CN115595127B - Deep water shallow gas hydrate multi-layer joint production drilling fluid system and hydrate inhibition performance regulation and control method - Google Patents
Deep water shallow gas hydrate multi-layer joint production drilling fluid system and hydrate inhibition performance regulation and control method Download PDFInfo
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- NMJORVOYSJLJGU-UHFFFAOYSA-N methane clathrate Chemical compound C.C.C.C.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O NMJORVOYSJLJGU-UHFFFAOYSA-N 0.000 title claims abstract description 160
- 239000012530 fluid Substances 0.000 title claims abstract description 145
- 238000005553 drilling Methods 0.000 title claims abstract description 116
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 title claims abstract description 81
- 230000005764 inhibitory process Effects 0.000 title claims abstract description 48
- 238000000034 method Methods 0.000 title claims abstract description 28
- 238000004519 manufacturing process Methods 0.000 title claims abstract description 26
- 230000033228 biological regulation Effects 0.000 title abstract description 7
- 238000000354 decomposition reaction Methods 0.000 claims abstract description 90
- 230000015572 biosynthetic process Effects 0.000 claims abstract description 49
- 239000003112 inhibitor Substances 0.000 claims abstract description 47
- HEMHJVSKTPXQMS-UHFFFAOYSA-M Sodium hydroxide Chemical compound [OH-].[Na+] HEMHJVSKTPXQMS-UHFFFAOYSA-M 0.000 claims abstract description 27
- FAPWRFPIFSIZLT-UHFFFAOYSA-M Sodium chloride Chemical compound [Na+].[Cl-] FAPWRFPIFSIZLT-UHFFFAOYSA-M 0.000 claims abstract description 20
- WCUXLLCKKVVCTQ-UHFFFAOYSA-M Potassium chloride Chemical compound [Cl-].[K+] WCUXLLCKKVVCTQ-UHFFFAOYSA-M 0.000 claims abstract description 18
- 239000003795 chemical substances by application Substances 0.000 claims abstract description 16
- 239000011248 coating agent Substances 0.000 claims abstract description 15
- 239000003638 chemical reducing agent Substances 0.000 claims abstract description 13
- 239000000706 filtrate Substances 0.000 claims abstract description 13
- 239000007788 liquid Substances 0.000 claims abstract description 11
- 239000000314 lubricant Substances 0.000 claims abstract description 11
- 239000011347 resin Substances 0.000 claims abstract description 11
- 229920005989 resin Polymers 0.000 claims abstract description 11
- 230000008901 benefit Effects 0.000 claims abstract description 10
- 239000011780 sodium chloride Substances 0.000 claims abstract description 10
- 229920000768 polyamine Polymers 0.000 claims abstract description 9
- 239000001103 potassium chloride Substances 0.000 claims abstract description 9
- 235000011164 potassium chloride Nutrition 0.000 claims abstract description 9
- 239000013535 sea water Substances 0.000 claims abstract description 9
- 239000000230 xanthan gum Substances 0.000 claims abstract description 9
- 229920001285 xanthan gum Polymers 0.000 claims abstract description 9
- 229940082509 xanthan gum Drugs 0.000 claims abstract description 9
- 235000010493 xanthan gum Nutrition 0.000 claims abstract description 9
- 239000002981 blocking agent Substances 0.000 claims abstract description 8
- 239000007789 gas Substances 0.000 claims description 160
- 239000012071 phase Substances 0.000 claims description 119
- 239000007791 liquid phase Substances 0.000 claims description 54
- 238000012546 transfer Methods 0.000 claims description 36
- 238000006243 chemical reaction Methods 0.000 claims description 33
- 238000009826 distribution Methods 0.000 claims description 27
- 239000011435 rock Substances 0.000 claims description 27
- 230000035699 permeability Effects 0.000 claims description 15
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 claims description 14
- 238000004140 cleaning Methods 0.000 claims description 12
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- 235000010948 carboxy methyl cellulose Nutrition 0.000 claims description 5
- 239000008112 carboxymethyl-cellulose Substances 0.000 claims description 5
- IIZPXYDJLKNOIY-JXPKJXOSSA-N 1-palmitoyl-2-arachidonoyl-sn-glycero-3-phosphocholine Chemical compound CCCCCCCCCCCCCCCC(=O)OC[C@H](COP([O-])(=O)OCC[N+](C)(C)C)OC(=O)CCC\C=C/C\C=C/C\C=C/C\C=C/CCCCC IIZPXYDJLKNOIY-JXPKJXOSSA-N 0.000 claims description 4
- 238000006073 displacement reaction Methods 0.000 claims description 4
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- 229940067606 lecithin Drugs 0.000 claims description 4
- LPMBTLLQQJBUOO-KTKRTIGZSA-N (z)-n,n-bis(2-hydroxyethyl)octadec-9-enamide Chemical compound CCCCCCCC\C=C/CCCCCCCC(=O)N(CCO)CCO LPMBTLLQQJBUOO-KTKRTIGZSA-N 0.000 claims description 3
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- 238000004781 supercooling Methods 0.000 claims description 3
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- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/02—Well-drilling compositions
- C09K8/04—Aqueous well-drilling compositions
- C09K8/06—Clay-free compositions
- C09K8/12—Clay-free compositions containing synthetic organic macromolecular compounds or their precursors
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- C—CHEMISTRY; METALLURGY
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- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/02—Well-drilling compositions
- C09K8/04—Aqueous well-drilling compositions
- C09K8/06—Clay-free compositions
- C09K8/08—Clay-free compositions containing natural organic compounds, e.g. polysaccharides, or derivatives thereof
- C09K8/10—Cellulose or derivatives thereof
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- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
- E21B41/0099—Equipment or details not covered by groups E21B15/00 - E21B40/00 specially adapted for drilling for or production of natural hydrate or clathrate gas reservoirs; Drilling through or monitoring of formations containing gas hydrates or clathrates
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- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
- C09K2208/22—Hydrates inhibition by using well treatment fluids containing inhibitors of hydrate formers
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Abstract
The invention relates to a deep water shallow gas hydrate multi-layer joint production drilling fluid system and a hydrate inhibition performance regulation method, which belong to the technical field of natural gas hydrate exploitation, wherein the drilling fluid system comprises the following components: sea water-based liquid, sodium hydroxide, filtrate reducer, tackifying coating agent, xanthan gum, polyamine, anti-balling lubricant, potassium chloride, sodium chloride, reservoir bridging agent, modified resin blocking agent, hydrate formation inhibitor and hydrate decomposition inhibitor, and under the conditions of wellbore temperature and pressure at different positions, the formation and decomposition inhibition performance of a drilling fluid system on natural gas hydrate is experimentally evaluated, and whether the natural gas hydrate is formed and decomposed is judged; when the horizontal complex well is drilled in the deep water weakly consolidated stratum, the method has the advantages of improving the working efficiency, reducing the well control risk, saving the drilling cost and the like, and the hydrate inhibition performance is obviously improved by applying the hydrate inhibition performance regulation method, so that the purposes of stabilizing the well wall and protecting the reservoir are achieved.
Description
Technical Field
The invention relates to a deep water shallow gas and hydrate multi-layer combined production drilling fluid system and a hydrate inhibition performance regulation and control method, and belongs to the technical field of natural gas hydrate exploitation.
Background
The natural gas hydrate is taken as an ideal substitute energy source in the 21 st century, has extremely high development and utilization value, and the natural gas hydrate reservoir is often provided with associated shallow gas, so that the water Ping Jingduo horizon combined mining technology can be realized, and the high-efficiency development of deep water shallow gas resources is realized. However, in deep water drilling, the drilling risk is high due to the fact that hydrate is easy to generate in a submarine shallow shaft, the stability of the well wall is poor, a drilling fluid safety density window is narrow, and the phase state of natural gas hydrate changes. Therefore, under the conditions of deep water, low temperature and high pressure, the drilling fluid has the advantages of no hydrate in a shaft, difficult generation, difficult decomposition of reservoir hydrate, no pollution, easy control of performance, good rheological property and lubricating property, strong blocking and inhibiting capability, strong stability of a well wall and the like. Due to the limitation of cost and technology, compared with developed countries, certain hysteresis exists in the related technology, so that how to realize deep water shallow gas and natural gas hydrate multi-layer combined production with maximum efficiency and minimum risk is an urgent problem in the field of natural gas exploration and development.
Disclosure of Invention
Aiming at the defects of the prior art, the invention provides a deep water shallow gas hydrate multi-layer joint production drilling fluid system and a hydrate inhibition performance regulation method. So as to fill the blank in the field of multi-layer combined production of deep water natural gas hydrate and shallow gas. The drilling fluid system can reduce well control risks to the greatest extent, reduce non-production time, improve economic benefit and maximize exploitation efficiency and economic benefit by inhibiting the decomposition of reservoir natural gas hydrate and the generation of shaft natural gas hydrate, maintaining well wall stability, reducing cost and the like.
The technical scheme of the invention is as follows:
a deep water shallow gas hydrate multi-layer joint production drilling fluid system, which comprises the following components: sea water-based liquid, sodium hydroxide, filtrate reducer, tackifying coating agent, xanthan gum, polyamine, anti-balling lubricant, potassium chloride, sodium chloride, reservoir bridging agent, modified resin blocking agent, hydrate formation inhibitor and hydrate decomposition inhibitor;
wherein, relative to 100 parts by weight of sea water-based liquid, the content of sodium hydroxide is 0.3 part by weight, the content of filtrate reducer is 2 parts by weight, the content of tackifying coating agent is 0.2 part by weight, the content of xanthan gum is 0.5 part by weight, the content of polyamine is 3 parts by weight, the content of anti-mud coating lubricant is 2 parts by weight, the content of potassium chloride is 5 parts by weight, the content of sodium chloride is 7 parts by weight, the content of reservoir bridging agent is 2 parts by weight, the content of modified resin plugging agent is 2 parts by weight, the content of hydrate formation inhibitor is 1 part by weight, and the content of hydrate decomposition inhibitor is 1 part by weight.
Preferably, the tackifying coating agent is low-viscosity carboxymethyl cellulose or low-viscosity polyanion cellulose, the anti-balling lubricant is fatty glyceride or oleic acid diethanolamide, the reservoir bridging agent is PF-EZCARRB, the modified resin blocking agent is PF-LSF, the hydrate formation inhibitor is any one of PVP, PVCap, VC713, and the hydrate decomposition inhibitor is any one of lecithin, PVP and PVCap.
The innovation point of the drilling fluid system is that a hydrate generation inhibitor and a hydrate decomposition inhibitor are added aiming at the characteristics of weak cementation, non-diagenetic and easy collapse of a hydrate reservoir. Compared with the traditional hydrate inhibitor (mainly referred to as thermodynamic generation inhibition), the addition of the hydrate generation inhibitor and the hydrate decomposition inhibitor can simultaneously inhibit the generation and the decomposition of the hydrate, namely, the hydrate decomposition of the reservoir can be prevented when the hydrate reservoir is drilled; the problem of blockage of hydrate generation in a shaft during drilling and mining of a shallow reservoir can be prevented, and finally multi-layer combined mining of deep water shallow gas and hydrate is realized.
Preferably, the filtrate reducer comprises PAC-LV and FLO, and the weight content ratio of the PAC-LV to the FLO is 1:3.
A method for regulating and controlling hydrate inhibition performance of a deep water shallow gas hydrate multi-layer joint production drilling fluid system comprises the following steps:
(1) Reading physical property data of current drilling parameters, shallow gas and natural gas hydrate reservoirs;
(2) Uniformly dividing cells in the drilling time, the well depth and the well periphery direction to form discrete grids;
(3) Respectively calculating the decomposition amount, the decomposition rate and the decomposition heat of the natural gas hydrate obtained in the natural gas hydrate reservoir;
(4) Establishing a fluid continuity equation, a momentum equation and an energy equation of a well annulus of a shallow gas and natural gas hydrate reservoir, and determining a temperature field distribution and a pressure field distribution of a well annulus and a Zhou Chu layer of a well;
(5) Under the conditions of shaft temperature and pressure at different well depth positions, the generation inhibition performance of the drilling fluid system on the natural gas hydrate is experimentally evaluated, and whether the natural gas hydrate is generated or not is judged;
(6) Experiment evaluation is carried out on the decomposition inhibition performance of the drilling fluid system on the natural gas hydrate under the conditions of temperature and pressure in porous media of reservoirs with different depths from the well wall, and whether the natural gas hydrate is decomposed or not is judged;
(7) If the natural gas hydrate in the well bore is generated or the natural gas hydrate in the reservoir is decomposed, adjusting the discharge capacity of the drilling fluid, the temperature of the drilling fluid and the concentration of the inhibitor, and repeating the steps (1) - (6) until the condition that the natural gas hydrate in the well bore is not generated and the natural gas hydrate in the reservoir is not decomposed is simultaneously satisfied.
Preferably, in step (1), the drilling parameters include: drilling fluid displacement, drilling fluid density, drilling fluid viscosity, drilling fluid constant pressure specific heat, drill rod inner diameter, drill bit diameter, well depth, well body structure, annulus fluid total heat transfer coefficient, drill rod fluid total heat transfer coefficient, well wall heat transfer coefficient and drilling time; reservoir physical property data include: the original temperature and pressure of the shallow gas reservoir, the relative permeability of the shallow gas reservoir, the rock density of the shallow gas reservoir, the constant pressure specific heat of the shallow gas rock, the effective heat conductivity coefficient of the shallow gas reservoir and the porosity of the shallow gas reservoir; the natural gas hydrate reservoir has the advantages of original temperature and pressure, relative permeability of the natural gas hydrate reservoir, rock density of the natural gas hydrate reservoir, constant pressure specific heat of the natural gas hydrate rock, effective heat conductivity coefficient of the natural gas hydrate reservoir and porosity of the natural gas hydrate reservoir.
Preferably, in the step (2), according to the drilling time, the time is divided into M cells, 1, 2 and 3 … M respectively; dividing N unit cells in the well depth direction into 1, 2 and 3 … N respectively; dividing K unit cells in the well circumferential direction into 1, 2 and 3 … K respectively; the divided cells are uniformly distributed.
Preferably, in the step (3), a natural gas hydrate phase balance model is established, the hydrate phase state is judged, and the decomposition amount, the decomposition rate and the decomposition heat of the natural gas hydrate are calculated;
Natural gas hydrate phase equilibrium model:
wherein: r is a gas constant, J/(mol.K); t is the system temperature, K; p is the system pressure, pa; v i Is the i-type pore number in the hydrate liquid phase molecule; θ ij Is the occupancy of the guest molecule j in the i-shaped hole, dimensionless and N c Is the amount of a hydrate-forming ingredient in the mixture; Δμ o Is the chemical potential difference between the water-rich phase and the pure water phase in the standard state; t (T) o And P o Is the temperature and pressure in the standard state, T under standard conditions o 273.15K, P o 0.1MPa; deltaH o Delta V and Delta C p Is the specific enthalpy difference, specific tolerance and specific heat difference between the rich water phase and the pure water phase; f (f) w The fugacity of water in the water-rich phase;the loss of pure water in reference states T and P;
natural gas hydrate decomposition rate model:
wherein M is h Is the molar mass of hydrate, kg/mol; k (k) d Is an intrinsic reaction constant of hydrate, and has a value of 2.6X10 5 m ol/(Pa·s·m 2 ) Delta E is the activation energy of the hydrate, the value of the Delta E is 104000J/mol, R is the gas constant, and J/(mol.K); t is the temperature, K; p is p eq The equilibrium pressure of the hydrate is MPa; p is p e Pore pressure, MPa, for hydrate formation; a is that h The specific surface area for decomposing the hydrate is calculated as follows:
wherein r is p An average particle size, m, of the reservoir matrix;porosity, dimensionless; s is S h Is hydrate saturation, dimensionless;
natural gas hydrate decomposition thermal model:
wherein P 'and T' are the pressure and temperature of hydrate formation/decomposition, MPa, K; ΔH d Is the heat of decomposition, kJ/mol; z is the gas compression coefficient, dimensionless;
natural gas hydrate formation rate model:
wherein M is g Is the average gas molar mass, g/mol; u is a coefficient representing the intensity of mass and heat transfer, dimensionless; k (K) 1 And K 2 Is a kinetic parameter, K 1 ＝2.608×10 16 kg/(m 2 Ks)，K 2 ＝-13600K；T s Is the system temperature, K; t (T) sub Is the degree of thermodynamic supercooling,k, which is defined as the difference between the equilibrium temperature of the hydrate and the temperature of the system: t (T) sub ＝T eq -T s ；T eq The equilibrium temperature, K, of hydrate formation at system pressure; a is that s Is the gas-liquid contact area m when the hydrate is generated 2 ；
Natural gas hydrate generation thermal model:
ΔH c heat release rate for hydrate formation, W/m 3 。
Preferably, in step (4), the fluid mass conservation equation in the wellbore is established as:
gas phase:
wherein A is a Is the annulus area, m2; e (E) g Is the gas phase volume fraction, dimensionless; ρ g Is the gas density, kg/m3; t is drilling time, s; u (u) g Is the gas velocity, m/s; z is the depth from the wellhead position, m;kg/(m·s) for drill cuttings hydrate phase to gas phase mass transfer rate; / >Kg/(m·s) for the wellbore fluid hydrate phase to gas phase mass transfer rate; />Kg/(m.s) for the gas phase to wellbore fluid hydrate phase mass transfer rate; q g Kg/(m·s) is the gas mass inflow rate;
liquid phase:
wherein E is l Is the liquid phase volume fraction, dimensionless; ρ l Is the density of liquid phase, kg/m3; u (u) l Is the liquid phase speed, m/s;kg/(m·s) is the drill cuttings hydrate phase to liquid phase mass transfer rate; />Kg/(m·s) for the wellbore fluid hydrate phase to liquid phase mass transfer rate; />Kg/(m·s) for the mass transfer rate of the liquid phase to the wellbore fluid hydrate phase;
and (3) rock debris phase:
wherein E is c Is the volume fraction of the rock debris phase, and has no dimension; ρ c The density of the rock debris phase is kg/m3; u (u) c Is the phase velocity of rock debris, m/s;the rate of decomposition of the hydrate in the rock debris is kg/(m.s);
hydrate phase:
wherein E is h Is the volume fraction of the hydrate phase, dimensionless; ρ h Is hydrate phase density, kg/m3; u (u) h Is hydrate phase velocity, m/s;is hydrate in wellbore fluidRate of phase decomposition, kg/(m·s);
establishing a wellbore annulus internal momentum equation, and calculating to obtain annulus pressure field distribution:
wherein p is a Is annular pressure, MPa; f is friction coefficient, dimensionless; ρ m The annular mixing density is kg/m3; u (u) m Is the annulus mixing flow rate, m/s; d (D) a Is the hydraulic diameter of the annulus, m; g is gravity acceleration, m/s2; θ is the angle of well deviation, degree.
Preferably, in step (4), a wellbore annulus fluid temperature field equation is established:
wherein T is a 、T p 、T e The temperature K of the well bore annulus, the drill pipe and the stratum fluid is respectively; r is (r) pi 、r ci The inner diameters of a drill rod and a casing pipe are respectively m; u (U) p 、U a W/(m2.K) is the total heat transfer coefficient in the well bore annulus and the drill rod;kg/(m.s) is the total decomposition rate of the hydrate; ΔH h J/kg is the heat of decomposition of the hydrate.
Preferably, in the step (4), reservoir fluid pressure field distribution is calculated according to a fluid continuity equation and a momentum equation in the natural gas hydrate reservoir and the shallow gas reservoir:
the fluid in the porous medium of the natural gas hydrate reservoir comprises drilling fluid, hydrate decomposition liquid phase and hydrate decomposition gas phase, and the gas phase velocity u in the porous medium of the reservoir is obtained through calculation of a gas phase continuity equation g Distribution:
calculating to obtain the liquid phase velocity u in the porous medium of the natural gas hydrate reservoir through a liquid phase continuity equation w Distribution:
wherein,is porosity, dimensionless; ρ w And ρ g Density of water and gas, kg/m 3 ，S w And S is g Saturation of water and gas, respectively; u (u) w And u g The speeds of water and gas, m/s, respectively; t is drilling time, s; / >And->Mass transfer rate of hydrate to water and gas, kg/(m) 3 ·s)；
Equation of pressure field in natural gas hydrate reservoir:
wherein k is the absolute permeability of the hydrate layer, is closely related to the pore structure and the saturation of the hydrate, and increases exponentially with the decomposition of the hydrate, m 2 ；k rw And k rg Is the relative permeability of water and gas in the porous medium, and is generally calculated using a stone model, and the capillary pressure is generally calculated using a VG (VanGenuchten) model; p is p w And p g Is the pressure of liquid phase and gas phase, pa；μ w Sum mu g The viscosities of water and gas, pa.s, respectively;
the fluid in the shallow porous medium comprises drilling fluid and shallow gas phase, and the gas phase speed u in the reservoir porous medium is obtained through calculation of a continuity equation sg And liquid phase velocity u sl Distribution:
and calculating to obtain the pressure field distribution in the porous medium of the shallow gas reservoir through a continuity equation:
wherein ρ is sg And ρ sl Density of gas phase and liquid phase, kg/m 3 ；u sg And u sl The flow rates of the gas phase and the liquid phase, m/s respectively; k (k) rsl And k rsg Relative permeabilities of the gas and liquid phases, respectively; mu (mu) sg Sum mu sl The viscosities of the gas phase and the liquid phase are Pa.s respectively; p is p sg And p sl The pressure of the gas phase and the liquid phase are respectively MPa.
Further preferably, in step (4), the distribution of the fluid temperature fields in the shallow gas and natural gas hydrate reservoirs is calculated according to the fluid energy equation in the reservoirs;
Equation of energy in natural gas hydrate reservoir:
energy equation in shallow gas reservoir:
in (ρC) eff Representing the effective product of fluid density and specific heat capacity in the formation, J/(m) 3 ·℃)；C w And C g The specific heat capacities of water and gas, J/(kg. DEG C), respectively; k (k) eff Indicating the effective thermal conductivity, w/(m·deg.C), of the fluid in the formation; q (Q) h J/(m) for decomposition heat of hydrate 3 ·s)，Q s J/(m) is the decomposition heat of superficial gas 3 ·s)。
Preferably, in the step (5), according to the wellbore temperature and pressure at different well depth positions calculated in the step (4), the inhibition performance of the drilling fluid system on the generation of the natural gas hydrate at the temperature and the pressure is experimentally evaluated, and whether the generation of the natural gas hydrate exists is judged, and the hydrate inhibition evaluation method comprises the following steps:
(5-1) opening the high-pressure reaction kettle and cleaning the inner wall, and preparing a solvent required by an experiment;
(5-2) opening the gas line and the methane cylinder, pressurizing by a gas pressurizing means, and increasing the pressure to 20MPa;
(5-3) adding an experimental solvent into the high-pressure reaction kettle, and screwing up a valve of the high-pressure device;
(5-4) turning on a vacuum pump, and vacuumizing for 15 minutes to reduce the pressure in the reaction kettle to minus 0.09MPa;
(5-5) opening a hydrate window for capturing, opening a pressurizing valve, injecting 14MPa pressure into the high-pressure reaction kettle, and simultaneously opening temperature control and stirring;
(5-6) after the temperature and the pressure are stable, carrying out pressure compensation again to ensure that the pressure in the reaction kettle is kept at 14MPa when the constant-speed cooling is started;
(5-7) observing turbidity of the solution in the kettle through a window, and simultaneously recording change of a temperature-pressure curve in the kettle, wherein when the solution in the kettle becomes turbid, or the temperature curve suddenly rises and the pressure curve suddenly drops, the hydrate is formed.
(5-8) comparing the formation temperature and pressure with the hydrate formation curve under pure water conditions, the lower the temperature is, the better the hydrate formation inhibition is;
(5-9) closing the pipeline valve and the gas cylinder, cleaning the experimental instrument and placing the experimental instrument in order.
Preferably, in the step (6), according to the temperature and pressure conditions in the porous medium of the reservoir with different depths from the well wall calculated in the step (4), the decomposition inhibition performance of the drilling fluid system on the natural gas hydrate at the temperature and the pressure is experimentally evaluated, and whether the natural gas hydrate is decomposed or not is judged, and the hydrate decomposition inhibition evaluation method comprises the following steps:
(6-1) opening the high-pressure reaction kettle and cleaning the inner wall, and preparing a solvent required by an experiment;
(6-2) opening the gas line and the methane cylinder, pressurizing by a gas pressurizing means, and increasing the pressure to 20MPa;
(6-3) adding pure water into the high-pressure reaction kettle, and screwing up a valve of the high-pressure device;
(6-4) turning on a vacuum pump, and vacuumizing for 15 minutes to reduce the pressure in the reaction kettle to minus 0.09MPa;
(6-5) opening a hydrate window for capturing, opening a pressurizing valve, injecting 14MPa pressure into the high-pressure reaction kettle, and simultaneously opening temperature control and stirring;
(6-6) after the temperature and the pressure are stable, carrying out pressure compensation again to ensure that the pressure in the reaction kettle is kept at 14Mpa when the constant-speed cooling is started;
(6-7) observing turbidity conditions of the solution in the kettle through a window, simultaneously recording change of a temperature-pressure curve in the kettle, and when the solution in the kettle becomes turbid or the temperature curve suddenly rises or the pressure curve suddenly drops, treating the solution as hydrate generation, and treating the solution as hydrate after the temperature-pressure is maintained for 30 minutes;
(6-8) injecting an experimental solvent into the kettle, and recording the temperature and pressure change in the kettle;
(6-9) comparing the formation temperature and pressure curve with the hydrate formation curve under pure water conditions, and considering that the lower the pressure in the autoclave is under the same temperature conditions, the better the decomposition inhibition is.
(6-10) closing the pipeline valve and the gas cylinder, cleaning the experimental instrument and placing the experimental instrument in order.
Preferably, in the step (7), if the natural gas hydrate of the shaft is generated, the discharge amount of the drilling fluid is increased, the temperature of the drilling fluid is increased, and the concentration of the inhibitor is increased; if the natural gas hydrate in the reservoir is decomposed, contrary to the generation, reducing the discharge of the drilling fluid, reducing the temperature of the drilling fluid and the concentration of the inhibitor, and repeating the steps (1) - (6) until the condition that the natural gas hydrate in the well bore is not generated and the natural gas hydrate in the reservoir is not decomposed is simultaneously satisfied.
The invention has the beneficial effects that:
1. when the horizontal complex well is drilled in the deep water weakly consolidated stratum, the method has the advantages of improving the working efficiency, reducing the well control risk, saving the drilling cost and the like, and the hydrate inhibition performance is obviously improved by applying the hydrate inhibition performance regulation method, so that the purposes of stabilizing the well wall and protecting the reservoir are achieved.
2. The drilling fluid system has good high temperature resistance, lubricity and inhibition, can meet various requirements of horizontal complex wells on shallow gas and natural gas hydrate joint production to the greatest extent, and realizes safe and efficient multi-layer joint production while protecting a reservoir.
3. The drilling fluid system is used as a water-based strong-inhibition environment-friendly drilling fluid system, has low cost, sufficient raw material sources and controllable drilling fluid performance, has a very remarkable effect on multi-layer joint production of a deep water drilling horizontal well, can relieve the dependency of China on energy sources to a certain extent, has very good economic benefit and social benefit, and is worthy of popularization and application.
Drawings
FIG. 1 shows the temperature and pressure parameter variation of the whole process of an inhibitor PVCap precursor system;
fig. 2 shows the overall temperature and pressure parameter variation of the system after addition of the inhibitor PVCap.
Detailed Description
The invention will now be further illustrated by way of example, but not by way of limitation, with reference to the accompanying drawings.
Example 1:
a deep water shallow gas hydrate multi-layer joint production drilling fluid system, which comprises the following components: sea water-based liquid, sodium hydroxide, filtrate reducer, tackifying coating agent, xanthan gum, polyamine, anti-balling lubricant, potassium chloride, sodium chloride, reservoir bridging agent, modified resin blocking agent, hydrate formation inhibitor and hydrate decomposition inhibitor;
wherein, relative to 100 parts by weight of sea water-based liquid, the content of sodium hydroxide is 0.3 part by weight, the content of filtrate reducer is 2 parts by weight, the content of tackifying coating agent is 0.2 part by weight, the content of xanthan gum is 0.5 part by weight, the content of polyamine is 3 parts by weight, the content of anti-mud coating lubricant is 2 parts by weight, the content of potassium chloride is 5 parts by weight, the content of sodium chloride is 7 parts by weight, the content of reservoir bridging agent is 2 parts by weight, the content of modified resin plugging agent is 2 parts by weight, the content of hydrate formation inhibitor is 1 part by weight, and the content of hydrate decomposition inhibitor is 1 part by weight.
The tackifying coating agent is low-viscosity carboxymethyl cellulose or low-viscosity polyanion cellulose, the anti-balling lubricant is fatty glyceride or oleic acid diethanolamide, the reservoir bridging agent is PF-EZCARB, the modified resin blocking agent is PF-LSF, the hydrate generation inhibitor is PVP, PVCap, VC713, the hydrate decomposition inhibitor is lecithin, PVP or PVCap, and the filtrate reducer comprises PAC-LV and FLO, wherein the weight content ratio of the two is 1:3.
Example 2:
a method for regulating and controlling hydrate inhibition performance of a deep water shallow gas hydrate multi-layer joint production drilling fluid system comprises the following steps:
(1) Reading physical property data of current drilling parameters, shallow gas and natural gas hydrate reservoirs;
the drilling parameters include: drilling fluid displacement, drilling fluid density, drilling fluid viscosity, drilling fluid constant pressure specific heat, drill rod inner diameter, drill bit diameter, well depth, well body structure, annulus fluid total heat transfer coefficient, drill rod fluid total heat transfer coefficient, well wall heat transfer coefficient and drilling time; reservoir physical property data include: the original temperature and pressure of the shallow gas reservoir, the relative permeability of the shallow gas reservoir, the rock density of the shallow gas reservoir, the constant pressure specific heat of the shallow gas rock, the effective heat conductivity coefficient of the shallow gas reservoir and the porosity of the shallow gas reservoir; the natural gas hydrate reservoir has the advantages of original temperature and pressure, relative permeability of the natural gas hydrate reservoir, rock density of the natural gas hydrate reservoir, constant pressure specific heat of the natural gas hydrate rock, effective heat conductivity coefficient of the natural gas hydrate reservoir and porosity of the natural gas hydrate reservoir.
(2) Uniformly dividing cells in the drilling time, the well depth and the well periphery direction to form discrete grids;
dividing the time into M cells according to the drilling time, wherein the M cells are 1, 2 and 3 … M respectively; dividing N unit cells in the well depth direction into 1, 2 and 3 … N respectively; dividing K unit cells in the well circumferential direction into 1, 2 and 3 … K respectively; the divided cells are uniformly distributed.
(3) Respectively calculating the decomposition amount, the decomposition rate and the decomposition heat of the natural gas hydrate obtained in the natural gas hydrate reservoir;
establishing a natural gas hydrate phase balance model, judging the phase state of the hydrate, and calculating to obtain the decomposition amount, the decomposition rate and the decomposition heat of the natural gas hydrate;
natural gas hydrate phase equilibrium model:
wherein: r is a gas constant, J/(mol.K); t is the system temperature, K; p is the system pressure, pa; v i Is the i-type pore number in the hydrate liquid phase molecule; θ ij Is the occupancy of the guest molecule j in the i-shaped hole, dimensionless and N c Is the amount of a hydrate-forming ingredient in the mixture; Δμ o Is the chemical potential difference between the water-rich phase and the pure water phase in the standard state; t (T) o And P o Is the temperature and pressure in the standard state, T under standard conditions o 273.15K, P o 0.1MPa; deltaH o Delta V and Delta C p Is the specific enthalpy difference, specific tolerance and specific heat difference between the rich water phase and the pure water phase; f (f) w The fugacity of water in the water-rich phase;the loss of pure water in reference states T and P;
natural gas hydrate decomposition rate model:
wherein M is h Is the molar mass of hydrate, kg/mol; k (k) d Is an intrinsic reaction constant of hydrate, and has a value of 2.6X10 5 mol/(Pa·s·m 2 ) Delta E is the activation energy of the hydrate, the value of the Delta E is 104000J/mol, R is the gas constant, and J/(mol.K); t is the temperature, K; p is p eq The equilibrium pressure of the hydrate is MPa; p is p e Pore pressure, MPa, for hydrate formation; a is that h The specific surface area for decomposing the hydrate is calculated as follows:
wherein r is p An average particle size, m, of the reservoir matrix;porosity, dimensionless; s is S h Is hydrate saturation, dimensionless;
natural gas hydrate decomposition thermal model:
wherein P 'and T' are the pressure and temperature of hydrate formation/decomposition, MPa, K; ΔH d Is the heat of decomposition, kJ/mol; z is the gas compression coefficient, dimensionless;
natural gas hydrate formation rate model:
wherein M is g Is the average gas molar mass, g/mol; u is a representationThe coefficient of mass and heat transfer intensity, dimensionless; k (K) 1 And K 2 Is a kinetic parameter, K 1 ＝2.608×10 16 kg/(m 2 Ks)，K 2 ＝-13600K；T s Is the system temperature, K; t (T) sub Is the thermodynamic supercooling degree, K, defined as the difference between the equilibrium temperature of the hydrate and the system temperature: t (T) sub ＝T eq -T s ；T eq The equilibrium temperature, K, of hydrate formation at system pressure; a is that s Is the gas-liquid contact area m when the hydrate is generated 2 ；
Natural gas hydrate generation thermal model:
ΔH c heat release rate for hydrate formation, W/m 3 。
Preferably, in step (4), the fluid mass conservation equation in the wellbore is established as:
gas phase:
wherein A is a Is the annulus area, m2; e (E) g Is the gas phase volume fraction, dimensionless; ρ g Is the gas density, kg/m3; t is drilling time, s; u (u) g Is the gas velocity, m/s; z is the depth from the wellhead position, m;kg/(m·s) for drill cuttings hydrate phase to gas phase mass transfer rate; />Kg/(m·s) for the wellbore fluid hydrate phase to gas phase mass transfer rate; />In the form of gas phase to wellbore fluid waterMass transfer rate of the compound phase, kg/(m·s); q g Kg/(m·s) is the gas mass inflow rate;
liquid phase:
wherein E is l Is the liquid phase volume fraction, dimensionless; ρ l Is the density of liquid phase, kg/m3; u (u) l Is the liquid phase speed, m/s;kg/(m·s) is the drill cuttings hydrate phase to liquid phase mass transfer rate; />Kg/(m·s) for the wellbore fluid hydrate phase to liquid phase mass transfer rate; />Kg/(m·s) for the mass transfer rate of the liquid phase to the wellbore fluid hydrate phase;
and (3) rock debris phase:
wherein E is c Is the volume fraction of the rock debris phase, and has no dimension; ρ c The density of the rock debris phase is kg/m3; u (u) c Is the phase velocity of rock debris, m/s;the rate of decomposition of the hydrate in the rock debris is kg/(m.s);
hydrate phase:
wherein E is h Is the volume fraction of the hydrate phase, dimensionless; ρ h Is hydrate phase density, kg/m3; u (u) h Is hydrate phase velocity, m/s;kg/(m.s) is the rate of hydrate phase decomposition in the wellbore fluid;
Establishing a wellbore annulus internal momentum equation, and calculating to obtain annulus pressure field distribution:
wherein p is a Is annular pressure, MPa; f is friction coefficient, dimensionless; ρ m The annular mixing density is kg/m3; u (u) m Is the annulus mixing flow rate, m/s; d (D) a Is the hydraulic diameter of the annulus, m; g is gravity acceleration, m/s2; θ is the angle of well deviation, degree.
(4) Establishing a fluid continuity equation, a momentum equation and an energy equation of a well annulus of a shallow gas and natural gas hydrate reservoir, and determining a temperature field distribution and a pressure field distribution of a well annulus and a Zhou Chu layer of a well;
in the step (4), establishing a well annulus fluid temperature field equation:
wherein T is a 、T p 、T e The temperature K of the well bore annulus, the drill pipe and the stratum fluid is respectively; r is (r) pi 、r ci The inner diameters of a drill rod and a casing pipe are respectively m; u (U) p 、U a W/(m2.K) is the total heat transfer coefficient in the well bore annulus and the drill rod;kg/(m.s) is the total decomposition rate of the hydrate; ΔH h J/kg is the heat of decomposition of the hydrate.
Calculating reservoir fluid pressure field distribution according to fluid continuity equations and momentum equations in natural gas hydrate reservoirs and shallow gas reservoirs:
the fluid in the porous medium of the natural gas hydrate reservoir comprises drilling fluid, hydrate decomposition liquid phase and hydrate decomposition gas phase, and the gas phase velocity u in the porous medium of the reservoir is obtained through calculation of a gas phase continuity equation g Distribution:
calculating to obtain the liquid phase velocity u in the porous medium of the natural gas hydrate reservoir through a liquid phase continuity equation w Distribution:
wherein,is porosity, dimensionless; ρ w And ρ g Density of water and gas, kg/m 3 ，S w And S is g Saturation of water and gas, respectively; u (u) w And u g The speeds of water and gas, m/s, respectively; t is drilling time, s; />And->Mass transfer rate of hydrate to water and gas, kg/(m) 3 ·s)；
Equation of pressure field in natural gas hydrate reservoir:
/>
wherein k is the absolute permeability of the hydrate layer, is closely related to the pore structure and the saturation of the hydrate, and increases exponentially with the decomposition of the hydrate, m 2 ；k rw And k rg Is the relative permeability of water and gas in the porous medium, and is generally calculated using a stone model, and the capillary pressure is generally calculated using a VG (VanGenuchten) model; p is p w And p g Is the pressure of liquid phase and gas phase, pa; mu (mu) w Sum mu g The viscosities of water and gas, pa.s, respectively;
the fluid in the shallow porous medium comprises drilling fluid and shallow gas phase, and the gas phase speed u in the reservoir porous medium is obtained through calculation of a continuity equation sg And liquid phase velocity u sl Distribution:
and calculating to obtain the pressure field distribution in the porous medium of the shallow gas reservoir through a continuity equation:
Wherein ρ is sg And ρ sl Density of gas phase and liquid phase, kg/m 3 ；u sg And u sl The flow rates of the gas phase and the liquid phase, m/s respectively; k (k) rsl And k rsg Relative permeabilities of the gas and liquid phases, respectively; mu (mu) sg Sum mu sl The viscosities of the gas phase and the liquid phase are Pa.s respectively; p is p sg And p sl The pressure of the gas phase and the liquid phase are respectively MPa.
Calculating the distribution of fluid temperature fields in the shallow gas and natural gas hydrate reservoir according to a fluid energy equation in the reservoir;
equation of energy in natural gas hydrate reservoir:
energy equation in shallow gas reservoir:
in (ρC) eff Representing the effective product of fluid density and specific heat capacity in the formation, J/(m) 3 ·℃)；C w And C g The specific heat capacities of water and gas, J/(kg. DEG C), respectively; k (k) eff Indicating the effective thermal conductivity, w/(m·deg.C), of the fluid in the formation; q (Q) h J/(m) for decomposition heat of hydrate 3 ·s)，Q s J/(m) is the decomposition heat of superficial gas 3 ·s)。
(5) Under the conditions of shaft temperature and pressure at different well depth positions, the generation inhibition performance of the drilling fluid system on the natural gas hydrate is experimentally evaluated, and whether the natural gas hydrate is generated or not is judged;
in the step (5), according to the wellbore temperature and pressure at different well depth positions calculated in the step (4), the generation inhibition performance of the drilling fluid system on the natural gas hydrate at the temperature and the pressure is experimentally evaluated, and whether the natural gas hydrate is generated or not is judged, wherein the hydrate inhibition evaluation method comprises the following steps:
(5-1) opening the high-pressure reaction kettle and cleaning the inner wall, and preparing a solvent required by an experiment;
(5-2) opening the gas line and the methane cylinder, pressurizing by a gas pressurizing means, and increasing the pressure to 20MPa;
(5-3) adding an experimental solvent into the high-pressure reaction kettle, and screwing up a valve of the high-pressure device;
(5-4) turning on a vacuum pump, and vacuumizing for 15 minutes to reduce the pressure in the reaction kettle to minus 0.09MPa;
(5-5) opening a hydrate window for capturing, opening a pressurizing valve, injecting 14MPa pressure into the high-pressure reaction kettle, and simultaneously opening temperature control and stirring;
(5-6) after the temperature and the pressure are stable, carrying out pressure compensation again to ensure that the pressure in the reaction kettle is kept at 14MPa when the constant-speed cooling is started;
(5-7) observing turbidity of the solution in the kettle through a window, and simultaneously recording change of a temperature-pressure curve in the kettle, wherein when the solution in the kettle becomes turbid, or the temperature curve suddenly rises and the pressure curve suddenly drops, the hydrate is formed.
(5-8) comparing the formation temperature and pressure with the hydrate formation curve under pure water conditions, the lower the temperature is, the better the hydrate formation inhibition is;
(5-9) closing the pipeline valve and the gas cylinder, cleaning the experimental instrument and placing the experimental instrument in order.
(6) Experiment evaluation is carried out on the decomposition inhibition performance of the drilling fluid system on the natural gas hydrate under the conditions of temperature and pressure in porous media of reservoirs with different depths from the well wall, and whether the natural gas hydrate is decomposed or not is judged;
In the step (6), according to the temperature and pressure conditions in the porous medium of the reservoir with different depths from the well wall calculated in the step (4), the decomposition inhibition performance of the drilling fluid system on the natural gas hydrate at the temperature and the pressure is experimentally evaluated, and whether the natural gas hydrate is decomposed or not is judged, and the hydrate decomposition inhibition evaluation method comprises the following steps:
(6-1) opening the high-pressure reaction kettle and cleaning the inner wall, and preparing a solvent required by an experiment;
(6-2) opening the gas line and the methane cylinder, pressurizing by a gas pressurizing means, and increasing the pressure to 20MPa;
(6-3) adding pure water into the high-pressure reaction kettle, and screwing up a valve of the high-pressure device;
(6-4) turning on a vacuum pump, and vacuumizing for 15 minutes to reduce the pressure in the reaction kettle to minus 0.09MPa;
(6-5) opening a hydrate window for capturing, opening a pressurizing valve, injecting 14MPa pressure into the high-pressure reaction kettle, and simultaneously opening temperature control and stirring;
(6-6) after the temperature and the pressure are stable, carrying out pressure compensation again to ensure that the pressure in the reaction kettle is kept at 14Mpa when the constant-speed cooling is started;
(6-7) observing turbidity conditions of the solution in the kettle through a window, simultaneously recording change of a temperature-pressure curve in the kettle, and when the solution in the kettle becomes turbid or the temperature curve suddenly rises or the pressure curve suddenly drops, treating the solution as hydrate generation, and treating the solution as hydrate after the temperature-pressure is maintained for 30 minutes;
(6-8) injecting an experimental solvent into the kettle, and recording the temperature and pressure change in the kettle;
(6-9) comparing the formation temperature and pressure curve with the hydrate formation curve under pure water conditions, and considering that the lower the pressure in the autoclave is under the same temperature conditions, the better the decomposition inhibition is.
(6-10) closing the pipeline valve and the gas cylinder, cleaning the experimental instrument and placing the experimental instrument in order.
(7) If the natural gas hydrate in the well bore is generated or the natural gas hydrate in the reservoir is decomposed, adjusting the discharge capacity of the drilling fluid, the temperature of the drilling fluid and the concentration of the inhibitor, and repeating the steps (1) - (6) until the condition that the natural gas hydrate in the well bore is not generated and the natural gas hydrate in the reservoir is not decomposed is simultaneously satisfied.
In the step (7), if the natural gas hydrate of the shaft is generated, the discharge capacity of the drilling fluid is increased, the temperature of the drilling fluid is increased, and the concentration of the inhibitor is increased; if the natural gas hydrate in the reservoir is decomposed, contrary to the generation, reducing the discharge of the drilling fluid, reducing the temperature of the drilling fluid and the concentration of the inhibitor, and repeating the steps (1) - (6) until the condition that the natural gas hydrate in the well bore is not generated and the natural gas hydrate in the reservoir is not decomposed is simultaneously satisfied.
Experimental example 1:
deep water shallow gas hydrate multi-layer joint production drilling fluid system preparation and rheological property test
(1) Laboratory formulation system 1 drilling fluid:
400 ml of seawater is measured by a measuring cylinder and placed in a slurry cup, and 1.2g of sodium hydroxide, 2g of filtrate reducer (PAC-LV), 6g of filtrate reducer (FLO), 0.8g of tackifying coating agent (low-viscosity carboxymethyl cellulose), 2g of xanthan gum, 12g of polyamine, 20g of potassium chloride, 28g of sodium chloride, 8g of reservoir bridging agent (PF-EZCARB), 8g of modified resin blocking agent (PF-LSF), 4g of formation inhibitor (PVP) and 4g of decomposition inhibitor (lecithin) are sequentially added under stirring at the rotating speed of 11000 r/min.
(2) Laboratory formulation system 2 drilling fluid:
the drilling fluid is prepared by adopting the method of (1), except that no inhibitor is added.
(3) Laboratory formulation system 3 drilling fluid:
400 ml of seawater is measured by a measuring cylinder and placed in a slurry cup, and 1.2g of sodium hydroxide, 2g of filtrate reducer (PAC-LV), 6g of filtrate reducer (FLO), 0.8g of tackifying coating agent (low-viscosity carboxymethyl cellulose), 2g of xanthan gum, 12g of polyamine, 8g of anti-balling lubricant (fatty acid glyceride), 20g of potassium chloride, 28g of sodium chloride, 8g of reservoir bridging agent (PF-EZCARB), 8g of modified resin blocking agent (PF-LSF), 4g of decomposition inhibitor (PVP) and 4g of formation inhibitor (PVCap) are sequentially added under stirring at the rotating speed of 11000 r/min.
(4) Laboratory formulation system 4 drilling fluid:
The drilling fluid is prepared by adopting the method of (3), except that sodium chloride is not added.
Rheological property test:
according to the formula of the system 1-4, each component is stirred at a high speed for more than 1h, the drilling fluid system 1 to the drilling fluid system 5 are obtained by uniformly mixing, and the performance parameters are tested by respectively hot rolling for 16h at 180K, and the parameter test results are shown in Table 1.
TABLE 1 results of Performance parameter tests for systems 1-4
The G10 "/10' parameter is the ratio of final cut to initial cut, the value of which is measured with a six-speed rotational viscometer ZNN-D6B, with reference to GB/T161782-1997.
As can be seen from Table 1, system 3 has good rheology and lubricity and the overall system performance is stable.
Experimental example 2: inhibition performance test for deep water shallow gas hydrate multi-layer joint production drilling fluid system
The drilling fluid system 3 is subjected to hydrate formation inhibition evaluation experiments, the parameter changes of the whole process temperature and pressure of the HEM system before and after inhibitor addition are made by using computer software, the calculation results are shown in fig. 1 and 2, the highest line is the gas molar quantity in fig. 1 and 2, and the lowest line is the jacket temperature.
As can be seen by comparing fig. 1 and fig. 2, under the condition of simulated well shut-in, i.e. in the process that the liquid temperature is reduced to the set reservoir temperature, some additives or salt inhibitors in the original drilling fluid will fail due to low temperature, thereby causing a large amount of hydrate to be generated and accumulated, and the hydrate is represented as obvious fluctuation of the gas phase temperature in fig. 1; however, after the hydrate inhibitor is added, the system inhibition performance is still better due to the synergistic effect between the agents, and the hydrate is not obviously generated, and the gas phase temperature is not fluctuated in fig. 2. When the well is restarted after simulated well closing (when the torque is 0, the well is closed, when the torque is recovered from 0, the well is restarted), the low-temperature drilling fluid system without the inhibitor is greatly increased in torque and then is recovered to be stable due to the fact that the hydrate structure is required to be destroyed, and meanwhile, the process is accompanied with the decomposition of the hydrate caused by physical action, and the process is gradually recovered to be stable after the gas phase temperature is greatly increased in the graph of fig. 1; however, as can be seen from comparison of FIG. 1, after the hydrate inhibitor is added, no large amount of hydrate is generated in the system, and the system torque is not greatly affected, so that the gas phase temperature is basically unchanged as can be seen in FIG. 2.
From this, it can be derived that: the inhibitor in the drilling fluid system 3 can effectively inhibit the generation and decomposition of the hydrate. Namely, the deep water shallow gas and hydrate multi-layer joint production drilling fluid system has very good capability of inhibiting the generation and decomposition of natural gas hydrate.
Claims (7)
1. A method for regulating and controlling hydrate inhibition performance of a deep water shallow gas hydrate multi-layer joint production drilling fluid system comprises the following components: sea water-based liquid, sodium hydroxide, filtrate reducer, tackifying coating agent, xanthan gum, polyamine, anti-balling lubricant, potassium chloride, sodium chloride, reservoir bridging agent, modified resin blocking agent, hydrate formation inhibitor and hydrate decomposition inhibitor;
wherein, relative to 100 parts by weight of sea water-based liquid, the content of sodium hydroxide is 0.3 part by weight, the content of filtrate reducer is 2 parts by weight, the content of tackifying coating agent is 0.2 part by weight, the content of xanthan gum is 0.5 part by weight, the content of polyamine is 3 parts by weight, the content of anti-mud coating lubricant is 2 parts by weight, the content of potassium chloride is 5 parts by weight, the content of sodium chloride is 7 parts by weight, the content of reservoir bridging agent is 2 parts by weight, the content of modified resin plugging agent is 2 parts by weight, the content of hydrate formation inhibitor is 1 part by weight, and the content of hydrate decomposition inhibitor is 1 part by weight;
The method is characterized by comprising the following steps:
(1) Reading physical property data of current drilling parameters, shallow gas and natural gas hydrate reservoirs;
(2) Uniformly dividing cells in the drilling time, the well depth and the well periphery direction to form discrete grids;
(3) Respectively calculating the decomposition amount, the decomposition rate and the decomposition heat of the natural gas hydrate obtained in the natural gas hydrate reservoir;
in the step (3), a natural gas hydrate phase balance model is established, the hydrate phase state is judged, and the natural gas hydrate decomposition amount, the natural gas hydrate decomposition rate and the natural gas hydrate decomposition heat are calculated;
natural gas hydrate phase equilibrium model:
wherein: r is a gas constant, J/(mol.K); t is the system temperature, K; p is the system pressure, pa; v i Is the i-type pore number in the hydrate liquid phase molecule; θ ij Is the occupancy of the guest molecule j in the i-shaped hole, dimensionless and N c Is the amount of a hydrate-forming ingredient in the mixture; Δμ o Is the chemical potential difference between the water-rich phase and the pure water phase in the standard state; t (T) o And P o Is the temperature and pressure in the standard state, T under standard conditions o 273.15K, P o 0.1MPa; deltaH o Delta V and Delta C p Is the specific enthalpy difference, specific tolerance and specific heat difference between the rich water phase and the pure water phase; f (f) w The fugacity of water in the water-rich phase; The loss of pure water in reference states T and P;
natural gas hydrate decomposition rate model:
wherein M is h Is the molar mass of hydrate, kg/mol; k (k) d Is an intrinsic reaction constant of hydrate, and has a value of 2.6X10 5 mol/(Pa·s·m 2 ) Delta E is the activation energy of the hydrate, the value of the Delta E is 104000J/mol, R is the gas constant, and J/(mol.K); t is the temperature, K; p is p eq The equilibrium pressure of the hydrate is MPa; p is p e Pore pressure, MPa, for hydrate formation; a is that h The specific surface area for decomposing the hydrate is calculated as follows:
wherein r is p An average particle size, m, of the reservoir matrix;porosity, dimensionless; s is S h Is hydrate saturation, dimensionless;
natural gas hydrate decomposition thermal model:
wherein P 'and T' are the pressure and temperature of hydrate formation/decomposition, MPa, K; ΔH d Is the heat of decomposition, kJ/mol; z is the gas compression coefficient, dimensionless;
natural gas hydrate formation rate model:
wherein M is g Is the average gas molar mass, g/mol; u is a coefficient representing the intensity of mass and heat transfer, dimensionless; k (K) 1 And K 2 Is a kinetic parameter, K 1 ＝2.608×10 16 kg/(m 2 Ks)，K 2 ＝-13600K；T s Is the system temperature, K; t (T) sub Is the thermodynamic supercooling degree, K, defined as the difference between the equilibrium temperature of the hydrate and the system temperature: t (T) sub ＝T eq -T s ；T eq The equilibrium temperature, K, of hydrate formation at system pressure; a is that s Is the gas-liquid contact area m when the hydrate is generated 2 ；
Natural gas hydrate generation thermal model:
ΔH c heat release rate for hydrate formation, W/m 3 ；
(4) Establishing a fluid continuity equation, a momentum equation and an energy equation of a well annulus of a shallow gas and natural gas hydrate reservoir, and determining a temperature field distribution and a pressure field distribution of a well annulus and a Zhou Chu layer of a well;
in the step (4), the fluid mass conservation equation in the shaft is established as follows:
gas phase:
wherein A is a Is the annulus area, m 2 ；E g Is the gas phase volume fraction, dimensionless; ρ g Is of gas density, kg/m 3 The method comprises the steps of carrying out a first treatment on the surface of the t is drilling time, s; u (u) g Is the gas velocity, m/s; z is the depth from the wellhead position, m;kg/(m·s) for drill cuttings hydrate phase to gas phase mass transfer rate; />Kg/(m·s) for the wellbore fluid hydrate phase to gas phase mass transfer rate; />Kg/(m.s) for the gas phase to wellbore fluid hydrate phase mass transfer rate; q g Kg/(m·s) is the gas mass inflow rate;
liquid phase:
wherein E is l Is the liquid phase volume fraction, dimensionless; ρ l Is of liquid phase density of kg/m 3 ；u l Is the liquid phase speed, m/s;kg/(m·s) is the drill cuttings hydrate phase to liquid phase mass transfer rate; />Kg/(m·s) for the wellbore fluid hydrate phase to liquid phase mass transfer rate; / >Kg/(m·s) for the mass transfer rate of the liquid phase to the wellbore fluid hydrate phase;
and (3) rock debris phase:
wherein E is c Is the volume fraction of the rock debris phase, and has no dimension; ρ c Is the phase density of the rock scraps, kg/m 3 ；u c Is the phase velocity of rock debris, m/s;the rate of decomposition of the hydrate in the rock debris is kg/(m.s);
hydrate phase:
wherein E is h Is the volume fraction of the hydrate phase, dimensionless; ρ h For hydrate phase density, kg/m 3 ；u h Is hydrate phase velocity, m/s;kg/(m.s) is the rate of hydrate phase decomposition in the wellbore fluid;
establishing a wellbore annulus internal momentum equation, and calculating to obtain annulus pressure field distribution:
wherein p is a Is annular pressure, MPa; f is friction coefficient, dimensionless; ρ m For annular mixing density kg/m 3 ；u m Is the annulus mixing flow rate, m/s; d (D) a Is the hydraulic diameter of the annulus, m; g is gravity acceleration, m/s 2 The method comprises the steps of carrying out a first treatment on the surface of the θ is the well inclination angle, °;
establishing a well annulus fluid temperature field equation:
wherein T is a 、T p 、T e The temperature K of the well bore annulus, the drill pipe and the stratum fluid is respectively; r is (r) pi 、r ci The inner diameters of a drill rod and a casing pipe are respectively m; u (U) p 、U a W/(m) is the total heat transfer coefficient in the well bore annulus and the drill pipe 2 ·K)；Kg/(m.s) is the total decomposition rate of the hydrate; ΔH h J/kg, which is the heat of decomposition of the hydrate;
calculating reservoir fluid pressure field distribution according to fluid continuity equations and momentum equations in natural gas hydrate reservoirs and shallow gas reservoirs:
The fluid in the porous medium of the natural gas hydrate reservoir comprises drilling fluid, hydrate decomposition liquid phase and hydrate decomposition gas phase, and the gas phase velocity u in the porous medium of the reservoir is obtained through calculation of a gas phase continuity equation g Distribution:
calculating to obtain the liquid phase velocity u in the porous medium of the natural gas hydrate reservoir through a liquid phase continuity equation w Distribution:
wherein,is porosity, dimensionless; ρ w And ρ g Density of water and gas, kg/m 3 ，S w And S is g Saturation of water and gas, respectively; u (u) w And u g The speeds of water and gas, m/s, respectively; t is drilling time, s; />And->Mass transfer rate of hydrate to water and gas, kg/(m) 3 ·s)；
Equation of pressure field in natural gas hydrate reservoir:
wherein k is the absolute permeability of the hydrate layer, m 2 ；k rw And k rg Is the relative permeability of water and gas in the porous medium; p is p w And p g Is the pressure of liquid phase and gas phase, pa; mu (mu) w Sum mu g The viscosities of water and gas, pa.s, respectively;
the fluid in the shallow porous medium comprises drilling fluid and shallow gas phase, and the gas phase speed u in the reservoir porous medium is obtained through calculation of a continuity equation sg And liquid phase velocity u sl Distribution:
and calculating to obtain the pressure field distribution in the porous medium of the shallow gas reservoir through a continuity equation:
Wherein ρ is sg And ρ sl Density of gas phase and liquid phase, kg/m 3 ；u sg And u sl The flow rates of the gas phase and the liquid phase, m/s respectively; k (k) rsl And k rsg Relative permeabilities of the gas and liquid phases, respectively; mu (mu) sg Sum mu sl The viscosities of the gas phase and the liquid phase are Pa.s respectively; p is p sg And p sl The pressure of the gas phase and the liquid phase are respectively MPa;
calculating the distribution of fluid temperature fields in the shallow gas and natural gas hydrate reservoir according to a fluid energy equation in the reservoir;
equation of energy in natural gas hydrate reservoir:
energy equation in shallow gas reservoir:
in (ρC) eff Representing the effective product of fluid density and specific heat capacity in the formation, J/(m) 3 ·℃)；C w And C g The specific heat capacities of water and gas, J/(kg. DEG C), respectively; k (k) eff Indicating the effective thermal conductivity, w/(m·deg.C), of the fluid in the formation; q (Q) h J/(m) for decomposition heat of hydrate 3 ·s)，Q s J/(m) is the decomposition heat of superficial gas 3 ·s)；
(5) Under the conditions of shaft temperature and pressure at different well depth positions, the generation inhibition performance of the drilling fluid system on the natural gas hydrate is experimentally evaluated, and whether the natural gas hydrate is generated or not is judged;
(6) Experiment evaluation is carried out on the decomposition inhibition performance of the drilling fluid system on the natural gas hydrate under the conditions of temperature and pressure in porous media of reservoirs with different depths from the well wall, and whether the natural gas hydrate is decomposed or not is judged;
(7) If the natural gas hydrate in the well bore is generated or the natural gas hydrate in the reservoir is decomposed, adjusting the discharge capacity of the drilling fluid, the temperature of the drilling fluid and the concentration of the inhibitor, and repeating the steps (1) - (6) until the condition that the natural gas hydrate in the well bore is not generated and the natural gas hydrate in the reservoir is not decomposed is simultaneously satisfied.
2. The method for regulating and controlling the hydrate inhibition performance of a deep water shallow gas hydrate multi-layer joint production drilling fluid system according to claim 1, wherein in the step (1), drilling parameters comprise: drilling fluid displacement, drilling fluid density, drilling fluid viscosity, drilling fluid constant pressure specific heat, drill rod inner diameter, drill bit diameter, well depth, well body structure, annulus fluid total heat transfer coefficient, drill rod fluid total heat transfer coefficient, well wall heat transfer coefficient and drilling time; reservoir physical property data include: the original temperature and pressure of the shallow gas reservoir, the relative permeability of the shallow gas reservoir, the rock density of the shallow gas reservoir, the constant pressure specific heat of the shallow gas rock, the effective heat conductivity coefficient of the shallow gas reservoir and the porosity of the shallow gas reservoir; the natural gas hydrate reservoir has the advantages of original temperature and pressure, relative permeability of the natural gas hydrate reservoir, rock density of the natural gas hydrate reservoir, constant pressure specific heat of the natural gas hydrate rock, effective heat conductivity coefficient of the natural gas hydrate reservoir and porosity of the natural gas hydrate reservoir.
3. The method for regulating and controlling the hydrate inhibition performance of a deep water shallow gas hydrate multi-layer joint production drilling fluid system according to claim 1, wherein in the step (2), the time is divided into M cells according to the drilling time, and the M cells are respectively 1, 2 and 3 … M; dividing N unit cells in the well depth direction into 1, 2 and 3 … N respectively; dividing K unit cells in the well circumferential direction into 1, 2 and 3 … K respectively; the divided cells are uniformly distributed.
4. The method for regulating and controlling the hydrate inhibition performance of a deep water shallow gas hydrate multi-layer joint production drilling fluid system according to claim 1, wherein in the step (5), according to the wellbore temperature and pressure at different well depth positions calculated in the step (4), the production inhibition performance of the drilling fluid system on the natural gas hydrate at the temperature and the pressure is experimentally evaluated, and whether the natural gas hydrate is produced is judged, and the hydrate inhibition evaluation method comprises the following steps:
(5-1) opening the high-pressure reaction kettle and cleaning the inner wall, and preparing a solvent required by an experiment;
(5-2) opening the gas line and the methane cylinder, pressurizing by a gas pressurizing means, and increasing the pressure to 20MPa;
(5-3) adding an experimental solvent into the high-pressure reaction kettle, and screwing up a valve of the high-pressure device;
(5-4) turning on a vacuum pump, and vacuumizing for 15 minutes to reduce the pressure in the reaction kettle to minus 0.09MPa;
(5-5) opening a hydrate window for capturing, opening a pressurizing valve, injecting 14MPa pressure into the high-pressure reaction kettle, and simultaneously opening temperature control and stirring;
(5-6) after the temperature and the pressure are stable, carrying out pressure compensation again to ensure that the pressure in the reaction kettle is kept at 14MPa when the constant-speed cooling is started;
(5-7) observing turbidity of the solution in the kettle through a window, and simultaneously recording change of a temperature-pressure curve in the kettle, wherein when the solution in the kettle becomes turbid, or the temperature curve suddenly rises or the pressure curve suddenly drops, the solution is regarded as hydrate generation;
(5-8) comparing the formation temperature and pressure with the hydrate formation curve under pure water conditions, the lower the temperature is, the better the hydrate formation inhibition is;
(5-9) closing the pipeline valve and the gas cylinder, cleaning the experimental instrument and placing the experimental instrument in order.
5. The method for regulating and controlling the hydrate inhibition performance of a deep water shallow gas hydrate multi-layer joint production drilling fluid system according to claim 1, wherein in the step (6), under the conditions of temperature and pressure in porous media of different depths from a well wall of the well wall, which are calculated in the step (4), the decomposition inhibition performance of the drilling fluid system on the natural gas hydrate at the temperature and the pressure is experimentally evaluated, and whether the natural gas hydrate is decomposed or not is judged, and the hydrate decomposition inhibition evaluation method comprises the following steps:
(6-1) opening the high-pressure reaction kettle and cleaning the inner wall, and preparing a solvent required by an experiment;
(6-2) opening the gas line and the methane cylinder, pressurizing by a gas pressurizing means, and increasing the pressure to 20MPa;
(6-3) adding pure water into the high-pressure reaction kettle, and screwing up a valve of the high-pressure device;
(6-4) turning on a vacuum pump, and vacuumizing for 15 minutes to reduce the pressure in the reaction kettle to minus 0.09MPa;
(6-5) opening a hydrate window for capturing, opening a pressurizing valve, injecting 14MPa pressure into the high-pressure reaction kettle, and simultaneously opening temperature control and stirring;
(6-6) after the temperature and the pressure are stable, carrying out pressure compensation again to ensure that the pressure in the reaction kettle is kept at 14Mpa when the constant-speed cooling is started;
(6-7) observing turbidity conditions of the solution in the kettle through a window, simultaneously recording change of a temperature-pressure curve in the kettle, and when the solution in the kettle becomes turbid or the temperature curve suddenly rises or the pressure curve suddenly drops, treating the solution as hydrate generation, and treating the solution as hydrate after the temperature-pressure is maintained for 30 minutes;
(6-8) injecting an experimental solvent into the kettle, and recording the temperature and pressure change in the kettle;
(6-9) comparing the formation temperature and pressure curve with the hydrate formation curve under the pure water condition, wherein the lower the pressure in the kettle is under the same temperature condition, the better the decomposition inhibition is;
(6-10) closing the pipeline valve and the gas cylinder, cleaning the experimental instrument and placing the experimental instrument in order.
6. The method for regulating and controlling the hydrate inhibition performance of a deep water shallow gas hydrate multi-layer joint production drilling fluid system according to claim 1, wherein in the step (7), if a well bore natural gas hydrate is generated, the drilling fluid displacement is increased, the drilling fluid temperature is increased, and the inhibitor concentration is increased; if the natural gas hydrate in the reservoir is decomposed, reducing the discharge of the drilling fluid, reducing the temperature of the drilling fluid and reducing the concentration of the inhibitor, and repeating the steps (1) - (6) until the condition that the natural gas hydrate in the well bore is not generated and the natural gas hydrate in the reservoir is not decomposed is simultaneously satisfied.
7. The method for regulating and controlling the hydrate inhibition performance of the deep water shallow gas hydrate multi-layer joint production drilling fluid system according to claim 1, wherein the tackifying coating agent is low-viscosity carboxymethyl cellulose or low-viscosity polyanion cellulose, the anti-mud-pack lubricant is fatty glyceride or oleic acid diethanolamide, the reservoir bridging agent is PF-EZCARB, the hydrate formation inhibitor is any one of PVP, PVCap, VC, and the hydrate decomposition inhibitor is any one of lecithin, PVP and PVCap.
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