Introduction

A high-pressure–high-temperature (HPHT) well designates a well condition of a formation pressure gradient above 18 kPa/m and reservoir temperature greater than 150 °C. It usually accompanies deep or ultradeep wells. In recent years, China has explored and exploited these onshore deep or ultradeep gas fields in the Sichuan, Tarim, and Ordos basins (Wu et al. 2020; Zhang and Emami-Meybodi 2020a; Zhu et al. 2021). During the early production of these HPHT gas wells, wellhead pressures are often excessively high, posing a high risk for on-site operation personnel. For the flowing well stream in the tubing, both the temperature and pressure of upwards-travelling gas gradually decrease. Under the conditions of critically low temperature and high pressure, natural gas is prone to hydrate formation; hydrates can block wellbores and/or pipelines (Ping et al. 2022; Sadeq et al. 2020, 2017; Wei et al. 2021). For safe operation, the hydrate formations need to be avoided. Therefore, either the pressure needs to be reduced or the temperature of flowing gases needs to be increased (Bui et al. 2018; Gambelli and Rossi 2023; Kakitani et al. 2019; Marsetyo et al. 2023).

Downhole chokes are being used in lieu of surface heaters and methanol injection for the mitigation of gas hydrate formation in surface facilities. By moving the point of pressure and temperature reduction downhole, the Joule–Thomson (JT) effect across the choke is thermally regulated (Luo and Wu 2020; White et al. 2014). Downhole chokes are also extensively utilized to reduce wellhead pressures for high-pressured and/or ultrahigh-pressure gas wells (Jiang et al. 2015). This technique has compelling advantages compared to surface chokes. The latter requires more areas to accommodate surface manifold facilities, which often entail an accompanying heater to alleviate the hydrate formation and produce subsequent plugging problems with pipelines. A downhole choke is also a competitive choice in gas production for offshore applications, where the space is very limited to accommodate the manifolds and their corresponding auxiliaries (Bigdeli et al. 2023). In addition, it reduces the surface gathering pressure, with the intended aim of heating cooled gas downstream of chokes.

However, during the early exploitation of HPHT gas wells, the pressures downstream a choke remain high enough and result in an undesirable JT heating effect, even if a choke is moved underground. Hence, a maximum wellhead flowing pressure (Pt) must exist for an HPHT gas well for the placement of a downhole choke, ensuring a cooled downstream temperature. Moreover, deep or ultradeep wells have fairly high gas production to be economically viable. A higher gas flow rate correlated to a higher downstream temperature across a choke; this occurs to the extent that it exceeds the ambient temperature, as evidenced in the study by Li et al. (2012) and Jia et al. (2020). This is undesirable and negates the intended aim of harnessing geothermal energy. Therefore, an upper limit to gas production for HPHT gas wells also exists in the application of the downhole throttling technique.

Farzaneh-Gord et al. indicated that the GERG-2008 equation of state calculated the JT inversion curve with high accuracy and developed a novel correlation for its estimation (Farzaneh-Gord et al. 2020). Agwu et al. developed a critical review of extant models for modelling oil and gas flow rates through chokes (Agwu et al. 2022; Shao et al. 2018). Xie et al. proposed a comprehensive model for predicting the production of downhole choke wells (Xie et al. 2022). For gas flow rate prediction through wellhead chokes in gas condensate fields, robust hybrid machine learning algorithms (Abad et al. 2022) or vector machine algorithms (Nejatian et al. 2014) have been used. Moreover, as a long-established technology, the downhole throttling technique receives widespread acceptance, demonstrated by a wealth of scientific papers. Jiang et al. suggested its use in mitigating sustained casing pressure in an HPHT gas well (Jiang et al. 2015). White et al. showed its field applications and performance impact (White et al. 2014). Temperature prediction through chokes was performed for high-pressure gas/water/monoethylene glycol (MEG) mixtures (Jia et al. 2020), for HPHT gas condensates (Li et al. 2012), and in highly choked conditions (Teng et al. 2016). Multiphase choke performance prediction has also been improved (AlAjmi et al. 2015). However, to the best of our knowledge, few efforts have been reported in the literature regarding downhole throttling applicability in HPHT gas wells. In an effort to guide its utilization, the objective of this study is to set selection criteria by finding the maximum wellhead flowing pressure and gas flow rate upper limit, which are applicable for downhole throttling techniques in HPHT gas wells.

This paper, in relation to others, aims to address the following research gaps:

  • The isenthalpic performances of both dry gas and high liquid hydrocarbon (LHC) content gas condensates are separately explored, and the pressures from both JT inversion curves are between 40 and 50 MPa.

  • To utilize a downhole choke, the upper limit to the wellhead following pressure is 52.5 MPa. Otherwise, downhole throttling will exhibit an undesirable JT heating effect.

  • To be geothermally viable for downhole throttling, the daily gas production needs to be less than 14 E4 m3, as along with the preceding pressure limit.

This paper is organized as follows: First, a brief explanation is provided on the throttling process that occurs across downhole chokes. Next, the isenthalpic curves of both dry gas and high LHC content gas condensates are plotted to explore their respective isenthalpic characteristics, with temperature and pressure ranges covering field applications. Some intuitive observations are derived from both charts. Third, based on the above results, an applicability study on downhole throttling is performed. Finally, some important conclusions are drawn.

Throttling process in a nutshell

A throttling JT process is a thermodynamic process in which the enthalpy of the gas or the medium remains constant (Yarveicy et al. 2018). Enthalpy has the following defined expression (Li et al. 2012):

$$H=U+{\text{PV}}$$
(1)

During the throttling process, no work is done by or on the system (dW = 0), as opposed to the turbine machinery, and usually no heat transfer occurs from or into the system (dQ = 0). Specifically, during the expansion (throttling) process, heat is not being evolved or absorbed. Thus, the process falls into an adiabatic process; specifically, no heat exchange occurs with the surroundings. In the end, the total energy balance reduces to the following (Teng et al. 2016):

$$\Delta H=0$$
(2)

For such a specialized case, no change in the system enthalpy is achieved. Therefore, the throttling process contains an isenthalpic process. However, the throttling process cannot be isentropic; it is a fundamentally irreversible process. The characteristics of the throttling process are as follows: 1. no work transfer; 2. no heat transfer; 3. irreversible process; 4. isenthalpic process.

A throttling of the flow causes a significant reduction in pressure because a throttling device causes a local pressure loss. A throttling process can be attained simply by introducing a restriction into a line through which a gas or liquid flows. This restriction is commonly performed by means of a partially open valve or a porous plug (see Fig. 1). During a throttling or JT process, a Joule–Thomson effect occurs, and its extent is quantified by the Joule–Thomson coefficient. The Joule–Thomson coefficient \({\mu }_{J}\) is the ratio of the temperature decrease to the pressure drop and has the following definition:

$${\mu }_{J}={\left(\partial T/\partial P\right)}_{h}$$
(3)

where T is the temperature, P is the pressure, and h is the enthalpy. For natural gas at low and intermediate pressures, \({\mu }_{J}\) >0 and P1 > P2; thus, the gas is cooled (T1 > T2) as it travels in a choke.

Fig. 1
figure 1

Throttling processes in action

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Isenthalpic curves of dry gas and gas condensate

Method of experimental measurement

The experiment to perform adiabatic throttling is known as the Joule–Thomson lab (Huang and Yang 2019; Jia et al. 2020; Zhu and Okuno 2015). In the setup represented schematically in Fig. 2(left), the inlet conditions are kept unchanged at position 1, the openness of the throttling unit is adjusted, and the different downstream states for 2a, 2b, 2c, and so on are measured. The pressures and temperatures related to various outlet conditions are recorded and plotted on a T versus P diagram, as shown in Fig. 2(right). Since the upstream enthalpy is equal to the downstream enthalpy of the throttling unit, a large number of state points, such as 1, 2a, 2b, and 2c, has the same enthalpy. The line intersecting these points is thus isenthalpic. By shifting the pressure and/or temperature at position 1 and redoing the preceding experiments, another isenthalpic curve is achieved. Thus, a cluster of isenthalpic curves is created on a T–P plane.

Fig. 2
figure 2

Adiabatic throttling process (left), T–P diagram of a fluid (right)

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Figure 2 (right) shows how pressure and temperature are related for a series of isenthalpic (Joule–Thomson) expansions. For example, if we start at point 1 (P1, T1) in the figure and the gas is throttled through a restriction, the pressure and temperature follow the isenthalpic line containing point 1. If the final pressure is P2, then the final temperature will be T2, as shown by point 2 (P2, T2). Since the Joule–Thomson process is isenthalpic, the slope of each line can be represented as \({(\delta T/\delta P)}_{h}\). This quantity is referred to as the Joule–Thomson coefficient \({\mu }_{{\text{J}}}\).

Figure 2 (right) shows that \({\mu }_{{\text{J}}}\) is negative at high pressures and high temperatures. Therefore, the gas heats up as it expands under these conditions. At lower temperatures, the temperature of the gas continues to increase if an expansion occurs at high pressures. However, at lower pressures, the slope, and hence \({\mu }_{{\text{J}}}\) becomes positive; thus, the gas cools upon expansion. The intermediate between these two effects is a pressure and temperature condition where \({\mu }_{{\text{J}}}=0\), as labelled point M in Fig. 2 (right). This temperature is known as the Joule–Thomson inversion temperature TM, with the corresponding pressure PM as the inversion pressure. Its value depends on the starting pressure and temperature and the nature of the gas.

The Joule–Thomson inversion curve is the locus in the T–P plane for which \({\mu }_{J}=0\) (where the temperature is invariant upon isenthalpic expansion). Within the region bordered by the inversion curve, temperature decreases when pressure is reduced, resulting in a JT cooling effect (\({\mu }_{{\text{J}}}>0\)). However, outside of this region, the expansion will result in a JT heating effect (\({\mu }_{{\text{J}}}<0\)). This curve is important in refrigeration and liquefaction processes since the sign of the JT coefficient determines whether the temperature of a real gas rises or falls by isenthalpic expansion. The experimental measurement of the JT inversion curve needs the measurement of the volumetric or caloric properties under certain conditions; therefore, its accurate measurement is difficult (Farzaneh-Gord et al. 2020).

Method of equations of state calculation

Values of the Joule–Thomson coefficient can be obtained from equations of state. Many vigorous isenthalpic flash methods exist in the literature (Heidari et al. 2014; Huang and Yang 2019; Yarveicy et al. 2018; Zhu and Okuno 2015). Di Zhu et al. presented a robust isenthalpic flash for multiphase water-containing hydrocarbon mixtures. Desheng Huang et al. performed multiphase isenthalpic flash calculations for compound mixtures of water/solvent/hydrocarbon at high pressures and elevated temperatures. Heidari et al. (2014) developed a highly efficient method for thermal compositional simulators. In this work, the fluids examined are dry gas and high LHC content gas condensate; both are well studied, and hence, the use of commercial software to estimate their isenthalpic curves for various inlet temperatures is justified.

The multiphase flow models in the OLGA program (Bendlksen et al. 1991), a commercial software in widespread use, are utilized in this study to calculate temperatures downstream of a choke in an adiabatic setting. In the OLGA program setup shown in Fig. 3, both “P_In” and “P_Out” are the pressure nodes, with the user entering pressures for the inlet and outlet, respectively. With a flow path titled “FLOWPATH_1” that is 10 m long, a valve model on hydrovalve is placed in its middle. A self-explanatory option for temperature is selected as “ADIABATIC.” A PVT table file is created with a third party software known as Multiflash and imported into this OLGA model, the compositions of which are listed in Table 1.

Fig. 3
figure 3

OLGA program setup for the isenthalpic curve projections

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Table 1 Compositions for the dry gas and high LHC content gas condensate
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Method of OLGA software simulation

The OLGA simulator is one of the principal components in the analysis of pipeline operations and well production optimizations (Bruijnen and de Boer 2016; Ganat et al. 2017; Zhang et al. 2023; Zhou et al. 2017). OLGA is a computational program developed to emulate multiphase flow in flow lines and pipeline networks, with processing equipment included. The program solves separate continuity equations for the gas, liquid bulk and liquid droplets: two momentum equations, one for the continuous liquid and one for the combination of gas and possible liquid droplets; and one mixture energy equation that considers that both phases are at the same temperatures. The equations are solved using the finite volume method and semi-implicit time integration. Successful designs and operations of multiphase production systems rely on a detailed understanding of flow behavior. OLGA provides a solution by accurately modelling true dynamics. Its transient simulator has an additional dimension to the traditional two-phase steady-state analysis by predicting the system dynamics, such as time-varying changes in flow rates, fluid composition, temperature, and operational shifts.

From wellbore dynamics for any well configuration to pipeline networks with many types of process equipment, the simulator engine provides an accurate prediction of the key operational conditions involving transient fluid flow (Bigdeli 2021; Bigdeli et al. 2019). After the model is set up as illustrated in Fig. 3, a table data file is created with the third party software Multiflash for dry gas (see Table 1 for its compositions) and imported to OLGA through the FILES keyword. Next, the steps below are followed:

  1. (1)

    For “P_In”, the pressure node, an inlet temperature of 172 °C and inlet pressure of 98.8 MPa are entered.

  2. (2)

    For “P_Out”, another pressure node, outlet temperature of 15 °C and pressure of 48.8 MPa at their respective box on the “Model Browser” are entered.

  3. (3)

    The signs of “Ready to simulate” and a green circle on the bottom left of the main window dialog box are checked; this indicates that the model is ready to run.

  4. (4)

    After the run is complete, the menu item “Profile Plot” is selected and the variables “PT” and “TM” are selected to display.

  5. (5)

    On the resulting plot, the inputs of 98.8 MPa and 172 °C and the outputs of 48.8 MPa and 179.952 °C are selected and read.

  6. (6)

    To obtain throttling temperatures other than 48.8 MPa, step 2 is used, and the pressure is changed.

Steps 2 through 6 are redone and an isenthalpic line of 172 °C in Fig. 4 is created. To obtain other lines, such as 158, 118, 78, 58, 38, and 18 °C, separately, steps 1 through 6 are repeatedly followed. Thus, the isenthalpic curves for dry gas at various inlet temperatures are obtained. With a high LHC content gas condensate, the preceding procedures are iterated for pressures from 2.54 MPa through 98.8 MPa, spanning a wide temperature range of 18 °C to 172 °C, and Fig. 5 is attained.

Fig. 4
figure 4

Isenthalpic curves for dry gas at various inlet temperatures

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Fig. 5
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Isenthalpic curves for high LHC content gas condensate at different inlet temperatures

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In either Figs. 4 or 5, the linking maxima from each isenthalpic curve form a line of the JT inversion curve, which falls between 40 and 50 MPa for both fluids at temperature ranges of 18 to 172 °C. The JT inversion curve is defined as the locus of the points where the JT coefficient becomes zero. It separates the region of positive JT coefficients from negative coefficients (Farzaneh-Gord et al. 2020). Nichita et al. calculated two typical reservoir fluids as examples, whose inversion pressures had a range of 35–50 MPa for typical reservoir temperatures (Nichita and Leibovici 2006). The JT inversion curve is important because it determines the sign of the JT coefficient. To the right of these inversion curves, JT coefficients are negative (\({\mu }_{{\text{J}}}\)<0), which results in a JT heating effect; this means a hotter gas after the expansion of the choke. Moreover, on the left-hand side of both inversion curves, the signs of the JT coefficients are positive, exposing the gas or condensate gas to a JT cooling effect. At the locus of these inversion curves, their JT coefficients are zero. Evidently, only points traversing inversions can have an invariant temperature during throttling processes.

By analyzing both Figs. 4 and 5, the following can be observed: ① For pressures above 28.8 MPa, all isenthalpic curves from different inlet temperatures are nearly flat. This indicates that downhole throttling is inapplicable for pressures higher than 28.8 MPa. Had downhole throttling occurred at pressures above 28.8 MPa, it will encounter an increase in temperature as pressure is reduced across a choke. This can contradict the aim of exploiting the geothermal energy. ② When the inlet temperature is above a certain value, the temperatures downstream of the choke are higher than the ambient temperature at the location of the downhole choke. Therefore, downhole chokes are applicable solely for low-production gas wells. This is partly because positive JT coefficients occur in the low inlet temperature region of both charts. Furthermore, low inlet temperatures entails low gas flow rates. On the other hand, for a gas with a high enough inlet temperature, its cooled downstream temperature through a choke is still high, to the extent above ambient.

Applicability study on downhole throttling

Determination of maximum Pt

Based on preceding insights that downhole throttling is not suitable for downstream pressures higher than 28.8 MPa, the objective of this study is to find its corresponding Pt, which is also the maximum allowable wellhead pressure for economically installing downhole chokes. We make a point of effectively absorbing geothermal energy by cooled gas streams. To determine this value, the following three conventions are used:

  1. 1.

    On depth at which downhole chokes are placed, we review 69 downhole choke installations that have been deployed in our oil field since June 2011. Its seating depth scatter chart is shown in Fig. 6. Integrating it with applications in other oil fields in China, we find a preferred depth of 2500 m. By the same means, we obtain a roughly accepted wellhead flowing temperature of 28 °C on most downhole choke installations.

  2. 2.

    The allowable pressure drop that downhole chokes can endure has been widely accepted to be 35 MPa (Huiyun et al. 2020); this correlates to 30 MPa after factoring in a safety allowance of 0.85. The well site back pressure, which is also called the wellhead downstream pressure, is usually set at 10 MPa for gas gathering systems. The geothermal temperature is 65.05 °C in our oil field, corresponding to a downhole choke placement depth of 2500 m.

  3. 3.

    For the critical pressure ratio, a value of 0.546 is selected after performing a literature review (Huiyun et al. 2020; Jia et al. 2020; Naseri et al. 2016; Shao et al. 2018; Xie et al. 2022).

Fig. 6
figure 6

Scatter chart of the downhole choke depth versus the choke size in a western China field

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Assuming a choke is set at 2500 m downhole, a computing flow diagram, as illustrated in Fig. 7(left), is framed. The first step is entering an initial wellhead pressure of 80 MPa, and then, this flow chart is followed; a maximum pressure of 52.5 MPa is reached after multiple iterations. Specifically, if the wellhead flowing pressure is below this value, then a cooled gas is achieved downstream of the choke.

Fig. 7
figure 7

Flow diagram for estimating the maximum Pt (left) and the temperature profile for a wellhead flowing pressure of 52.2 MPa and gas production of 15 E4 m3/d (right)

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However, even if Pt is less than 52.5 MPa, the resulting cooled gas temperatures can still be higher than the ambient temperature of 65.05 °C if gas production is high enough. This negates our fundamental objective of having downhole throttling techniques, i.e., harnessing geothermal energy to heat chilled gas. To illustrate this phenomenon, data from Zhu Guangyou et al. are drawn on (Zhu et al. 2021), with key parameters listed in Table 2. A wellbore temperature profile is plotted in Fig. 7(right) for a wellhead flow pressure of 52.2 MPa, gas production being 15 E4 m3/d. From this chart, even if the downstream temperature is lowered somewhat, it can still stand above the ambient line. Hence, suitable gas production is needed for a cooled gas through a choke to be geothermally heated.

Table 2 Essential well parameters in use with a downhole choke
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Applicable gas production

Gas stream temperatures in the downstream chokes are reliant on both upstream pressures and temperatures and throttling pressure drops. Upstream gas stream temperatures are a function of the gas flow rate and temperature gradients where a gas well is located and its well depth. To explore the gas production applicable to the downhole throttling technique, a vertical gas well in western China, which has an ambient temperature gradient of 1.98 °C/100 m and a total vertical depth of 8100 m, was used. Other key parameters are listed in Table 2. The well stream used is dry gas, and its composition is listed in Table 1. The software utilized is commercially available and marketed as PIPESIM. In addition to a downhole choke deployed at 2500 m, a variable choke is installed at the Christmas tree, with the goal of safeguarding surface facilities in case of failures in the downhole choke. The outlet pressure is fixed at 10 MPa. To run multiple cases, other key variables are listed in Table 3, such as reservoir pressures and gas productivity indices (Kalantariasl et al. 2022; Zhang and Emami-Meybodi 2020b).

Table 3 Key variables used in the multi-case studies of the 8100 m well depth
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After entering into or choosing from an appropriate amount of data in the PIPESIM graphic user interface, the allowable pressure difference through downhole choke is maintained by varying the beam size of the chokes for either downholes or surface chokes. Then, multiple runs are performed for various reservoir pressure gradients and gas productivity indices, simulating diverse well conditions. Therefore, Fig. 8 shows the resulting data. In this chart, two flowing Pts, at 52.5 MPa and 25.8 MPa, are separately provided. In Fig. 8 (left) for flowing Pt at 52.5 MPa, the subcooling remains above zero for all daily gas productions, and especially as low as 2.0 E4 m3. This supports the results above, with a maximum wellhead flowing pressure of 52.5 MPa, as estimated from the flow diagram.

Fig. 8
figure 8

Relationship between the daily gas production and subcooling at various formation pressure gradients for an 8100 m well depth with a constant flowing Pt at 52.5 MPa (left) and at 25.8 MPa (right). The subcooling is calculated by subtracting the ambient temperature at 2500 m from the downstream temperature

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In Fig. 8 (right) for flowing Pt at 25.8 MPa, for the daily gas production below 14 E4 m3, most subcooling is less than zero. Thus, from an engineering application viewpoint, that value is the applicable upper limit in the gas production to the downhole throttling technique. The subcooling values above zero are caused by a downhole throttling pressure drop constraint of 30 MPa. This also imposes an impact on the lower end of the line with pressure gradient 1.00 MPa/100 m. For the rest of the lines in Fig. 8(right), a lower gas flow rate correlate to a larger subcooling. Specifically, a larger temperature difference between the downstream and ambient conditions provides better benefits in the application of the downhole throttling technique.

To improve the robustness of the upshots above, another HPHT gas well with a typical well configuration is set up in PIPESIM. It is differentiated from the preceding example well with a well depth of 5000 m and the other information listed in Table 4.

Table 4 Primary variables used in the multi-case studies of 5000 m well depth
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After performing multiple cases with various reservoir pressures and gas productivity indices, Fig. 9 is obtained by visualizing the resultant data.

Fig. 9
figure 9

Relationship between the daily gas production and subcooling at various formation pressure gradients for 5000 m well depth, with constant flowing Pt at 52.5 MPa (left) and at 25.8 MPa (right)

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Both charts in Fig. 9 reinforce the findings from Fig. 8, with the exception of the applicable daily gas production being 16 E4 m3. As the research target of this work is ultradeep wells, the preceding value is more desirable.

Statistical analysis of field applications

The downhole throttling technique has been deployed in a western China field for over a decade. In field applications, the maximum pressure drop across the downhole choke follows. In this work, data pairs of daily gas production and flowing Pt are shown in Fig. 10. The formation of pressure gradients, correlating to these datasets, span a range of 1.33–0.73 MPa/100 m. For this chart, both upper limits to the flowing Pt of 52.5 MPa and the daily gas production of 14 E4 m3 are verified.

Fig. 10
figure 10

Cross chart of the daily gas production versus flowing Pt

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Downhole throttling application in action

To facilitate the use of the conclusions from this work, Fig. 11 is proposed as a simple decision tree. First, production engineers are expected to determine two inputs. One is flowing Pt, preferably at daily gas production as close to 14 E4 m3 as possible. This is the flowing wellhead pressure before a downhole choke is deployed, and it is often available from well testing. The other is gas production, which is the desired gas flow rate after placing a downhole choke.

Fig. 11
figure 11

Simple decision tree for selecting the downhole throttling or surface chokes

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Discussion

This study has the following advantages and disadvantages.

Advantages: Isenthalpic lines of both dry gas and LHC content gas condensate are used to arrive at the pressure upper limit. Building on two deep gas gushers, multiple simulations are run and field data records are used to justify both upper limits of flowing Pt and gas production.

Disadvantages: The flowing upper pressure limit is based on practice; here, the allowable pressure difference through a downhole choke is 30 MPa. As technology advances, this constraint is likely to lessen. The upper gas production limit rests on a well site back pressure of 10 MPa, which is derived from the gas gathering system pressure. Since gas zones may mark major oil formations, their production needs lower well site back pressure.

Conclusions

First, a pair of T–P plots for dry gas and high liquid hydrocarbon (LHC) content gas condensates were separately calculated using commercial software. Second, a method to estimate the maximum wellhead flowing pressure (Pt) was proposed, and its exact value was determined with the application of downhole throttling. Third, based on the well data from two deep gas producers in western China, the pressure upper limit applicable to the downhole throttling technique was re-confirmed while separating the allowable maximum gas flow rate by running multiparameter modelling. Last, both upper limits were re-verified by statistical analysis of field data records. As such, the following conclusions were drawn:

  1. 1.

    The pressure upper limit for the downhole throttling technique was estimated to be 52.5 MPa. Otherwise, a hotter gas was encountered downstream of the chokes; this was indicative of a Joule–Thomson (JT) heating effect and an undesirable effect.

  2. 2.

    The pressure upper limit and the gas flow rate were important parameters. Daily gas production applicable to the downhole throttling technique was determined to be 14 E4 m3. For the low formation pressure gradients, a lower gas flow rate correlated to a better gain of the JT cooling effect on downhole throttling.

  3. 3.

    The pressures of JT inversion curves of both dry gas and high LHC content gas condensate fell between 40 and 50 MPa at temperature ranges of 18–172 °C; this had implications in refrigeration and liquefaction processes.