Survey
* Your assessment is very important for improving the workof artificial intelligence, which forms the content of this project
* Your assessment is very important for improving the workof artificial intelligence, which forms the content of this project
See discussions, stats, and author profiles for this publication at: https://www.researchgate.net/publication/315007723 EXPERIMENTAL STUDY OF THE EFFECT OF CO2 GAS KICK, TEMPERATURE AND AGING TIME ON WATER BASED FLUID PROPERTIES Experiment Findings · April 2013 CITATIONS READS 0 394 1 author: Faith Okoro Politecnico di Torino 10 PUBLICATIONS 5 CITATIONS SEE PROFILE Some of the authors of this publication are also working on these related projects: Oil and Gas Pipeline Design View project All content following this page was uploaded by Faith Okoro on 14 March 2017. The user has requested enhancement of the downloaded file. EXPERIMENTAL STUDY OF THE EFFECT OF CO2 GAS KICK, TEMPERATURE AND AGING TIME ON WATER BASED FLUID PROPERTIES BY OKORO FAITH EFEREMO APRIL, 2013 ABSTRACT There might be a possibility of CO2 leakage from the storage reservoir during carbon sequestration and storage (CSS) process and this may lead to kick in nearby reservoir being drilled. The CO2 kick, when it comes into contact with the drilling mud, will tend to alter the properties of the drilling mud. The effect in the properties of the drilling mud could result into failure of the drilling programme. This experimental research work studied the effect of CO2 kick, temperature and aging on the properties of water based drilling. A simple-based mud was prepared and the properties of the mud were investigated as CO2 is injected into the mud at interval to simulate CO2 gas kick during drilling. The measured properties of the injected mud indicated that there was a 18% reduction in the density of the mud upon CO2 injection within the first 11days.That is, low density would result into pressure under-balance resulting into further influx of the CO2 to the well been drilled and this is dangerous for the drilling operation This research also shows that there was a corresponding 75.23% reduction in the viscosity of the mud within the first 12days of contact with CO2 which makes the mud totally ineffective in its ability to clean the well and transport drill cuttings to surface and this will result into lower drilling rate and higher drilling cost. After the first 11 days of CO2 influx, the density and viscosity of the drilling mud remains constant and this is an indication that a drilling mud, when reconditioned with a viscosifier, can be reused after some days of CO2 contamination without a further CO2 kick altering its density and viscosity properties. The research also indicated that the pH of the mud reduces gradually turning an initial basic mud to a slightly acidic mud. This is an indication of possible reduction in equipment corrosion. The resistivity of the mud also increased 58.8% which is an indication of reduced ionic activities as a result of reactions between the injected CO2 and the mud. It is also evident from the research findings that plastic viscosity and yield point decrease steadily with increase in temperature for all values of aging time. It is also observed as well that viscosity at a given temperature decreases with increase in aging time. It is also observed from this research that viscosity, yield point, gel strength and shear stress at a given shear rate decrease with increase in temperature and aging time. 1.0 INTRODUCTION The success of any drilling activity is based on details from the drilling fluid. Therefore the successful completion of an oil well depends on the drilling fluid. A drilling fluid or mud is any fluid that is used in a drilling operation Wells have different conditions, thus the drilling must be able to cope with these conditions. For this to be successful, the composition of mud must be varied with its properties. These various properties are affected by contaminants. A contaminant is any type of material (solid, liquid and gas) that has a detrimental effect on the physical or chemical characteristics of a drilling fluid Contaminant can lead to unfavorable rheological properties and slow the drilling rate. Eventually, the contaminant shows its effect by altering the fluid properties. In this study, the contaminant is carbon dioxide. Most drilling fluid formulations contain a base liquid and additives which must be dissolved or mechanically dispersed into the liquid to form a homogenous fluid. The resulting fluid may contain one or more of the following: water-dispersible (soluble) polymers or resins, clays or other insoluble but dispersible fine solids and soluble salts. The fluids are mixed or sheared for the number of times appropriate to achieve a homogenous mixture and are then set aside to “age”. Aging of drilling fluid is the process in which a drilling fluid sample previously subjected to a period of shear is allowed to more fully develop its rheological and filtration properties. Aging takes place when mud is left inactive for example during tripping. Aging is done under conditions which vary from static to dynamic and from ambient to highly elevated temperatures. Drilling fluids satisfy many needs in their capacity to do the following: 1) Removal of Drill Cuttings, (2) Control Formation Pressure, (3) Stabilizing the wellbore, (4) Cool and lubricate the bit, (5) Transmit hydraulic horsepower to bit (6) Support Weight of Tubulars, (7)Minimize Formation Damage, (8) Reducing Environmental Impact. Annis [1] investigated the changes in rheological property with time and temperature up to 3000F by a concentric-cylinder, rotational viscometer of the Fann type. His experiments covered the effects of temperature and aging on shear rate – shear stress , gel strength and viscosity. The study concluded that high temperature causes flocculation of bentonite clays, resulting in high yield points, high viscosities at low shear rates, high gel strengths and a permanent thickening of the mud. He added that proper treatment of bentonite mud with NaOH and lignosulphate reduces the effect of dispersion and flocculation at high temperature. Alderman et al [2] carried out experiments with water-base mud to study the rheology at temperatures up to 2660F and pressures up to 145000psi. They concluded that high shear viscosity decreases with increasing temperature in a similar manner for all drilling fluids examined and increases with pressure to an extent which depend on mud density. Yield stress is essentially independent of pressure and weakly dependent on temperatures. Their study did not simulate the bottom-hole conditions and did not consider the aging effect. Mohammed Shahjahan Ali [3], later wrote a thesis from a laboratory investigation on the effect of high temperature (4900F) and aging time of 30days on water-base mud properties using the HTHP viscometer, baroid roller oven (dynamic aging) and distilled water as the continuous phase.The result shows a decrease in viscosity, yield point and gel strength with the increase in temperature for all values of aging time. He concluded that shear stress for a particular temperature increases with increase in shear rate, but shear stress at a given shear rate decreases with increase in temperature. Viscosity, yield point and gel strength at a given temperature increase with aging time and aging effects are diminishing with the increase in aging time. Shear stress at a given shear rate increases with aging time and aging effects decrease with the increase in aging time. Shokoya et al [4] conducted a study on the rheology and corrosivity of water-base drilling fluid under simulated downhole conditions. The rheological property and corrosion behavior relationship of mild steel type 1018 in a typical drilling fluid used in deep drilling and hot wells was studied. The tests were conducted under conditions that simulate flow, temperature, and pressure encountered during drilling operations. Physical properties that were considered are: shear stress-shear rate relationship, effective and plastic viscosities, yield strength and gel strength. The properties were determined under high temperature and pressure by using a flow loop, the Baroid roller oven and the FANN-70 viscometer. The corrosion measurements were carried out by weight loss and electrochemical techniques. The effective and plastic viscosities of the drilling fluid decrease with increase in temperature and increase in time of exposure to downhole conditions. The corrosion rate of 1018 mild steel will increase with a decrease in the pH of the fluid. The corrosion rates are lower at the mildly alkaline pH and higher in the mildly acidic pH range. The drilling fluid generally attacks the grain boundaries of the steel samples. Diffusion was found to be the rate limiting step for the corrosion reactions. S.Salimi et al [5] conducted a research on the rheological behavior of polymer-extended waterbased drilling muds at high temperatures and high pressures simulating their true working conditions in a deep oil well. The performance of these polymers as a rheology modifier in drilling systems was then investigated using a Fann 50C commercial viscometer. By measuring shear stress vs. shear rate (i.e., the flow curve) at pressures up to 500 psi and temperatures up to 300°F , it was found that temperature had a detrimental effect on the rheological properties of the test fluids while the effect of pressure on these properties was realized to be less significant (specially at pressure above 300 psi). Osman and Aggour [6] carried out an experiment to determine drilling mud density change with pressure and temperature using a newly developed Artificial Neural Networks (ANN) model. Available experimental measurements of water-base and oil-base drilling fluids at pressures ranging from 0 to 1400 psi and temperatures up to 400 °F were used to develop and test the ANN model. With the knowledge of the drilling mud type (water-base, or oil-base) and its density at standard conditions (0 psi and 70°F) the developed model provides predictions of the density at any temperature and pressure (within the ranges studied) with an average absolute percent error of 0.367, a root mean squared error of 0.0056 and a correlation coefficient of 0.9998. Ran Qi (2009) [7] research into CO2transport in aquifer and applied it to optimize CO2 storage in aquifer and oil reservoirs. Jens T. Birkholzer et al (2008) carried out research on the largescale impact of CO2 storage in deep saline aquifers with the main objective on investigation of the three dimensional region of influence during/after injection of CO2 and evaluating the possible implications for shallow groundwater resources. Jennie C. Stephens (2008) [8] considered the geochemical reactions that enhance transformation of CO2gas into dissolved or solid phase carbon. This involves liberation of cations to neutralize carbonic acid. They carried out the assessment of potentials and limitations of various geochemical techniques. CO2 flooding in practice usually involve alternating CO2 injection and water injection. 2.0 METHODOLOGY 2.1 APPARATUS USED The experimental apparatus used in this study consists of a Fann Model 800 HighTemperature, High Pressure (HTHP) Viscometer, the Hamilton beach mixer, the hot plate, stirrer, API filter press, pH meter and the mud balance. 2.2 MUD PROPERTIES SAMPLE A Laboratory temperature = 29.5oC Volume of water = 350ml Mass of Bentonite = 12.5grams Mass of NaCl = 1grams Mass of Barite = 145grams 2.3 PROCEDURES The procedures followed in the course of this research are thus: 1. A water-based mud of 10.6ppg was prepared. 2. Initial properties of the mud were measured such as the density, shear stress, yield point, resistivity and acidity. From this the apparent and plastic viscosity were calculated. 3. Mud sample was placed in a modified filter press to serve as a high pressure vessel in form of a closed system. 4. CO2 gas was injected into the mud sample at an average pressure of 900psi and temperature of 29.50C. Injection was daily after the first injection of 3days. 5. Just before the injections the following measurements were carried out: The shear stress and gel strength of the mud were measured with rotary viscometer. The viscosity of the mud was then calculated from the measured properties. Also, the resistivity of the mud and pH of the mud was measured. 3.0 RESULTS AND ANALYSIS Details of the experiments are tabulated below. The values of plastic, apparent viscosities, yield points, shear stresses, pH, density and resistivity are represented in the table. The values obtained, are a function of aging and temperature. Table 3.1 shows the effect of aging on the rheological properties of water based mud Shear Stress Temperature( 600 RPM 300 RPM PV(Cp) O C) Days 0 3 4 4 6 7 8 9 10 11 12 13 29.5 29.5 29.5 29.5 29.5 29.5 29.5 29.5 29.5 29.5 29.5 29.5 52 50 48 45 43 41 40 39 38 37 36 34 46 45 43 40 38 37 36 35 34 34 33 31 AP(Cp) 6 5 5 5 5 4 4 4 4 3 3 3 26 25 24 22.5 21.5 20.5 20 19.5 19 18.5 18 17 YP(lb/1000ft) 40 40 38 35 34 32 32 31 31 30 29 28 Table 3.2 shows the effect of temperature and aging of the rheological properties of water based drilling fluid o Days 1 2 3 4 5 6 7 8 9 o o o 40 C 50 C 60 C 70 C 600RPM 300RPM 600RPM 300RPM 600RPM 300RPM 600RPM 300RPM 45 35 42 33 40 30 38 28 43 33 40 30 38 28 35 25 42 30 38 28 36 25 33 23 40 28 36 27 34 22 31 21 38 26 34 25 32 20 29 18 36 25 32 23.5 30 19 27 16 34 23 30 21 28 18 25 15 32 22 28 20 25 17 23 13 30 20 25 18 22 15 20 12 Figure 1 shows Shear stresses as a function of aging Graph of Shear Stress Against Time 60 50 Shear Stress 40 30 600 RPM 300 RPM 20 10 0 0 5 10 Time, Days 15 Figure 2 shows Plastic, Apparent viscosities and yield point as a function of aging Graph of Viscosity Against Time 45 40 35 Viscosity,Cp 30 PV 25 AV 20 YP 15 10 5 0 0 2 4 6 8 Time, Days 10 12 14 Figure 3 and 4 shows the effect of temperature and aging on water based drilling fluid Graph of Shear stress(300 RPM) Against Time 40 35 Shear Stress 30 25 40 deg 50 deg 20 60 deg 70 deg 15 10 5 0 0 2 4 Time,Days 6 8 10 Figure 4 Graph of Shear Stress(600 RPM) Against Time 50 45 40 Shear,Stress 35 40 deg 30 50 deg 25 60deg 20 70 deg 15 10 5 0 0 2 4 Time, Days 6 8 10 Table 3.3 shows the Viscosity, Density, hydrogen ion concentration and resistivity for a CO2 contaminated mud as a function of aging Shear Stress Density Temperat O Days ure( C) 600 RPM 300 RPM PV(Cp) YP(Cp) AV(Cp) 0 29.5 52 45 7 38 26 3 29.5 45 36 9 27 22.5 4 29.5 30 21 9 12 15 4 29.5 28 19 9 10 14 6 29.5 24 16 8 8 12 7 29.5 20 12 8 4 10 8 29.5 18 10 8 2 9 9 29.5 16 10 6 4 8 10 29.5 15 9 6 3 7.5 11 29.5 14 9 5 4 7 12 29.5 13 8 5 3 6.5 13 29.5 13 8 5 3 6.5 ` ph 9.52 8.13 7.22 6.98 6.78 6.5 6 5.89 5.8 5.65 5.6 5 ppg 10.6 10.4 10 9.8 9.5 9 8.9 8.8 8.75 8.7 8.7 8.7 3 lb/ft 79 78 75 74.5 72 67.5 66.5 66 65.5 65 65 65 S.G Resistivity (ῼ) 1.27 0.35 1.25 0.36 1.2 0.37 1.19 0.4 1.14 0.43 1.08 0.45 1.07 0.5 1.06 0.53 1.05 0.55 1.04 0.58 1.04 0.6 1.04 0.6 Figure 5, shows resistivity variation with time after CO2 contamination Graph of Resistivity Against Time 0.7 Resistivity,ῼ 0.6 0.5 0.4 0.3 Resistivity 0.2 0.1 0 0 2 4 6 8 10 12 14 Time, Days Figure 6 shows Viscosity variation with time after CO2 contamination Graph of Viscosity Against Time 40 35 Viscosity,Cp 30 25 PV,(Cp) 20 AV,(Cp) 15 YP,(lb/1000ft) 10 5 0 0 2 4 6 8 Time, Days 10 12 14 Figure 7 shows hydrogen ion concentration variation with time after CO2 contamination Graph of pH Against Time 10 9 8 7 pH 6 5 4 pH 3 2 1 0 0 2 4 6 8 10 12 14 Time, Days Figure 8 shows shear stress variation with time after CO2 contamination Graph of Shear Stress Against Time 60 50 Shear Stress 40 600 RPM 30 300 RPM 20 10 0 0 2 4 6 8 Time,Days 10 12 14 Figure 9 shows Density variation after CO2 contamination Graph of Density Against Time 90 80 70 Density 60 50 Density(ppg) 40 Density(S.G) 30 Density(lb/ft3) 20 10 0 0 5 Time, Days 10 15 Table 3.4 shows the Shear Stress of the mud after CO2 contamination mud as a function of temperature and time Days 1 2 3 4 5 6 7 8 9 10 40oC 50oC 60oC 70oC 600RPM 300RPM 600RPM 300RPM 600RPM 300RPM 600RPM 300RPM 45 35 42 33 40 30 38 28 40 25 38 23 35 20 33 18 30 20 28 18 25 15 23 13 25 16 23 15 20 13 19 11 20 14 19 11 16 10 14 9 18 12 15 9 13 8 10 7 15 8 9 7 8 6 7 5 10 6 7 4 6 3 5 2.5 8 4 6 3 5 2.5 4 2 5.5 3 4 2 3 2 2 1 ANALYSIS OF RESULT Effect of temperature The effect of temperature on water based drilling mud can be as a result of the interplay of various factors, some of these factors are more pre-dominant than others. These factors include; reduction in the degree of hydration of the counterions, reduction of the viscosity of the suspending medium, increased dispersion of associated clay micelles, changes in the electrical double layer thickness and increased thermal energy of the clay micelles. Since all these processes take place in the drilling fluid simultaneously as the temperature changes, therefore an interpretation of the observed results would be possible in cases whereby some of the effects are predominant and as such be easily identified. As shown in figures3 and 4, shear stress decrease steadily with increase in temperature for all values of aging time. Aging effect The effect of aging on mud rheology was also studied. The results are shown in figure 1 and 2. it was observed that viscosity at a given temperature decreases with increase in aging time and the aging effect are diminishing as the aging time increases especially for the yield point. The reason for this decrease in viscosity may be gotten from an analysis of the composition of the drilling fluid formulated for this study. Salt (NaCl) was added to maximize gel strength and also for compatibility against salt formations. Moreover, salt from its chemical properties is known to have a high water retention capacity which increases with exposure time (i.e.aging). This can even be physically observed when a sample of sodium chloride salt is exposed to the air; the salt becomes moist after some time. it can be thus be deduced that there is an increase in moisture content as a result of the absorption of water molecules from the surrounding by the salt molecules as aging time increased which therefore results in a decrease in viscosity. Effect of CO2 gas kick on resistivity As shown in figure 5, resistivity increase with increase in CO2 gas contamination. Effect of CO2 gas kick on viscosity From figure 6, it was discovered that viscosity decreases with increasing CO2 gas contamination Effect of CO2 gas kick on pH As shown in figure 7, it shows that pH decreases with an increasing amount of CO 2 contamination. Effect of CO2 gas kick on density As shown in figure 9, it shows that density decreases with increase in CO2 gas contamination CONCLUSION It is has been established that temperature and aging have effects on the drilling fluid properties. It was also discovered from this research that viscosity, yield point, gel strength and shear stress at a given shear rate decrease with increase in temperature and aging time. Challenges in drilling operation can be avoided if the optimum values of these properties are maintained. RECOMMENDATION Further research work should be carried out to prevent or minimized the effect of CO2 gas on water based drilling fluid. REFERENCES 1. Annis, M.R. 1997. Retention of synthetic-based drilling material on cuttings discharged to the Gulf of Mexico. Report for the American Petroleum Institute (API) ad hoc Retention on Cuttings Work Group under the API Production Effluent Guidelines Task Force. American Petroleum Institute, Washington, DC. August 29, 1997. 2. Alderman, N. J., Gavignet, D. and Maitland, G. C., "High Temperature, High Pressure Rheology of Water-Based Muds" SPE18035, Symposium, Oct. 2 – 5, 1988, pp187-195 3. Mohammed Shahjahan Ali (M.Sc. Thesis, June 1990): "The Effects of High Temperature and Aging on Water – Based Drilling Fluids." King Fahd University, Dhahran, Saudi Arabia 4. Shokoya O.S., Ashiru O. A. And Al-Marhoun M. A. 1997. The Rheology and corrosivity of water-base drilling fluid under simulated downhole conditions. King Fhad University of Petroleum and Minerals, P.O. Box 589, Dhahran 31261 (Saudi Arabia) 5. Salimi, S., Sadeghy, K., Kharandish, M.G., "Rheological Behaviour of PolymerExtended Water-Based Drilling Muds at High Pressures and Temperatures", University of Tehran, Iran, pp. 1-6. 6. Osman, E.A. and Aggour, M.A.: "Determination of Drilling Mud Density Change with Pressure and Temperature Made Simple and Accurate by ANN", Paper SPE 81422, Presented at the 2003 SPE Middle East Oil Show and Conference, Bahrain, 5 -8 April. F.A.Makinde et al./Petroleum&Coal 53(3) 167-182, 2011 173 7. Ran Qi, (2009) Simulation of Geological Carbon Dioxide Storage, Ph.D. dissertation, Department of Earth Science and Engineering, Imperial College London, UK . 8. Jennie C. Stephens and David W. Keith , June 2008, Assessing geochemical carbon management, Springer on line publications, (http://www.clarku.edu /faculty/jstephens/ documents/) View publication stats