Investigation of Acid-Induced Emulsion Formation and Asphaltene Precipitation in Low Permeability Carbonate Reservoirs

Transcription

1 Investigation of Acid-Induced Emulsion Formation and Asphaltene Precipitation in Low Permeability Carbonate Reservoirs Authors: Tariq A. Al-Mubarak, Dr. Mohammed H. Al-Khaldi, Hussain A. Al-Ibrahim, Majid M. Rafie and Omar Al-Dajani ABSTRACT The increasing demand for energy has extended the development horizon toward relatively tighter formations all over the world. In Saudi Arabia, hydrochloric (HCl) and organic acids have been used extensively to enhance well productivity or injectivity in low permeability formations. The use of these acids, however, is associated with severe formation damage, which is attributed to acid-oil emulsion formation and/or asphaltene precipitation in some of the low permeability carbonate reservoirs. Consequently, a detailed study of different factors that influence the mechanisms of acid-oil emulsion formation and asphaltene precipitation was carried out for these reservoirs. Several compatibility studies were conducted using representative crude samples and different acid systems, such as HCl and formic acid. The experiments were conducted at various temperatures up to 24 F using high-pressure/high temperature (HPHT) aging cells for both live and spent acid samples; some of the experiments also included anti-sludge, iron control and demulsifier chemical additives. In addition, another set of experiments was performed in the presence of ferric ions (Fe 3+ ). The total iron concentration in these experiments varied between ppm and 1, ppm. The results obtained from this study revealed that the acid systems were not compatible with several representative oil field samples. The amount of asphaltene precipitation and the stability of the emulsions created increased significantly in the presence of Fe 3+. Several wells that had already been acidized therefore showed major damage. This article discusses different tests conducted to identify, quantify and treat acid-oil emulsion formation and/or asphaltene precipitation in tight carbonate reservoirs. It also provides details of a special solvent treatment fluid recommended to revive dead wells that were damaged by acid-induced emulsion formation and asphaltene precipitation. INTRODUCTION The Lower Fadhili (LF) formation is the deepest of the Upper Jurassic limestone reservoirs in field F. Underlying two other carbonate reservoirs, the LF formation has been appraised as a relatively lower quality formation, with a reservoir quality in- dex of ~.13, a flow zone indicator of ~.73 and a net to gross ratio of ~.62. This reservoir is heterogeneous with clay-rich limestone/dolomite, having permeability in the range of 1 millidarcy (md) to 15 md and porosity ranging between 5% and 2%. Production in the LF formation is expected to be more challenging than in common reservoirs due to its low kh, a high hydrogen sulfide (H 2 S) content of ~7% and its crude oil quality. The wells in this reservoir are drilled as horizontal multilateral wells and completed as open hole completions. Several wells have been acidized using treatments based on adjacent field recipes, but acidizing in these cases resulted in complete loss of production. To discover the cause, the LF oil was tested and found to have a tendency to precipitate asphaltene. The calculated colloidal instability index (CII) for the LF oil was found to be above.9, indicating that the LF oil is unstable, and as noted, tends to precipitate asphaltenes 1. The LF formation was drilled with oil-based mud (OBM), which created an OBM cake that acted as an impermeable barrier on the formation face; the subsequent mud cake removal required acid treatment. While hydrochloric (HCl) and organic acids have been extensively used in acid stimulation treatments and acid washes to enhance well productivity or injectivity, one main potential problem associated with these acids is incompatibility issues with the reservoir's oil which appeared to be a factor with these wells. Acid-oil incompatibility causes precipitation of asphaltene particles, forming a thick sludge that can plug the formation, resulting in severe formation damage 2-4. Emulsion Formation and Asphaltene Precipitation Asphaltenes are negatively charged particles, composed mainly of condensed aromatic ring structures containing oxygen, sulfur and nitrogen atoms. Asphaltenes exist in heavy crude oil as dispersed colloidal particles that are stabilized by adsorbed resin maltene particles. Both asphaltenes and resins form stabilized micelles in heavy crude oil 2. When these stabilized micelles are disrupted by acid contact, the result is asphaltene precipitation, triggered by two main mechanisms: dissolution of resins and neutralization of asphaltenes. Following the dissolution of resins and neutralization of asphaltenes by proton ions, H +, the destabilized colloidal asphaltene particles form FALL 215 SAUDI ARAMCO JOURNAL OF TECHNOLOGY

2 large aggregates, which precipitate out of heavy crude oils and form deposits at the formation pore throats. The precipitation therefore plugs the formation and causes severe damage 5. The degree of acid-induced sludge accumulation is affected by several factors. Two main factors that can increase the degree of asphaltene precipitation are the type/strength of the acid used and the presence of contaminants, such as iron. Generally, asphaltene precipitation is relatively higher when heavy oil contacts high strength HCl acid; compared to live HCl acid, organic and spent HCl acids have less potential for causing sludge in asphaltic crudes. The presence of ferric ions (Fe 3+ ), though, can aggravate the asphaltene precipitation. It results in flocculation of asphaltene particles following their coordination with different functional groups present in heavy oil, such as phenolic hydroxyl 3, 4. Acid-oil sludge can be reduced or prevented by minimizing the acid s contact with the oil. One way to achieve this is by using a preflush ahead of the main acid stage, which acts as a barrier between the reservoir s heavy oil and the injected acid. This preflush fluid contains mainly mutual solvents, such as ethylene glycol monobutyl ether. Another cost-effective method is to add surfactants to the injected acid. The surfactant additive acts as an anti-sludging agent to prevent asphaltene precipitation 5. Another potential problem associated with acid-oil interactions is the formation of emulsions. Generally, the formation of emulsions in oil is due to the presence of polar compounds, resins, and heterocyclic compounds, such as acids, bases, phenolics, asphaltenes and high molecular weight complex compounds, which act like a surfactant. They trap droplets of water 1 µm to 2 µm in the oil phase. Volatile aromatic compounds, mono-aromatics and polycyclic aromatics in crude oils, such as benzene and ethylbenzene, dissolve asphaltenes and resins. Therefore, crude oils containing higher quantities of these volatile compounds have a lower tendency to form emulsions when they come in contact with water 6, 7. Drill-in Fluids and Mud Cake Removal Drill-in fluids (DIFs) are commonly used in drilling the pay zone of many horizontal/multilateral wells. DIF systems are typically designed by incorporating xanthan gum, starch or polyanionic cellulose with bridging agents, such as calcium carbonate (CaCO 3 ). Compared to regular mud systems, DIF systems are relatively clean and cause less formation damage to the target zone. They are designed to form a thin, impermeable mud cake on the borehole wall in permeable formations via filtration into the rock pores. The formed mud cake seals the wellbore and prevents both the fluid filtrate and the drilling solids from invading and damaging the pay zone while the well is drilled. Once drilling activities are completed, effective mud cake removal is essential to restore the well productivity or injectivity and to reduce DIF associated skin factors. Both mechanical and chemical means have been used in the field to clean up DIF mud cake. Chemical means include acids, oxidizers, chelating agents, enzymes or a combination of these chemicals, which are used to dissolve the CaCO 3 bridging materials in the mud cake. Achieving uniform mud cake removal across long horizontal sections with open hole completions using rapid reacting chemicals, such as HCl acid, is a challenging task 8. Although the use of harsh chemicals, such as HCl acid, is widespread, there are many concerns and limitations associated with their use, especially in high temperature formations since strong acids have high corrosion rates that are difficult to inhibit at high temperatures 9. In addition, their high reaction rates with CaCO 3 result in the degradation of mud cake mainly at the point of acid introduction. This promotes a rapid and localized reaction, which results in uneven removal of the mud cake, leaving the rest of the formation untreated. The main objectives of this study are to: (1) evaluate several systems for the removal of OBM mud cake, (2) explore the compatibility of LF reservoir oil with HCl acid, and (3) design an effective non-damaging acid recipe to stimulate the acidsensitive LF formation. PROCEDURE AND EXPERIMENTAL WORK Materials Representative heavy oil samples from the LF reservoir were used to conduct all the acid-oil sludge and emulsion experiments. Solutions of 2 wt% HCl acid were prepared using analytical grade 37 wt% HCl acid and distilled water with a resistivity greater than 18.cm at room temperature. The antisludge, iron control and demulsifier additives were supplied by a service company and were used as received for the sludge and emulsion tests. Preflush, surfactants and micro-emulsion chemicals were used as received for the mud cake removal tests. The surfactants were supplied by a second service company, while the micro-emulsion chemical system was supplied by a third service company. The micro-emulsion system contains solvents, surfactants and acetic acid, Table 1. A mixture of two solvents paraffin dissolver and tar dissolver surfactant and diesel was supplied by a fourth service company and was used for the sludge and emulsion removal tests. Table 2 shows the conventional asphaltene/sludge removal treatment recipe. Component Amount (vol%) Fresh Water 63 Surfactant 21 Solvent 5 Acid Corrosion Control 1 Acetic Acid 1 Table 1. Micro-emulsion recipe for mud cake removal SAUDI ARAMCO JOURNAL OF TECHNOLOGY FALL 215

3 Component Amount (vol%) Paraffin Dissolver 3 Tar Dissolver 3 Diesel 38 Surfactant 2 Table 2. Typical paraffin dissolver and tar dissolver sludge treatment X-Ray Diffraction X-ray diffraction (XRD) was performed on core samples to gain knowledge about the mineralogy of the reservoir rock. The samples were crushed to fine powder using a mill. The clay-size fractions of the sample were separated and air dried on a glass slide. The air-dried glass slide was glycolated in a desiccator containing ethylene glycol at 14 F in the oven. The identification of the crystalline phases was analyzed. Subsequent semi-quantification of XRD data was done using the Rietveld Refinement method. The clay-size material, < 2 microns equivalent spherical diameter, was separated from the larger size particles by sedimentation techniques. Environmental Scanning Electron Microscope (ESEM) Micro-structural characterizations, in terms of porosity, pore size and the presence of clay and foreign materials in the pores, are important in understanding the behavior of reservoirs. In addition, such investigations help in selecting the right acidizing treatment for the formation. In this test, the environmental scanning electron microscope (ESEM) analytical techniques were utilized with an integrated ultra-thin window energy dispersive X-ray detector to perform comprehensive micro-structural characterizations of the core samples in this reservoir. The ESEM data are used to identify the minerals in the core, any materials blocking the pore space, the type of cementing materials present and also the elemental compositions of the core plug samples. In addition, the ESEM can indicate any clay settlement close to the pore throats, which would potentially block the fluid flow pathways. The primary goal in this test was to identify the main components of the reservoir core samples and to correlate them with the XRD results to have a better understanding of the acid-rock interactions in this reservoir. Coreflood A coreflood apparatus was designed and built to simulate fluid flow in porous media in the reservoir. A positive displacement pump, equipped with a programmable controller, was used to deliver fluids at constant flow rates at variable speeds up to 2 cm 3 /min and at pressures up to 1, psi. The pump was connected to two accumulators to deliver brine or chemical solutions. Accumulators with floating pistons rated up to 3, psi and 25 F were used to store and deliver the fluids. A set of valves was used to control the injected fluid into the core sample. The core holder can accommodate a core plug with a diameter of 1½ and a length up to 3. Pressure transducers were used to measure the pressure drop across the core. A back pressure regulator was used to control the flowing pressure downstream of the core, and a second back pressure regulator was used to control the confining pressures on the core plug. A convection oven was used to provide a temperature controlled environment. A data acquisition system was used to collect data from the pressure transducers. Below are the procedures used to prepare the core for the coreflooding experiments: 1. The core samples were dried overnight at a temperature of 212 F in an oven. 2. The core samples were saturated with formation brine in a vacuum, then centrifuged to initial water saturation. 3. The core samples were loaded into the core holder, and confining pressure was applied. 4. A 6% potassium chloride brine was injected in the core to establish ~1% water saturation. 5. The base permeability to water was measured using a flow rate of 1 cm 3 /min. 6. Distilled water was then pumped to test the sensitivity to clay swelling and migration at flow rates of 2 and 4 cm 3 /min. Formation Water/Mixing Water Compatibility The high-pressure/high temperature (HPHT) aging cell was used to investigate the mixing water/formation water scaling tendency. The experiments were performed at a temperature of 24 F. The pressure was maintained at 5 psi using nitrogen gas. The duration of the water compatibility test was 24 hours. The ratios of the mixing water/formation water were 1/9, 25/75, 4/6, 5/5, 75/25 and 9/1. In addition to the lab experiments, a scale simulation was run to predict the scaling tendency of the two water types. The simulation included water compositions and reservoir properties. SARA Analysis The four SARA fractions are: (1) saturates iso- and cycloparaffins, (2) aromatics containing one or more aromatic rings, (3) resins polar substituents miscible with heptanes or pentane, and (4) asphaltenes polar substituents insoluble in an excess of heptanes or pentane. The SARA analysis is a method for characterizing heavy oil based on fractionation, where a heavy oil sample is separated into smaller quantities, or fractions, with each fraction having a different composition. Fractionation was based on the solubility of hydrocarbon components in the various solvents used in this test, with each frac- FALL 215 SAUDI ARAMCO JOURNAL OF TECHNOLOGY

4 tion consisting of a solubility class containing a range of different molecular weight species. Gravity-driven chromatographic separation (adsorption chromatography) was used to determine the fractions of the reservoir s oil 1. Gravity-driven chromatographic separation is conducted as follows: 1. Prepare the crude oil sample. 2. Use n-hexane to separate the asphaltenes. 3. Use two columns to separate the rest: An attapulgite clay-packed column adsorbs the resins. A column packed with activated silica gel separates the aromatics from the saturate fraction. 4. Use a 1:1 mixture of toluene and acetone to recover the resin fraction from the clay packing. 5. Recover the aromatics by Soxhlet extraction of the silica gel in hot toluene. 6. Calculate the amount of the volatile components lost during the process by calculating the weight difference. Acid-Oil Compatibility The HPHT aging cell was used to investigate the sludging tendency of the LF oil after it contacted both live and spent 2 wt% HCl acids. The experiments were performed at temperatures ranging from 14 F to 24 F. The pressure was maintained at 5 psi using nitrogen gas. Another set of experiments was conducted using the anti-sludge, iron control and demulsifier additives. The duration of each acid-oil sludge test varied between 2 to 24 hours. The acid-oil ratio was kept constant for all conducted tests at mixing volume ratios of 1:1. Each oil sample was filtered, using 1 µm mesh size, before and after the sludging test. For the spent acid sludging experiments, a HCl acid solution was neutralized with CaCO 3 until the ph reached 3. Another set of sludging experiments was conducted in the presence of Fe 3+. The total iron concentration in the experiments varied between ppm and 1, ppm. Several tests were conducted to determine the effect of H 2 S on the sludge/asphaltene precipitation and its stability. The H 2 S tests were conducted using a closed system loop. H 2 S was generated by reacting iron sulfide (FeS) with 1 wt% HCl acid in an erlenmeyer flask; the generated H 2 S gas was then diverted to a second flask containing live 2 wt% HCl acid and the LF oil at a 1:1 ratio with iron concentrations ranging from ppm to 1, ppm. After exposing the solution to H 2 S gas, the H 2 S was then diverted to a third flask containing cadmium sulfate (CdSO 4 ) where the H 2 S was scavenged completely into cadmium sulfide (CdS). The setup is shown in Fig. 1. The H 2 S experiments lasted 2 to 4 hours and the acid-oil was then filtered through 1 µm mesh size to determine the severity of the sludge/asphaltene. Removal of Acid-Induced Sludge The effectiveness of different mixtures of two solvents Fig. 1. H 2 S generation setup used in testing the effect of H 2 S on sludge/ asphaltene precipitation. paraffin dissolver and tar dissolver surfactant and diesel in removing the acid-induced sludging material from the LF formation was explored. The sludge/asphaltene removal experiments were performed at a temperature of 14 F and atmospheric pressure. The ratio of dissolver/sludging material was kept at 1:1 (ml:g). The duration of all conducted sludging removal experiments was 4 hours. Mud Cake Removal The mud cake removal experiments were performed using an HPHT filter press cell. A nearly 2 ml representative sample of the oil-based DIF used during LF drilling operations was introduced into the fluid loss cell. Using 3 µm ceramic disks as a medium, the filtration process was initiated by applying a differential pressure of 3 psi. This filtration process was continued at 24 F until the fluid loss reached a constant volume, indicating that a mud filter cake had been built on top of the ceramic disk. The mud filter cake was then soaked in the acid treatment for 4 hours under 24 F and 3 psi. The weight of the formed mud cake was measured before and after it was soaked in the clean out treatment acid. The recorded values were used to calculate the percentage of the cake weight lost due to its interaction with the clean out treatment acid. RESULTS AND DISCUSSION Mineralogical and Rock Analysis XRD analysis is necessary to screen the rock to eliminate any possibility of acid-sensitive clays being present, such as excess amounts of chlorite or illite. The XRD results showed that the samples consisted of carbonate minerals calcite and ankerite with minor quantities of clay minerals kaolinite, I-S and illite as well as sand quartz in some of the samples. Table 3 gives the chemical compounds of these minerals and others common in the oil industry. Table 4 shows the bulk mineralogical composition of several core plugs from this reservoir. The data indicated that calcite was the most domi- SAUDI ARAMCO JOURNAL OF TECHNOLOGY FALL 215

5 Calcite Ankerite Dolomite Illite Kaolinite Quartz Pyrite CaCO3 Ca(Fe,Mg,Mn) (CO3)2 CaMg(CO3)2 (K,H3O)(Al,Mg,Fe)2 (Si,Al)4O1[(OH)2,(H2O)] Al2Si2O5(OH)4 SiO4 FeS2 Table 3. Chemical composition of minerals in the formation samples Plug Calcite Ankerite Illite + IS Kaolinite Quartz Grain Density # wt% wt% wt% wt% wt% g/cm Table 4. XRD results T nant mineral in the samples, with wt% ranges between 7% to 98%. The second dominant mineral was dolomite, with 1 wt% to 16 wt%. Clay minerals, including total clays of mixed layers of illite-smectite, illite and kaolinite, were also detected in the same samples, reaching up to 14 wt% in the extreme case. Some core samples did not have any clay in them. Figure 2 contains the ESEM images confirming the presence of CaCO3, mainly in the reservoir core sample. In addition, Fig. 2 shows that the pore throats are clay free in the reservoir core sample. Multiple solubility tests were conducted following the XRD analysis to confirm the abundant presence of CaCO3, Fig. 3. cm3/min for 9 pore volumes at each rate. The pressure drop was measured between the inlet and the outlet of the core sample. The pressure drop showed no change while pumping distilled water at 2 cm3/min. The rate was increased to 4 cm3/ min, and the pressure drop still did not show any significant spikes or changes. This indicated that the clays in the core Clay Swelling and Migration Coreflood tests were run several times to test the sensitivity of the samples to clay swelling and migration. Figure 4 shows the coreflood graphs. The core was first flooded with a temporary salt clay stabilizer to determine a base permeability. The core was then flooded with distilled water at 2 cm3/min and 4 Fig. 3. Solubility test result indicating a high amount of CaCO3 in the reservoir core sample. Fig. 2. ESEM analysis confirming the presence of CaCO3 mainly in the reservoir, with the pore throats being clay free. FALL 215 SAUDI ARAMCO JOURNAL OF TECHNOLOGY Fig. 4. Coreflood results indicating no damaging effects from clay swelling and migration.

6 Parameter Ca Mg Cl Fe K Na Sr SO 4 Mixing water Formation water 37, 6,7 122,5 3 1, 34, 1,4 48 Table 5. Comparison between mixing water and formation water samples didn t have major swelling or migrating effects that would hinder the flow of hydrocarbons. asphaltenes are unstable, while.7 < CII <.9 indicates a potential asphaltene problem. CII <.7 indicates that the Scale Analysis Scale formation in the reservoir rock could block the pores and hydrocarbon pathways, which hinders the flow of hydrocarbons to the wellbore. Water compatibility is a factor in scale formation, between the mixing water used to mix the acid system and the formation water encountered while pumping the acid treatment. This makes it very critical to test both water compositions for scaling compatibility. Table 5 shows the comparison between the mixing water and formation water. Simulation runs were performed to determine the critical mixing ratios at which scale could occur; Figure 5 shows the results. The simulation indicated some minor scale precipitation, but the amount of scale precipitation was below the threshold of scale quantities that would hinder the flow of hydrocarbons to the wellbore. To confirm this, seven samples were tested for compatibility in the lab at different ratios of mixing water/formation water 1/9, 25/75, 4/6, 5/5, 75/25 and 9/1. The samples were prepared and kept in a convection oven for 24 hours at reservoir temperature. The compatibility results indicated no scale precipitation issues between the mixing water and formation water, Fig. 6. SARA Analysis SARA analysis was conducted on the crude oil to determine the amount of saturates, aromatics, resins and asphaltene in the oil. Several coefficients can be calculated to determine if the oil is problematic in terms of asphaltene/sludge precipitation. One of the most common misconceptions in diagnosing asphaltene problems is that calculating the resin to asphaltene ratio is enough, basing the diagnosis solely on this number. This method is not very accurate because many other factors besides resin content contribute to the stability of asphaltenes in crude oil. One coefficient was found to be very helpful in taking many components of the oil into consideration prior to determining the asphaltene stability. Equation 1 is the coefficient of the CII: (1) High resin and aromatic content help keep the asphaltene stabilized in the oil, preventing it from precipitating out and so hindering the oil flow. High saturates content, in contrast, destabilizes the asphaltene. CII >.9 indicates that the Fig. 5. Mixing water/formation water simulation results indicate very minimal scale with no issues of hindering the flow of hydrocarbons. SAUDI ARAMCO JOURNAL OF TECHNOLOGY FALL 215

7 Fig. 6. Mixing water/formation water compatibility tests 1 through 7 at 1/9, 25/75, 4/6, 5/5, 6/4, 75/25 and 9/1 ratios, respectively, indicating no scaling issues. Saturates Aromatics Resins Asphaltenes CII Table 6. SARA analysis T asphaltenes are stable in the oil11. The CII calculated for the LF oil is 1.6, which indicates problematic oil in terms of sludge/asphaltene precipitation. Table 6 shows the SARA analysis results and CII calculation. performed in the presence of Fe3+ at 24 F for 24 hours. Figure 8 also depicts the amount of sludge/asphaltene precipitation after LF oil was mixed with live and spent 2 wt% HCl acid as a function of Fe3+ concentration. The amount of sludge/asphaltene precipitation in the acid-oil mixture clearly increased in the presence of iron. For example, in the 1/1 ml mixture of LF oil/live 2 wt% HCl acid, the amount of sludging material increased from 6 g to 8 g when the Fe3+ concentration was increased from ppm to 1, ppm. Similarly, the amount of sludge in the LF oil/spent 2 wt% HCl acid mixture increased from 8.5 g to 12.5 g when the iron concentration was increased from ppm to 1, ppm. In addition to sludge/asphaltene precipitation, it was found that the LF oil formed a stable emulsion when it was mixed with 2 wt% HCl acid. The stability of this emulsion mainly depended on the ph of the acid solution, the presence of Fe3+ and time. Figures 9 and 1 show the percentage of acid separated from the LF oil and acid emulsion as a function of time and Fe3+ concentration for both live and spent 2 wt% HCl acid, respectively, at 14 F and 24 hours. The maximum percentage of separated acid for both live and spent 2 wt% HCl acid Acid-Oil Compatibility Several compatibility experiments were performed to assess the LF oil tendency to form a sludge or emulsion due to its mixing with live and spent 2 wt% HCl acid. The experiments were conducted using a 1:1 acid-oil mixing ratio at 24 F and 5 psi for 24 hours. Filtering using 1 µm mesh size revealed heavy sludge/asphaltene precipitation when the LF oil was in contact with both live and spent 2 wt% HCl acid, Fig. 7. The amount of sludge material was more in the mixture with spent HCl acid; for example, nearly 6 g and 8.5 g of sludge material precipitated out of 1 ml of the LF oil when it was mixed with 1 ml of live and spent 2 wt% HCl acid, respectively, Fig. 8 (far left). Another set of LF acid-oil compatibility experiments was Fig. 7. Asphaltenes/sludge precipitation after mixing LF oil with both live and spent 2 wt% HCl acid at 24 ºF for 24 hours. FALL 215 SAUDI ARAMCO JOURNAL OF TECHNOLOGY Fig. 8. Amount of sludge/asphaltene after mixing LF oil with live (white bar) and spent (black bar) 2 wt% HCl acid as a function of Fe3+ concentration at 24 ºF for 24 hours. Fig. 9. Percentage of acid phase separated out of LF oil/live 2 wt% HCl acid emulsion at 1:1 mixing ratio and 14 ºF.

8 Fig. 1. Percentage of acid phase separated out of LF oil/spent 2 wt% HCl acid emulsion at 1:1 mixing ratio and 14 ºF. reached only 4% of the present acid amount in the LF oil and HCl acid emulsion. Compared to live 2 wt% HCl acid, the LF oil formed a more stable emulsion with spent 2 wt% HCl acid. The maximum percentage of separated acid was reached after nearly one hour for the spent 2 wt% HCl acid/lf oil emulsion compared to only 1 minutes for the live 2 wt% HCl acid/lf oil emulsion. In addition to the ph value of the acid solution, it was found that the presence of Fe3+ stabilized the LF acid-oil emulsion. The presence of Fe3+ up to 1, ppm had no effect on the stability of the LF oil/spent 2 wt% HCl acid emulsion. For example, the percentage of acid separated from the spent 2 wt% HCl acid/lf oil emulsion after nearly one hour remained constant when the Fe3+ amount was increased from ppm to 1, ppm. In contrast, the presence of Fe3+ had a significant impact on the stability of the LF oil emulsion with live 2 wt% HCl acid. The percentage of acid phase separated from that acid-oil emulsion dropped from 4% to ppm when the Fe3+ concentration increased from ppm to 5 ppm. Furthermore, several H2S experiment results indicated that a H2S and iron combination stabilized the sludge/asphaltene. Figure 11 shows the result of filtering the acid and oil after exposing it to 1, ppm iron and low concentrations of H2S for 4 hours. The majority of the fluid failed to pass through the 1 µm mesh size, which indicated that the sludge thickness became more severe due to the combined effect of the H2S and iron on the sludge/asphaltene. It is evident from the above results that the LF oil forms sludging material and a stable acid emulsion when it is in contact with 2 wt% HCl acid, especially in the presence of Fe3+. Therefore, demulsifier, anti-sludge and iron control acid additives were used in further tests. Citric acid, an iron control agent, was used at 2 lb/gal to chelate nearly 2,5 ppm of Fe3+. The concentrations of both demulsifier and anti-sludge agents were varied until no sludge/emulsion occurred when 2 wt% HCl acid was mixed with the LF oil. Figures 12 and 13 show that adding demulsifier agent at 5 gpt, anti-sludge agent Fig. 11. Oil was run through 1 μm mesh size, then the acid-oil sludge mix that was generated in the presence of H2S and 1, ppm iron was poured on the mesh, following that, hot water was poured on the mesh, and the remaining material is thick sludge precipitation. Fig. 12. Effect of adding different concentrations of demulsifier agent to the acidoil mix ( gpt to 15 gpt). at 5 gpt and iron control agent at 2 lb/gal was effective in preventing sludge precipitation and emulsion formation when the LF oil was mixed with 2 wt% HCl acid at a 1:1 ratio and at 14 F. Asphaltene/Sludge Removal As mentioned, several LF wells had been previously stimulated with HCl acid without demulsifier and anti-sludge additives. The wells ceased to flow after the stimulation treatments. SAUDI ARAMCO JOURNAL OF TECHNOLOGY FALL 215

9 Fig. 15. Solubility of LF acid-oil sludge in different solvent recipes at a 1:1 solid:liquid ratio for 4 hours. Fig. 13. HCl acid (2 wt%)/lf oil mixture at 1:1 ratio and 14 ºF for 24 hours: (a) without additives, and (b) with demulsifier, anti-sludge and iron control agents. Results indicated the high likelihood that the stimulated wells had been damaged with asphaltene/sludge precipitation due to the incompatibility of HCl acid and LF oil. Therefore, several solvent formulations were tested to find the most effective aphaltene/sludge removal recipe. Initially, a neat paraffin dissolver solvent was used to dissolve asphaltene/sludge laboratory samples formed by mixing LF oil with live 2 wt% HCl acid. This solvent was not effective as it only dissolved 2% of the sludging material after 4 hours at a 1:1 solid:liquid ratio and 14 F, Fig. 14. Further tests explored the effectiveness of several recipes of two solvents paraffin and tar dissolver surfactant and diesel in terms of removal efficiency and cost effectiveness, Figs. 15 and 16, and Table 7. It was found that paraffin dissolver/surfactant/diesel at a volume percentage of 3/2/68, respectively, is the most economical and effective recipe to remove the acid-induced sludge of LF oil. It removed more than 9% of the LF sludge after a soaking time of 4 hours at 24 F, Fig. 17. Mud Cake Removal Treatment Table 8 shows the DIF mud recipe used to drill the pay zone. To effectively remove the generated OBM cake, different Fig. 16. Paraffin dissolver/tar dissolver/surfactant/diesel combinations of (a) 3/3/2/38, (b) 3/2/2/48, and (c) 3/1/2/58 at a ratio of 1:1 at 14 F for 4 hours. Fig. 14. Paraffin dissolver treatment of LF oil sludging material at a 1:1 liquid:solid ratio at 14 ºF for 4 hours. FALL 215 SAUDI ARAMCO JOURNAL OF TECHNOLOGY removal recipes were investigated, Table 9. Two recipes, 1 and 2, consisted of a two-stage treatment: (1) mutual solvent/surfactant, and (2) acetic acid. The first stage utilizes surfactant to alter the wettability of the mud cake to water-wet, which enables the second stage, the use of acetic acid to dissolve the mud cake bridging material, or CaCO3 particles. For the test of recipe 1, an OBM cake weighing 9 g initially

10 Recipe Concentration, vol% Paraffin Dissolver/Tar Dissolver/ Cost ($/bbl) Surfactant/Diesel 1 3/3/2/38 1,55 2 9//2/ /1/2/ //2/ Table 7. Different recipes used to dissolve acid-oil sludge service company, was not effective in dissolving the LF OBM cake. After soaking for 4 hours at 24 F in 2 ml of mutual solvent and surfactant-2 each at 1 vol%, there was no weight loss in the OBM cake. This was followed with the same 1 wt% acetic acid treatment for 4 hours. This stage 2 was also not effective, indicating that the CaCO 3 particles in the mud cake were still covered with oil, Fig. 19. After tests of these different two-stage treatments, a single-stage OBM cake removal was investigated. The micro-emulsion system, supplied by a service company, used in the test consists of fresh water, a surfactant, a solvent and an acid corrosion control, Table 9. It was found that this micro-emulsion treatment was capable of dissolving the organic layer and treating the CaCO 3 weighting Fig. 17. Paraffin dissolver/surfactant/diesel effect on LF oil sludging material at a ratio of 1:1 liquid:solid at 24 ºF for 4 hours. was soaked for 4 hours at 24 F in 2 ml of mutual solvent and surfactant-1 at 1 vol% and 3 gpt, respectively. The mud cake was then soaked in 2 ml of 1 wt% acetic acid solution for 4 hours at 24 F. It was observed that the stage 1 treatment had no effect on the mud cake, while the acetic acid during stage 2 removed only 27% of the mud cake, Fig. 18. Similarly, recipe 2, using a surfactant supplied by the same Recipe Components Removal Efficiency (wt%) Stage 1: Mutual Solvent (1 vol%), Surfactant-1 (3 gpt) Stage 2: Acetic Acid (1 wt%) 27 Stage 1: Mutual Solvent (1 vol%), Surfactant-2 (1 vol%) Stage 2: Acetic Acid (1 wt%) Micro-emulsion System: Fresh Water 63% Surfactant 21% Solvent 5% Acid Corrosion Control 1% Table 9. Efficiency of OBM cake removal recipes efficiency > 95 Component Initial Fresh Mud Properties Average Properties Base Oil (bbl).76/.6 Density (pcf) Primary Emulsifier (gal).75 1 Plastic Viscosity (cp) 16 2 < 35 Alkalinity Source (lb) 8 Yield Point (lb/1 ft 2 ) Organophilic Lignite (lb) RPM Readings Fresh Water (bbl).13/.25 Gels, 1 sec (lb/1 ft 2 ) Organophilic Clay (lb) 6 8 Gels, 1 min (lb/1 ft 2 ) Low Shear Rheology Modifier (ppb) 2 3 Gels, 3 min, lb/1 ft Secondary Emulsifier (gal) 1.5 FL HPHT 25 F (ml/3 min) 4 6 < 4 CaCl 2 (78%) (lb) 25 Electrical Stability (volts) 25 > 6 CaCO 3 Fine (lb) 8/15 Chlorides 195, 19, 2, CaCO 3 Medium (lb) 7/15 Wetting Agent (gal) 1 2 Table 8. OBM used to drill formation SAUDI ARAMCO JOURNAL OF TECHNOLOGY FALL 215

11 Fig. 18. LF OBM cake treated with recipe 1, (mutual solvent/surfactant #1 followed by 1 wt% acetic acid) at 24 ºF for 4 hours: mud cake (a) before treatment, (b) after treatment with 1 vol% mutual solvent and 3 gpt surfactant #1, and (c) after treatment with 1 wt% acetic acid. be 15 gallons per foot (gpf) this includes the regular HCl acid and the diversion acid. Preflush and post-flush are inert fluids used for formation conditioning. A spacer before the acid stage should be pumped to displace the completion fluid away from the wellbore. Preflush and post-flush can be waterbased or diesel-based depending on several factors, such as the reservoir pressure. In addition, a mutual solvent and surfactant should be added to the preflush and post-flush. The preflush should be at least one-third of the main treatment acid volume, or 5 gpf, and the post-flush volume should be enough to displace all acids away from the wellbore. The use of any necessary chemical additives, such as the H 2 S scavenger, anti-sludge agent, demulsifiers, iron control, corrosion inhibitor, surfactants, diversion fluids or foams, should be evaluated on a well-by-well basis. Chemical QA/QC Fig. 19. LF OBM cake treated with recipe 2, (mutual solvent/surfactant #2 followed by 1 wt% acetic acid) at 24 ºF for 4 hours: mud cake (a) before treatment, (b) after treatment with mutual solvent and surfactant #2 each at 1 vol%, and (c) after treatment with 1 wt% acetic acid. material with acid all in one stage. When a 9 g OBM cake was soaked in 2 ml of this system, it removed nearly 95% of the LF OBM cake after 4 hours soaking time at 24 F, Fig. 2. FIELD QUALITY ASSURANCE/QUALITY CONTROL Many factors must be considered to achieve a successful stimulation treatment. Planning the recipe and testing the chemicals are important. But having a clean, smooth operation application is the real key to a successful treatment. To achieve this, several procedures must be followed, known as the quality assurance/quality control (QA/QC) procedures. Each stage or chemical has its own procedure that operators must follow to check quality and performance. Operational QA/QC is divided into several parts and discussed next. Recipe General Guidelines For matrix acidizing, the total treatment acid volume should HCl acid concentration: A titration test must be conducted to determine the acid wt%. Emulsified acid: A conductivity test or a drop test in water must be completed. Iron concentration: Tests of the acid should ensure iron is less than 1 ppm as excess iron will initiate severe sludge or emulsion formation. Sulfate concentration: Tests should ensure the suflate is less than 1 ppm, as excess sulfate will form insoluble CaSO 4 scale in the spent acid. Equipment: All mixing and transporting tanks should be clean, flushed and corrosion free. Acid Flow Back Tests To calculate ph and determine the optimum soaking time. To analyze the reaction products and determine the effectiveness of the acid concentrations. To analyze the cations, including iron content, to determine the proper loading of iron control. To look for the presence of emulsions; if the emulsion did not break, tests are needed to see if higher concentrations of demulsifier are required. Fig. 2. LF OBM cake treated with recipe 3, (micro-emulsion) at 24 ºF for 4 hours: mud cake (a) before treatment, and (b) after treatment with micro-emulsion system. The above guidelines were followed and the necessary tests were conducted on the wells where the new acid recipe and removal treatment were applied. Many chemical mixes were not up to standards and had to be remixed. The mixing water was often contaminated. In addition, emulsified acid quality was a major issue due to the low emulsifier concentration and the inadequate cleanliness of the diesel tanks, Figs. 21 and 22. Once these quality issues were addressed, the results were very

12 niques were explored to prevent and treat the HCl acid-induced emulsion and asphaltene precipitation. Additionally, several removal systems for the LF OBM cake were evaluated. Based on this study, the following conclusions were drawn: LF oil was found to be incompatible with both live and spent 2 wt% HCl acid. It formed stable emulsion and asphaltene/sludge at 24 F. The presence of iron aggravates the HCl-induced emulsion and asphaltene precipitation. A significant impact of the iron presence was observed in live 2 wt% HCl acid. The formation of asphaltene/sludge can be prevented by using anti-sludge, demulsifier and iron control agents at concentrations of 5 gpt, 5 gpt and 2 lb/gal, respectively. Fig. 21. Samples taken while mixing: (a) Quality of the diesel and emulsifier portion of the emulsified acid was monitored and the portion was remixed until the fluid was cleaner, (b) First failed emulsified acid mix, (c) On-site tests to increase the emulsifier concentration, and (d) Emulsified acid passed drop test after adjustments and remixing. The formed asphaltene/sludge was found to be soluble in a mixture of two solvents paraffin dissolver and tar dissolver surfactant and diesel. Nearly 9% of the LF asphaltene/sludge was dissolved in a mixture of 3% paraffin dissolver, 2% surfactant and 68% diesel after 4 hours at 24 F. A micro-emulsion system was found to be effective in removing the LF OBM cake. More than 95% of the mud cake was dissolved after soaking for 4 hours at 24 F. Fig. 22. Mixing water was sampled in each stage and remixed when the quality did not meet standards. A field operation was successful and resulted in a water injector injectivity increase of 5% and an oil producer PI increase of 2%. ACKNOWLEDGMENTS Well Type PI/Injectivity Increase 1 Injector 5% 2 Producer 2% Table 1. Field treatments after adjusting recipe T The authors would like to thank the management of Saudi Aramco for their support and permission to publish this article. This article was presented at the SPE Annual Technical Symposium and Exhibition, al-khobar, Saudi Arabia, April 2123, 215. successful due to the collaboration between the lab and field engineers. A power injector well drilled in the LF reservoir showed an injectivity increase of around 5% after undergoing a stimulation treatment with the new recipe. An oil producer achieved a productivity index (PI) increase of 2% after the new recipe adjustments and guidelines were applied, Table 1. REFERENCES CONCLUSIONS 2. Moore, E.W., Crowe, C.W. and Hendrickson, A.R.: Formation, Effect and Prevention of Asphaltene Sludges during Stimulation Treatments, Journal of Petroleum Technology, Vol. 17, No. 9, September 1965, pp The compatibility of LF oil with HCl acid was extensively investigated at different conditions. It was evaluated as a function of the ph value of the acid solution, the presence of iron and well temperature. Several experiments and different tech- 1. de Boer, R.B., Leerlooyer, K., Eigner, M.R.P. and van Bergen, A.R.D.: Screening of Crude Oils for Asphalt Precipitation: Theory, Practice, and the Selection of Inhibitors, SPE Production & Facilities, Vol. 1, No. 1, February 1995, pp Houchin, L.R., Dunlap, D.D., Arnold, B.D. and Domke,

13 K.M.: The Occurrence and Control of Acid-Induced Asphaltene Sludge, SPE paper 1941, presented at the SPE Formation Damage Control Symposium, Lafayette, Louisiana, February 22-23, Barker, K.M. and Newberry, M.E.: Inhibition and Removal of Low-pH Fluid-Induced Asphaltic Sludge Fouling of Formations in Oil and Gas Wells, SPE paper 12738, presented at the International Symposium on Oil Field Chemistry, Houston, Texas, February 28 - March 2, Strassner, J.E.: Effect of ph on Interfacial Films and Stability of Crude Oil-Water Emulsions, Journal of Petroleum Technology, Vol. 2, No. 3, March 1968, pp Bobra, M.A.: A Study of the Formation of Water-in-Oil Emulsions, Proceedings of the 13 th Arctic and Marine Oil Spill Program Technical Seminar, Edmonton, Alberta, Canada, June 6-8, 199, 485 p. 7. Fingas, M.F., Fieldhouse, B., Bobra, M.A. and Tennyson, E.J.: The Physics and Chemistry of Emulsions, Proceedings of the Workshop on Emulsions, Marine Spill Response Corporation, Washington, D.C., 1993, 11 p. 8. Mason, S.D., et al.: e-methodology for Selection of Wellbore Cleanup Techniques in Open Hole Horizontal Completions, SPE paper 68957, presented at the SPE European Formation Damage Conference, The Hague, The Netherlands, May 21-22, Crowe, C.W., McGowan, G.R. and Baranet, S.E.: Investigation of Retarded Acids Provides Better Understanding of Their Effectiveness and Potential Benefits, SPE Production Engineering, Vol. 5, No. 2, May 199, pp Fan, T., Wang, J. and Buckley, J.: Evaluating Crude Oils by SARA Analysis, SPE paper 75228, presented at the SPE/DOE Improved Oil Recovery Symposium, Tulsa, Oklahoma, April 13-17, Yen, A., Yin, Y.R. and Asomaning, S.: Evaluating Asphaltene Inhibitors: Laboratory Tests and Field Studies, SPE paper 65376, presented at the SPE International Symposium on Oil Field Chemistry, Houston, Texas, February 13-16, 21. BIOGRAPHIES Tariq A. Al-Mubarak is a Petroleum Engineer with the Formation Damage and Stimulation Unit of Saudi Aramco s Exploration and Petroleum Engineering Center Advanced Research Center (EXPEC ARC). Prior to joining this unit, his experience included work with Saudi Aramco s Gas Reservoir Management Department, Schlumberger s field engineering/research lab in Louisiana and the undergraduate research summer program at Texas A&M University. During these years, Tariq participated in many projects that included gas field management, matrix acidizing, damage removal, acid fracturing and hydraulic fracturing along with attending many stimulation field QA/QC jobs. He is an active member of the Society of Petroleum Engineers (SPE) and strongly advocates for young professionals to shape the future of the oil and gas industry. Tariq has published 1 SPE papers and filed one U.S. patent. In 213 and 214, he received the SPE Best Technical Paper award, winning first place in both the 3 rd and 4 th SPE-SAS technical paper contests. Tariq received his B.S. degree with honors in Petroleum Engineering from Texas A&M University, College Station, TX. Dr. Mohammed H. Al-Khaldi joined Saudi Aramco in 21 as a Research Engineer working in Saudi Aramco s Exploration and Petroleum Engineering Center Advanced Research Center (EXPEC ARC). Since this time, he has been responsible for evaluating different stimulation treatments, conducting several research studies and investigating several stimulation fluids. In addition, Mohammed was involved in the design of acid fracturing treatments. As an award for his efforts, he received the Vice President s Recognition Award for significant contributions to the safe and successful completion of the first 1 fracturing treatments. Mohammed s research interests include well stimulation, formation damage mitigation and conformance control. He is an active member of the Society of Petroleum Engineers (SPE). Mohammed has published more than 15 SPE papers and seven journal articles, and has two patents. In 211, he received the SPE Best Technical Paper Award, winning first place in the 2 nd GCC SPE paper contest. He received his B.S. degree in Chemical Engineering (with First Class Honors) from King Fahd University of Petroleum and Minerals (KFUPM), Dhahran, Saudi Arabia. Mohammed also received his M.S. and Ph.D. degrees in Petroleum Engineering (with First Class Honors) from Adelaide University, Adelaide, Australia. FALL 215 SAUDI ARAMCO JOURNAL OF TECHNOLOGY

14 Hussain A. Al-Ibrahim is a Petroleum Engineer with the Formation Damage and Stimulation Unit of Saudi Aramco s Exploration and Petroleum Engineering Center Advanced Research Center (EXPEC ARC). He is passionate about projects related to drill-in fluid evaluation and filter cake removal evaluation, such as evaluating different acid precursors, chelating agents, micro-emulsion fluids and organic acids. Hussain has also worked in the area of evaluating different treatments for condensate banking problems, asphaltene deposition and scaling potential. He has been an active part for the last 7 years of a team that promotes behavioral based safety. Hussain has also trained many young professionals and technicians on using various pieces of equipment and conducting different formation damage-related experiments. He also coauthored four Society of Petroleum Engineers (SPE) papers. Hussain received his B.S. degree in Petroleum Engineering from King Fahd University of Petroleum and Minerals (KFUPM), Dhahran, Saudi Arabia, and is currently pursuing an M.S. degree in the same field. Omar Al-Dajani is a Petroleum Engineer with the Drilling Technology team of Saudi Aramco s Exploration and Petroleum Engineering Center Advanced Research Center (EXPEC ARC). Upon joining Saudi Aramco, he started rotating assignments with the Offshore Drilling Department where he worked as a Drilling Engineer, writing several oil and gas well drilling programs as well as witnessing critical jobs in the field. Omar also worked as a full-time Tool Pusher in the field, overseeing the safe execution of drilling programs. His next assignment was with the Northern Area Production Engineering and Well Services Department as a Production Engineer assigned to the AFK Production Engineering Unit, where he ensured the target rate and API blend were safely and properly met. Omar received his B.S. degree with honors in Petroleum Engineering, with a minor in Geology, from Texas A&M University, College Station, TX. Currently, he is pursuing his M.S. degree in Geotechnical Engineering and Geomechanics at MIT, Cambridge, MA. Majid M. Rafie is a Field Production Engineer in Saudi Aramco s Southern Area Production Engineering Department. Before he joined Saudi Aramco, his experience included working with Baker Hughes in Houston, TX, as a Field Engineer for unconventional wells. Majid enjoys working on artificial lift techniques, such as electrical submersible pumps. He also is interested in the areas of multistage acid fracturing and matrix acidizing. Majid participates in many Society of Petroleum Engineers (SPE) events and has published three SPE papers. He received his B.S. degree in Petroleum Engineering from Texas A&M University, College Station, TX. SAUDI ARAMCO JOURNAL OF TECHNOLOGY FALL 215