CN115595127A - Deepwater shallow gas hydrate multi-layer combined production drilling fluid system and hydrate inhibition performance regulation and control method - Google Patents
Deepwater shallow gas hydrate multi-layer combined production drilling fluid system and hydrate inhibition performance regulation and control method Download PDFInfo
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- CN115595127A CN115595127A CN202211137111.8A CN202211137111A CN115595127A CN 115595127 A CN115595127 A CN 115595127A CN 202211137111 A CN202211137111 A CN 202211137111A CN 115595127 A CN115595127 A CN 115595127A
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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 158
- 239000012530 fluid Substances 0.000 title claims abstract description 152
- 238000005553 drilling Methods 0.000 title claims abstract description 120
- 230000005764 inhibitory process Effects 0.000 title claims abstract description 48
- 238000000034 method Methods 0.000 title claims abstract description 41
- 238000004519 manufacturing process Methods 0.000 title claims description 16
- 230000033228 biological regulation Effects 0.000 title abstract description 7
- 238000000354 decomposition reaction Methods 0.000 claims abstract description 93
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims abstract description 63
- 238000005065 mining Methods 0.000 claims abstract description 15
- 238000011156 evaluation Methods 0.000 claims abstract description 8
- 239000007789 gas Substances 0.000 claims description 165
- 239000012071 phase Substances 0.000 claims description 112
- 239000007791 liquid phase Substances 0.000 claims description 51
- 239000003112 inhibitor Substances 0.000 claims description 45
- 230000015572 biosynthetic process Effects 0.000 claims description 43
- 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
- HEMHJVSKTPXQMS-UHFFFAOYSA-M Sodium hydroxide Chemical compound [OH-].[Na+] HEMHJVSKTPXQMS-UHFFFAOYSA-M 0.000 claims description 24
- 239000003795 chemical substances by application Substances 0.000 claims description 22
- FAPWRFPIFSIZLT-UHFFFAOYSA-M Sodium chloride Chemical compound [Na+].[Cl-] FAPWRFPIFSIZLT-UHFFFAOYSA-M 0.000 claims description 18
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 claims description 17
- WCUXLLCKKVVCTQ-UHFFFAOYSA-M Potassium chloride Chemical compound [Cl-].[K+] WCUXLLCKKVVCTQ-UHFFFAOYSA-M 0.000 claims description 16
- 238000002474 experimental method Methods 0.000 claims description 16
- 230000035699 permeability Effects 0.000 claims description 15
- 239000007788 liquid Substances 0.000 claims description 13
- 238000004140 cleaning Methods 0.000 claims description 12
- 239000002904 solvent Substances 0.000 claims description 12
- 239000000654 additive Substances 0.000 claims description 11
- 239000011248 coating agent Substances 0.000 claims description 11
- 239000011347 resin Substances 0.000 claims description 11
- 229920005989 resin Polymers 0.000 claims description 11
- 230000000996 additive effect Effects 0.000 claims description 10
- 230000001276 controlling effect Effects 0.000 claims description 10
- 239000000314 lubricant Substances 0.000 claims description 10
- 230000001105 regulatory effect Effects 0.000 claims description 10
- 238000004364 calculation method Methods 0.000 claims description 9
- 230000008859 change Effects 0.000 claims description 9
- 239000011780 sodium chloride Substances 0.000 claims description 9
- 229920000768 polyamine Polymers 0.000 claims description 8
- 239000011148 porous material Substances 0.000 claims description 8
- 239000001103 potassium chloride Substances 0.000 claims description 8
- 235000011164 potassium chloride Nutrition 0.000 claims description 8
- 239000013535 sea water Substances 0.000 claims description 8
- 238000003756 stirring Methods 0.000 claims description 8
- 239000000230 xanthan gum Substances 0.000 claims description 8
- 229920001285 xanthan gum Polymers 0.000 claims description 8
- 229940082509 xanthan gum Drugs 0.000 claims description 8
- 235000010493 xanthan gum Nutrition 0.000 claims description 8
- 238000005520 cutting process Methods 0.000 claims description 6
- 230000009467 reduction Effects 0.000 claims description 6
- 229920002134 Carboxymethyl cellulose Polymers 0.000 claims description 5
- 239000001768 carboxy methyl cellulose Substances 0.000 claims description 5
- 235000010948 carboxy methyl cellulose Nutrition 0.000 claims description 5
- 239000008112 carboxymethyl-cellulose Substances 0.000 claims description 5
- 239000000126 substance 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
- 125000005456 glyceride group Chemical group 0.000 claims description 4
- 239000000787 lecithin Substances 0.000 claims description 4
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- 229940067606 lecithin Drugs 0.000 claims description 4
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- 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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- 239000004615 ingredient Substances 0.000 claims description 3
- 239000011159 matrix material Substances 0.000 claims description 3
- 239000002245 particle Substances 0.000 claims description 3
- 229910052700 potassium Inorganic materials 0.000 claims description 3
- 239000000047 product Substances 0.000 claims description 3
- 238000003860 storage Methods 0.000 claims description 3
- 238000004781 supercooling Methods 0.000 claims description 3
- 230000001502 supplementing effect Effects 0.000 claims 1
- 230000008901 benefit Effects 0.000 abstract description 6
- 230000000087 stabilizing effect Effects 0.000 abstract description 2
- 150000004677 hydrates Chemical class 0.000 description 6
- 238000012360 testing method Methods 0.000 description 6
- 230000008569 process Effects 0.000 description 5
- 230000002401 inhibitory effect Effects 0.000 description 4
- 239000003345 natural gas Substances 0.000 description 4
- 238000011161 development Methods 0.000 description 3
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- -1 natural gas hydrates Chemical class 0.000 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
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
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- 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
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- 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 deepwater shallow gas hydrate multi-layer combined mining drilling fluid system and a hydrate inhibition performance regulation and control method, belonging to the technical field of natural gas hydrate mining, wherein the drilling fluid system comprises the following components: the method comprises the following steps of (1) carrying out experimental evaluation on the generation and decomposition inhibition performance of a drilling fluid system on a natural gas hydrate under the conditions of wellbore temperature and wellbore pressure at different positions, and judging whether the natural gas hydrate is generated and decomposed or not; when a horizontal complex well is drilled in a deep water weakly cemented 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 decomposition and generation inhibition of the natural gas hydrate are obviously improved by applying the hydrate inhibition performance regulation and control method, so that the purposes of stabilizing the well wall and protecting the reservoir stratum are achieved.
Description
Technical Field
The invention relates to a deepwater shallow gas and hydrate multi-layer combined mining drilling fluid system and a hydrate inhibition performance regulation and control method, and belongs to the technical field of natural gas hydrate mining.
Background
The natural gas hydrate is used as an ideal alternative energy source in the 21 st century, has extremely high development and utilization values, and the natural gas hydrate reservoir frequently has associated shallow gas, so that a horizontal well multi-layer combined mining technology can be applied to the natural gas hydrate reservoir, and the efficient development of deep water shallow gas resources is realized. However, in deep water drilling, the drilling risk is high due to the fact that hydrates are easily generated in a seabed shallow layer shaft, the stability of a well wall is poor, the safe density window of drilling fluid is narrow, the phase state of natural gas hydrates is changed, and the like. Therefore, under the deep water, low temperature and high pressure conditions, the drilling fluid has the advantages of keeping a shaft free of hydrates and difficult to generate, reservoir hydrates are difficult to decompose, the drilling fluid is pollution-free, the performance is easy to control, the rheological and lubricating properties are good, the plugging and inhibiting capabilities and the capability of keeping the stability of a well wall are strong, and the like. Due to the limitations of cost and technology, the related technology has certain hysteresis compared with developed countries, and therefore how to realize the multi-layer combined mining of deep water shallow gas and natural gas hydrate with the lowest efficiency and 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 deepwater shallow gas hydrate multi-layer combined production drilling fluid system and a hydrate inhibition performance regulation method. The method fills the gap of the existing multi-layer combined mining field of the deep water natural gas hydrate and the shallow gas. By utilizing the drilling fluid system, well control risks can be reduced to the maximum extent, nonproductive time can be reduced, economic benefits can be improved, and the maximization of the exploitation efficiency and the economic benefits can be realized through the aspects of inhibiting the decomposition of reservoir natural gas hydrates and the generation of shaft natural gas hydrates, maintaining the stability of a well wall, reducing the cost and the like.
The technical scheme of the invention is as follows:
a deepwater shallow gas hydrate multi-layer combined mining drilling fluid system comprises the following components: seawater-based liquid, sodium hydroxide, a fluid loss additive, a tackifying coating agent, xanthan gum, polyamine, an anti-balling lubricant, potassium chloride, sodium chloride, a reservoir bridging agent, a modified resin plugging agent, a hydrate generation inhibitor and a hydrate decomposition inhibitor;
wherein, relative to 100 parts by weight of seawater-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-balling 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 polyanionic 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 formation inhibitor is any one of PVP, PVCap and VC713, and the hydrate decomposition inhibitor is any one of lecithin, PVP and PVCap.
The drilling fluid system is characterized in that a hydrate generation inhibitor and a hydrate decomposition inhibitor are added according to the characteristics of weak cementation, no diagenesis and easy collapse of a hydrate reservoir. Compared with the traditional hydrate inhibitor (mainly referring to thermodynamic generation inhibition), the addition of the hydrate generation inhibitor and the hydrate decomposition inhibitor can inhibit the generation and decomposition of the hydrate at the same time, namely the hydrate decomposition of the reservoir can be prevented when the hydrate reservoir is drilled and produced; the problem that hydrates in a shaft are blocked when a shallow reservoir is drilled and produced can be solved, and finally multi-layer combined production of deep water shallow gas and hydrates is realized.
Preferably, the fluid loss additive comprises PAC-LV and FLO in a weight ratio of 1.
A method for regulating and controlling the hydrate inhibition performance of a deepwater shallow gas hydrate multi-layer combined production drilling fluid system comprises the following steps:
(1) Reading current drilling parameters, shallow gas and natural gas hydrate reservoir physical property data;
(2) Uniformly dividing the drilling time, the well depth and the well circumferential direction into cells to form discrete grids;
(3) Respectively calculating the decomposition amount, the decomposition rate and the decomposition heat of the natural gas hydrate in the natural gas hydrate storage layer;
(4) Establishing a borehole annulus fluid continuity equation, a momentum equation and an energy equation of shallow gas and natural gas hydrate reservoir, and determining the temperature field distribution and the pressure field distribution of the borehole annulus and the surrounding reservoir;
(5) The method comprises the following steps of (1) evaluating the generation inhibition performance of a drilling fluid system on natural gas hydrate under the conditions of temperature and pressure of a shaft at different well depth positions through experiments, and judging whether natural gas hydrate is generated or not;
(6) The decomposition inhibition performance of the drilling fluid system on the natural gas hydrate is evaluated in an experiment under the conditions of temperature and pressure in the porous medium of the reservoir stratum with different borehole wall depths, and whether the natural gas hydrate is decomposed or not is judged;
(7) And (4) if the natural gas hydrate in the shaft is generated or the natural gas hydrate in the reservoir is decomposed, adjusting the discharge amount of the drilling fluid, the temperature of the drilling fluid and the concentration of the inhibitor, and repeating the steps (1) to (6) until the natural gas hydrate in the shaft is not generated and the natural gas hydrate in the reservoir is not decomposed.
Preferably, in step (1), the drilling parameters include: the method comprises the following steps of (1) discharging volume of drilling fluid, density of the drilling fluid, viscosity of the drilling fluid, constant pressure specific heat of the drilling fluid, inner diameter of a drill rod, diameter of a drill bit, well depth, well body structure, total heat transfer coefficient of annular fluid, total heat transfer coefficient of the drill rod fluid, heat transfer coefficient of well wall and drilling time; the reservoir property data includes: the method comprises the following steps of (1) obtaining the original temperature and pressure of a 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 thermal conductivity coefficient of the shallow gas reservoir and the porosity of the shallow gas reservoir; the method comprises the steps of obtaining the original temperature and pressure of a natural gas hydrate reservoir, the relative permeability of the natural gas hydrate reservoir, the rock density of the natural gas hydrate reservoir, the constant pressure specific heat of the natural gas hydrate rock, the effective heat conductivity coefficient of the natural gas hydrate reservoir and the porosity of the natural gas hydrate reservoir.
Preferably, in the step (2), the time is divided into M unit cells according to the drilling time, wherein M is 1, 2 and 3, 8230; n unit cells are divided in the well depth direction and are respectively 1, 2 and 3 \8230N; k unit cells are divided in the well circumferential direction and are respectively 1, 2 and 3 \8230andK; the divided cells are uniformly distributed.
Preferably, in the step (3), a natural gas hydrate phase equilibrium 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 obtained through calculation;
natural gas hydrate phase equilibrium model:
wherein: r is a gas constant, J/(mol. K); t is the system temperature, K; p is system pressure, pa; v. of i Is the number of i-type pores in the hydrate liquid phase molecule; theta.theta. ij Is the occupancy fraction, dimensionless, N of guest molecules j in the i-shaped cavity c The amount of hydrate-forming ingredients in the mixture; delta mu o Is the chemical potential difference between the water-rich phase and the pure water phase in the standard state; t is o And P o Is the temperature and pressure in the standard state, T under standard conditions o Is 273.15K, P o Is 0.1MPa; delta H o DeltaV and DeltaC p Is the specific enthalpy difference, specific tolerance and specific heat difference between the water-rich phase and the water-pure phase; f. of w Is the fugacity of water in the rich phase;
is pureThe fugacity of water at reference states T and P;
model of natural gas hydrate decomposition rate:
in the formula, M h Is the molar mass of the hydrate, kg/mol; k is a radical of d Is the intrinsic reaction constant of hydrate, and has a value of 2.6 × 10 5 m ol/(Pa·s·m 2 ) Delta E is the activation energy of the hydrate, the value is 104000J/mol, R is the gas constant, J/(mol · K); t is temperature, K; p is a radical of formula eq Equilibrium pressure for hydrate, MPa; p is a radical of e Pore pressure for hydrate formation, MPa; a. The h For the specific surface area of hydrate decomposition, the calculation method is as follows:
in the formula, r p Is the average particle size of the reservoir matrix, m;
porosity, dimensionless; s. the 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; Δ H d Is the heat of decomposition, kJ/mol; z is the gas compression coefficient, dimensionless;
natural gas hydrate formation rate model:
in the formula, M g Is the average gas molar mass, g/mol; u is a coefficient for representing the strength of mass and heat transfer, and has no dimension; 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 is sub Is the thermodynamic supercooling degree, K, which is defined as the difference between the hydrate equilibrium temperature and the system temperature: t is sub ＝T eq -T s ；T eq Equilibrium temperature for hydrate formation, K, at system pressure; a. The s The gas-liquid contact area in the formation of hydrate, m 2 ；
Natural gas hydrate formation thermal model:
ΔH c rate of exotherm for hydrate formation, W/m 3 。
Preferably, in the step (4), the equation for conservation of mass of the fluid in the wellbore is established as follows:
gas phase:
in the formula, A a Is the annular area, m2; e g Is a gas phase volume fraction, and is dimensionless; rho g Gas density, kg/m3; t is the drilling time, s; u. of g Is the gas velocity, m/s; z is the depth from the wellhead position, m;
the rate of mass transfer of drill cuttings hydrate phase to gas phase, kg/(m · s);
is the wellbore fluid hydrate phase to gas phase mass transfer rate, kg/(m · s);
mass transfer rate, kg/(m · s), of gas phase to wellbore fluid hydrate phase; q. q.s g Kg/(m · s), gas mass inflow rate;
liquid phase:
in the formula, E l Is liquid phase volume fraction, dimensionless; ρ is a unit of a gradient l Is liquid phase density, kg/m3; u. of l Liquid phase velocity, m/s;
the mass transfer rate of drill cuttings hydrate phase to liquid phase, kg/(m.s);
is the wellbore fluid hydrate phase to liquid phase mass transfer rate, kg/(m · s);
mass transfer rate, kg/(m · s), of liquid phase to wellbore fluid hydrate phase;
rock debris phase:
in the formula, E c Is the volume fraction of the rock debris phase, and has no dimension; rho c Is the density of rock debris phase, kg/m3; u. u c The rock debris phase velocity is m/s;
the decomposition rate of hydrate in rock debris is kg/(m.s);
hydrate phase:
in the formula, E h Is hydrate phaseVolume fraction, dimensionless; rho h Hydrate phase density, kg/m3; u. of h Is the hydrate phase velocity, m/s;
the rate of decomposition of the hydrate phase in the wellbore fluid, kg/(m · s);
establishing a borehole annular internal momentum equation, and calculating to obtain annular pressure field distribution:
in the formula, p a The annular pressure is MPa; f is the friction coefficient and is dimensionless; rho m Is the annular mixed density, kg/m3; u. of m The annular mixed flow velocity is m/s; d a Is the annulus hydraulic diameter, m; g is the gravity acceleration, m/s2; theta is the angle of inclination, deg..
Preferably, in the step (4), an equation of the temperature field of the fluid in the borehole annulus is established:
in the formula, T a 、T p 、T e Well bore annulus, drill pipe and formation fluid temperatures, K, respectively; r is pi 、r ci The inner diameters m of the drill rod and the sleeve respectively; u shape p 、U a The total heat transfer coefficient of the shaft annulus and the drill rod is W/(m < 2 >. K);
the total decomposition rate of the hydrate is kg/(m.s); Δ H h J/kg is the hydrate decomposition heat.
Preferably, in the step (4), the distribution of the reservoir fluid pressure field is calculated according to a continuity equation and a momentum equation of the fluids 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 phaseAnd calculating to obtain the gas phase velocity u in the porous medium of the reservoir through 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 the content of the first and second substances,
is porosity, dimensionless; rho w And ρ g Density of water and gas, kg/m respectively 3 ，S w And S g Water and gas saturations, respectively; u. of w And u g The velocity of the water and gas, m/s, respectively; t is the drilling time, s;
and
the mass transfer rates of the hydrate to water and gas, kg/(m) 3 ·s)；
Pressure field equation in the natural gas hydrate reservoir:
where k is the absolute permeability of the hydrate layer, is closely related to the pore structure and the saturation of the hydrate, and is in an exponential form with the decomposition of the hydrateIncrease of (a) m 2 ；k rw And k rg Is the relative permeability of water and gas in porous media, generally calculated using the stone model, and the capillary pressure is generally calculated using the VG (vangenichten) model; p is a radical of w And p g Is the liquid and gas phase pressure, pa; mu.s w And mu g Viscosity of water and gas, pa · s, respectively;
the fluid in the shallow layer porous medium contains drilling fluid and shallow layer gas phase, and the gas phase velocity u in the reservoir layer porous medium is obtained through calculation of a continuity equation sg And velocity u of liquid phase sl Distribution:
and (3) calculating pressure field distribution in the porous medium of the shallow gas reservoir through a continuity equation:
where ρ is sg And ρ sl Density in kg/m of gas and liquid phases, respectively 3 ；u sg And u sl Flow velocities of the gas phase and the liquid phase, m/s, respectively; k is a radical of formula rsl And k rsg Relative permeability of the gas and liquid phases, respectively; mu.s sg And mu sl The viscosity, pa · s, of the gas phase and of the liquid phase, respectively; p is a radical of sg And p sl The pressure of the gas phase and the liquid phase, respectively, is MPa.
Preferably, in the step (4), the temperature field distribution of the fluid in the shallow gas reservoir and the fluid in the natural gas hydrate reservoir is calculated according to the fluid energy equation in the reservoir;
energy equation in the natural gas hydrate reservoir:
energy equation in shallow gas reservoir:
in the formula, (rho C) eff Represents the effective product of the density and specific heat capacity of the fluid 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 is a radical of eff Represents the effective thermal conductivity of the fluid in the formation, w/(m DEG C); q h Is the heat of decomposition of the hydrate, J/(m) 3 ·s)，Q s The heat of decomposition of superficial gas, J/(m) 3 ·s)。
Preferably, in the step (5), according to the wellbore temperatures and pressures at different wellbore depths calculated in the step (4), the formation inhibition performance of the drilling fluid system on the natural gas hydrate at the temperatures and pressures is evaluated experimentally, and whether the natural gas hydrate is formed is judged, wherein the hydrate inhibition evaluation method includes the steps of:
(5-1) opening the high-pressure reaction kettle, cleaning the inner wall, and preparing a solvent required by an experiment;
(5-2) opening the gas pipeline and the methane gas cylinder, pressurizing by a gas pressurizing device, and adding the pressure to 20MPa;
(5-3) adding an experimental solvent into the high-pressure reaction kettle, and screwing down a valve of the high-pressure device;
(5-4) opening a vacuum pump, vacuumizing for 15 minutes, and reducing the pressure in the reaction kettle to-0.09 MPa;
(5-5) starting a hydrate window for capturing, opening a pressurizing valve, injecting pressure of 14MPa into the high-pressure reaction kettle, and simultaneously starting temperature control and stirring;
(5-6) after the temperature and the pressure are stable, performing pressure compensation again to keep the pressure in the reaction kettle at 14MPa when the constant-speed temperature reduction is started;
(5-7) observing the turbidity condition of the solution in the kettle through a window, simultaneously recording the change of the temperature-pressure curve in the kettle, and when the solution in the kettle becomes turbid, or the temperature curve suddenly rises and the pressure curve suddenly drops, determining that the hydrate is generated.
(5-8) comparing the generation temperature and pressure with a hydrate generation curve under a pure water condition, wherein the lower the temperature is, the better the hydrate generation inhibition is;
(5-9) closing the pipeline valve and the gas cylinder, cleaning the experimental instrument and putting the experimental instrument in order.
Preferably, in the step (6), the decomposition inhibition performance of the drilling fluid system on the natural gas hydrate under the temperature and the pressure is experimentally evaluated according to the temperature and the pressure conditions in the porous medium of the reservoir with different borehole wall depths, which are obtained by calculation in the step (4), so as to judge whether the natural gas hydrate is decomposed, and the hydrate decomposition inhibition evaluation method comprises the following steps:
(6-1) opening the high-pressure reaction kettle, cleaning the inner wall, and preparing a solvent required by an experiment;
(6-2) opening a gas pipeline and a methane gas cylinder, and pressurizing by a gas pressurizing device to increase the pressure to 20MPa;
(6-3) adding pure water into the high-pressure reaction kettle, and screwing down a valve of the high-pressure device;
(6-4) opening a vacuum pump, vacuumizing for 15 minutes, and reducing the pressure in the reaction kettle to-0.09 MPa;
(6-5) starting a hydrate window for capturing, opening a pressurizing valve, injecting pressure of 14MPa into the high-pressure reaction kettle, and simultaneously starting temperature control and stirring;
(6-6) after the temperature and the pressure are stable, performing pressure compensation again to keep the pressure in the reaction kettle at 14Mpa when the constant-speed temperature reduction is started;
(6-7) observing the turbidity condition of the solution in the kettle through a window, simultaneously recording the change of a temperature-pressure curve in the kettle, and when the solution in the kettle becomes turbid or the temperature curve suddenly rises and the pressure curve suddenly drops, determining that a hydrate is generated, and maintaining the temperature and the pressure for 30 minutes determines that the hydrate is completed;
(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 curves with the hydrate formation curve under pure water, a lower pressure in the autoclave is considered to be more excellent in decomposition inhibition under the same temperature conditions.
(6-10) closing the pipeline valve and the gas cylinder, cleaning the experimental instrument and putting the experimental instrument in order.
Preferably, in the step (7), if the wellbore natural gas hydrate 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; and (4) if the reservoir natural gas hydrate is decomposed, reducing the discharge amount of the drilling fluid, reducing the temperature of the drilling fluid and reducing the concentration of the inhibitor, and repeating the steps (1) to (6) until the conditions that the natural gas hydrate in the shaft is not generated and the natural gas hydrate in the reservoir is not decomposed are met.
The invention has the beneficial effects that:
1. when a horizontal complex well is drilled in a deep water weakly cemented 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 method obviously improves the decomposition and generation inhibition performance of the natural gas hydrate by applying the hydrate inhibition performance regulation and control method so as to achieve the purposes of stabilizing the well wall and protecting the reservoir.
2. The drilling fluid system has good high temperature resistance, lubricity and inhibitive performance, can meet various requirements of horizontal complex wells on shallow gas and natural gas hydrate combined production to the maximum extent, and realizes safe and efficient multi-layer combined production while protecting a reservoir stratum.
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 obvious effect on multi-layer combined mining of deep-water drilling horizontal wells, can relieve the dependence of China on energy to a certain extent, has very good economic and social benefits, and is worthy of popularization and application.
Drawings
FIG. 1 shows the variation of temperature and pressure parameters of the whole process of a PVCap precursor system with an inhibitor added;
FIG. 2 shows the temperature and pressure parameter changes of the system in the whole process after the inhibitor PVCap is added.
Detailed Description
The present invention will be further described by way of examples, but not limited thereto, with reference to the accompanying drawings.
Example 1:
a deepwater shallow gas hydrate multi-layer combined mining drilling fluid system comprises the following components: seawater-based liquid, sodium hydroxide, a fluid loss additive, a tackifying coating agent, xanthan gum, polyamine, an anti-balling lubricant, potassium chloride, sodium chloride, a reservoir bridging agent, a modified resin plugging agent, a hydrate generation inhibitor and a hydrate decomposition inhibitor;
wherein, relative to 100 parts by weight of seawater-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-balling 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 viscosity-increasing coating agent is low-viscosity carboxymethyl cellulose or low-viscosity polyanionic 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 formation inhibitor is any one of PVP, PVCap and VC713, the hydrate decomposition inhibitor is any one of lecithin, PVP and PVCap, and the fluid loss additive comprises PAC-LV and FLO in a weight content ratio of 1.
Example 2:
a method for regulating and controlling the hydrate inhibition performance of a deepwater shallow gas hydrate multi-layer combined production drilling fluid system comprises the following steps:
(1) Reading current drilling parameters, shallow gas and natural gas hydrate reservoir physical property data;
the drilling parameters include: the method comprises the following steps of (1) discharging volume of drilling fluid, density of the drilling fluid, viscosity of the drilling fluid, constant pressure specific heat of the drilling fluid, inner diameter of a drill rod, diameter of a drill bit, well depth, well body structure, total heat transfer coefficient of annular fluid, total heat transfer coefficient of the drill rod fluid, heat transfer coefficient of well wall and drilling time; the reservoir property data includes: the method comprises the following steps of (1) obtaining the original temperature and pressure of a 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 thermal conductivity coefficient of the shallow gas reservoir and the porosity of the shallow gas reservoir; the method comprises the steps of obtaining the original temperature and pressure of a natural gas hydrate reservoir, the relative permeability of the natural gas hydrate reservoir, the rock density of the natural gas hydrate reservoir, the constant pressure specific heat of the natural gas hydrate rock, the effective heat conductivity coefficient of the natural gas hydrate reservoir and the porosity of the natural gas hydrate reservoir.
(2) Uniformly dividing the drilling time, the well depth and the well circumferential direction into cells to form discrete grids;
according to the drilling time, the time is divided into M unit cells, namely 1, 2 and 3, 8230M; n unit cells are divided in the well depth direction and are respectively 1, 2 and 3 \8230N; k unit cells are divided in the well circumferential direction and are respectively 1, 2 and 3 \8230K; the divided cells are uniformly distributed.
(3) Respectively calculating the decomposition amount, the decomposition rate and the decomposition heat of the natural gas hydrate in the natural gas hydrate storage layer;
establishing a natural gas hydrate phase equilibrium 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 system pressure Pa; v. of i Is the number of i-type pores in the hydrate liquid phase molecule; theta ij Is the occupancy fraction, dimensionless, N of guest molecules j in the i-shaped cavity c The amount of hydrate-forming ingredients in the mixture; delta mu o Is the chemical potential difference between the water-rich phase and the pure water phase in the standard state; t is o And P o Is the temperature and pressure at standard conditions, T o Is 273.15K, P o Is 0.1MPa; delta H o DeltaV and DeltaC p Between a water-rich phase and a pure water phaseSpecific enthalpy difference, specific tolerance and specific heat difference; f. of w The fugacity of water in the water-rich phase;
the fugacity of pure water under the reference states T and P;
model of natural gas hydrate decomposition rate:
in the formula, M h Is the molar mass of the hydrate, kg/mol; k is a radical of formula d Is the intrinsic reaction constant of hydrate, and has a value of 2.6 × 10 5 mol/(Pa·s·m 2 ) Delta E is the activation energy of the hydrate, the value is 104000J/mol, R is the gas constant, J/(mol.K); t is temperature, K; p is a radical of eq Equilibrium pressure for hydrate, MPa; p is a radical of e Pore pressure for hydrate formation, MPa; a. The h The specific surface area for hydrate decomposition is calculated as follows:
in the formula, r p Is the average particle size of the reservoir matrix, m;
porosity, dimensionless; s. the 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; Δ H d Is the heat of decomposition, kJ/mol; z is the gas compression coefficient, dimensionless;
natural gas hydrate formation rate model:
in the formula, M g Is the average gas molar mass, g/mol; u is a coefficient for representing the mass and heat transfer strength, and has no dimension; k is 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 is a unit of sub Is the thermodynamic supercooling degree, K, which is defined as the difference between the hydrate equilibrium temperature and the system temperature: t is sub ＝T eq -T s ；T eq Equilibrium temperature for hydrate formation, K, at system pressure; a. The s Is the gas-liquid contact area in the formation of hydrate, m 2 ；
Natural gas hydrate formation thermal model:
ΔH c rate of exotherm for hydrate formation, W/m 3 。
Preferably, in the step (4), the equation for conservation of mass of the fluid in the wellbore is established as follows:
gas phase:
in the formula, A a Is the annular area, m2; e g Is gas phase volume fraction, and has no dimension; ρ is a unit of a gradient g Gas density, kg/m3; t is the drilling time, s; u. of g Is the gas velocity, m/s; z is the depth from the wellhead position, m;
the drill cuttings hydrate phase to gas phase mass transfer rate, kg/(m · s);
is the wellbore fluid hydrate phase to gas phase mass transfer rate, kg/(m · s);
mass transfer rate, kg/(m · s), of gas phase to wellbore fluid hydrate phase; q. q.s g Kg/(m · s), gas mass inflow rate;
liquid phase:
in the formula, E l Is liquid phase volume fraction, dimensionless; ρ is a unit of a gradient l Is the density of liquid phase, kg/m3; u. of l Liquid phase velocity, m/s;
the mass transfer rate of drill cuttings hydrate phase to liquid phase, kg/(m.s);
the mass transfer rate of wellbore fluid hydrate phase to liquid phase, kg/(m · s);
mass transfer rate, kg/(m · s), of liquid phase to wellbore fluid hydrate phase;
rock debris phase:
in the formula, E c Is the volume fraction of the rock debris phase, and has no dimension; ρ is a unit of a gradient c Is the density of rock debris phase, kg/m3; u. of c Is the rock debris phase velocity, m/s;
the decomposition rate of hydrate in the rock debris is kg/(m.s);
hydrate phase:
in the formula, E h Is hydrate phase volume fraction, dimensionless; rho h Hydrate phase density, kg/m3; u. of h Is the hydrate phase velocity, m/s;
the rate of decomposition of the hydrate phase in the wellbore fluid, kg/(m · s);
establishing a borehole annular internal momentum equation, and calculating to obtain annular pressure field distribution:
in the formula, p a The annular pressure is MPa; f is the friction coefficient and is dimensionless; ρ is a unit of a gradient m Is the annular mixed density, kg/m3; u. u m The annular mixed flow velocity is m/s; d a Is the annulus hydraulic diameter, m; g is gravity acceleration, m/s2; theta is the angle of inclination, deg..
(4) Establishing a borehole annulus fluid continuity equation, a momentum equation and an energy equation of shallow gas and natural gas hydrate reservoir, and determining the temperature field distribution and the pressure field distribution of the borehole annulus and the surrounding reservoir;
in the step (4), establishing a borehole annulus fluid temperature field equation:
in the formula, T a 、T p 、T e Well bore annulus, drill pipe and formation fluid temperatures, K, respectively; r is pi 、r ci The inner diameters m of the drill rod and the sleeve respectively; u shape p 、U a The total heat transfer coefficient of the shaft annulus and the drill rod is W/(m < 2 >. K);
the total decomposition rate of the hydrate is kg/(m.s); Δ H h J/kg is the hydrate decomposition heat.
Calculating the distribution of the fluid pressure field of the reservoir according to a continuity equation and a momentum equation of fluids in a natural gas hydrate reservoir and a 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 calculated through 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 the content of the first and second substances,
is porosity, dimensionless; rho w And ρ g Density of water and gas, kg/m, respectively 3 ，S w And S g Saturation of water and gas, respectively; u. of w And u g The velocity of the water and gas, m/s, respectively; t is the drilling time, s;
and
the mass transfer rates of the hydrate to water and gas, kg/(m) 3 ·s)；
Pressure field equation in the natural gas hydrate reservoir:
where 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 porous media, generally calculated using the stone model, and the capillary pressure is generally calculated using the VG (vangenichten) model; p is a radical of w And p g Is the liquid and gas phase pressure, pa; mu.s w And mu g Viscosity of water and gas, pa · s, respectively;
the fluid in the shallow porous medium contains drilling fluid and shallow gas phase, and the gas phase velocity u in the reservoir porous medium is calculated through a continuity equation sg And velocity u of liquid phase sl Distribution:
and (3) calculating pressure field distribution in the porous medium of the shallow gas reservoir through a continuity equation:
wherein ρ sg And ρ sl Density in kg/m of gas and liquid phases, respectively 3 ；u sg And u sl The flow velocities of the gas phase and the liquid phase, m/s, respectively; k is a radical of formula rsl And k rsg Relative permeability of the gas and liquid phases, respectively; mu.s sg And mu sl The viscosity, pa · s, of the gas phase and of the liquid phase, respectively; p is a radical of sg And p sl The pressure of the gas phase and the liquid phase, respectively, is MPa.
Calculating the temperature field distribution of shallow gas and fluid in the natural gas hydrate reservoir according to the fluid energy equation in the reservoir;
energy equation in the natural gas hydrate reservoir:
energy equation in shallow gas reservoir:
in the formula, (rho C) eff Represents the effective product of the density and specific heat capacity of the fluid 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 is a radical of eff Represents the effective thermal conductivity of the fluid in the formation, w/(m DEG C); q h Is the heat of decomposition of the hydrate, J/(m) 3 ·s)，Q s The heat of decomposition of superficial gas, J/(m) 3 ·s)。
(5) The method comprises the following steps of (1) evaluating the generation inhibition performance of a drilling fluid system on natural gas hydrate under the conditions of temperature and pressure of a shaft at different well depth positions through experiments, and judging whether natural gas hydrate is generated or not;
in the step (5), according to the wellbore temperatures and pressures at different well depth positions calculated in the step (4), the formation inhibition performance of the drilling fluid system on the natural gas hydrate under the temperatures and pressures is evaluated in an experiment, whether the natural gas hydrate is formed or not is judged, and the hydrate inhibition evaluation method comprises the following steps:
(5-1) opening the high-pressure reaction kettle, cleaning the inner wall, and preparing a solvent required by an experiment;
(5-2) opening a gas pipeline and a methane gas cylinder, and pressurizing by a gas pressurizing device to increase the pressure to 20MPa;
(5-3) adding an experimental solvent into the high-pressure reaction kettle, and screwing down a valve of a high-pressure device;
(5-4) opening a vacuum pump, vacuumizing for 15 minutes, and reducing the pressure in the reaction kettle to-0.09 MPa;
(5-5) starting a hydrate window for capturing, opening a pressurizing valve, injecting pressure of 14MPa into the high-pressure reaction kettle, and simultaneously starting temperature control and stirring;
(5-6) after the temperature and the pressure are stable, performing pressure compensation again to keep the pressure in the reaction kettle at 14MPa when the constant-speed temperature reduction is started;
(5-7) observing the turbidity condition of the solution in the kettle through a window, simultaneously recording the change of the temperature-pressure curve in the kettle, and when the solution in the kettle becomes turbid, or the temperature curve suddenly rises and the pressure curve suddenly drops, determining that the hydrate is generated.
(5-8) comparing the generation temperature and pressure with a hydrate generation curve under a pure water condition, wherein the lower the temperature is, the better the hydrate generation inhibition is;
and (5-9) closing the pipeline valve and the gas cylinder, cleaning the experimental instrument and putting the experimental instrument in order.
(6) The decomposition inhibition performance of the drilling fluid system on the natural gas hydrate is evaluated in an experiment under the conditions of temperature and pressure in the porous medium of the reservoir stratum with different borehole wall depths, and whether the natural gas hydrate is decomposed or not is judged;
in the step (6), the decomposition inhibition performance of the drilling fluid system on the natural gas hydrate under the temperature and the pressure is evaluated according to the temperature and the pressure in the porous medium of the reservoir stratum with different borehole wall depths calculated in the step (4) in an experiment, 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, cleaning the inner wall, and preparing a solvent required by an experiment;
(6-2) opening the gas pipeline and the methane gas cylinder, and pressurizing by a gas pressurizing device to increase the pressure to 20MPa;
(6-3) adding pure water into the high-pressure reaction kettle, and screwing down a valve of the high-pressure device;
(6-4) opening a vacuum pump, vacuumizing for 15 minutes, and reducing the pressure in the reaction kettle to-0.09 MPa;
(6-5) starting a hydrate window for capturing, opening a pressurizing valve, injecting pressure of 14MPa into the high-pressure reaction kettle, and simultaneously starting temperature control and stirring;
(6-6) after the temperature and the pressure are stable, performing pressure compensation again to keep the pressure in the reaction kettle at 14Mpa when the constant-speed temperature reduction is started;
(6-7) observing the turbidity condition of the solution in the kettle through a window, simultaneously recording the change of a temperature-pressure curve in the kettle, and when the solution in the kettle becomes turbid or the temperature curve suddenly rises and the pressure curve suddenly drops, determining that a hydrate is generated, and maintaining the temperature and the pressure for 30 minutes to determine that the hydrate is completed;
(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 curves with the hydrate formation curve under pure water, a lower pressure in the autoclave is considered to be more excellent in decomposition inhibition under the same temperature conditions.
(6-10) closing the pipeline valve and the gas cylinder, cleaning the experimental instrument and putting the experimental instrument in order.
(7) And (5) if the shaft natural gas hydrate is generated or the reservoir natural gas hydrate is decomposed, adjusting the discharge amount of the drilling fluid, the temperature of the drilling fluid and the concentration of the inhibitor, and repeating the steps (1) - (6) until the conditions that the shaft natural gas hydrate is not generated and the reservoir natural gas hydrate is not decomposed are met at the same time.
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 an inhibitor is increased; and (4) if the reservoir natural gas hydrate is decomposed, reducing the discharge amount of the drilling fluid, reducing the temperature of the drilling fluid and reducing the concentration of the inhibitor, and repeating the steps (1) to (6) until the conditions that the natural gas hydrate in the shaft is not generated and the natural gas hydrate in the reservoir is not decomposed are met.
Experimental example 1:
preparation and rheological property test of deepwater shallow gas hydrate multi-layer combined production drilling fluid system
(1) Preparing a system 1 drilling fluid in a laboratory:
400 ml of seawater is measured by a measuring cylinder and placed in a pulp cup, 1.2g of sodium hydroxide, 2g of fluid loss additive (PAC-LV), 6g of fluid loss additive (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 plugging agent (PF-LSF), 4g of generation inhibitor (PVP) and 4g of decomposition inhibitor (lecithin) are sequentially added while stirring at the rotating speed of 11000 r/min.
(2) Laboratory formulation system 2 drilling fluid:
the drilling fluid is prepared by the method (1) except that no inhibitor is added.
(3) Laboratory preparation system 3 drilling fluid:
400 ml of seawater is measured by a measuring cylinder and placed in a pulp cup, 1.2g of sodium hydroxide, 2g of fluid loss additive (PAC-LV), 6g of fluid loss additive (FLO), 0.8g of tackifying coating agent (low-viscosity carboxymethyl cellulose), 2g of xanthan gum, 12g of polyamine, 8g of anti-claying lubricant (fatty glyceride), 20g of potassium chloride, 28g of sodium chloride, 8g of reservoir bridging agent (PF-EZCARB), 8g of modified resin plugging agent (PF-LSF), 4g of decomposition inhibitor (PVP) and 4g of generation inhibitor (PVCap) are sequentially added under stirring at the rotating speed of 11000 r/min.
(4) Laboratory preparation system 4 drilling fluid:
and (4) preparing the drilling fluid by adopting the method (3), except that sodium chloride is not added.
And (3) testing rheological properties:
according to the formula of the systems 1-4, all the components are stirred at a high speed for more than 1h, the components are uniformly mixed to obtain a drilling fluid system 1-a drilling fluid system 5, the drilling fluid systems are respectively hot rolled for 16h under 180K, and performance parameter tests are carried out, wherein the parameter test results are shown in table 1.
TABLE 1 test results of Performance parameters of systems 1-4
The G10 '/10' parameter is the ratio of the final cut to the initial cut, the value of which is determined with reference to GB/T161782-1997 using a six-speed rotational viscometer ZNN-D6B.
As can be seen from Table 1, system 3 has good rheological properties and lubricity, and the whole system has stable performance.
Experimental example 2: test for inhibition performance of deepwater shallow gas hydrate multi-layer combined production drilling fluid system
The drilling fluid system 3 is subjected to a hydrate formation inhibition evaluation experiment, parameter changes of the temperature and pressure of the HEM system in the whole process before and after the addition of the inhibitor are made by computer software, and the calculation results are shown in figures 1 and 2, wherein the highest line is the gas molar weight and the lowest line is the jacket temperature in figures 1 and 2.
Comparing fig. 1 and fig. 2, it can be seen that under the condition of simulated shut-in, that is, during the process of reducing the liquid temperature to the set reservoir temperature, some additives or salt inhibitors in the original drilling fluid may fail due to low temperature, thereby causing a large amount of hydrates to be generated and aggregated, which is represented as a significant 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 of the agent and the agent, no hydrate is obviously generated, and the gas phase temperature is not fluctuated in figure 2. When restarting is carried out after simulated shut-in (the shut-in is considered when the torque is 0, and the restart is considered when the torque is recovered from 0), the hydrate structure of the low-temperature drilling fluid system without the inhibitor is required to be damaged, so that the torque is greatly increased and then is recovered to be stable, and meanwhile, the process is accompanied with hydrate decomposition caused by physical action, which is represented in figure 1 that the hydrate is gradually recovered to be stable after the gas phase temperature is greatly increased; 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 torque of the system is not greatly influenced, so that the gas phase temperature is basically unchanged as can be seen from fig. 2.
From this it follows that: the inhibitor in the drilling fluid system 3 can effectively inhibit the generation and decomposition of hydrate. Namely, the deepwater shallow gas and hydrate multi-layer combined mining drilling fluid system has very good capability of inhibiting the generation and decomposition of natural gas hydrate.
Claims (10)
1. The deep water shallow layer gas hydrate multi-layer combined mining drilling fluid system is characterized by comprising the following components: seawater-based liquid, sodium hydroxide, a fluid loss additive, a tackifying coating agent, xanthan gum, polyamine, an anti-balling lubricant, potassium chloride, sodium chloride, a reservoir bridging agent, a modified resin plugging agent, a hydrate generation inhibitor and a hydrate decomposition inhibitor;
wherein, relative to 100 parts by weight of seawater-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-balling 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.
2. The deepwater shallow gas hydrate multi-layer combined production drilling fluid system according to claim 1, wherein a tackifying coating agent is low-viscosity carboxymethyl cellulose or low-viscosity polyanionic cellulose, an anti-balling lubricant is fatty glyceride or oleic acid diethanolamide, a reservoir bridging agent is PF-EZCARB, a modified resin plugging agent is PF-LSF, a hydrate formation inhibitor is any one of PVP, PVCap and VC713, and a hydrate decomposition inhibitor is any one of lecithin, PVP and PVCap;
preferably, the fluid loss additive comprises PAC-LV and FLO in a weight ratio of 1.
3. A method for regulating and controlling the hydrate inhibition performance of a deepwater shallow gas hydrate multi-layer combined production drilling fluid system is characterized by comprising the following steps:
(1) Reading current drilling parameters, shallow gas and natural gas hydrate reservoir physical property data;
(2) Uniformly dividing the drilling time, the well depth and the well circumferential direction into cells to form discrete grids;
(3) Respectively calculating the decomposition amount, the decomposition rate and the decomposition heat of the natural gas hydrate in the natural gas hydrate storage layer;
(4) Establishing a continuity equation, a momentum equation and an energy equation of shallow gas and natural gas hydrate reservoir borehole annular fluid, and determining borehole annular and periborehole reservoir temperature field distribution and pressure field distribution;
(5) The method comprises the following steps of (1) evaluating the generation inhibition performance of a drilling fluid system on natural gas hydrate under the conditions of temperature and pressure of a shaft at different well depth positions through experiments, and judging whether natural gas hydrate is generated or not;
(6) The decomposition inhibition performance of the drilling fluid system on the natural gas hydrate is evaluated in an experiment under the conditions of temperature and pressure in the porous medium of the reservoir stratum with different borehole wall depths, and whether the natural gas hydrate is decomposed or not is judged;
(7) And (4) if the natural gas hydrate in the shaft is generated or the natural gas hydrate in the reservoir is decomposed, adjusting the discharge amount of the drilling fluid, the temperature of the drilling fluid and the concentration of the inhibitor, and repeating the steps (1) to (6) until the natural gas hydrate in the shaft is not generated and the natural gas hydrate in the reservoir is not decomposed.
4. The method for regulating and controlling the hydrate inhibition performance of the deepwater shallow water hydrate multi-layer combined mining drilling fluid system according to claim 3, wherein in the step (1), the drilling parameters comprise: the method comprises the following steps of (1) discharging volume of drilling fluid, density of the drilling fluid, viscosity of the drilling fluid, constant pressure specific heat of the drilling fluid, inner diameter of a drill rod, diameter of a drill bit, well depth, well body structure, total heat transfer coefficient of annular fluid, total heat transfer coefficient of the drill rod fluid, heat transfer coefficient of well wall and drilling time; the reservoir property data includes: the method comprises the following steps of (1) obtaining the original temperature and pressure of a 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 thermal conductivity coefficient of the shallow gas reservoir and the porosity of the shallow gas reservoir; the method comprises the steps of obtaining the original temperature and pressure of a natural gas hydrate reservoir, the relative permeability of the natural gas hydrate reservoir, the rock density of the natural gas hydrate reservoir, the constant pressure specific heat of the natural gas hydrate rock, the effective heat conductivity coefficient of the natural gas hydrate reservoir and the porosity of the natural gas hydrate reservoir.
5. The method for regulating and controlling the hydrate inhibition performance of the deepwater shallow layer gas hydrate multi-layer combined mining drilling fluid system according to claim 3, wherein in the step (2), according to the drilling time, the time is divided into M unit cells which are respectively 1, 2 and 3 \8230M; n unit cells are divided in the well depth direction and are respectively 1, 2 and 3 \8230N; k unit cells are divided in the well circumferential direction and are respectively 1, 2 and 3 \8230K; the divided cells are uniformly distributed.
6. The method for regulating and controlling the hydrate inhibition performance of the deepwater shallow layer gas hydrate multi-layer combined mining drilling fluid system according to claim 3, wherein in the step (3), a natural gas hydrate phase equilibrium 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 obtained through calculation;
natural gas hydrate phase equilibrium model:
wherein: r is a gas constant, J/(mol · K); t is the system temperature, K; p is system pressure, pa; v. of i Is the number of i-type pores in the hydrate liquid phase molecule; theta ij Is the occupancy fraction, dimensionless, N of guest molecules j in the i-shaped cavity c The amount of hydrate-forming ingredients in the mixture; delta mu o Is the chemical potential difference between the water-rich phase and the pure water phase in the standard state; t is o And P o Is the temperature and pressure in the standard state, T under standard conditions o Is 273.15K, P o Is 0.1MPa; delta H o DeltaV and DeltaC p Is the specific enthalpy difference, specific tolerance and specific heat difference between the water-rich phase and the pure water phase; f. of w The fugacity of water in the water-rich phase;
the fugacity of pure water under reference states T and P;
model of natural gas hydrate decomposition rate:
in the formula, M h Is the molar mass of the hydrate, kg/mol; k is a radical of d Is the intrinsic reaction constant of hydrate, and has a value of 2.6 × 10 5 mol/(Pa·s·m 2 ) Delta E is the activation energy of the hydrate, the value is 104000J/mol, R is the gas constant, J/(mol.K); t is the temperature, K; p is a radical of formula eq Equilibrium pressure for hydrate, MPa; p is a radical of e Pore pressure for hydrate formation, MPa; a. The h For the specific surface area of hydrate decomposition, the calculation method is as follows:
in the formula, r p Is the average particle size of the reservoir matrix, m;
porosity, dimensionless; 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; Δ H d Is the heat of decomposition, kJ/mol; z is the gas compression coefficient, dimensionless;
natural gas hydrate formation rate model:
in the formula, M g Is the average gas molar mass, g/mol; u is a coefficient for representing the mass and heat transfer strength, and has no dimension; 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 is a unit of sub Is the thermodynamic supercooling degree, K, which is defined as the difference between the hydrate equilibrium temperature and the system temperature: t is a unit of sub ＝T eq -T s ；T eq Equilibrium temperature of hydrate formation, K, at system pressure; a. The s The gas-liquid contact area in the formation of hydrate, m 2 ；
Natural gas hydrate formation thermal model:
ΔH c the rate of heat release for hydrate formation, W/m 3 。
7. The method for regulating and controlling the hydrate inhibition performance of the deepwater shallow gas hydrate multi-layer combined production drilling fluid system according to claim 3, wherein in the step (4), the equation for conservation of mass of fluid in the shaft is established as follows:
gas phase:
in the formula, A a Is the annular area, m2; e g Is gas phase volume fraction, and has no dimension; rho g Gas density, kg/m3; t is the drilling time, s; u. of g Is the gas velocity, m/s; z is the depth from the wellhead position, m;
the drill cuttings hydrate phase to gas phase mass transfer rate, kg/(m · s);
is the wellbore fluid hydrate phase to gas phase mass transfer rate, kg/(m · s);
mass transfer rate of gas phase to wellbore fluid hydrate phase, kg/(m · s); q. q.s g Kg/(m · s), gas mass inflow rate;
liquid phase:
in the formula, E l Is liquid phase volume fraction, and has no dimension; rho l Is liquid phase density, kg/m3; u. of l Liquid phase velocity, m/s;
the mass transfer rate of drill cuttings hydrate phase to liquid phase, kg/(m.s);
the mass transfer rate of wellbore fluid hydrate phase to liquid phase, kg/(m · s);
mass transfer rate, kg/(m · s), of liquid phase to wellbore fluid hydrate phase;
rock debris phase:
in the formula, E c Is the volume fraction of the rock debris phase, and has no dimension; rho c Is the density of rock debris phase, kg/m3; u. of c The rock debris phase velocity is m/s;
the decomposition rate of hydrate in the rock debris is kg/(m.s);
hydrate phase:
in the formula, E h Is hydrate phase volume fraction, dimensionless; ρ is a unit of a gradient h Hydrate phase density, kg/m3; u. of h Is the hydrate phase velocity, m/s;
the rate of decomposition of the hydrate phase in the wellbore fluid, kg/(m · s);
establishing a borehole annular internal momentum equation, and calculating to obtain annular pressure field distribution:
in the formula, p a The annular pressure is MPa; f is the friction coefficient and is dimensionless; rho m Is the annular mixed density, kg/m3; u. of m The annular mixed flow velocity is m/s; d a Is the annulus hydraulic diameter, m; g is the gravity acceleration, m/s2; theta is the angle of inclination, degree;
establishing a borehole annular fluid temperature field equation:
in the formula, T a 、T p 、T e Well bore annulus, drill pipe and formation fluid temperatures, K, respectively; r is pi 、r ci The inner diameters of the drill rod and the sleeve are m; u shape p 、U a The total heat transfer coefficient of the shaft annulus and the drill rod is W/(m < 2 >. K);
the total decomposition rate of the hydrate is kg/(m.s); Δ H h J/kg is the decomposition heat of the hydrate;
and (3) calculating the distribution of the fluid pressure field of the reservoir according to a continuity equation and a momentum equation of fluids 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 by 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, the first and the second end of the pipe are connected with each other,
is porosity, dimensionless; rho w And ρ g Density of water and gas, kg/m respectively 3 ，S w And S g Saturation of water and gas, respectively; u. u w And u g The velocity of the water and gas, m/s, respectively; t is the drilling time, s;
and
mass transfer rates of hydrate to water and gas, kg/(m) 3 ·s)；
Pressure field equation in the 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 a porous medium; p is a radical of formula w And p g Is the liquid and gas phase pressure, pa; mu.s w And mu g Respectively the viscosity of water and gas, pa · s;
the fluid in the shallow porous medium contains drilling fluid and shallow gas phase, and the gas phase velocity u in the reservoir porous medium is calculated through a continuity equation sg And velocity u of liquid phase sl Distribution:
and (3) calculating pressure field distribution in the porous medium of the shallow gas reservoir through a continuity equation:
where ρ is sg And ρ sl Density in kg/m of gas and liquid phases, respectively 3 ；u sg And u sl The flow velocities of the gas phase and the liquid phase, m/s, respectively; k is a radical of formula rsl And k rsg Relative permeabilities of the gas and liquid phases, respectively; mu.s sg And mu sl Viscosity, pa · s, of the gas and liquid phases, respectively; p is a radical of sg And p sl The pressure of the gas phase and the liquid phase respectively, MPa;
calculating the temperature field distribution of shallow gas and fluid in a natural gas hydrate reservoir according to the fluid energy equation in the reservoir;
energy equation in the natural gas hydrate reservoir:
energy equation in shallow gas reservoir:
in the formula, (rho C) eff Represents the effective product of the density and specific heat capacity of the fluid 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 is a radical of eff Represents the effective thermal conductivity of the fluid in the formation, w/(m DEG C); q h Is the heat of decomposition of the hydrate, J/(m) 3 ·s)，Q s The heat of decomposition of superficial gas, J/(m) 3 ·s)。
8. The method for regulating and controlling the hydrate inhibition performance of the deep-water shallow-layer hydrate multi-layer combined-production drilling fluid system according to claim 3, wherein in the step (5), the hydrate inhibition performance of the drilling fluid system on the natural gas hydrate under the temperature and the pressure is evaluated experimentally according to the temperatures and the pressures of the shafts at different well depth positions calculated in the step (4), whether the natural gas hydrate is generated or not is judged, and the hydrate inhibition evaluation method comprises the following steps:
(5-1) opening the high-pressure reaction kettle, cleaning the inner wall, and preparing a solvent required by an experiment;
(5-2) opening a gas pipeline and a methane gas cylinder, and pressurizing by a gas pressurizing device to increase the pressure to 20MPa;
(5-3) adding an experimental solvent into the high-pressure reaction kettle, and screwing down a valve of the high-pressure device;
(5-4) opening a vacuum pump, vacuumizing for 15 minutes, and reducing the pressure in the reaction kettle to-0.09 MPa;
(5-5) starting a hydrate window for capturing, opening a pressurizing valve, injecting 14MPa pressure into the high-pressure reaction kettle, and simultaneously starting temperature control and stirring;
(5-6) after the temperature and the pressure are stable, performing pressure compensation again to keep the pressure in the reaction kettle at 14MPa when the constant-speed temperature reduction is started;
(5-7) observing the turbidity condition of the solution in the kettle through a window, simultaneously recording the change of a temperature-pressure curve in the kettle, and when the solution in the kettle becomes turbid or the temperature curve suddenly rises and the pressure curve suddenly drops, determining that a hydrate is generated;
(5-8) comparing the generation temperature and pressure with a hydrate generation curve under a pure water condition, wherein the lower the temperature is, the better the hydrate generation inhibition is;
and (5-9) closing the pipeline valve and the gas cylinder, cleaning the experimental instrument and putting the experimental instrument in order.
9. The method for regulating and controlling the hydrate inhibition performance of the deep-water shallow-layer gas hydrate multi-layer combined production drilling fluid system according to claim 3, wherein in the step (6), the decomposition inhibition performance of the drilling fluid system on the gas hydrate at different temperatures and pressures is evaluated in an experiment according to the temperature and pressure conditions in the porous medium of the reservoir layer with different borehole wall depths obtained by calculation in the step (4), whether the 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, cleaning the inner wall, and preparing a solvent required by an experiment;
(6-2) opening the gas pipeline and the methane gas cylinder, and pressurizing by a gas pressurizing device to increase the pressure to 20MPa;
(6-3) adding pure water into the high-pressure reaction kettle, and screwing down a valve of the high-pressure device;
(6-4) opening a vacuum pump, vacuumizing for 15 minutes, and reducing the pressure in the reaction kettle to-0.09 MPa;
(6-5) starting a hydrate window for capturing, opening a pressurizing valve, injecting 14MPa pressure into the high-pressure reaction kettle, and simultaneously starting temperature control and stirring;
(6-6) after the temperature and the pressure are stable, performing pressure supplementing again to keep the pressure in the reaction kettle at 14Mpa when the constant-speed temperature reduction is started;
(6-7) observing the turbidity condition of the solution in the kettle through a window, simultaneously recording the change of a temperature-pressure curve in the kettle, and when the solution in the kettle becomes turbid or the temperature curve suddenly rises and the pressure curve suddenly drops, determining that a hydrate is generated, and maintaining the temperature and the pressure for 30 minutes to determine that the hydrate is completed;
(6-8) injecting an experimental solvent into the kettle, and recording the temperature and pressure change in the kettle;
(6-9) comparing the generation temperature and pressure curve with the hydrate generation curve under the condition of pure water, wherein the lower the pressure in the kettle is, the better the decomposition inhibition is;
(6-10) closing the pipeline valve and the gas cylinder, cleaning the experimental instrument and putting the experimental instrument in order.
10. The method for regulating and controlling the hydrate inhibition performance of the deepwater shallow layer gas hydrate multi-layer combined production drilling fluid system according to claim 3, wherein in the step (7), if a wellbore natural gas hydrate is generated, the drilling fluid discharge amount is increased, the drilling fluid temperature is increased, and the inhibitor concentration is increased; and (5) if the reservoir natural gas hydrate is decomposed, reducing the discharge amount 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 conditions that the natural gas hydrate in the shaft is not generated and the natural gas hydrate in the reservoir is not decomposed are met at the same time.
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