Fast response fluid properties monitoring system

Abstract

A fast response fluid monitoring system (300) used for fast evaluations and predictions of the properties of a drilling fluid or a fracturing fluid (204) onsite of an oilfield operation, by measuring the fluid properties under two shear rates at current temperature, predicting the fluid properties under other shear rates and under an elevated standard testing temperature, and comparing and updating results of the test to the predicted results to optimize next-time predicting practice.

Claims

1. A fast response fluid properties monitoring system comprising: a) a viscometer to measure viscosity properties of a sample fluid, b) a temperature control device to manipulate temperature of said sample fluid to at least an elevated standard temperature condition, c) a mud treatment system capable of treating said sample fluid according to the input of said viscosity properties of said sample fluid under at least said elevated standard temperature condition, d) a mathematical procedure to predict viscosity properties of said sample fluid based on a quickly measured rheology properties of said sample fluid at current temperature under at least one shear rate and previously measured viscosity properties of a second similar sample fluid under said elevated standard temperature condition.

2. The system of claim 1, wherein said sample fluid is a drilling mud.

3. The system of claim 1, wherein said viscometer is capable of measuring fluid properties of said sample fluid at various pressures.

4. The system of claim 1, wherein viscosity properties comprise, but are not limited to, viscosity, ten second gel strength, and ten minute gel strength.

5. The system of claim 1, wherein said predicted viscosity properties are further compared to said sample fluid measured fluid properties under at said elevated standard temperature to optimize said mathematical procedure to predict viscosity properties of said sample fluid.

6. The system of claim 1, wherein said mud treatment system is at a drilling location.

7. A method for a fast response fluid properties monitoring system, comprising the steps of: a) obtaining fluid properties of a first sample fluid through testing under at least an elevated standard temperature condition, b) obtaining minimum required properties of a second sample fluid which is similar to said first sample fluid at a current temperature conditions, c) predicting said second sample fluid properties at said elevated standard temperature condition according to the fluid properties of said first sample fluid under at least said elevated standard temperature condition and said minimum required properties of said second sample fluid, d) treating said second sample fluid based on said predicted fluid properties of said second sample fluid at said elevated standard temperature condition, e) finishing testing of said second sample fluid at said elevated standard test condition to improve said predicting accuracy of said second sample fluid properties for the future.

8. The method of claim 7, wherein said fluid properties comprise, but are not limited to, viscosity, ten second gel strength, ten minute gel strength, and density.

9. The method of claim 7, wherein said first sample fluid and said second fluid comprises, but is not limited to, at least one of a group consisting of a drilling fluid and fracturing fluid.

10. The method of claim 7, wherein said first sample fluid and said second sample fluid properties at a set of temperature and pressure conditions is measured using a viscometer.

11. The method of claim 7, wherein said first sample fluid and said second sample fluid properties at a set of temperature and pressure conditions is measured using a densitometer.

12. The method of claim 7, wherein said obtaining fluid properties of a first sample fluid through testing under at least an elevated standard temperature condition further comprises obtaining fluid properties of a first sample fluid through testing under at least an elevated pressure condition.

13. The method of claim 12, wherein said predicting said second sample fluid properties at said elevated standard temperature condition according to the fluid properties of said first sample fluid under at least said elevated standard temperature condition and said minimum required properties of said second sample fluid, further comprising predicting said second sample fluid properties at said elevated standard temperature condition and said at least an elevated pressure condition according to the fluid properties of said first sample fluid under at least said elevated standard temperature condition and said at least an elevated pressure condition and said minimum required properties of said second sample fluid.

Description

DRAWING FIGURES

(1) The following figures are included to illustrate certain aspects of the present disclosure and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, as will occur to one having ordinary skill in the art and the benefit of this disclosure.

(2) FIG. 1 is a schematic representation of the fast response fluid properties monitoring system at a drilling location.

(3) FIG. 2 is a schematic representation of the fast response fluid properties monitoring system at a fracturing location.

(4) FIG. 3 is a flow chart of the fast response fluid properties monitoring system.

(5) FIG. 4 is a diagram of RPM dial readings vs. temperatures at 100 psi.

(6) FIG. 5 is a diagram of 10-second and 10-minutes gel strength vs. temperature at 100 psi.

(7) FIG. 6 is a diagram of predicted and measured dial readings at 600 RPM at 150 F. vs. pressure in psi.

(8) TABLE-US-00001 Reference Numerals in Drawings 102 Drilling Rig 104 Mud Pump 106 Mud Tank 108 Mud Treatment 110 Shaker 202 Fracturing Truck 204 Fracturing Fluid 206 Well Head 208 Formation 210 Production Casting 212 Fracture 214 Production Zone 300 Fast Response Fluid Properties Monitoring System

DETAILED DESCRIPTION

(9) Embodiments disclosed herein relate generally to a system and method for measuring fluid properties at a drilling or fracturing location. More specifically, embodiments disclosed herein relate to systems and methods for fast evaluating and predicting properties of drilling fluid and fracturing fluid onsite of oilfield.

(10) FIG. 1 shows a schematic representation of a fast response fluid properties monitoring system 300 at a drilling location. FIG. 1 consists of a drilling fluid that is pumped into a wellbore, through a drilling rig 102, a drilling string and a drill bit, to facilitate the drilling string, cool and lubricate the drill bit, and remove solid particles from the wellbore. Afterwards, the drilling fluid is transported through a shaker 110 and a mud treatment 108. Then the drilling fluid is then circulated back to a mud tank 106 then to a mud pump 104 and back to the drilling rig 102 where the operation started. A fast response fluid properties monitoring system 300 can be either installed after the shaker 110, before a mud pump 104, or in another place that is needed.

(11) As the drilling fluid circulates through the wellbore, solid particles, including drill cuttings, become entrained within the drilling fluid and are conveyed from the wellbore to the surface of the drilling operation. Because characteristics of the drilling fluid may change as a result of the circulation of the fluid through the wellbore, those of ordinary skill in the art will appreciate that fast monitoring of the drilling fluid may be beneficial. Examples of fluid characteristics that may change include fluid density, viscosity, rheology, temperature, and pH, as well as other components of the drilling fluid. Also, as the drilling fluid circulates through the wellbore, the fluid removes entrained cuttings, and as such, characteristics of the drilling fluid may be affected by the addition of drill cuttings, hydrocarbons, and other contaminants. Therefore, it is important to measure the properties of the drilling fluid, fast evaluate and predict the properties, and make a quick adjustment according to the current drilling fluid characteristics. This is why the fast response fluid properties monitoring system 300 can be so vital to the industry today.

(12) FIG. 2 shows a schematic representation of the fast response fluid properties monitoring system 300 at a fracturing location. FIG. 2 consists of a fracturing truck 202, which pumps a fracturing fluid 204 that leads into a formation 208 through a well head 206 and a production casing 210 in order to generate and maintain a fracture 212 when the hydraulic pressure is over formation pressure. The fracture fluid 204 contains proppant which is made of sand or ceramic for maintaining the fracture and to increase the permeability of a production zone 214. The viscosity of the fracturing fluid is related to the width of the fracture 212 and has the capability of transporting the propping agent into the fracture 212. The density of fracturing fluid 204 will affect the surface injection pressure and the ability of the fracturing fluid 204 to flow back after the treatment. The fast response fluid property monitoring system 300 can be installed on the pipe line of the fracturing fluid 204 in order to have a fast evaluation and prediction of the properties of fracturing fluid 204.

(13) FIG. 3 shows a flow chart of the fast response fluid properties monitoring system 300. Generally, drilling fluid, fracturing fluid, or cement is measured or monitored by a field engineer who determines whether these fluids meet the drilling requirements before and during oilfield operation. The measurement of these properties gives the field engineer a status report of the fluid and how it is reacting with the formation and the subsurface environment. These fluids undergo constant proper treatment and adjustment so that the fluid properties, including density and rheology, are maintained to the best condition for current drilling operations. Drilling fluid is used to remove drill cuttings from the bottom of the hole among other things and the temperature is elevated so the drilling fluid properties experience numerous changes. Since drilling fluid properties experience changes corresponding to temperature changes, a typical drilling program, used to control drilling and mud treatment process, only requires a target rheology property of drilling fluids at 120 F. for a shallow well and 150 F. for a deep well. In this case, 120 F. or 150 F. is regarded as an elevated standard temperature testing condition. In this embodiment, a test fluid is introduced 302 into a fluid properties monitoring system 300. The fluid properties monitoring system 300 may include a viscometer, a densiometer or other devices used to measure fluid rheology or other similar properties. The test fluid will not be required to be heated to an elevated standard testing temperature in order to save time; therefore the rheology measurement will be conducted immediately at the current temperature under two different shear rates 306. The most commonly used shear rates are corresponding to 300 rpm and 600 rpm testing speeds when using an API 13 compliant rheometer.

(14) Before the drilling process occurs, a set of measured rheology numbers should already be obtained through testing originally designed drilling fluid 304. While drilling, at least two shear stress readings under 600 rpm and 300 rpm can be measured at current temperature 306 for when the drilling fluid has returned to the top. These two shear stress measurements can be used to predict the properties at an elevated standard temperature using the mathematical method 308. In the preferred embodiment first obtain one or two quickly measured rheology numbers at current temperature. Then derive the properties of the tested fluid at current temperature based on latest tested data of last fluid which is similar to currently tested fluid at an elevated standard temperature condition. Once the current temperature properties are measured, the derived properties at the current temperature would then be compared to the measured properties at the current temperature. The difference between the measured and derived numbers would be used to predict the properties of fluids currently being measured at elevated standard conditions such as 120 F. and 150 F. The fluid is then treated according to this prediction 312. The mathematical method described is very similar to the practice of extrapolation and interpolation. Meanwhile, fluid that is currently being tested is heated to elevated standard temperature and its properties are measured thereafter 310. These measured properties are compared to the predicted properties at the elevated standard temperature 314. If there is not a difference between the measured and the derived properties, then the mathematical method does not require an improvement. If there is a difference between the predicted and measured properties, then the difference is used to improve the method of prediction of future drilling fluid properties 316.

(15) An example of a mathematical method that can be used to predict or derive drilling fluid properties is the power law extrapolation. For example, the equation used to find the power law extrapolation for dial readings at 600 rpm at constant pressure is as follows,
d.sub.600=n.sub.600*t.sup.k(Equation 1)

(16) where t is the temperature and d.sub.600 is the dial reading at that particular temperature. The equation shown has two unknowns, n.sub.600, and k, therefore one who is skilled in the art will be capable of using the two different known temperatures and corresponding dial readings at 600 rpm to solve for the unknowns. Linear extrapolation or any other form of mathematical method can be used as a prediction method to predict the dial readings at other shear rates as well. For example, if the data for the ten second and ten minute gel strength was predicted by using linear extrapolation, under constant pressure the following formula could be used,
gs(t.sub.*)=n.sub.gs*t.sub.*+b.sub.gs(Equation 2)

(17) where the unknown gel strength is gs(t.sub.*) at the temperature t.sub.* and n.sub.gs and b.sub.gs are the unknown constants.

(18) In actuality a wellbore environment and a fracturing location have elevated temperatures as well as elevated pressure conditions. Some may choose to assume constant pressure to predict the properties at an elevated temperature as stated above and then make assumptions with the pressure. But in a more advanced treatment program the pressure as well as the temperature should be derived or predicted for the prediction of the drilling fluid properties as it travels down a wellbore or a formation. The mathematical method can also be utilized for constant temperature by using the following equation,
d(p.sub.*)=n.sub.p*p.sub.*+b.sub.p(Equation 3)

(19) Where p.sub.* is the pressure, n.sub.p and b.sub.p are constants, d(p.sub.*) is the dial reading for the corresponding pressure. Drilling fluid properties normally exhibit a linear pattern as the pressure increases, if temperature is constant. One who is skilled in the art will be capable of using the two different known pressures and corresponding dial readings at a single rpm to solve for the unknowns. If the rheological properties of the original mud are known at two different pressures, for example 2000 psi and 5000 psi, Equation 3 can be used to predict the rheological properties of the current mud at an elevated pressure. A combination of Equation 1 and Equation 3 can be used to predict or derive the rheological properties of the drilling fluid at elevated temperatures and elevated pressures by using a mathematical method that would help to find the current drilling fluid properties at the current temperature and pressure. Once the derived data is found, it will be compared to the measured data at the current temperature and pressure. If there are any differences between the derived properties and the current drilling fluid properties these differences will be applied to the prediction of the elevated standard temperature and pressure, for example 120 F. at 5000 psi and the fluid will be treated according to this prediction 312. In this way the results will be updated and will be optimized for next-time predicting practice 316. The described mathematical methods are not limited to predicting or deriving dial readings or gel strengths, these methods can also be used to derive and predict other fluid properties such as density, and other desirable properties of the drilling fluid.

EXAMPLES

(20) The following examples are displayed in order to facilitate a better understanding of the described embodiment of the present disclosure. In no way should the following examples be read to limit, or to define, the scope of the present disclosure.

Example 1

(21) The original mud properties for 80 F. and 120 F., as shown in Table 1, are known before the drilling fluid or mud enters the monitoring system 300 at constant pressure, then the drilling fluid properties of the current mud at the current temperature, or 100 F. can be derived using the mathematical method from equation 1. The diagram of RPM dial readings vs. temperatures at 100 psi is shown in FIG. 4.

(22) TABLE-US-00002 TABLE 1 Measured Drilling fluid Data at 80 F. and 120 F. Dial Dial Dial Dial Dial Dial 10 sec 10 min Reading Reading Reading Reading Reading Reading Gel Gel (lbf/100 (lbf/100 (lbf/100 (lbf/100 (lbf/100 (lbf/100 Strength Strength TEMP PRESS ft.sup.2) at 3 ft.sup.2) at 6 ft.sup.2) at 100 ft.sup.2) at 200 ft.sup.2) at 300 ft.sup.2) at 600 (lbf/100 (lbf/100 ( F.) (PSI) RPM RPM RPM RPM RPM RPM ft.sup.2) ft.sup.2) 80 100 10.4 13 39 57.2 71.5 97.5 127.4 118.3 120 100 8 10 30 44 55 75 87.4 92.3

(23) Assuming the drilling fluid was sampled to the viscometer at the current temperature of 100 F., then the properties at 100 F. are measured. These measured properties are compared to the derived properties at 100 F. under constant pressure. The results are shown in table 2. The differences between the measured and derived properties are used as an adjustment along with the mathematical method to predict fluid properties at elevated standard temperatures, in this case, 120 F.

(24) TABLE-US-00003 TABLE 2 Measured and Derived Drilling Fluid Dial Readings at 100 F. Temp 100 F. Dial Reading (lbf/100 ft.sup.2) Dial Reading (lbf/100 ft.sup.2) Press 100 psi at 300 rpm at 600 rpm Measured 61.9 84.4 Derived 63 85.5

(25) As stated above the difference between the measured data at 100 F. and the derived data at 100 F. was noted and used along with the mathematical method in order to predict the data at 120 F. While the data at the elevated standard temperature, or 120 F. is being measured the fluid is being treated based on the predicted properties at that temperature. Once the measurement at 120 F. is completed, it's result is compared to the predicted data at 120 F. as shown in Table 3. The drilling program will use this updated measurement to update its fluid treatments. Furthermore, the difference in data is used to improve the prediction method of fluid properties at next sample testing.

(26) TABLE-US-00004 TABLE 3 Measured and Predicted Drilling fluid Data at 120 F. Dial Dial Dial Dial Dial Dial Temp Reading Reading Reading Reading Reading Reading 120 F. (lbf/100 ft.sup.2) (lbf/100 ft.sup.2) (lbf/100 ft.sup.2) (lbf/100 ft.sup.2) (lbf/100 ft.sup.2) (lbf/100 ft.sup.2) Press 100 at 3 at 6 at 100 at 200 at 300 at 600 10 s gel 10 min gel psi RPM RPM RPM RPM RPM RPM (lbf/100 ft.sup.2) (lbf/100 ft.sup.2) Measured 8 10 30 44 55 75 12.3 15.4 Predicted 8.3 10.1 30.3 44.2 55.3 75.4 12.6 15.9

(27) If the ten minute gel strength and the ten second gel strength are known at two different temperatures under constant pressure, the mathematical method shown in equation 2 can be used to find the ten second and ten minute gel strengths at different temperatures. In a similar manner, once the gel strengths are measured they can be compared to the predicted gel strengths, as displayed in Table 3, and if there is any difference between the two sets of data, this can be used as an improvement of the mathematical method for future predictions of the drilling fluid rheology properties. The diagram of 10-second and 10-minute gel strength vs. temperature at 100 psi is shown in FIG. 5.

(28) If the rheological properties of the original drilling fluid are known at two different pressures, for example 1000 psi and 5000 psi, and at two different temperatures (as shown in table 4) then equation 1 and equation 3 can be used to predict the rheological properties of the current mud at an elevated pressure and elevated temperature. Once the properties are measured at these pressures and temperatures, the predicted properties are then compared to the measured properties, as shown in Table 5. If there is little to no difference between the measured and predicted properties, then the mathematical method does not require an improvement. If there is a difference between the measured properties and the predicted properties then the difference is used as an improvement of the mathematical method for future predictions of the drilling fluid rheology properties. The diagram of predicted and measured dial readings at 600 RPM at 150 F. vs. pressure in psi is shown in FIG. 6.

(29) TABLE-US-00005 TABLE 4 Known dial readings at 600 RPM Dial Reading at 600 RPM Temperature ( F.) Pressure (psi) 80 120 1000 108.9 74.8 5000 120.2 86.1

(30) TABLE-US-00006 TABLE 5 Measured and Predicted Dial Readings using Extrapolation Mathematical Methods for 600 RPM Measured Dial Predicted Pressure Temp Reading at Dial Reading (psi) ( F.) 600 RPM at 600 RPM 1000 150 69.9 68.8 5000 150 81.3 80.2 10000 150 92.6 91.5 15000 150 104 103.5

Ramifications

(31) In FIG. 1, the fast response fluid properties monitoring system 300 can be placed after the shaker 110, after the mud tank 106, or other places that are needed.

(32) In FIG. 1, any type of drilling fluid may be used, if it can be safely used and contained in the fast response fluid properties monitoring system 300 at a drilling location

(33) In FIG. 2, any type of vehicle or fracturing device may be used if it can pump a fracturing fluid 204 through a well head 206 and a production casing 210 to generate and maintain a fracture 212.

(34) In FIG. 2, any type of fracturing fluid 204 may be used, if it can be safely used and contained in the fast response fluid properties monitoring system 300 at a fracturing location

(35) In FIG. 3, after measuring the fluid under at least two shear rates or stirring speeds 306, the rest properties are predicted under other shear rates and temperatures 308 and the rest of the tests are finished under different shear rates and temperatures.

(36) In FIG. 3, after predicting the rest properties under other shear rates and temperatures 308, the fluid is treated according to the predicted properties 312 and the measured fluid properties results are compared and updated with the predicted properties 314 and eventually help to update fluid properties profile and optimized next time predicting practice 316.

(37) In FIG. 3, the fluid properties monitoring system 300 may include a electrical stability meter, a resistivity meter, or any other devices that is used to measure fluid properties.

(38) In FIG. 3, any type of fracturing fluid 204, drilling fluid or otherwise may be used, if it can be safely used and contained in the fast response fluid properties monitoring system 300.

(39) In FIG. 3, any type of mathematical method may be used, if it accurately predicts the fluid properties and or the density of the drilling fluid.

(40) In FIG. 3, any type of mathematical method may be used, if it accurately predicts the fluid properties and or the density of the fracturing fluid.

CONCLUSION AND SCOPE

(41) Accordingly, the reader skilled in the art will see that this invention and method can be used to quickly determine and monitor fluid properties on site of an oilfield operation. In doing so it satisfies an eminent need for the oil industry which requires fluid properties of a drilling fluid to quickly be monitored and adjusted as it goes through a drilling location and fracturing location. Accordingly, the scope of the fast response fluid properties monitoring system 300 should be determined not by the embodiments illustrated, but by the appended claims and their legal equivalents.