During the exploitation of a gas reservoir containing water, the scaling problem is usually affecting the gas production in gas wells. Although the scale formation that occurs during oil field development is quite different from the aforementioned gas field, the phase behavior plays a pivotal role in the formation of inorganic scale in gas field development. It is a well-known fact that there is no device that can directly measure the extent of scaling formation in a high-temperature and high-pressure reservoir. At the same time, the commonly applied scaling prediction method does not account for the fluid phase state. In this work, the scaling condition and alteration in controlling parameters in an actual gas reservoir were studied by self-developed high-temperature and high-pressure formation fluid equipments. From thermodynamics, a new scaling prediction model for the multiphase equilibrium of gas reservoir fluid is proposed that considers gas, liquid hydrocarbon, formation water, and inorganic salt scale. For the complexity of the direct solution for a phase equilibrium system with a chemical reaction, a simplified method for calculating the phase change and chemical equilibrium in a multiphase equilibrium system with chemical reactions is proposed based on the conservation of materials and the unification of the physical properties of components. The results show that the predicted value of the model was consistent with the experimental results. The new scaling prediction model considered the influence of the phase state which can accurately predict the change of the fluid phase state and the amount of inorganic salt scaling of actual gas reservoir fluids under the condition of multiphase equilibrium. Moreover, the average deviation of the prediction results is about 3%. The predicted scaling amount of the model without considering the effect of phase change is significantly lower than that of the experimental results. More specifically, the average deviation is around 30%. With the decrease of gas reservoir pressure, formation water evaporation intensifies under the influence of the oil and gas phase state, which leads to the increase of the formation water ion concentration when the influence of the fluid phase change is not considered. Then, the prediction of the inorganic salt scaling will be significantly lower.
In the exploration of gas reservoirs containing water, a scaling problem is usually created which severely affects the production of gas wells [
The alteration in temperature and pressure is not the only factor governing the scaling, but the dissolution and precipitation of oil and gas components and the evaporation of water can also severely influence the inorganic scale formation. Due to the involvement of mass transfer and energy conversation (Peyghambarzadeh et al. [
In this research, a set of experimental devices which has taken the phase change of oil, gas, and water into account was developed to understand the scaling law of the fluid in the actual gas reservoir. Based on thermodynamics, a multiphase equilibrium scaling prediction model of gas (natural gas)-liquid (hydrocarbon)-liquid (formation water)-solid (inorganic salt) was proposed that takes into account the change of fluid phase state and the reaction of inorganic salt scaling, and the fluid phase state transformation and scaling law of the actual gas reservoir were investigated.
In this research, a set of experimental devices was developed that was able to simultaneously test the phase change of fluid in gas reservoirs under high-temperature and high-pressure conditions and the amount of formation water ion and scaling. The schematic diagram of the device is shown in Figure
Scaling test device under the high temperature and pressure.
The gas, oil, and water samples obtained from the BS8 well in the Qianmiqiao gas reservoir were used in the experiment. The sample composition was shown in Tables
Composition of BS8 formation water.
Ion | Content (mg/l) | Ion | Content (mg/l) |
---|---|---|---|
Na+ | Cl- | ||
K+ | 279.7 | SO42- | 269.0 |
Ca2+ | 113.5 | HCO3- | 463.6 |
Mg2+ | 9.024 | NO3- | 145.5 |
Sr2+ | 17.83 | Total | |
pH | 6.8 (dimensionless) |
Composition of BS8 natural gas.
Ion | CO2 | N2 | C1 | C2 | C3 | IC4 | NC4 | IC5 | NC5 | C6 |
---|---|---|---|---|---|---|---|---|---|---|
Percentage (%) | 8.73 | 0.56 | 80.22 | 6.75 | 2.14 | 0.57 | 0.55 | 0.27 | 0.19 | 0.02 |
Composition of BS8 condensate oil.
Ion | CO2 | N2 | C1 | C2 | C3 | IC4 | NC4 | IC5 | NC5 | C6 | C7+ |
---|---|---|---|---|---|---|---|---|---|---|---|
Percentage (%) | 0.77 | 0.07 | 5.12 | 2.52 | 1.88 | 3.84 | 2.6 | 5.82 | 4.22 | 13.58 | 59.58 |
In the experiment, the formation fluid was first compounded according to the production data and pumped to the intermediate container by an automatic pump. Then, the fluid was heated and pressurized under constant temperature and pressure in a cylinder to restore the formation conditions. It was then held for 24 hours to ensure that the phase changes of the oil, gas, and water in the formation fluid and the scaling reaction proceeded sufficiently and achieved equilibrium. The volume of natural gas saturated with water at the top of the PVT cylinder and the volume of formation water that the gas dissolved were then obtained. Finally, the condensate gas of a small amount of saturated water at the upper part of the PVT tube was discharged, and the natural gas and the saturated water content were flashed to the standard condition and measured. The PVT cylinder was set for half an hour; then, the formation water of natural gas dissolved in the lower part was discharged and measured. The ion detection analyzer was used to measure the concentration of each ion in the formation water. According to the change of ionic concentration and formation water physical property before and after the experiment, the scaling amount of the formation fluid was determined.
Beginning from the initial formation conditions, the high-temperature and high-pressure phase analysis and scaling test of the BS8 well fluid were carried out under five pressure and three temperature conditions, respectively. The results of the experiment are shown in Figures
Gas and water dissolved content change curves of BS8 formation fluid.
BS8 reservoir water’s salinity and ion content change curves with pressure (171.4°C).
Scaling quantity curve of BS8 formation fluid.
Contrast curves of the scaling amount of BS8’s degassed formation water and the actual formation fluid.
Under the experimental condition, the ions such as Na+ and K+ were not involved in the scaling reaction, and the concentration change was mainly due to the change of water physical properties caused by high temperature and high pressure. Taking the concentration of Na+ as a standard, the change of scale ions in formation water before and after the experiment can be calculated by the test data as follows:
According to the change of ion concentration, the type of scaling and the amount of scaling of the inorganic salt in the formation fluid under the standard condition were determined. The amount of scaling under the experimental conditions was also obtained according to the change of the volume coefficient and density of the formation water. As shown in Figure
At present, as the formation pressure was 11.5 MPa and the formation temperature was 117.4°C, more CaCO3 scales and a small amount of SrSO4 scales appeared in the formation fluid. In addition, the amount of fouling increased with the decrease of experimental pressure and increased with the rise of temperature.
In order to study the influence of fluid phase change on the scaling of inorganic salts, scaling tests were carried out under the same conditions using BS8 degassed formation water. As indicated in Figure
The inorganic salt scaling in a gas reservoir was a complex multiphase system consisting of natural gas, liquid hydrocarbons, formation water, and various solid inorganic salt scales with chemical reactions. Under equilibrium conditions, the system should meet the conditions of material conservation and thermodynamic equilibrium. The system consists of
Only the phase equilibrium exists, and the total molar conservation of the components is observed.
For the electrolyte solution with ions, the charge conservation condition should also be satisfied.
For a given temperature and pressure, the system should meet the minimum thermodynamic equilibrium condition of Gibbs free energy.
The entire gas reservoir multiphase system with inorganic salt scaling was divided into two interactive processes: the first process is the natural gas and liquid hydrocarbon phase change between formation water electrolyte solutions and the other process is the chemical reaction of each ion and inorganic salt in formation water. Further analysis was made on the representation method of the composition of the multiphase system and the calculation method of the thermodynamic equilibrium of the two processes.
In order to clearly express the composition of the phases in the system, the material representation method of phase equilibrium was adopted. Under certain equilibrium conditions,
Unlike the conventional phase equilibrium problem, the molar composition of the components in a multiphase system may change continuously due to the chemical reaction. Under different conditions, the total number of moles of the system and the molar composition of each component are shown as follows:
The fugacity of each component in each phase should be equal when the equilibrium of gas, liquid, and liquid was achieved:
In the formula,
According to the Gibbs free energy minimum principle and the calculation method of the chemical potential of the solution components, the equilibrium condition in the chemical reaction is as follows:
In the field practice, the Oddo-Tomson Saturation Index was commonly used to obtain the equilibrium conditions for inorganic salt scaling:
The condition of scaling was judged by the saturation index of the inorganic salt
According to the balance of materials and the equilibrium conditions, the scaling prediction method considering multiphase equilibria in electrolyte solution was deduced. Under equilibrium conditions, the relationship between the amount of inorganic salt scale and solution ion concentration is as follows:
In this research, the entire gas reservoir multiphase system with inorganic salt scaling was divided into two interactive processes: the first process is the natural gas and liquid hydrocarbon phase change between formation water electrolyte solutions and the other process is the chemical reaction of each ion and inorganic salt in formation water. Except for the H2O and CO2, the other components have only undergone one change process. The problem can be simplified greatly if the phase equilibrium state equation and the chemical reaction calculation method are adopted on the basis of the conservation of material. Meanwhile, the ratio of gas and water in a gas reservoir was very large, and the molar content of ionic components in the whole system was relatively small. The change of the electrolyte solution concentration caused by the phase state change between gas, oil, and water has a greater influence on the scaling of inorganic salt, while the physical property change caused by inorganic salt scaling on the gas, liquid, and liquid phase states is relatively weaker. Therefore, the phase equilibrium of gas, liquid, and liquid in the entire multiphase system is solved firstly, then the chemical equilibrium in the formation water is calculated under the condition of phase equilibrium. Finally, the final condition based on the conservation of materials and the unity of physical properties is determined. The specific solution steps are as follows (Figure
Flow chart of gas-liquid-liquid-solid multiphase equilibrium scale prediction.
We input the pressure (
The composition of formation water determined by flash calculation is used to predict the tendency of inorganic salt scaling. If
If the formation water is not in the chemical equilibrium state, the initial scale of each inorganic salt and the composition of formation water are calculated by equations (
After eliminating the inorganic salt scale, the three-phase flash evaporation was used to determine the molar content (
We combine the mole content of each phase in the gas, liquid, and liquid three-phase fluid calculated by Step
We calculate the scaling tendency of the solution after flashing calculation in Step
We combine the formation water that was still in a nonchemical equilibrium state with the inorganic salt scale. Then, the formation water that was still in a nonchemical equilibrium state is combined with the inorganic salt scale. Steps
The prediction of inorganic salt scaling in an electrolyte solution is an important part of the Multiphase Equilibrium Prediction model. The accuracy of this part is of great significance to the comprehensive prediction of formation fluid. Based on the data of formation water and injected water in the Qianmiqiao reservoir, the scaling of formation water and injected water mixtures is predicted by using the model established above. Afterwards, the model outcomes were compared with the experimental data and the predicted values of the Oddo-Tomson model, respectively. In the simulation, the pressure and temperature were 10 MPa and 171.4°C, respectively, and the composition of formation water is shown in Table
Composition of injection water.
Ion | Content (mg/l) | Ion | Content (mg/l) |
---|---|---|---|
Na+ | 13400 | Cl- | 19840 |
K+ | 310 | SO42- | 2470 |
Ca2+ | 620 | HCO3- | 132 |
Mg2+ | 15.42 | NO3- | 754 |
Sr2+ | 0 |
By comparing the experimental value of electrolyte solution scaling, the predicted value was calculated by applying the Oddo-Tomson model as shown in Table
Comparative analysis of scale amount in electrolyte solution.
Mass fraction (%) | Scale amount (mg/l) | Error (%) | |||
---|---|---|---|---|---|
Experimental results | Prediction results under phase equilibrium | Prediction results without phase equilibrium | Model without phase equilibrium | Model with phase equilibrium | |
0 | 0.00 | 0.00 | 0.00 | 0.00 | 0.00 |
10 | 360.02 | 370.24 | 370.54 | 2.70 | 2.70 |
20 | 330.54 | 320.21 | 340.74 | 3.00 | 3.00 |
30 | 260.17 | 250.54 | 250.35 | 3.80 | 3.80 |
40 | 210.32 | 220.87 | 210.21 | 4.70 | 0.00 |
50 | 160.28 | 140.03 | 150.32 | 12.50 | 6.20 |
60 | 130.14 | 110.58 | 120.33 | 15.30 | 7.60 |
70 | 100.70 | 80.31 | 90.91 | 20.00 | 10.00 |
80 | 70.21 | 60.68 | 75.35 | 14.20 | 7.10 |
90 | 40.36 | 50.25 | 45.23 | 25.00 | 12.50 |
100 | 0.00 | 0.00 | 0.00 | 0.00 | 0.00 |
The proposed model for predicting multiphase equilibrium fouling and the prediction model of formation water scaling based on the Oddo-Tomson saturation index were applied to predict the scale of the fluid in the BS8 well fluid under experimental conditions, and the predicted results were compared with the experimental result to verify the reliability of the proposed model. From the results (Table
Comparative analysis of the predicted scale amount of BS8 reservoir fluid and the experiment data.
Temperature (°C) | Pressure (MPa) | Scale amount (mg/l) | Error (%) | |||
---|---|---|---|---|---|---|
Experimental results | Prediction results under phase equilibrium | Prediction results without phase equilibrium | Model with phase equilibrium | Model without phase equilibrium | ||
171.4 | 43.57 | 1.36 | 1.42 | 0.85 | 4.44 | 67.27 |
30 | 8.98 | 8.83 | 7.90 | 1.69 | 10.38 | |
20 | 14.52 | 13.89 | 12.71 | 4.35 | 8.12 | |
11.5 | 88.59 | 90.18 | 70.49 | 1.79 | 22.23 | |
5 | 281.67 | 292.98 | 216.10 | 4.01 | 27.29 | |
155 | 30 | 1.24 | 1.22 | 0.38 | 1.62 | 67.31 |
20 | 6.70 | 6.72 | 5.67 | 0.18 | 15.63 | |
11.5 | 12.36 | 11.65 | 9.91 | 5.73 | 14.07 | |
5 | 144.32 | 141.93 | 95.39 | 1.66 | 32.24 | |
135 | 5 | 8.13 | 7.71 | 2.36 | 5.25 | 65.74 |
The multiphase equilibrium scaling model was used to predict the inorganic salt scaling and fluid phase changes in the BS8 wellbore and formation. At present, the wellhead pressure was 3 MPa and the temperature was 60°C. The other production data were described above. The prediction results are shown in Figures
Saturated water content distribution curve of BS8 formation gas.
Balanced scaling amount in BS8 formation water.
Phase distribution of BS8 fluid in formation.
Scaling points of BS8 formation fluid.
A set of experimental devices for testing the amount of inorganic salt scales in formation fluids under high-temperature and high-pressure conditions was developed. The high-temperature and high-pressure phase analysis and scaling test of the actual gas reservoir fluid in the BS8 well were carried out by the devices. The experimental results demonstrated that with the decrease of formation pressure, the dissolved gas volume of formation water decreased, while the saturated water content in natural gas increased. In addition, two kinds of CaCO3 scale and SrSO4 scale were generated in the gas reservoir fluid under experimental conditions. The amount of fouling increased with the decrease of pressure and increased with the increase of temperature. The change of scaling with the pressure and temperature in the actual gas reservoir is more obvious than the degassing formation water A new model for predicting the scale of inorganic salts in gas-liquid-liquid-solid multiphase equilibria is established. According to the composition characteristics of gas reservoir fluid, the chemical equilibrium calculation of the inorganic salt scaling under the condition of gas, liquid, and liquid equilibrium is put forward. The method can simplify the complicated problem of directly solving the phase equilibrium system of a chemical reaction The new multiphase equilibrium scaling model was proposed which can accurately predict the amount of inorganic salt scale in the actual gas reservoir fluid. The prediction results were close to the experimental data with an average deviation of 3%. In comparison, the prediction results of models that did not consider phase changes were significantly lower than the experimental data, and the average deviation was about 30%. To accurately predict the amount of scaling in gas reservoir fluids, it is necessary to consider the changes in the phase state of the fluid Through the prediction of the scaling in the BS8 well, much CaCO3 and a little of SrSO4 scale were generated in the current formation under equilibrium conditions. With the decrease of the formation pressure, the amount of scale increased from the formation to the near-wellbore area, and the total inorganic salt scale at the bottom of the well reached 133.8 mg/l
Pressure, volume, and temperature relationship.
The data for the paper can be accessed through the following link:
The authors declare that they have no conflicts of interest.
The authors express their appreciation to the National Science and Technology Major Project (No. 2009ZX05009), a project of the China Natural Science Foundation (50774091), for financially supporting this work. The authors also express their appreciation to the support from the China Postdoctoral Science Foundation (2018M631765). At the same time, we would like to thank Nasir Khan for his help in the process of writing the manuscript and Wang Yong and Jianshe Feng for the samples they provided during the experiment.