CN118582198B - A monitoring method for cementing displacement process - Google Patents
A monitoring method for cementing displacement process Download PDFInfo
- Publication number
- CN118582198B CN118582198B CN202411063396.4A CN202411063396A CN118582198B CN 118582198 B CN118582198 B CN 118582198B CN 202411063396 A CN202411063396 A CN 202411063396A CN 118582198 B CN118582198 B CN 118582198B
- Authority
- CN
- China
- Prior art keywords
- fluid
- tracer
- concentration
- well
- cementing
- 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.)
- Active
Links
- 238000000034 method Methods 0.000 title claims abstract description 106
- 238000006073 displacement reaction Methods 0.000 title claims abstract description 55
- 230000008569 process Effects 0.000 title claims abstract description 53
- 238000012544 monitoring process Methods 0.000 title claims abstract description 36
- 239000012530 fluid Substances 0.000 claims abstract description 274
- 239000000700 radioactive tracer Substances 0.000 claims abstract description 181
- 238000005553 drilling Methods 0.000 claims abstract description 111
- 239000002002 slurry Substances 0.000 claims abstract description 98
- 238000005070 sampling Methods 0.000 claims abstract description 58
- 238000005086 pumping Methods 0.000 claims abstract description 28
- 230000029087 digestion Effects 0.000 claims description 40
- 238000011010 flushing procedure Methods 0.000 claims description 36
- 238000000120 microwave digestion Methods 0.000 claims description 29
- VEXZGXHMUGYJMC-UHFFFAOYSA-N Hydrochloric acid Chemical compound Cl VEXZGXHMUGYJMC-UHFFFAOYSA-N 0.000 claims description 23
- 238000002156 mixing Methods 0.000 claims description 23
- 238000001514 detection method Methods 0.000 claims description 22
- 229910052761 rare earth metal Inorganic materials 0.000 claims description 18
- GRYLNZFGIOXLOG-UHFFFAOYSA-N Nitric acid Chemical compound O[N+]([O-])=O GRYLNZFGIOXLOG-UHFFFAOYSA-N 0.000 claims description 14
- 229910017604 nitric acid Inorganic materials 0.000 claims description 14
- 229910052723 transition metal Inorganic materials 0.000 claims description 12
- 229910052689 Holmium Inorganic materials 0.000 claims description 10
- 229910052769 Ytterbium Inorganic materials 0.000 claims description 10
- 238000010438 heat treatment Methods 0.000 claims description 10
- 229910052691 Erbium Inorganic materials 0.000 claims description 8
- UYAHIZSMUZPPFV-UHFFFAOYSA-N erbium Chemical compound [Er] UYAHIZSMUZPPFV-UHFFFAOYSA-N 0.000 claims description 8
- KJZYNXUDTRRSPN-UHFFFAOYSA-N holmium atom Chemical compound [Ho] KJZYNXUDTRRSPN-UHFFFAOYSA-N 0.000 claims description 8
- NAWDYIZEMPQZHO-UHFFFAOYSA-N ytterbium Chemical compound [Yb] NAWDYIZEMPQZHO-UHFFFAOYSA-N 0.000 claims description 8
- 239000000203 mixture Substances 0.000 claims description 6
- 150000003839 salts Chemical class 0.000 claims description 6
- 239000002253 acid Substances 0.000 claims description 4
- 229910052684 Cerium Inorganic materials 0.000 claims description 3
- 229910052692 Dysprosium Inorganic materials 0.000 claims description 3
- 229910052693 Europium Inorganic materials 0.000 claims description 3
- 229910052688 Gadolinium Inorganic materials 0.000 claims description 3
- 229910052765 Lutetium Inorganic materials 0.000 claims description 3
- 229910052779 Neodymium Inorganic materials 0.000 claims description 3
- 229910052777 Praseodymium Inorganic materials 0.000 claims description 3
- 229910052772 Samarium Inorganic materials 0.000 claims description 3
- 229910052771 Terbium Inorganic materials 0.000 claims description 3
- 229910052775 Thulium Inorganic materials 0.000 claims description 3
- GWXLDORMOJMVQZ-UHFFFAOYSA-N cerium Chemical compound [Ce] GWXLDORMOJMVQZ-UHFFFAOYSA-N 0.000 claims description 3
- KBQHZAAAGSGFKK-UHFFFAOYSA-N dysprosium atom Chemical compound [Dy] KBQHZAAAGSGFKK-UHFFFAOYSA-N 0.000 claims description 3
- OGPBJKLSAFTDLK-UHFFFAOYSA-N europium atom Chemical compound [Eu] OGPBJKLSAFTDLK-UHFFFAOYSA-N 0.000 claims description 3
- UIWYJDYFSGRHKR-UHFFFAOYSA-N gadolinium atom Chemical compound [Gd] UIWYJDYFSGRHKR-UHFFFAOYSA-N 0.000 claims description 3
- 229910052746 lanthanum Inorganic materials 0.000 claims description 3
- FZLIPJUXYLNCLC-UHFFFAOYSA-N lanthanum atom Chemical compound [La] FZLIPJUXYLNCLC-UHFFFAOYSA-N 0.000 claims description 3
- OHSVLFRHMCKCQY-UHFFFAOYSA-N lutetium atom Chemical compound [Lu] OHSVLFRHMCKCQY-UHFFFAOYSA-N 0.000 claims description 3
- QEFYFXOXNSNQGX-UHFFFAOYSA-N neodymium atom Chemical compound [Nd] QEFYFXOXNSNQGX-UHFFFAOYSA-N 0.000 claims description 3
- PUDIUYLPXJFUGB-UHFFFAOYSA-N praseodymium atom Chemical compound [Pr] PUDIUYLPXJFUGB-UHFFFAOYSA-N 0.000 claims description 3
- KZUNJOHGWZRPMI-UHFFFAOYSA-N samarium atom Chemical compound [Sm] KZUNJOHGWZRPMI-UHFFFAOYSA-N 0.000 claims description 3
- GZCRRIHWUXGPOV-UHFFFAOYSA-N terbium atom Chemical compound [Tb] GZCRRIHWUXGPOV-UHFFFAOYSA-N 0.000 claims description 3
- 238000009826 distribution Methods 0.000 claims description 2
- 150000004679 hydroxides Chemical class 0.000 claims 2
- 238000002955 isolation Methods 0.000 claims 1
- 239000004568 cement Substances 0.000 abstract description 13
- 238000010276 construction Methods 0.000 abstract description 13
- 238000004088 simulation Methods 0.000 abstract description 6
- 239000007788 liquid Substances 0.000 description 102
- 239000000243 solution Substances 0.000 description 12
- 238000013461 design Methods 0.000 description 11
- 238000002347 injection Methods 0.000 description 9
- 239000007924 injection Substances 0.000 description 9
- 239000012086 standard solution Substances 0.000 description 8
- 238000009616 inductively coupled plasma Methods 0.000 description 5
- 238000005259 measurement Methods 0.000 description 5
- 238000003756 stirring Methods 0.000 description 5
- XLYOFNOQVPJJNP-UHFFFAOYSA-M hydroxide Chemical compound [OH-] XLYOFNOQVPJJNP-UHFFFAOYSA-M 0.000 description 4
- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical compound [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 description 3
- 238000004364 calculation method Methods 0.000 description 3
- 238000011049 filling Methods 0.000 description 3
- 229910002804 graphite Inorganic materials 0.000 description 3
- 239000010439 graphite Substances 0.000 description 3
- 239000011268 mixed slurry Substances 0.000 description 3
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 3
- 238000005266 casting Methods 0.000 description 2
- 230000008859 change Effects 0.000 description 2
- 239000003795 chemical substances by application Substances 0.000 description 2
- 230000000694 effects Effects 0.000 description 2
- 239000000706 filtrate Substances 0.000 description 2
- 238000001914 filtration Methods 0.000 description 2
- 239000007789 gas Substances 0.000 description 2
- 238000004519 manufacturing process Methods 0.000 description 2
- 238000002360 preparation method Methods 0.000 description 2
- 239000002689 soil Substances 0.000 description 2
- 239000011550 stock solution Substances 0.000 description 2
- 239000000126 substance Substances 0.000 description 2
- 230000036962 time dependent Effects 0.000 description 2
- 229910021642 ultra pure water Inorganic materials 0.000 description 2
- 239000012498 ultrapure water Substances 0.000 description 2
- 238000004458 analytical method Methods 0.000 description 1
- 230000009286 beneficial effect Effects 0.000 description 1
- 238000009835 boiling Methods 0.000 description 1
- 239000003153 chemical reaction reagent Substances 0.000 description 1
- 238000001816 cooling Methods 0.000 description 1
- 239000003517 fume Substances 0.000 description 1
- 230000006872 improvement Effects 0.000 description 1
- 238000007689 inspection Methods 0.000 description 1
- 238000013507 mapping Methods 0.000 description 1
- 238000001819 mass spectrum Methods 0.000 description 1
- 239000000463 material Substances 0.000 description 1
- 229910052751 metal Inorganic materials 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- 238000011084 recovery Methods 0.000 description 1
- 239000011435 rock Substances 0.000 description 1
- 238000007789 sealing Methods 0.000 description 1
- 239000013049 sediment Substances 0.000 description 1
- 230000035945 sensitivity Effects 0.000 description 1
- 230000001360 synchronised effect Effects 0.000 description 1
- 238000012360 testing method Methods 0.000 description 1
- 238000010792 warming Methods 0.000 description 1
- 238000005406 washing Methods 0.000 description 1
- 238000005303 weighing Methods 0.000 description 1
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
- E21B47/10—Locating fluid leaks, intrusions or movements
- E21B47/11—Locating fluid leaks, intrusions or movements using tracers; using radioactivity
Landscapes
- Physics & Mathematics (AREA)
- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Geophysics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Analysing Materials By The Use Of Radiation (AREA)
Abstract
本公开的实施例提供一种用于固井顶替过程的监测方法，该方法包括：将投放示踪剂的固井用各入井液按照常规程序分别泵入井眼环空，其中每种入井液中分别投放一种示踪剂且示踪剂种类彼此不同；按预定的取样时刻采集固井返排液样品；检测所述固井返排液样品中各示踪剂浓度；获得取样时刻与各示踪剂浓度的对应关系，实现对顶替过程的监测。该方法通过固井顶替监测示踪的方式，能够实现对实际固井施工中水泥浆对钻井液的顶替过程的实时监测，能够科学地监测固井顶替过程，满足精细化固井和提高顶替效率，解决现有顶替过程监测方法只能用于实验室模拟，以及其存在较大误差的问题。
The embodiment of the present disclosure provides a monitoring method for cementing displacement process, the method comprising: pumping each cementing fluid with a tracer into the wellbore annulus according to a conventional procedure, wherein a tracer is respectively placed in each fluid and the tracers are of different types; collecting cementing flowback fluid samples at a predetermined sampling time; detecting the concentration of each tracer in the cementing flowback fluid sample; obtaining the corresponding relationship between the sampling time and the concentration of each tracer, and realizing the monitoring of the displacement process. The method can realize real-time monitoring of the displacement process of cement slurry for drilling fluid in actual cementing construction by means of cementing displacement monitoring and tracing, can scientifically monitor the cementing displacement process, meet the requirements of refined cementing and improved displacement efficiency, and solve the problem that the existing displacement process monitoring method can only be used for laboratory simulation and has large errors.
Description
Technical Field
The embodiments of the present disclosure relate to the field of oil and gas well drilling, and in particular, to a monitoring method for a well cementation displacement process.
Background
The well cementation is one of important links in the well construction process of the oil and gas well, and is a hidden underground operation project with wide involved area, high risk, high operation requirement and strong technical performance. The well cementation comprises the links of well cementation design, well cementation preparation, well cementation construction, well cementation process, well cementation quality inspection, analysis and the like. The well cementation construction refers to the process of inserting a casing into a well, injecting cement slurry into an annular space/annulus between a well bore and the casing, displacing drilling fluid in the annulus, and solidifying to form a cement wall after the well bore annulus is filled with the cement slurry, so that the sealing of the well wall is realized. In actual well cementation construction, a pre-fluid (flushing fluid or isolating fluid) is pumped in before cement slurry is injected, so that the cement slurry is separated from the drilling fluid, and the cement slurry is prevented from being polluted by the drilling fluid. Because a plurality of fluids are injected into the annulus in the well cementation construction, the annulus slurry column is a complex multiphase flow displacement process, and a displacement interface in the annulus slurry column structure is always in a slurry mixing state. How to mix and displace, the well cementation annular displacement efficiency is affected, and the well cementation quality is determined.
At present, the measurement means in the prior art cannot be realized in actual well cementation construction, or the measurement data is not accurate enough, so that the monitoring of displacement efficiency in the prior art is generally limited to laboratory simulation monitoring, and cannot be used for actual well cementation construction. In actual well cementation construction, the displacement effect is generally judged empirically only by observing the color and state of the well cementation returned liquid, so that the knowledge of the slurry mixing state and the displacement process is lacked, and the requirements of fine well cementation and improvement of the displacement efficiency cannot be met.
Disclosure of Invention
To address the above technical problem, embodiments described herein provide a monitoring method for a well cementation displacement process.
The technical scheme of the invention is as follows:
According to a first aspect of the present disclosure, a monitoring method for a well cementation displacement process is provided. The method comprises the following steps:
Pumping each well-entering liquid for well cementation into which the tracer is put into the well annulus according to a conventional procedure, wherein each well-entering liquid is respectively put with one tracer, and the types of the tracers are different from each other;
collecting a well cementation flowback fluid sample according to a preset sampling time;
Detecting the concentration of each tracer in the well cementation flowback fluid sample;
and obtaining the corresponding relation between the sampling time and the concentration of each tracer, and realizing the monitoring of the displacement process. In some embodiments of the disclosure, the method further comprises the step of evaluating the slurry mixing condition of each well fluid in the well cementation flowback fluid;
The step of evaluating the slurry mixing condition of each well entering liquid in the well cementation flowback liquid comprises the following steps:
According to the corresponding relation between the sampling time and the concentration of each tracer and the put concentration of each tracer, the slurry mixing condition of each well entering liquid in the well cementation flowback fluid is evaluated by the following formula:
the ratio of a certain well-entering liquid in a well cementation flowback liquid at a certain moment=the concentration factor of the certain well-entering liquid at the certain moment/the sum of all the concentration factors of the well-entering liquid at the certain moment 100% （1）；
Detection concentration of tracer injected into certain well fluid in certain well cementation flowback fluid at certain moment = certain well fluid concentration factor/certain well fluid tracer injection concentration100% （2）。
In some embodiments of the present disclosure, the well fluid comprises at least a drilling fluid and a collar fluid.
Correspondingly, the step of pumping each well-entering liquid for well cementation with tracer into the annular space of the well hole according to the conventional procedure comprises the following steps: adding a first tracer into the drilling fluid to obtain a drilling fluid in which the tracer is put, and pumping the drilling fluid in which the tracer is put into the annular space of a borehole; and adding a second tracer into the collar slurry to obtain the collar slurry with the tracer, and pumping the collar slurry with the tracer into the annular space of the well bore after the drilling fluid with the tracer is pumped.
Correspondingly, the ratio of the drilling fluid at a certain moment in the well cementation flowback fluid=the drilling fluid concentration factor at a certain moment/(the drilling fluid concentration factor at a certain moment+the slurry-catching concentration factor at a certain moment)100% （11）；
Ratio of collar slurry at certain moment in well cementation flowback fluid = collar slurry concentration factor at certain moment/(drilling fluid concentration factor at certain moment + collar slurry concentration factor at certain moment)100% （12）；
At a moment, drilling fluid concentration factor=detection concentration of tracer injected into drilling fluid in well cementation flowback fluid at a moment/injection concentration of tracer in drilling fluid100% （21）；
Detection concentration of tracer in collar slurry in well cementation flowback fluid at moment = detection concentration of tracer in collar slurry at moment/delivery concentration of tracer in collar slurry100% （22）。
In some embodiments of the disclosure, the working fluid further comprises a pad fluid. The front liquid is selected from any one of flushing liquid and isolating liquid.
Correspondingly, the step of pumping each well-entering liquid for well cementation with tracer into the annular space of the well hole according to the conventional procedure comprises the following steps: adding a first tracer into the drilling fluid to obtain a drilling fluid in which the tracer is put, and pumping the drilling fluid in which the tracer is put into the annular space of a borehole; adding a third tracer into the pre-fluid to obtain a pre-fluid into which the tracer is put, and pumping the pre-fluid into which the tracer is put into the annular space of the well bore after the drilling fluid into which the tracer is put is pumped; and adding a second tracer into the collar slurry to obtain the collar slurry with the tracer, and pumping the collar slurry with the tracer into the annular space of the well bore after the front-end liquid pump with the tracer is completed.
Correspondingly, the ratio of the drilling fluid at a certain moment in the well cementation flowback fluid=the drilling fluid concentration factor at a certain moment/(the drilling fluid concentration factor at a certain moment+the front fluid concentration factor at a certain moment+the slurry-catching concentration factor at a certain moment)100%（11）；
Ratio of collar slurry at a certain moment in well cementation flowback fluid = collar slurry concentration factor at a certain moment/(drilling fluid concentration factor at a certain moment + pad fluid concentration factor at a certain moment + collar slurry concentration factor at a certain moment)100% （12）；
The ratio of the front fluid at a certain moment in the well cementation flowback fluid=the front fluid concentration factor at a certain moment/(the drilling fluid concentration factor at a certain moment+the front fluid concentration factor at a certain moment+the slurry-catching concentration factor at a certain moment)100%（13）；
At a moment, drilling fluid concentration factor=detection concentration of tracer injected into drilling fluid in well cementation flowback fluid at a moment/injection concentration of tracer in drilling fluid100% （21）；
Detection concentration of tracer in collar slurry in well cementation flowback fluid at moment = detection concentration of tracer in collar slurry at moment/delivery concentration of tracer in collar slurry100% （22）；
At a certain moment, the concentration factor of the head fluid=the detection concentration of the tracer injected into the head fluid in the well cementation flowback fluid at a certain moment/the injection concentration of the tracer in the head fluid100% （23）。
In some embodiments of the present disclosure, the step of collecting a sample of the well cementation flowback fluid at a predetermined sampling time comprises: predicting the starting moment of returning the well entering liquid fed with the tracer from the wellhead; determining sampling time according to sampling interval of 0.2-1 min from the predicted starting time of returning; before sampling, numbering the sampling bottle, and corresponding the sampling bottle number to the sampling time; and collecting a well cementation flowback fluid sample.
In some embodiments of the present disclosure, the starting time T start time of return of the tracer-injected well fluid returning from the wellhead is predicted from the initial time T 0 of the tracer-injected well fluid entering the wellbore annulus, the time it travels from the bottom of the wellbore annulus to the top:
T start time of return = T0+V Wellbore annulus / Q Well logging liquid （3）；
T0= T initial starting drilling fluid pump +V Inside of drill pipe /Q Well logging liquid （4）；
V Inside of drill pipe =π[（R Drill rod -d Drill rod 2）2/4]L Drill rod （5）；
For a wellbore where no variable diameter section is present, the estimated equation for the wellbore annulus volume is:
V Wellbore annulus =π/4（R Well bore 2-R Casing pipe 2）L （6）；
For a wellbore having two variable diameter sections, the estimated equation for the wellbore annulus volume is:
V Wellbore annulus =π/4（R1 Well bore 2-R1 Casing pipe 2）L1+π/4（R2 Well bore 2-R2 Casing pipe 2）L2（7）；
Wherein V Wellbore annulus represents the borehole annulus volume estimated from the borehole structural design data and casing dimensions; q Well logging liquid represents the flow of the well stream into which the tracer is injected, which can be read by a flow meter provided on the pump-in line; t initial starting drilling fluid pump represents the time at which the pump for pumping in the well fluid into which the tracer is to be administered is initially turned on, and in some embodiments of the present disclosure, the time at which the pump for pumping in the well fluid into which the tracer is to be administered is initially turned on is referenced to time 0 to simplify the calculation process; V Inside of drill pipe represents the internal volume of the drill pipe; r Drill rod represents the outer diameter of the drill rod, d Drill rod represents the wall thickness of the drill rod, L Drill rod represents the actual footage of the drill rod, and all the data are known; R Well bore denotes the outer diameter of the wellbore estimated using the bit diameter, R Casing pipe denotes the outer diameter of the casing, L denotes the depth of the well estimated using the designed drill pipe run in, R 1 Well bore denotes the outer diameter of the wellbore section 1 estimated using the bit diameter, R 2 Well bore denotes the outer diameter of the wellbore section 2 estimated using the bit diameter, R 1 Casing pipe represents the casing outside diameter of section 1, R 2 Casing pipe represents the casing outside diameter of section 2, L 1 represents the estimated well depth of section 1 using the designed drill pipe run-in, L 2 represents the estimated well depth of section 2 using the designed drill pipe run-in, these data are all known data.
Equation (7) is described using the example of a wellbore having two variable diameter sections, and similarly, if there are multiple variable diameter sections, the sum of the wellbore annular volumes of the multiple variable diameter sections is taken as the total wellbore annular volume.
In some embodiments of the present disclosure, to avoid missing the start time of the actual return, sampling is started 5-10 minutes ahead of the predicted start time of the return.
In some embodiments of the present disclosure, the end time of the tracer-injected well fluid returning from the wellhead is predicted from the predicted start time of the return, the running time of the total tracer-injected well fluid pumped into the wellbore annulus.
In some embodiments of the present disclosure, the sampling is ended 10-20 minutes after the end time of the predicted return to ensure that the sampling time encompasses the end time of the actual return.
In some embodiments of the disclosure, the concentration of each tracer in the well cementation flowback fluid sample is detected after digestion treatment of the well cementation flowback fluid sample.
In some embodiments of the disclosure, the digestion is microwave digestion;
the microwave digestion process comprises the following steps: and mixing the well cementation flowback fluid sample and the digestion liquid in a digestion tank, then placing the mixture in a microwave digestion instrument, and heating the microwave digestion instrument to a digestion temperature so as to perform microwave digestion on the sample.
In some embodiments of the disclosure, the digestion solution is a mixture of concentrated nitric acid and concentrated hydrochloric acid; the volume ratio of the concentrated nitric acid to the concentrated hydrochloric acid is (1-6): 1.
In some embodiments of the present disclosure, the digestion liquid is used in an amount of at least 9ml of digestion liquid per 0.5g of the well cementation flowback fluid sample.
In some embodiments of the present disclosure, the means of increasing the temperature is a gradient increase in temperature.
In some embodiments of the present disclosure, the digestion temperature is no greater than 190 ℃.
In some embodiments of the present disclosure, the method further comprises the step of acid-repelling the sample after microwave digestion.
In some embodiments of the present disclosure, the tracer is selected from any one of an oxide of a transition metal element, a hydroxide of a transition metal element, a salt of a transition metal element, a complex of a transition metal element.
In some embodiments of the present disclosure, the tracer is selected from any one of an oxide of a rare earth element, a hydroxide of a rare earth element, a salt of a rare earth element, a complex of a rare earth element.
In some embodiments of the present disclosure, the rare earth element is selected from any one of lanthanum, cerium, praseodymium, neodymium, samarium, europium, gadolinium, terbium, dysprosium, holmium, erbium, thulium, ytterbium, lutetium.
The beneficial technical effects of the invention are as follows:
According to the monitoring method for the well cementation displacement process, provided by the embodiment of the invention, the displacement process of cement slurry in actual well cementation construction on drilling fluid can be monitored in real time in a well cementation displacement monitoring and tracing mode. Specifically, because different types of tracers are respectively put into each well entering liquid for well cementation such as drilling liquid, cement slurry and the like, the concentration of each tracer in the well cementation flowback liquid is detected and corresponds to the sampling time, so that the displacement process of the corresponding well entering liquid in an annulus during flowback is reflected through the distribution condition of each tracer concentration along with time, namely the displacement process of each well entering liquid in a well cementation slurry column structure. Because the method measures in the actual well cementation construction process, the error caused by the fact that a laboratory simulation device cannot simulate the actual situation can be avoided, and the displacement process is monitored more accurately and intuitively. Therefore, the method can scientifically monitor the well cementation displacement process, meet the requirements of fine well cementation and improve the displacement efficiency, and solve the problems that the existing displacement process monitoring method can only be used for laboratory simulation and has larger error. In addition, the method has short time, is synchronous with the drilling and well cementation construction operation, does not interfere with the normal drilling and well cementation operation, and does not need to delay the construction period of the drilling and well cementation operation; and the method has low cost.
Furthermore, the monitoring method can be used for evaluating the slurry mixing condition/slurry mixing state of each well entering liquid in the well cementation flowback fluid through calculation by combining the put-in concentration of each tracer on the basis of the corresponding relation between the sampling time and the concentration of each tracer. Specifically, firstly, comparing the detected concentration of each tracer in the well cementation flowback fluid at a certain moment with the input concentration of the corresponding tracer, calculating the concentration factor of each well entering fluid, and normalizing the concentration; and then comparing the concentration factor of each well entering liquid with the total concentration factor (namely the sum of all the well entering liquid concentration factors), so as to obtain the duty ratio of each well entering liquid in the well cementation flowback liquid, namely the mixed slurry condition/mixed state and degree of each well entering liquid in the well cementation slurry column structure when the well entering liquid is returned out (particularly in the middle and later stages of returning out), particularly the mixed slurry state of the collar slurry and the drilling liquid at the final stage of the flowback, or the mixed slurry state of the collar slurry and the drilling liquid and the front liquid, and the displacement efficiency of cement slurry/collar slurry to the displaced liquid can be reflected laterally, so that a basis is provided for the simulation of the displacement efficiency.
According to the method, the microwave digestion is firstly carried out on the well cementation flowback fluid sample, the well cementation flowback fluid sample can be completely digested into clear liquid by controlling the components, proportion, consumption, digestion temperature, heating mode and the like, so that the measured concentration of the tracer in the sample can more truly represent the real concentration of the tracer, and the recovery rate of the tracer in the well cementation flowback fluid can reach more than 98.9%.
Drawings
In order to more clearly illustrate the technical solutions of the embodiments of the present disclosure, the following brief description of the drawings of the embodiments will be given, it being understood that the drawings described below relate only to some embodiments of the present disclosure, not to limitations of the present disclosure, in which:
FIG. 1 is a schematic flow chart of a method for monitoring a well cementation displacement process according to an embodiment of the present invention;
FIG. 2 is a schematic flow chart of a method for monitoring a well cementation displacement process according to another embodiment of the present invention;
FIG. 3 is a graph showing the time concentration of each tracer in the well cementation flowback fluid provided by the application example of the invention.
Detailed Description
In order to make the objects, technical solutions and advantages of the embodiments of the present disclosure more apparent, the technical solutions of the embodiments of the present disclosure will be clearly and completely described below with reference to the accompanying drawings. It will be apparent that the described embodiments are some, but not all, of the embodiments of the present disclosure. All other embodiments, which can be made by those skilled in the art based on the described embodiments of the present disclosure without the need for creative efforts, are also within the scope of the protection of the present disclosure.
Unless otherwise defined, all terms (including technical and scientific terms) used herein have the same meaning as commonly understood by one of ordinary skill in the art to which the presently disclosed subject matter belongs. It will be further understood that terms, such as those defined in commonly used dictionaries, should be interpreted as having a meaning that is consistent with their meaning in the context of the specification and relevant art and will not be interpreted in an idealized or overly formal sense unless expressly so defined herein. As used herein, a statement that two or more parts are "connected" or "coupled" together shall mean that the parts are joined together either directly or joined through one or more intermediate parts.
The reagents used in the examples were as follows:
Ultrapure water with resistivity not less than 18 mu m omega cm; concentrated nitric acid: ρ (HNO 3) =1.42 g/ml (mass fraction of nitric acid 71.6%), superior purity; concentrated hydrochloric acid: ρ (HCl) =1.19 g/ml (mass fraction of hydrochloric acid 40%), superior purity; external standard solution: mixed standard solution of rare earth elements Ho, er and Yb, wherein rho=10mug/ml; internal standard solution (for investigating the stability of the instrumental measurements): rh standard solution (ρ=100 μg/ml), re standard solution (ρ=100 μg/ml); mass spectrometer tuning liquid: ρ=10μg/L.
The instruments and equipment used in the examples and application examples are as follows:
an inductively coupled plasma mass spectrometer; analytical balance: precision 0.0001g; a microwave digestion instrument; a graphite digestion instrument; a filtering device; and (5) an ultrapure water instrument.
Example 1
Fig. 1 is a schematic flow chart of a monitoring method for a well cementation displacement process according to an embodiment of the present invention, as shown in fig. 1, and the method includes the following steps:
S1, pumping each well-entering liquid for well cementation into which the tracer is put into the annular space of the well bore according to a conventional procedure.
Wherein each well fluid is respectively provided with a tracer, and the types of the tracers are different from each other.
In particular embodiments, the well fluid includes drilling fluid, pad fluid, and collar fluid. The step of pumping each well-entering liquid for well cementation into which the tracer is put into the annular space of the well bore respectively according to the conventional procedure comprises the following steps: adding a first tracer into the drilling fluid to obtain a drilling fluid in which the tracer is put, and pumping the drilling fluid in which the tracer is put into the annular space of a borehole; adding a third tracer into the pre-fluid to obtain a pre-fluid into which the tracer is put, and pumping the pre-fluid into which the tracer is put into the annular space of the well bore after the drilling fluid into which the tracer is put is pumped; and adding a third tracer into the collar slurry to obtain the collar slurry with the tracer, and pumping the collar slurry with the tracer into the annular space of the well bore after the front-end liquid pump with the tracer is completed.
The method comprises the steps of (1) slowly adding 20L of a first tracer solution into about 10m 3 of drilling fluid at a filling port of a drilling fluid tank, circulating for 4 hours by using a slurry pump, and continuously stirring a stirring blade in the tank to ensure that a tracer is uniformly mixed with the drilling fluid to obtain the drilling fluid added with the tracer; slowly adding a second tracer solution 20L into the flushing liquid at the position of a flushing liquid tank bin filling port, circulating for 2 hours by using a slurry mixing pump, and simultaneously rotating stirring blades in the tank to ensure that the tracer and the flushing liquid are uniformly mixed to obtain the flushing liquid in which the tracer is put; 5L of third tracer solution is used for replacing part of the collar slurry preparation water to prepare collar slurry for adding the tracer in the volume of about 10m 3, and stirring is continuously carried out by using stirring blades to ensure that the tracer and the collar slurry are uniformly mixed, so as to obtain the collar slurry for adding the tracer; pumping the drilling fluid fed with the tracer, the flushing fluid fed with the tracer and the slurry-taking device fed with the tracer into the well annulus from the bottom of the well in sequence, and simultaneously recording the initial time of pumping into the well annulus and the pumping amount of each.
In a specific embodiment, before drilling fluid for adding the tracer, flushing fluid for adding the tracer and slurry for adding the tracer are pumped, samples for adding the tracer are collected for multiple times at the filling openings of respective material tanks, for example, 3 times, and the sampling interval is 1-2 min, so that the adding concentration of the corresponding tracer in each sample is obtained through detection.
In a specific embodiment, the tracer delivery concentration in the drilling fluid for delivering the tracer, the pre-fluid for delivering the tracer and the collar slurry for delivering the tracer is greater than the detection limit of the detection instrument and greater than 20 times of the background concentration of the corresponding tracer contained in the drilling fluid stock solution so as to eliminate the interference of the background concentration of the tracer and improve the detection accuracy.
In a specific embodiment, the substance as the tracer is any one of an oxide of a transition metal element, a hydroxide of a transition metal element, a salt of a transition metal element, and a complex of a transition metal element. Further, the substance used as the tracer is any one of an oxide of a rare earth element, a hydroxide of a rare earth element, a salt of a rare earth element, and a complex of a rare earth element. The rare earth element can be any one of lanthanum, cerium, praseodymium, neodymium, samarium, europium, gadolinium, terbium, dysprosium, holmium, erbium, thulium, ytterbium and lutetium.
Illustratively, the first tracer is a complex of ytterbium (Yb), the third tracer is a complex of erbium (Er), and the second tracer is a complex of holmium (Ho).
S2, collecting a well cementation flowback fluid sample according to a preset sampling time.
In a specific embodiment, the step of collecting a sample of the well cementation flowback fluid at a predetermined sampling time comprises: predicting the starting moment of returning the well entering liquid fed with the tracer from the wellhead; determining sampling time according to sampling interval of 0.2-1 min from the predicted starting time of returning; before sampling, numbering the sampling bottle, and corresponding the sampling bottle number to the sampling time; and collecting a well cementation flowback fluid sample.
In a specific embodiment, the starting time T start time of return of returning the tracer-injected well fluid from the wellhead is predicted according to the initial time T 0 of entering the wellbore annulus by the tracer-injected well fluid and the time of running from the bottom to the top of the wellbore annulus:
T start time of return = T0+V Wellbore annulus / Q Well logging liquid （3）；
T0= T initial starting drilling fluid pump +V Inside of drill pipe /Q Well logging liquid （4）；
V Inside of drill pipe =π[（R Drill rod -d Drill rod 2）2/4]L Drill rod （5）；
For a wellbore where no variable diameter section is present, the estimated equation for the wellbore annulus volume is:
V Wellbore annulus =π/4（R Well bore 2-R Casing pipe 2）L （6）；
For a wellbore having two variable diameter sections, the estimated equation for the wellbore annulus volume is:
V Wellbore annulus =π/4（R1 Well bore 2-R1 Casing pipe 2）L1+π/4（R2 Well bore 2-R2 Casing pipe 2）L2（7）；
Wherein V Wellbore annulus represents the borehole annulus volume estimated from the borehole structural design data and casing dimensions; q Well logging liquid represents the flow of the well stream into which the tracer is injected, which can be read by a flow meter provided on the pump-in line; t initial starting drilling fluid pump represents the time at which the pump for pumping in the well fluid into which the tracer is to be administered is initially turned on, and in some embodiments of the present disclosure, the time at which the pump for pumping in the well fluid into which the tracer is to be administered is initially turned on is referenced to time 0 to simplify the calculation process; V Inside of drill pipe represents the internal volume of the drill pipe; r Drill rod represents the outer diameter of the drill rod, d Drill rod represents the wall thickness of the drill rod, L Drill rod represents the actual footage of the drill rod, and all the data are known; R Well bore denotes the outer diameter of the wellbore estimated using the bit diameter, R Casing pipe denotes the outer diameter of the casing, L denotes the depth of the well estimated using the designed drill pipe run in, R 1 Well bore denotes the outer diameter of the wellbore section 1 estimated using the bit diameter, R 2 Well bore denotes the outer diameter of the wellbore section 2 estimated using the bit diameter, R 1 Casing pipe represents the casing outside diameter of section 1, R 2 Casing pipe represents the casing outside diameter of section 2, L 1 represents the estimated well depth of section 1 using the designed drill pipe run-in, L 2 represents the estimated well depth of section 2 using the designed drill pipe run-in, these data are all known data.
Equation (7) is described using the example of a wellbore having two variable diameter sections, and similarly, if there are multiple variable diameter sections, the sum of the wellbore annular volumes of the multiple variable diameter sections is taken as the total wellbore annular volume.
In a specific embodiment, in order to avoid missing the actual start time of the return, sampling is started 5 to 10 minutes ahead of the predicted start time of the return.
In a specific embodiment, the end time of returning the tracer-injected well fluid from the wellhead is predicted according to the predicted start time of returning and the running time of the total pumping-in amount of the tracer-injected well fluid in the well annulus.
For example, the end time T End time of return of the return of the tracer-injected well fluid from the wellhead can be predicted by the following equation:
T End time of return =T start time of return +V Well logging liquid / Q Well logging liquid （8）；
Wherein, T start time of return is calculated by a formula (3), V Well logging liquid represents the total pumping-in amount of the well fluid into which the tracer is put, and Q Well logging liquid represents the flow rate of the well fluid into which the tracer is put.
It should be noted that the flow rate of the well fluid into which the tracer is put is different, for example: the current discharge capacity of the drilling fluid is 1.12m 3/min; the discharge rate of the flushing liquid is 0.63m 3/min at the moment; the discharge capacity of the slurry is 1.58m 3/min.
In a specific embodiment, the sampling is ended 10-20 minutes after the end time of the predicted return to ensure that the sampling time covers the end time of the actual return.
The sampling time interval can be adjusted according to the flow rate and the actual working condition of the well cementation flowback fluid; in addition, the sampling tool is rinsed for a plurality of times in real time in the sampling process.
S3, detecting the concentration of each tracer in the well cementation flowback fluid sample.
In a specific embodiment, the step of detecting the concentration of the tracer in the well cementation flowback fluid sample comprises: and after carrying out microwave digestion treatment on the well cementation flowback fluid sample, detecting the concentration of each tracer in the well cementation flowback fluid sample by an inductively coupled plasma mass spectrometer. The reference standard for microwave digestion treatment is the digestion microwave digestion method of total amount of HJ832-2021 soil and sediment metal elements; the mass spectrum detection reference standard is an inductively coupled plasma mass spectrometer for measuring 65 elements of HJ700-2014 water quality.
The microwave digestion process comprises the following steps: and mixing the well cementation flowback fluid sample and the digestion liquid in a digestion tank, then placing the mixture in a microwave digestion instrument, and heating the microwave digestion instrument to a digestion temperature so as to perform microwave digestion on the sample.
In a specific embodiment, the digestion solution is a mixture of concentrated nitric acid and concentrated hydrochloric acid; the volume ratio of the concentrated nitric acid to the concentrated hydrochloric acid is (1-6): 1; the concentrated hydrochloric acid refers to hydrochloric acid with the concentration of more than 30% (mass fraction, g/100 g); the concentrated nitric acid refers to nitric acid with the concentration of more than 60% (mass fraction, g/100 g); the using amount of the digestion liquid is at least 9ml per 0.5g of the volume of the digestion liquid used by the well cementation flowback fluid sample; the heating mode is gradient heating; the digestion temperature is not greater than 190 ℃.
Illustratively, the microwave digestion process includes: weighing 0.5g of well cementation flowback fluid sample, placing the sample in a digestion tank, sequentially adding 6ml of concentrated nitric acid and 3ml of concentrated hydrochloric acid, fully and uniformly mixing the sample and the digestion solution, placing the digestion tank into a bracket of the digestion tank, placing the bracket into a furnace chamber of a microwave digestion instrument, sequentially heating the microwave digestion instrument to each digestion temperature according to a gradient heating program of table 1, and keeping for a period of time so as to perform microwave digestion on the sample, and cooling after the program is finished. And taking out the digestion tank in the acid-proof fume hood after the temperature in the tank is reduced to the room temperature, slowly decompressing and deflating, and opening the digestion tank cover.
TABLE 1 microwave digestion gradient warming procedure
| Program | Digestion temperature | Hold time |
| 1 | Room temperature 90 DEG C | 5min |
| 2 | 90→120℃ | 5min |
| 3 | 120→190℃ | 60min |
In a specific embodiment, the method further comprises the step of acid removal of the sample after microwave digestion. Illustratively, acid is removed through graphite digestion, specifically, the digestion tank is moved to a graphite furnace digestion instrument, the heating temperature is set to 120 ℃, and acid is removed in a boiling state for 30min.
In a specific embodiment, the method further comprises the steps of fixing the volume and filtering the acid-removed sample.
The digestion tank is taken out, residual liquid in the tank is transferred into a 50ml centrifuge tube, the inner wall of the digestion tank is washed by nitric acid solution with the concentration of 2% (mass fraction, g/100 g), washing liquid is transferred into the centrifuge tube, then the volume of the digestion tank is fixed by 50g by nitric acid solution with the concentration of 2% (mass fraction, g/100 g), shaking is carried out uniformly, liquid in the centrifuge tube is filtered after standing for 60min to obtain filtrate, and 10ml of filtrate is taken out and transferred into a test tube to be tested.
In a specific embodiment, the step of detecting the concentration of the tracer in the cementing flowback fluid sample and each well-entering fluid sample for cementing by using an inductively coupled plasma mass spectrometer comprises the following steps: after the plasma is ignited, the instrument is preheated for 30min, and then the sensitivity, the oxide and the double charges of the instrument are tuned by using a mass spectrometer tuning liquid; preparing a series of standard solutions of elements to be detected by using a rare earth element mixed standard solution, measuring the standard solutions of the elements to be detected by using an inductively coupled plasma mass spectrometer, and drawing a standard curve of the elements to be detected; finally, the concentration of the rare earth elements of the three tracers in each sample is measured, before the measurement, the system is flushed with a nitric acid solution with the concentration of 2% (mass fraction, g/100 g) until the signal is minimized, and the measurement of the sample is started after the analyzed signal is stabilized.
And S4, obtaining the corresponding relation between the sampling time and the concentration of each tracer, and realizing the monitoring of the displacement process.
In a specific embodiment, the step of obtaining the correspondence between the sampling time and the concentration of each tracer, and implementing the monitoring of the displacement process includes: and (3) corresponding the detection result of the concentration of each tracer in the step (S3) to the sampling time in the step (S2), drawing a table or drawing a time concentration curve graph of each tracer in the well cementation flowback fluid, and obtaining the time-dependent change relation of the concentration of the three tracers in the well cementation flowback fluid sample, wherein the time-dependent change relation reflects the displacement process of the collar slurry, the drilling fluid and the flushing fluid.
Example 2
The monitoring method for the well cementation displacement process of the embodiment further comprises S5, as shown in fig. 2, of evaluating the slurry mixing condition of each well entering liquid in the well cementation flowback liquid on the basis of the embodiment 1.
In a specific embodiment, the step of evaluating the slurry mixing condition of each well entering liquid in the well cementation flowback fluid comprises the following steps:
According to the corresponding relation between the sampling time and the concentration of each tracer and the put concentration of each tracer, the slurry mixing condition of each well entering liquid in the well cementation flowback fluid is evaluated by the following formula:
the ratio of a certain well-entering liquid in a well cementation flowback liquid at a certain moment=the concentration factor of the certain well-entering liquid at the certain moment/the sum of all the concentration factors of the well-entering liquid at the certain moment 100% （1）；
Detection concentration of tracer injected into certain well fluid in certain well cementation flowback fluid at certain moment = certain well fluid concentration factor/certain well fluid tracer injection concentration100% （2）。
In a specific embodiment, the well entering liquid comprises drilling liquid, a front-end liquid and a collar slurry, and the ratio of the three well entering liquids in the well cementation flowback liquid and the concentration factor formulas of the three well entering liquids are as follows;
The ratio of drilling fluid at a certain moment in the well cementation flowback fluid=the drilling fluid concentration factor at a certain moment/(the drilling fluid concentration factor at a certain moment+the front fluid concentration factor at a certain moment+the slurry-catching concentration factor at a certain moment) 100%（11）；
Ratio of collar slurry at a certain moment in well cementation flowback fluid = collar slurry concentration factor at a certain moment/(drilling fluid concentration factor at a certain moment + pad fluid concentration factor at a certain moment + collar slurry concentration factor at a certain moment)100% （12）；
The ratio of the front fluid at a certain moment in the well cementation flowback fluid=the front fluid concentration factor at a certain moment/(the drilling fluid concentration factor at a certain moment+the front fluid concentration factor at a certain moment+the slurry-catching concentration factor at a certain moment)100%（13）；
At a moment, drilling fluid concentration factor=detection concentration of tracer injected into drilling fluid in well cementation flowback fluid at a moment/injection concentration of tracer in drilling fluid100% （21）；
Detection concentration of tracer in collar slurry in well cementation flowback fluid at moment = detection concentration of tracer in collar slurry at moment/delivery concentration of tracer in collar slurry100% （22）；
At a certain moment, the concentration factor of the head fluid=the detection concentration of the tracer injected into the head fluid in the well cementation flowback fluid at a certain moment/the injection concentration of the tracer in the head fluid100% （23）。
According to formulas (21) to (23), the ratio of the detected concentration of the tracer injected into each well injection liquid in the well cementation flowback liquid at a certain moment to the injection concentration can be obtained, and the concentration is normalized; according to formulas (11) - (13), the ratio of each well entering liquid in the well cementation flowback liquid at a certain moment, namely the mixing condition/mixing state and degree of each well entering liquid in the well cementation slurry column structure when the well entering liquid is returned out (especially in the middle and later stages of the returning), especially the mixing state of the slurry collecting and drilling liquid and the front liquid at the final stage of the flowback can be used for reflecting the displacement efficiency of the cement slurry/the slurry collecting to the displaced liquid laterally, and providing a basis for the simulation of the displacement efficiency. The denominator of formulas (11) - (13) is the total duty ratio of the concentration factors of the three injected well entering liquids, namely the duty ratio of each well entering liquid in the well cementation flowback liquid formed by all the well entering liquids is only displayed, so that the influence of the residual part of slurry, stratum rock soil and stratum water in the flowback process on the concentration of each tracer is eliminated.
Application example 1
A monitoring method for a well cementation displacement process of example 1 was applied to an actual production well whose well bore structural design data: drilling a drill bit with the diameter of 311.1mm to 500m; the drill bit with the diameter of 215.9mm is drilled to 1859m.
Sleeve selection: one-way design phi 244.5mm x 500m sleeve; phi 139.7mm x 1859m sleeve was designed for two-way design.
The outer diameter of the drill rod is 127mm, the wall thickness is 7.52mm, the actual length 1743m of the drill rod,
The flow rate of drilling fluid into which the tracer is put is 1.12m 3/min, the flow rate of flushing fluid into which the tracer is put is 0.63m 3/min, and the slurry-catching flow rate into which the tracer is put is 1.58m 3/min.
With the moment when the drilling liquid pump for pumping the drilling liquid into which the tracer is put being initially started being 0 moment, the initial moment T 0 = pi when the drilling liquid into which the tracer is put enters the borehole annulus[（127-7.522）2/4]1859/1000000=18.30m3/1.12 m3/min =16.34min；
The annulus volume vcell annulus estimated from the well bore structural design data and casing dimensions is 43.45m 3:
V wellbore annulus = pi/4 （311.12-244.52）500/1000000+π/4（215.92-139.72）(1859-500)/1000000=43.45m3；
Predicting the starting moment T returning from the wellhead of the drilling fluid injected with the tracer = T 0 + V borehole annulus/Q drilling fluid = 16.34+43.45/1.12 = 55.13min ≡55min;
predicting end time of returning of collar slurry fed with tracer from wellhead
Initial moment T 0 = pi of feeding tracer to get into borehole annulus[（127-7.522）2/4]1859/1000000=18.30m3/1.58 m3/min =11.58min；
Predicting the starting moment T returning from the wellhead of the drilling fluid injected with the tracer agent = T 0 + V borehole annulus/Q drilling fluid = 11.58+43.45/1.58 = 39.08min ≡39min;
predicting the end time tstretched from the end time tstretched of the tracer put in from the wellhead = the start time tstretched + V/Q drilling fluid = 39+9.5/1.58 = 45.01min.
The method comprises the following steps:
Pumping drilling fluid 13.5m 3 of ytterbium complex, flushing fluid 8.8m 3 of erbium complex and collar slurry 9.5m 3 of holmium complex into the well annulus in sequence;
Acquiring a well cementation flowback fluid sample 5min in advance according to the predicted flowback starting time until the sampling is finished 15min after the predicted flowback ending time;
Detecting the complex concentration of ytterbium, the complex of erbium and the complex concentration of holmium after carrying out microwave digestion treatment on all the well cementation flowback fluid samples;
And obtaining the corresponding relation between the sampling time and the concentration of each tracer, and realizing the monitoring of the displacement process. As shown in table 2 and fig. 3, the displacement process is: starting to return from 10.00min of drilling fluid for initially starting a pump (time 0) for pumping the well fluid into which the tracer is put, and arranging the drilling fluid in a concentrated flow back way during 11.00-19.50 min; the flushing fluid starts to return from 20.00min, and the flushing fluid is mixed with the drilling fluid and returns during 20 min-24.33 min; returning from 24.67min to 26.67min, and collecting flowback during 25min to 26.67 min; wherein the slurry is mixed with the drilling fluid and the flushing fluid and returned out in the period of 24.67 min-25 min; the slurry is mixed with the flushing fluid and returned out in the period of 25.33 min-25.67 min; and (3) leading the slurry to return independently in the period of 26.00-26.67 min, wherein the Ho concentration in the slurry reaches the casting concentration, and the Yb in the drilling fluid and the Er in the flushing fluid are both in local concentrations, which indicates that the cement slurry has returned to the designed depth.
TABLE 2 mapping of actual well tracer concentration to sampling time
| Sampling time/min | 0.00 | 1.00 | 2.00 | 3.00 | 4.00 | 5.00 |
| Yb concentration/. Mu.g/L | 3.744 | 0.100 | 3.542 | 1.969 | 6.000 | 4.731 |
| Er concentration/. Mu.g/L | 0.207 | 0.699 | 0.408 | 0.683 | 0.147 | 0.467 |
| Ho concentration/. Mu.g/L | 0.259 | 1.235 | 0.466 | 0.380 | 0.266 | 1.133 |
| Sampling time/min | 6.00 | 7.00 | 8.00 | 9.00 | 10.00 | 11.00 |
| Yb concentration/. Mu.g/L | 3.221 | 4.064 | 6.428 | 6.760 | 56.866 | 351.642 |
| Er concentration/. Mu.g/L | 0.373 | 0.485 | 0.552 | 0.584 | 0.488 | 0.098 |
| Ho concentration/. Mu.g/L | 0.480 | 0.784 | 0.243 | 1.087 | 0.055 | 0.632 |
| Sampling time/min | 12.00 | 13.00 | 14.00 | 15.00 | 16.00 | 17.00 |
| Yb concentration/. Mu.g/L | 326.854 | 365.369 | 361.235 | 360.081 | 347.573 | 351.317 |
| Er concentration/. Mu.g/L | 0.253 | 0.587 | 0.378 | 0.543 | 0.453 | 0.210 |
| Ho concentration/. Mu.g/L | 0.783 | 0.805 | 1.147 | 0.073 | 0.215 | 1.114 |
| Sampling time/min | 18.00 | 18.50 | 19.00 | 19.50 | 20.00 | 20.33 |
| Yb concentration/. Mu.g/L | 329.625 | 361.488 | 369.864 | 342.836 | 282.962 | 230.341 |
| Er concentration/. Mu.g/L | 0.048 | 0.583 | 0.053 | 0.478 | 98.609 | 154.329 |
| Ho concentration/. Mu.g/L | 0.532 | 1.123 | 0.551 | 0.831 | 1.125 | 0.613 |
| Sampling time/min | 20.67 | 21.00 | 21.33 | 21.67 | 22.00 | 22.33 |
| Yb concentration/. Mu.g/L | 186.723 | 160.306 | 116.839 | 203.564 | 196.381 | 169.466 |
| Er concentration/. Mu.g/L | 203.672 | 243.082 | 291.275 | 190.534 | 200.035 | 235.612 |
| Ho concentration/. Mu.g/L | 1.036 | 0.572 | 0.665 | 1.107 | 0.159 | 1.171 |
| Sampling time/min | 22.67 | 23.00 | 23.33 | 23.67 | 24.00 | 24.33 |
| Yb concentration/. Mu.g/L | 65.511 | 161.371 | 242.463 | 269.763 | 120.356 | 141.824 |
| Er concentration/. Mu.g/L | 348.127 | 228.639 | 155.339 | 127.420 | 287.584 | 262.521 |
| Ho concentration/. Mu.g/L | 0.206 | 1.106 | 0.036 | 1.011 | 0.359 | 0.313 |
| Sampling time/min | 24.67 | 25.00 | 25.33 | 25.67 | 26.00 | 26.33 |
| Yb concentration/. Mu.g/L | 69.110 | 30.103 | 3.079 | 3.541 | 7.808 | 5.356 |
| Er concentration/. Mu.g/L | 177.112 | 146.086 | 61.634 | 34.703 | 0.125 | 0.684 |
| Ho concentration/. Mu.g/L | 141.975 | 214.517 | 343.254 | 367.379 | 384.724 | 366.882 |
| Sampling time/min | 26.67 | |||||
| Yb concentration/. Mu.g/L | 6.688 | |||||
| Er concentration/. Mu.g/L | 0.136 | |||||
| Ho concentration/. Mu.g/L | 385.305 |
Note that: the background concentration of Yb contained in the drilling fluid stock solution is 0.100-6.76 mu g/L (corresponding sampling time is 0.00-9.00 min), the background concentration of Er is 0.048-0.699 mu g/L (corresponding sampling time is 0.00-19.50 min), the background concentration of Ho is 0.036-1.235 mu g/L (corresponding sampling time is 0.00-24.33 min); the tracer concentration in the drilling fluid C （Yb） = 368.603 μg/L, the tracer concentration in the head fluid C （Er） = 439.633 μg/L, and the tracer concentration in the collar slurry C （Ho） = 386.134 μg/L.
Application example 2
A monitoring method for a well cementation displacement process of example 1 was applied to an actual production well whose well bore structural design data: drilling a drill bit with the diameter of 311.1mm to 500m; the drill bit with the diameter of 215.9mm is drilled to 1859m.
Sleeve selection: one-way design phi 244.5mm x 500m sleeve; phi 139.7mm x 1859m sleeve was designed for two-way design.
The outer diameter of the drill rod is 127mm, the wall thickness is 7.52mm, the actual length 1743m of the drill rod,
The flow rate of drilling fluid into which the tracer is put is 1.12m 3/min, the flow rate of flushing fluid into which the tracer is put is 0.63m 3/min, and the slurry-catching flow rate into which the tracer is put is 1.58m 3/min.
With the moment when the drilling liquid pump for pumping the drilling liquid into which the tracer is put being initially started being 0 moment, the initial moment T 0 = pi when the drilling liquid into which the tracer is put enters the borehole annulus[（127-7.522）2/4]1859/1000000=18.30m3/1.12 m3/min =16.34min；
The annulus volume vcell annulus estimated from the well bore structural design data and casing dimensions is 43.45m 3:
V wellbore annulus = pi/4 （311.12-244.52）500/1000000+π/4（215.92-139.72）(1859-500)/1000000=43.45m3；
Predicting the starting moment T returning from the wellhead of the drilling fluid injected with the tracer = T 0 + V borehole annulus/Q drilling fluid = 16.34+43.45/1.12 = 55.13min ≡55min;
predicting end time of returning of collar slurry fed with tracer from wellhead
Initial moment T 0 = pi of feeding tracer to get into borehole annulus[（127-7.522）2/4]1859/1000000=18.30m3/1.58 m3/min =11.58min；
Predicting the starting moment T returning from the wellhead of the drilling fluid injected with the tracer agent = T 0 + V borehole annulus/Q drilling fluid = 11.58+43.45/1.58 = 39.08min ≡39min;
predicting the end time tstretched from the end time tstretched of the tracer put in from the wellhead = the start time tstretched + V/Q drilling fluid = 39+9.5/1.58 = 45.01min.
The method comprises the following steps:
Pumping drilling fluid 13.5m 3 of ytterbium complex, flushing fluid 8.8m 3 of erbium complex and collar slurry 9.5m 3 of holmium complex into the well annulus in sequence;
Acquiring a well cementation flowback fluid sample 5min in advance according to the predicted flowback starting time until the sampling is finished 15min after the predicted flowback ending time;
Detecting the complex concentration of ytterbium, the complex of erbium and the complex concentration of holmium after carrying out microwave digestion treatment on all the well cementation flowback fluid samples;
And obtaining the corresponding relation between the sampling time and the concentration of each tracer, and realizing the monitoring of the displacement process. As shown in table 3 and fig. 3, the displacement process is: starting to return from 10.00min of drilling fluid for initially starting a pump (time 0) for pumping the well fluid into which the tracer is put, and arranging the drilling fluid in a concentrated flow back way during 11.00-19.50 min; the flushing fluid starts to return from 20.00min, and the flushing fluid is mixed with the drilling fluid and returns during 20 min-24.33 min; returning from 24.67min to 26.67min, and collecting flowback during 25min to 26.67 min; wherein the slurry is mixed with the drilling fluid and the flushing fluid and returned out in the period of 24.67 min-25 min; the slurry is mixed with the flushing fluid and returned out in the period of 25.33 min-25.67 min; and (3) leading the slurry to return independently in the period of 26.00-26.67 min, wherein the Ho concentration in the slurry reaches the casting concentration, and the Yb in the drilling fluid and the Er in the flushing fluid are both in local concentrations, which indicates that the cement slurry has returned to the designed depth.
The data in Table 3 are carried into the following formula to evaluate the slurry mixing condition of each well entering liquid in the well cementation flowback fluid:
The ratio of drilling fluid in the well cementation annular flowback fluid is tau Drilling fluid :
τ Drilling fluid =α/(α+β+γ)100% （21）
the ratio of flushing fluid in the well cementation annular flowback fluid is tau Flushing liquid :
τ Flushing liquid =β/(α+β+γ)100% （22）
the ratio of collar slurry in the well cementation annular flowback fluid is tau Collar slurry :
τ Collar slurry =γ/(α+β+γ)100% （23）
Note that: alpha represents the ratio of the detected concentration of Yb in the well cementation annular flowback fluid to the thrown concentration of Yb in the drilling fluid at a certain moment;
Beta represents the ratio of the detection concentration of Er in the well cementation annular flowback fluid to the throwing concentration of Er in the flushing fluid at a certain moment;
gamma represents the ratio of the detection concentration of Ho in the well cementation annular flowback fluid to the throwing concentration of Ho in the collar slurry at a certain moment.
The obtained correspondence of the sampling timings with α, β, γ, (α+β+γ), τ Drilling fluid 、τ Flushing liquid , and τ Collar slurry is shown in table 3.
TABLE 3 mixing conditions of drilling fluid, flushing fluid and collar slurry in well cementing flowback fluid
| Sampling time/min | α | β | γ | α+β+γ | τ Drilling fluid | τ Flushing liquid | τ Collar slurry |
| 10.00 | 0.154 | 0.001 | 0.000 | 0.155 | 99.2% | 0.7% | 0.1% |
| 11.00 | 0.953 | 0.000 | 0.002 | 0.955 | 99.8% | 0.0% | 0.2% |
| 12.00 | 0.886 | 0.001 | 0.002 | 0.889 | 99.7% | 0.1% | 0.2% |
| 13.00 | 0.991 | 0.001 | 0.002 | 0.994 | 99.7% | 0.1% | 0.2% |
| 14.00 | 0.979 | 0.001 | 0.003 | 0.983 | 99.6% | 0.1% | 0.3% |
| 15.00 | 0.976 | 0.001 | 0.000 | 0.978 | 99.9% | 0.1% | 0.0% |
| 16.00 | 0.942 | 0.001 | 0.001 | 0.944 | 99.8% | 0.1% | 0.1% |
| 17.00 | 0.953 | 0.000 | 0.003 | 0.956 | 99.6% | 0.1% | 0.3% |
| 18.00 | 0.894 | 0.000 | 0.001 | 0.895 | 99.8% | 0.0% | 0.2% |
| 18.50 | 0.980 | 0.001 | 0.003 | 0.984 | 99.6% | 0.1% | 0.3% |
| 19.00 | 1.003 | 0.000 | 0.001 | 1.004 | 99.8% | 0.0% | 0.1% |
| 19.50 | 0.930 | 0.001 | 0.002 | 0.933 | 99.7% | 0.1% | 0.2% |
| 20.00 | 0.767 | 0.224 | 0.003 | 0.995 | 77.1% | 22.6% | 0.3% |
| 20.33 | 0.625 | 0.351 | 0.002 | 0.977 | 63.9% | 35.9% | 0.2% |
| 20.67 | 0.506 | 0.464 | 0.003 | 0.973 | 52.1% | 47.7% | 0.3% |
| 21.00 | 0.435 | 0.553 | 0.001 | 0.989 | 43.9% | 55.9% | 0.1% |
| 21.33 | 0.317 | 0.663 | 0.002 | 0.981 | 32.3% | 67.5% | 0.2% |
| 21.67 | 0.552 | 0.434 | 0.003 | 0.988 | 55.8% | 43.9% | 0.3% |
| 22.00 | 0.532 | 0.455 | 0.000 | 0.988 | 53.9% | 46.1% | 0.0% |
| 22.33 | 0.460 | 0.536 | 0.003 | 0.999 | 46.0% | 53.7% | 0.3% |
| 22.67 | 0.178 | 0.792 | 0.001 | 0.971 | 18.3% | 81.6% | 0.1% |
| 23.00 | 0.438 | 0.520 | 0.003 | 0.961 | 45.5% | 54.2% | 0.3% |
| 23.33 | 0.657 | 0.354 | 0.000 | 1.011 | 65.0% | 35.0% | 0.0% |
| 23.67 | 0.731 | 0.290 | 0.003 | 1.024 | 71.4% | 28.3% | 0.3% |
| 24.00 | 0.326 | 0.655 | 0.001 | 0.982 | 33.2% | 66.7% | 0.1% |
| 24.33 | 0.385 | 0.598 | 0.001 | 0.983 | 39.1% | 60.8% | 0.1% |
| 24.67 | 0.187 | 0.403 | 0.368 | 0.958 | 19.6% | 42.1% | 38.4% |
| 25.00 | 0.082 | 0.332 | 0.556 | 0.970 | 8.4% | 34.3% | 57.3% |
| 25.33 | 0.008 | 0.140 | 0.889 | 1.038 | 0.8% | 13.5% | 85.7% |
| 25.67 | 0.010 | 0.079 | 0.951 | 1.040 | 0.9% | 7.6% | 91.5% |
| 26.00 | 0.021 | 0.000 | 0.996 | 1.018 | 2.1% | 0.0% | 97.9% |
| 26.33 | 0.015 | 0.002 | 0.950 | 0.966 | 1.5% | 0.2% | 98.3% |
| 26.67 | 0.018 | 0.000 | 0.998 | 1.016 | 1.8% | 0.0% | 98.2% |
Note that: since the cementing flowback fluid sample was at a local concentration substantially before 10.00min, the flowback fluid was started after 10.00min, and thus only 10.00min later data were taken in table 3.
As can be seen from Table 3, during the flowback period of 10.00 min-26.67 min, the respective ratios of Yb, er and Ho in the well cementation flowback fluid at any sampling time reflect the mixing condition of drilling fluid, flushing fluid and collar slurry in the well cementation slurry column structure during the flowback period.
For example, in table 3, at 24.67min, the values of τ drilling fluid, τ flushing fluid, and τ collar slurry were 19.6%, 42.1%, and 38.4%, respectively, which means that the ratios of drilling fluid, flushing fluid, and collar slurry contained in the flowback fluid at 24.67min were 19.6%, 42.1%, and 38.4%, respectively, that is, the ratios of drilling fluid, flushing fluid, and collar slurry involved in the mixing.
As used herein and in the appended claims, the singular forms of words include the plural and vice versa, unless the context clearly dictates otherwise. Thus, when referring to the singular, the plural of the corresponding term is generally included. Similarly, the terms "comprising" and "including" are to be construed as being inclusive rather than exclusive. Likewise, the terms "comprising" and "or" should be interpreted as inclusive, unless such an interpretation is expressly prohibited herein. Where the term "example" is used herein, particularly when it follows a set of terms, the "example" is merely exemplary and illustrative and should not be considered exclusive or broad.
Further aspects and scope of applicability will become apparent from the description provided herein. It is to be understood that various aspects of the application may be implemented alone or in combination with one or more other aspects. It should also be understood that the description and specific examples are intended for purposes of illustration only and are not intended to limit the scope of the present disclosure.
While several embodiments of the present disclosure have been described in detail, it will be apparent to those skilled in the art that various modifications and variations can be made to the embodiments of the present disclosure without departing from the spirit and scope of the disclosure. The scope of the present disclosure is defined by the appended claims.
Claims (8)
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CN202411063396.4A CN118582198B (en) | 2024-08-05 | 2024-08-05 | A monitoring method for cementing displacement process |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CN202411063396.4A CN118582198B (en) | 2024-08-05 | 2024-08-05 | A monitoring method for cementing displacement process |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| CN118582198A CN118582198A (en) | 2024-09-03 |
| CN118582198B true CN118582198B (en) | 2024-11-26 |
Family
ID=92526171
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CN202411063396.4A Active CN118582198B (en) | 2024-08-05 | 2024-08-05 | A monitoring method for cementing displacement process |
Country Status (1)
| Country | Link |
|---|---|
| CN (1) | CN118582198B (en) |
Citations (5)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN103556986A (en) * | 2013-11-11 | 2014-02-05 | 中国石油化工股份有限公司 | Measuring method for displacement efficiency of simulated well cementation cementing |
| CN109113704A (en) * | 2018-08-09 | 2019-01-01 | 中国石油天然气股份有限公司 | Tracing monitoring method for multi-stage fracturing flowback fluid |
| CN110541704A (en) * | 2019-09-10 | 2019-12-06 | 大庆亿莱检验检测技术服务有限公司 | method for evaluating staged water yield of compact oil multi-stage fracturing well by using tracer |
| CN113376244A (en) * | 2021-07-21 | 2021-09-10 | 青岛大地新能源技术研究院 | Detection method of thickened oil water-soluble tracer |
| CN118325594A (en) * | 2023-01-10 | 2024-07-12 | 大庆石油管理局有限公司 | An identifiable high-efficiency cementing pre-fluid, preparation process and application |
Family Cites Families (3)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| MX2007004800A (en) * | 2004-10-22 | 2007-12-11 | Core Lab L P | Method for determining tracer concentration in oil and gas production fluids. |
| CN108729909A (en) * | 2018-06-01 | 2018-11-02 | 青岛大地新能源技术研究院 | A method of utilizing Uranium determination agent level monitoring well staged fracturing effect |
| CN109931052A (en) * | 2019-03-19 | 2019-06-25 | 固安国勘石油技术有限公司 | Utilize the method for effect and production capacity situation after tracer monitoring oil well delamination or staged fracturing |
-
2024
- 2024-08-05 CN CN202411063396.4A patent/CN118582198B/en active Active
Patent Citations (5)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN103556986A (en) * | 2013-11-11 | 2014-02-05 | 中国石油化工股份有限公司 | Measuring method for displacement efficiency of simulated well cementation cementing |
| CN109113704A (en) * | 2018-08-09 | 2019-01-01 | 中国石油天然气股份有限公司 | Tracing monitoring method for multi-stage fracturing flowback fluid |
| CN110541704A (en) * | 2019-09-10 | 2019-12-06 | 大庆亿莱检验检测技术服务有限公司 | method for evaluating staged water yield of compact oil multi-stage fracturing well by using tracer |
| CN113376244A (en) * | 2021-07-21 | 2021-09-10 | 青岛大地新能源技术研究院 | Detection method of thickened oil water-soluble tracer |
| CN118325594A (en) * | 2023-01-10 | 2024-07-12 | 大庆石油管理局有限公司 | An identifiable high-efficiency cementing pre-fluid, preparation process and application |
Also Published As
| Publication number | Publication date |
|---|---|
| CN118582198A (en) | 2024-09-03 |
Similar Documents
| Publication | Publication Date | Title |
|---|---|---|
| CN107989588B (en) | Method and system for testing oil-gas-water profile of each section of horizontal well by using environment-friendly tracer | |
| EP0282232B1 (en) | Monitoring drilling mud circulation | |
| US8162049B2 (en) | Injection-backflow technique for measuring fracture surface area adjacent to a wellbore | |
| CN109113704A (en) | Tracing monitoring method for multi-stage fracturing flowback fluid | |
| Novakowski | The analysis of tracer experiments conducted in divergent radial flow fields | |
| US9267371B2 (en) | Oil and gas fracture liquid tracing with oligonucleotides | |
| US11384636B2 (en) | Method to determine tracer response from non-ideal chemical tracers | |
| US20220017815A1 (en) | Tracer eluting proppants for hydraulic fracturing | |
| US8360143B2 (en) | Method of determining end member concentrations | |
| CN1699998B (en) | Constant quantity substance tracer agent for oilfield monitoring and application in oil deposit dynamic monitoring | |
| US4782898A (en) | Determining residual oil saturation using carbon 14 labeled carbon dioxide | |
| Reilly et al. | Experimental evaluation of factors affecting temporal variability of water samples obtained from long‐screened wells | |
| RU164347U1 (en) | DEVICE WITH INDICATOR IN AN AMPOULE FOR TRACER RESEARCH OF HORIZONTAL WELL WITH SEPARATED INTERVAL PACKERS AND INTERMEDIATE HYDRAULIC BREAKING | |
| CN118582198B (en) | A monitoring method for cementing displacement process | |
| US6498341B2 (en) | Method for characterizing ground water measurement points by distinguishing ground water from subterranean water accumulation | |
| CN112943226A (en) | Method for evaluating staged fracturing effect and oil-water contribution of each stage of horizontal well by oil-water tracer | |
| CN112943227A (en) | Lanthanide complex staged fracturing tracing technology | |
| US20150198037A1 (en) | Back titration methods for scaling cations and downhole tools for performing such methods | |
| CN110412064B (en) | Drilling fluid nuclear magnetic resonance on-line measuring system | |
| CN118564238B (en) | Method for evaluating annular volume of well bore | |
| CN117418829A (en) | Method for testing horizontal well fluid production profile using quantum dot tracers | |
| CN111622749A (en) | Water exploration pipe column and water exploration method for thick oil thermal recovery screen pipe well completion horizontal well | |
| US10066482B2 (en) | Method and systems for integrating downhole fluid data with surface mud-gas data | |
| CN1049719C (en) | Method for testing water-covering oil layer saturation degree by using normal boring sample-test reference | |
| CN110185443B (en) | Sampling method for water injection pressure maintaining |
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 | ||
| GR01 | Patent grant | ||
| GR01 | Patent grant |