CN104675371B - Composite oil displacement experimental method for alternately injecting gel and polymer solution after polymer flooding and subsequent water flooding - Google Patents

Abstract

The present invention relates to a composite oil flooding experimental method of alternately injecting gel and polymer solution after polymer flooding plus subsequent water flooding, the specific steps are as follows: step 1, first prepare a large slab rock core; step 2, then carry out polymer flooding; step 3 1. Multiple rounds of alternating injection of gel + polymer solution to drive oil; Step 4, subsequent water flooding; Step 5, sorting out data and calculating the ultimate recovery factor. Based on the distribution of remaining oil after polymer flooding and the change of reservoir permeability, the composite flooding experimental method of the present invention seeks an economical and effective method for tapping the potential of remaining oil in the subsequent water flooding stage, which greatly improves the recovery The rate has made a certain contribution to the actual oil recovery work.

Description

A kind of composite flooding in which gel and polymer solution are injected alternately after polymer flooding and subsequent water flooding oil test method

technical field

The invention relates to the technical field of chemical flooding, in particular to a compound flooding experimental method in which gel and polymer solutions are alternately injected after polymer flooding and subsequent water flooding.

Background technique

For reservoirs with large permeability gradients and severe interlayer heterogeneity, there are problems such as early water breakthrough in oil wells during water flooding, rapid rise of water cut, and low oil recovery. The polymer solution itself has a high viscosity, which can effectively improve the water-oil mobility ratio, help alleviate interlayer conflicts, improve the liquid absorption profile, and expand the swept volume of the displacement liquid, thereby enhancing oil recovery. For such reservoirs, polymer flooding can be carried out directly before water flooding to improve oilfield recovery efficiency. Although polymer flooding can effectively avoid the above-mentioned problems of water flooding in reservoirs, about 50% of the crude oil remains underground after polymer flooding. Therefore, it is particularly important to improve the recovery of residual oil after polymer flooding.

The main reason for the limited enhanced recovery of polymer flooding is that the ineffective water circulation phenomenon of channeling along the large pores and subsequent water flooding is serious, the utilization rate of polymer is low, and the crude oil in the middle and low permeability parts cannot be effectively displaced. After polymer flooding, the application of ASP flooding technology can still increase the recovery rate by about 10%, but the performance characteristics of the mixture of different components of chemical agents in the porous media of the reservoir are quite different, such as adsorption, diffusion and migration. It leads to the "chrome effect" and unsatisfactory "synergistic effect" during oil displacement in the pores of the reservoir. When strong alkali additives are used, serious scaling will occur in many links during the recovery process, which will affect the normal production of oil wells. There are a series of problems such as shortened period and difficulty in demulsification and dehydration of produced fluid; foam flooding after polymer flooding can increase the recovery rate by 10%, but the pilot experiment carried out in the oil field has unsatisfactory results and complicated construction; The feasibility of using microbial flooding to further enhance oil recovery after flooding has also been studied indoors, but the value of indoor enhanced oil recovery is not high, and microorganisms have strict requirements on formation conditions, so the generalization is not strong.

Therefore, based on the distribution of remaining oil after polymer flooding and the change of reservoir permeability, it is imperative to find an economical and effective method to tap the potential of remaining oil after polymer flooding.

Contents of the invention

In view of the above analysis, the present invention aims to provide a composite flooding experimental method of alternately injecting gel and polymer solution after polymer flooding plus subsequent water flooding, so as to solve the technical problem of low recovery rate of existing oilfields.

The purpose of the present invention is mainly achieved through the following technical solutions:

A composite flooding experimental method of alternately injecting gel and polymer solution after polymer flooding plus subsequent water flooding, characterized in that the specific steps are as follows:

Step 1. First prepare a large slab core

① Use quartz sand with a quartz content of more than 99wt%, and re-screen it into four grades of 40-60 mesh, 60-100 mesh, 100-200 mesh, and 200 mesh or more with a vibrating sieve machine; E-44 epoxy resin, benzene Dibutyl diformate, ethylenediamine and acetone are mixed to form an adhesive;

② Prepare different ratios of quartz sand and adhesives in stages, add 20wt% natural core debris after manual sand rubbing, put them into large flat core molds in stages, and pressurize for 1 minute each;

③ Place the pressed large slab core in a constant temperature box at 100°C for drying;

④ Glue the four corners and the center of the dried large slab core to end caps, and each end cap is equipped with a Φ8mm male buckle;

⑤ Scrape the surface of the core, and scrape the glue twice to prevent the adhesive from penetrating into the core during casting;

⑥Epoxy resin is used to cast the rock core in the mold, and the large slab core shows a positive rhythm change, and the permeability increases sequentially from top to bottom.

The size of the large slab core is 600mm in length, 600mm in width, and 45mm in height; the purity of the chemicals used is above chemical purity.

Step 2, then carry out polymer flooding, and calculate the recovery factor after polymer flooding:

①The salinity range of the simulated formation water salinity range is 6000mg/L～6400mg/L after the large slab core is evacuated with saturated formation water, and the water phase permeability K _w and porosity Φ _w of the core are measured;

②Inject simulated oil into the core at an experimental temperature of 40°C to 50°C until no water flows out from the outlet end of the core. The original oil saturation of the large slab core is determined to be 52.92% (volume ratio, including water content after that). Volume ratio);

③ After injecting 0.56PV-0.64PV polymer, stop the injection, carry out water flooding until the water content reaches 97%-99%, and then stop the flooding (the polymer is hydrolyzed polypropylene with a molecular weight of 25 million and a concentration of 1200mg/L amides);

④ During the displacement process, record the displacement speed, time, oil production, water production and pressure;

⑤ Change the graduated cylinder every half hour to measure the output fluid and oil volume, measure the water cut, and turn off the pump when the water cut reaches 97% to 99%, and calculate the recovery after polymer flooding.

Step 3: Use 0.02PV～0.03PV gel + 0.02PV～0.03PV polymer solution to flood oil alternately for multiple rounds. The gel forming time is 12h～24h. 13 rounds, 0.40PV ~ 0.78PV, record the displacement speed, time, oil production, water production and pressure of each round of alternating injection in each stage (among which the molecular weight of the gel is 25 million, the concentration of the polymer is 1800mg/L, Chromium ion gel system with a poly/cross ratio of 40:1).

Step 4: Subsequent water flooding at a constant flow rate of 2-4mL/min until the water cut reaches 97%-99%, then stop the displacement; record the displacement speed, time, oil production, water production and pressure during the displacement process .

Step 5, organize the data and calculate the ultimate recovery factor.

The parameters of interlayer heterogeneous large slab cores used in the experiment are shown in Table 1 below.

Table 1. Interlayer heterogeneous large slab core parameters

Beneficial effects of the present invention: Since the present invention directly applies the polymer to carry out oil displacement before water flooding, it can effectively avoid the viscous fingering phenomenon caused by the difference in oil-water viscosity, and slow down the rising speed of water cut; in addition, at the same displacement pore volume multiple (PV number), the recovery rate of direct polymer flooding is higher than that of water flooding followed by polymer flooding, and the oil flooding time is short and the oil recovery effect is good.

Additional features and advantages of the invention will be set forth in the description which follows, and in part will be apparent from the description, or may be learned by practice of the invention. The objectives and other advantages of the invention may be realized and attained by the structure particularly pointed out in the written description and claims hereof as well as the appended drawings.

Description of drawings

The drawings are for the purpose of illustrating specific embodiments only and are not to be considered as limitations of the invention, and like reference numerals refer to like parts throughout the drawings.

Fig. 1 is the variation curve between injection volume and recovery factor, pressure and water cut.

Detailed ways

Preferred embodiments of the present invention will be specifically described below in conjunction with the accompanying drawings, wherein the accompanying drawings constitute a part of the application and are used together with the embodiments of the present invention to explain the principle of the present invention.

Embodiment one

(1) After evacuating the cast model for 6 hours, saturate the artificially synthesized brine, and measure the porosity;

(2) Place the model saturated with artificially synthesized brine in an incubator at a constant temperature (45°C) for 12 hours or more;

(3) Oil flooding until the model does not produce water, then determine the original oil saturation;

(4) Use conventional sewage, 25 million ultra-high molecular weight, concentration of 1200mg/L (viscosity 40-50mPa.s, viscosity 20-25mPa.s after shear dilution) to drive oil, injection speed is 3mPa.s min, the injection rate is 0.60PV, and then water flooding to 98% water cut, calculate the recovery factor of polymer flooding + subsequent water flooding;

(5) inject 0.03PV gel system slug;

(6) Inject a slug of surfactant solution of 0.03PV, and record liquid production and oil production;

(7) Carry out multiple rounds of parallel experiments according to the experimental plan and steps (5) and (6).

According to the experimental procedure, first inject 0.60PV of polymer solution to drive oil, and then inject water until the water cut reaches 98%, and calculate the oil recovery; inject 0.03PV gel system solution into segmental plugs, and inject 0.03PV polymer into segmental plugs accordingly Solution, calculate the pressure and output liquid volume of each composite slug after injection, until the total amount of injected gel + polymer solution slug reaches 0.72PV; follow-up water injection until the water content reaches 98%, measure the output liquid volume and Calculate oil recovery rate. It is used to evaluate the oil displacement effect of surfactant solution after gel profile control.

Embodiment two

(1) After evacuating the cast model for 6 hours, saturate the artificially synthesized brine, and measure the porosity;

(2) Place the model saturated with artificially synthesized brine in an incubator at a constant temperature (45°C) for 12 hours or more;

(3) Oil flooding until the model does not produce water, then determine the original oil saturation;

(4) Use conventional sewage, 25 million ultra-high molecular weight, concentration of 1200mg/L (viscosity 40-50mPa.s, viscosity 20-25mPa.s after shear dilution) to drive oil, injection speed is 3mPa.s min, the injection volume is 0.64PV, after which the water is flooded to a water cut of 98%, and the recovery factor of polymer flooding is calculated;

(5) inject 0.02PV gel system slug;

(6) Inject a polymer solution slug of 0.02PV, and record liquid production and oil production;

(7) Carry out multiple rounds of parallel experiments according to the experimental plan and steps (5) and (6).

According to the experimental procedure, inject 0.64PV polymer solution to drive oil, and then inject water until the water cut reaches 98%, and calculate the oil recovery rate; inject 0.02PV gel system solution into segments, and inject 0.02PV polymer solution into segments accordingly , calculate the pressure and output fluid volume of each compound slug after injection, until the total amount of injected gel + polymer solution slug reaches 0.44PV; follow-up water injection until the water content reaches more than 99%, measure the output fluid volume and production volume Calculate oil recovery rate. It is used to compare the profile control effect of small slug multi-round injection with that of large slug injection.

The above is only a preferred embodiment of the present invention, but the scope of protection of the present invention is not limited thereto. Any person skilled in the art can easily conceive of changes or modifications within the technical scope disclosed in the present invention. Replacement should be covered within the protection scope of the present invention.

Claims (5)

1. A kind of composite flooding experimental method of injecting gel and polymer solution alternately after polymer flooding adds follow-up water flooding, it is characterized in that, concrete steps are as follows: Step 1, first preparing a large slab rock core; Step 2, then carry out polymer flooding, and calculate the recovery factor after polymer flooding; Step 3: multiple rounds of alternate injection of gel + polymer solution for oil displacement; Step 4, subsequent water flooding; Step 5, organize the data and calculate the ultimate recovery factor; Described step one specifically comprises the following steps: ① Use quartz sand with a quartz content of more than 99wt%, and re-screen it into four grades of 40-60 mesh, 60-100 mesh, 100-200 mesh, and 200 mesh or more with a vibrating sieve machine; E-44 epoxy resin, benzene Dibutyl diformate, ethylenediamine and acetone are mixed to form an adhesive; ② Prepare different ratios of quartz sand and adhesives in stages, add 20wt% natural core debris after manual sand rubbing, put them into large flat core molds in stages, and pressurize for 1 minute each; ③ Place the pressed large slab core in a constant temperature box at 100°C for drying; ④ Glue the four corners and the center of the dried large slab core to end caps, and each end cap is equipped with a Φ8mm male buckle; ⑤ Scrape the surface of the core, and scrape the glue twice to prevent the adhesive from penetrating into the core during casting; ⑥Using epoxy resin to cast the rock core in the mold, the large slab rock core changes in a positive rhythm, and the permeability increases sequentially from top to bottom; The multiple rounds of alternating injection of gel + polymer solution for oil displacement is as follows: 0.01PV-0.03PV gel + 0.02PV-0.04PV polymer solution are used for multiple rounds of alternate injection for oil displacement, and the gelation time is 12h ～24h, a total of 10～14 rounds of gel + polymer solution flooding, 0.3PV～0.98PV, record the displacement speed, time, oil production, water production and pressure of each round of alternating injection in each stage; Described step 2 specifically comprises the following steps: ① Evacuate the large slab core and saturate it with simulated formation water. The salinity of the simulated formation water ranges from 6000mg/L to 6400mg/L, and measure the water phase permeability K _w and porosity Φ _w of the core; ②Inject simulated oil into the core at the experimental temperature of 40°C to 50°C until no water flows out from the outlet end of the core, and the original oil saturation of the large slab core is determined to be 52.92%; ③After injecting 0.56PV～0.64PV polymer, stop the injection, carry out subsequent water flooding until the water content reaches 97%, and then stop the flooding; ④ During the displacement process, record the displacement speed, time, oil production, water production and pressure; ⑤ Change the graduated cylinder every half hour to measure the output fluid and oil volume, measure the water cut, and turn off the pump when the water cut reaches 97%, and calculate the recovery after polymer flooding. 2. a kind of polymer flooding according to claim 1 adds follow-up water flooding and alternately injects the compound oil flooding experimental method of gel and polymer solution, it is characterized in that, described E-44 epoxy resin, benzene two The purity of dibutyl formate, ethylenediamine and acetone are all above chemical purity. 3. The composite flooding experimental method of alternately injecting gel and polymer solution after polymer flooding plus subsequent water flooding according to claim 1, characterized in that: the polymer has a molecular weight of 25 million and a concentration of 1200 mg /L of hydrolyzed polyacrylamide. 4. The composite flooding experimental method of alternately injecting gel and polymer solution after a kind of polymer flooding plus follow-up water flooding according to claim 1, characterized in that: the gel has a molecular weight of 25 million and a polymer concentration of It is a chromium ion gel system with 1800mg/L and a poly/cross ratio of 40:1. 5. The composite flooding experimental method of polymer flooding plus follow-up water flooding according to claim 1, wherein gel and polymer solutions are alternately injected, wherein the follow-up water flooding is at 2-4mL/ Subsequent water flooding at a constant flow rate of 1 min until the water cut was 98%, and then the displacement was stopped; during the displacement process, the displacement speed, time, oil production, water production and pressure were recorded.