CN113266333A - By extrusion of saturated CO2Method for improving permeability of oil sand reservoir by using brine - Google Patents
By extrusion of saturated CO2Method for improving permeability of oil sand reservoir by using brine Download PDFInfo
- Publication number
- CN113266333A CN113266333A CN202110724704.3A CN202110724704A CN113266333A CN 113266333 A CN113266333 A CN 113266333A CN 202110724704 A CN202110724704 A CN 202110724704A CN 113266333 A CN113266333 A CN 113266333A
- Authority
- CN
- China
- Prior art keywords
- permeability
- well
- saturated
- brine
- pressure
- 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.)
- Granted
Links
- 230000035699 permeability Effects 0.000 title claims abstract description 152
- 229920006395 saturated elastomer Polymers 0.000 title claims abstract description 57
- 239000012267 brine Substances 0.000 title claims abstract description 52
- HPALAKNZSZLMCH-UHFFFAOYSA-M sodium;chloride;hydrate Chemical compound O.[Na+].[Cl-] HPALAKNZSZLMCH-UHFFFAOYSA-M 0.000 title claims abstract description 40
- 239000003027 oil sand Substances 0.000 title claims abstract description 32
- 238000001125 extrusion Methods 0.000 title claims abstract description 20
- 238000000034 method Methods 0.000 claims abstract description 44
- FAPWRFPIFSIZLT-UHFFFAOYSA-M Sodium chloride Chemical compound [Na+].[Cl-] FAPWRFPIFSIZLT-UHFFFAOYSA-M 0.000 claims abstract description 37
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims abstract description 37
- 238000002347 injection Methods 0.000 claims abstract description 29
- 239000007924 injection Substances 0.000 claims abstract description 29
- 239000011780 sodium chloride Substances 0.000 claims abstract description 19
- 239000000243 solution Substances 0.000 claims abstract description 19
- 239000007788 liquid Substances 0.000 claims abstract description 16
- 230000006872 improvement Effects 0.000 claims abstract description 14
- 239000010779 crude oil Substances 0.000 claims abstract description 8
- 238000010796 Steam-assisted gravity drainage Methods 0.000 claims description 17
- 230000015572 biosynthetic process Effects 0.000 claims description 16
- 238000012360 testing method Methods 0.000 claims description 14
- 238000010276 construction Methods 0.000 claims description 11
- 230000008569 process Effects 0.000 claims description 11
- BTCSSZJGUNDROE-UHFFFAOYSA-N gamma-aminobutyric acid Chemical compound NCCCC(O)=O BTCSSZJGUNDROE-UHFFFAOYSA-N 0.000 claims description 9
- 239000011148 porous material Substances 0.000 claims description 8
- 239000012530 fluid Substances 0.000 claims description 7
- 238000004519 manufacturing process Methods 0.000 claims description 7
- 238000011160 research Methods 0.000 claims description 7
- 230000002706 hydrostatic effect Effects 0.000 claims description 6
- 238000005259 measurement Methods 0.000 claims description 6
- 238000002791 soaking Methods 0.000 claims description 5
- 230000009466 transformation Effects 0.000 claims description 5
- BVKZGUZCCUSVTD-UHFFFAOYSA-M Bicarbonate Chemical compound OC([O-])=O BVKZGUZCCUSVTD-UHFFFAOYSA-M 0.000 claims description 4
- 230000020477 pH reduction Effects 0.000 claims description 4
- 238000010793 Steam injection (oil industry) Methods 0.000 claims description 3
- 238000004140 cleaning Methods 0.000 claims description 3
- 239000008398 formation water Substances 0.000 claims description 3
- 238000009533 lab test Methods 0.000 claims description 3
- 238000010297 mechanical methods and process Methods 0.000 claims description 3
- 238000007789 sealing Methods 0.000 claims description 3
- 238000013517 stratification Methods 0.000 claims description 3
- 230000001052 transient effect Effects 0.000 claims description 3
- 238000011835 investigation Methods 0.000 claims description 2
- 238000009738 saturating Methods 0.000 claims description 2
- 230000000694 effects Effects 0.000 abstract description 8
- 238000011084 recovery Methods 0.000 abstract description 2
- 238000001802 infusion Methods 0.000 abstract 1
- 239000010410 layer Substances 0.000 description 50
- 239000003921 oil Substances 0.000 description 14
- 208000010392 Bone Fractures Diseases 0.000 description 9
- 206010017076 Fracture Diseases 0.000 description 9
- 230000004048 modification Effects 0.000 description 8
- 238000012986 modification Methods 0.000 description 8
- 238000011068 loading method Methods 0.000 description 7
- 230000009286 beneficial effect Effects 0.000 description 5
- 238000010586 diagram Methods 0.000 description 5
- 239000011435 rock Substances 0.000 description 5
- 239000002253 acid Substances 0.000 description 4
- 230000007797 corrosion Effects 0.000 description 4
- 238000005260 corrosion Methods 0.000 description 4
- 238000005516 engineering process Methods 0.000 description 4
- 239000004576 sand Substances 0.000 description 4
- 239000002131 composite material Substances 0.000 description 3
- 238000011161 development Methods 0.000 description 3
- 230000018109 developmental process Effects 0.000 description 3
- 230000003628 erosive effect Effects 0.000 description 3
- 238000005530 etching Methods 0.000 description 3
- 239000000203 mixture Substances 0.000 description 3
- 230000009471 action Effects 0.000 description 2
- 239000004568 cement Substances 0.000 description 2
- 238000004891 communication Methods 0.000 description 2
- 238000007596 consolidation process Methods 0.000 description 2
- 238000000605 extraction Methods 0.000 description 2
- 239000000295 fuel oil Substances 0.000 description 2
- 229910021532 Calcite Inorganic materials 0.000 description 1
- 208000013201 Stress fracture Diseases 0.000 description 1
- 239000003929 acidic solution Substances 0.000 description 1
- 230000002378 acidificating effect Effects 0.000 description 1
- 230000032683 aging Effects 0.000 description 1
- 230000008901 benefit Effects 0.000 description 1
- 230000033558 biomineral tissue development Effects 0.000 description 1
- 238000006243 chemical reaction Methods 0.000 description 1
- 230000003247 decreasing effect Effects 0.000 description 1
- 230000007812 deficiency Effects 0.000 description 1
- 238000005553 drilling Methods 0.000 description 1
- 238000002474 experimental method Methods 0.000 description 1
- 238000005470 impregnation Methods 0.000 description 1
- 230000000977 initiatory effect Effects 0.000 description 1
- 229910052500 inorganic mineral Inorganic materials 0.000 description 1
- 230000003993 interaction Effects 0.000 description 1
- 239000011229 interlayer Substances 0.000 description 1
- 230000007246 mechanism Effects 0.000 description 1
- 239000011707 mineral Substances 0.000 description 1
- 229920000642 polymer Polymers 0.000 description 1
- 238000002360 preparation method Methods 0.000 description 1
- 230000009467 reduction Effects 0.000 description 1
- 230000004044 response Effects 0.000 description 1
- 150000003839 salts Chemical class 0.000 description 1
- 239000002689 soil 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
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/25—Methods for stimulating production
- E21B43/26—Methods for stimulating production by forming crevices or fractures
-
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
- Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
- Y02P90/00—Enabling technologies with a potential contribution to greenhouse gas [GHG] emissions mitigation
- Y02P90/70—Combining sequestration of CO2 and exploitation of hydrocarbons by injecting CO2 or carbonated water in oil wells
Landscapes
- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Investigation Of Foundation Soil And Reinforcement Of Foundation Soil By Compacting Or Drainage (AREA)
Abstract
By extrusion of saturated CO2The method for improving the permeability of the oil sand reservoir by using the brine calculates the integral permeability variation coefficient of a permeability profile, reasonably selects conventional water injection and injects saturated CO at normal temperature2Saline, high temperature CO injection2Saturated brine; calculating a permeability improvement coefficient, and drawing a relation between the initial permeability and the permeability improvement coefficient; reasonably controlling wellhead pressure will saturate CO2Gradually and slowly squeezing saline water into a reservoir; recalculating the integral permeability coefficient of variation, and successfully modifying when the integral coefficient of variation of the stratum is reduced to be less than 0.5; if the integral permeability variation coefficient of the stratum is still larger than 0.5, injecting CO again at high temperature2Brine for 24 hours or extending the infusion time by 2 days. Under the premise of not influencing the traditional liquid squeezing and capacity expansion effect, CO is used2The solution selectively erodes the argillaceous components, and weakens the heterogeneity of permeability along the well bore direction while increasing the whole permeability of the reservoir, thereby ensuring the even expansion of the steam cavity along the well bore direction, increasing the crude oil yield,and the crude oil recovery rate is improved.
Description
Technical Field
The invention belongs to the technical field of unconventional oil and gas reservoir transformation and oil and gas development, and particularly relates to a method for improving oil and gas reservoirs by squeezing saturated CO2A method for improving permeability of oil sand reservoirs with brine.
Background
The oil sand reservoir liquid squeezing and capacity expanding technology is applied to marine oil sand in the Alberta Canada region for the first time, and a sand grain contact structure of the oil sand reservoir liquid squeezing and capacity expanding technology forms an interlocking structure similar to a super-consolidation soil state under the action of glaciers. The land-phase heavy oil reservoir in the oilfield of the Xinjiang Fengcheng is not compacted by glaciers, the reservoir layer structure is loose, the physical interlayer develops, and the capacity expansion mechanism of the reservoir layer structure is different from that of Canada marine-phase oil sand. The key of the technology lies in whether a reservoir layer can be circularly preheated in a short time to form a uniform steam cavity, and the porosity, permeability and water saturation of the reservoir layer are improved and the preheating period is shortened by adopting a mode of squeezing water into a high-pressure stratum between a horizontal well pair before preheating.
China has abundant super heavy oil sand resources, but reservoir expansion potential is low, crude oil viscosity is high, heterogeneity is strong, oil sand mud content is high, the SAGD startup stage preheating period is long, and steam consumption is large. At present, based on the quick and uniform starting of SAGD of oil sand micro-fracturing water injection, the oil field of the northwest wind city of the Xinjiang Quadrature basin is subjected to pilot exploration and development. After water injection and capacity expansion are carried out on the well group FHW302, the communication degree of the horizontal section reaches 73% when the steam circulation is switched for 25 days, compared with the preheating time of other 13 pairs of conventional starting well groups which are developed in the same period in the same block, the preheating time is shortened by 46%, and the steam consumption is reduced by 55%. In addition, the average preheating period of the windward oil field after the well group expansion construction of the heavy 1 well zone 2 and the heavy 18 well zone 9 is respectively shortened by 80% and 71%. However, most wells in Xinjiang oil fields for micro fracturing are affected by heterogeneous reservoirs, and the actual production effect is poorer than that of the conventional preheating effect.
Due to the influence of the heterogeneity of the oil reservoir, the consolidation compactness of the reservoir stratum in the actual horizontal shaft direction is different, so that the fracture pressure at different positions in the shaft direction is different, the expansion of the loose section is obvious, the expansion of the compact section is not obvious, and the heterogeneity of the reservoir stratum is further expanded, so that dozens of wells actually implemented in the Xinjiang oil field are only effective for one third of the wells, and the actual production effect of most wells influenced by the heterogeneity is worse than the conventional preheating effect.
Laboratory or field experiments prove that CO2After the sandstone reservoir is injected, mud is formed within 2 to 3 daysThe cement undergoes erosion in an acidic environment and the permeability is significantly increased. Thus, the use of CO is contemplated2The acidic solution erodes the cement in the oil sand. On one hand, along the direction of a shaft, the part with high argillaceous content has low permeability, high pore pressure and CO2The solution has high acidity and strong corrosion action; low permeability, low pore pressure, and CO at low argillaceous sites2The acidity of the solution is low, and the corrosion effect is weak, and the selective corrosion characteristic reduces the heterogeneity of permeability along the direction of a shaft; on the other hand, perpendicular to the direction of the wellbore, CO2The solution can chemically react with the argillaceous components within the micro-fracturing construction time to generate erosion pores, so that the permeability of a remote stratum and the overall permeability of a reservoir are increased.
Disclosure of Invention
In order to overcome the above-mentioned drawbacks of the prior art, it is an object of the present invention to provide a method for the impregnation of saturated CO by extrusion2The method for improving the permeability of the oil sand reservoir by using brine solves the problem of intensified permeability heterogeneity along the well hole direction in the existing oil sand liquid squeezing technology, and realizes the purpose of CO passing through the oil sand reservoir on the premise of not influencing the traditional liquid squeezing capacity expansion effect2The solution selectively erodes the argillaceous components, and the permeability heterogeneity along the well bore direction is weakened while the whole permeability of the reservoir is increased, so that the steam cavity is ensured to be uniformly expanded along the well bore direction, the crude oil yield is increased, and the crude oil recovery rate is improved.
In order to achieve the purpose, the invention adopts the technical scheme that:
by extrusion of saturated CO2The method for improving the permeability of the oil sand reservoir by using brine is characterized by comprising the following steps:
step 1): acquiring a permeability section of a reservoir layer near the SAGD well through well logging interpretation, wherein the permeability section is a section of a well bore axis passing through an I well and a P well (the I well and the P well are respectively a steam injection well and a production well in the SAGD well); researching the range from 5m above a well I to the bottom of a reservoir, layering every 1m in the vertical direction, wherein the number of layering is N, and dividing grids every 1m in each layer in the horizontal direction;
step 2): reading permeability values of grids in each layer, and measuringCalculating the permeability coefficient of variation V of each layerm(ii) a According to the distance between each layer and the shaft, different weight coefficients are given to different layers, the sum of the weight coefficients of permeability variation coefficients of each layer is 1, and the whole permeability variation coefficient V in the research range is calculatedt；
Permeability coefficient of variation V of mth layermThe formula for calculating (a) is as follows,
in the formula, m is 1-H; h is the total number of stratification in the study area; n is the number of grids of each layer; kiPermeability values corresponding to each hierarchical mesh;
the average value of the permeability corresponding to each layered grid;
the overall permeability coefficient of variation Vt is calculated as:
Vt＝λ1V1+λ2V2+…λmVm+…+λHVH
in the formula, λmA weight coefficient which is a permeability coefficient of variation of the mth layer;
step 3): if the integral permeability variation coefficient is less than 0.5, adopting conventional water injection for expansion; if the integral permeability variation coefficient is more than 0.5 and less than 0.7, injecting saturated CO at normal temperature2Expanding the volume of saline water; if the integral permeability variation coefficient is more than 0.7, injecting CO at high temperature2Expanding the volume of saturated saline;
the conventional water injection and expansion in the step 3) refers to a method for injecting underground produced fluid into the stratum according to the step 7) and the step 8); injecting saturated CO at normal temperature2The brine expansion refers to the configuration of saturated CO according to the temperature and pressure of the stratum where the reservoir is located2Brine and injected into the formation according to step 7), step 8); CO injection at high temperature2The saturated saline water expansion refers to the expansion according to the formation pressure and the steps5) The obtained optimal temperature T is configured with saturated CO2Brine and injected into the formation according to step 7), step 8);
step 4): at bottom hole pressure Pmax bottom holePreparing saturated CO at different temperatures2Brine solution, testing pH, analyzing temperature versus CO2Law of influence of the pH value of saline solutions, Pmax bottom holeThe maximum bottom hole pressure of the liquid squeezing construction is a value which is 0.5MPa lower than the fracture pressure of the stratum;
step 5): drawing a temperature-pH curve, and determining that the temperature T is the optimal temperature when the temperature is increased from T to T +10 ℃ and the pH reduction value is less than 0.2;
step 6): taking a core column from an on-site underground coring bit, and taking an underground core into a standard core column indoors; testing of initial permeability K of different core legs0Then, standard core string is placed in saturated CO2In saline water at pressure Pmax bottom holeSoaking for 2.5 days, simulating the actual pore pressure of the underground reservoir to fully saturate the core with fluid, testing the permeability of the soaked core column, and calculating the permeability improvement coefficient I of each core; plotting the initial permeability K0-permeability improvement factor I relation;
step 7): calculating the formation fracture pressure at the vertical depth of the P well as PbThe hydrostatic column pressure in the vertical depth of the P well is Pw(ii) a The maximum bottom hole pressure of the liquid squeezing construction is calculated to be 0.5MPa less than the formation fracture pressure, namely Pmax bottom hole＝Pb-0.5; calculating the difference between the maximum bottom hole pressure and the hydrostatic column pressure, namely Pmax well head＝Pmax bottom hole-Pw；
Step 8): cleaning the SAGD well, simultaneously controlling the well head pressure of the P well and the I well, and keeping the well head pressure of the two wells consistent; the pressure is increased step by step in four stages until the maximum wellhead pressure is reached, and the pressure increasing amplitude of each stage is Pmax well headThe pressure increase completion time of each stage is 30-60 min; after the pressure is increased in the first three stages, the constant pressure is maintained for 12h, and after the pressure is increased in the fourth stage, the constant pressure is maintained for 24h, namely the transformation is finished;
step 9): push buttonInitial permeability K0-a permeability improvement factor I relationship, multiplying the permeability of all meshes in the initial permeability profile within the investigation region by the corresponding factor I; recalculating the overall permeability coefficient of variation in the research area, and successfully modifying when the overall coefficient of variation of the stratum is reduced to be less than 0.5;
step 10): if the integral permeability variation coefficient of the stratum is still larger than 0.5, adopting saturated CO injection2Well of brine, high temperature CO injection again2Brine for 24 hours; for the adopted high-temperature injection of saturated CO2Brine wells, the injection time was extended by 2 days.
In each stratified layer in the step 1), grids are divided every 1m from the root to the toe of the horizontal well, and when the width of the last grid is greater than or equal to 0.5m, the grid is separated into one grid; when the width of the last grid is less than 0.5m, the last grid and the last grid are combined into a grid; the area range of the grid is divided into 5m from the bottom of the reservoir to the upper part of the I well in the vertical direction and from the root of the horizontal well to the toe of the horizontal well in the horizontal direction.
The weighting coefficient influencing the permeability coefficient of variation of each layer in the step 2) depends on the distance between each layer and the well bore.
The solute composition and content of the brine in the step 3) are matched with those of the produced water of the stratum.
The solute in the saline solution in the step 3) mainly comprises Na+、K+、Ca+、Mg+Isocation and Cl-、SO4 2-、HCO3 -、CO3 2-And (4) plasma.
In the step 3), the saline solution can be formed by directly using the formation water after crude oil treatment, or can be formed by using the saline solution prepared by a laboratory experiment.
The step 3) is to inject saturated CO at normal temperature2By expansion of brine or by injection of CO at high temperature2During the expansion of saturated brine, to prevent CO2The solution corrodes the bottom layer of the mudstone, two types of sieve pipes are designed and produced, wherein the common sieve pipe is used for the well I, and a special sieve pipe is used for the well PThe sieve tube, I well sieve tube all slot, P well sieve tube only upper portion slot, the lower part does not slot.
The step 4) is to prepare saturated CO2The temperature range of the saline solution is that the temperature of the stratum where the reservoir is located is 80 ℃.
The step 6) of indoor coring to obtain the standard core means that the core taken by the coring bit is processed into a standard cylinder with the diameter of 25mm and the length of 50mm by a manual or mechanical method, and the standard cylinder needs to be sealed by a sealing bag and stored in a refrigerator at the temperature of 20 ℃ below zero.
The permeability testing method in the step 6) can adopt a steady state method or a transient state method, and can adopt gas measurement or liquid measurement.
The invention has the beneficial effects that:
by cyclically injecting CO into the injection-production double horizontal well2The saturated saline water is subjected to micro-fracturing, so that the development of the near-well reservoir micro-fractures can be effectively promoted, the porosity, permeability and water saturation of the reservoir are improved, and the hydraulic and thermal communication between wells is quickly established. In addition, the argillaceous and calcite minerals are rich in CO2The corrosion in the saline acid solution is beneficial to the initiation of new pores and microcracks, the porosity and pore connectivity are improved, and the permeability is increased. CO 22During brine-rock interaction, the degree of mudstone erosion increases with increasing temperature. Oil sand is mostly argillaceous cementation, the argillaceous content is high, and CO2Water-rock reactions offer natural advantages. From the viewpoint of aging, the room test is rich in CO2The saline water is injected for about 50 hours, so that the permeability of the argillaceous cemented sandstone reservoir can be increased by about 10-100 times. This means that if the oil sand formation is cyclically injected with saturated CO2The salt water is 3-4 days or so, and the permeability of a near-well reservoir can be effectively improved. The traditional strong acid acidification method has strong destructiveness on the stratum and the cover layer, poor controllability and saturated CO2Saline solutions can make up for the above deficiencies.
The construction sequence related by the invention is before various thermal oil extraction methods, and can be smoothly completed only by utilizing the existing well type, ground and underground pipe columns. The method can obviously improve the permeability of the oil sand reservoir, thereby improving the heat convection capacity of the reservoir, has low cost and quick response, and is suitable for various thermal oil extraction technologies.
Drawings
FIG. 1 is a drawing of a process for the preparation of a polymer by the extrusion of saturated CO2Technical flow diagram of a process for brine to improve permeability of oil sands reservoirs.
FIG. 2 is a schematic of a slotted zone of a specially designed screen for a P-well in a SAGD well.
FIG. 3 is a schematic diagram of the slot positions and sizes of a parallel staggered slotted screen for a SAGD well.
FIG. 4 is a schematic view perpendicular to the direction of borehole extension of the downhole location and angle of the I-well and P-well screens in a SAGD well.
FIG. 5 is a schematic representation of the downhole location and angle of the I-well and P-well screens in a SAGD well along the borehole extension.
FIG. 6 is a schematic diagram of a specially designed I-well and P-well screens that control the direction of the produced water flow.
Fig. 7 is a schematic diagram of the hydraulic-acid etching composite expansion zone of the near well region and the hydraulic expansion zone of the far well region perpendicular to the extension direction of the well hole.
Fig. 8 is a schematic diagram of the hydraulic-acid etching composite expansion zone of the near well region and the hydraulic expansion zone of the far well region parallel to the well bore extending direction.
Detailed Description
The invention is further described with reference to the following figures and examples.
As shown in FIG. 1, a method of saturating CO by extrusion2The method for improving the permeability of the oil sand reservoir by using brine is characterized by comprising the following steps:
step 1): acquiring a permeability section of a reservoir layer near the SAGD well through well logging interpretation, wherein the permeability section is a section of a well bore axis passing through an I well and a P well (the I well and the P well are respectively a steam injection well and a production well in the SAGD well); researching the range from 5m above a well I to the bottom of a reservoir, layering every 1m in the vertical direction, wherein the number of layering is N, and dividing grids every 1m in each layer in the horizontal direction;
step 2): reading the permeability value of the grid in each layer, and calculating the permeability variation coefficient V of each layerm(ii) a According to each layered distance wellThe distance of the cylinder is given to different layers with different weight coefficients, the sum of the weight coefficients of the permeability variation coefficients of all layers is 1, and the integral permeability variation coefficient V in the research range is calculatedt；
Permeability coefficient of variation V of mth layermThe formula for calculating (a) is as follows,
in the formula, m is 1-H; h is the total number of stratification in the study area; n is the number of grids of each layer; kiPermeability values corresponding to each hierarchical mesh;
the average value of the permeability corresponding to each layered grid;
the overall permeability coefficient of variation Vt is calculated as:
Vt＝λ1V1+λ2V2+…λmVm+…+λHVH
in the formula, λmA weight coefficient which is a permeability coefficient of variation of the mth layer;
step 3): if the integral permeability variation coefficient is less than 0.5, adopting conventional water injection for expansion; if the integral permeability variation coefficient is more than 0.5 and less than 0.7, injecting saturated CO at normal temperature2Expanding the volume of saline water; if the integral permeability variation coefficient is more than 0.7, injecting CO at high temperature2Expanding the volume of saturated saline;
the conventional water injection and expansion in the step 3) refers to a method for injecting underground produced fluid into the stratum according to the step 7) and the step 8); injecting saturated CO at normal temperature2The brine expansion refers to the configuration of saturated CO according to the temperature and pressure of the stratum where the reservoir is located2Brine and injected into the formation according to step 7), step 8); CO injection at high temperature2The saturated saline water expansion means that saturated CO is configured according to the formation pressure and the optimal temperature T obtained in the step 5)2Brine and according to step 7),Step 8) a method of injecting into a formation;
step 4): at bottom hole pressure Pmax bottom holePreparing saturated CO at different temperatures2Brine solution, testing pH, analyzing temperature versus CO2Law of influence of the pH value of saline solutions, Pmax bottom holeThe maximum bottom hole pressure of the liquid squeezing construction is a value which is 0.5MPa lower than the fracture pressure of the stratum;
step 5): drawing a temperature-pH curve, and determining that the temperature T is the optimal temperature when the temperature is increased from T to T +10 ℃ and the pH reduction value is less than 0.2;
step 6): taking a core column from an on-site underground coring bit, and taking an underground core into a standard core column indoors; testing of initial permeability K of different core legs0Then, standard core string is placed in saturated CO2In saline water at pressure Pmax bottom holeSoaking for 2.5 days, simulating the actual pore pressure of the underground reservoir to fully saturate the core with fluid, testing the permeability of the soaked core column, and calculating the permeability improvement coefficient I of each core; plotting the initial permeability K0-permeability improvement factor I relation;
step 7): calculating the formation fracture pressure at the vertical depth of the P well as PbThe hydrostatic column pressure in the vertical depth of the P well is Pw(ii) a The maximum bottom hole pressure of the liquid squeezing construction is calculated to be 0.5MPa less than the formation fracture pressure, namely Pmax bottom hole＝Pb-0.5; calculating the difference between the maximum bottom hole pressure and the hydrostatic column pressure, namely Pmax well head＝Pmax bottom hole-Pw；
Step 8): cleaning the SAGD well, simultaneously controlling the well head pressure of the P well and the I well, and keeping the well head pressure of the two wells consistent; the pressure is increased step by step in four stages until the maximum wellhead pressure is reached, and the pressure increasing amplitude of each stage is Pmax well headThe pressure increase completion time of each stage is 30-60 min; after the pressure is increased in the first three stages, the constant pressure is maintained for 12h, and after the pressure is increased in the fourth stage, the constant pressure is maintained for 24h, namely the transformation is finished;
step 9): according to initial permeability K0The permeability improvement factor I, the area to be investigatedMultiplying the permeability of all grids in the initial permeability profile by a corresponding coefficient I; recalculating the overall permeability coefficient of variation in the research area, and successfully modifying when the overall coefficient of variation of the stratum is reduced to be less than 0.5;
step 10): if the integral permeability variation coefficient of the stratum is still larger than 0.5, adopting saturated CO injection2Well of brine, high temperature CO injection again2Brine for 24 hours; for the adopted high-temperature injection of saturated CO2Brine wells, the injection time was extended by 2 days.
In each stratified layer in the step 1), grids are divided every 1m from the root to the toe of the horizontal well, and when the width of the last grid is greater than or equal to 0.5m, the grid is separated into one grid; when the width of the last grid is less than 0.5m, the last grid and the last grid are combined into a grid; the area range of the grid is divided into 5m from the bottom of the reservoir to the upper part of the I well in the vertical direction and from the root of the horizontal well to the toe of the horizontal well in the horizontal direction.
The weighting coefficient influencing the permeability coefficient of variation of each layer in the step 2) depends on the distance between each layer and the well bore.
The solute composition and content of the brine in the step 3) are matched with those of the produced water of the stratum.
The solute in the saline solution in the step 3) mainly comprises Na+、K+、Ca+、Mg+Isocation and Cl-、SO4 2-、HCO3 -、CO3 2-And (4) plasma.
In the step 3), the saline solution can be formed by directly using the formation water after crude oil treatment, or can be formed by using the saline solution prepared by a laboratory experiment.
The step 3) is to inject saturated CO at normal temperature2By expansion of brine or by injection of CO at high temperature2During the expansion of saturated brine, to prevent CO2The solution corrodes the mudstone bottom layer, two types of sieve pipes are designed and produced, wherein a common sieve pipe is used for the I well, a special sieve pipe is adopted for the P well, the sieve pipe of the I well is completely slotted, and as shown in figure 2, the sieve pipe of the P well is only slotted at the upper part and is only slotted at the lower partNo slit is formed.
The step 4) is to prepare saturated CO2The temperature range of the saline solution is that the temperature of the stratum where the reservoir is located is 80 ℃.
The step 6) of indoor coring to obtain the standard core means that the core taken by the coring bit is processed into a standard cylinder with the diameter of 25mm and the length of 50mm by a manual or mechanical method, and the standard cylinder needs to be sealed by a sealing bag and stored in a refrigerator at the temperature of 20 ℃ below zero.
The permeability testing method in the step 6) can adopt a steady state method or a transient state method, and can adopt gas measurement or liquid measurement.
The embodiment is a certain SAGD well in a Xinjiang Fengcheng oil field, the vertical depth of an I well is 372m, the vertical depth of a P well is 377m, the distance between the P well and a mudstone bottom layer is 2m, the length of a horizontal section is 500m, and the fracture pressure gradient of a reservoir stratum is 0.016 MPa/m. According to the parameters, the research area can be divided into 12 layers, and each layer is divided into 500 grids. The permeability coefficient of variation of the 12 layers from top to bottom was calculated to be 0.33, 0.42, 0.65, 0.76, 0.36, 0.54, 0.78, 0.89, 0.32, 0.56, 0.87, 0.33, respectively. The permeability coefficient of variation of the 12 layers from top to bottom are respectively 1/45, 2/45, 1/15, 4/45, 1/9, 1/9, 4/45, 1/15, 4/45, 1/9, 1/9 and 4/45. The overall permeability coefficient of variation was calculated to be 0.5822.
Because the integral permeability variation coefficient is more than 0.5 and less than 0.7, the injection of saturated CO at normal temperature is adopted2And (5) expanding the volume by using saline water.
Drilling underground rock cores of a reservoir section on site in an oil field, obtaining 5 standard rock core columns indoors, testing the initial permeability of the standard rock cores, and respectively recording the initial permeability as k1、k2…k5(ii) a Respectively placing 5 standard core columns in CO2Soaking in saturated saline for 2.5 days; setting fluid pressure P by a pressure intensifiermax bottom holeThe permeability of the soaked core column was tested at 5.5MPa and was reported as k'1、k'2…k'5(ii) a Calculating the saturated CO adopted by each core column2The permeability improvement factor I after brine soaking, i.e. the ratio of the core soaked to the initial permeability, is recorded as I1、I2…I20。
Initial permeability K of 5 standard cores00.01mD, 0.2mD, 0.8mD, 1.2mD and 2.9mD in sequence, and the permeability improvement coefficients I are 19.5, 8.6, 5.6, 3.7 and 1.3 in sequence. Fitting the relationship between the initial permeability and the permeability improvement coefficient, I ═ 3.193lnK can be obtained0+4.426。
In this example, saturated CO2The base fluid of the brine adopts a brine solution matched with the produced liquid of the stratum, wherein the solute composition is as follows: HCO3 -Concentration 1496.15mg/L, Cl-The concentration is 1950.53mg/L, Ca+The concentration is 7.33mg/L, Na+And K+The concentration is 2003.16mg/L, and the total mineralization is 4970.24 mg/L.
In this example, well I used a conventional sand screen; as shown in FIG. 2, the P-well is made of a special screen, 1/2 area is slotted and 1/2 area is non-slotted. As shown in FIG. 3, the slit part is a staggered slit with a width of 0.2-0.5 mm. The production screen is run in with the slotted zone facing up as shown in figures 4-5. As shown in FIG. 6, this particular screen allows only CO2The saturated saline water extrudes liquid upwards, can avoid the mudstone bottom layer to be corroded.
In this example, the maximum wellhead pressure P for squeeze construction is calculatedmax outlet1.8 MPa. The I well and the P well are squeezed in four stages: loading the wellhead pressure of the three wells from 0 to 0.45MPa in 60min at the first stage, and maintaining the pressure of 0.45MPa for 12 hours; loading the wellhead pressure of the three wells from 0.45MPa to 0.9MPa in the second stage, and maintaining the pressure of 0.9MPa for 12 hours; loading the wellhead pressure of the three wells in the third stage from 0.9MPa to 1.35MPa, and maintaining the pressure of 1.35MPa for 12 hours; the wellhead pressure of the three wells in the fourth stage is loaded from 1.35MPa to 1.8MPa, and the pressure of 1.8MPa is maintained for 24 hours.
As shown in FIGS. 7-8, in this embodiment, saturated CO is squeezed into the reservoir2After the saline solution, a hydraulic and acid-etching composite expansion area is generated in a near well area, and a hydraulic expansion area is generated in a far well area, so that the porosity and the permeability of a reservoir stratum are effectively increased.
The permeability coefficient of variation of each layer was recalculated to have permeability coefficients of 0.23, 0.32, 0.45, 0.56, 0.24, 0.45, 0.74, 0.61, 0.22, 0.36, 0.65, and 0.25 for 12 layers from top to bottom, respectively. And according to the weight coefficient of the permeability coefficient of each layer, calculating to obtain an integral permeability coefficient of 0.4362, which indicates that the effect is better after modification and the modification is finished.
Example two:
by extrusion of saturated CO according to the invention2The modification steps, the working principle, the beneficial effects and the like of the other embodiment of the method for improving the permeability of the oil sand reservoir by using the brine are the same as those of the first embodiment, except that the permeability variation coefficients of 12 layers are as follows: the permeability coefficient of variation of the 12 layers from top to bottom are 0.35, 0.22, 0.35, 0.46, 0.34, 0.24, 0.58, 0.49, 0.38, 0.56, 0.77 and 0.43 respectively. The permeability coefficient of variation of the 12 layers from top to bottom are respectively 1/45, 2/45, 1/15, 4/45, 1/9, 1/9, 4/45, 1/15, 4/45, 1/9, 1/9 and 4/45. The overall permeability coefficient of variation was calculated to be 0.4502.
Because the integral permeability variation coefficient is less than 0.5, the conventional water injection expansion is adopted. In this example, conventional sand screens were used for wells I and P.
Example three:
by extrusion of saturated CO according to the invention2The modification steps, the working principle, the beneficial effects and the like of the other embodiment of the method for improving the permeability of the oil sand reservoir by using the brine are the same as those of the first embodiment, except that the permeability variation coefficients of 12 layers are as follows: the permeability coefficient of variation of the 12 layers from top to bottom are 0.75, 0.82, 0.65, 0.86, 0.64, 0.84, 0.58, 0.79, 0.68, 0.86, 0.77 and 0.69 respectively. The permeability coefficient of variation of the 12 layers from top to bottom are respectively 1/45, 2/45, 1/15, 4/45, 1/9, 1/9, 4/45, 1/15, 4/45, 1/9, 1/9 and 4/45. The overall permeability coefficient of variation was calculated to be 0.7444.
Because the coefficient of variation of the overall permeability is greater than 0.7, CO injection at high temperature is used2And (5) expanding the volume by saturated saline water.
The reduction in pH when the temperature increased from 55 to 65 ℃ was equal to 0.21; when the temperature increased from 65 to 75 ℃, the pH decreased by 0.18, thus determining that the temperature of 65 ℃ was the optimum temperature.
The permeability coefficient of variation of each layer was recalculated to have permeability coefficients of 0.33, 0.42, 0.54, 0.56, 0.44, 0.45, 0.34, 0.61, 0.22, 0.36, 0.65, and 0.55 for 12 layers from top to bottom, respectively. And according to the weight coefficient of the permeability coefficient of each layer, calculating to obtain an integral permeability coefficient of 0.4622, which indicates that the effect is better after modification and the modification is finished.
Example four:
by extrusion of saturated CO according to the invention2The other embodiment of the method for improving the permeability of the oil sand reservoir by using the brine has the same modification steps, working principles, beneficial effects and the like as those of the first embodiment, except for the matching relationship of all parameters in the modification steps:
the embodiment is a certain SAGD well in a Xinjiang Fengcheng oil field, the vertical depth of an I well is 372m, the vertical depth of a P well is 377m, and the fracture pressure gradient of a reservoir stratum is 0.017 MPa/m. Calculating to obtain the maximum wellhead pressure P of the squeeze constructionmax outlet2.2 MPa. The I well and the P well are squeezed in four stages: loading the wellhead pressure of the two wells from 0 to 0.55MPa within 50min at the first stage, and maintaining the pressure of 0.55MPa for 12 hours; loading the wellhead pressure of the two wells from 0.55MPa to 1.1MPa in the second stage, and maintaining the pressure of 1.1MPa for 12 hours; loading the wellhead pressure of the two wells in the third stage from 1.1MPa to 1.65MPa, and maintaining the pressure of 1.65MPa for 12 hours; and loading the wellhead pressure of the two wells in the fourth stage from 1.65MPa to 2.2MPa, and maintaining the pressure of 2.2MPa for 24 hours, namely finishing the transformation.
Claims (10)
1. By extrusion of saturated CO2The method for improving the permeability of the oil sand reservoir by using brine is characterized by comprising the following steps:
step 1): acquiring a permeability section of a reservoir layer near the SAGD well through well logging interpretation, wherein the permeability section is a section of a well bore axis passing through an I well and a P well (the I well and the P well are respectively a steam injection well and a production well in the SAGD well); researching the range from 5m above a well I to the bottom of a reservoir, layering every 1m in the vertical direction, wherein the number of layering is N, and dividing grids every 1m in each layer in the horizontal direction;
step 2): reading the permeability value of the grid in each layer, and calculating the permeability variation coefficient V of each layerm(ii) a According to the distance between each layer and the shaft, different weight coefficients are given to different layers, the sum of the weight coefficients of permeability variation coefficients of each layer is 1, and the whole permeability variation coefficient V in the research range is calculatedt；
Permeability coefficient of variation V of mth layermThe formula for calculating (a) is as follows,
in the formula, m is 1-H; h is the total number of stratification in the study area; n is the number of grids of each layer; kiPermeability values corresponding to each hierarchical mesh;
the average value of the permeability corresponding to each layered grid;
the overall permeability coefficient of variation Vt is calculated as:
Vt＝λ1V1+λ2V2+…λmVm+…+λHVH
in the formula, λmA weight coefficient which is a permeability coefficient of variation of the mth layer;
step 3): if the integral permeability variation coefficient is less than 0.5, adopting conventional water injection for expansion; if the integral permeability variation coefficient is more than 0.5 and less than 0.7, injecting saturated CO at normal temperature2Expanding the volume of saline water; if the integral permeability variation coefficient is more than 0.7, injecting CO at high temperature2Expanding the volume of saturated saline;
the conventional water injection and expansion in the step 3) refers to a method for injecting underground produced fluid into the stratum according to the step 7) and the step 8); injecting saturated CO at normal temperature2The brine expansion refers to the configuration of saturated CO according to the temperature and pressure of the stratum where the reservoir is located2Brine and injected into the formation according to step 7), step 8); high temperature bottom pouringInto CO2The saturated saline water expansion means that saturated CO is configured according to the formation pressure and the optimal temperature T obtained in the step 5)2Brine and injected into the formation according to step 7), step 8);
step 4): at bottom hole pressure Pmax bottom holePreparing saturated CO at different temperatures2Brine solution, testing pH, analyzing temperature versus CO2Law of influence of the pH value of saline solutions, Pmax bottom holeThe maximum bottom hole pressure of the liquid squeezing construction is a value which is 0.5MPa lower than the fracture pressure of the stratum;
step 5): drawing a temperature-pH curve, and determining that the temperature T is the optimal temperature when the temperature is increased from T to T +10 ℃ and the pH reduction value is less than 0.2;
step 6): taking a core column from an on-site underground coring bit, and taking an underground core into a standard core column indoors; testing of initial permeability K of different core legs0Then, standard core string is placed in saturated CO2In saline water at pressure Pmax bottom holeSoaking for 2.5 days, and simulating the actual pore pressure of the underground reservoir to saturate CO2Fully saturating the core with saline water, testing the permeability of the soaked core column, and calculating the permeability improvement coefficient I of each core; plotting the initial permeability K0-permeability improvement factor I relation;
step 7): calculating the formation fracture pressure at the vertical depth of the P well as PbThe hydrostatic column pressure in the vertical depth of the P well is Pw(ii) a The maximum bottom hole pressure of the liquid squeezing construction is calculated to be 0.5MPa less than the formation fracture pressure, namely Pmax bottom hole＝Pb-0.5; calculating the difference between the maximum bottom hole pressure and the hydrostatic column pressure, namely Pmax well head＝Pmax bottom hole-Pw；
Step 8): cleaning the SAGD well, simultaneously controlling the well head pressure of the P well and the I well, and keeping the well head pressure of the two wells consistent; the pressure is increased step by step in four stages until the maximum wellhead pressure is reached, and the pressure increasing amplitude of each stage is Pmax well headThe pressure increase completion time of each stage is 30-60 min; the constant pressure is maintained for 12h after the pressure is increased in the first three stages, and the constant pressure is maintained after the pressure is increased in the fourth stageThe pressure is 24h, namely the transformation is finished;
step 9): according to initial permeability K0-a permeability improvement factor I relationship, multiplying the permeability of all meshes in the initial permeability profile within the investigation region by the corresponding factor I; recalculating the overall permeability coefficient of variation in the research area, and successfully modifying when the overall coefficient of variation of the stratum is reduced to be less than 0.5;
step 10): if the integral permeability variation coefficient of the stratum is still larger than 0.5, adopting saturated CO injection2Well of brine, high temperature CO injection again2Brine for 24 hours; for the adopted high-temperature injection of saturated CO2Brine wells, the injection time was extended by 2 days.
2. A process according to claim 1, wherein the CO is saturated by extrusion2The method for improving the permeability of the oil sand reservoir by using the saline water is characterized in that in step 1), grids are divided every 1m from the root to the toe of the horizontal well in each sub-layer, and when the width of the last grid is greater than or equal to 0.5m, the last grid is separated into one grid; when the width of the last grid is less than 0.5m, the last grid and the last grid are combined into a grid; the area range of the grid is divided into 5m from the bottom of the reservoir to the upper part of the I well in the vertical direction and from the root of the horizontal well to the toe of the horizontal well in the horizontal direction.
3. A process according to claim 1, wherein the CO is saturated by extrusion2The method for improving the permeability of the oil sand reservoir by the saline water is characterized in that the weighting coefficient influencing the permeability variation coefficient of each layer in the step 2) is determined by the distance between each layer and a wellbore.
4. A process according to claim 1, wherein the CO is saturated by extrusion2The method for improving the permeability of the oil sand reservoir by the brine is characterized in that the solute component and the content of the brine in the step 3) are matched with the produced water of the stratum.
5. A process according to claim 1, wherein the CO is saturated by extrusion2The method for improving the permeability of the oil sand reservoir by using brine is characterized in that the solute in the brine solution in the step 3) mainly comprises Na+、K+、Ca+、Mg+Isocation and Cl-、SO4 2-、HCO3 -、CO3 2-And (4) plasma.
6. A process according to claim 1, wherein the CO is saturated by extrusion2The method for improving the permeability of the oil sand reservoir by using the brine is characterized in that the brine solution in the step 3) can be formed by directly using the formation water after crude oil treatment or can be formed by using brine prepared in a laboratory experiment.
7. A process according to claim 1, wherein the CO is saturated by extrusion2The method for improving the permeability of the oil sand reservoir by using the brine is characterized in that saturated CO is injected at normal temperature in the step 3)2By expansion of brine or by injection of CO at high temperature2During the expansion of saturated brine, to prevent CO2The solution corrodes the bottom layer of the mudstone, two types of sieve pipes are designed and produced, wherein a common sieve pipe is used for a well I, a special sieve pipe is used for a well P, the sieve pipe of the well I is completely slotted, and the sieve pipe of the well P is only slotted at the upper part and is not slotted at the lower part.
8. A process according to claim 1, wherein the CO is saturated by extrusion2The method for improving the permeability of the oil sand reservoir by using the brine is characterized in that saturated CO is prepared in the step 4)2The temperature range of the saline solution is that the temperature of the stratum where the reservoir is located is 80 ℃.
9. A process according to claim 1, wherein the CO is saturated by extrusion2The method for improving the permeability of the oil sand reservoir by saline water is characterized in that the step 6) of indoor coring into the standard core is that the core taken by a coring bit is processed into a standard cylinder with the diameter of 25mm and the length of 50mm by a manual or mechanical method, needs to be sealed by a sealing bag and is stored in a refrigerator at the temperature of-20 ℃.
10. A process according to claim 1, wherein the CO is saturated by extrusion2The method for improving the permeability of the oil sand reservoir by using the brine is characterized in that the permeability testing method in the step 6) can adopt a steady state method or a transient state method, and can adopt gas measurement or liquid measurement.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CN202110724704.3A CN113266333B (en) | 2021-06-29 | 2021-06-29 | By extrusion of saturated CO 2 Method for improving permeability of oil sand reservoir by using brine |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CN202110724704.3A CN113266333B (en) | 2021-06-29 | 2021-06-29 | By extrusion of saturated CO 2 Method for improving permeability of oil sand reservoir by using brine |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| CN113266333A true CN113266333A (en) | 2021-08-17 |
| CN113266333B CN113266333B (en) | 2023-04-18 |
Family
ID=77236145
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CN202110724704.3A Active CN113266333B (en) | 2021-06-29 | 2021-06-29 | By extrusion of saturated CO 2 Method for improving permeability of oil sand reservoir by using brine |
Country Status (1)
| Country | Link |
|---|---|
| CN (1) | CN113266333B (en) |
Cited By (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN114135265A (en) * | 2021-10-19 | 2022-03-04 | 中海油能源发展股份有限公司 | Low-cost and high-efficiency transformation process method for low-permeability reservoir of offshore oilfield |
| CN115032337A (en) * | 2022-05-23 | 2022-09-09 | 中国石油大学(华东) | Maximized CO 2 Brine pre-pumping amount and reinjection amount calculation method for sealing efficiency and site test verification method |
Citations (20)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| NO20022204D0 (en) * | 2001-05-09 | 2002-05-08 | Inst Francais Du Petrole | Method for determining by numerical simulation of recovery conditions, of reservoir fluids, of a single complex well damaged during drilling operations |
| US20030109385A1 (en) * | 1999-12-29 | 2003-06-12 | Gunn Alistair Manson | Process for altering the ralative permeability if a hydrocarbon-bearing formation |
| RU2482271C1 (en) * | 2011-11-18 | 2013-05-20 | Общество с ограниченной ответственностью "Газпромнефть Научно-Технический Центр" (ООО "Газпромнефть НТЦ") | Method for determining relative phase permeabilities of formation |
| US20130144533A1 (en) * | 2011-12-05 | 2013-06-06 | Korea Institute Of Geoscience And Mineral Resources | Apparatus and method of measuring porosity and permeability of dioxide carbon underground storage medium |
| CN103233709A (en) * | 2013-05-13 | 2013-08-07 | 中国石油大学(华东) | Super heavy oil deposit exploiting carbon capture, utilization and storage (CCUS) system and method based on CO2 assisted steam assisted gravity drainage (SAGD) |
| CN104500050A (en) * | 2014-10-31 | 2015-04-08 | 中国石油大学(华东) | Fractured reservoir permeability tensor and anisotropy quantitative prediction method |
| US20150168596A1 (en) * | 2013-12-18 | 2015-06-18 | King Fahd University Of Petroleum And Minerals | Inflow performance relationship for horizontal wells producing oil from multi-layered heterogeneous solution gas-drive reservoirs |
| CN104747185A (en) * | 2015-03-19 | 2015-07-01 | 成都北方石油勘探开发技术有限公司 | Heterogeneous reservoir stratum synthetic classifying evaluation method |
| US20150204171A1 (en) * | 2013-11-06 | 2015-07-23 | Geosierra, Llc | Carbon dioxide energy storage and enhanced oil recovery |
| CN105888656A (en) * | 2016-03-15 | 2016-08-24 | 中国石油天然气股份有限公司 | Method for quantitatively evaluating hydraulic permeability under pressure of natural microcrack development tight reservoir |
| CN106812522A (en) * | 2015-12-01 | 2017-06-09 | 中国石油化工股份有限公司 | Reservoir heterogeneity research method based on three-dimensional geological model |
| CN107313756A (en) * | 2017-07-04 | 2017-11-03 | 中国石油大学(北京) | The jet connection of SAGD mudstone foundations is made to squeeze sour remodeling method |
| CN108194069A (en) * | 2018-01-17 | 2018-06-22 | 中国石油大学(北京) | The method of straight well auxiliary SAGD well transformations thick oil reservoir containing muddy intercalation |
| CN110242266A (en) * | 2019-07-08 | 2019-09-17 | 新疆中凌工程技术有限公司 | A kind of horizontal well group of SAGD is temporarily stifled to be segmented dilatation reservoir reconstruction method |
| CN111219176A (en) * | 2020-01-09 | 2020-06-02 | 成都合信恒泰工程技术有限公司 | Water injection well expansion reservoir transformation method |
| CN111520117A (en) * | 2020-06-24 | 2020-08-11 | 陕西延长石油（集团）有限责任公司 | Bottom water injection method and verification suitable for shallow layer horizontal seam oil reservoir |
| CN111734374A (en) * | 2020-08-01 | 2020-10-02 | 西南石油大学 | Associative polymer combination oil displacement method for greatly improving heterogeneous oil reservoir recovery ratio |
| CN112560310A (en) * | 2020-12-11 | 2021-03-26 | 中国海洋石油集团有限公司 | Method for quantitatively characterizing permeability dynamic change of multilayer oil reservoir |
| CN112727421A (en) * | 2019-10-14 | 2021-04-30 | 中国石油天然气股份有限公司 | Method for increasing communication length of SAGD horizontal sections of double horizontal wells |
| CN113006755A (en) * | 2019-12-19 | 2021-06-22 | 中国石油天然气股份有限公司 | Method for fracturing transformation of interlayer in SAGD (steam assisted gravity drainage) mining mode |
-
2021
- 2021-06-29 CN CN202110724704.3A patent/CN113266333B/en active Active
Patent Citations (20)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US20030109385A1 (en) * | 1999-12-29 | 2003-06-12 | Gunn Alistair Manson | Process for altering the ralative permeability if a hydrocarbon-bearing formation |
| NO20022204D0 (en) * | 2001-05-09 | 2002-05-08 | Inst Francais Du Petrole | Method for determining by numerical simulation of recovery conditions, of reservoir fluids, of a single complex well damaged during drilling operations |
| RU2482271C1 (en) * | 2011-11-18 | 2013-05-20 | Общество с ограниченной ответственностью "Газпромнефть Научно-Технический Центр" (ООО "Газпромнефть НТЦ") | Method for determining relative phase permeabilities of formation |
| US20130144533A1 (en) * | 2011-12-05 | 2013-06-06 | Korea Institute Of Geoscience And Mineral Resources | Apparatus and method of measuring porosity and permeability of dioxide carbon underground storage medium |
| CN103233709A (en) * | 2013-05-13 | 2013-08-07 | 中国石油大学(华东) | Super heavy oil deposit exploiting carbon capture, utilization and storage (CCUS) system and method based on CO2 assisted steam assisted gravity drainage (SAGD) |
| US20150204171A1 (en) * | 2013-11-06 | 2015-07-23 | Geosierra, Llc | Carbon dioxide energy storage and enhanced oil recovery |
| US20150168596A1 (en) * | 2013-12-18 | 2015-06-18 | King Fahd University Of Petroleum And Minerals | Inflow performance relationship for horizontal wells producing oil from multi-layered heterogeneous solution gas-drive reservoirs |
| CN104500050A (en) * | 2014-10-31 | 2015-04-08 | 中国石油大学(华东) | Fractured reservoir permeability tensor and anisotropy quantitative prediction method |
| CN104747185A (en) * | 2015-03-19 | 2015-07-01 | 成都北方石油勘探开发技术有限公司 | Heterogeneous reservoir stratum synthetic classifying evaluation method |
| CN106812522A (en) * | 2015-12-01 | 2017-06-09 | 中国石油化工股份有限公司 | Reservoir heterogeneity research method based on three-dimensional geological model |
| CN105888656A (en) * | 2016-03-15 | 2016-08-24 | 中国石油天然气股份有限公司 | Method for quantitatively evaluating hydraulic permeability under pressure of natural microcrack development tight reservoir |
| CN107313756A (en) * | 2017-07-04 | 2017-11-03 | 中国石油大学(北京) | The jet connection of SAGD mudstone foundations is made to squeeze sour remodeling method |
| CN108194069A (en) * | 2018-01-17 | 2018-06-22 | 中国石油大学(北京) | The method of straight well auxiliary SAGD well transformations thick oil reservoir containing muddy intercalation |
| CN110242266A (en) * | 2019-07-08 | 2019-09-17 | 新疆中凌工程技术有限公司 | A kind of horizontal well group of SAGD is temporarily stifled to be segmented dilatation reservoir reconstruction method |
| CN112727421A (en) * | 2019-10-14 | 2021-04-30 | 中国石油天然气股份有限公司 | Method for increasing communication length of SAGD horizontal sections of double horizontal wells |
| CN113006755A (en) * | 2019-12-19 | 2021-06-22 | 中国石油天然气股份有限公司 | Method for fracturing transformation of interlayer in SAGD (steam assisted gravity drainage) mining mode |
| CN111219176A (en) * | 2020-01-09 | 2020-06-02 | 成都合信恒泰工程技术有限公司 | Water injection well expansion reservoir transformation method |
| CN111520117A (en) * | 2020-06-24 | 2020-08-11 | 陕西延长石油（集团）有限责任公司 | Bottom water injection method and verification suitable for shallow layer horizontal seam oil reservoir |
| CN111734374A (en) * | 2020-08-01 | 2020-10-02 | 西南石油大学 | Associative polymer combination oil displacement method for greatly improving heterogeneous oil reservoir recovery ratio |
| CN112560310A (en) * | 2020-12-11 | 2021-03-26 | 中国海洋石油集团有限公司 | Method for quantitatively characterizing permeability dynamic change of multilayer oil reservoir |
Cited By (3)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN114135265A (en) * | 2021-10-19 | 2022-03-04 | 中海油能源发展股份有限公司 | Low-cost and high-efficiency transformation process method for low-permeability reservoir of offshore oilfield |
| CN114135265B (en) * | 2021-10-19 | 2023-09-29 | 中海油能源发展股份有限公司 | Low-cost and high-efficiency transformation process method for low-permeability reservoir of offshore oil field |
| CN115032337A (en) * | 2022-05-23 | 2022-09-09 | 中国石油大学(华东) | Maximized CO 2 Brine pre-pumping amount and reinjection amount calculation method for sealing efficiency and site test verification method |
Also Published As
| Publication number | Publication date |
|---|---|
| CN113266333B (en) | 2023-04-18 |
Similar Documents
| Publication | Publication Date | Title |
|---|---|---|
| US20170314377A1 (en) | Method for Enhancing Oil Recovery in Huff-Puff Oil Production of Tight Oil from a Fractured Horizontal Well | |
| CN105114048B (en) | A kind of staged fracturing of horizontal well single-well injection-production oil production method | |
| CN113266333B (en) | By extrusion of saturated CO 2 Method for improving permeability of oil sand reservoir by using brine | |
| US20220127942A1 (en) | Volumetric fracturing method of temporarily plugging and diverting through functional slick water with oil displacement agent injected simultaneously | |
| CN109209306B (en) | Horizontal well CO injection for ultra-low permeability tight oil reservoir2Asynchronous throughput energy supplementing method | |
| CN103939071B (en) | Horizontal well steam flooding well pattern structure and steam flooding method | |
| CN105317407B (en) | Development method of extratable reservoir with extra-high water-cut period | |
| CN106194122A (en) | The method that a kind of oil field abandoned well transform geothermal well or sub-salt well as | |
| CN106437642A (en) | Injection-production asynchronous mining method for horizontal well of fractured reservoir | |
| CN110847881A (en) | Fishbone type SAGD horizontal well capacity-expansion quick-starting and reservoir transformation structure method | |
| RU2478164C1 (en) | Development method of oil deposit located above gas deposit and separated from it with non-permeable interlayer | |
| CN110886594B (en) | Method for exploiting coal bed gas | |
| CN110005388A (en) | Fracturing and yield increasing method for 3-inch semi-slim well side drilling of ultra-low permeability oil reservoir | |
| CN105178931B (en) | Method for improving initial production speed of SAGD (steam assisted gravity drainage) | |
| RU2513791C1 (en) | Development method of multilayer oil deposit using hydraulic fracturing of formation | |
| CN114135265B (en) | Low-cost and high-efficiency transformation process method for low-permeability reservoir of offshore oil field | |
| RU2504650C1 (en) | Method of development of flooded oil deposit | |
| CN105545272A (en) | Oil extraction method for ultra-low permeability water-sensitive reservoir/compact reservoir | |
| CN103046916A (en) | Selective injection method of refracturing plugging agent for double parallel connection rock core | |
| CN106468161A (en) | A kind of oil production method for fractured carbonate rock water logging heavy crude reservoir | |
| RU2494247C1 (en) | Development method of water-flooded oil deposit | |
| CN103048253A (en) | Testing method of substrate permeation rate of repeated fracturing plugging agent | |
| CN111520117B (en) | Bottom water injection method and verification suitable for shallow layer horizontal seam oil reservoir | |
| CN211737114U (en) | Fish bone type SAGD horizontal well dilatation quick start and reservoir transformation structure | |
| RU2509885C1 (en) | Development method of water-flooded oil deposit |
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 |