High temperature and high pressure rheological properties of high-density water-based drilling fluids for deep wells

Petroleum Science, Sep 2012

To maintain tight control over rheological properties of high-density water-based drilling fluids, it is essential to understand the factors influencing the rheology of water-based drilling fluids. This paper examines temperature effects on the rheological properties of two types of high-density water-based drilling fluids (fresh water-based and brine-based) under high temperature and high pressure (HTHP) with a Farm 50SL rheometer. On the basis of the water-based drilling fluid systems formulated in laboratory, this paper mainly describes the influences of different types and concentration of clay, the content of a colloid stabilizer named GHJ-1 and fluid density on the rheological parameters such as viscosity and shear stress. In addition, the effects of aging temperature and aging time of the drilling fluid on these parameters were also examined. Clay content and proportions for different densities of brine-based fluids were recommended to effectively regulate the rheological properties. Four rheological models, the Bingham, power law, Casson and H-B models, were employed to fit the rheological parameters. It turns out that the H-B model was the best one to describe the rheological properties of the high-density drilling fluid under HTHP conditions and power law model produced the worst fit. In addition, a new mathematical model that describes the apparent viscosity as a function of temperature and pressure was established and has been applied on site.

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High temperature and high pressure rheological properties of high-density water-based drilling fluids for deep wells

Pet.Sci. High temperature and high pressure rheological properties of high-density Wang Fuhua 2 3 Tan Xuechao 2 3 Wang Ruihe 2 3 Sun Mingbo 2 3 Wang Li 1 2 Liu Jianghua 0 2 0 Institute of Oil Production Technology, Xinjiang Oil Company , Kelamayi, Xinjiang 834000 , China 1 Institute of Oil Production Engineering, Daqing Oil Company , Daqing, Heilongjiang 163453 , China 2 China University of Petroleum (Beijing) and Springer-Verlag Berlin Heidelberg 2012 3 College of Petroleum Engineering, China University of Petroleum , Qingdao, Shandong 266555 , China To maintain tight control over rheological properties of high-density water-based drilling paper examines temperature effects on the rheological properties of two types of high-density water-based were also examined. Clay content and proportions for different densities of brine-based fluids were recommended to effectively regulate the rheological properties. Four rheological models, the Bingham, that describes the apparent viscosity as a function of temperature and pressure was established and has been applied on site. 1 Introduction One of the greatest problems encountered in deep well drilling is that drilling fluid requires excellent thermal stability and high density due to the high temperature and high pressure (HTHP) reservoir conditions. Environmental considerations and cost concerns have stimulated new Therefore, an improved water-based drilling fluid system is needed to meet these reservoir conditions, and the key to designing this system is to control the rheological properties of the drilling fluid (Pu et al, 2001; Wang and Wu, 2004; Wang et al, 2007). To provide better control of rheological properties and excellent thermal stability, the activated weighting agents, thermally stable clay and various fluid systems with temperature and contaminant tolerance have polymers, which provide suitable filtration and rheological properties and high thermal stability, have appeared on the market. In addition, the micro-mechanisms of rheology at high temperatures are being identified (Ezell and Harrison, 2008; Attia et al, 2010; Samaei and Tahmasbi, 2007; Tehrani et al, 2007; Kar et al, 2009). High-density water-based drilling fluid behaves as a viscous colloidal suspension system, possessing a high solid phase content, high dispersion of solids and a low free water content. Invading cuttings are difficult to remove from the contaminated fluid. Severe down-hole conditions also pose a challenge to the control over fluid rheological properties. So research on the HTHP rheological properties of high-density water-based fluid has been conducted to help bridge the gap in deep well drilling 2 Rheological properties of water-based Fresh water and brine were used to prepare drilling fluids and the formulations were optimized on the basis of laboratory experiments. The additives used in water-based Chemical composition Fresh water-based Sodium bentonite, g 2.2 Rheological measurements In this part, barite was used as weighting agent for fresh (mass ratio is 1:2) as weighting agent for brine-based drilling fluid of a density of 2.2 g/cm3. Before measurements, the rheological behavior, a rheometer (Fann 50SL, Fann Corp, MPa. The shear rate can be controlled from 0 to 1,022 s-1. The density and rheological properties of the water-based drilling fluids are not sensitive to pressure change owing to the relatively low compressibility of water (Demirdal et al, 2007; Piber et al 2006). However, temperature has a drilling, the drilling fluid is circulated from the surface to the drilling zone in deep formations and subjected to high temperature and high pressure. Thus, the combined effect of pressure and temperature should be taken into consideration in following tests. The rheological parameters were evaluated at different temperatures and 5 MPa. The experimental procedure for measuring rheological properties is as follows: 1) After placing the drilling fluid inside the rheometer, the sample was heated for 1 h up to the desired temperature. 2) 30 min of pre-shear at a shear rate of 1,022 s-1 was performed on each sample before rheological measurement in order to eliminate the effects of shearing, temperature, and pressure (Gusler et al, 2006; Saasen et al, 2008). 3) The pressure was adjusted to 5 MPa and the shear 3. The mass ratio of barite to limonite was 1:2. stresses were measured at different shear rates (ranging from 0 to 1,022 s-1) and at different temperatures. 2.3 Analysis of rheological properties of water-based 2.3.1 Rheological curves at different temperatures The rheological properties of two types of water-based drilling fluids were measured with the Fann rheometer at 5 MPa, and the shear-stress versus shear-rate curves are shown in Fig. 1. The experimental results indicate that both highthe temperature increased at high shear rates. This is attributed to thermal dispersion and thermal dehydration of clay particles in the suspension. Though the plastic viscosity (PV) particles, its structural viscosity decreased with increasing shear rate. The decrease in the structural viscosity was higher than the increase in the plastic viscosity. Therefore, the shear stress at high shear rates dropped rapidly with increasing temperature. However, the shear stress of brine-based fluid showed no significant trend as the temperature increased at high shear rates. 2.3.2 The effect of temperature on the viscosity of drilling The apparent viscosity (AV) and the plastic viscosity The results show that temperature heavily influenced the decreased with an increase in temperature. However, the began to increase. The values of apparent viscosity and plastic viscosity of two drilling fluids exceeded 20 mPa·s and 15 fluids had excellent cuttings carrying capacity under HTHP conditions. AV of fresh water-based fluid PV of fresh water-based fluid AV of brine-based fluid PV of brine-based fluid 30 60 90 120 150 180 210 240 Temperature, The rheological properties of the water-based fluid are influenced by a variety of factors. Focusing mainly on the fundamental components of the drilling fluid, systematic weighting materials, the additive GHJ-1, fluid density, and aging temperature and time on the rheological parameters of 3.1 Clay Clay content limit of the drilling fluid refers to the maximum and minimum clay contents (upper and lower the upper and lower limits, the rheological parameters of the drilling fluid can remain stable at elevated temperatures. It is required below 17.l kg/m3 when the density of the fluid exceeds 2.0 g/cm3. When the actual clay content exceeds the upper limit, the fluid tends to thicken, gel or even solidify at high temperatures. If the actual clay content is below the the viscosity decreases after exposure to high temperature. As for the two limits, the upper limit is more important than the lower one. The higher the upper limit and the larger the 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 Barite Used to increase the fluid density to 1.5 g/cm3 Used to increase the fluid density to 2.2 g/cm3 3.1.2 Fluids of a high density Samples 5#-8# (weighted to 2.2 g/cm3 with barite) were used here. The rheological properties are shown in Table 4. Samples 1#-4# (weighted to 1.5 g/cm3 with barite) were differential value between the upper and the lower limits, the easier the rheological properties are to maintain. The bentonite to sepiolite on the apparent viscosity, plastic Table 3 shows that for brine-based fluids containing different contents of sodium bentonite and sepiolite (samples 1#-3#), the plastic viscosity decreased but the yield point increased after aging (hot rolling). As the relative content of sodium bentonite in fluids increased, the yield point of the fluids increased significantly. When the content of sodium bentonite in the fluids was below 2%(w/v), the apparent viscosity changed slightly before and after aging. As the content of sodium bentonite exceeded 2%, the apparent viscosity increased significantly after aging. This indicates that in the fluid with a high content of sodium bentonite, thermal treatment (hot rolling) promoted the formation of a gel structure of sodium bentonite. However, as the relative content of sepiolite increased, the viscosity and the yield point exhibited little variations before and after aging. This is mainly attributed to the excellent heat resistance of sepiolite, whose structure remained stable during aging. Thus, the key to maintaining the rheological properties of water-based drilling fluids is to control the clay content, especially the content of sodium bentonite. One effective technical measure is to use sepiolite, which is relatively stable to the changes of temperature and salinity, to substitute for sodium bentonite in a minimum concentration within clay capacity limits. The total content of clay in fluid 2# was 3%, the viscosity and 3, the clay content should be controlled below 3% and the ratio of sodium bentonite to sepiolite should be kept at 1:2. Yield point Pa 15.0 30.0 25.0 15.5 27.0 20.0 5.5 113.5 5# 6# 7# 8# Before aging After aging Before aging After aging Before aging After aging Before aging After aging Density g/cm3 2.2 2.2 2.2 2.2 Apparent viscosity Plastic viscosity potassium formate, contained a lower solid content than other fluids weighted by NaCl when they had the same density, which helped to control the rheological properties of highan unpleasant smell was emitted during aging. This indicates that some barite could dissolve in the saturated potassium formate solution under thermal conditions, and react with potassium formate to generate poisonous (HCOO)2Ba, thus weighted with ilmenite instead of barite, the rheological is mainly because weighting materials would dissolve in the potassium formate solution at high temperatures. The fluid was contaminated by high valence ions (or cations), resulting Therefore, a colloid stabilizer with high tolerance to highvalence cations should be employed to stabilize the colloidal suspension at high temperatures when designing high-density were desirable. The viscosity and yield point of sample 6# were a little lower than those of sample 7# both before and and 3.5 MPa. Therefore, 2% clay content and a mass ratio of sodium bentonite to sepiolite of 1:1 are recommended to 3.2 Colloid stabilizer GHJ-1 A colloid stabilizer GHJ-1 was prepared to enhance the thermal stability of the high-density fluid. GHJ-1 has high salinity (saturated salt or calcium up to 12.5 g/L). Laboratory evaluations indicate that GHJ-1 possesses outstanding capacity to maintain the rheological properties of drilling fluids (colloidal suspension) at high temperatures and excellent properties to reduce fluid loss. Besides, because of its excellent compatibility with sulphonated additives commonly used in deep well drilling, GHJ-1 can greatly enhance the thermal stability of the drilling fluid with minimum costs. GHJ-1 are listed in Table 5. The influence of the colloid stabilizer GHJ-1 on the rheological properties of drilling Water mL 100 increased with the concentration of GHJ-1 before and after aging. GHJ-1, with a moderate-to-high molecular weight, The yield point reflects the strength of the gel structure formed by clay particles and high molecular polymer when of GHJ-1 when optimizing the formulations. In experiments the concentration is required in the range of 1.0% to 2.0%. It would be difficult to maintain the rheological properties of 90 ·sa 75 P ,ym 60 it s isco 45 v t ren 30 a p pA 15 0 0.0 Fig. 3 70 60 a 50 P it,n 40 o ldp 30 e iY 20 10 0 0.0 Fig. 4 Before aging After aging Before aging After aging 0.5 1.0 1.5 2.0 2.5 Concentration of GHJ-1, % 0.5 1.0 1.5 Concentration of GHJ-1, % 2.0 2.5 by macromolecular GHJ-1 in the drilling fluid caused an increase in the yield point, but the viscosity and the yield point decreased to some extent after aging. During aging, hydrolysis of polymer chains takes place, but the degradation of free radicals in the molecular chain can be neglected. The drop of the yield point was not attributed to the decrease in the relative molecular weight of the polymer, but to the decrease in the node number and intensity in the gel structure. This is because the original group dehydrated into the adsorption behavior on the clay particles. Fluid with a low addition of polymer thinned after aging. This was due to the hydrolysis of original group in the molecular chains. With increased again, as shown in Fig. 4. High solids content is the obstacle encountered in maintaining rheological properties of water-based drilling huge particle surface area greatly reduces free water in the in the cuttings capacity limits. Once contamination occurs, solid particles interplay and form a gel structure, causing an increase in the viscosity and shear stress. To maintain the et al, 1999; Shaughnessy et al, 2003). In this paper, the Figs. 5 and 6 show that as the density increased, both the apparent viscosity and the plastic viscosity increased However, after aging the difference between apparent viscosity and plastic viscosity was not significant, the yield density when the density of drilling fluids was below 1.8 g/cm3, the relatively high solids content produced substantial friction. A mixture of barite and ilmenite (mass ratio 1:2) g/cm3, so the yield point of the fluid of a density of 1.8 g/cm3 was lower than that of the fluid of a density of 1.5 g/cm3. However, as the density continued to rise, the yield point increased gradually. When mixing the high density drilling fluid at a high stirring rate, some bubbles were produced and the free water was greatly reduced due to the addition of a large amount of weighting materials (710 g barite was added to attain 2.2 g/cm3 for 350 mL drilling fluid thicken. So before aging the viscosity increased with point after aging was mainly attributed to some thermal degradation of the additive and accordingly a decrease in the molecular weight. AV after aging PV after aging AV before aging PV before aging 0.8 1.2 1.8 2.0 2.4 Density of the brine-based fluid, g/cm3 Fig. 5 Before aging After aging 120 100 s ·aP 80 m t,y 60 i s o isc 40 V 20 0 40 30 a P , t n iop 20 d l e i Y 10 0 0.5 1.0 1.5 2.0 Density of the brine-based fluid, g/cm3 2.5 Fig. 6 3.4 Aging temperature aging temperature. Temperature aggravates the degradation of additives, desorption of additives on clay surfaces and the dehydration of hydrophilic groups in additives. Consequently, elevated temperature reduces the effectiveness of fluid additives that protect the clay particles. Temperature exerts a and the effect of temperature on viscosity can be classified into three categories. 1) High temperature thinning. The viscosity decreases with increasing temperature, causing a reduction in carrying capacity and suspending ability of cuttings then barite sags when breaking circulation and tripping or settles in the fluid ditch. 2) High temperature thickening. The fluid experiences an increase in viscosity and yield point after aging at high temperatures thus losing its fluidity (gelation after a high temperature treatment). 3) High temperature solidification. The fluid completely lost barite-ilmenite (mass ratio of 1:2) was employed as weighting agent for 2.2 g/cm3. Exact experimental results are presented in Table 6. 3.5 Aging time The brine- and fresh water-based fluid with a density of 2.2 g/cm3 Performances were evaluated after aging for 16, 24, 48, and 72 h, respectively, and listed in Table 7. The apparent viscosity and the yield point of drilling fluids increased dropped. 4 R h e o l o g i c a l m o d e l s f o r h i g h - d e n s i t y Four widely-used rheological models, the Bingham, power law, Casson and H-B models, were used to estimate 1998). This paper aimed at experimental data above 150 predictive qualities are presented in Tables 8 and 9. For highmodel provided the best fits at 150-220 °C among the four rheological models. hole conditions from the apparent viscosity measured at the wellhead. The down-hole viscosity as a function of the apparent viscosity measured at the wellhead needs to be plotted. As the drilling fluids are circulated to the bottom of the borehole at deep formations they are subjected to high temperature and high pressure. However, pressure and pressure variation have only a slight effect on rheological properties of fluids. Emphasis is placed on the influence of temperature on the rheological properties of drilling fluids. Parameters of the drilling fluid at a given pressure with temperature changes were tested. Taking both temperature and pressure into consideration, the viscosity as a function of temperature and pressure can be rewritten into (Zhao et al, 2007): the wellhead possesses high temperature due to the bottomhole conditions in deep wells. The apparent viscosity of the Regression model regression model were high (R > 0.99). The apparent viscosity estimated with the model had a maximum error of 12.06%, showing good agreement with the measured value and completely satisfying the requirement for apparent viscosity an exponential function of temperature. Utilizing this model in conjunction with surface apparent viscosity, geothermal gradient and pressure gradient, the apparent viscosity of the be applied on site. 6 Conclusions 1) The effective measures to control the rheological clay content and employ sepiolite. In order to better maintain be kept at 3% and the mass ratio of bentonite to sepiolite 1:2 in the brine-based drilling fluid of a low-and-moderate density ( =1.5 g/cm3); the total clay content should be less than 2% and the mass ratio of bentonite to sepiolite 1:1 in the =2.2 g/cm3). 2) GHJ-1 could remarkably enhance the thermal stability of the drilling fluid, but the concentration of GHJ-1 could affect the rheological properties of the drilling fluid. The evaluation results indicate that as the concentration of GHJ-1 increased, the viscosity rose. Its concentration was desirable of GHJ-1 exceeded 2%. 3) The reason why density affects the rheological properties of the water-based drilling fluid is that the weighting materials cause the solid content to increase. There are two ways to reduce the solid content in the highmaterials can be used to reduce the solid content. Aging the appropriate content of additives is essential to maintain the rheological parameters within a reasonable range. 4) Temperature heavily influenced the viscosity of the fresh water-based drilling fluid. The apparent viscosity and an increase in temperature. The brine-based fluid had the lowest apparent viscosity and plastic viscosity at 150 ºC. 5) With the linear regression method, for high-density drilling fluids, the H-B model fitted the HTHP rheological parameters best. The established mathematical model can accurately describe the viscosity as a function of temperature and pressure. Acknowledgements The efforts of Professor Yan Jienian in the China University of Petroleum (Beijing) are especially appreciated. Attia M, Elsorafy W and Stefano D A. New engineered approach to North Africa Technical Conference and Exhibition, 14-17 February 2010, Cairo, Egypt Audibert A, Rousseau L and Kieffer J. 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Fuhua Wang, Xuechao Tan, Ruihe Wang, Mingbo Sun, Li Wang, Jianghua Liu. High temperature and high pressure rheological properties of high-density water-based drilling fluids for deep wells, Petroleum Science, 2012, 354-362, DOI: 10.1007/s12182-012-0219-4