CN111101925A - Method for evaluating scaling trend of water injection well - Google Patents
Method for evaluating scaling trend of water injection well Download PDFInfo
- Publication number
- CN111101925A CN111101925A CN201911170132.8A CN201911170132A CN111101925A CN 111101925 A CN111101925 A CN 111101925A CN 201911170132 A CN201911170132 A CN 201911170132A CN 111101925 A CN111101925 A CN 111101925A
- Authority
- CN
- China
- Prior art keywords
- scaling
- scale
- water injection
- injection well
- evaluating
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Pending
Links
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 title claims abstract description 60
- 238000002347 injection Methods 0.000 title claims abstract description 44
- 239000007924 injection Substances 0.000 title claims abstract description 44
- 238000000034 method Methods 0.000 title claims abstract description 30
- 230000015572 biosynthetic process Effects 0.000 claims abstract description 33
- 238000009826 distribution Methods 0.000 claims abstract description 31
- 230000008859 change Effects 0.000 claims abstract description 17
- 230000008569 process Effects 0.000 claims abstract description 12
- 239000011435 rock Substances 0.000 claims abstract description 12
- 230000035699 permeability Effects 0.000 claims abstract description 10
- 239000012530 fluid Substances 0.000 claims abstract description 9
- 150000001768 cations Chemical class 0.000 claims description 15
- 230000000694 effects Effects 0.000 claims description 11
- 150000001450 anions Chemical class 0.000 claims description 7
- 238000004364 calculation method Methods 0.000 claims description 7
- 239000000243 solution Substances 0.000 claims description 7
- 238000006243 chemical reaction Methods 0.000 claims description 6
- 239000012071 phase Substances 0.000 claims description 6
- 150000001875 compounds Chemical class 0.000 claims description 3
- 230000005484 gravity Effects 0.000 claims description 3
- 239000007791 liquid phase Substances 0.000 claims description 3
- 239000007787 solid Substances 0.000 claims description 3
- 239000007790 solid phase Substances 0.000 claims description 3
- 230000007797 corrosion Effects 0.000 claims description 2
- 238000005260 corrosion Methods 0.000 claims description 2
- 238000004519 manufacturing process Methods 0.000 abstract description 13
- 230000007774 longterm Effects 0.000 abstract description 2
- 230000002265 prevention Effects 0.000 abstract description 2
- 239000003921 oil Substances 0.000 description 23
- 230000002829 reductive effect Effects 0.000 description 8
- BHPQYMZQTOCNFJ-UHFFFAOYSA-N Calcium cation Chemical compound [Ca+2] BHPQYMZQTOCNFJ-UHFFFAOYSA-N 0.000 description 6
- 229910001424 calcium ion Inorganic materials 0.000 description 6
- 239000000047 product Substances 0.000 description 6
- 239000000126 substance Substances 0.000 description 6
- 230000005764 inhibitory process Effects 0.000 description 5
- 239000002455 scale inhibitor Substances 0.000 description 5
- 239000007788 liquid Substances 0.000 description 4
- 229910021645 metal ion Inorganic materials 0.000 description 4
- 238000010521 absorption reaction Methods 0.000 description 3
- 239000003129 oil well Substances 0.000 description 3
- BVKZGUZCCUSVTD-UHFFFAOYSA-M Bicarbonate Chemical compound OC([O-])=O BVKZGUZCCUSVTD-UHFFFAOYSA-M 0.000 description 2
- 229910001422 barium ion Inorganic materials 0.000 description 2
- TZCXTZWJZNENPQ-UHFFFAOYSA-L barium sulfate Chemical compound [Ba+2].[O-]S([O-])(=O)=O TZCXTZWJZNENPQ-UHFFFAOYSA-L 0.000 description 2
- OSGAYBCDTDRGGQ-UHFFFAOYSA-L calcium sulfate Chemical compound [Ca+2].[O-]S([O-])(=O)=O OSGAYBCDTDRGGQ-UHFFFAOYSA-L 0.000 description 2
- 239000013522 chelant Substances 0.000 description 2
- 238000010276 construction Methods 0.000 description 2
- 239000010779 crude oil Substances 0.000 description 2
- 230000003247 decreasing effect Effects 0.000 description 2
- 230000003628 erosive effect Effects 0.000 description 2
- 150000002500 ions Chemical class 0.000 description 2
- 239000002332 oil field water Substances 0.000 description 2
- 230000036961 partial effect Effects 0.000 description 2
- 239000011148 porous material Substances 0.000 description 2
- 229920006395 saturated elastomer Polymers 0.000 description 2
- 229910001427 strontium ion Inorganic materials 0.000 description 2
- NAWXUBYGYWOOIX-SFHVURJKSA-N (2s)-2-[[4-[2-(2,4-diaminoquinazolin-6-yl)ethyl]benzoyl]amino]-4-methylidenepentanedioic acid Chemical compound C1=CC2=NC(N)=NC(N)=C2C=C1CCC1=CC=C(C(=O)N[C@@H](CC(=C)C(O)=O)C(O)=O)C=C1 NAWXUBYGYWOOIX-SFHVURJKSA-N 0.000 description 1
- 230000009471 action Effects 0.000 description 1
- 230000004075 alteration Effects 0.000 description 1
- 230000009286 beneficial effect Effects 0.000 description 1
- 230000000903 blocking effect Effects 0.000 description 1
- 239000012267 brine Substances 0.000 description 1
- 239000011575 calcium Substances 0.000 description 1
- 210000005056 cell body Anatomy 0.000 description 1
- 230000001186 cumulative effect Effects 0.000 description 1
- 230000008021 deposition Effects 0.000 description 1
- 238000004090 dissolution Methods 0.000 description 1
- 238000002474 experimental method Methods 0.000 description 1
- 229910017053 inorganic salt Inorganic materials 0.000 description 1
- 230000000670 limiting effect Effects 0.000 description 1
- 230000007246 mechanism Effects 0.000 description 1
- 230000020477 pH reduction Effects 0.000 description 1
- 239000002245 particle Substances 0.000 description 1
- 230000000704 physical effect Effects 0.000 description 1
- 238000011084 recovery Methods 0.000 description 1
- 150000003839 salts Chemical class 0.000 description 1
- 238000004088 simulation Methods 0.000 description 1
- HPALAKNZSZLMCH-UHFFFAOYSA-M sodium;chloride;hydrate Chemical compound O.[Na+].[Cl-] HPALAKNZSZLMCH-UHFFFAOYSA-M 0.000 description 1
- 230000000087 stabilizing effect Effects 0.000 description 1
- 238000003860 storage Methods 0.000 description 1
- 238000006467 substitution reaction Methods 0.000 description 1
- 239000013589 supplement Substances 0.000 description 1
Images
Classifications
-
- 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
- E21B47/00—Survey of boreholes or wells
-
- 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
- E21B47/00—Survey of boreholes or wells
- E21B47/06—Measuring temperature or pressure
-
- G—PHYSICS
- G06—COMPUTING; CALCULATING OR COUNTING
- G06Q—INFORMATION AND COMMUNICATION TECHNOLOGY [ICT] SPECIALLY ADAPTED FOR ADMINISTRATIVE, COMMERCIAL, FINANCIAL, MANAGERIAL OR SUPERVISORY PURPOSES; SYSTEMS OR METHODS SPECIALLY ADAPTED FOR ADMINISTRATIVE, COMMERCIAL, FINANCIAL, MANAGERIAL OR SUPERVISORY PURPOSES, NOT OTHERWISE PROVIDED FOR
- G06Q50/00—Information and communication technology [ICT] specially adapted for implementation of business processes of specific business sectors, e.g. utilities or tourism
- G06Q50/02—Agriculture; Fishing; Forestry; Mining
Landscapes
- Engineering & Computer Science (AREA)
- Life Sciences & Earth Sciences (AREA)
- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Geology (AREA)
- Geochemistry & Mineralogy (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Business, Economics & Management (AREA)
- Fluid Mechanics (AREA)
- Environmental & Geological Engineering (AREA)
- Geophysics (AREA)
- Primary Health Care (AREA)
- Theoretical Computer Science (AREA)
- Strategic Management (AREA)
- Tourism & Hospitality (AREA)
- Human Resources & Organizations (AREA)
- General Business, Economics & Management (AREA)
- General Physics & Mathematics (AREA)
- Marketing (AREA)
- General Health & Medical Sciences (AREA)
- Economics (AREA)
- Health & Medical Sciences (AREA)
- Marine Sciences & Fisheries (AREA)
- Animal Husbandry (AREA)
- Agronomy & Crop Science (AREA)
- Testing Resistance To Weather, Investigating Materials By Mechanical Methods (AREA)
Abstract
The invention discloses a method for evaluating the scaling tendency of a water injection well, which comprises the following steps: s1, establishing a stratum pressure field model by calculating stratum pressure at any point among multiple wells; s2, establishing a formation temperature field model through the heat exchange process between the fluid and the rock and the heat exchange process between the inner parts of the unit bodies; s3, establishing a random normal distribution and permeability model of the initial porosity of the stratum; s4, establishing a scaling prediction model: and predicting the change of the scale distribution range, the scale amount, the scale distribution and the porosity by using a scale prediction model. The invention predicts the scaling trend by establishing the scaling prediction model, so that the scaling trend of the water injection well can be predicted, thereby carrying out accurate scale prevention and ensuring the long-term stable production of the oil and gas well.
Description
Technical Field
The invention relates to the technical field of oilfield development, in particular to a method for evaluating scaling tendency of a water injection well.
Background
As oil field development continues, the natural energy on which oil and gas are produced is depleted. More and more oil fields supplement and recover energy on the ground in a water injection mode, so that the pressure of an oil reservoir is kept, and the effects of stabilizing the yield for a long time and improving the oil gas recovery ratio are achieved. However, waterflooding development also presents a series of problems, with fouling being one of the most serious.
The oil field scaling refers to a deposition substance caused by various reasons in an underground reservoir, a well shaft of an oil production well, a casing, a production oil pipe, underground well completion equipment, surface oil and gas gathering and transportation equipment and pipelines in the production process of the oil field, and the oil in the pipelines is blocked due to the generation of the scaling, so that the smooth operation of oil production is prevented. The scaling phenomenon is a phenomenon commonly existing in the production process of an oil field, is commonly existing in each link of the production process of the oil field, and can also occur in any position of a water system of the oil field, such as underground reservoirs, pump and oil well shafts and pipelines of ground oil and gas gathering and transportation equipment, and inorganic salt scaling can be generated, so that great harm is brought to oil and gas exploitation, and unnecessary loss is caused.
In the process of oilfield water injection, because water in the water injection well stratum contains barium ions, strontium ions and calcium ions, and injected water contains sulfate radicals or bicarbonate ions, the barium ions, the strontium ions and the calcium ions are mixed in the water injection well stratum to generate insoluble barium sulfate scale and calcium sulfate scale which are easy to block the stratum, so that the pressure of the water injection well is increased, and the water injection is not performed or is insufficient. In the prior art, scale removal and blockage removal are generally carried out by adopting injection increasing measures such as acidification, fracturing and the like, but effective prediction of scaling tendency is lacked, the reason for blockage generation cannot be timely and effectively determined, and blind construction is carried out, so that a plurality of negative effects are brought.
Disclosure of Invention
Aiming at the problems, the invention provides a method for evaluating the scaling trend of a water injection well, which predicts the scaling trend by establishing a scaling prediction model so that the scaling trend of the water injection well can be predicted.
The invention adopts the following technical scheme:
a method of evaluating a water injection well for scaling tendency, comprising the steps of:
s1, establishing a stratum pressure field model by calculating stratum pressure at any point among multiple wells;
s2, establishing a formation temperature field model through the heat exchange process between the fluid and the rock and the heat exchange process between the inner parts of the unit bodies;
s3, establishing a random normal distribution and permeability model of the initial porosity of the stratum;
s4, establishing a scaling prediction model: and predicting the change of the scale distribution range, the scale amount, the scale distribution and the porosity by using a scale prediction model.
Preferably, the conditions for establishing the prediction model are as follows:
(1) the solid phase and the liquid phase can not be compressed and do not generate chemical reaction with each other;
(2) and without considering the influence of capillary force and gravity;
(3) the thickness of the stratum is not changed;
(4) neglecting thermal motion caused by fluid kinetic energy change and viscosity dissipation;
(5) water flooding formation pressures are generally greater than the crude oil bubble point pressure, thus ignoring the presence of gas phases.
Preferably, in step S1, the calculation formula of the formation pressure at any point between multiple wells is:
wherein M is K · Krw/μ.
Preferably, the formation temperature field model is:
wherein:
in the formula, TjFormation temperature, C, without taking into account the exotherm of the acid-rock reaction.
Preferably, the porosity random normal distribution model is as follows:
in the formula, phi0Initial porosity, dimensionless; phi is the porosity after corrosion without dimension; g is an array conforming to random normal distribution, the range is-1 to 1, and the dimension is zero; sigma is a standard deviation coefficient, the value range is 0-1, and the dimension is zero.
Preferably, the fouling prediction model is:
Is＝log(Fs)＝log{[Me][An]/Kc(t,P,Si)}
or
Is＝log{[Me][An]+PKc(t,P,Si)}
Wherein t is temperature, P is pressure, and Si is ionic strength;
the standard for judging whether scale is generated is as follows:
when Is 0, the solution Is in equilibrium with the solid scale;
when Is more than 0, supersaturation state Is shown, and scaling can be formed;
when Is < 0, it means an undersaturated state and scale formation Is not possible.
Preferably, the fouling distribution range is a range between a maximum distance and a minimum distance of the fouling from the well bore, and the calculation formula is as follows:
maximum distance of scale from wellbore:
log{[Me][An]/Kc(T(i,j)max,P(i,j)min,Si)}＝0
minimum distance of scale from wellbore:
log{[Me][An]/Kc(T(i,j)min,P(i,j)min,Si)}＝0
wherein [ Me ] is the cation activity and [ An ] is the anion activity.
Preferably, the formula for calculating the fouling amount is as follows:
in the formula (I), the compound is shown in the specification,
in order to inject the cation concentration, g/L;
g/L is the concentration of extracted cations; mMeIs the cation relative molecular mass; m is the relative molecular mass of the scale.
Preferably, the calculation formula of the fouling distribution is as follows:
preferably, the formula of the change of the porosity is as follows:
the invention has the beneficial effects that:
the invention predicts the scaling trend by establishing the scaling prediction model, so that the scaling trend of the water injection well can be predicted, thereby carrying out accurate scale prevention and ensuring the long-term stable production of the oil and gas well.
Drawings
In order to more clearly illustrate the technical solutions of the embodiments of the present invention, the drawings of the embodiments will be briefly described below, and it is apparent that the drawings in the following description only relate to some embodiments of the present invention and are not limiting on the present invention.
FIG. 1 is a cloud plot of the target well pressure distribution range of the present invention;
FIG. 2 is a cloud of target well temperature profiles in accordance with the present invention;
FIG. 3 is a cloud of target well scale distributions of the present invention;
FIG. 4 shows a target well Ca of the present invention2+A concentration distribution cloud;
FIG. 5 is a schematic illustration of the cumulative amount of scale formation for a target well according to the present invention;
FIG. 6 is a schematic illustration of a target well fouling distribution range according to the present invention;
FIG. 7 is a schematic view of the change in the target well apparent water absorption index of the present invention;
FIG. 8 is a schematic illustration of the amount of fouling along an adjacent well for a target well of the present invention;
FIG. 9 is a schematic of the permeability of a target well of the present invention along an adjacent well;
Detailed Description
In order to make the objects, technical solutions and advantages of the embodiments of the present invention clearer, the technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the drawings of the embodiments of the present invention. It is to be understood that the embodiments described are only a few embodiments of the present invention, and not all embodiments. All other embodiments, which can be derived by a person skilled in the art from the described embodiments of the invention without any inventive step, are within the scope of protection of the invention.
Unless otherwise defined, technical or scientific terms used herein shall have the ordinary meaning as understood by one of ordinary skill in the art to which this disclosure belongs. The use of the word "comprising" or "comprises", and the like, in this disclosure is intended to mean that the elements or items listed before that word, include the elements or items listed after that word, and their equivalents, without excluding other elements or items. "upper", "lower", "left", "right", and the like are used merely to indicate relative positional relationships, and when the absolute position of the object being described is changed, the relative positional relationships may also be changed accordingly.
The invention is further illustrated with reference to the following figures and examples.
As shown in fig. 1 to 9, a method for evaluating a water injection well fouling tendency includes the steps of:
s1, establishing a stratum pressure field model by calculating stratum pressure at any point among multiple wells;
the water injection well is considered to have a constant injection pressure, i.e. a stable production dynamics. According to Darcy's law, there are
For any well in the formation, the flow area a at any distance r is 2 π rh, then the above equation becomes:
let Q be constant, separate the variables and integrate to get:
for oil production wells
For water injection well
According to the principle of potential superposition, multiple wells are produced simultaneously, and the pressure of each point in the stratum is
P＝P1+P2+···+Pn-(n-1)Pe(6)
In the formula:
substituting the formula (7) into the formula (6) to obtain an expression of the formation pressure at any point in the formation when multiple wells are simultaneously produced, wherein the expression is as follows:
from equation (8), the bottom hole flow pressure of the first well is
Subtracting the formula (9) from the formula (8), and calculating the formation pressure at any point between the multiple wells:
taking M as K.Krw/mu, the formula (10) is converted into
S2, establishing a formation temperature field model through the heat exchange process between the fluid and the rock and the heat exchange process between the inner parts of the unit bodies;
the heat exchange process of the simulated minimum unit body i is divided into two parts, one part is the heat exchange process between the fluid and the rock, and the other part is the heat exchange process between the inner parts of the unit bodies.
(1) And heat exchange inside the unit body
The heat transferred into the unit body on the left side is as follows:
the right side outlet unit body heat is:
(2) heat exchange between fluid and rock
The left inflow cell body heat is:
ρLvrrθHCLT (14)
the right outflow unit body heat is:
(3) unit body unit time heat quantity change
From the heat balance equation:
in the formula, vwtThe apparent flow velocity of the liquid at the well wall is m/min; v. ofrThe liquid inflow radial velocity is m/min; t is the radial temperature of the reservoir, DEG C; lambda [ alpha ]LThe heat conductivity coefficient of the injection liquid, kcal/(m-min. DEG C); cLThe specific heat of the injection liquid, kcal/(kg DEG C); lambda [ alpha ]rIs the formation rock thermal conductivity coefficient, kcal/(m.min. DEG C); rhorIs the density of stratum rock in kg/m3；CrIs the specific heat of formation rock, kcal/(kg ℃); h is the layer thickness, m.
The simplified formula (17) is:
wherein:
in the formula, TjThe formation temperature, in degrees c, is not considered for the exothermic acid-rock reaction.
S3, establishing a random normal distribution and permeability model of the initial porosity of the stratum;
establishing a porosity random normal distribution model:
the change in physical properties in the pore medium is characterized according to the semi-empirical relationship of Garman-Kozeny:
in the formula: phi is a0-initial porosity, dimensionless; phi-porosity after erosion, dimensionless; k0-initial permeability, mD, K-permeability after erosion, mD, β -experimentally measured value, dimensionless, G-array according to random normal distribution, range-1, dimensionless, σ -standard deviation coefficient, value range 0-1, dimensionless;
s4, establishing a scaling prediction model: and predicting the change of the scale distribution range, the scale amount, the scale distribution and the porosity by using a scale prediction model.
The conditions for establishing the prediction model are as follows:
(1) the solid phase and the liquid phase can not be compressed and do not generate chemical reaction with each other;
(2) and without considering the influence of capillary force and gravity;
(3) the thickness of the stratum is not changed;
(4) neglecting thermal motion caused by fluid kinetic energy change and viscosity dissipation;
(5) water flooding formation pressures are generally greater than the crude oil bubble point pressure, thus ignoring the presence of gas phases.
And solving a saturation index according to the saturation ratio. The saturation ratio is the ratio of the activity product to the solubility product of the ions, as follows:
FS＝[Me][An]/Ksp (21)
wherein [ Me ] is the cation activity, [ An ] is the anion activity, and Ksp is the solubility product of the substance.
Since activity is the product of the activity coefficient, which is a function of temperature, pressure and ionic strength, and concentration, and the solubility product is a function of temperature, pressure and ionic strength, the solubility product coefficient Kc is used in the prediction equation.
The saturation index Is introduced from the formula (21), and the formula becomes.
Is＝log(Fs)＝log{[Me][An]/Kc(t,P,Si)} (22)
Or
Is＝log{[Me][An]+PKc(t,P,Si)} (23)
Wherein t is temperature, P is pressure, and Si is ionic strength;
the standard for judging whether scale is generated is as follows:
when Is 0, the solution Is in equilibrium with the solid scale;
when Is more than 0, supersaturation state Is shown, and scaling can be formed;
when Is < 0, it means an undersaturated state and scale formation Is not possible.
There are two cases for the model:
(1) in the presence of a gas phase, the equation is as follows:
(2) when no gas phase exists, the equation is shown below.
[Ca2+]The concentration of calcium ions in water is mol/L;
the concentration of bicarbonate ion in water is mol/L;
is at CH4And CO2In the mixed gas (wherein CO)2Low content) of CO2Ease factor of (d);
is prepared from CO under certain conditions of temperature and pressure2Content in the gas phase, mol% or%;
for CO under ground conditions2Content in gas, oil, salt water mixed system, mol% or; qgThe total amount of gas produced daily under standard temperature and pressure conditions, 106m3；
For daily CO production in brine and oil2Content, mol/L; qwM is the amount of water taken out per day3；QoM is the amount of oil produced per day3；
Is CO produced daily under standard temperature and pressure conditions2Gas volume, 106m3。
(1) Scale distribution range
The scale distribution range of the water injection well is the range between the maximum distance and the minimum distance of the scale from the shaft, and is obtained by the following formula:
log{[Me][An]/Kc(T(i,j)max,P(i,j)min,Si)}＝0 (31)
log{[Me][An]/Kc(T(i,j)min,P(i,j)min,Si)}＝0 (32)
(2) amount of scale formation
The scaling amount of the water injection well has important significance on the using amount of the scale inhibitor, and the scaling weight can be obtained by the following formula:
in the formula (I), the compound is shown in the specification,
in order to inject the cation concentration, g/L;
g/L is the concentration of extracted cations; mMeIs the cation relative molecular mass; m is the relative molecular mass of the scale.
(3) Fouling distribution
The scale deposit of water injection well distributes and mainly masters the scale deposit volume of each department, masters each point jam condition, judges the biggest scale deposit point, and its accessible following formula is solved:
(4) change in porosity
The blocking condition of the stratum caused by scaling is obtained by the following formula:
the scale inhibitor used in the prior art has the action mechanism that anions of the scale inhibitor and scale forming cations in water form five-membered or six-membered chelate rings to seal metal ions, prevent the metal ions from contacting with other anions in the water to generate scale forming substances, and increase the saturated solubility of insoluble substances in the water, thereby playing a role in scale inhibition.
According to the conservation of mass:
the introduction of the average scale inhibition rate can obtain:
the scale inhibition rate is related to temperature and pressure, and the two factors are introduced:
and (4) drawing the scale inhibition rate under different temperature and pressure according to an indoor experimental method, and carrying out the above formula.
The first-order partial differential equation and the second-order partial differential equation are discretized by utilizing finite difference, and a numerical method is utilized to implicitly solve the discrete solution on each grid node, namely the dynamic changes of the formation pressure P (i, j, T), the temperature T (i, j, T) and the concentration C (i, j, T) of the scaling ions along with the time and the distance. And substituting the calculation results of P (i, j, T), T (i, j, T) and C (i, j, T) into the scaling model and the scale inhibition model to obtain the dynamic change of the saturation index Is along with time and distance, namely Is (i, j, T), and judging the scaling trend of the oil field water according to the critical saturation index. When the scaling exists, the scaling amount W (i, j) in the unit body and the concentration of the outflowing cations are calculated, the porosity change is solved through a porosity change model, the permeability change is solved according to a Garman-Kozeny semi-empirical relation, and then the flow of the next point is calculated according to the permeability distribution of the nearby points. And then entering a cycle calculation until the minimum fouling concentration is reached.
Examples
TABLE 1 target formation Property parameters
As shown in table 1 and fig. 1 to 4 (target daily water injection rate of 70 cubic meters, total water injection production time of 3 years, and scale inhibitor used in two and a half years), the pressure is reduced from the water injection well mainly along the direction of the oil well, the temperature change is mainly concentrated in a range of about 10m from the well bore, and the temperature of the injected water reaches the original temperature of the formation through heat exchange in the interval, and the temperature of the formation cannot be reduced by extending the temperature outward. The temperature variation range is too small, the temperature is a main influence factor of the scaling, the scaling distribution is determined to be in a smaller range, if the result is not convenient to observe from the whole injection-production unit, and the scaling simulation result is displayed only in a range of 10m around the shaft of the water injection well. Ca2+The water injection well is firstly unchanged along the direction of the oil well, then slowly reduced, then rapidly reduced and finally tends to be unchanged; the scale is distributed in the range of 2-8m from the well shaft of the water injection well, and is mainly distributed in about 5 m.
As shown in fig. 5 to 9, the amount of scale formation increases linearly, and the maximum amount of scale formation is about 5m from the wellbore. After the scale remover is added, anions of the scale remover and scale forming cations in water form five-membered or six-membered chelate rings to seal metal ions, so that the metal ions are prevented from contacting with other anions in the water to generate scale forming substances, the saturated solubility of insoluble substances in the water is increased, the scaling is obviously slowed down, and the accumulated scaling speed is reduced to 9.32 kg/month from 33.3 kg/month; the water absorption index is decreased in a negative index, the water absorption capacity of an oil storage layer is mainly characterized, pores are blocked due to continuous scaling, the formation permeability is decreased continuously, water injection is difficult, if the injection amount is kept unchanged, the water injection pressure needs to be increased continuously, and the cost, the construction difficulty and the risk are increased. As the stratum set in the model is heterogeneous, the scaling amount in each direction is different, and the water injection well is selected to study scaling characteristics along the radial direction of the adjacent well. The scale formation is generated at a position about 2m away from a shaft, mainly because the temperature of injected water is low, the formation temperature of a near-wellbore area is reduced, the temperature is too low, the dissolution equilibrium constant is very small, the scale formation is difficult to generate,in addition, the flow rate of injected water in the near wellbore area is too high, and scale particles are not easy to precipitate, so that the scale is difficult to form; at a distance of about 5m, the formation temperature is high, the flow velocity of injected water is greatly slowed down, and the scale forming is the best place, so a large amount of scale is generated; about 8m, Ca2+The concentration reaches the minimum fouling concentration so no fouling occurs. After the scale inhibitor is added, the highest scaling amount is reduced from 799g/L to 691g/L, and the lowest permeability is reduced from 61X 10-3m2Increase to 65 x 10-3m2。
Although the present invention has been described with reference to a preferred embodiment, it should be understood that various changes, substitutions and alterations can be made herein without departing from the spirit and scope of the invention as defined by the appended claims.
Claims (10)
1. A method of evaluating a water injection well for scaling tendency, comprising the steps of:
s1, establishing a stratum pressure field model by calculating stratum pressure at any point among multiple wells;
s2, establishing a formation temperature field model through the heat exchange process between the fluid and the rock and the heat exchange process between the inner parts of the unit bodies;
s3, establishing a random normal distribution and permeability model of the initial porosity of the stratum;
s4, establishing a scaling prediction model: and predicting the change of the scale distribution range, the scale amount, the scale distribution and the porosity by using a scale prediction model.
2. The method for evaluating the scaling tendency of the water injection well according to the claim 1, characterized in that the prediction model is established under the conditions of:
(1) the solid phase and the liquid phase can not be compressed and do not generate chemical reaction with each other;
(2) and without considering the influence of capillary force and gravity;
(3) the thickness of the stratum is not changed;
(4) neglecting thermal motion caused by fluid kinetic energy change and viscosity dissipation;
(5) ignoring the presence of a gas phase.
3. The method for evaluating the scaling tendency of a water injection well according to claim 1, wherein in step S1, the calculation formula of the formation pressure at any point between multiple wells is:
wherein M is K · Krw/μ.
4. The method of claim 1, wherein the formation temperature field model is:
wherein:
in the formula, TjFormation temperature, C, without taking into account the exotherm of the acid-rock reaction.
5. The method for evaluating the scaling tendency of the water injection well according to the claim 1, wherein the porosity random normal distribution model is as follows:
in the formula, phi0Is initial porosity, noneThe order of the factors; phi is the porosity after corrosion without dimension; g is an array conforming to random normal distribution, the range is-1 to 1, and the dimension is zero; sigma is a standard deviation coefficient, the value range is 0-1, and the dimension is zero.
6. The method for evaluating the scaling tendency of the water injection well according to any one of the claims 1 or 2, characterized in that the scaling prediction model is:
Is＝log(Fs)＝log{[Me][An]/Kc(t,P,Si)}
or
Is＝log{[Me][An]+PKc(t,P,Si)}
Wherein t is temperature, P is pressure, and Si is ionic strength;
the standard for judging whether scale is generated is as follows:
when Is 0, the solution Is in equilibrium with the solid scale;
when Is more than 0, supersaturation state Is shown, and scaling can be formed;
when Is < 0, it means an undersaturated state and scale formation Is not possible.
7. The method for evaluating the scaling tendency of the water injection well according to the claim 6, wherein the scaling distribution range is the range between the maximum distance and the minimum distance of the scaling from the well bore, and the calculation formula is as follows:
maximum distance of scale from wellbore:
log{[Me][An]/Kc(T(i,j)max,P(i,j)min,Si)}＝0
minimum distance of scale from wellbore:
log{[Me][An]/Kc(T(i,j)min,P(i,j)min,Si)}＝0
wherein [ Me ] is the cation activity and [ An ] is the anion activity.
8. The method for evaluating the scaling tendency of the water injection well according to the claim 6, wherein the scaling amount is calculated by the formula:
in the formula (I), the compound is shown in the specification,
in order to inject the cation concentration, g/L;
g/L is the concentration of extracted cations; mMeIs the cation relative molecular mass; m is the relative molecular mass of the scale.
9. The method for evaluating the scaling tendency of the water injection well according to the claim 6, wherein the scaling distribution is calculated by the formula:
10. the method for evaluating the scaling tendency of the water injection well according to the claim 6, wherein the variation formula of the porosity is as follows:
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CN201911170132.8A CN111101925A (en) | 2019-11-26 | 2019-11-26 | Method for evaluating scaling trend of water injection well |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CN201911170132.8A CN111101925A (en) | 2019-11-26 | 2019-11-26 | Method for evaluating scaling trend of water injection well |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CN111101925A true CN111101925A (en) | 2020-05-05 |
Family
ID=70421260
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CN201911170132.8A Pending CN111101925A (en) | 2019-11-26 | 2019-11-26 | Method for evaluating scaling trend of water injection well |
Country Status (1)
| Country | Link |
|---|---|
| CN (1) | CN111101925A (en) |
Cited By (5)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN112065379A (en) * | 2020-10-12 | 2020-12-11 | 西南石油大学 | Method for predicting scaling damage of water injection well |
| CN113656982A (en) * | 2020-08-26 | 2021-11-16 | 中国石油大学(北京) | Modeling method for organic scale damage oil-gas layer, damage degree spatial-temporal evolution 4D quantitative and intelligent diagnosis method and system thereof |
| CN115293066A (en) * | 2022-08-09 | 2022-11-04 | 西南石油大学 | Gas well temperature field calculation method considering stratum seepage heat transfer effect |
| CN115831243A (en) * | 2023-02-21 | 2023-03-21 | 西南石油大学 | Method for predicting critical temperature and pressure of scaling |
| CN115936258A (en) * | 2023-01-09 | 2023-04-07 | 西南石油大学 | Construction method of shaft scaling dynamic deposition blockage prediction model |
Citations (5)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| FR2420025A1 (en) * | 1978-03-16 | 1979-10-12 | Neftegazovy Inst | Petroleum prodn. by hot fluid injection from mine system - with controlled injection and prodn. periods |
| CN104677775A (en) * | 2015-02-06 | 2015-06-03 | 李年银 | Methods for testing performance of removing barium/strontium precipitate and influences on core permeability of chelating agent solution containing organic alkali |
| US20150378052A1 (en) * | 2014-06-27 | 2015-12-31 | Saudi Arabian Oil Company | Methods and systems for estimating sizes and effects of wellbore obstructions in water injection wells |
| CN108804862A (en) * | 2017-05-02 | 2018-11-13 | 中国石油化工股份有限公司 | A kind of prediction technique for calcium carbonate scaling trend |
| CN108843314A (en) * | 2018-07-02 | 2018-11-20 | 中国石油大学(华东) | Experimental provision and method for the evaluation of water-producing gas well pit shaft fouling risk |
-
2019
- 2019-11-26 CN CN201911170132.8A patent/CN111101925A/en active Pending
Patent Citations (5)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| FR2420025A1 (en) * | 1978-03-16 | 1979-10-12 | Neftegazovy Inst | Petroleum prodn. by hot fluid injection from mine system - with controlled injection and prodn. periods |
| US20150378052A1 (en) * | 2014-06-27 | 2015-12-31 | Saudi Arabian Oil Company | Methods and systems for estimating sizes and effects of wellbore obstructions in water injection wells |
| CN104677775A (en) * | 2015-02-06 | 2015-06-03 | 李年银 | Methods for testing performance of removing barium/strontium precipitate and influences on core permeability of chelating agent solution containing organic alkali |
| CN108804862A (en) * | 2017-05-02 | 2018-11-13 | 中国石油化工股份有限公司 | A kind of prediction technique for calcium carbonate scaling trend |
| CN108843314A (en) * | 2018-07-02 | 2018-11-20 | 中国石油大学(华东) | Experimental provision and method for the evaluation of water-producing gas well pit shaft fouling risk |
Non-Patent Citations (4)
| Title |
|---|
| FADAIRO: "Modelling scale saturation around the wellbore for non-Darcy radial flow system", 《EGYPTIAN JOURNAL OF PETROLEUM》 * |
| 张益等: "华池油田结垢预测及软件开发", 《特种油气藏》 * |
| 李年银等: "注采单元地层结垢机理及数值模拟研究", 《油气藏评价与开发》 * |
| 贺代兰等: "冀东油田南堡1-5区注入水相容性研究", 《油气田地面工程》 * |
Cited By (8)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN113656982A (en) * | 2020-08-26 | 2021-11-16 | 中国石油大学(北京) | Modeling method for organic scale damage oil-gas layer, damage degree spatial-temporal evolution 4D quantitative and intelligent diagnosis method and system thereof |
| CN113656982B (en) * | 2020-08-26 | 2022-08-09 | 中国石油大学(北京) | Modeling method for organic scale damage oil-gas layer, damage degree spatial-temporal evolution 4D quantitative and intelligent diagnosis method and system thereof |
| CN112065379A (en) * | 2020-10-12 | 2020-12-11 | 西南石油大学 | Method for predicting scaling damage of water injection well |
| CN115293066A (en) * | 2022-08-09 | 2022-11-04 | 西南石油大学 | Gas well temperature field calculation method considering stratum seepage heat transfer effect |
| CN115293066B (en) * | 2022-08-09 | 2023-09-01 | 西南石油大学 | Gas well temperature field calculation method considering stratum seepage heat transfer effect |
| CN115936258A (en) * | 2023-01-09 | 2023-04-07 | 西南石油大学 | Construction method of shaft scaling dynamic deposition blockage prediction model |
| CN115936258B (en) * | 2023-01-09 | 2023-05-02 | 西南石油大学 | Construction method of wellbore scaling dynamic deposition blocking prediction model |
| CN115831243A (en) * | 2023-02-21 | 2023-03-21 | 西南石油大学 | Method for predicting critical temperature and pressure of scaling |
Similar Documents
| Publication | Publication Date | Title |
|---|---|---|
| CN111101925A (en) | Method for evaluating scaling trend of water injection well | |
| Hoefner et al. | CO2 foam: results from four developmental field trials | |
| Wan et al. | Numerical model and program development of TWH salt cavern construction for UGS | |
| Wang et al. | In-situ CO2 generation for EOR by using urea as a gas generation agent | |
| CN102536166B (en) | Method for deep treatment of oil layer through self-generation foam acidification | |
| CN108868731B (en) | Calculation method of fractured reservoir acid fracturing dynamic comprehensive fluid loss coefficient | |
| CN112347601B (en) | Method for optimizing gas well foam drainage gas production online real-time foaming agent addition | |
| CN104675360A (en) | Leakage-proofing process for exploiting hot-dry-rock geothermal resource by injecting CO2 (supercritical carbon dioxide) | |
| CN106529184A (en) | Method for calculating productivity of water-producing gas well of tilted water-bearing gas reservoir | |
| Nitschke et al. | THC simulation of halite scaling in deep geothermal single well production | |
| Wei et al. | Experimental research on brine crystallization mechanism in solution mining for salt cavern energy storage | |
| Missimer et al. | Hydraulic and density considerations in the design of aquifer storage and recovery systems | |
| Von Hirtz | Silica scale control in geothermal plants—Historical perspective and current technology | |
| CN109918769A (en) | Utilize the method for instantaneous equation calculation fracture-pore reservoir unstable state water enchroachment (invasion) water influx | |
| CN115831243B (en) | Scaling critical temperature and pressure prediction method | |
| CN116738113A (en) | Construction method of mathematical model for predicting scaling position in geothermal well bore | |
| CN105003251A (en) | Method for predicting and calculating quantities of recoverable resources of deep-stratum underground brine single wells | |
| Chasteen | Geothermal steam condensate reinjection | |
| Paramitasari et al. | Injection management at darajat field, Indonesia: impact of moving infield injection to edgefield | |
| Satman et al. | Modeling of production/reinjection behavior of the Kizildere geothermal field by a two-layer geothermal reservoir Lumped-Parameter Model | |
| Champel | Discrepancies in brine density databases at geothermal conditions | |
| Wang et al. | Review on mechanism, prediction, and remediation of salt deposition in gas production wells | |
| Almukhametova et al. | Scaling Prevention on Wells of Tarasovskoe Field | |
| Xie et al. | Modeling debrining of an energy storage salt cavern considering the effects of temperature | |
| Yanto et al. | MANAGING THE CYCLING EFFECT ON WELL EPT-L |
Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| PB01 | Publication | ||
| PB01 | Publication | ||
| SE01 | Entry into force of request for substantive examination | ||
| SE01 | Entry into force of request for substantive examination | ||
| WD01 | Invention patent application deemed withdrawn after publication |
Application publication date: 20200505 |
|
| WD01 | Invention patent application deemed withdrawn after publication |