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1 SPE Development of High-Performance Water-Based Mud Formulation Based on Amine Derivatives Nima Gholizadeh-Doonechaly, SPE, Petroleum University of Technology; Koroush Tahmasbi, SPE, Pars Drilling Fluids Co.; Ehsan Davani, SPE, Texas A&M University Copyright 2009, Society of Petroleum Engineers This paper was prepared for presentation at the 2009 SPE International Symposium on Oilfield Chemistry held in The Woodlands, Texas, USA, April 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 Many benefits by use of Oil-Based Mud (OBM) in drilling oil and gas wells have been identified in the oil industries worldwide. However the current ever increasing environmental legislations in preventing OBM application in the industries have dictated the use of water-based drilling fluid as the most environmentally acceptable alternative. On the other hand, drilling with water-based systems in shaly formations may cause many problems such as wellbore instability and high torque and drag. Therefore the most optimum alternatives would be different kinds of inhibited water-based systems in which adverse effects of shaly formations can also be controlled. These water-based alternatives are called High-Performance Water-Based Mud (HPWBM). Also the OBM properties is the final goal of the researchers to reach in their investigations to design a suitable HPWBM since OBM is the ideal drilling fluid to drill problematic formations. In this investigation attempts have been made to develop and formulate a water-based drilling fluid in which a suitable amine derivative has been successfully added to the system as a strong shale inhibitor agent instead of other conventional alternatives. Besides shale inhibition, an important challenge when using amine compounds in HPWBM is to overcome the thermal instability. Such a system must be formulated to achieve the right concentration of each mud additive to satisfy the necessity of a system that provides proper thermal stability during the drilling operation in high temperature sections. The newly HPWBM that was developed in this study comprises a specific concentration of a unique poly-ethoxylated alkyl diamine compound for shale inhibition, an amphoteric/polymeric shale encapsulator, a high-performance lubricant/deflocculating agent and special fluid loss additive to reach thermal stability up to 200 F. The designed system has exhibited optimum rheological properties and shale recovery in laboratory testing that was very close to that of OBM. The designed system has optimally improved the performance of previously formulated HPWBMs. Introduction To solve the drilling problems associated with shaly formations, various Non-Aqueous Drilling Fluids (NADF) have been used in the fields by the operators. In addition to shale inhibition, suitable lubricity and temperature stability were seen by using these systems (Friedheim et al. 1991; Friedheim and Conn 1996). However these advantages are realized as the ultimate goal in HPWBM researches, NADF have disadvantages, such as high cost, environmental limitations, disposal problems, and health and safety issues (Beihoffer et al. 1992; Patel et al. 2001). Shaly formations have a high tendency to absorb water from the surrounding fluid. This will happen by either rapid swelling or shale deflocculation mechanism which will result in problems such as bit balling, wash out, high torque and drag, etc (van Oort et al. 1996a; Steiger and Leung 1992). To reduce such anxious problems many chemicals have been used in the previous decades. These chemicals act via different mechanisms. The most widely used method was based on the addition of high concentrations of salts as like as sodium chloride (NaCl) and potassium chloride (KCl) to the drilling fluid. However using these salts in high concentrations causes environmental problems and results in high cost of disposal (Patel et al. 2007). The first generation of the shale inhibitor fluids introduced into the industry included sodium chloride/starch-, silicate-, limeand calcium sulfate-based gypsum mud (van Oort et al. 1996b). However environmental problems and limitations in mud formulation restricted their wide application.

2 2 SPE The next generation came with polymer/kcl system which was a combination of a specific polymer and a suitable amount of KCl. However this system requires a high concentration of electrolyte to be effective shale inhibitor which causes environmental problems and also increases the disposal cost (Clark et al. 1976). The usage of the silicate-based mud as another solution for drilling shaly formations was also restricted because of the silica precipitation problem during the drilling operation which leads to high torque and drag, health hazards associated with high ph value and restricted mud formulation (Patel et al. 2007). In another attempt, cation exchange which was the dominant inhibition mechanism amongst almost all of the inhibitor fluids motivated the researchers to use amine compounds as another alternative to obtain better results. However the first generations of these systems gave poor results, evolution of the amine compounds led to higher inhibition level. The amine/phpa system was one of the most suitable alternatives that has been designed and used by operators in the world (Patel et al. 2007). This system is a combination of a specific amine compound as the main inhibitor and Partially Hydrolyzed Poly-acrylamide (PHPA) as the secondary inhibitor. Like other conventional inhibitors, amine molecule acts through cation exchange mechanism and sticks to the clay layers and binds them together. However PHPA causes inhibition through a different mechanism. PHPA has a high molecular weight which cannot penetrate into the gap between the clay layers. It just physically encapsulates the clay particles that have already been inhibited by the amine molecules and prevents further penetration of water molecules from the surrounding fluid. This combination of the chemical and physical inhibition mechanism gives perfect results which can compete with that of OBM (Guerrero et al. 2006). The challenge in Iran to improve drilling fluids to reduce the shaly formation problems with the lowest environmental impacts, encouraged researchers to develop new water-based alternatives instead of conventional systems. Also other common fluid parameters such as adequate rheological properties and lubricity needed to be met. This paper describes the development of such HPWBM which is a combination of an amine compound as the main inhibitor, PHPA as an encapsulator and a conventional shale inhibitor (KCl) used in a lower concentration in comparison to the conventional water-based inhibitor fluids and also compares the laboratory results with the other shale inhibitor systems such as OBM and glycol mud. Optimized HPWBM with Amine-Based Inhibitor The HPWBM that has been designed in this study was optimized for the density of kg/m 3 and will be suggested for Asmary shaly formation in Maroon oilfield in the south of Iran. Rheology, filtration and shale inhibition analysis were the main concerns in this study. Components that were used for the nominated HPWBM formulation and their values are listed in Table 1. Suitable materials were successfully added to the system to adjust hardness and alkalinity of the designed mud. KCl also was used as a conventional shale inhibitor with lower concentration in comparison to conventional inhibitor systems. A specific filtration control agent was intentionally added to control the filter loss (FL) volume of the designed HPWBM. In addition to the nominated function, other benefits are also associated with that agent as like as compatibility in high saline conditions, resistance to bacterial attacks and stability at high temperatures. However there was a higher viscosity alternative for the filtration control purpose, the incompatibility of the designed mud with that high viscosity filtration control agent, as will be discussed in the dispersion stability test result, led to the usage of the lower viscosity agent. Also suitable viscosifier has been used for better hole-cleaning and suspension of solids. PHPA is another shale inhibition agent which its mechanism of inhibition was described before. The amine compound that was used as the main inhibitor in this study was from polyethoxylated alkyl diamine group with very low toxicity and high inhibition level. Because of the detergent characteristic of the amine compound, suitable defoamer was successfully added to the system to suppress foaming. Also proper weighting agent was added to the system to control formation pressures. To evaluate the performance of the designed HPWBM, two other systems were designed namely OBM and Glycol mud. Also the mud weights of these three systems were intentionally designed to be equal ( kg/m 3 ). The components of OBM and their values are listed in Table 2. Also the components of the glycol mud were exactly the same as the amine included system except that the amine compound was replaced with an equal amount of glycol to compare their inhibition level while other parameters are fixed. The glycol compound was selected from poly-alkylene glycol group. Rheological and filtration properties of these three systems were measured separately after hot rolling each mud sample which was sealed in an aging cell for 16 hours at 200 F in the oven as the American Petroleum Institute (API) standard, Standard Procedure for Laboratory Testing Drilling Fluids, and results are shown in Fig.1. As can be seen in Fig. 1, glycol system has a higher plastic viscosity (PV) and apparent viscosity (AV) than HPWBM with amine inhibitor which is attributed to the higher molecular weight of polymeric glycol compared with amine compound. Also the plastic viscosity of the amine included system can be easily adjusted with proper amount of viscosifier agent as can be seen in Fig. 2. The yield point (YP) value of the mud with amine additive is larger than the YP of glycol system because of the higher polarity of the amine molecule in comparison to the glycol compound. Gel strength analysis shows perfect results for all three systems. However amine included system tended to be better off amongst the three systems because of the lowest difference between 10 second- and 10 minute-gel values (0.5 Pa).

3 SPE FL volume of the OBM is always measured by the High-Pressure High-Temperature (HPHT) filter press device because of the excellent performance of oil-based systems. The glycol and amine muds also were tested with API filter press equipment. As it is shown in Fig.1 the OBM has very low FL volume which is due to the presence of special filtration control additives and capillary effects. The FL volume of the amine system was approximately 0.3 cm 3 higher than the glycol system s. As the amine and glycol systems additives were exactly the same, the only reason that could result in such a small difference in FL volume is the higher molecular weight and chain length of the polymeric glycol compound compared with amine compound. The thin filter cake deposited on the filter paper by the designed HPWBM with amine additive is shown in Fig. 3. Dispersion Stability Test To analyze the tendency of the dispersed phase (amine compound) in the designed HPWBM to be separated from the bulk fluid as a function of time, a quantity of well-mixed mud sample should be placed in a transparent container under quiescent condition for 24 hours. Two different fluid systems were prepared in the laboratory for the dispersion stability test. The first system was the newly designed HPWBM with components as shown in Table 1 and the second system has been choosed with the same components as the first one except that the filtration control agent in the designed system was replaced with an equal amount of a higher viscosity alternative. Prepared samples were allowed to be remained in static condition at room temperature for 24 hours. The results are shown in Fig. 4. As can be seen in Fig. 4, this test shows that the designed HPWBM is not compatible with high viscosity filtration control agent. Contamination Test In this test the effect of three different contaminants, namely seawater, OCMA clay and lime were analyzed on mud properties. The presence of common contaminants during the drilling operation was artificially simulated to observe the reflection of the designed HPWBM. All of the properties were measured after hot rolling each contaminated mud sample which was sealed in an aging cell, for 16 hours at 200 F in the oven and the results are outlined in Fig. 5. These measurements reveal the level of resistance and flexibility of the drilling fluid to those contaminants during the drilling operations. Each contaminant was added to 350 cm 3 of the mud sample in a period of one minute and then mixed for 10 minutes. The amount of each contaminant is as follows according to API specification, Standard Procedure for Laboratory Testing Drilling Fluids: -Sea Water: 35 g -OCMA: 35 g -Lime: 10 g Seawater Salt is a powerful flocculant that initially increases viscosity, gel strength and FL volume. Once the flocculants completely collapsed, the viscosity and gel strength decrease. Seawater addition to the system causes dilution as well as introduction of active ions into the solution. Effects of the sea water addition on mud properties can be seen in Fig. 5. Dilution causes reduction in ph, MW (as the original MW was higher than the seawater density) and PV and it will increase the FL volume. On the other hand, introduction of the active ions into the solution causes the YP and gel strength to increase. Any changes in apparent viscosity would depend on variations in plastic viscosity and yield point. Since the PV remained constant after seawater contamination, increase of the YP caused increase in AV. Totally it can be realized that the seawater does not have a significant effect on the properties of designed HPWBM. OCMA Clay OCMA Clay is a bentonite compound which is a clay base substance. Therefore it would be expected to be hydrated after addition to the drilling fluid. However all of the bentonite could not be hydrated. Contamination of the designed mud with OCMA clay causes a significant increases on the total number of solids in the system and on the other hand modifies the inter particle charges as it is an active solid. Therefore it will result in a significant increase on plastic viscosity, yield point and gel strength as shown in Fig. 5. Increase on mud-weight is due to the addition of the solid particle which is heavier than the original mud. Also hydrated clay particles can help the filter cake to be produced faster and therefore reduces the FL volume. Lime Lime is the active part of the cement and it is a rich source of calcium which is a flocculating agent. Addition of a flocculating agent to the mud causes a significant increase in yield point and gel strength which contradicts with the results taken from the lime contamination test as shown in Fig. 5. This phenomenon can be justified by increase of ph value that causes failure of the polymers which were used in this mud. One of the basic functions of the polymers is to decrease the FL volume. However flocculation causes the FL volume to increase, increase of approximately 46 cm 3 in FL volume shows nearly the complete failure of the polymers presented in the designed system which can cause a disaster during the drilling operation in such conditions.

4 4 SPE Qualitative Shale Recovery Qualitative shale recovery test was done to evaluate qualitatively the shale inhibition performance of newly designed HPWBM. The same test was carried out on the OBM with components as listed in Table 2 to compare the results with nominated HPWBM. Two shale samples were taken from the Pabdeh layer of Abteimur oilfield in Iran, well No.37, at the depth of 2730 m. Each mud sample (HPWBM and OBM) containing one of the shale pills was sealed in an aging cell and let to be hot rolled in the oven for 16 hours at 200 F. After this period shale samples were collected and visually analyzed for any change in their shapes. As can be seen in Fig. 6 perfect results were obtained by the OBM. The performance of amine system, as can be seen in Fig. 7, was somehow satisfactory, hence implementation of the next step for exact comparison of the shale inhibition characteristics. Quantitative Shale Recovery For more precise comparative analysis, quantitative shale recovery test was done on the designed HPWBM as well as OBM and glycol mud. For this test shale samples was selected from well No. 281 of Asmary formation in Maroon oilfield in Iran from the depth of 1217 m and were processed according to API specification, Standard Procedure for Laboratory Testing Drilling Fluids, which is given in Appendix A. The results of this test are shown in Fig. 8. As can be seen in Fig. 8, shale inhibition level of the designed HPWBM with amine inhibitor is very close to that of OBM (98.7 and 99% respectively) and also enhanced the glycol mud s shale inhibition level to a high extent which reveals a new achievement for water-based inhibitor fluids researches. Also the shale samples which were tested with the designed HPWBM are shown in Fig. 9 in their pre- and post-hot rolling state. As can be seen in Fig. 9, no considerable change could be observed in the size and shape of the samples before and after hot rolling which shows excellent inhibition level of the designed HPWBM with amine inhibitor. Conclusions Significant improvement has been made through the advent of amine chemistry in designing HPWBM to reach the performance of the OBM. The laboratory results reveal that the newly developed HPWBM significantly reduces clay damage and hydration associated with the conventional water-based systems. The newly designed HPWBM with amine inhibitor has improved the temperature stability of the previous systems up to 200 F and it is flexible in mud additives. Ease of handling and higher shale recovery percentage are two dominant characteristics of the designed amine system which cause it to be more preferred than the glycol mud. Glycol compounds as shale inhibitor agents need a minimum temperature to function well which is known as the cloud point and it varies for different glycol samples. Amine products have been employed as a corrosion inhibitor in the petroleum industry. This could be another incentive for further development of the amine included systems. The amount of defoamer utilized to suppress foaming was quite small, thus making its use extremely economical. References Beihoffer, T.W., Dorrough, D.S., Deem, C.K., Schmidt, D.D., and Bray, R.P. March Cationic Polymer Drilling Fluid Can Sometimes Replace Oil-Base Mud. Oil & Gas Journal. 11 (89): Clark, R.K., Scheuerman, R.F., Rath, H. and Van Larr, H.G. June Poly-acrylamide/Potassium-Chloride Mud for Drilling Water- Sensitive Shales. JPT 6 (28): SPE-5514-PA. Friedheim, J.E., Hans, G.J., Park, A. and Ray, C.R An Environmentally Superior Replacement for Mineral-Oil Drilling Fluids. Paper SPE presented at the Offshore Europe Conference, Aberdeen, 3-6 September. Friedheim, J.E. and Conn, H.L Second Generation Synthetic Fluids in the North Sea: Are They Better?. Paper SPE presented at IADC/SPE Drilling Conference, New Orleans, March. Guerrero X., Guerrero M., and Warren B Use of Amine/PHPA System to Drill High Reactive Shales in the Orito Field in Colombia. Paper SPE presented at International Oil Conference and Exhibition, Mexico, 31 August 2 September Patel, A., Stamatakis E., Friedheim J. E., and Davis E Highly Inhibitive Water-Based Fluid System Provides Superior Chemical Stabilization of Reactive Shale Formations. Paper AADE 01-NC-HO-55 presented at AADE National Drilling Technical Conference, Houston, Texas, March.

5 SPE Patel, A., Stamatakis, E., Young, S., and Friedheim, J Advances in Inhibitive Water-Based Drilling Fluids Can They Replace Oil- Base Muds?. Paper SPE presented at SPE International Symposium on Oilfield Chemistry, Houston, Texas, 28 February 2 March. Steiger, R.P. and Leung, P.K Quantitative Determination of the Mechanical Properties of Shales. SPEDE 3 (7): SPE PA. van Oort E., Hale, A.H., Mody, F.K. and Roy, Sanjit Transport in Shales and the Design of Improved Water-Based Shale Drilling Fluids. SPEDC 3 (11): SPE PA. van Oort, E., Ripley, D., Ward I., Chapman, J.W., Williamson, R., and Aston, M. Silicate-Based Drilling Fluids: Competent, Cost-Effective and Benign Solutions to Wellbore Stability Problems Paper SPE presented at SPE/IADC Drilling Conference, New Orleans, March. Appendix A Quantitative Shale Recovery Test Procedure 1. The shale samples should be selected with as near to in-situ moisture content as possible and before starting the test, the shale pieces should be screened to size less than 4 mm and greater than 2 mm. 2. The mud sample must be screened with a 0.5 mm sieve to remove any oversize particles that could be incorrectly reported as recovered shale. 3. A mud sample of 350 cm 3 must be poured into an aging cell g of the shale samples (screened prior to use) should be added to the fluid sample in the aging cell and then should be sealed and agitated gently and quickly. 5. The aging cell must be placed in the preheated roller oven and must be rolled for 16 hours. 6. After the rolling period and the aging cell have cooled to a safe handling temperature, they should be transferred to a static position to be cooled further to a temperature constant for all sequential recovery operations. 7. The content of the aging cell should be poured onto a numbered, pre-weighted 0.5 mm aperture sieve while wash water is applied to the screen to prevent viscous blocking. The residual contents of the aging cell should also be displaced onto the sieve with wash water. 8. The drilling fluid should be washed from the remaining shale pieces by a wash water flow of 2 L/min, through a hose with a circular outlet of approximately 0.75 cm ID. Water is systematically played across the full area of the screen many times for a period of approximately 1 minute or until the shale and screen are visually free of mud residue. 9. The sieve should be transferred to a 2 liter bath containing tapwater and then the sieve should be quickly and gently submerged so than the sieve and the shale particles have rinsed of wash water. 10. The sieve should be placed onto a sieve base and should be dried in the drying oven to a constant weight. Then the dried shale particles should be cooled in a desicator and after cooling they should be weighted which is the final dried weight.

6 6 SPE Table 1 Typical components of newly designed HPWBM. Amount needed per 1 m 3 Materials of mud sample, kg Drill Water Hardness Control Additive 0.5 ph Control Agent 0.7 KCl 55.4 Filtration Control Agent 10 Viscosifier 2 PHPA 3 Amine-Based Inhibitor 50 Weighting Agent Defoamer 0.8 Table 2 Typical components of OBM. Amount needed per 1 m 3 Materials of mud sample, kg Primary Emulsifier 23 Lime 23 Filtration Control Agent 20 Water CaCl Secondary Emulsifier 6 Viscosifier 7.1 Barite Fig.1 Rheological and filtration properties of designed HPWBM with amine additive, OBM and glycol mud. Fig. 2 PV adjustment with suitable amount of viscosifier agent. Fig. 3 Filter cake deposited on filter paper by designed HPWBM in API filtration test.

7 SPE Dispersion stability test results show that the designed HPWBM is not compatible with high viscosity filtration control agent (the left sample). Fig. 5 Contamination test results with three different contaminating agents, seawater, OCMA clay and lime. Fig. 6 Qualitative shale recovery test results for OBM, Pre- and Post-Hot Rolling.

8 8 SPE Fig. 7 Qualitative shale recovery test results for designed HPWBM, Pre- and Post-Hot Rolling. Fig. 8 Quantitative shale recovery test results for three inhibitor mud systems, glycol mud, designed HPWBM and OBM. Fig. 9 Shale samples processed according to API specification for quantitative shale recovery test, pre- and post-hot rolling for 16 hours at 200 F.