RU2142557C1 - Method of development of oil pool - Google Patents

Abstract

FIELD: oil production. SUBSTANCE: method includes maintaining of formation pressure by injection into formation of displacement agent. For this purpose, subject to determination on section of oil pool are oil withdrawal volume of injected displacement agent and time for observation of the process, and efficiency of process of maintaining of formation pressure and its effect on formation. Technology of maintaining of formation pressure is varied. Displacement agent in varied technology of maintaining of formation pressure is used in form of CO₂ margin generated in formation and forced over formation with water. In this case, CO₂ margin is produced in formation by successive injection of aqueous solution of neutral salt of carbonic acid with addition of 0.5-1 wt.% of surfactant, 0.05-0.2 wt.% of water-soluble polymer of acryl series, and acid solution. Efficiency of maintaining of formation pressure and its effect on formation are assessed by Herst's index determined in course of process. Technology of maintaining of formation pressure is varied with Herst's index amounting to less than 0.5. EFFECT: higher efficiency of system f maintaining of formation pressure and oil recovery from formation. 3 cl, 2 tbl

Description

 The invention relates to oil production, in particular to a method for developing an oil reservoir, which allows to extract oil from a pre-flooded reservoir under complex geological and tectonic conditions at a late stage of development.

 There is a method of developing an oil reservoir, which consists in maintaining reservoir pressure (RPM) by injecting a displacing agent into the reservoir, determining an oil withdrawal site, the volume of injected displacing agent, selecting a displacing agent, monitoring process time, determining the effectiveness of the reservoir pressure maintenance process and the degree its impact on the reservoir, changing the technology of maintaining reservoir pressure [1].

 It is known that in the initial stage of development, the RPM system is designed schematically and is designed to provide compensation for fluid taken from the reservoir and oil displacement to production wells. It is difficult to foresee at the initial design in the RPM system the influence on the filtering process of natural heterogeneity, the filtration-capacitive properties of the collectors. At a late stage of development, the technogenic heterogeneity caused by the unsystematic operation of the RPM is superimposed on the natural heterogeneity of the reservoirs. The unsystematic operation of the RPM leads to an extremely uneven distribution of water pressure in the reservoir. This, in turn, leads to a breakthrough of water into production wells, the formation of stagnant and weakly drained zones, which generally affects the development strategy and requires a change in development technology.

In order to increase the coverage of the reservoirs with water flooding and to displace residual oil from the waterflood zones, as a rule, various agents are added to the water, including polymers, surfactants, alkalis, hydrocarbon gas (CO ₂ ), micellar solutions and other chemicals. Only those working agents that mix with oil and water or have ultra-low interfacial tension at the contact can displace residual oil from water-flooded formations. Such conditions arise during the displacement of oil by agents, which almost completely eliminate the negative effect of capillary forces on oil displacement.

 According to the estimates of Russian experts, an increase in the final oil recovery should be expected during reservoir flooding, respectively, when using surfactants - by 4-6%, when injecting water-gas mixtures - by 6-7%, sulfuric acid and alkali - by 5%, carbon dioxide - by 15% and more.

The most promising method for enhanced oil recovery waterflood system at various layers is considered injection into the formation rim CO _2. It is particularly important that the injection of CO ₂ can be effectively applied in a wide range of geological conditions for the extraction of both light and heavy oils.

The analysis of the research results revealed a number of positive effects observed during the implementation of technologies based on the use of CO ₂ .

Determined that:
when 5-10% CO ₂ was dissolved in water, an increase in viscosity by 20-30% was observed, a decrease in the mobility factor by 2–3 times;
upon dissolution of CO ₂ in oil, a decrease in oil viscosity by 1.5-2.5 times was observed;
when CO ₂ is dissolved in oil, the interfacial tension at the oil-water interface decreases;
when carbon dioxide is dissolved in oil and water, an increase in the volume of oil occurs (volume effect) and the residual oil is washed out.

At the same time, some shortcomings were noted in the introduction of the technology for injecting the CO ₂ rim to increase oil recovery, including:
with insignificant changes in thermobaric conditions, including well shutdowns, a decrease in the concentration of CO ₂ in oil occurs, which entails the coagulation and precipitation of asphaltenes and resins. This, in turn, indicates the predominant adsorption of resinous oil components on the rock, leading to the formation on the hard surface of a highly viscous oil film that is not washed during normal water flooding;
breakthrough of CO ₂ into production wells;
corrosion of oilfield equipment;
the problems of transporting large volumes of carbon dioxide;
lack of necessary machinery and equipment to ensure the safe storage and use of CO ₂ ;
high cost of technology;
and, finally, the most important thing is the absence of sufficient quantities of CO ₂ in many oil producing regions for implementation in oil production.

The aim of the invention is to increase the efficiency of the system for maintaining reservoir pressure and, accordingly, oil recovery. In addition, the creation of such a technology using CO ₂ , which would retain all the positive effects, and on the other hand, would prevent the negative effects of previous technologies.

The goal is achieved by the fact that in the method of developing an oil reservoir, which includes maintaining reservoir pressure by pumping a displacing agent into the reservoir, determining an oil withdrawal site, the volume of injected displacing agent, the observation time of the process, determining the effectiveness of the process of maintaining reservoir pressure and its impact on reservoir, changing the FPD, as a displacing agent in PDP technology variable used in the formation fringe generated CO _2, water is pushed through the bed, etc. This rim and create a CO ₂ formation by sequential injection in the middle of carbonic acid salt formation with the addition of surface-active compounds (surfactants) (0.5-1 wt.%) and a water-soluble acrylic polymer of (0.05 to 0.2 weight .%) and acid solution.

 In addition, as an indicator characterizing the effectiveness of the reservoir pressure and the degree of its impact on the reservoir, the Hurst parameter is determined and the change in the technology for maintaining reservoir pressure is made at a value of less than 0.5. The medium salt of carbonic acid with surfactant and polymer, and the acid solution are injected alternately, and fresh water is pumped before the acid solution is injected.

The proposed technology provides for the formation of CO ₂ in reservoir conditions as a result of the reaction of special aqueous solutions of chemicals injected into the reservoir.

 A gas-forming solution and an acid solution are successively pumped into the formation. The gas-forming solution is an aqueous solution of a medium salt of carbonic acid with the addition of a surfactant (0.5-1 wt.%) And polymer (0.05-0.2 wt.%), The mass concentration of carbonic acid salt is determined based on the concentration of acid in acid solution from stoichiometric ratios. The injected gas-forming and acidic solutions are Newtonian fluids, which facilitates their penetration primarily into the highly permeable interlayer, where carbon dioxide is formed between them as a result of a chemical reaction. The polymer added to the aqueous solution of carbonic acid salt makes it possible to level the injection front, significantly reduce its mixing with the reservoir fluid, serves as a foaming agent at the stage of blocking the high permeability interval, and at the stage of penetration into low permeable layers shows viscoelastic properties.

 On the other hand, microembryonic bubble systems formed during an exothermic reaction have abnormal rheological properties, which, ceteris paribus, can increase waterflooding efficiency by 1.2-1.3 times and further increase the final oil recovery by 3-5% compared to other waterflooding technologies.

 The abnormal state of the system is determined by the volume fraction of gas nuclei in the mixture and occurs at a pressure of 1.2-2.0 times the saturation pressure of the system at a given gas content and temperature.

 In addition, the surfactant additive contributes to the hydrophobization of the first space during the filtration of the solution in the pre-transition phase state through the reservoir and, as a result, to an increase in its viscoelastic nonequilibrium properties.

The rim of the foamed gas-liquid system formed in this way in highly permeable and washed areas creates a significant additional resistance to the flow of water injected after it. Here, most of the CO ₂ gas produced is sent to create a barrier to waterlogged areas. Part of the CO ₂ dissolved in the oil creates a volumetric effect and provides the washing away of residual oil. Moreover, under certain thermobaric conditions, carbon dioxide generated directly in the reservoir can be mixed with oil in unlimited proportions. The proportion of CO ₂ dissolved in water, increasing the viscosity of the water, helps to level out the displacement front and increase the coverage of the formation.

Thus, for the first time, it was possible to prevent the above negative consequences and disadvantages of the known method of injecting CO ₂ into the reservoirs, while maintaining its positive properties and effectiveness. Moreover, the use of the rim of a pseudo-boiling gas-liquid system (OGPS) is incomparably cheaper than the available modifications of the CO ₂ injection technology, since used CO ₂ is created directly in reservoir conditions.

 Observance of the condition of complete saturation of carbon dioxide in the created rim provides single-phase and nonequilibrium of the obtained rim, which significantly increases the effectiveness of the proposed method in contrast to existing methods in which, when the carbon dioxide is supersaturated, the rim is biphasic, as a result, is ahead of the gas breakthrough to production wells under carbon dioxide undersaturation, the properties of the rim practically do not differ from the properties of water.

 Preparation and conduct of field trials.

Preparation for the technological operation includes the following main activities:
a systematic analysis of the state and forecast of the effectiveness of the replaced waterflooding technology for injection sites (injection well clusters, blocks, elements);
system analysis of the overall effectiveness of the reservoir pressure maintenance system (RPM);
conducting a set of geophysical and field studies in the selected injection wells to determine the technical condition of the injection well string, running elevator pipes, cleaning sand from the wells and determining water absorption profiles using standard debitometry methods;
equipment of the mouth of injection wells for injection of composite systems and acid solution;
preparation of a composite system in tanks CA-320;
preparing a solution of hydrochloric acid in an acidic.

The executive part is as follows:
pushing the composite composition into the well through the unit;
subsequent injection of a solution of hydrochloric acid;
further injection of water into the reservoir.

 The injection rate is regulated in order to control the phase state of the resulting gas-liquid system.

 To implement the method in the field, water-flooding systems operating on deposits (water pipes, pumps, etc.) are used. Working solutions are prepared immediately before injection. The necessary concentrations and volumes of injected portions of the reagents are set based on the required volume of the rim, the magnitude of the reservoir pressure and temperature. If necessary, to prevent mixing of the reagents in the wellbore, a portion of fresh water is pumped between them in the volume of the well or tubing.

 If necessary, the saline solution with additives and the acid solution are pumped alternately.

 As a water-soluble polymer of the acrylic series, for example, polyacrylamide, polyacrylonitrile (PAN), VO-65 ionomer can be used.

 As surfactants can be used cationic surfactants, ionic surfactants, neonogenic surfactants. It is preferable to use cationic surfactants, since they are not only active water repellents, but also corrosion inhibitors.

 An example implementation of the method.

 On the analyzed section of the reservoir, which is developed by maintaining reservoir pressure by water flooding, the selection of oil, the volume of injected water, the selection of injected water, the selection of fluid, the time of observation are determined.

The Hurst index is determined by the formula:
R / S = (a • t) ^H ,
where R is the cumulative range, m ³ ;
S is the standard deviation, m ³ ;
t is the process observation time, s;
H is the Hurst exponent.

 The obtained value of Hurst indicators for the entire development period and for individual periods is presented in table. 1.

 Analysis of the data allows us to conclude that, most often, the reservoir system for all development indicators is persistent, the Hurst indicator is H> 0.5, with the exception of the parameters “water injection” and “water injection-withdrawal” for the period from 06.93 to 12.98. "when H <0.5.

 This suggests that the "mobile" water in the reservoir does not perform the required useful work to maintain reservoir pressure.

 The drainage map also indicates the presence of a large number of stagnant and slightly drained zones. Therefore, there is a need to make changes to the mode of maintaining reservoir pressure.

For this, a 10% aqueous solution of soda ash with the addition of 1% surfactant (sulfanol or any other surfactant) and 0.1% polyacrylamide in a volume of 18 m ³ , 12 m ^{3 of a} 10% aqueous solution was successively pumped into the reservoir through injection wells hydrochloric acid and 5 m ^{3 of} water at a pressure of 6.5 MPa. The well was allowed to react for 5 hours. Then, the rim was squeezed with water through the PPD line for 1.5 hours. The results are shown in table. 2.

 As can be seen from the tabular data, the selection of oil for reacting production wells in the initial period increased on average by almost 2 times.

In another case, a 10% aqueous solution of soda ash with the addition of 1% surfactant (sulfanol) and 0.1% polyacrylamide in a volume of 18 m ³ , 12 m ^{3 of a} 10% aqueous hydrochloric acid solution was sequentially injected into the formation through injection wells, and 5 m ^{3 of} water at a pressure of 6.5 MPa.

 This operation is repeated by injection of similar volumes of reagents, while the injection pressure at the end of the stage is 8.5 MPa.

The well was allowed to react for 5 hours. Then, the rim was squeezed with water through the PPD line for 1.5 hours. Then, the next portion of the composition was pumped into the formation - a 10% aqueous solution of soda ash in a volume of 15 m ³ with the addition of sulfanol and polyacrylamide in the above concentrations. The injection was carried out at a pressure of 7.5 MPa.

At the final stage, 5 m ^{3 of} water was injected at a pressure of 9.0 MPa. The well was left for 20 minutes to react with the injected reagents. Then the rim was sold with water.

 As a result, oil recovery from reactive production wells increased from 10 to 100%.

Thus, the effectiveness of the reservoir pressure maintenance system has been confirmed by creating a rim for the specified downhole and reservoir conditions, microgerm gas content, as well as cyclic injection. As a result, the obtained single-phase solution more uniformly enters the high- and low-permeability layers, increasing the treatment coverage in thickness and depth of the required size of the CO ₂ rim, its phase state, and injection rate are easily monitored and controlled.

Sources of information
1. Mirzadzhanzade A. X., Shakhverdiyev A.Kh. Dynamic processes in oil and gas production. -M.:, Science, 1997, p. 175-177.

Claims (3)

 1. A method of developing an oil reservoir, including maintaining reservoir pressure by injecting a displacing agent into the reservoir, determining an oil withdrawal site, the volume of injected displacing agent, the process monitoring time, determining the effectiveness of the reservoir pressure maintenance process and the degree of its effect on the reservoir, changing the technology maintaining reservoir pressure, characterized in that as a displacing agent in a variable technology, the carbon dioxide rim generated in the formation is used pushed through the reservoir with water, while the carbon dioxide rim is created by sequentially injecting into the reservoir an aqueous solution of a medium carbonic acid salt with the addition of 0.5-1 wt.% surfactant, 0.05-0.2 wt.% water-soluble polymer acrylic series and acid solution, and as an indicator characterizing the effectiveness of the process of maintaining reservoir pressure and the degree of its impact on the reservoir, determine the Hurst indicator and a change in the technology of maintaining reservoir pressure is made at azatelya less than 0.5.  2. The method according to claim 2, characterized in that the injection of an aqueous solution of a medium salt of carbonic acid with additives and an acid solution is carried out alternately.  3. The method according to claim 1 or 2, characterized in that before the injection of the acid solution, fresh water is pumped into the formation.

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