An algorithm for determining the mass flow rate and dryness of a thermal agent at the mouth of steam injection wells in specialized software

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Introduction
The K field uses a thermal method of influencing the formation – injection of saturated water vapor. A distinctive feature of the produced thermal agent is the presence of both a vaporous and a liquid phase in the general flow.
Since the beginning of the implementation of steam–thermal exposure technology and to the present time, the determination of steam consumption in the steam injection wells is carried out by calculation: the total volume of the steam-thermal agent produced is distributed among the steam injection wells in proportion to the ratio of the reservoir conductivity index in the corresponding wells, which leads to significant errors, since hydraulic losses in steam pipelines are not taken into account, as well as changes caused by constant regulation of the agent's expenses by means of regulation.
Incorrect accounting of steam injection into steam injection wells leads to an incorrect assessment of the technical and economic efficiency of the reacting cells, which, in turn, reduces the effectiveness of the measures taken to regulate steam pumping and makes it difficult to make timely decisions on the expediency of a targeted transition to alternative less costly impact technologies.
The issue of ensuring accurate accounting of steam consumption in the wells of the K field is under the control of the Central Commission for exploration and development of minerals of the Republic of Kazakhstan. By the protocol decision of the Central Commission No. 8 dated 06/25/2018 on the issues of technologies for the development of the K field, the commission recommended that downhole accounting of steam consumption be provided for effective control of the possibility of regulating its injection.
In order to implement protocol decisions, from 2020 to the present, attempts have been made to search for equipment for measuring the steam-thermal agent in the steam injection wells with the appropriate pilot tests. So from 2020 to 2023 several stages of testing steam flowmeters from different manufacturers were carried out, however, the results obtained did not meet the accepted criteria for the success of pilot tests, and also did not agree with the calculation data on the thermal balance, taking into account the 2-phase structure of the transported and injected agent: wet saturated steam is a mixture of dry saturated steam with a suspended fine liquid located in with steam in thermodynamic and kinetic equilibrium.
Measuring the flow rate of a steam–water system is a very difficult task.
Modern devices for determining steam consumption based on measuring the alternating flow of a two-phase medium (steam and water), having a methodological error of more than 10%, cannot provide the necessary accuracy and reliability of measurements, due to the fact that wet steam is characterized by spatial, thermal variability and, accordingly, a change in the ratio of the phases contained in the flow during transportation, that is, dynamic errors associated with changes in the degree of steam dryness are not taken into account [1, 2].
As you can see, the multidimensionality of the task of controlling the flow of wet steam, which is not solved by known means of control, is associated with the following problems [3]:
1. The difficulty of determining the degree of dryness of wet saturated steam in the flow.
2. The density of steam increases with increasing humidity, while the dependence of the density of wet steam on pressure at different degrees of dryness is ambiguous.
3. As the humidity of the steam increases, the specific enthalpy of saturated steam decreases.
4. The gas and liquid phases of wet saturated steam move at different speeds and occupy a variable equivalent cross-sectional area of the pipeline.
Due to the above difficulties, the work on creating an effective system for measuring the degree of steam dryness in a certain time mode is extremely relevant, and the search for solutions to this problem is still being considered within the framework of research [4-7].
Thus, taking into account the fact that at the moment there is no unambiguously practical solution to the problem of accounting for heat and mass of wet steam flows by manufacturers, it became necessary to develop an alternative option that would correctly solve the problem of determining the degree of dryness of steam by calculation.
In order to perform a priori estimates of the accounting of steam injected into the formation (counting at the mouth of a separate steam injection well the wet steam coming through the steam pipeline from one source – a steam generator), an algorithm is proposed for constructing a mathematical model for simulating a two-phase steam-water flow in specialized software [8].
The proposed solution makes it possible to calculate the degree of dryness of wet steam, which will provide an alternative option for reliably determining the mass flow rate and dryness of wet steam at the mouth of each well in order to control accounting and ensure more accurate regulation of steam-thermal exposure processes.

Features of the above-ground steam pumping system at the K field
Since 2009, steam generating units of the MPGU and SPGU type with a capacity of 11 tons/hour, 18 tons/hour and 23 tons/hour have been used at the K field. The nominal operating parameters of the steam of these installations range from Rrab = 6-17.2 MPa, Trab = 276-353 °C.
The purpose of MPGU, SPGU is to produce wet saturated steam for steam-thermal effects on productive oil reservoirs in order to increase the recovery coefficient and intensify oil production at the field. The generated thermal agent is transported to the steam injection wells through mobile and stationary steam pipelines.
All steam generators with a capacity of 11 tons/hour (MPGU-11t) and part of the steam generators with a capacity of 18 tons/hour (SPGU-18t) are connected to the steam injection wells directly through mobile steam pipeline systems, thus making up injection systems individual for these steam generators with a binding of 3-5 steam injection wells. Currently, 5 units of MPGU-11 and 13 units of SPGU-18 are involved in individual systems, a total of 101 steam injection wells are connected (29% of the existing steam injection well stock).
The main injection of the thermal agent to the steam injection wells is carried out through a single stationary steam pipeline system, into which all 16 units are connected. Steam generators with a capacity of 23 tons/hour (MPGU-23t) and 6 units of SPGU-18t, in total 71% of the existing steam injection well stock (248 units) are connected to this system.
Theoretical foundations for determining steam quality
The determination of steam quality is related to the phase transitions of water with changes in temperature, pressure and enthalpy. Figure 1 conventionally shows the path of changing the phases of water from the reservoir to the borehole in the PH and PT diagrams. Away from the boiling conditions at a certain pressure, a change in the enthalpy of water leads to a change in temperature (line a,b). However, being brought to boiling conditions (line b-c in the PH diagram) at constant pressure and temperature, water consumes heat for the gradual evaporation of liquid into steam – there is no abrupt transition from one phase to another. Only when the phase transition is completed does the enthalpy affect the temperature rise again (line c,d). Further along the path of steam from the source to the drain with lower pressure, the water loses heat, again passes into the two-phase region (line d,e,f,g).

Figure 1 – Theoretical foundations of steam quality assessment
The main purpose of steam injection is to deliver to the reservoir as much steam as possible, rather than liquid, or higher–quality steam. Steam quality is the ratio of the mass of the fraction of steam to the sum of the masses of the fractions of steam and liquid or to the total mass of water in a certain volume (1).

Steam quality=(m (steam))/(m (steam+liquid))=(p(steam)*S(steam))/(p(steam)*S(steam)+p(liquid)*S(liquid) ) (1)
where m is the mass;
p is the density;
S is the saturation of the fluid.

Description of the determination of the flow rate and dryness of the thermal agent at the mouth of steam injection wells using specialized software
To determine the flow rate and dryness of the thermal agent at the mouth of steam injection wells, specialized software was used, which is a simulator for modeling multiphase flow. The correlation "Hagedorn & Brown" for vertical flow and "Beggs&Brill revised" for horizontal flow was used for calculations.
To simulate steam injection in specialized software, 3 main stages are performed.
1) The corresponding keywords are written in the Engine keywords of the HOME – Simulation settings – Advanced dialog box.
a) If only the well is analyzed, then Steam is registered in the Single branch keywords block. Superheated steam is set only with this keyword. If the steam quality is known at the mouth, then it is indicated through Inlet Quality = 0.9, for example. The user-defined temperature will be ignored in this case.
b) If the network is analyzed, including drains or wells, then setup comp=steam is written in the Network keywords (bottom) block. Superheated steam is set only with this keyword. If the steam quality is known at the source, then it is indicated via source name = 'Source' quality = 0.9, for example, where 'Source' is the name of the source. The user-defined temperature will be ignored in this case.
2) Pure water is set using the "Black oil" model.
3) If the flow rate is determined in boundary conditions, then it must be massive (mass rate instead of liquid rate).
The productivity index of the injection well is set for the liquid.
The assessment of gas quality after calculations is carried out through the parameter "Flowing gas mass fraction" (Mass fraction of gas flow) in the tab "Profile results" (Fig. 2).

Figure 2 – Assessment of gas quality by the parameter "Flowing gas mass fraction"
The analysis of steam injection into the system is displayed in the Report on the "Output summary" tab (Fig. 3).

Figure 3 is a report on steam injection on the Output summary tab
The steam quality is calculated using a separate ASTEM liquid modeling package based on the international tables of steam properties IAPWS-IF97.

Adaptation of the steam pipeline network
Several functions can be used in the software to adapt the steam pipeline network.
First, it is worth noting data managers such as HOME – Flowline manager and HOME – Simulation settings – Heat transfer (the "Use local" option, working with the "U value multiplier" variable).
Secondly, the approach of automated finding of the diameter of the wellhead fitting with a given flow limit deserves attention. To run the optimization calculation, the following is performed:
1) It is necessary to deactivate all fittings before injection wells (Fig. 4).

Figure 4 – Deactivation of the Choke object in Network schematic
2) Instead, install fittings in wellhead facilities at the wellhead level with a diameter larger than the tubing diameter (Fig. 5).

Figure 5 – Installation of the wellhead fitting on the Downhole equipment tab
3) Mass flow limits are set for the required wells in Network simulation on the Rate constraints tab. For these wells, the specified boundary condition for the calculation will be pressure.
4) After setting all the boundary conditions, Network simulation is started for calculation. The selected diameters of the fittings are shown on the Output summary tab (Fig. 6).

Figure 6 – Output of the optimal diameter of the fitting to the report on the Output summary tab
Thirdly, if there are problems with the convergence of the calculation and there are calculated data on it, you can visualize the vectors on the GIS map. On the "FORMAT" tab, "Results gradients" is activated and the analyzed parameter is selected, for example, "Pressure gradient" (Fig. 7). By the spread of values, you can identify the problem area.
 
Figure 7 – Calculation results for pressure gradient in GIS map

Conditions and assumptions when performing calculations
The following factors may affect the error of the results:
- salt deposition in the coil of the steam generator, as well as in steam pipelines;
- the correctness of the measured wellhead pressure, temperature and diameter of the fitting used;
- different condition of the sections of the steam pipeline, and as a result, different roughness, as well as an internal conditional passage. The calculation uses the average roughness index and the standard value of the conditional passage.

Conclusions
1. To date, it has not been possible to select equipment that allows correctly registering the 2-phase flow of steam-thermal agent injected into wells, characteristic of the conditions of the K field.
2. In order to improve the accuracy of accounting, an algorithm has been developed for calculating the volume of injection into the at the mouth of steam injection wells using specialized software. This solution has been approved by the mineral developer for use in the field in order to account for the mass flow of steam through wells.

 

 

About the authors

Murat Usenovich Yerlepessov

Филиал ТОО «КМГ Инжиниринг» «КазНИПИмунайгаз»

Email: m.yerlepessov@kmge.kz

эксперт Службы системы сбора, транспортировки и подготовки продукции

Kazakhstan, 130000, Казахстан, г. Актау, 35 микрорайон, здание 6/1

Abay Almatayevich Yermekov

Филиал ТОО «КМГ Инжиниринг» «КазНИПИмунайгаз»

Email: A.Yermekov@kmge.kz

руководитель Службы системы сбора, транспортировки и подготовки продукции 

Kazakhstan, 130000, Казахстан, г. Актау, 35 микрорайон, здание 6/1

Bakzat Kurbanbayuly Sansyzbayev

Филиал ТОО «КМГ Инжиниринг» «КазНИПИмунайгаз»

Email: B.Sansyzbayev@kmge.kz

директор Департамента техники и технологии добычи нефти и газа

Kazakhstan, 130000, Казахстан, г. Актау, 35 микрорайон, здание 6/1

Sain Kubeysinovich Amirov

Филиал ТОО "КМГ Инжиниринг" "КазНИПИмунайгаз"

Author for correspondence.
Email: s.amirov@kmge.kz

ведущий инженер Службы системы сбора, транспортировки и подготовки продукции Департамента техники и технологии добычи нефти и газа

Kazakhstan, 130000, Казахстан, г. Актау, 35 микрорайон, здание 6/1

References

Supplementary files