CN110819317B - Drilling fluid and application thereof in tight sandstone reservoir or fractured tight sandstone reservoir - Google Patents
Drilling fluid and application thereof in tight sandstone reservoir or fractured tight sandstone reservoir Download PDFInfo
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- 239000012530 fluid Substances 0.000 title claims abstract description 109
- 238000005553 drilling Methods 0.000 title claims abstract description 108
- 239000003795 chemical substances by application Substances 0.000 claims abstract description 90
- 230000035699 permeability Effects 0.000 claims abstract description 22
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims abstract description 20
- 239000000440 bentonite Substances 0.000 claims abstract description 17
- 229910000278 bentonite Inorganic materials 0.000 claims abstract description 17
- SVPXDRXYRYOSEX-UHFFFAOYSA-N bentoquatam Chemical compound O.O=[Si]=O.O=[Al]O[Al]=O SVPXDRXYRYOSEX-UHFFFAOYSA-N 0.000 claims abstract description 17
- 239000000314 lubricant Substances 0.000 claims abstract description 16
- 239000003112 inhibitor Substances 0.000 claims abstract description 12
- 239000003638 chemical reducing agent Substances 0.000 claims abstract description 5
- VTYYLEPIZMXCLO-UHFFFAOYSA-L Calcium carbonate Chemical compound [Ca+2].[O-]C([O-])=O VTYYLEPIZMXCLO-UHFFFAOYSA-L 0.000 claims description 34
- 150000003863 ammonium salts Chemical class 0.000 claims description 31
- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical group [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 claims description 19
- 239000010439 graphite Substances 0.000 claims description 19
- 229910002804 graphite Inorganic materials 0.000 claims description 19
- XAEFZNCEHLXOMS-UHFFFAOYSA-M potassium benzoate Chemical compound [K+].[O-]C(=O)C1=CC=CC=C1 XAEFZNCEHLXOMS-UHFFFAOYSA-M 0.000 claims description 19
- 229910000019 calcium carbonate Inorganic materials 0.000 claims description 17
- 239000000654 additive Substances 0.000 claims description 16
- 239000010426 asphalt Substances 0.000 claims description 16
- 239000002253 acid Substances 0.000 claims description 15
- 230000000996 additive effect Effects 0.000 claims description 15
- 239000003077 lignite Substances 0.000 claims description 14
- 229920005989 resin Polymers 0.000 claims description 14
- 239000011347 resin Substances 0.000 claims description 14
- 239000000835 fiber Substances 0.000 claims description 13
- 239000002245 particle Substances 0.000 claims description 13
- 239000000706 filtrate Substances 0.000 claims description 8
- 230000009467 reduction Effects 0.000 claims description 4
- ZLMJMSJWJFRBEC-UHFFFAOYSA-N Potassium Chemical compound [K] ZLMJMSJWJFRBEC-UHFFFAOYSA-N 0.000 claims description 3
- 239000011591 potassium Substances 0.000 claims description 3
- 229910052700 potassium Inorganic materials 0.000 claims description 3
- 238000005461 lubrication Methods 0.000 claims description 2
- 238000011084 recovery Methods 0.000 abstract description 10
- 238000001914 filtration Methods 0.000 abstract description 8
- 239000002981 blocking agent Substances 0.000 abstract description 2
- 230000002265 prevention Effects 0.000 abstract description 2
- 230000002401 inhibitory effect Effects 0.000 abstract 1
- WCUXLLCKKVVCTQ-UHFFFAOYSA-M Potassium chloride Chemical compound [Cl-].[K+] WCUXLLCKKVVCTQ-UHFFFAOYSA-M 0.000 description 22
- 235000019738 Limestone Nutrition 0.000 description 15
- 239000006028 limestone Substances 0.000 description 15
- 230000000052 comparative effect Effects 0.000 description 12
- 239000011159 matrix material Substances 0.000 description 11
- 229920002401 polyacrylamide Polymers 0.000 description 11
- 229920002239 polyacrylonitrile Polymers 0.000 description 11
- 239000001103 potassium chloride Substances 0.000 description 11
- 235000011164 potassium chloride Nutrition 0.000 description 11
- 239000001768 carboxy methyl cellulose Substances 0.000 description 10
- 239000007789 gas Substances 0.000 description 10
- 238000000034 method Methods 0.000 description 10
- 206010017076 Fracture Diseases 0.000 description 9
- DPXJVFZANSGRMM-UHFFFAOYSA-N acetic acid;2,3,4,5,6-pentahydroxyhexanal;sodium Chemical compound [Na].CC(O)=O.OCC(O)C(O)C(O)C(O)C=O DPXJVFZANSGRMM-UHFFFAOYSA-N 0.000 description 8
- 239000011148 porous material Substances 0.000 description 8
- 235000019812 sodium carboxymethyl cellulose Nutrition 0.000 description 8
- 229920001027 sodium carboxymethylcellulose Polymers 0.000 description 8
- 238000012360 testing method Methods 0.000 description 8
- 238000011085 pressure filtration Methods 0.000 description 7
- 208000013201 Stress fracture Diseases 0.000 description 6
- 238000011161 development Methods 0.000 description 6
- 230000018109 developmental process Effects 0.000 description 6
- 238000003756 stirring Methods 0.000 description 6
- 239000004575 stone Substances 0.000 description 6
- 208000010392 Bone Fractures Diseases 0.000 description 5
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- 238000005096 rolling process Methods 0.000 description 5
- 238000005516 engineering process Methods 0.000 description 4
- 239000003208 petroleum Substances 0.000 description 4
- BWHMMNNQKKPAPP-UHFFFAOYSA-L potassium carbonate Chemical compound [K+].[K+].[O-]C([O-])=O BWHMMNNQKKPAPP-UHFFFAOYSA-L 0.000 description 4
- 101100532801 Caenorhabditis elegans sdn-1 gene Proteins 0.000 description 3
- 239000004354 Hydroxyethyl cellulose Substances 0.000 description 3
- 238000009826 distribution Methods 0.000 description 3
- 230000000694 effects Effects 0.000 description 3
- 235000019447 hydroxyethyl cellulose Nutrition 0.000 description 3
- 230000009545 invasion Effects 0.000 description 3
- 239000000203 mixture Substances 0.000 description 3
- 229920003023 plastic Polymers 0.000 description 3
- 239000004033 plastic Substances 0.000 description 3
- 239000002994 raw material Substances 0.000 description 3
- 229920002134 Carboxymethyl cellulose Polymers 0.000 description 2
- VEXZGXHMUGYJMC-UHFFFAOYSA-N Hydrochloric acid Chemical compound Cl VEXZGXHMUGYJMC-UHFFFAOYSA-N 0.000 description 2
- 229920000663 Hydroxyethyl cellulose Polymers 0.000 description 2
- 239000008186 active pharmaceutical agent Substances 0.000 description 2
- JBIROUFYLSSYDX-UHFFFAOYSA-M benzododecinium chloride Chemical compound [Cl-].CCCCCCCCCCCC[N+](C)(C)CC1=CC=CC=C1 JBIROUFYLSSYDX-UHFFFAOYSA-M 0.000 description 2
- 235000010948 carboxy methyl cellulose Nutrition 0.000 description 2
- 239000008112 carboxymethyl-cellulose Substances 0.000 description 2
- 229920002678 cellulose Polymers 0.000 description 2
- 239000001913 cellulose Substances 0.000 description 2
- 238000011156 evaluation Methods 0.000 description 2
- 238000002474 experimental method Methods 0.000 description 2
- 230000005764 inhibitory process Effects 0.000 description 2
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 description 2
- 238000012986 modification Methods 0.000 description 2
- 230000004048 modification Effects 0.000 description 2
- 229910000027 potassium carbonate Inorganic materials 0.000 description 2
- 229920005614 potassium polyacrylate Polymers 0.000 description 2
- 150000003839 salts Chemical class 0.000 description 2
- 230000035945 sensitivity Effects 0.000 description 2
- 238000010008 shearing Methods 0.000 description 2
- 239000007790 solid phase Substances 0.000 description 2
- 150000005846 sugar alcohols Polymers 0.000 description 2
- 238000010998 test method Methods 0.000 description 2
- 230000009471 action Effects 0.000 description 1
- 150000004703 alkoxides Chemical class 0.000 description 1
- 239000007864 aqueous solution Substances 0.000 description 1
- 229910021383 artificial graphite Inorganic materials 0.000 description 1
- 230000000903 blocking effect Effects 0.000 description 1
- 229920003090 carboxymethyl hydroxyethyl cellulose Polymers 0.000 description 1
- 230000008859 change Effects 0.000 description 1
- 239000002734 clay mineral Substances 0.000 description 1
- 239000011248 coating agent Substances 0.000 description 1
- 238000000576 coating method Methods 0.000 description 1
- 238000013329 compounding Methods 0.000 description 1
- KUNSUQLRTQLHQQ-UHFFFAOYSA-N copper tin Chemical compound [Cu].[Sn] KUNSUQLRTQLHQQ-UHFFFAOYSA-N 0.000 description 1
- 239000006185 dispersion Substances 0.000 description 1
- 210000001320 hippocampus Anatomy 0.000 description 1
- 230000006872 improvement Effects 0.000 description 1
- 230000001050 lubricating effect Effects 0.000 description 1
- 238000004519 manufacturing process Methods 0.000 description 1
- 238000002156 mixing Methods 0.000 description 1
- 239000003345 natural gas Substances 0.000 description 1
- 230000020477 pH reduction Effects 0.000 description 1
- 238000011056 performance test Methods 0.000 description 1
- 239000003209 petroleum derivative Substances 0.000 description 1
- 159000000001 potassium salts Chemical class 0.000 description 1
- 238000012545 processing Methods 0.000 description 1
- 230000001681 protective effect Effects 0.000 description 1
- 239000011435 rock Substances 0.000 description 1
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- 230000008961 swelling Effects 0.000 description 1
- 230000002195 synergetic effect Effects 0.000 description 1
- 238000005406 washing Methods 0.000 description 1
Classifications
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- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/02—Well-drilling compositions
- C09K8/04—Aqueous well-drilling compositions
- C09K8/14—Clay-containing compositions
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
- C09K2208/12—Swell inhibition, i.e. using additives to drilling or well treatment fluids for inhibiting clay or shale swelling or disintegrating
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- Chemical & Material Sciences (AREA)
- Dispersion Chemistry (AREA)
- Life Sciences & Earth Sciences (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Materials Engineering (AREA)
- Organic Chemistry (AREA)
- Earth Drilling (AREA)
Abstract
本发明涉及本发明涉及致密砂岩储层所用的钻井液领域，公开了一种钻井液及其在致密砂岩储层或裂缝性致密砂岩储层的应用。其中，以该钻井液的总量为基准，该钻井液包括：膨润土2‑4重量％、增粘剂0.4‑0.6重量％、降滤失剂4‑6重量％、抑制剂1.7‑5重量％、封堵防塌剂1‑5重量％、润滑剂1‑3重量％、防水锁剂0.4‑1重量％、致密承压暂堵剂0‑4重量％、加重剂0‑20重量％，水51.4‑89.5重量％，所述钻井液的密度为1.05‑1.15g/cm3。采用以上配比制得的钻井液具有针对致密砂岩储层或者裂缝性致密砂岩储层抑制防塌、减小水锁损害、降低滤失量，提高井壁稳定性，渗透率恢复值高的特点。The present invention relates to the field of drilling fluid used in tight sandstone reservoirs, and discloses a drilling fluid and its application in tight sandstone reservoirs or fractured tight sandstone reservoirs. Wherein, based on the total amount of the drilling fluid, the drilling fluid includes: 2-4% by weight of bentonite, 0.4-0.6% by weight of tackifier, 4-6% by weight of fluid loss reducer, and 1.7-5% by weight of inhibitor , 1-5 wt % of plugging and anti-slump agent, 1-3 wt % of lubricant, 0.4-1 wt % of waterproof locking agent, 0-4 wt % of dense pressure temporary blocking agent, 0-20 wt % of weighting agent, water 51.4-89.5 wt%, and the density of the drilling fluid is 1.05-1.15 g/cm 3 . The drilling fluid prepared by the above ratio has the characteristics of inhibiting collapse prevention, reducing water lock damage, reducing filtration loss, improving wellbore stability, and high permeability recovery value for tight sandstone reservoirs or fractured tight sandstone reservoirs. .
Description
Technical Field
The invention relates to the field of drilling fluid used for tight sandstone reservoirs, in particular to a drilling fluid and application thereof in tight sandstone reservoirs or fractured tight sandstone reservoirs.
Background
In recent years, with the continuous improvement of the oil and gas exploration and development degree, the development of compact sandstone oil and gas resources is gradually increased, and the compact sandstone oil and gas resources in China are widely distributed in large-scale sedimentary basins such as Ordos, Sichuan, Songliao, Tuhao, Tarim and the like, wherein the Ordos basin and the Sichuan basin have been commercially exploited in a large scale.
The compact sandstone matrix has the characteristics of low porosity and low permeability, the compact sandstone reservoirs with oil and gas production capacity have different degrees of fracture development, the fractures are good oil and gas seepage channels, but the drilling fluid invades the fractures under the action of pressure difference to cause reservoir damage, so that the permeability of the reservoir is reduced.
The fractured compact sandstone reservoir has the engineering geological characteristics of low porosity, low permeability, fine pore throat, natural fracture development, abundant clay minerals and the like, so that the fractured compact sandstone has potential damage types such as sensitive damage of different degrees, water lock damage, drilling fluid filtrate, solid invasion, drilling fluid leakage damage to the reservoir and the like. Once a fractured tight sandstone reservoir is damaged, the economic and effective development of tight oil and gas is seriously hindered.
CN105295872A discloses a drilling fluid suitable for tight sandstone reservoirs, which comprises bentonite, a coating inhibitor, a flow pattern regulator, a filtrate reducer, a waterproof locking agent, a temporary plugging agent, a biological polyalcohol salt, a weighting agent and water, wherein a large amount of biological polyalcohol salt is added into the drilling fluid to adjust the lubricity and the filtrate activity of the drilling fluid, so that a low-solid-phase drilling fluid is formed, and the drilling fluid has a better flow pattern in a high-temperature deep well. However, because the expansion rate of the biological poly alkoxide is relatively high, the anti-collapse performance is limited, and the micro-fracture development reservoir cannot be protected.
Because tight sandstone reservoirs can have fractures of different degrees, in order to relieve the damage of drilling fluid invading the fractures to the reservoirs, a drilling fluid suitable for the tight sandstone reservoirs is urgently needed, and the drilling fluid is more suitable for fractured tight sandstone reservoirs.
Disclosure of Invention
The invention aims to solve the problem that a plugging layer formed by drilling fluid is not suitable for a fractured compact sandstone reservoir in the prior art, and provides the drilling fluid and the application of the drilling fluid in the compact sandstone reservoir or the fractured compact sandstone reservoir.
In order to achieve the above object, a first aspect of the present invention provides a drilling fluid, wherein the drilling fluid comprises, based on the total amount of the drilling fluid: 2-4 wt% of bentonite, 0.4-0.6 wt% of tackifier, 4-6 wt% of filtrate reducer, 1.7-5 wt% of inhibitor, 1-5 wt% of plugging anti-collapse agent, 1-3 wt% of lubricant, 0.4-1 wt% of waterproof locking agent, 0-4 wt% of compact pressure-bearing temporary plugging agent, 0-20 wt% of weighting agent and 51.4-89.5 wt% of water.
The invention also provides application of the drilling fluid in tight sandstone reservoirs or fractured tight sandstone reservoirs.
The drilling fluid prepared by the invention has moderate viscosity and shearing force, small high-temperature and high-pressure filtration loss and reduced invasion of the filtrate of the drilling fluid; the anti-collapse agent has excellent anti-collapse performance, stabilizes a reservoir and reduces the water sensitivity damage of the reservoir; has excellent waterproof lock performance and reduces the damage of the water lock of the compact sandstone matrix.
The compact pressure-bearing temporary plugging agent in the drilling fluid prepared by the invention is prepared by the synergistic effect of calcium carbonate, high-acid-soluble fiber and ultra-low permeability treatment agent, and the plugging pressure-bearing capacity and stability of the drilling fluid are improved. Meanwhile, the compact pressure-bearing temporary plugging agent is uniformly mixed with other components, so that the invasion of fluid into the stratum can be prevented, and acidification and plugging removal can be carried out after well drilling and completion operation.
The fluid loss additive, the inhibitor, the plugging anti-collapse agent and the waterproof locking agent are matched with each other and act synergistically, so that the water sensitivity damage of a reservoir is further reduced, and the reservoir is stabilized.
Detailed Description
The endpoints of the ranges and any values disclosed herein are not limited to the precise range or value, and such ranges or values should be understood to encompass values close to those ranges or values. For ranges of values, between the endpoints of each of the ranges and the individual points, and between the individual points may be combined with each other to give one or more new ranges of values, and these ranges of values should be considered as specifically disclosed herein.
The invention provides a drilling fluid in a first aspect, wherein the drilling fluid comprises the following components by taking the total amount of the drilling fluid as a reference: 2-4 wt% of bentonite, 0.4-0.6 wt% of tackifier, 4-6 wt% of filtrate reducer, 1.7-5 wt% of inhibitor, 1-5 wt% of plugging anti-collapse agent, 1-3 wt% of lubricant, 0.4-1 wt% of waterproof locking agent, 0-4 wt% of compact pressure-bearing temporary plugging agent, 0-20 wt% of weighting agent and 51.4-89.5 wt% of water.
In the invention, the total amount of the drilling fluid is taken as a reference, and the compact pressure-bearing temporary plugging agent accounts for 2-4 wt% of the drilling fluid.
In the invention, the density of the drilling fluid is 1.05-1.15g/cm3。
In the invention, the compact pressure-bearing temporary plugging agent is preferably 2-4 wt%, and the drilling fluid prepared under the condition is more suitable for a fractured compact sandstone reservoir, so that the protection of the drilling fluid system on a compact sandstone matrix and a microcrack is improved, the mechanical drilling speed is favorably improved, and the friction resistance is reduced.
In the invention, based on the total amount of the compact pressure-bearing temporary plugging agent, the compact pressure-bearing temporary plugging agent comprises: 60-70 wt% of calcium carbonate, 20-30 wt% of high acid soluble fiber and 5-20 wt% of ultra-low permeability treatment agent.
Preferably, the calcium carbonate has a particle size of 40-400 mesh.
The selection of calcium carbonate is not particularly limited as long as the particle size of calcium carbonate is 40 to 400 mesh, preferably 100-300 mesh, within which the calcium carbonate is more sufficiently mixed with other components. The particle size of the calcium carbonate is graded, and for example, the particle size satisfies D50-187.9 μm and D90-365.9 μm.
In the invention, the length of the high acid soluble fiber is 20-40 μm, and the diameter is 0.5-2 μm.
The selection of the high acid-soluble fiber is not particularly limited, and the above conditions are satisfied, and for example, SDCF-1, manufacturer: shandong province Yingshi Dai Innovation Co., Ltd.
In the invention, the grain diameter of the ultra-low permeation treating agent is 80-2000 meshes.
The ultra-low permeability treatment agent is purchased from stone major innovation ltd of Dongying city under the trademark SDN-1, and the particle size distribution of the ultra-low permeability treatment agent can be D50-66.91 μm and D90-182.2 μm. The ultra-low permeability treatment agent in the particle size range is more uniformly mixed with calcium carbonate and high acid soluble fiber, and can effectively prevent fluid from invading stratum.
The weighting agent is used for adjusting the density of the drilling fluid, the selection of the weighting agent is not particularly limited, and limestone can be used.
In the invention, the selection of the bentonite is not particularly limited, and the bentonite meets the quality index of the bentonite for drilling mud in GB/T20973, and comprises the filtration loss of less than or equal to 15cm3The reading of the viscometer is more than or equal to 30 r/min, the yield value/plastic viscosity is less than or equal to 3, and the mass fraction of the 75 mu m screen residue is less than or equal to 4 percent. The tackifier is not particularly limited, and polyanionic cellulose, low-viscosity carboxymethyl cellulose and hydroxyethyl cellulose can be selected, so that the filtration loss is less than or equal to 10 mL.
In the invention, the fluid loss additive comprises the following components by taking the total amount of the drilling fluid as a reference: 2-3 wt% of high-temperature high-pressure fluid loss additive and 2-3 wt% of lignite resin.
The selection of the high-temperature high-pressure fluid loss additive is not particularly limited, and examples thereof include SD201 and SD 202. The selection of the lignite resin is not particularly limited, and the lignite resin having a trade name of SPNH may be selected so that the apparent viscosity is not more than 12mPa · s. The high-temperature high-pressure fluid loss additive is matched with the lignite resin, so that the fluid loss reduction effect is good, and the performance is stable.
In the present invention, the inhibitor includes potassium salts and ammonium salts; preferably, the potassium salt is an organic potassium salt and/or an inorganic potassium salt, and the ammonium salt is an organic ammonium salt and/or an inorganic ammonium salt.
The inhibitor adopts a mode of compounding potassium salt and ammonium salt, and preferably the addition amount of the potassium salt is 1.2-3.5 wt% and the addition amount of the ammonium salt is 0.5-1.5 wt% based on the total amount of the inhibitor. Wherein the potassium salt can be selected from potassium chloride, potassium carbonate, polyacrylamide potassium salt, and potassium polyacrylate. The ammonium salt can be selected from dodecyl dimethyl benzyl ammonium chloride and hydrolyzed polyacrylonitrile ammonium salt.
According to the invention, the plugging anti-collapse agent is high-acid-soluble sulfonated asphalt, the softening point of the high-acid-soluble sulfonated asphalt is more than or equal to 80 ℃, and the acid solubility is more than or equal to 90%.
The selection of the high acid-soluble sulfonated asphalt is not particularly limited, and may satisfy the specification that the softening point is not less than 80 ℃ and the acid solubility is not less than 90%, and may be FF-1, for example. The plugging anti-collapse agent is matched with the inhibitor, so that the high-temperature and high-pressure filtration loss of the drilling fluid is reduced, and the anti-collapse performance is improved.
In the invention, the lubricant is graphite, the particle size of the graphite is 325-10000 meshes, and the reduction rate of the lubricating coefficient is more than or equal to 45%.
Graphite can be artificial graphite, cubic graphite, scale graphite or microcrystalline graphite, and the particle size of graphite can be 325-type 10000 meshes, preferably 325-type 600 meshes, and in this particle size range, graphite is as the lubricant, can with other component intensive mixing, the coefficient of lubrication reduction is more than or equal to 45%.
In the present invention, the selection of the water-blocking agent is not particularly limited as long as the specification is satisfied with a density of 0.8 to 1.0g/cm3The surface tension of the 1% aqueous solution is less than or equal to 28mN/m, and can be SDFS-1, manufacturer: shandong province Yingshi Dai Innovation Co., Ltd.
The second aspect of the invention provides an application of the drilling fluid in tight sandstone reservoirs, preferably fractured tight sandstone reservoirs.
The drilling fluid prepared by the method can reduce the water lock damage of a compact sandstone matrix reservoir, has better anti-collapse performance and water lock prevention performance aiming at a fractured compact sandstone reservoir, and has obvious reservoir protection effect. Aiming at the fractured compact sandstone reservoir, the addition amount of the compact pressure-bearing temporary plugging agent can be adjusted according to the width of the fracture. When the compact pressure-bearing temporary plugging agent is adjusted within the range, the performance of the whole drilling fluid cannot be changed, and the compact pressure-bearing temporary plugging agent is mixed with other components in the drilling fluid, so that the protection capability of the drilling fluid on compact sandstone matrixes and microcracks is improved.
The present invention will be described in detail below by way of examples. In the following examples of the present invention,
aiming at a low-pore ultralow-permeability compact sandstone matrix reservoir and a microfracture compact sandstone reservoir, the rheological property and the filtration property of the drilling fluid are evaluated according to the following methods: GB-T29170-2012 is adopted: and (4) testing the performance of the drilling fluid in the petroleum and natural gas industry. And testing the rheological property and the API (American Petroleum institute) filtration loss of the sample to be tested by using a six-speed viscometer and a medium-pressure filtration loss meter. Then, a sample to be tested is put into a high-temperature aging tank, is subjected to hot roll aging for 16h at the temperature of 80 ℃, and is tested for rheological property and filtration loss by the same method, and the high-temperature high-pressure filtration loss at the temperature of 80 ℃ and the pressure of 3.5 MPa.
Aiming at a low-pore ultralow-permeability compact sandstone matrix reservoir, the drilling fluid is subjected to an inhibition and anti-collapse performance test: selecting a red river oil field reservoir section shale sample, performing a drilling fluid system rolling dispersion experiment by referring to a test method of physicochemical properties of shale of oil and gas industry standard SY/T5613-2000 of the people's republic of China, and calculating the rolling recovery rate of aged rock debris. Selecting a red river oil field extension group shale core, processing the red river oil field extension group shale core into a 100-mesh specification, performing an expansion experiment by referring to a test method of physicochemical properties of shale of oil and gas industry standard SY/T5613-2000 of the people's republic of China, and testing the expansion rate.
Aiming at a low-pore ultralow-permeability compact sandstone matrix reservoir, evaluating the reservoir protection performance of the drilling fluid: selecting a low-pore ultralow-permeability compact sandstone matrix core of a red river oil field reservoir, measuring the permeability value of the core before and after the drilling fluid is polluted according to an indoor evaluation method of the oil layer damage caused by the drilling fluid completion fluid of the oil and gas industry standard SY/T T6540-2002 of the people's republic of China, and calculating the permeability recovery value. The experimental conditions are as follows: the temperature is 80 ℃, the pressure difference is 3.5MPa, and the drilling fluid pollution time is 125 min.
Aiming at a micro-fracture compact sandstone reservoir, testing the compact pressure-bearing temporary plugging performance of the drilling fluid: selecting a tight sandstone core of a reservoir in the red river oil field, carrying out seam making treatment by using a core seam making device, and controlling the opening of the microcracks by padding copper (tin) wires with different diameters. According to an evaluation method of a petroleum and gas industry standard SY/T T6540-2002 drilling fluid completion fluid damage oil reservoir indoor of the people's republic of China, permeability before and after plugging a core is tested (conditions are that the temperature is 80 ℃, the pressure difference is 3.5MPa, and the drilling fluid pollution time is 125min), and fracture plugging rate is calculated; after the blocking layer is soaked by hydrochloric acid (mass concentration is 15%), the reverse permeability is measured, and the flowback recovery rate is calculated.
The specifications and manufacturers of the raw materials involved in the following examples are as follows:
bentonite: meets the standard of GB/T20973;
tackifier: polyanionic cellulose (PAC-LV), low viscosity carboxymethyl cellulose (CMC-LV), hydroxyethyl cellulose (HEC) available from Shandong Shunyuan Petroleum science, Inc.;
high-temperature high-pressure fluid loss additives, the grades SD201 and SD202, are purchased from Stone major Innovation science and technology Limited in Dongying city, Shandong province;
lignite resin, brand SPNH, purchased from mao innovative technologies ltd, yobo, eastern, city, mountain;
potassium chloride, potassium carbonate, potassium polyacrylamide, potassium polyacrylate, purchased from Zhengzhou Oriental auxiliary agent Co., Ltd;
dodecyl dimethyl benzyl ammonium chloride, hydrolyzed polyacrylonitrile ammonium salt, purchased from Zhengzhou Oriental auxiliary agent Co., Ltd;
high acid-soluble sulfonated asphalt, brand FF-1, available from Shandong Shunyuan Petroleum science, Inc.;
lubricant: graphite 325 plus 10000 meshes, and the mark GR-1 is purchased from Stone big Innovation technology Co., Ltd, Dongying City, Shandong province;
waterproof locking agent: the designation SDFS-1, purchased from Hippocampus Dongying City Stone major Innovation science and technology Co., Ltd;
compact pressure-bearing temporary plugging agent: calcium carbonate, 40-400 mesh, brand ZDJ-1; high acid soluble fiber, brand SDCF-1, available from mao innovative technologies ltd, stone, east, west; ultra-low permeability treatment agent, brand SDN-1, purchased from great innovation technologies ltd, stone, avenue;
weighting devicePreparation: limestone with specification density of 2.5-2.7g/cm3。
The drilling fluids prepared in examples 1-7 and comparative examples 1-3 were primarily directed to low pore ultra-low permeability tight sandstone matrix reservoirs.
Example 1
According to the weight percentage, 4 weight percent of bentonite, 0.6 weight percent of tackifier (low-viscosity sodium carboxymethyl cellulose CMC-LV), 2 weight percent of high-temperature high-pressure fluid loss additive (SD201), 3 weight percent of lignite resin (SPNH), 0.3 weight percent of polyacrylamide potassium salt (KPAM), 2 weight percent of potassium chloride, 1.5 weight percent of hydrolyzed polyacrylonitrile ammonium salt (NH)4HPAN), 4 wt% high acid-soluble sulfonated asphalt (FF-1), 2 wt% lubricant (325 mesh graphite), 1 wt% waterproof locking agent (SDFS-1), 10 wt% weighting agent (limestone, 2.5g/cm3) And 69.6 wt% water to a density of 1.08g/cm3The drilling fluid of (1).
Example 2
According to the weight percentage, 3 weight percent of bentonite, 0.4 weight percent of tackifier (low-viscosity sodium carboxymethyl cellulose CMC-LV), 3 weight percent of high-temperature high-pressure fluid loss additive (SD201), 2 weight percent of lignite resin (SPNH), 0.3 weight percent of polyacrylamide potassium salt (KPAM), 1.5 weight percent of potassium chloride, and 1.5 weight percent of hydrolyzed polyacrylonitrile ammonium salt (NH)4HPAN), 2 wt% high acid-soluble sulfonated asphalt (FF-1), 3 wt% lubricant (600 mesh graphite), 0.4 wt% waterproof locking agent (SDFS-1), 20 wt% weighting agent (limestone, 2.5g/cm3) And 62.9 wt% water were mixed with stirring to give a density of 1.15g/cm3The drilling fluid of (1).
Example 3
According to the weight percentage, 2 weight percent of bentonite, 0.5 weight percent of tackifier (low-viscosity sodium carboxymethyl cellulose CMC-LV), 2 weight percent of high-temperature high-pressure fluid loss additive (SD202), 3 weight percent of lignite resin (SPNH), 0.5 weight percent of polyacrylamide potassium salt (KPAM), 1 weight percent of potassium chloride, 0.5 weight percent of hydrolyzed polyacrylonitrile ammonium salt (NH)4HPAN), 3 wt% high acid-soluble sulfonated asphalt (FF-1), 1 wt% lubricant (10000 mesh graphite), 0.8 wt% waterproof locking agent (SDFS-1), 15 wt% weighting agent (limestone, 2.5g/cm3) And 70.7 weight% water was mixed with stirring to give a mixture having a density of 1.10g/cm3The drilling fluid of (1).
Example 4
According to the weight percentage, 4 weight percent of bentonite, 0.6 weight percent of tackifier (low-viscosity sodium carboxymethyl cellulose CMC-LV), 2 weight percent of high-temperature high-pressure fluid loss additive (SD201), 3 weight percent of lignite resin (SPNH), 0.5 weight percent of polyacrylamide potassium salt (KPAM), 0.7 weight percent of potassium chloride, 0.5 weight percent of hydrolyzed polyacrylonitrile ammonium salt (NH)4HPAN), 4 wt% high acid-soluble sulfonated asphalt (FF-1), 2 wt% lubricant (325 mesh graphite), 1 wt% waterproof locking agent (SDFS-1), 15 wt% weighting agent (limestone, 2.7g/cm3) And 66.7 wt% water were mixed with stirring to give a density of 1.10g/cm3The drilling fluid of (1).
Example 5
According to the weight percentage, 4 weight percent of bentonite, 0.6 weight percent of tackifier (low-viscosity sodium carboxymethyl cellulose CMC-LV), 2 weight percent of high-temperature high-pressure fluid loss additive (SD202), 3 weight percent of lignite resin (SPNH), 0.3 weight percent of polyacrylamide potassium salt (KPAM), 2.5 weight percent of potassium chloride, 1.5 weight percent of hydrolyzed polyacrylonitrile ammonium salt (NH)4HPAN), 4 wt% high acid-soluble sulfonated asphalt (FF-1), 2 wt% lubricant (325 mesh graphite), 1 wt% waterproof locking agent (SDFS-1), 15 wt% weighting agent (limestone, 2.7g/cm3) And 64.1 wt% water were mixed with stirring to give a mixture having a density of 1.10g/cm3The drilling fluid of (1).
Example 6
According to the weight percentage, 4 weight percent of bentonite, 0.6 weight percent of tackifier (low-viscosity sodium carboxymethyl cellulose CMC-LV), 2 weight percent of high-temperature high-pressure fluid loss additive (SD201), 3 weight percent of lignite resin (SPNH), 0.3 weight percent of polyacrylamide potassium salt (KPAM), 2 weight percent of potassium chloride, 1.5 weight percent of hydrolyzed polyacrylonitrile ammonium salt (NH)4HPAN), 1 wt% high acid-soluble sulfonated asphalt (FF-1), 2 wt% lubricant (325 mesh graphite), 1 wt% waterproof locking agent (SDFS-1), 15 wt% weighting agent (limestone, 2.7g/cm3) And 67.6 wt% water were mixed with stirring to give a mixture having a density of 1.10g/cm3The drilling fluid of (1).
Example 7
According to the weight percentage, 4 weight percent of bentonite, 0.6 weight percent of tackifier (low-viscosity sodium carboxymethyl cellulose CMC-LV), 2 weight percent of high-temperature high-pressure fluid loss additive (SD201), 3 weight percent of lignite resin (SPNH), 0.3 weight percent of polyacrylamide potassium salt (KPAM), 2 weight percent of potassium chloride, 1.5 weight percent of hydrolyzed polyacrylonitrile ammonium salt (NH)4HPAN), 5 wt% high acid-soluble sulfonated asphalt (FF-1), 2 wt% lubricant (325 mesh graphite), 1 wt% waterproof locking agent (SDFS-1), 15 wt% weighting agent (limestone, 2.7g/cm3) And 63.6 wt% water were mixed with stirring to give a density of 1.10g/cm3The drilling fluid of (1).
The drilling fluids prepared in examples 8-10 and comparative examples 4-5 were primarily directed to tight sandstone microfracture reservoirs.
Example 8
According to the weight percentage, 4 weight percent of bentonite, 0.6 weight percent of tackifier (low-viscosity sodium carboxymethyl cellulose CMC-LV), 2 weight percent of high-temperature high-pressure fluid loss additive (SD201), 3 weight percent of lignite resin (SPNH), 0.3 weight percent of polyacrylamide potassium salt (KPAM), 2 weight percent of potassium chloride, 1.5 weight percent of hydrolyzed polyacrylonitrile ammonium salt (NH)4HPAN), 4 wt% of high acid-soluble sulfonated asphalt (FF-1), 2 wt% of lubricant (325 mesh graphite), 1 wt% of waterproof locking agent (SDFS-1), 4 wt% of compact pressure-bearing temporary plugging agent and 6 wt% of weighting agent (limestone, 2.5 g/cm)3) And 69.6 wt% water to a density of 1.08g/cm3The drilling fluid of (1).
Wherein, in the compact pressure-bearing temporary plugging agent, the addition amount of calcium carbonate ZDJ-1 is 65 wt%, the weight of high acid soluble fiber (SDCF-1) is 25 wt% and the weight of ultra-low permeability treatment agent (SDN-1) is 10 wt% based on the total amount of the compact pressure-bearing temporary plugging agent. The particle size distribution of calcium carbonate D50-187.9 μm, D90-365.9 μm; the length of the high acid soluble fiber is 20 μm; the particle size distribution of the ultra-low permeability treatment agent D50-66.91 μm and D90-182.2 μm.
Example 9
The procedure of example 8 was followed except that the dense pressure-bearing temporary plugging agent was added in an amount of 2% by weight and the weighting agent (limestone) was added in an amount of 8% by weight.
Wherein, in the compact pressure-bearing temporary plugging agent, the addition amount of calcium carbonate is 70 wt%, the addition amount of the high acid soluble fiber is 25 wt% and the addition amount of the ultra-low permeation treating agent is 5 wt% based on the total amount of the compact pressure-bearing temporary plugging agent.
Example 10
The procedure of example 8 was followed except that the dense pressure-bearing temporary plugging agent was added in an amount of 3% by weight and the weighting agent (limestone) was added in an amount of 7% by weight.
Wherein, in the compact pressure-bearing temporary plugging agent, the addition amount of calcium carbonate is 60 weight percent, the addition amount of the high acid soluble fiber is 30 weight percent and the addition amount of the ultra-low permeation treating agent is 10 weight percent based on the total amount of the compact pressure-bearing temporary plugging agent.
Comparative example 1
The procedure of example 1 was followed except that no hydrolyzed polyacrylonitrile ammonium salt was added and the weighting agent (limestone) was added in an amount of 11.5% by weight.
Comparative example 2
The procedure of example 1 was followed except that potassium polyacrylamide and potassium chloride were not added and the amount of the weighting agent (limestone) added was 12.3% by weight.
Comparative example 3
The procedure of example 1 was followed except that the highly acid-soluble sulfonated asphalt FF-1 was not added and the weighting agent (limestone) was added in an amount of 14% by weight.
Comparative example 4
According to the method of example 8, except that the compact pressure-bearing temporary plugging agent contains 70 wt% of calcium carbonate and 30 wt% of ultra-low permeation treatment agent, based on the total amount of the compact pressure-bearing temporary plugging agent.
Comparative example 5
According to the method of example 8, except that in the dense pressure-bearing temporary plugging agent, based on the total amount of the dense pressure-bearing temporary plugging agent, 50% by weight of calcium carbonate was added and 50% by weight of high acid-soluble fiber was added.
The drilling fluid prepared in examples 1 to 7 and comparative examples 1 to 3 for the low-pore ultra-low-permeability tight sandstone matrix reservoir is subjected to the test results of the rheological property and the fluid loss property of the drilling fluid system, and the test results of the rolling dispersivity, the swelling rate and the permeability recovery value are shown in table 1 and table 2.
TABLE 1
TABLE 1 (continuation)
In Table 1, AV represents the apparent viscosity of the drilling fluid, PV represents the plastic viscosity of the drilling fluid, YP represents the hydrodynamic shear force of the drilling fluid, Gel represents the initial and final shear of the drilling fluid, and FL representsAPIIndicates drilling fluid API fluid loss, HkExpressing the thickness of the mud cake, FLHTHPIndicating the high-temperature high-pressure filtration loss of the drilling fluid.
TABLE 2
As can be seen from the results in tables 1 and 2, the reservoir protection drilling fluid system for the low-pore ultralow-permeability compact sandstone matrix prepared in each example has the advantages of little rheological property change before and after aging, moderate viscosity and shearing force, small API fluid loss before and after aging and high-temperature and high-pressure fluid loss, capability of better preventing drilling fluid filtrate from entering the reservoir, high rolling recovery rate, low expansion rate, good system inhibition performance and high permeability recovery value after core pollution. In comparative examples 1 and 2, if only potassium salt or ammonium salt is used as the inhibitor, the rolling recovery rate of the drilling fluid is low, and the expansion rate is high; in comparative example 3, if the high acid-soluble sulfonated asphalt is not added to the raw materials, the prepared drilling fluid has high expansion rate and low permeability recovery value.
The results of the rheological and fluid loss tests on the drilling fluids for the microcracked tight sandstone reservoirs prepared in examples 8-10 and comparative examples 4-5 are shown in table 3, and the results of the tight bearing temporary plugging test are shown in table 4.
TABLE 3
In Table 3, AV represents the apparent viscosity of the drilling fluid, PV represents the plastic viscosity of the drilling fluid, YP represents the hydrodynamic shear force of the drilling fluid, Gel represents the initial and final shear of the drilling fluid, and FL representsAPIIndicates drilling fluid API fluid loss, HkExpressing the thickness of the mud cake, FLHTHPIndicating the high-temperature high-pressure filtration loss of the drilling fluid.
As can be seen from the data in Table 3, after the compact pressure-bearing temporary plugging agent is added into the raw materials, the rheological property and the filtration loss of the drilling fluid are not greatly influenced, the components are uniformly dispersed and have good compatibility, and the API filtration loss and the high-temperature and high-pressure filtration loss before and after aging are small.
TABLE 4
The results in table 4 show that, for the micro-fracture tight sandstone reservoir, the plugging rate of the tight pressure-bearing temporary plugging agent of the drilling fluid prepared in each embodiment is more than 98%, the solid phase of the drilling fluid is effectively prevented from invading the micro-fracture, the acid solubility of mud cakes is more than 70%, and the flowback recovery rate after acid washing is more than 85%. When the fracture width of the compact sandstone reservoir is increased to 287.22 mu m, the protective effect on the compact sandstone reservoir is still better.
In comparative examples 4 and 5, if the compact pressure-bearing temporary plugging agent only adopts two components or a single component, the compatibility with other components is poor, the prepared drilling fluid has poor temporary plugging rate and high leakage loss, and particularly the temporary plugging rate of the drilling fluid is worse after the crack width is widened.
The preferred embodiments of the present invention have been described above in detail, but the present invention is not limited thereto. Within the scope of the technical idea of the invention, many simple modifications can be made to the technical solution of the invention, including combinations of various technical features in any other suitable way, and these simple modifications and combinations should also be regarded as the disclosure of the invention, and all fall within the scope of the invention.
Claims (8)
1. A drilling fluid, wherein the drilling fluid comprises, based on the total amount of the drilling fluid: 2-4 wt% of bentonite, 0.4-0.6 wt% of tackifier, 4-6 wt% of filtrate reducer, 1.7-5 wt% of inhibitor, 1-5 wt% of plugging anti-collapse agent, 1-3 wt% of lubricant, 0.4-1 wt% of waterproof locking agent, 2-4 wt% of compact pressure-bearing temporary plugging agent, 0-20 wt% of weighting agent and 51.4-89.5 wt% of water;
wherein, use the total amount of compact pressure-bearing temporary plugging agent as the benchmark, this compact pressure-bearing temporary plugging agent includes: 60-70 wt% of calcium carbonate, 20-30 wt% of high acid soluble fiber and 5-20 wt% of ultra-low permeability treatment agent;
wherein the particle size of the calcium carbonate is 40-400 meshes; the length of the high acid soluble fiber is 20-40 μm, and the diameter is 0.5-2 μm; the grain size of the ultra-low permeability treatment agent is 80-2000 meshes.
2. The drilling fluid of claim 1, wherein the fluid loss additive comprises, based on the total amount of the drilling fluid: 2-3 wt% of high-temperature high-pressure fluid loss additive and 2-3 wt% of lignite resin.
3. The drilling fluid of claim 1, wherein the inhibitor comprises potassium and ammonium salts.
4. The drilling fluid of claim 3, wherein the potassium salt is an organic potassium salt and/or an inorganic potassium salt, and the ammonium salt is an organic ammonium salt and/or an inorganic ammonium salt.
5. The drilling fluid of claim 1, wherein the plugging anti-collapse agent is high-acid-soluble sulfonated asphalt, the softening point of the high-acid-soluble sulfonated asphalt is more than or equal to 80 ℃, and the acid solubility is more than or equal to 90%.
6. The drilling fluid as claimed in claim 1, wherein the lubricant is selected from graphite, the particle size of the graphite is 325-10000 meshes, and the reduction rate of the lubrication coefficient is more than or equal to 45%.
7. A drilling fluid according to any one of claims 1 to 6, wherein the drilling fluid has a density of from 1.05 to 1.15g/cm3。
8. Use of the drilling fluid according to any one of claims 1 to 7 in tight sandstone reservoirs or fractured tight sandstone reservoirs.
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