System for preventing the water cone formation in gas deposits with low gas thickness

: The article describes the problem of water cone formation in gas deposits of small gas-saturated thickness. The process of pulling the water cone into the production well is analyzed. The most popular and effective methods of solving this problem are presented. A method of using an electric screw pump to prevent water accumulation in the bottomhole zone is proposed. The method of calculating the optimal pump flow rate, which allows operating the well without its overheating, is considered.


Problem description
Currently, the main complication in the operation of deposits withlow gas-saturated thickness is the rapid breakthrough of bottom water [1]. In connection with this problem, a water cone begins to move towards the operated well. If the resulting cone of water is not timely eliminated, it will block all perforations, which will lead to the well stopping.

Relevance of the problem
We would like to give an example of statistics on wells in the Pyreynoye and Beregovoye fields of PAO Rosneft. It is in these fields where the problem of the bottom water breakthrough is very pronounced. Thus, 19 of the 28 wells at the Pyreynoyefield were stopped due to a high water cut. On the Beregovoye field, the situation is much better:only 8 wells out of 63 were stopped due to a high water cut. This statistic can be seenin Table 1.

Methods for solving the problem of the bottom water breakthrough
Currently, not only Russian gas companies but also foreign ones are actively countering this problem. We have already accumulated quite a lot of experience in using various methods to solve the problem of the cone formation:periodic "blowing" of the well; replacement of pump and compressor pipes with pipes of smaller diameter; use of concentric lift and plunger lift systems; use of surfactants with their delivery to the bottom of the well; use of the bottom hole layouts for pumping water.
In this paper, we will consider the last of the listed options for solving the problem, as well as the method for calculating the optimal operation mode of the downhole assembly.
2 Analysis of the model of water cone formation in gas deposits

Analysis of the dependence of the water rate over time on various values of the permeability anisotropy
To experiment, the "TNavigator" software for hydrodynamic modeling was used. The simplest reservoir model of the "gas -water" equilibrium system was created. The value of the horizontal permeability was equal to 100 md. The vertical permeability varied, and four different values of 10, 25, 50, and 70 md were set. Four calculations were made, where the permeability anisotropy took the values 0.1, 0.25, 0.5, and 0.7. The results of the calculations can be seen in Figure 1. In Figure 1, we observe that when the permeability anisotropy is 0.7, the water cone is pulled up to 11 of the perforation block. With the lowest permeability anisotropy of0.1, the water cone is pulled up to only 3 perforation blocks.
Next, based on the results of the hydrodynamic model, we will graph the dependence of the water rate on time for different values of the permeability anisotropy. It can be seen in Figure 2.  Figure 2 shows that the time of the water breakout and the rateof its movement increase with the increasein permeability anisotropy. The shortest water breakout time and the highest water flow rate with the permeability anisotropy is equal to 0.7. The longest water breakout time and the lowest water flow rate areachieved in the case with a permeability anisotropy equal to 0.1.
Based on this study, we can conclude that vertical permeability increases in water production in gas deposits. The higher the vertical permeability, the greater is the flow rate of water from the gas well, hence the larger the volume of the water cone is.

Typical assembly of downhole equipment
Currently, it is very important to remove liquid from the bottom of a gas well. In this paper, we propose to improve and refine the existing promising technology usingan inverted pump [2,3]. This technology, as shown by the experience of the Centrilift Company, allows to effectively counter the formation of a water cone in gas fields. In this work, it is proposed to use an electric screw pump instead of a centrifugal one, since the service life of the screw pump is much longer. A typical piece of equipment is shown in Figure 3.
Let us describethe main nodes of this assembly. These are an input module for gas production, a hydro protection module, an electric motor, an input module for pumping reservoir liquid (water) into a water-saturated interval, a check valve, a packer over which the liquid accumulates, and, of course, the pumping unit, i.e., an electric screw pump . Let us pay attention to the operation principle of the entire system. Water that isaccumulated in the above-packer space is forced back into the water-saturated intervalwith an electric screw pump. Since in Western and Eastern Siberia the horizontal permeability is much higher than the vertical one, the system will not accelerate the formation of a water cone, since water will mostly be distributed in the horizontal direction, though it will also move in the vertical direction.

Method of selecting the optimal pumping aggregate
The main element of the entire system is an electric screw pump. For effective operation of the system, it is necessary to determine the optimal performance of the pumping unit undercertain conditions. To do this, atypical scheme ( Figure 4) for calculating the optimal pump ratecan be used.
where ∆ =pressure characteristic of the pump; q=optimal rate; =productivity factor; ∆ℎ =hydrostatic pressure; =reservoir pressure; 1 =downhole pressure at the level of the first perforation interval.
The pressure characteristic of the pump is determined by equation (2). The coefficients a, b, c, d arederived from a polynomial of 3 rd degree: ∆Pesp q = aq 3 + bq 2 + cq + d (2) The pressure characteristic of the pump is attached tothe screw pump passport. Figure 5 shows the pressure characteristic of the ESP5-100-1000 pump. -0,7619q + 9,4286q 2 -33,0952q + 150 -q/kp+ ρg∆h = P r -P 1 The productivity coefficient is determined from equation (4) kp =2πkh/μ d lnRe/r w (4) where =rock permeability coefficient; h=capacity of the water-saturated area of the reservoir; =dynamic viscosity of water; =radius of the power loop; =radius of the well.
, , , as well as coefficients a, b, c, and d, were used to select the optimal brand one of the 6 pump brands initially chosen, on the basis of the best result shown. The calculation results for this brand of the pump are shown in Table 2. Based on the results of calculations, it was concluded that at a permeability of 150 md, the pump of brand 4 had the best effThe other brands of pumping units showed efficiencies of 50 and 160 3 /day.

Comparison of possible feed options for pump units
In the TNavigatorprogram for hydrodynamic modeling, the analysis of production rates was performed when implementing an inverted pump with different feeds (320, 160 and 50 As it can be seen from Figure 6, the best rate is 320 3 /day. With this rate, there is a noticeable increase in gas production. Rates of 50 and 160 3 /dayare noticeably inferior in production to the best option.

Comparison of gas production without inverted pump (basic option) and
with inverted pump at 320 3 /day For this comparison, it was necessary to use the TNavigatorprogram for hydrodynamic modeling ". The results of calculationsfor two options are shown in Figure 7. Let us note that the beginning of the decline in production without the introduction of the proposed technology occurs in 2 years, and with the introduction of the technology -in 3 years. The duration of the well operation is also increased by more than 3 years.

Analysis of the economic efficiency after the introduction of the technology
The main criterion for analyzing the effectiveness of the technology implementation was chosen the NPV indicator. The main parameters included in the NPV were theprofit tax of 0.035 rubles/ 3 ; the cost of gas in the Russian Federation (this cost is routinelyaccepted bycompanies for calculating economic efficiency) of 6 rubles/ 3 ; the discount rate of 0.15; total electricity costs of 402 thousand rubles; lifting of liquid (water) 500 rubles/ 3 . The results of the NPV analysis are presented in Figure 8.

Automation of pumping unit operation
To reduce energy costs, it is planned to develop software that will monitor the operation of the pumping unit, the pressure in the well, as well as the volume of accumulated water. To create the software, studies shallbe performed on the operation of a gas well using an inverted pump in the program for hydrodynamic modeling. After processing the research results, it is necessary to identify correlations of physical dependencies, build graphs of the dependence of the rate of removal of the water cone on the power of the pumping unit, gas flow rate, reservoir productivity coefficient, etc.,as well as determine the type of optimizing function.

Prospects for the development of technology
Evaluation of the efficiency of technology showed that the introduction of an inverted electric screw pump is a promising solution. Thanks to the introduction of this technology, it is possible to increase the volume of gas produced, increase the life of the well, as well as NPV.

NVP, mln. rub
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