2.3.1 High temperature deteriorates drilling fluid properties
As the temperature increases, various properties of the drilling fluid change. Generally speaking, rising temperature will worsen the wall-building performance of drilling fluid, that is, the mud cake will become thicker, the permeability will increase, and the filter loss will increase. However, this changing trend is not directly and necessarily related to the size of the API fluid loss. That is, the fluid loss of drilling fluid with a small API fluid loss under high temperature and high pressure conditions does not necessarily mean a small fluid loss. This shows that there are different mechanisms of action at high temperatures.
The impact of high temperature on the rheology of drilling fluid is relatively complex, and its impact can be studied in detail from the relationship curve between viscosity and temperature. The common viscosity-temperature curves have the following typical forms (Figure 2.2).
Curve ① represents the dispersed drilling fluid with strong temperature resistance and low clay content. In the rheological composition of this type of drilling fluid, the non-structural viscosity accounts for a larger proportion than the structural viscosity, such as a system in which a polymer treatment agent increases the plastic viscosity of the drilling fluid. Drilling fluids with strong coalescence and high clay content are generally likely to show curve ③. This kind of drilling fluid has a very strong structure (including the "card house structure" and the space grid structure of polymer-clay particles). greatly exceeds the contribution of plastic viscosity to viscosity.
Figure 2.2 Several common viscosity-temperature curves of water-based drilling fluids
All types of water-based drilling fluids generally exhibit curves in a wide temperature range (normal temperature to high temperature) The change pattern of ② is just that different drilling fluid systems show different minimum values ??of plastic viscosity (eta effective) and temperature (tB).
If tB is greater than the operating temperature of the drilling fluid, it becomes curve type ①. If tB is lower than room temperature, the viscosity-temperature curve of the system appears as curve ③. It can be said that curve ③ is a general rule for all types of water-based drilling fluids, while curves ① and ② are two special cases. Research shows that this temperature-dependent property may be reversible. Therefore, it can better reflect the actual changes in drilling fluid performance during the circulation process from wellhead → well bottom → wellhead during use. It is a key issue whether the drilling fluid system can meet the engineering and geological requirements of deep well sections. Obviously, this high-temperature change characteristic can cause a huge difference in the performance of drilling fluids at high temperatures at the bottom of the well and at low temperatures at the wellhead. Therefore, the wellhead performance of drilling fluids measured by conventional instruments must not be used to measure the actual performance of downhole drilling fluids at high temperatures. It can only be measured with instruments that simulate actual high temperature and high pressure conditions downhole, and is used as a basis for designing and maintaining deep well drilling fluid performance parameters and judging downhole conditions to determine engineering measures.
2.3.2 High temperature reduces the thermal stability of drilling fluid
High temperature causes changes in the components themselves and between components in the drilling fluid that are not easy to occur at low temperatures. Violent reactions and inconspicuous effects have become intensified, and at the same time, the inevitable formation pollution (salt, calcium, drill cuttings, acid gas, etc.) caused by long-term open-hole drilling has been aggravated. The results of all these effects will inevitably seriously change, damage or even completely destroy the original properties of the drilling fluid, and this effect is an irreversible and permanent change. It indicates the stability ability of the drilling fluid system after being subjected to high temperature (or the ability of the drilling fluid to resist high temperature damage), which is especially called the thermal stability of the drilling fluid system. Generally, the changes in the performance (measured under the same conditions) of the drilling fluid before and after high temperature are used to actually reflect the changes in the wellhead performance of the drilling fluid during use (sometimes even the changes in the inlet and outlet properties).
2.3.2.1 Effect of high temperature on the rheological and thermal stability of drilling fluid
(1) High temperature thickening
The apparent viscosity of drilling fluid after high temperature, The phenomenon of plastic viscosity, dynamic shear force and static shear force increasing is an irreversible change. If the drilling fluid loses fluidity after being exposed to high temperatures, it is called high-temperature gelation of the drilling fluid. It can obviously be regarded as a serious high-temperature thickening phenomenon. High temperature thickening is the most common phenomenon in deep well drilling fluids. During use, the drilling fluid viscosity and shear force continue to rise, especially during tripping operations, the drilling fluid increases even more after long-term high-temperature aging. Therefore, the performance of the drilling fluid is unstable and the treatment is frequent. It often brings trouble to the use of deep well drilling fluids (especially heavy drilling fluids), and for drilling fluids that are seriously thickened at high temperatures, the use of diluents is generally not effective, and may even make the problem worse. This is a prominent feature.
Drilling fluids with high clay content and strong dispersion often exhibit this phenomenon.
(2) High-temperature thickening
After the drilling fluid is exposed to high temperature, the dynamic and static shear forces decrease, which is called high-temperature thickening. The main manifestation is a decrease in dynamic and static shear forces. This kind of phenomenon is often observed in brine drilling fluids with poor soil, low soil content, and high salinity. It is not due to changes in drilling fluid components but is purely a change caused by high temperature. In actual use, it manifests as a gradual and slow decrease in drilling fluid wellhead viscosity and shear. This decrease is difficult to increase with conventional thickeners. Since severe high-temperature thickening can lead to heavy drilling fluid barite precipitation, full attention should also be paid during use. Generally, it can be solved by using surfactants or appropriately increasing the clay content in the drilling fluid.
(3) High-temperature solidification
The phenomenon that the drilling fluid is shaped and has a certain strength after being exposed to high temperature is called high-temperature solidification. Drilling fluids that solidify at high temperatures not only completely lose their fluidity but also experience a sharp increase in water loss. This situation mostly occurs in drilling fluids with high clay content, high Ca2+ concentration, and high pH.
Practice has proven that the drilling fluid often exhibits four different phenomena after being exposed to high temperatures, namely high-temperature thickening, gelling, solidification and de-thickening. These phenomena not only occur in different drilling fluid systems, but also may occur under different conditions in the same drilling fluid system. This fully illustrates the complexity of the impact of high temperature on drilling fluids.
2.3.2.2 Effect of high temperature on the thermal stability of drilling fluid wall-building properties
After the drilling fluid is exposed to high temperature, it is a common phenomenon that water loss increases and the mud cake thickens. The degree of increase varies depending on the drilling fluid system. However, some drilling fluid systems, such as the SMC-SMP salt water drilling fluid system, show the opposite result, that is, the drilling fluid filtration loss decreases and the mud cake quality becomes better after high temperature. The former is manifested as an increase in fluid loss or HIHP fluid loss at the wellhead temperature. The deeper the well and the higher the temperature, the greater the increase. In the latter case, the performance of the drilling fluid improves with use, and shows a trend that the deeper the well, the higher the temperature, and the longer the use time, the better the effect. That is, it shows a trend that high temperature improves the performance of the drilling fluid, see Table 2.3.
Table 2.3 Effect of high temperature on the wall-building properties of drilling fluid
2.3.3 High temperature reduces the pH value of drilling fluid
Practice has proved that drilling fluid after high temperature The pH value then drops, and the degree of drop varies depending on the drilling fluid system. The higher the salinity of the drilling fluid, the greater the degree of its decline. The pH value of the saturated brine drilling fluid after high temperature generally drops to 7-8. This decrease in pH will inevitably worsen the performance of the drilling fluid and affect the thermal stability of the drilling fluid. The tendency of the pH value of the drilling fluid system to decrease after high temperatures during use cannot generally be solved by adding caustic soda. The more alkali is added, the more alkali is added. , the more the pH value drops, the more unstable the drilling fluid performance becomes. Generally, surfactants can be used to suppress the decrease in pH value of the system or to use a drilling fluid system with a lower pH.
2.3.4 Effect of high temperature and high pressure on mud density and dispersion
As the well depth increases, the temperature and pressure of the formation will continue to increase, and the performance of the drilling fluid will be significantly improved. change. Among them, density is one of the important parameters that changes. The density of drilling fluid in the wellbore is the necessary basic data for various drilling construction and design. The density of ultra-deep well drilling fluid under high temperature and high pressure environment is no longer a constant, but changes with changes in temperature and pressure. The high temperature and high pressure density characteristics of drilling fluid are directly related to the accurate calculation of hydrostatic column pressure distribution and circulating pressure loss in the wellbore. In order to more accurately predict the true density of drilling fluid under high temperature and high pressure, the study of p-ρ-T characteristics of high temperature and high pressure water-based drilling fluid has important practical significance.
With the continuous deepening of domestic oil and gas field exploration and development, the number of deep wells and ultra-deep wells continues to increase. The formation of deep wells and ultra-deep wells is complex, the downhole temperature and pressure are high, and the drilling fluid density is prone to changes, which may lead to some downhole complexities. situation occurs. From this perspective, for deep wells and ultra-deep wells, it is of great significance to study the density characteristics of drilling fluids under high temperature and high pressure.
2.3.4.1 Volume changes of the solid phase in drilling fluids under high temperature and high pressure conditions
According to the regulations of the American Petroleum Institute (API), drilling fluids can be divided according to the size of the solid particles. The solid phase in the liquid is divided into three categories: clay (API colloid), mud and sand (API sand). Its sources are mainly useless components in clay powder, rock debris, weighted materials (such as heavy gold stone), etc. The density change of drilling fluid under high temperature and high pressure may be affected by the thermal expansion and high pressure shrinkage of these solid phases.
(1) Volume changes of clay particles in drilling fluid under high temperature and high pressure
Research has shown that the properties of clay components in drilling fluid will change greatly under high temperature and high pressure conditions. change. According to the previous explanation (section 2.1.1), the hydration and dispersion of clay is enhanced, the ζ potential is increased, and a thicker hydration film is formed around the particles than at normal temperature, that is, high-temperature dispersion occurs. When the clay content in the drilling fluid exceeds a certain upper limit, the drilling fluid will undergo high-temperature gelation at high temperatures: the clay will rapidly increase or even condense into clumps. At this time, compared with the high-temperature dispersion of clay particles, their own volume changes can be ignored.
At present, there is no research directly related to the impact of the volume change of clay particles in drilling fluid on the density of drilling fluid. It is speculated that the volume change of clay particles themselves should be similar to that of the useless solid phase.
(2) Volume changes of harmful solid phases in drilling fluid under high temperature and high pressure
Rock cuttings in drilling fluid, kaolinite, illite, etc. in clay powder cannot make slurry The ingredients occupy a certain proportion in the drilling fluid. The specific gravity is larger in ordinary drilling fluids without weighting agents. After the cuttings are ground or cut by the drill bit, the stress state changes and the volume changes accordingly; then they are carried by the drilling fluid and float up to the wellhead for removal. During this period, the volume of cuttings continues to change, affecting the density of the drilling fluid in the annulus of the wellbore (Figure 2.3).
Figure 2.3 Analysis of the stress state of downhole cuttings
Existing theoretical derivation and calculations show that under the conditions of a 10,000m deep hole, using a high temperature of 300°C and a high pressure of 260MPa, the drilling fluid is calculated The harmful solid phase deformation is between 0.25% and 0.45% (Figure 2.4).
Figure 2.4 Volume deformation of cuttings caused by temperature and pressure
According to the above figure, it can be seen that the width of line A is between 27 and 49 from bottom to top, and the width of line B is between Between 30 and 46.
The overall cutting deformation is estimated to be 40, or 0.4%. Assuming that the solid volume content in the returning drilling fluid is 5%, the volume change of the drilling fluid caused by the change in the volume of the solid component is:
Scientific ultra-deep well drilling technology program pre-research special results report ( Middle volume)
The change in drilling fluid density is:
Scientific ultra-deep well drilling technology program pre-research special results report (Middle volume)
If drilling 10,000 The density of drilling fluid used in ultra-deep wells is 1.76g/cm3. The change in drilling fluid caused by the change in solid phase volume is 0.0007g/cm3. This effect is very small.
2.3.4.2 Volume changes of the liquid phase in the drilling fluid under high temperature and high pressure
The influence of high temperature and high pressure on the density of the drilling fluid is mainly affected by the volume of the liquid phase components in the drilling fluid under high temperature and high pressure conditions. The influence of changes, and the previous research results show that the impact of the liquid phase on the density of drilling fluid is much greater than the impact of the solid phase. This may be due to two reasons: first, the liquid phase component occupies a considerable part of the drilling fluid, and the cumulative effect of small changes in the liquid phase may be amplified; second, the intermolecular forces of the liquid phase Small, it is more susceptible to change than solid phase molecules when affected by temperature.
According to the description in the book "Engineering Fluid Mechanics" written by Qi Deqing of Tongji University and others: The experiment pointed out that at one atmospheric pressure, when the temperature is low (10~20℃), for every 1℃ increase, the water The volume changes by 1.5×10-4. When the temperature is high, the change is about T×10-4.
It can be roughly deduced that when the drilling fluid temperature rises to 300°C, the volume change of the fluid is approximately:
Scientific ultra-deep well drilling technology program pre-research special results The report (mid-volume)
is 0.0017 times its original volume.
The change ratio of drilling fluid density is:
Special results report on pre-research on scientific ultra-deep well drilling technology plan (Part 2)
Assume that the density of ultra-deep well drilling fluid is 1.76g/cm3, then the change in density of the drilling fluid caused solely by the high temperature volume change of the water medium in the water-based drilling fluid is: 0.003g/cm3. It can be seen that the impact of changes in liquid volume on the density of drilling fluid is an order of magnitude greater than the impact of solid content in the drilling fluid.
2.3.4.3 Effect of high temperature and high pressure on drilling fluid density
Density characteristics are mainly determined by changes in volume, and volume is affected by temperature and pressure. The influence of temperature is manifested as expansion, and the influence of pressure is manifested as compressibility.
The high-temperature and high-pressure density test mainly measures the volume change of drilling fluid under different temperature and pressure combinations relative to normal temperature (room temperature) and normal pressure. The volume change of the test fluid is measured by how much it is sucked in or discharged, and then the weighing method is used. get. When the density and volume of the test fluid under normal temperature and pressure are known, the density of the test fluid under each combination of temperature and pressure is calculated based on the principle of mass conservation, that is,
Pre-research topic on scientific ultra-deep well drilling technology plan Results report (middle volume)
In the formula: ρ (p, T) is the density of the test fluid under pressure p and temperature T, g/cm3; ρ0 is the initial density of the drilling fluid, g/cm3; V0 is the initial volume of the test solution, m3; ΔV is the volume change, m3.
(1) Effect of temperature on drilling fluid density
According to Wang Minsheng (2007) and others who used a high temperature and high pressure drilling fluid density characteristic test device to conduct on-site preparation of ultra-deep wells in Well Sembcorp 1 Drilling fluid, Wang Gui (2007) and other laboratory drilling fluid research, the effect of temperature on density when the pressure is 10MPa, 30MPa, 50MPa is shown in Figure 2.5 and Figure 2.6.
Figure 2.5 The effect of temperature on the density of drilling fluid 1
Figure 2.6 The effect of temperature on the density of drilling fluid 2
The curve relationship in Figure 2.5 is:< /p>
At 10MPa: R2=0.9998; ρ=-1×T2+0.0007T+1.7408
At 20MPa: R2=0.9999; ρ=-1×T2+0.0008T+1.7363< /p>
At 30MPa: R2=1; ρ=-1×T2+0.001T+1.7266
It can be seen from Figure 2.5 that when the pressure is constant, as the temperature increases, the density of the drilling fluid decreases , and the decrease is relatively large. When the pressure is 50MPa and the temperature is 60°C, the density is 1.758g/cm3. When the temperature reaches 150°C, the density drops to 1.703g/cm3, with a decrease of about 3%. At the same time, under the same pressure, as the temperature increases, the downward trend becomes more obvious, indicating that the drilling fluid is more compressible at high temperatures and the nonlinearity of the curve is more serious. As can be seen from Figure 2.6, under certain pressure conditions, the density of water-based drilling fluid has a quadratic relationship with temperature. And the decrease in density is within a few percent.
(2) Effect of pressure on drilling fluid density
The effect of pressure on drilling fluid density is shown in Figure 2.7 and Figure 2.8.
Figure 2.7 Effect of pressure on drilling fluid density 1
Figure 2.8 Effect of pressure on drilling fluid density 2
In Figure 2.7, a linear relationship between pressure and density can be used The description is:
At 100℃: ρ=0.0004p+1.7102, R2=0.9997;
At 120℃: ρ=0.0006p+1.6771, R2=0.9999;
At 140℃: ρ=0.0007p+1.6408, R2=0.9996;
At 170℃: ρ=0.0009p+1.5664, R2=0.9986.
As can be seen from Figure 2.7, when the temperature is constant (temperatures are 60°C, 90°C, 120°C, and 150°C respectively), the density of drilling fluid increases as the pressure increases. When the pressure increases to a certain value When, the drilling fluid density no longer increases significantly. Comparing Curve 2 and Figure 2.7, we can see that drilling fluid is greatly affected by temperature and less affected by pressure. It can be seen from Figure 2.8 that under certain temperature conditions, the density of water-based drilling fluid has a linear relationship with pressure, and as the temperature increases, the slope of the straight line gradually becomes larger.
(3) Derivation of theoretical models
Currently, there are many theoretical models for analyzing the changes of drilling fluid density under high temperature and high pressure. Models of pressure changes can be divided into composite models and empirical models.
For the composite model, the drilling fluid is composed of water, oil, solid phase and weighted substances, and the performance of each component changes with temperature and pressure differently. After determining the high-temperature and high-pressure change patterns of these single components, a composite model for predicting drilling fluid density changes can be obtained.
This type of model is similar, represented by the models of Hoberock, Scolle, etc., which consider the compressibility and thermal expansion characteristics of different liquid phase components in the drilling fluid, while ignoring the compression and expansion of the solid phase. The use of composite models requires separate testing of different components of drilling fluid (water, oil, solid phase, etc.) to master their laws, so its application is subject to certain limitations.
Empirical models have different expression forms, and the accuracy of their use is acceptable. This model only requires a limited set of tests on the drilling fluid used to determine the constants in the model, and then the hydrostatic column pressure and equivalent static density of the drilling fluid can be calculated based on the model. Due to the limitations of experimental equipment, there is still a certain distance between the test pressure and temperature and the actual temperature and pressure, and the liquid phase composition is complex, so only the empirical model can be used. Fit the experimental data in the figure to get the equation
Scientific Ultra-deep Well Drilling Technology Program Pre-Research Special Achievements Report (Volume Two)
In the formula, x1 represents the temperature, ℃; x2 represents pressure, MPa.
It can be seen from equation (2.6) that if the bottom hole pressure is 100MPa and the temperature is 220°C, the density becomes 1.62g/cm3, which is a decrease of 7.5 percentage points compared with 1.75g/cm3 at normal temperature. According to the above model, assuming a low temperature gradient of 2.5°C/100m and a surface temperature of 25°C, when the well depth exceeds 10,000 meters, the effects of temperature and pressure on the density of the drilling fluid should be within a few percentage points.
According to the research of Wang Gui et al., five model regressions were performed on the experimental data:
Linear form: ρ=ρ0 (a+bp+cT);
Polynomial form: ρ=ρ0 (aT2+bT+cp+dpT+e);
Logarithmic function form: ρ=ρ0ln (aT2+bT+cp+dpT+e);
Exponential function form: ρ=ρ0exp (aT2+bT+cp+dpT+e);
Empirical model: ρ=ρ0exp (aT2+bT+cp+d);
< p>Calculate the regression coefficient, correlation coefficient, regression sum of squares, residual sum of squares and F value of each regression model. By conducting F test on the regression model, the optimal model is selected. Finally, the relationship between the density of drilling fluid and temperature and pressure in the examples cited in this article is:Scientific Ultra-deep Well Drilling Technology Program Pre-Research Special Achievements Report (Part Two)
Table 2.4 Comparison of model errors
As can be seen from Table 2.4, the water-based drilling fluid density model calculated using the exponential model of Wang Gui et al. has higher accuracy.
2.3.5 High temperature increases treatment agent consumption
Experience shows that high-temperature drilling fluid consumes much more treatment agent than conventional drilling fluid in shallow wells. Table 2.5 shows the US statistical data.
Table 2.5 Changes in treatment agent consumption at different temperatures
Although the data recorded in this document may not be applicable to all types of drilling fluids, as the well depth increases and the temperature increases, drilling fluids The general trend of significant increase in liquid treatment agent consumption is the same. There are two reasons for this: one is to maintain the drilling fluid performance required under high temperature and high pressure, which consumes more treatment agents than at low temperatures; the other is necessary supplement to make up for the losses caused by the destructive effect of high temperature. Therefore, the higher the temperature and the longer the use time, the greater the consumption of treatment agents, which also increases the technical difficulty of deep well drilling fluids.