core-flood experiments Core-flood testing was conducted to investigate the effect of various acid systems, wash acid and stimulation acid, on the permeability of reservoir cores. These experiments were carried out in a linear mode at a temperature value of 186°F and a back-pressure of 1,500 psi using representative reservoir core plugs, Table 3.

In each conducted core-flood experiment, the core plug was first saturated with Jilah water while monitoring the pressure drop across the core plug. Initial core permeability to Jilah water was determined before the injection of acid. After acid introduction at 1 cm3/min, Jilah water was injected again in forward or reverse direction to measure the retained permeability after acid interaction with the core plug. At the end of any core-flood experiment that indicated a negative acid interaction, the treated core plug was extracted and cut into two equal halves, along acid flow path, and then analyzed with ESEM.

In one of core-flood experiments involving injection of wash acid; the core plug was first saturated with NH4Cl brine to prevent any induced damage as a result of clays instability during the experiment. This step was important in order to: 1) assess the effect of mixing wash acid with Jilah water on the core permeability with no other potential damaging mechanisms and 2) compare the effect of wash acid-Jilah water mixture on the core permeability to that of wash acid-NH4Cl mixture.

Results and discussion Treatments and chemicals for returns analyses A stimulation program was initiated to restore the injectivity of N-510. It consisted of two main treatments. The first one was a wash acid job, which included injection of HCl/formic mixture to remove mud filter cake built on the face of the formation after drilling operations. Following this treatment, an injectivity test showed that the well injection rate was below expectation. Therefore, it was decided to proceed with the second treatment where the well was stimulated with HCl/HF blend to remove any present formation damage limiting the well injection rate. Tables 4 and 5 show the main stages of the wash acid and the acidization treatments, respectively.

Water of low salinity and sulfate concentration, Manjor water, was used for fluid preparation of pre-flush, acid, post flush, and displacement stages of both wash acid and acid stimulation treatments. The chemical composition of this water along with those of other injected fluids are shown in Table 1. It is worth noting that the injection water, Jilah water, contained relatively high sulfate content, 4,100 ppm. This high sulfate concentration played a key role in the injectivity decline experienced by N-510, as will be discussed later.

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Well flow-back analysis (wash acid treatment) The main objective of wash acid treatment was to remove mud filter cake built on the face of the drilled formation. The cleanout fluids were pumped down using coil tubing and the well was shut-in and then flowed back for nearly 25 h. Samples collected after flow-back were analyzed for pH and key ions.

Figure 2 shows the pH value of flow-back samples as a function of time. The pH remained nearly constant at 4 for almost 2 h after the start of flow-back. This pH value indicated that these collected samples were pre-acid returns. The arrival of acid returns was clearly indicated by the sharp drop in pH to the lowest value of 0.7. The pH remained at this level for the consecutive 4 h after 2 h of the start of flow-back. In subsequent samples the pH increased again to 2.5 over the next two hours. It is interesting to note that the rise again in the pH of flow-back samples was slower than its sharp decrease rate, which means that the late returns of spent acid had more mixing degree than its early returns. This is also evident from the analysis of the excess acid in collected samples.

Figure 3 depicts the excess acid in flow-back samples as a function of time. The excess acid was not present in the samples collected before 2 h of flow-back. After the start of spent acid arrival, the excess acid value, with a sharp increase, reached an average maximum value of 3 wt% in returns collected at 2-6 h. However, in subsequent samples, it gradually decreased to zero at 10 h. The difference between the concentrations of excess acid in flow-back samples and fresh injected acid is mainly due to two factors namely: dilution effect and acid reaction. To assess the degree of dilution and the amount of acid consumed, chloride content in produced fluids was used since spent acid, if present in the collected return, would still be detectable as a chloride salt.

Figure 4 shows the profile of chloride concentration in flow-back samples as a function of time. From the variation of chloride concentration with time, three main observations can be stated. First, the samples before and after acid returns were mixtures of Jilah water, pre-flush or post-flush samples, since chloride concentration of 16,700 ppm falls between those of Jilah water and NH4Cl brine, Table 1. Second, similar to excess acid content, chloride concentration increased to a maximum of 48,500 ppm at 5 h and then, gradually decreased to the level of pre-acid samples after 18 hours. It is interesting to note that the maximum chloride concentration obtained was nearly 100% of the injected acid chloride concentration. This result highlighted the fact that there was no dilution or dispersion of acid between 5-7 h. The third observation from Figure 4 is that the decrease rate in chloride content was slower than its sharp increase rate. This behavior re-states the fact that the later stages of the acid returns had higher degree of mixing than its early stages.

Using the chloride ion as a tracer, the dilution factor, spent acid vol% in produced samples, was calculated, Figure 5. These dilution factors were determined from measured chloride content in flowed back samples and chloride concentration of different injected fluids. For example, the dilution factor of flow-back sample produced at 14 h with chloride content of 24,000 ppm can be calculated as follows:

                1

 

                                                                                                                   1                                                                                                              

             14  24,000                              5  %    5  %  48,630         16,700                                                  

     24,000

48,630   1 16,700 24,000 0.23

hese dilution factors provided new insights into the analysis of excess acid results. From Figure 5, it is clear that 5-7 h flo

T

wback samples had dilution factors of nearly unity, indicating that they were un-diluted acid returns. Excess acid results of these samples, Figure 3, highlighted the fact that 70% of injected acid was consumed in down-hole reactions, where excess acid value is 30% of original acid concentration. The excess acid was a result of either using an acid amount more than needed for this clean-out treatment or the acid did not have sufficient soaking time. The latter possibility was found to be the case, after analyzing later acid returns. Flowed back sample at 10 h had nearly zero excess acid. This absence of excess acid could be due to dilution effect or complete acid reaction. From, Figure 5, this sample had an acid vol% of 0.4. If the acid amount used was more than required for this clean-out job or excess acid amount was diluted with brine, then an acid excess value of (3 wt% *0.4 = 1.5 wt%) would have been still detected in this sample. This result indicated that early acid returns did not have sufficient soaking time and were flowed back with relativity high excess acid values. Most of this excess acid was in the form of formic acid. This is evident from Figures 2 and 6, where at pH values from 0 to nearly 1, only very low percent of formic acid dissociates into hydrogen and

SPE 144007 5

formate ions. This indicated that only low amount of formic acid in early acid returns, having relatively short soaking time, was consumed. Formic acid has retarded reaction time and requires long soaking time to be completely consumed.

At 20 h after flow back, the spent acid disappeared from flow-back samples, as indicated by dilution factors of nearly zero, Fig

function of time. Similar to the chloride profile with time, aluminum lev

that the spike in the content of both calcium and magnesium ions started at 2 h of flowback to reach a ma

al sulfate ion concentration, in flow-bac

rom the analysis of the wash acid returns, the following items can be concluded: based on chloride as a tracer.

th calcium carbonate particles and rock cuttings present in

sulfate precipitated during the cleanout treatment. Most of this precipitation occurred in late stages of the

La testing results (filter cake removal) used during mudcake removal treatment applied in N-510, the solubility of different

it is clear that the HC

ure 5. This clearly indicated that the flow back was enough to produce all the spent acid. This also evident from the calcium, magnesium, and aluminum contents in flow back samples.

Figure 7 shows the concentration of aluminum ion as ael with time started increasing after the start of spent acid production at 2 h till it reached a maximum of 1,000 ppm and then,

decreased to nearly zero at 18 h. The most likely source of aluminum is the clay minerals present in the rock cuttings mixed with the mud filter cake.

Figure 8 shows ximum of 9,000 and 4,000 ppm, respectively, before dropping back to pre-acid levels. The source of magnesium ion is most

likely the ankerite and/or dolomite traces present in rock cuttings mixed with mudcake. The significant difference between the calcium and magnesium levels is due to the additional reaction of acid with calcium carbonate particles present in the mudcake. The un-diluted acid returns showed that nearly 7 wt% of the injected acid was consumed due to acid reaction. Considering only the reaction of HCl with mudcake, a calcium concentration of approximately 26,000 ppm results from the complete reaction of 5 wt% HCl with limestone. However, there is a significant difference between the maximum measured calcium concentration of 9,000 ppm and the theoretical value of 26,000 ppm. This difference was initially attributed to only the partial acid reaction with both the clay minerals and corrosion products in casing or screens to produce aluminum and iron, respectively, Figure 9. However, this believe was ruled out after the analysis of sulfate ion in produced samples.

Figure 10 shows the variation of sulfate ion concentration with time. The profile of actuk samples, can be divided into four main parts: (1) constant portion at 3,600 ppm, (2) sharp decrease to a minimum of 1,260

ppm, (3) sharp increase to 2,500 ppm, and (4) nearly constant portion at 2,500 ppm. The first constant portion of the sulfate ion profile with time represents the sulfate concentration in pre-acid samples. It is worth noting that the sulfate content in these samples is less than that in Jilah water; 4,100 ppm. This reduction in sulfate concentration was due to dilution with low-sulfate post-flush. The mixing of injection water with acid returns also explains the sharp decrease in sulfate concentration at nearly 3.3 h after flow-back, where the dilution factor increased from nearly 0.2 to unity. Similarly, it was noted that the sulfate concentration in post-acid samples is lower than 4,100. At first, this reduction was expected to be also due to dilution effect. However, from Figure 10, it is clear that the extent of this reduction in sulfate ion concentration was significantly more than that observed with calculated sulfate concentrations based on dilution factors. This result indicated that the reduction in sulfate ion concentration was partially due to dilution with acid returns. The additional reduction in sulfate concentration highlighted the presence of calcium sulfate precipitation, which explains the difference noticed between the measured calcium concentration and its theoretical value. Calcium sulfate occurred in the late stages of acid returns due to two main reasons. First, the mixing degree of spent acid with high sulfate water is high towards the end of flow-back. Second, calcium sulfate is more soluble in low pH solutions than in neutral pH solutions (Li and Demopoulos 2005, Vetter and Phillips 1970). It is expected that most of calcium sulfate precipitated in the vicinity of the wellbore where most of the mixing between spent acid and Jilah water occurred.

F

• During flow-back, the injected acid was diluted. The dilution factor can be calculated • More soaking time is required for clean-out treatments utilizing formic acid or its mixtures. • The flow-back time was enough to produce the spent acid. • The injected acid was mainly consumed by the reaction wi

mud filter cake. In addition, the acid was partially consumed by the reaction with corrosion products present in the casing.

• Calciumwell flow-back when the spent acid, with high calcium ion, was mixed with high sulfate water in the wellbore vicinity.

b

To evaluate the performance of wash acidmudcakes in 5 wt% HCl + 5 wt% formic acid was measured, using HPHT filter pressure cell, at 186°F and 300 psi differential pressure. The solubility tests were used to determine the percent loss in mudcake weight due to acid interaction.

Figure 11 shows the solubility values of different mudcakes in clean-out acid solutions. From this figure, l/formic mixture at 5/5 wt% was efficient to dissolve significant amount of the original mud filter cake, where the weight loss

percent, after acid/cake interaction, reached nearly 85%. This high weight loss value was expected since the main component of the mud filter cake was calcium carbonate, which is very soluble in HCl solutions.

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In order to simulate down-hole drilling operations, different weight percents of formation rock cuttings were added to several generated mudcakes. The presence of formation rock cuttings had negative impact on the effectiveness of the wash acid in removing the mudcake, as shown in Figure 11. For example, increasing the formation cuttings weight percent to 2 wt% decreased the mudcake solubility in wash acid from 85 to nearly 25%. Although rock cuttings were present in low amount, however, they resulted in significant decrease in acid dissolving power. This behavior can be understood knowing that these cuttings are mainly composed of quartz, which has low solubility in HCl. This characteristic enabled these cuttings to act as a barrier that prevented the acid contact with the remaining un-dissolved mudcake, Photo 1.

The discussion stated above provides another possible explanation to the presence of high excess acid in flowed back samples after N-510 wash acid treatment. It was stated earlier that this excess acid indicated that the acid did not have enough contact time with the mudcake. However, the high excess acid in flow-back returns could also be due to the presence of rock cuttings in mud filter cake, where these cuttings may have acted as a slow-soluble barrier between the clean-out acid and the mudcake. Hence, this led to the partial acid spending which in turn led to the presence of high excess acid in flow-back returns.

Lab testing results (acid compatibility) Samples of wash acid system were reacted with calcium carbonate powder while stirring until the pH value reached nearly 3-4. This procedure represents the reaction of wash acid system with mud filter cake, which is mainly composed of calcium carbonate. Samples of partial spent acid were mixed with Jilah water at 1:1 weight ratio.

No precipitation resulted from the mixing of spent wash acid samples with Jilah water at room temperature. However, onset of precipitation started only after 15 minutes when spent wash acid-Jilah water mixtures were heated up to 80°C. SEM analysis conducted has shown that calcium sulfate, CaSO4, is the main component present in collected solids from this precipitation. These results indicated that spent wash acid is not completely compatible with Jilah water. This interesting finding was supported by the analysis of flow-back returns from N-510 wash treatment, which indicated that calcium sulfate precipitated during clean-out treatment was due to the mixing of spent wash acid, having high calcium content, with Jilah water, having high sulfate ion content. The calcium sulfate precipitation has high impact on formation permeability as will be discussed in the following section.

Lab testing results (core-flood) Four core-flood experiments were carried out with (5 wt% HCl/5 wt% formic) acid, or mud acid (9 wt% HCl/1 wt% HF) and core plugs, selected from “N” field, at reservoir temperature of 186ºF. These experiments were conducted to investigate the effect of different injected fluids and their mixtures on the permeability of reservoir cores.

The first core-flood test was performed using N-704 core plug # 101. The experiment was carried out such that it simulated the clean-out and stimulation treatments conducted on N-510. The first step commenced with injection of Jilah water (10 PV) in the forward direction. This step was done to saturate the core plug with Jilah water and to measure its initial permeability. Once the pressure drop across the core stabilized, the experiment was stopped to extract the core plug and build a mudcake on its inlet face. This cake was generated at reservoir temperature and pressure using HPHT filter press and a mud sample similar to the one used during N-510 drilling operations. After that, the core plug was charged again into the core holder and the experiment was resumed by injecting nearly 2 PV of clean-out acid (5 wt% HCl/5 wt% formic) in the forward direction at 1 cm3/min. After the acid injection, the core was again retrieved and the residual materials of mud filter cake after its reaction with wash acid were removed mechanically from the core inlet face. Then, the saturated core with spent wash acid was partially flushed out by injecting 0.5 PV of Jilah water at 1 cm3/min in the reverse direction. The remaining acid in the core (0.5 PV) was mixed with Jilah water, where 2 PV of Jilah water were introduced into the core plug in the forward direction. This sequence of clean-out acid and Jilah water injection simulated the mixing that occurred between wash acid and Jilah water during the well flow-back and well injectivity stages, following clean-out treatment. The final steps of the core-flood experiment included the injection of 1 PV of mud acid (9 wt% HCl/1wt% HF) at 1 cm3/min in the forward direction, 3 PV and 4 PV of Jilah water in the forward and reverse directions at 1 cm3/min, respectively. These three stages of injection simulated the first stimulation treatment conducted on N-510.

Figure 12 shows the pressure drop across the N-704 core plug # 101 as a function of cumulative pore volume of injected fluids. The pressure drop increased upon the injection of wash acid into the core, at 1 cm3/min, from nearly zero to 1,000 psi. Since the injection was at constant flow rate (1 cm3/min) and the wash acid viscosity value is comparable to that of Jilah water, the pressure increase across the plug was considered to be as a result of two causes: 1) presence of partially-removed mudcake on the inlet face of core plug; 2) incompatibility between partially spent wash acid with Jilah water. Mechanical removal of the remaining residual materials of mudcake from the plug inlet face resulted in a decrease in the pressure drop from 1,000 to almost 10 psi. This indicated that most of the observed initial increase in the pressure drop was due to the un-complete removal of the filter cake. In addition, it highlighted that the mixing of partially spent wash acid with Jilah water had negative impact on the core permeability, where the retained permeability after acid injection, with no presence of any mudcake residual materials, was only 8% (defined as the final Jellh water permeability divided by the initial Jellh water permeability). This suggests that mixing of spent wash acid with Jilah water can significantly reduce the formation permeability, and hence, injectivity. This incompatible

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mixing resulted in calcium sulfate precipitation as observed in compatibility lab testing. It was considered that the precipitation of calcium sulfate could have caused this additional 10 psi of pressure drop. This precipitation can be partially removed with fresh mud acid since the retained permeability increased from 8 to 57% upon the injection of 1 PV of 9 wt% HCl/1 wt% HF at 1 cm3/min.

Damage due to the mixing of partially spent acid with Jilah water was also observed in a second core-flood using N-704 core plug # 87. This experiment was designed such that the extent of calcium sulfate precipitation effect on core permeability can be investigated with no other induced damage. Therefore, injected wash acid was first partially reacted with calcium carbonate powder prior to its injection into the core plug. This step simulated the wash acid reaction with mud filter cake, mainly composed of calcium carbonate, and eliminated the need to cover the inlet face of the core plug with a mudcake. Another important step is that the core was saturated with NH4Cl brine to ensure that no any potential damage due to clays instability during the experiment. Finally, the core plug was analyzed before and after the experiment using CT scan.

Figure 13 shows the pressure drop across the core # 87 as a function of cumulative pore volume of injected fluids. It is clear from this figure that partially-spent wash acid had some stimulation effect on the core when it was injected after the NH4Cl saturation step. The core permeability to NH4Cl brine increased from 47 to nearly 50 mD after injection of 1 PV of 5 wt% HCl/5 wt% formic acid at 1 cm3/min. After this stage, the core was saturated with Jilah water by injecting nearly 4 PV of Jilah water at 1 cm3/min in the forward direction. This was followed by injection of 1 PV of partially-spent acid and 2 PV of Jilah water at 1 cm3/min in the forward and reverse direction, respectively. The final core permeability to Jilah water was measured by injecting nearly 3 PV of Jilah water in the forward direction and it was found to be 44 mD. This value is nearly 88% of core permeability to NH4Cl brine prior to mixing Jilah water and spent wash acid in the core. This difference between the two permeability values attributed to the difference between the Jilah water viscosity to that of NH4Cl brine or due to calcium sulfate precipitation. To investigate the presence of calcium sulfate precipitation, the treated core plug was first analyzed using CT scan and then cut into two halves along the flow path and both pieces were analyzed using SEM. Figure 14 shows the CT scans of the core plug before and after its interaction with injected fluids. Basically, these scans showed that a lower density material, indicated by low CT scan numbers (1,600-1,700), precipitated in the core and significant amount of this material was present near the inlet face of the core. SEM analysis identified the precipitated material as calcium sulfate, Figure 15. These results indicated that calcium sulfate precipitated during the mixing of Jilah water with partially-spent acid. However, the effect of this precipitation on the core permeability was not significant, possibly due to the stimulation effect of wash acid.

The effect of calcium sulfate on core permeability was more pronounced in a core-flood experiment using N-704 core plug # 125, Figure 16. The core was first saturated with Jilah water with initial permeability to Jilah water of 200 mD. Unlike other core-flood experiments, the Jilah water was not completely displaced out of the core with wash acid. Only 0.75 PV of wash acid was injected at 1 cm3/min in the forward direction and soaked for 1 h. Then, Jilah water was injected in the reverse direction at 1 cm3/min, simulating flow-back stage in the field. Finally Jilah water was injected at 1 cm3/min in the forward direction, thereby simulating the injectivity test in the field. The retained core permeability to Jilah water was nearly 72% of initial permeability. This result combined with other core-flood results, clearly indicated the negative impact of the mixing of Jilah water with partially-spent wash acid on the permeability of reservoir cores.

The effect of the mud acid injection on reservoir cores permeability was completely investigated in a core-flood experiment. In Figure 17, 3 PV of mud acid were injected at 1 cm3/min into N-704 core plug # 71, following the plug saturation with Jilah water. The pressure drop across the plug decreased from 1.4 psi to almost 0.5 psi upon the injection of mud acid. The core permeability to Jilah water increased after the injection of mud acid from 63 to 195 mD, a permeability enhancement of 68% (defined as difference between initial and final permeability values to Jilah water divided by initial Jilah water permeability). This core-flood experiment clearly showed that mud acid was able to stimulate M sandstone core plugs, with no observed negative impact. The mud acid interaction with core plugs and with calcium sulfate precipitation was studied with fresh acid samples. The effect of spending of mud acid on its interaction with both calcium sulfate and sandstone formation will be discussed later.

Well flow-back analysis (acid stimulation treatment) N-510 well was stimulated with 9 wt% HCl-1 wt% HF to improve its injection rate. The treatment included the injection of pre-flush (4 wt% NH4Cl brine), acid pre-flush (5 wt% HCl/5 wt% formic), mud acid (9 wt% HCl/1 wt% HF), acid over-flush (5 wt% HCl), and post-flush (4 wt% NH4Cl brine). These fluids were pumped down and the well was shut-in and then flowed back for nearly 18 h. Samples collected after flow-back were analyzed for pH, acid concentration and key ions.

The pH values of the flowed back fluids are shown in Figure 18. The high pH values (~ 7) measured at 2 and 3 h after the start of flow-back are due to the use of post-flush and displacement NH4Cl brines at the end of treatment. However, earlier fluid returns had relatively lower pH values (2-4), which indicated that low amounts of spent acid returned with these flow-back samples. Further production of partially spent acid returns decreased the pH values of produced fluids to reach a minimum of 0.7 at nearly 5 h after the start of flow-back. The pH remained at this value for the 7 consecutive hours before it increased again to 1.9 at 18 h

8 SPE 144007

after flow-back. This low pH value at the end of flow-back stage suggested that the spent acid was not completely recovered. This is also evident from chloride contents in produced samples.

Figure 19 depicts the profile of chloride content in flow-back samples as a function of time. The chloride content was initially around 10,000 ppm, but it increased to a maximum of 70,000 ppm in 4 hours. It remained at this value for the 5 consecutive hours before it decreased to 45,000 ppm at the end of flow-back. The highest value of chloride content in returns represented nearly 78% of maximum injected chloride content during mud acid stage (9 wt% HCl-1 wt% HF). Dilution of mud acid returns with acid pre-flush served as a major cause of this difference between injected chloride content and that measured in flow-back samples. This extent of mixing or dilution factor can be calculated using the measured chloride content in returns, the injected chloride content during mud acid (90,000 ppm), and acid pre-flush (50,000 ppm), as shown earlier. For example, at 8 h after flow-back, the measured chloride content of 70,000 ppm indicated that the dilution factor of the mud acid returns was nearly 0.7. In other words, 70 vol% of the flow-back sample at 8 h was spent mud acid.

Based on these calculated dilution factors, the maximum fluoride content of 7,000 ppm is expected to be in flow-back samples at 8 h to 12 h after flow-back, where the minimum dilution extent of spent mud acid occurred. However, the most striking feature of Figure 19, showing fluoride content in returns, is the low concentration of fluoride ion, as low as 200 ppm. In general, the reduction in fluoride concentration in returns is due to two main causes: dilution and precipitation. Given the measured fluoride is drastically lower than expected diluted values, this significant additional reduction in fluoride content is due to precipitation.

Fluoride loss can be a result of its interaction with different dissolved ions produced from reaction of mud acid with different minerals. Among the common fluoride precipitates are aluminum fluoride and sodium, potassium fluosilicates:

3 F- + Al3+ ↔ AlF3↓

H2SiF6 + 2 Na+ Na2SiF6 ↓ + 2H+ →H2SiF6 +2 K+ K2SiF6 ↓ + 2H+ →Aluminum fluoride precipitates when F/Al ratio is 3 or above. The F/Al is dependent on the pH value of the mud acid reaction

solution where it reaches 3 at pH values of 2.5 and above (Shuchart and Gdanski 1996). From Figure 18, it is clear that the maximum pH in spent mud acid returns was around 2, indicating that aluminum fluoride did not precipitate during N-510 stimulation treatment. This is also clear from the profile of aluminum concentration, in returned samples, with time, Figure 20. The aluminum content increased upon the start of production of spent mud acid returns until it reached a maximum of 7,000 at 10 h after flow-back. No reduction was observed in aluminum content, in subsequent samples, except for the one expected due to dilution effect near the end of flow-back. Similarly, the potassium content showed similar profile to that of aluminum, Figure 21. It increased to a maximum of 3,000 ppm, suggesting that low amounts of illite and feldspars minerals were dissolved. At the end of flowback stage, potassium ion concentration decreased due to mixing of spent mud acid with acid pre-flush returns. Sodium content in return samples as function of time showed different profile, Figure 22. The Na content was initially around 7,000 ppm, but decreased throughout the returns to as low as 2,300 ppm in spent acid returns. The major source of sodium is the pre-acid samples which contained around 7,000 ppm. Based on calculated dilution factor of 0.7, the expected sodium content in this mixture of acid returns with pre-acid samples is approximately 2,100, which is equal to the measured value. Therefore, the observed reduction in sodium content in spent acid returns is mainly due to mixing effect.

Contacting HF with calcium ions will produce calcium fluoride, a white precipitate that can cause formation damage.

2 HF + Ca++ CaF2 ↓ +2H+ →

Figure 23 depicts the calcium ion content in fluid returns as a function of time. The spike in calcium concentration started upon the production of spent acid returns to reach a maximum of around 8,500 ppm. It remained constant at this level before it decreased at 15 h after flow-back. Based on calcium concentration trend with time, no calcium precipitation was expected. However, striking features of this trend were noted when it was compared with that of both sulfate and magnesium. Figure 24 shows the concentration of magnesium ion in flow-back samples. Unlike the calcium concentration, the magnesium content had a continuous increase before it decreased at 15 h after flow-back. The source of magnesium is the reaction of acid with ankerite and/or dolomite which are present in the formation, Table 3. Therefore, if magnesium content increased, then calcium content would increase as well. However, from Figures 23 and 24, the magnesium content increased from 3,500 to 4,100 ppm at 10 and 12 h, respectively, while calcium content decreased from 8,700 to 7,900 ppm. This suggested that calcium-based precipitation occurred. This precipitation is expected to be calcium fluoride since it resulted in the reduction of both calcium and fluoride content at the same time. This precipitation of calcium fluoride occurred in-situ due to spending of mud acid. At low pH values, mud acid was first compatible with dissolved calcium because the fluoride is associated with hydrogen ion, with no free fluoride ions. In other words, calcium fluoride is very soluble in low pH mud acid solutions, (Pan and Darvell 2007). However, as the mud acid reacted with aluminum-silicates or calcite in the formation, acid concentration decreased and more free fluoride ions

SPE 144007 9

produced in the reaction solution, Figure 25, and as a result calcium fluoride precipitated. In addition to calcium fluoride scale, calcium sulfate precipitation also occurred during N-510 stimulation treatment.

Figure 26 shows the sulfate ion content as a function of time. It increased to a maximum of 9,000 at 7 h after flow-back, and then decreased to a minimum of 3,000 ppm and remained constant until the end of flow-back. The source of this high sulfate ions content in the returns was the calcium sulfate scale that precipitated during the wash acid treatment, as stated earlier. Calcium sulfate has high solubility in HF solutions compared to that of HCl and brine solutions. Therefore, the peak in sulfate concentration was expected to occur in spent mud acid returns. However, the maximum sulfate concentration was measured in acid post-flush returns. This suggested that high amounts of initially dissolved calcium sulfate during mud acid stage precipitated upon the spending of the acid in the formation.

During mud acid stimulation treatments, acid pre-flush stage is pumped ahead of the mud acid stage in order to dissolve the calcium/magnesium materials and prevent the mud acid contact with calcium/magnesium ions, which results in calcium/magnesium fluoride precipitations at high pH values. In N-510, the acid pre-flush did not prevent the contacting of mud acid with calcium ions because they were present as calcium sulfate solids, which have relatively low solubility in HCl solutions. As a result, the injected mud acid initially dissolved most of calcium sulfate scale and then calcium re-precipitated as calcium fluoride upon the acid spending in the formation.

Conclusions and Recommendations:

• Formic is a weak acid and its reaction rate is relatively slow. Therefore, long soaking time is required for HCl/formic clean-out jobs.

• Mixing between spent acid, high in calcium content, and high sulfate water will result in calcium sulfate precipitation. • Live mud acid can dissolve calcium sulfate scale. However, upon acid spending, both calcium sulfate and calcium

fluoride will precipitate due to the increase in acid solution pH value. • Large volume of acid pre-flush, during clean-out jobs, should be injected to prevent the mixing between spent acid

and high sulfate water during the well flow-back. This will prevent the precipitation of calcium sulfate. • Calcium sulfate scale inhibitor should be added to the acid stage during mudcake clean-out treatments. This is

required to prevent calcium sulfate precipitation when the spent acid is mixed with high-content sulfate water.

Acknowledgments The authors wish to acknowledge the Saudi Arabian Oil Company (Saudi Aramco) for granting permission to present and publish this paper. Special thanks go to the Chemistry and Advanced Instruments Units of the R&D Center for their analysis of different solutions and solids

References Allaga, D.A., Wu, G., Sharma, M.M., and Lake, L.W., 1992. Barium and calcium sulfate precipitation and migration inside sand-packs. SPE

Formation Evaluation, (March), 79–86. Crowe, C.W., 1985. Evaluation of agents for preventing precipitation of ferric hydroxide from spent treating acid. J. Pet. Technol. 37(4), 691. Crowe, C.W., 1986. Prevention of Undesirable Precipitates from Acid Treating Fluids. Paper SPE 14090 presented at the SPE 19th International

Meeting on Petroleum Engineering held in Beijing, China, March 17-30. Smith et al., 1967. Removal and Inhibition of Calcium Sulfate Scale in Waterflood Projects. Paper SPE 1957

presented at the SPE 42nd Annual Fall Meeting held in Houston, USA, October 1-4.

Carlberg, B.L., and Matthews, R.R., 1973. Solubility of calcium sulfate in brine. Paper SPE 4353 presented at SPE Oilfield Chemistry Symp., held in Denver, CO, USA, May 24-25.

Nasr-El-Din, H.A., Zabihi, M., Al-Dossary, K., Djelliout, M.A., and Kelkar, S.K., 2006. Restoring Injectivity of Wells Drilled in Sour Carbonate

Formations. Paper SPE 102860 presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, September 24-27.

Delorey, J.R., Allen, S., and McMaster, L.,. 1996. Precipitation of Calcium Sulphate During Carbonate Acidizing: Minimizing the Risk. Paper

SPE 96-84 presented at the 47th Annual Technical Meeting of The Petroleum Society in Calgary, Alberta, Canada, June 10 -12. Leal, J. et al., 2007. A Systematic Approach to Remove Iron Sulphide Scale: A Case History. Paper SPE 105607 presented at the SPE Middle

East Oil and Gas Show and Conference, Kingdom of Bahrain, March 11-14.

10 SPE 144007

Moghadasi, J. et al., 2003. Scale Formation in Iranian Oil Reservoir and Production Equipment During Water Injection. Paper SPE 80406 presented at the International Symposium on Oilfield Scale, Aberdeen, UK, January 29-30.

Raju, K.U., Nasr-El-Din, H.A., Hilab, V.V., Siddiqui, S., and Mehta, S., 2005. Injection of Aquifer Water and GOSP Disposal Water into Tight

Carbonate Reservoirs. SPEJ, 10, 374-384. Raju, K.U., and Nasr-El-Din, H.A., 2004. Calcium Sulfate Scale: Field Tests and Model Predictions. Paper 04397 presented at the NACE

International, CORROSION, New Orleans, La, March 28 - April 1. Ramsdell, L.S., and Partridge, E.P., 1929. The crystal forms of calcium sulphate. J. American Mineralogist, 14, 59-74. Li, Z., and Demopoulos, G., 2005. Solubility of CaSO4 Phases in Aqueous HCl + CaCl2 Solutions from 283 K to 353 K. J. Chem. Eng. Data,

50, 1971-1982. Pan, H., and Darvell, B., 2007. Solubility of calcium fluoride and fluorapatite by solid titration. Archives of Oral biology, 52, 861–868. Shuchart, C., and Gdanski, R., 1996. Improved Success in Acid Stimulations with a New Organic-HF System. Paper SPE 36907 presented at

European Petroleum Conference held in Milan, Italy, October 22-24. Silcock, H.L. Solubilities of Inorganic and Organic Compounds vol. 3. Pergamon, New York, USA, pp. 754–755. Vetter, O., and Phillips, R., 1970. Prediction of Deposition of Calcium Sulfate Under Down-Hole Conditions. J. Petroleum Technology,

October, 1299-1308.

SPE 144007 11

Table 1: Chemical composition of injected fluids.

Variable Manjor water

Jilah water

Pre-flush Post-flush

Displacement

Acid (HCl/formic)

Acid (HCl/HF)

Chloride, mg/L 542 7,800 39,542 48,542 86,842 Fluoride, mg/L 0 0 0 0 9,500

Aluminum, mg/L 0 0 0 0 0 Calcium, mg/L 202 672 202 202 202

Magnesium, mg/L 72 409 72 72 72 Sulfate, mg/L 1,500 4,100 1,500 1,500 1,500

pH 7-8 7-8 4-5 < 0 < 0

Table 2: Formulation of 1.0 bbl of water-based mud formulation used during M-5 drilling operations. Variable Value

XC-Polymer, gal 0.5-1.0 Pac-L, lb 3.0-4.0 KCl, lb 22.0 KOH, lb 0.15-0.50

CaCO3 (fine), lb 9.0 CaCO3 (medium), lb 15.0

Lubricant, vol% 1-3 Distilled water, bbl 0.95

pH 9-10

Table 3: Average mineralogical composition of core used in core-flood experiments Mineral Concentration, wt%

Quartz (SiO2) 68 - 97 Feldspar (KAlSi3O8 - NaAlSi3O8 - CaAl2Si2O8) 0 - 19

Illite/smectite KAl4(Si8,Al)O20(OH)4/(Ca,Na)(Al,Mg,Fe)4(Si,Al)8O20(OH)4 0 - 13 Kaolinite (Al2Si2O5(OH)4) 0 - 8

Ankerite ((Ca,Fe, Mg)(CO3)2) 0 - 7 Anhydrite (CaSO4) 0 - 4

Chlorite (Fe5Al)(AlSi3)O10(OH)8 0 - 2 Calcite (CaCO3) 0 - 1

12 SPE 144007

Table 4: Main stages of wash acid treatment Treatment stage Main fluid & additives Volume, gal

Pre-flush 4 wt% NH4Cl Surfactant, mutual solvent 4,550

Acid 5 wt% HCl + 5 wt% Formic Corrosion inhibitor, iron control agent, surfactant 13,650

Post-flush 4 wt% NH4Cl Surfactant, mutual solvent 2,730

Displacement 4 wt% NH4Cl Surfactant, mutual solvent 5,887

Table 5: Main stages of acid stimulation treatment Treatment stage Main fluid & additives Volume, gal

Pre-flush 4 wt% NH4Cl Surfactant, mutual solvent 4,550

Acid pre-flush 5 wt% HCl + 5 wt% Formic Corrosion inhibitor, iron control agent, surfactant 13,650

Main acid 9 wt% HCl + 1 wt% HF Corrosion inhibitor, iron control agent, surfactant 18,200

Post-flush 4 wt% NH4Cl Surfactant, mutual solvent 4,550

Displacement 4 wt% NH4Cl Surfactant, mutual solvent

5,887

SPE 144007 13

0

500

1000

1500

2000

2500

0 10,000 20,000 30,000 40,000

Wel

l hea

d pr

essu

re, p

si

Injection rate, BWD

N‐510 after Mud Acid N‐510 after Acid wash

N‐511 N‐503

Figure 1: Injection rates results after stimulation treatments in different “N” wells.

0

2

4

6

8

10

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28

pH

Time, h

Arrival of acid returns

Figure 2: Flow-back analysis (wash acid treatment): pH.

14 SPE 144007

Figure 3: Flow-back analysis (wash acid treatment): excess acid.

0

2

4

6

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28

Aci

d co

ncen

trat

ion,

wt%

Time, h

Effect of dilution

Acid with no dispersion

0

10000

20000

30000

40000

50000

60000

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28

Con

cent

ratio

n, m

g/L

Time, h

Chloride in acid wash fluid = 48,630 ppm

Chloride content in pre and after acid returns = 16,700 ppm

Acid with no dispersion

Figure 4: Flow-back analysis (wash acid treatment): chloride.

SPE 144007 15

0

0.2

0.4

0.6

0.8

1

1.2

0 5 10 15 20 25 30

Dilu

tion

fact

or

Time, h

Dilution factor of acid solution = Acid volume

Acid volume + Injected water volume

Dilution factor = 0.4(40% of produced sample is acid)

Figure 5: Flow-back analysis (wash acid treatment): dilution factor.

Figure 6: Distribution of formic acid species as a function of pH.

0.00

0.20

0.40

0.60

0.80

1.00

0 2 4 6 8 10 12 14

α

pH

Formate ion

Formic acid

16 SPE 144007

Figure 7: Flow-back analysis (wash acid treatment): aluminum.

0

200

400

600

800

1000

1200

0 5 10 15 20 25 30

Alu

min

um, m

g/L

Time, h

Figure 8: Flow-back analysis (wash acid treatment): calcium and magnesium.

0

2000

4000

6000

8000

10000

12000

0 5 10 15 20 25 30

Con

cent

ratio

n, m

g/L

Time, h

Magnesium level in pre‐acid and post ‐acid samples = 420 ppm

Calcium level in pre‐acid and post ‐acidsamples = 1,070 ppm

SPE 144007 17

Figure 9: Flow-back analysis (wash acid treatment): iron.

0

1000

2000

3000

4000

5000

0 5 10 15 20 25 30

Iron,

mg/

L

Time, h

Figure 10: Flow-back analysis (wash acid treatment): sulfate.

0

1000

2000

3000

4000

5000

0 5 10 15 20 25 30

Con

cent

ratio

n, m

g/L

Time, h

Sulfate concentration calculated based on dilution factor, only

mixing occured

[SO42‐]actual < [SO4

2‐]dilution , indicating the formation of sulfate‐based scale

[SO42‐]actual = [SO4

2‐]dilution , no preceipitation

Zone of precipitation

18 SPE 144007

0

20

40

60

80

100

0 2 8 25

Wei

ght l

oss,

%

Rock cuttings, wt%Figure 11: Solubility of mud filter cake in 5 wt% HCl + 5 wt% formic fluid at 186°F as a function of rock cuttings wt%.

Figure 12: Pressure drop across the core during injection of clean-out and mud acids, core plug # 101.

SPE 144007 19

Figure 13: Pressure drop across the core during injection of clean-out acid, core plug # 87.

20 SPE 144007

Figure 14: CT scan analysis of core plug # 87 before and after injection of spent clean-out acid and Jilah water at 186°F.

SPE 144007 21

Figure 15: Calcium sulfate precipitation in core plug # 87 after injection of spent clean-out acid and Jilah water at 186°F.

Calcium sulfate (CaSO4.H2O) Quartz (SiO2)

22 SPE 144007

Figure 16: Pressure drop across the core during injection of clean-out acid, core plug # 125, soaking time =1 h.

Figure 17: Pressure drop across the core after injection of mud acid (9 wt% HCl/1 wt% HF), core plug # 71.

SPE 144007 23

Figure 18: Flow-back analysis (stimulation acid treatment): pH.

0

1

2

3

4

5

6

7

8

0 5 10 15 20

pH

Time, h

Start of spent acid returnspHfinal flow-back sample = 2

Spent acid was partially flowed back

Figure 19: Flow-back analysis (stimulation acid treatment): chloride and fluoride.

0

100

200

300

400

500

600

700

800

900

0

20000

40000

60000

80000

100000

0 2 4 6 8 10 12 14 16 18 20

Con

cent

ratio

n, m

g/L

Time, h

F-

Cl-

(9 wt% HCl/1 wt% HF)returns with minmum

dispersion

F-

Cl-

Con

cent

ratio

n, m

g/L

24 SPE 144007

Figure 20: Flow-back analysis (stimulation acid treatment): aluminum.

0

1000

2000

3000

4000

5000

6000

7000

8000

0 5 10 15 20

Alu

min

um, m

g/L

Time, h

Figure 21: Flow-back analysis (stimulation acid treatment): potassium.

0

500

1000

1500

2000

2500

3000

3500

4000

0 5 10 15 20

Pota

ssiu

m, m

g/L

Time, h

SPE 144007 25

Figure 22: Flow-back analysis (stimulation acid treatment): sodium.

0

1000

2000

3000

4000

5000

6000

7000

8000

0 5 10 15 20

Sodi

um, m

g/L

Time, h

Figure 23: Flow-back analysis (stimulation acid treatment): calcium.

0

2000

4000

6000

8000

10000

0 5 10 15 20

Cal

cium

, mg/

L

Time, h

26 SPE 144007

Figure 24: Flow-back analysis (stimulation acid treatment): magnesium.

0

1000

2000

3000

4000

5000

0 5 10 15 20

Mag

nesi

um, m

g/L

Time, h

Figure 25: Distribution of HF acid species as a function of pH.

0.00

0.20

0.40

0.60

0.80

1.00

0.0 2.0 4.0 6.0 8.0 10.0 12.0 14.0

αi

pH

F‐

HF

SPE 144007 27

Figure 26: Flow-back analysis (stimulation acid treatment): sulfate.

0

2000

4000

6000

8000

10000

0 5 10 15 20

Sulfa

te, m

g/L

Time, h

28 SPE 144007

Fresh mudcake, no acid interaction

Mudcake residuals after acid reaction Mudcake residuals after acid reaction Rock cuttings = 0 wt% Rock cuttings = 2 wt%

Mudcake residuals after acid reaction Mudcake residuals after acid reaction Rock cuttings = 8 wt% Rock cuttings = 25 wt%