This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Denver, Colorado, USA, August 2014.

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1 URTeC: Examining Innovative Techniques For Matrix Acidizing In Tight Carbonate Formations To Minimize Damage To Equipment And Environment Fred Markey 1, Tyler Betz 1, Jarand Gauteplass 2, Kyle Taylor 3, Daniel Ackwith 3, and Reza Barati 1* 1) Department of Chemical and Petroleum Engineering, University of Kansas, Lawrence, KS; 2) University of Bergen, Norway; 3) Earthborn Clean Products, Colby, Kansas Copyright 2014, Unconventional Resources Technology Conference (URTeC) DOI /urtec This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Denver, Colorado, USA, August The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitt ed by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper without the written consent of URTeC is prohibited. Abstract Well acidizing is one of the most common practices in the oil industry that has been used traditionally for wellbore cleanup, matrix acidizing, and acid fracturing. Hydrochloric acid (HCl) has been used as the main acid for limestone stimulation purposes. There are several concerns with the use of HCl acids: health and safety of the field crew, corrosive nature of the acids for the flow lines and equipment, and environmental effects of the produced HCl. Moreover, fast reaction times and consumption rates of HCl make it a less favorable option for the stimulation of long wells with long or multiple stages of fractures. FF-01 is an environmentally-friendly and equipment-friendly product. It is a conversion to an organic base to maintain very low ph as a vehicle for aggressiveness, along with the creation of buffers and surface tension relievers. Low ph, slower reaction rates with limestone, small amount of residue after reaction, safety, minimum damage to equipment, and longevity are the properties of this product. The main objective of this study is to validate the application of the environmentally-friendly and equipment-friendly FF-01 product for stimulation and matrix treatment of carbonate formations and compare the performance of this product with 15% HCl. Beaker, rheology, and core-flooding tests have been conducted to develop this new product and study possible improvements in this blend. It was observed, using inductively coupled plasma atomic emission spectroscopy (ICP- AES), that FF-01 dissolves limestone rock samples with smaller reaction constants compared to HCl. However, it will dissolve the same mass of rock if enough time is given, and it lasts longer during the course of reaction while leaving fewer residues. Core floods using HCl and FF-01 were performed at temperatures of 25 C and 40 C. Wormhole paths were observed using CT scan imaging. The results showed that core surface was strongly dissolved for the HCl treated cores, but wormholes were not deeply extended into the core. On the other hand, core surface was mildly dissolved for the FF-01 treated cores, but wormholes were deeply extended into the core. HCl performs better in cleaning the near wellbore rock while FF-01 performs better in generating long wormholes and higher effective permeability compared to the cores that were treated using HCl. FF-01 was able to increase permeability in limestone core samples by up to 795 times. Introduction

2 URTeC: Matrix acidizing is a practice that dates back as far as 1895 when the Ohio Oil Company used HCl to treat limestone formations [2]. The goal of matrix acidizing is to improve well performance by either removing or bypassing damage from drilling, workover, or completion processes. In carbonate reservoirs, an HCl solution is almost always used to remove formation damage. However, HF is the only common, inexpensive acid available for dissolving siliceous minerals. Therefore, a combination of HF and HCl is often used to remove damage from sandstone formations [6]. The two low ph chemicals that were examined in this study are HCl and FF-01. HCl is commonly used for acidizing applications, but it has its disadvantages. HCl has a relatively fast reaction rate with limestone, especially at high temperatures. This fast reaction rate causes the acid to spend quickly, which could prevent the acid from propagating through the damaged zone. Moreover, fast reaction times make HCl a less favorable option when it comes to long injection wells and wells with long or multiple stages of fractures [1, 7, 10]. There are also a number of safety hazards associated with the use of HCl: difficult to handle safely, corrosive to equipment, and the need to be neutralized when returned to the surface [2]. Cleaning up formation damage, or bypassing it altogether, is the goal of acidizing treatments. In the matrix acidizing process, acid is injected at a pressure below the fracture pressure of the formation in order to generate a wormhole structure. By generating a wormhole structure through the formation, the damage can be bypassed. A wormhole is a highly conductive flow channel that is formed by the reaction of the acid with a carbonate porous media. During injection of acid, the regions of highest permeability or higher reaction rate start to generate initial flow paths that are enlarged by rapid dissolution of the matrix material. A dominant channel forms and continues to propagate while diverting flow from other regions [8]. There are many types of alternatives to HCl that are used in the oil and gas industry today. Acetic Acid and Formic Acid have been used for many years as alternatives, or additives, to HCl in matrix acidizing. Acetic and formic acid have slower reaction rates, which allows the acid to propagate further into the reservoir [9]. However, the rate of reaction is so slow that acetic acid by itself is not capable of generating enough wormholes [13]. Dissolvers like chelating agents have also been used as an additive to HCl. One chelating agent that was explored for the stimulation of carbonate formations is a polyacid called GLDA chelate. As an additive to HCl, GLDA is effective in preventing the precipitation of Fe in spent acids. GLDA is also less corrosive and more environmentally friendly than HCl. The downfall to GLDA, and other chelating agents, is that chelate solutions provide significantly lower calcite dissolving capacity than acids. This makes this option less economical than using HCl alone [11]. Another chelating agent that was examined in 2011 is a novel polyacid chelate (NPC). The chelate-based fluid effectively dissolves calcium carbonate, yet has a low corrosion potential and is easy to apply. The same issue comes up with NPC as seen in other chelating agents. There is a significantly lower calcite dissolving capacity for NPC than for HCl. This means that higher volumes of NPC will be needed to generate the desired stimulation compared to HCl, which makes this option less economically viable [12]. Many of the experiments that will be outlined in this paper are matrix acidizing experiments using FF-01. FF-01 is an environmentally-friendly and equipment-friendly product of Earthborn Clean Products located in Colby, Kansas. FF-01 is a conversion to an organic base to maintain very low ph (0 to 2) as a vehicle for aggressiveness, along with the creation of buffers and surface tension relievers for effectiveness and safety. Low ph, linear reaction with limestone, small amount of residue after reaction, and longevity are the claimed properties of this product. This product and similar products by the Earthborn Clean Products have been bench tested and reacted successfully with limestone samples. This product was considered in this project to be used as an environmentally-friendly, equipment-friendly, and non-hazardous reservoir stimulation product for production and injection wells [1]. The unconventional tight zone of the Mississippian Limestone Play (MLP) is a good candidate for acid treatments. The MLP has become an important source of income for both Kansas and Oklahoma states [3]. Hundreds of horizontal wells have been drilled and completed and millions of dollars of extra income are expected for the state of Kansas [5]. Acidizing of oil wells using HCl with the purpose of increasing their productivity is a very common practice. Specifically, HCl is used in the application of acid washing, matrix acidizing, and acid fracturing. The

3 URTeC: purpose of these HCl acid treatments is to clean the wellbore, clean the near wellbore matrix, clean the near fracture matrix, or propagate fractures. In addition to the MLP, the Lansing Kansas City limestone formation has also been a major target of acid treatments. Considering the millions of barrels of fluids that are being used for fracturing, acid fracturing, matrix acidizing, and wellbore cleanup, use of a more environmentally and equipment friendly product such as FF-01 will both save money on equipment and prevent the exposure of the acidizing crew and surface environment to HCl. The main objective of this study is to validate the application of the environmentally-friendly and equipmentfriendly FF-01 product for stimulation of both high permeability and low permeability limestone formations and compare the performance of this product with 15% HCl. Moreover, application of this new product for matrix acidizing of chalk formations is studied. Materials and Methods Materials The following chemicals and rock samples were used as supplied: FF-01 ( Earthborn Clean Products, Colby, Kansas), Hydrochloride acid (HCl, Fisher Scientific, Pittsburgh, PA, Lot ), potassium chloride (KCl, AMRESCO, Solon, OH, Lot #0833C056), Indiana limestone core plugs from the same block (Kocurek Industries, Caldwell, TX). Methods Preparation of 2% KCl Brine: 20 grams of KCl was added to 980mL of D.I./R.O. water and stirred at 450rpm for 30 minutes. Indiana Limestone core plugs: 3in. long 1.5in. diameter core plugs of low and high permeability were used for matrix acidizing experiments. 1 in. 1in. 1.5in. cubical samples of rock were used for beaker tests. Austin Chalk core plugs: 3in. long 1.5in. diameter core plugs were used for matrix acidizing experiments. Rheological Testing Procedure: A 5mL sample of FF-01 was added to an Anton Parr rheometer in order to measure viscosity versus shear rate at temperatures of 25, 40, and 60 degrees Celsius. A data acquisition system connected to a computer will log viscosity versus shear rate. Similar procedure was applied to the 15% w/w HCl to compare the results. Beaker Test Procedure: Two 1000mL beakers were set side by side on a stir plate. 800mL of FF-01 was added to one beaker while 800 ml of 15% HCl was added to the other beaker. A stir bar was added to each beaker and mixed at 250RPM for 10 minutes. Each core was located 1 inch above the stir bar using a holder that was set into the beakers and the reaction started. Samples from each beaker were taken often until the reaction was complete. Next, the samples were diluted times so that they could be used to measure the calcium concentration using inductively coupled plasma atomic emission spectroscopy (ICP-AES). Finally, the calcium concentrations were calculated from the diluted values and graphed. Figure 1 is a schematic of the setup used to conduct the beaker test. Procedure for Core Flooding Tests: Several linear coreflooding experiments were performed using both 15% HCl and FF-01. The primary focus was on high and low permeability limestone core plugs. The apparatus that was used to conduct these experiments is shown schematically in Figure 2. Indiana Limestone cores 1.5 inches in diameter and 3 inches long were placed inside the core holder after being saturated with brine, confining pressure was simulated by injecting a non-reactive oil behind the hassle sleeve and the system was pressurized. Coreflooding experiments were conducted at 25 and 40 degrees Celsius. These temperatures were chosen in order to simulate a typical LKC reservoir. The first step in each experiment was to saturate the cores. The mass of the core was taken, and then the core was completely dried and ready to be saturated with brine. The core was then placed in a desiccator, vacuum pressure was applied to the core and 2%KCl brine was introduced into the system. After the core was saturated, the coreflooding experiment could be conducted. Experiments were performed by first placing a core in the coreholder and setting the confinement pressure to 500 psi. Brine is then injected into the core

4 URTeC: at a rate between.5-4 ml/min. At these constant injection rates, a computer records differential pressure across the core. These differential pressures were used to calculate the permeability using Darcy s Law. 15% w/w HCl or FF-01 was then injected at a constant rate of 0.5 ml/min. The line pressure was monitored, and the confinement pressure was gradually increased so that the confinement pressure was always 500psi above the line pressure. This is done to ensure that flow did not bypass the core. While injecting acid, the differential pressure across the core is monitored and recorded. Production samples were taken and sent for ICP analysis. Acid injection is continued until differential pressure across the core drops significantly, indicating acid breakthrough. Gas produced from the acid reacting with the core is kept in solution by the applied back pressure allowing the use of Darcy s Law. Following acid breakthrough, brine is again injected at the same rates as done before acid injection but along the opposite direction. Differential pressures across the core are again recorded at the given rates in order to calculate the overall permeability of the core following matrix acidizing. A visual representation of the core flooding setup is shown in Figure 2. Figure 1 Beaker test schematic showing two core plugs of similar weight and shape reacting with 15% HCl (left) and FF-01 (right). Samples were taken while the reaction was occurring and calcium and magnesium ions were measured with time.

5 URTeC: Figure 2 Core Flooding Setup Results and Discussion Rheological Testing Viscosity versus shear rate was measured for FF-01 using an Anton Paar rheometer at 25 C, 40 C, and 60 C and pressures of 100, 1000, 2000 and 3000 psi. Viscosity of the FF-01 decreased with shear rate at shear rates higher than 300 s -1 and temperatures of 25 C, 40 C, and 60 C, respectively. This shear thinning is very favorable during the injection of FF-01 since high shear rates are experienced in the wellbore. Smaller shear rates are experienced when the fluid reaches wormholes and fractures generated in the rock. This increase in viscosity when the fluid reaches the wormholes will help to prevent leak-off of the FF-01 and allow for branching off of the original wormhole. Increasing the pressure from 100 psi to 3000 psi did not change the viscosity of the FF-01. Moreover, FF-01 shows a significantly higher viscosity compared to 15% HCl at different temperatures (Figure 3).

6 URTeC: Figure 3- Viscosity versus shear rate for FF-01 and 15% HCl at 25 C, 40 C, and 60 C. Beaker Tests The results of the calcium concentration measurements are shown in Figure 4. The linear relationship between calcium concentration and time that was observed for FF-01 was compared to the calcium concentration versus time for 15% HCl, which is fitted using a second order polynomial with a negative second derivative. This shows the slower reaction rate of FF-01 compared to 15% HCl. However, the core was completely consumed after 2 hours submerged in FF-01, while it was consumed after only 20 minutes using 15 % HCl. Fewer residues were generated by FF-01 at a certain time compared to residues left from faster reaction of HCl. This will help preventing formation damaging.

7 URTeC: Figure 4 - Calcium concentration versus time for FF-01 and 15% HCl reacting with limestone rock samples. Core Flooding Tests Multiple coreflooding experiments were conducted and the results are outlined in Tables 1-4. Each core plug was saturated with 2% KCl after being dried at 70 C. Initial permeability varied among the cores, but the core plugs are divided into two groups of low and high permeability. Tables 1-4 summarize the core properties and important information for each test. Further examination of Table 1 shows that low permeability limestone cores treated with FF-01 experienced a much higher increase in permeability than the cores that were acidized with 15% HCl at 40 degrees Celsius. When backpressure was applied, the results were slightly better for both HCl and FF-01 tests. Table 2 outlines low permeability limestone cores acidized with FF-01 at 25 degrees Celsius. Again, cores acidized with the FF-01 experienced a higher increase in permeability than the cores that were acidized with 15% HCl. When back pressure was applied, the HCl results were much better. However, backpressure only slightly increased the permeability increase ratio for the FF-01 tests. One experiment that is interesting to look at is core IL-15 in Table 3. Table 3 shows the results using high permeability limestone cores. Core IL-15 was first matrix acidized with 15% HCl. It was then flooded with FF-01 to see if there was a benefit to treating wells with FF-01 that had already been acidized with HCl. After acidizing core IL-15 with HCl, the permeability increase ratio was about 1. As shown in Table 1, after acidizing core IL-15 with FF-01, the permeability increased times. This is an evidence that it would be beneficial to treat previously acidized wells with FF-01. This is important because many old wells in states like Kansas and Oklahoma have already been acidized using HCl. This shows the benefit of doing another matrix treatment using FF-01. Smaller, but still very significant incremental permeability was observed for high permeability cores compared to low permeability cores. Reproducibility of the results is also double checked in Table 3. Table 4 is the summary of the FF-01 acidizing test that was done on an Austin Chalk core plug. The results of this

8 URTeC: test are similar to the results seen using Indiana Limestone. The permeability of the chalk core after being acidized with the FF-01 increased by 113 times. Acid Type Table 1 Low Permeability Indiana Limestone Core Flooding Tests at 40 Degrees Celsius Core Name K (before), K (after), K Increase Ratio T, C Backpressure, psi UF IL_7D UF IL-7C HCl IL-8D HCl IL-8C Acid Type Table 2 Low Permeability Indiana Limestone Core Flooding Tests at 25 Degrees Celsius Core Name K (before), K (after), K Increase Ratio T, C Backpressure, psi UF IL-7B UF IL-7A HCl IL-8B HCl IL-8A Acid Type Table 3 High Permeability Indiana Limestone Core Flooding Tests at 40 Degrees Celsius Core Name K (before), K (after), K Increase Ratio T, C Backpressure, psi HCl and UF IL UF IL UF IL UF IL Acid Type Core Name K (before), Table 4 Austin Chalk Core Flooding Tests K (after), K Increase Ratio T, C Backpressure, psi UF AC Figure 5 below is a visual representation of the difference between matrix acidizing with HCl and matrix acidizing with FF-01. FF-01 tends to do a better job than HCl in generating a wormhole to bypass the near inlet zone. We conclude that HCl cleans up the immediate area near the wellbore, but often spends too quickly to bypass the damaged zone with wormholes. There is a significant amount of face dissolution happening on the HCl core, while there is little face dissolution on the FF-01 flooded core. CT scanning confirmed that there was not a continuous wormhole from the inlet to outlet of the core treated with HCl. CT scanning also confirmed that the wormhole on the inlet side of the FF-01 core is the same wormhole that can be seen at the outlet of the core. There are also other smaller diameter wormholes around the main wormhole on the outlet side of the core treated by FF-01. This is indicative of the FF-01 branching off of the original wormhole.

9 URTeC: Figure 5 CT Scanned Images of Core plugs after the matrix acidizing with FF-01 and HCl. Figure 6 is measured pressure differentials across two cores vs. pore volume injected while acidizing with FF-01. In both cases there is a significant drop in pressure near the end of the acidizing process. This pressure drop is representative of the wormhole reaching the end of the core sample. More information on the acidizing experiments represented in Figures 6 can be referenced in Table 1. These two cores shown in Figure 6 were similar plugs. Their before acidizing permeabilities were very low, and their permeabilities after acidizing were similarly high. These two tests are outlined to show reproducibility of the tests as well as a representative pressure drop behavior. Figure 6 - Differential pressure profile for two Limestone cores acidized with FF-01 Higher pressure drops required by 15% HCl before it generates a wormhole through the core compared to the pressure drop reported for FF-01 may be caused by the higher consumption rate of HCl and also higher residue left caused by higher reaction rate of HCl compared to FF-01. Higher amounts of residue caused by HCl may cause pore plugging and prevent propagation of wormholes deeper into the formation. HCl showed strong face dissolution which is ideal for acid washing purposes. On the other hand, FF-01 spent much more slowly than HCl, causing it to have a much deeper penetration through the core. Deeper penetration is ideal for generating long wormholes that will bypass the damaged zone. FF-01 also has opportunities for application in long horizontal wells by matrix acidizing the many perforated stages of the well. Moreover, UltraSeries FF family of

10 URTeC: products is environmentally friendly and will cause minimum harm to the equipment and field crew. Conclusions Beaker tests showed that FF-01 dissolves the same mass and volumes of limestone rock samples with slower reaction rates compared to 15% HCl. In addition, it lasts longer during the course of reaction and leaves fewer residues. Calcium concentration measurements showed a linear increase in the calcium as a product of the rock-acid reaction. For 15% HCl the linear part of the concentration vs. time curve showed a larger slope. Rheology tests showed a shear thinning behavior between s -1 shear rates and an almost constant viscosity at shear rates above 300 s -1. The shear thinning behavior of FF-01 is a favorable property during an acid fracturing or matrix acidizing treatment sine this product shows higher viscosity at lower shear rates. Pressure had no significant effect on viscosity. Significantly higher viscosity values were observed for FF-01 compared with 15% HCl. Core floods using 15% HCl and FF-01 showed significant increases in permeability when FF-01 was used comparing with cores treated using 15% HCl. CT scan analysis determined that FF-01 generated a wormhole through the entire core, while 15% HCl porpagated a wormhole of only about half the length of the core. Acidizing with FF-01 following an HCl treatment caused an increase in permeability by 55.5 times. Acidizing the Austin Chalk core with FF-01 produced an increase in permeability by 113 times. Acknowledgements The authors of this paper would like to acknowledge the Tertiary Oil Recovery Program (TORP) at the University of Kansas for providing us with the ICP measurements. We would like to specifically thank Dr. Karen Peltier for conducting the measurements. We would also like to thank Ms. Isabel Leon from the Chemical and Petroleum Engineering department at the University of Kansas for her help in conducting some of the core flooding experiments. Finally, we would like to thank Mr. Alan Walker from the University of Kansas for his help in preparing and fixing laboratory equipment. References [1] Decontamination Series-FF-01; Material Safety Data Sheet; 101st Earthborn Environmental Technologies, LP, Colby, KS, May, [2] Al-Harthy, Salah, Oscar Bustos, Mathew Samuel, John Still, Michael Fuller, Nurul Hamzah, Mohd Isal pudin bin Ismail, and Arthur Parapat. "Options for High-Temperature Well Stimulation." Oilfield Review (2008/2009): Print. [3] Bolt, B., The Mississippian Lime: America s Next Big Resource Play, [4] Earthborn Clean Products, [Online]. Available: [5] Everly, S., Kansas could see oil boom from Mississippi Lime formation, The Kansas City Star, Kansas City, 2012 [6] Gomaa, Ahmed, Jennifer Cutler, Qi Qu, Joel Boles, and Xiaolan Wang. "Matrix Stimulation: An Effective One- Step Sandstone Acid System.". Ed. SPESociety of Petroleum Engineers, Print. [7] Hendrickson, A., Rosene, R., Wieland, D. Acid Reaction Parameters and Reservoir Characteristics Used in the Design of Acidizing Treatments, [8] Fredd, C.N., and H. Scott Fogler. "Alternative Stimulation Fluids and Their Impact on Carbonate Acidizing.". Ed. SPE Print.

11 URTeC: [9] Buijse, Marten, Peter de Boer, Bert Breukel, and Gerardo Burgos. "Oganic Acids in Carbonate Acidizing.". Ed. SPE2003. Print. [10] Williams, B., Gidley, J., Schechter, R., Acidizing Fundamentals, New York: Society of Petroleum Engineers, [11] LePage, J.N., C.A. De Wolf, et al. "An Environmentally Friendly Stimulation Fluid for High Temperature Applications." 2009 SPE International Symposium on Oilfield Chemistry. (2009): 1-3. Print. [12] Collins, Natalia, Kingsley Nzeadibe, and Stephen Almond. "A Biodegradable Chelating Agent Designed to be an Environmentally Friendly Filter-cake Breaker." SPE European Health, Safety and Environmental [13] Dill, Walter. "Reaction Times on Hydrochloric-Acetic Acid Solutions on Limestone." American Chemical Society (1960): 14. OnePetro. Web. 14 Apr 2014.