Drilling a well with predicting sagged fluid composition and mud weight
Methods of drilling or treating a well including the steps of: designing a fluid with high-gravity solids (e.g., barite); calculating the sagged fluid mud weight after allowing for sag according to formulas; forming a fluid according to the sagged fluid mud weight; and introducing the fluid into the well. The methods can be used to help control the well or to avoid excessive drilling torque or pressure, kick, or lost circulation due to sag of high-gravity solids such as barite.
1. A method of drilling or treating a portion of a well, the method comprising the steps of:
(A) designing or obtaining a fluid comprising the following components:
(i) a continuous oil phase;
(ii) an internal water phase;
(iii) one or more high-gravity solids in particulate form, wherein the high-gravity solids have a specific gravity in the range of 2.7 to 8.0 and are insoluble in both the oil phase and the water phase; and
optionally (iv) one or more low-gravity solids in particulate form, wherein the low-gravity solids are insoluble in both the oil phase and the water phase;
(B) determining:
MW i =Σρ j i *φ j i
where MW i is the mud weight of the fluid when the fluid is a uniformly dispersed fluid;
where ρ j i is the density of each of the components of the fluid when the fluid is a uniformly dispersed fluid; and
where φ j i is the volume fraction of each of the components of the fluid when the fluid is a uniformly dispersed fluid;
(C) predicting a sagged fluid mud weight (MW s ) of a portion of the fluid as:
MW s =Σρ j s *φ j s
where the portion of the fluid has a higher density than when the fluid is a uniformly dispersed fluid due to settling of the high-gravity solids;
where MW s is the sagged fluid mud weight of the portion of the fluid after allowing time for sag in the fluid of the high-gravity solids when the fluid is under conditions of low shear or no shear;
where ρ j s for each of the components of the portion is selected to be adjusted for a design temperature and pressure in the portion of the well or where ρ j s for each of the components of the portion selected to be within 30% of the ρ j i of each of the components of the fluid, respectively;
where φ j s is the volume fraction of each of the components of the portion, wherein:
the ratio of φ j s for each of the high-gravity solids to φ j s for the water phase is selected to be within 20% of the ratio of φ j i for each of the high-gravity solids to φ j i for the water phase, respectively;
φ j s for each of the low-gravity solids is selected to be anywhere in the range of zero to 2 times φ j i for each of the low-gravity solids, respectively;
the sum of φ j s for the water phase, φ j s for each of the high-gravity solids, and φ j s for each of the low-gravity solids is selected to be anywhere in the range of 0.5 to 0.75; and
the φ j s for the oil phase is selected to be the balance of the volume fraction of the portion;
(D) designing or obtaining wellbore flow conditions in the well;
(E) determining whether the MW s is sufficient for control of the well or avoiding an equivalent circulation density difference greater than 0.05 ppg in the well;
(F) modifying the fluid or the flow conditions to control the well or avoid the equivalent circulation density difference greater than 0.1 ppg in the well; and
(G) flowing the fluid in the well.
2. The method according to claim 1 , wherein the portion of the fluid is a bottom portion of the fluid under a laboratory static aging test of 48 hours at the design temperature of the portion of the well.
3. The method according to claim 1 , wherein ρ j s for each of the components of the portion is selected to be anywhere within 10% of the ρ j i of each of the component of the fluid.
4. The method according to claim 1 , wherein ρ j s for each of the components of the portion is selected to be about equal to the ρ j i of each of the component of the fluid.
5. The method according to claim 1 , wherein the ratio of φ j s for each of the high-gravity solids to φ j s for the water phase is selected to be about equal to the ratio of φ j i for each of the high-gravity solids to φ j i for the water phase, respectively.
6. The method according to claim 1 , wherein φ j s for each of the low-gravity solids is selected to be anywhere in the range of 0.8 to 1.2 times of φ j i each of the low-gravity solids.
7. The method according to claim 1 , wherein φ j s for each of the low-gravity solids is selected to be about equal to φ j i for each of the low-gravity solids.
8. The method according to claim 1 , wherein the sum of φ j s for the water phase, φ j s for each of the high-gravity solids, and φ j s for each of the low-gravity solids is selected to be anywhere in the range of 0.60 to 0.70.
9. The method according to claim 1 , wherein the sum of φ j s for the water phase, φ j s for each of the high-gravity solids, and φ j s for each of the low-gravity solids is selected to be anywhere in the range of 0.63 to 0.68.
10. The method according to claim 1 , wherein the oil phase comprises crude oil, petroleum distillates, diesel, kerosene, diesel oils, crude oils, gas oils, fuel oils, paraffin oils, mineral oils, low toxicity mineral oils, other petroleum distillates, polyolefins, polydiorganosiloxanes, siloxanes, organosiloxanes, and any combination thereof.
11. The method according to claim 1 , wherein the water phase comprises a water-soluble salt or soluble liquid.
12. The method according to claim 11 , wherein the water-soluble salt is selected from the group consisting of: an alkali metal halide, alkaline earth halide, alkali metal formate, and any combination thereof.
13. The method according to claim 1 , wherein the one or more high-gravity solids each has a particle size distribution wherein 90% or more of the particles are anywhere in the range of 0.1 micrometer to 500 micrometers.
14. The method according to claim 1 , wherein the one or more high-gravity solids comprise barite.
15. The method according to claim 1 , wherein the one or more low-gravity solids each has a density greater than the density of the continuous oil phase as measured under standard laboratory conditions.
16. The method according to claim 1 , wherein the one or more low-gravity solids each has a particle size distribution wherein 90% or more of the particles are anywhere in the range of 0.1 micrometer to 500 micrometers.
17. The method according to claim 1 , wherein the step of determining or the step of predicting is performed with the aid of a computer device.
18. The method according to claim 1 , further comprising the step of circulating the fluid in the well at a fluid circulation rate of less than 100 ft/min.
19. The method according to claim 1 , further comprising the step of circulating the fluid in the well at a circulation rate of less than 100 ft/min or with a drill pipe rotation speed less than 100 RPM anywhere in the wellbore for at least 1 hour.
20. The method according to claim 1 , wherein the well bore inclination is in the range of 20° to 60° to the horizontal.
21. The method according to claim 11 , wherein the water-soluble salt is an inorganic salt.