CN113833447A - Method for realizing effective support of complex fractures in fracturing and application thereof - Google Patents
Method for realizing effective support of complex fractures in fracturing and application thereof Download PDFInfo
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- 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
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- E—FIXED CONSTRUCTIONS
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- E21B43/25—Methods for stimulating production
- E21B43/26—Methods for stimulating production by forming crevices or fractures
- E21B43/261—Separate steps of (1) cementing, plugging or consolidating and (2) fracturing or attacking the formation
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- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- 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
- E21B43/267—Methods for stimulating production by forming crevices or fractures reinforcing fractures by propping
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Abstract
The invention discloses a method for realizing effective support of complex cracks in fracturing and application thereof, which comprises the following steps of: step 1, plugging construction of a third-level natural crack; step 2, injecting fracturing fluid carrying small-particle-size proppant; step 3, injecting a fracturing fluid carrying a medium-particle-size proppant; and 4, injecting a fracturing fluid carrying the large-particle-size proppant. The method can be applied to fracturing construction. The method adopts a grading temporary plugging mode, and utilizes the temporary plugging agent to block the communicated natural cracks in a grading mode in the extension process of the main crack, so that the influence of the filtration loss of the fracturing fluid on the net pressure in the crack is avoided, the net pressure in the crack is ensured, and the early termination of the extension of the main crack caused by the large filtration loss of the fracturing fluid is avoided; and finally, effective communication and plugging of the full-seam long inner secondary seam are realized.
Description
Technical Field
The invention belongs to the field of fracturing, relates to a horizontal well staged multi-cluster fracturing technology, and particularly relates to a method for realizing effective support of complex fractures in fracturing and application thereof.
Background
The shale gas resource in China has great potential and the recoverable resource amount is about 26 multiplied by 1012m3Roughly equivalent to the united states. Only two sets of shales of the Sichuan basin frigid-armed system and the shixiu system are used, and the resource amount of the shales is 1.5-2.5 times of the conventional natural gas resource amount of the basin. However, the shale gas reservoir has low porosity and low permeability, and a complex natural fracture network is established in the shale gas reservoir through hydraulic fracturing operation to realize commercial gas flow. Therefore, whether an effective complex fracture network can be formed is very important for the fracturing effect of the shale gas well.
At present, in order to activate natural fractures in a large area, a mode of injecting low-viscosity slick water by a large-displacement pump is usually adopted on site, so that the natural fractures are effectively communicated while main fractures are formed, and a complex fracture network with the natural fractures and artificial main fractures staggered with each other is formed. However, after the artificial fracture is communicated with the natural fracture, a large amount of fracturing fluid is lost, the pressure in the fracture is reduced, and on one hand, the extension capacity of the main fracture is reduced; on the other hand, the opening difficulty of the far well natural fracture is increased, the opening of the natural fracture at the far fracture opening is not facilitated, and the increase of the transformation volume is greatly restricted. Therefore, how to form an effective complex fracture network and further increase the effective modification volume becomes a technical problem to be solved urgently by hydraulic fracturing of the shale gas well.
Chinese patent CN 103244097A relates to a process method for oil extraction in oil field, in particular to a method for controlling multi-crack fracturing of medium-depth coal bed for coal bed downhole operation, which comprises 1) preparing fluid loss reducing fracturing fluid; 2) using a high-pressure pump set, 3) using the high-pressure pump set, 4) using the high-pressure pump set, and 5) using the pre-liquid stage; 6) and finishing the work by six steps. Through theoretical analysis and on-site verification, the conventional active water sand fracturing method is changed, and the filtration loss reducing fracturing fluid, the pad fluid variable displacement technology, the multi-stage particle size slug technology, the reasonable sand ratio lifting technology and the like are adopted, so that the difficulties of large filtration loss, poor sand carrying capacity, excessive filtration loss of fracturing fluid, high construction pressure and the like existing in the opening of natural cracks in the conventional active water fracturing are overcome. The multi-crack is effectively prevented and treated by means of fluid loss fracturing fluid reduction, a pre-liquid variable displacement technology and a multi-stage particle size slug technology, so that the construction pressure is reduced, the proppant is ensured to be added smoothly, and the fracturing construction success rate is improved. But the patent is primarily directed to coal seam gas.
Chinese patent CN 106567701A provides a temporary blocking, steering and fracturing method based on polyvinyl alcohol fiber after surface modification, which comprises the following steps: 1) surface modified water-soluble polyvinyl alcohol fibers; 2) preparing a fracturing working fluid; 3) using active water to replace the liquid in the squeezed wellbore; 4) setting a fracturing packer; 5) injecting a pad fluid to form a main crack; 6) injecting water-soluble degradable fiber temporary plugging fracturing fluid into the formed main crack in a stepped manner, and injecting the water-soluble degradable fiber temporary plugging fracturing fluid into the stratum to form a new branch crack; 7) injecting a pad fluid into the formed new branch seam to enlarge the seam length; 8) step-type injection of sand carrying liquid into the formed new branch seam; 9) and (5) replacing the sand carrying liquid in the shaft with active water. According to the invention, old cracks or filled sand cracks are temporarily blocked, new cracks are made in the direction which has a certain angle with the original cracks, more natural cracks and areas which are not used by the primary cracks are communicated, a new crack drainage system is formed, the oil and gas yield and the final recovery ratio of an oil and gas field are improved, and the problems of recovering the yield of old wells and realizing the fracturing yield increase of new wells are solved. However, under the method described in this patent, the natural fracture opening range is limited by the pressure distribution within the fracture.
Chinese patent CN 106593389A discloses a fracturing method for realizing high-angle natural fracture oil deposit by adopting a permanent plugging agent, which comprises the steps of firstly using a drift size to drift a well, and then cleaning mechanical impurities in a shaft; then testing the pressure; perforating planned fracturing sections in the shaft; then, a fracturing pipe column is lowered for fracturing construction; then pumping the pad fluid: injecting temporary plugging agents with large particle sizes in different proportions into the pad fluid stage for multiple rounds in a slug mode to initially plug high-angle natural cracks; pumping and injecting a sand carrying liquid: filling high-angle natural micro cracks by using a small-particle-size plugging agent and a spiral slug sand adding mode, and ensuring effective expansion of the cracks; and finally, open flow, production demand and well completion. The method provided by the invention effectively blocks the upper and lower high-angle natural fractures of the reservoir, prevents the fractures from channeling in the fracturing process, controls the height of the fractures, realizes long-fracture transformation, ensures the full transformation of the reservoir, forms a fracturing technical mode suitable for the high-angle natural fracture reservoir, and improves the initial yield by more than 20%. However, under the method described in this patent, the natural fracture opening range is limited.
Disclosure of Invention
In order to solve the problem that the activation range of a natural fracture is limited when the existing shale gas well is fractured, the invention provides a method for realizing effective support of a complex fracture by controlling the opening of the natural fracture.
Compared with rock matrix, the natural fracture has higher permeability, is easy to become a fracturing fluid filtration channel in the fracturing process, reduces the pressure in the main fracture, and influences the extension capacity of the main fracture. Therefore, in natural fracture-developing formations, premature opening of the natural fracture should be avoided as much as possible to ensure the extension capability of the main fracture. At present, shale gas well fracturing often adopts two methods to achieve the purpose, namely: increasing displacement and controlling net pressure. Although the influence of natural fracture filtration loss on the main fracture liquid inlet amount is reduced through high discharge capacity, the fracturing liquid filtration loss is further increased under the action of high discharge capacity, the liquid inlet amount in the main fracture is limited in growth range, and the construction discharge capacity is greatly limited under the influence of wellhead device pressure limitation and cost; although the latter reduces the amount of fracturing fluid loss through low net pressure, when the formation pressure is lower than the construction pressure, the fracturing fluid easily seeps into the natural fractures, causing the main fractures to communicate with the natural fractures, resulting in fracturing fluid loss, which is particularly serious when the natural fractures open.
In the invention, a graded temporary plugging mode is adopted, and the temporary plugging agent is used for graded plugging of communicated natural cracks in the extension process of the main crack, so that the influence of the filtration loss of the fracturing fluid on the net pressure in the crack is avoided, the net pressure in the crack is ensured, and the early termination of the extension of the main crack caused by the large filtration loss of the fracturing fluid is avoided.
One of the purposes of the invention is to provide a method for realizing effective support of complex fractures in fracturing, which comprises the following treatment after main fracture creation:
and step 1, plugging construction of a third-level natural crack.
In a preferred embodiment, in the step 1, a soluble temporary plugging agent is used for plugging construction, and preferably, the dissolving time of the soluble temporary plugging agent is 10-40 min.
In a further preferred embodiment, the soluble temporary blocking agent is a mixture of 150-200 mesh soluble temporary blocking agent and 70-140 mesh soluble temporary blocking agent, preferably, the proportion of the 150-200 mesh soluble temporary blocking agent is 40-60%, for example, 50%.
In a further preferred embodiment, the soluble blocking agent preferably has an apparent density of 1.02 to 1.05g/cm3。
On one hand, the small-particle-size temporary plugging agent is small in size, so that a bridging effect is favorably formed at the junction of the natural fracture and the main fracture, and the small-particle-size temporary plugging agent can fill pores of a large-particle-size propping agent and can strengthen the quick plugging effect of the temporary plugging agent; the other partyThe apparent density of the temporary plugging agent is 1.02-1.05 g/cm3The density of the fracturing fluid is basically equivalent to that of the fracturing fluid (1.013 g/cm)3Left and right) basically can realize the full suspension effect of the temporary plugging agent in the fracturing fluid and ensure the plugging effect of the temporary plugging agent.
In a preferred embodiment, in the step 1, the fracturing fluid carrying the soluble temporary plugging agent is continuously injected according to different agent-liquid ratios of A1% -B1% -C1% -D1%, wherein A1 is 1-2%, B1 is 2-4%, C1 is 4-6%, and D1 is 6-8%; preferably, the percentage of A1% -B1% -C1% -D1% is 1-3-5-7%.
In the invention, the first stage temporary plugging is realized by injecting the fracturing fluid carrying the soluble plugging agent at the dosage ratio of A1% and B1%, the second stage temporary plugging is realized by injecting the fracturing fluid carrying the soluble plugging agent at the dosage ratio of C1%, and the third stage temporary plugging is realized by injecting the fracturing fluid carrying the soluble plugging agent at the dosage ratio of D1%.
In a further preferred embodiment, in step 1, the dissolution time of the soluble temporary blocking agent employed at different agent-to-liquid ratios of a 1%, B1%, C1% and D1% is: t is tA1＝tB1＜tC1＜tD1(ii) a Preferably, under the condition of the agent-liquid ratio of A1% and B1%, the dissolving time of the adopted soluble temporary plugging agent is 10-16 min, preferably 15 min; under the condition of an agent-liquid ratio of C1%, the dissolving time of the adopted soluble temporary plugging agent is 18-25 min, preferably 20 min; under the condition of D1% of agent-liquid ratio, the dissolving time of the adopted soluble temporary plugging agent is 28-40 min, preferably 30 min.
Wherein, tA1、tB1、tC1And tD1The dissolution times of the temporary plugging agents used at the agent-to-liquid ratios of A1%, B1%, C1% and D1% are indicated, respectively.
The source of the temporary plugging agent is not strictly limited, the conventional temporary plugging agent is generally adopted, and a commercially available product can be directly purchased or prepared by adopting a method disclosed by the prior art as long as the dissolving time is met. For example, it can be prepared by surface treatment and processing using inorganic salts, soluble organic substances, water-soluble polymers, active agents, etc. as raw materials.
In the invention, the temporary plugging of the natural fracture within the main fracture extension full-fracture length range is divided into 3 construction sub-stages, and the temporary plugging agent with the same mixed particle size but different dissolving time is adopted in the construction of each sub-stage.
In a preferred embodiment, in step 1, the volume of the fracturing fluid under different agent-fluid ratios is 0.5-1.5 times of the volume of the well bore.
In a further preferred embodiment, in the step 1, the viscosity of the fracturing fluid is 2-3 mPa.s, and the displacement is the maximum value under the pressure limiting of a wellhead.
In a preferred embodiment, in step 1, after the soluble temporary plugging agent enters the stratum, the ground pressure is increased to 0.5-1 MPa/min, and 50-100 m is injected3The fracturing fluid of (1).
Wherein, if the ground pressure is increased to 0.5-1 MPa/min, the concentration of the temporary plugging agent is relatively high, and 50-100 m of temporary plugging agent needs to be injected3The fracturing fluid is used for dispersing the temporary plugging agent at the end part of the main crack to avoid plugging the main crack.
And 2, injecting a fracturing fluid carrying a small-particle-size proppant.
When the first-stage temporary plugging agent (with the shortest dissolving time) is almost completely dissolved, fracturing fluid carrying small-particle-size propping agent is injected, and the small-particle-size propping agent can be filled when the liquid inlet speed in the natural fracture is relatively high, so that the effective support of the natural fracture is ensured.
In a preferred embodiment, in step 2, a fracturing fluid carrying 70-140 mesh proppant is injected in a slug-type manner, preferably 2-4 slugs, for example 3 slugs.
In a further preferred embodiment, in the step 2, the sand-liquid ratio of each slug is a 2% -B2% -C2% -D2%, wherein a2 is 2-3%, B2 is 4-5%, C2 is 6-7%, and D2 is 8-10%; preferably, a 2% -B2% -C2% -D2% ═ 2% -4% -6% -8%.
In a further preferred embodiment, in the step 2, the amount of the sand-carrying liquid is 30 to 40m for each sand-liquid ratio3The amount of the isolating liquid between every two slugs is 40 to c60m3。
And 3, injecting a fracturing fluid carrying the medium-particle-size proppant.
Wherein, in the second stage, the temporary plugging agent is dissolved for a time tC118-25 min) is injected into the fracturing fluid carrying the medium-particle-size proppant when the fracturing fluid is nearly completely dissolved.
In a preferred embodiment, in step 3, a fracturing fluid carrying 40-70 mesh proppant is injected by continuous sand adding.
In a more preferred embodiment, in step 3, the sand-to-liquid ratio is a 3% -B3% -C3% -D3% -E3% -F3%, wherein a3 is 4-6%, B3 is 7-9%, C3 is 10-12%, D3 is 13-15%, E3 is 16-18%, and F3 is 19-20%; the sand-liquid ratio is preferably 5% -8% -11% -14% -17% -20%.
In a further preferred embodiment, in step 3, the amount of the sand-carrying liquid is 40 to 50m for each sand-liquid ratio3And the viscosity of the fracturing fluid is 15-20 mPa.s.
And 4, injecting a fracturing fluid carrying the large-particle-size proppant.
Wherein, in the third stage, the temporary plugging agent (dissolution time t)D128-40 min) is injected into the fracturing fluid carrying the proppant with large particle size when the fracturing fluid is nearly completely dissolved.
In a preferred embodiment, in step 4, a fracturing fluid carrying 30-50 mesh and/or 20-40 mesh proppant is injected by continuous sand addition.
In a more preferred embodiment, in step 4, the sand-to-liquid ratio is a 4% -B4% -C4% -D4% -E4% -F4%, wherein a4 is 12-16%, B4 is 18-22%, C4 is 23-26%, D4 is 28-32%, E4 is 34-36%, and F4 is 38-42%; the sand-liquid ratio is preferably 15% -20% -25% -30% -35% -40%.
In a further preferred embodiment, in step 4, the amount of the sand-carrying liquid is 8 to 10m for each sand-liquid ratio3And the viscosity of the fracturing fluid is 50-60 mPa.s.
In the invention, under the influence of intra-fracture friction and fracturing fluid filtration loss, the intra-fracture pressure at the far fracture opening is low, the activation range of the natural fracture is limited, the flow rate of the intra-fracture fracturing fluid is low, and the sand carrying capacity is weak, so that the small-particle size proppant can more easily enter the natural fracture at the near well mouth, and the fracture supporting capacity at the far fracture opening is limited. Aiming at the problem, in order to ensure the smooth construction, the invention divides the temporary plugging of the natural crack within the range of the main crack extension full crack length into 3 construction sub-stages, and adopts the temporary plugging agent with the same particle size in each sub-stage construction, with different soluble time.
Therefore, with the further extension of the main crack, the natural cracks at three different positions of the near-crack opening, the near-crack middle part and the near-crack end are communicated and blocked in sequence, so that the former stage natural crack has enough time to open and extend after the temporary blocking agent at the former stage natural crack opening is dissolved and before the temporary blocking agent at the former stage natural crack opening is dissolved. At the moment, the fracturing fluid carrying the small-particle size proppant can be injected, and the small-particle size proppant can be timely filled when the liquid inlet speed in the natural fracture is relatively high.
When the upper stage natural fracture is fully extended and saturated and filled and the temporary plugging agent at the fracture of the current stage natural fracture is dissolved, even if high-displacement fracturing fluid is injected, the fracturing fluid, the propping agent and the like are difficult to enter the upper stage natural fracture again and flow into the main fracture and percolate into the current stage natural fracture, so that the communication and plugging of the current stage natural fracture are facilitated. Finally, effective communication and plugging of the full-seam long inner secondary seam are realized.
The second purpose of the invention is to provide a fracturing method, which comprises the following steps:
(1) performing feature evaluation on brittleness, three-dimensional ground stress and natural fracture of a fracturing target layer;
(2) optimizing crack parameters and fracturing construction parameters;
(3) optimizing injection parameters of the temporary plugging agent;
(4) performing combined operation of bridge plug and perforation;
(5) acid pretreatment operation;
(6) pre-liquid pre-seam construction;
(7) the construction treatment is carried out by adopting the method which is one of the purposes of the invention;
(8) replacing operation, and lowering a bridge plug;
(9) repeating the steps (4) to (8) until all sections are constructed;
(10) drilling and plugging after pressing, flowback, testing and production solving.
In a preferred embodiment, in step (1), the brittleness of the target zone may be evaluated according to pilot hole logging data and a mechanical experiment of a coring core, the three-dimensional geostress of the target zone may be evaluated by combining the pilot hole logging data and an acoustic emission mechanical experiment of the coring core, and the natural fracture characteristics may be determined according to a plurality of methods such as X-ray diffraction analysis, dipole acoustic logging, FMI imaging logging, core surface observation, and the like.
In a preferred embodiment, in step (2), conventional fractured well yield prediction simulation software (e.g., ECLIPSE, etc.) and fracture design simulation optimization software (e.g., Stimplan, Gohfer, Meyer, etc.) are applied to simulate the productivity and fracture morphology under different fracture parameters and fracture construction parameters, so as to optimize the fracture morphology parameters and construction parameters.
In the present invention, the operations of bridge plug, perforation combination and acid pretreatment are performed according to the conventional procedures disclosed in the prior art.
In a preferable embodiment, in the step (6), a low-viscosity fracturing fluid with the viscosity of 2-3 mPa.s is adopted, the discharge capacity is the maximum value under the pressure limiting of a wellhead, and the fluid quantity is 1-2 times of the volume of the shaft.
In a preferred embodiment, in the step (8), the displacement liquid amount is 1.1 to 1.2 times of the volume of the well bore; preferably, the first 20-30% of the high-viscosity fracturing fluid is 50-60 mPa.s, and the high-viscosity fracturing fluid is mainly used for cleaning settled sand in a shaft; 70-80% of low-viscosity fracturing fluid with the viscosity of 2-3 mPa.s; more preferably, the displacement is taken to be a maximum value under wellhead pressure limitation.
The third purpose of the invention is to provide the application of the method in fracturing construction.
Compared with the prior art, the invention has the following beneficial effects:
(1) the method adopts a grading temporary plugging mode, and utilizes the temporary plugging agent to block the communicated natural cracks in a grading mode in the extension process of the main crack, so that the influence of the filtration loss of the fracturing fluid on the net pressure in the crack is avoided, the net pressure in the crack is ensured, and the early termination of the extension of the main crack caused by the large filtration loss of the fracturing fluid is avoided;
(2) two low-density temporary plugging agents with small particle size specifications are adopted, so that the temporary plugging can be successfully carried out;
(3) the invention finally realizes effective communication and plugging of the secondary seam in the full-seam long inner seam through grading temporary plugging.
Drawings
Fig. 1 shows a schematic flow diagram of a fracturing method according to the present invention.
Detailed Description
While the present invention will be described in detail with reference to the following examples, it should be understood that the following examples are illustrative of the present invention and are not to be construed as limiting the scope of the present invention.
The raw materials used in the examples and comparative examples are disclosed in the prior art if not particularly limited, and may be, for example, directly purchased or prepared according to the preparation methods disclosed in the prior art.
The temporary plugging agent used in the examples can be purchased directly from the market.
[ example 1 ]
The vertical depth of a shale gas well in the southwest Sichuan area is 2180m, the depth measurement is 3980m, and the horizontal section is 1512 m. The method is characterized by comprising the following steps:
(1) and (3) carrying the perforating gun by adopting a coiled tubing to complete the 1 st section perforating operation. Wherein the perforation length is 3m, the hole density is 16 holes/m, and 3 clusters are formed.
(2) After the 1 st section of perforation operation is finished, after the first section of perforation operation, the distance is 1m3Permin discharge capacity co-injection pretreatment acid 10m3. The displacement is then increased to 6m3Injecting low-viscosity slick water 45 m/min3Replacing acid, and finally reducing the discharge capacity to 2m3Injecting low-viscosity slick water for 5 m/min3And replacing acid, thereby ensuring that the acid liquor fully reacts with the rock.
(3) The adopted low-viscosity slick water makes the main seam, and the discharge capacity is quickly increased to 16m3The viscosity of the fracturing fluid is 2mPa.s, and the amount of the fracturing fluid is 70m3。
(4) Injecting the carried temporary plugging agent (the weight of 150-200 meshes and 70-140 meshes is 1:1, and the apparent density is 1.05g/cm3) The low-viscosity slippery water is prepared by continuously injecting the agent-liquid ratio of 1-3-5-7% into 7.55m3The amount of the fracturing fluid under the conditions of each agent-to-fluid ratio is 40m3、50m3、50m3、45m3. Wherein the dissolving time of the temporary plugging agent under the condition of the first 2 agent-liquid ratios is 15min, the dissolving time of the temporary plugging agent under the condition of the 3 rd agent-liquid ratio is 20min, and the dissolving time of the temporary plugging agent under the condition of the 4 th agent-liquid ratio is 30 min. Then injecting low-viscosity slick water 60m3。
(5) Injecting 2mPa.s low-viscosity slippery water carrying 70-140-mesh low-density ceramsite, and continuously injecting 6.9m of sand-liquid ratio according to the proportion of 2-4-6-8%3The amount of the fracturing fluid under each sand-fluid ratio condition is 40m3、40m3、35m3、30m3. Then injecting 2mPa.s low-viscosity slickwater 60m3。
(6) Injecting and carrying 70-140 mesh low-density ceramsite (density is 1.40 g/cm)3) 2mPa.s low-viscosity slickwater, and continuously injecting the sand liquid into the water according to the proportion of 2-4-6-8 percent to 6.9m3The amount of the fracturing fluid under each sand-fluid ratio condition is 40m3、40m3、35m3、30m3. Then injecting 2mPa.s low-viscosity slickwater 40m3。
(7) Injecting 2mPa.s low-viscosity slippery water carrying 70-140-mesh low-density ceramsite, and continuously injecting 6.9m of sand-liquid ratio according to the proportion of 2-4-6-8%3The amount of the fracturing fluid under each sand-fluid ratio condition is 40m3、40m3、35m3、30m3. Then injecting 2mPa.s low-viscosity slickwater 50m3。
(8) Injecting 2mPa.s low-viscosity slippery water carrying 70-140-mesh low-density ceramsite, and continuously injecting 6.9m of sand-liquid ratio according to the proportion of 2-4-6-8%3The amount of the fracturing fluid under each sand-fluid ratio condition is 40m3、40m3、35m3、30m3. Then injecting 2mPa.s low-viscosity slickwater 60m3。
(9) Injecting high-viscosity slick water carrying 40-70 mesh low-density ceramsite, wherein the viscosity is 18mPa.s, and continuously injecting 32.55m of sand liquid according to the proportion of 5-8-11-14-17-20%3The amount of the fracturing fluid under each sand-fluid ratio condition is 50m3、50m3、45m3、45m3、40m3、40m3. Then injecting 2 mPas low-viscosity slickwater 60m3。
(10) Injecting high-viscosity glue solution carrying 30-50 meshes of low-density ceramsite, wherein the viscosity is 50mPa.s, and continuously injecting the sand solution into the high-viscosity glue solution according to the proportion of 15-20-25-30-35-40% to obtain a mixture with the particle size of 14.45m3The amount of the fracturing fluid under each sand-fluid ratio condition is 10m3、10m3、9m3、9m3、8m3、8m3。
(11) Injecting a displacement fluid comprising: 15m3High viscosity glue (viscosity 50mPa.s) and 40m3Low viscosity slickwater (viscosity 2 mpa.s). Then the bridge plug is lowered.
(12) A similar process is used to perform the fracturing operation of the remaining section.
(13) Treating the return liquid, and discharging, mining and evaluating the yield.
After the well is put into production, compared with other shale gas wells on the same platform, the gas production rate and the stable production time are obviously improved by 26 percent, which shows that the method can obviously increase the modification volume by improving the reservoir exploitation degree in the longitudinal direction, and proves the effectiveness and the reliability of the method.
[ example 2 ]
The vertical depth of a shale gas well in the southwest Sichuan area is 2080m, the depth is 4380m, and the horizontal section is 1512 m. The method is characterized by comprising the following steps:
(1) and (3) carrying the perforating gun by adopting a coiled tubing to complete the 1 st section perforating operation. Wherein the perforation length is 3m, the hole density is 16 holes/m, and 3 clusters are formed.
(2) After the 1 st section of perforation operation is finished, after the first section of perforation operation, the distance is 1m3Permin discharge capacity co-injection pretreatment acid 10m3. The displacement is then increased to 6m3Injecting low-viscosity slick water 45 m/min3Replacing acid, and finally reducing the discharge capacity to 2m3Injecting low-viscosity slick water for 5 m/min3And replacing acid, thereby ensuring that the acid liquor fully reacts with the rock.
(3) The adopted low-viscosity slick water makes the main seam, and the discharge capacity is quickly increased to 16m3The viscosity of the fracturing fluid is 3mPa.s, and the amount of the fracturing fluid is 70m3。
(4) Injecting the carried temporary plugging agent (the weight of 150-200 meshes and 70-140 meshes is 4:6, and the apparent density is 1.05g/cm3) The low-viscosity slippery water is prepared by continuously injecting the agent-liquid ratio of 2-4-6-8% into 7.55m3The amount of the fracturing fluid under the conditions of each agent-to-fluid ratio is 40m3、50m3、50m3、45m3. Wherein the dissolving time of the temporary plugging agent under the condition of the first 2 agent-liquid ratios is 15min, the dissolving time of the temporary plugging agent under the condition of the 3 rd agent-liquid ratio is 20min, and the dissolving time of the temporary plugging agent under the condition of the 4 th agent-liquid ratio is 30 min. Then injecting low viscosity slick water of 3mPa.s for 60m3。
(5) Injecting 3mPa.s low-viscosity slippery water carrying 70-140-mesh low-density ceramsite, and continuously injecting 6.9m of sand-liquid ratio according to the proportion of 2-4-6-8%3The amount of the fracturing fluid under each sand-fluid ratio condition is 40m3、40m3、35m3、30m3. Then injecting 3mPa.s low-viscosity slickwater 80m3。
(6) Injecting and carrying 70-140 mesh low-density ceramsite (density is 1.40 g/cm)3) The 3mPa.s low-viscosity slickwater is prepared by continuously injecting the sand liquid into the water according to the proportion of 3-5-7-10 percent3The amount of the fracturing fluid under each sand-fluid ratio condition is 40m3、40m3、35m3、30m3. Then injecting 3mPa.s low-viscosity slickwater 40m3。
(7) Injecting low-viscosity slippery water carrying 70-140-mesh low-density ceramsite, and continuously injecting the sand liquid into the container according to the proportion of 3-5-7-10% for 6.9m3The amount of the fracturing fluid under each sand-fluid ratio condition is 40m3、40m3、35m3、30m3. Then injected with 3mPa.s low viscosity slip50m of water3。
(8) Injecting and carrying 70-140 mesh low-density ceramsite (density is 1.40 g/cm)3) The 3mPa.s low-viscosity slickwater is prepared by continuously injecting the sand liquid into the water according to the proportion of 3-5-7-10 percent3The amount of the fracturing fluid under each sand-fluid ratio condition is 40m3、40m3、35m3、30m3. Then injecting 3mPa.s low-viscosity slickwater 60m3。
(9) Injecting and carrying 40-70 mesh low-density ceramsite (density is 1.46 g/cm)3) The high-viscosity slickwater has the viscosity of 20mPa.s, and the sand liquid ratio is continuously injected into 32.55m according to the proportion of 4-7-10-13-16-19%3The amount of the fracturing fluid under each sand-fluid ratio condition is 50m3、50m3、45m3、45m3、40m3、40m3. Then injecting 3mPa.s low-viscosity slickwater 60m3。
(10) Injecting and carrying 20-40 mesh low-density ceramsite (density is 1.48 g/cm)3) The high-viscosity glue solution has the viscosity of 60mPa.s, and the sand-liquid ratio is continuously injected into the sand-liquid mixture according to the proportion of 15-20-25-30-35-40 percent to 14.45m3The amount of the fracturing fluid under each sand-fluid ratio condition is 10m3、10m3、9m3、9m3、8m3、8m3。
(11) Injecting a displacement fluid comprising: 15m3High viscosity glue (viscosity 50mPa.s) and 40m3A low viscosity slickwater (viscosity of 3 mpa.s). Then the bridge plug is lowered.
(12) A similar process is used to perform the fracturing operation of the remaining section.
(13) Treating the return liquid, and discharging, mining and evaluating the yield.
After the well is put into production, compared with other shale gas wells on the same platform, the gas production rate and the stable production time are obviously improved by 21 percent, which shows that the method can obviously increase the modification volume by improving the reservoir exploitation degree in the longitudinal direction, and proves the effectiveness and the reliability of the method.
Claims (13)
1. A method for realizing effective support of complex fractures in fracturing comprises the following treatment after main fracture creation:
step 1, plugging construction of a third-level natural crack;
step 2, injecting fracturing fluid carrying small-particle-size proppant;
step 3, injecting a fracturing fluid carrying a medium-particle-size proppant;
and 4, injecting a fracturing fluid carrying the large-particle-size proppant.
2. The method according to claim 1, wherein in the step 1, a soluble temporary plugging agent with the dissolving time of 10-40 min is adopted for plugging construction;
preferably, the soluble temporary plugging agent is a mixture of 150-200-mesh soluble temporary plugging agent and 70-140-mesh soluble temporary plugging agent, wherein the proportion of the 150-200-mesh soluble temporary plugging agent is preferably 40-60%;
more preferably, the apparent density of the soluble plugging agent is 1.02-1.05 g/cm3。
3. The method as claimed in claim 1, wherein in step 1, the fracturing fluid carrying the soluble temporary plugging agent is injected continuously according to different agent-liquid ratios of A1% -B1% -C1% -D1%, wherein A1 is 1-2%, B1 is 2-4%, C1 is 4-6%, and D1 is 6-8%.
4. The method according to claim 3, wherein in step 1, the dissolution time of the soluble transient blocking agent used at different agent-to-liquid ratios of A1%, B1%, C1% and D1% is: t is tA1＝tB1＜tC1＜tD1；
Preferably, under the condition of the agent-liquid ratio of A1% and B1%, the dissolving time of the adopted soluble temporary plugging agent is 10-16 min; under the condition of an agent-liquid ratio of C1%, the dissolving time of the adopted soluble temporary plugging agent is 18-25 min; under the condition of D1% of agent-liquid ratio, the dissolving time of the adopted soluble temporary plugging agent is 28-40 min.
5. The method according to claim 4, wherein, in step 1,
the volume of the fracturing fluid under different agent-liquid ratios is 0.5-1.5 times of the volume of the shaft; and/or
The viscosity of the fracturing fluid is 2-3 mPa.s, and the discharge capacity is the maximum value under the pressure limiting of a wellhead; and/or
After the soluble temporary plugging agent enters the stratum, the ground pressure is increased to 0.5-1 MPa/min, and 50-100 m of the soluble temporary plugging agent is injected3The fracturing fluid of (1).
6. The method according to claim 1, characterized in that in step 2, 70-140 mesh proppant-carrying fracturing fluid is injected in a slug-type manner, preferably 2-4 slugs;
preferably, the sand-liquid ratio of each slug is A2% -B2% -C2% -D2%, wherein A2 is 2-3%, B2 is 4-5%, C2 is 6-7%, and D2 is 8-10%.
7. The method according to claim 6, wherein, in step 2,
the sand carrying liquid volume under each sand-liquid ratio condition is 30-40 m3；
The amount of the spacer fluid between every two slugs is 40-60 m3。
8. The method as claimed in claim 1, wherein in step 3, a fracturing fluid carrying 40-70 mesh proppant is injected by means of continuous sand adding;
preferably, the sand-liquid ratio is A3% -B3% -C3% -D3% -E3% -F3%, wherein A3 is 4-6%, B3 is 7-9%, C3 is 10-12%, D3 is 13-15%, E3 is 16-18%, and F3 is 19-20%;
more preferably, the amount of the sand-carrying fluid under each sand-fluid ratio condition is 40-50 m3And the viscosity of the fracturing fluid is 15-20 mPa.s.
9. The method as claimed in claim 1, wherein in step 4, a fracturing fluid carrying 30-50 mesh and/or 20-40 mesh proppant is injected by means of continuous sand adding; preferably, the sand to liquid ratioIs A4% -B4% -C4% -D4% -E4% -F4%, wherein A4 is 12-16%, B4 is 18-22%, C4 is 23-26%, D4 is 28-32%, E4 is 34-36%, F4 is 38-42%; preferably, the amount of the sand carrying liquid under each sand-liquid ratio condition is 8-10 m3And the viscosity of the fracturing fluid is 50-60 mPa.s.
10. A method of fracturing, comprising the steps of:
(1) performing feature evaluation on brittleness, three-dimensional ground stress and natural fracture of a fracturing target layer;
(2) optimizing crack parameters and fracturing construction parameters;
(3) optimizing injection parameters of the temporary plugging agent;
(4) performing combined operation of bridge plug and perforation;
(5) acid pretreatment operation;
(6) pre-liquid pre-seam construction;
(7) carrying out construction treatment by the method according to any one of claims 1 to 9;
(8) replacing operation, and lowering a bridge plug;
(9) repeating the steps (4) to (8) until all sections are constructed;
(10) drilling and plugging after pressing, flowback, testing and production solving.
11. The fracturing method according to claim 10, wherein in step 6, a low viscosity fracturing fluid with the viscosity of 2-3 mpa.s is used, the displacement is the maximum value under the pressure limiting of a wellhead, and the fluid volume is 1-2 times of the well bore volume.
12. The fracturing method according to claim 10 or 11, wherein in step 8, the displacement fluid amount is 1.1 to 1.2 times the volume of the wellbore; preferably, the first 20-30% of the high-viscosity fracturing fluid is 50-60 mPa.s; 70-80% of low-viscosity fracturing fluid with the viscosity of 2-3 mPa.s; more preferably, the displacement is taken to be a maximum value under wellhead pressure limitation.
13. Use of the method of any one of claims 1 to 9 in fracturing operations.
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