Gas Condensate Wells Research Articles

Analysis of the measures to prevent and elimination troubles during operation of gas and gas-condensate wells with water in their production stream in the East-Tarkosalinskoe field

Analysis of the measures to prevent and elimination troubles during operation of gas and gas-condensate wells with water in their production stream in the East-Tarkosalinskoe field

A new deliverability evaluation method of gas condensate wells in gas–liquid two-phase state

Gas well deliverability evaluation and analysis are challenging due to the frequent abnormalities of deliverability test data of gas condensate wells caused by seepage of oil and gas phases in the reservoirs. To this end, based upon the pseudo-single-phase seepage equation and the oil–gas two-phase seepage equation, a new deliverability evaluation method was established which is applicable to the following two cases when the flow of a gas well reaches the quasi-steady stage, i.e., the pseudo-single-phase stable point deliverability evaluation for the case when the formation pressure is above the dew pressure; the gas–liquid two-phase stable point deliverability evaluation for the case when the formation pressure is below the dew pressure. Using this established deliverability evaluation method, based on the basic parameters of the Yaha gas field, Tarim Basin, the IPR curves were first obtained of gas wells do not get this at the same production gas–oil ratio and at the formation pressure above and below the dew point pressure; then, according to the four condensate gas fields, such as Yaha, Tazhong I, Qianmiqiao and Dina 2, the absolute open flow (AOF) potentials of condensate gas wells under different gas–oil production ratios were calculated. Finally, through statistical analysis of the calculation results from typical wells, the following findings were obtained. This new deliverability evaluation method under the two states of condensate gas wells with quasi-single-phase and gas–liquid two-phase stable points can be used to avoid cases due to the oil–gas flow in a condensate gas well which has remained unresolved by the classical deliverability evaluation methods. Also, with the increase of gas–oil ratios in gas condensate wells, a variable discrepancy is gradually reduced in AOF potentials calculated respectively by the quasi-single-phase and gas–liquid two-phase stable point deliverability evaluation equations. For the condensate gas wells with high condensate content and low condensate gas production rates, the AOF potentials calculated by the gas–liquid two-phase stable point deliverability equation is more appropriate and reliable compared with that obtained by classical methods.

IR Spectrometric Determination of Weight Fractions of Oil and Gas Condensate in Products Oil and Gas Condensate Wells

A method of the IR spectrometric determination of weight fractions of oil and gas condensate in the production of oil and gas condensate wells is proposed. The features of infrared spectra of the integrated absorbance of hydrocarbon solutions, recorded using a Fourier-transform IR spectrometer and an IKAR-3 scanning IR spectrometer, are discussed.

Application of proxy-based MCMC and EDFM to history match a shale gas condensate well

History matching is an important process for uncertainty quantification of reservoir performance. Hundreds of reservoir simulation cases, or more, are typically required to sample the posterior probability density function of the uncertain parameters. The process is extremely challenging for shale reservoirs due to large uncertainties including reservoir heterogeneity, wide range of permeability, gas desorption, and fracture properties. Direct application of stimulated rock volume or dual continuum model fails to capture fracture connectivity and fracture conductivity that dominate the fluid transport in most shale developments. Embedding discrete fractures in reservoir simulation model is thus a preferable method to attain more realistic reservoir behavior. However, the option of using local grid refinement to embed the fractures is computationally expensive as well as intrusive to a reservoir model. Even more challenging is generating a huge set of fracture-embedded reservoir cases during the history matching process. Nevertheless, recent developments in a methodology called Embedded Discrete Fracture Model (EDFM) have successfully overcome the computational complexity to include discrete fractures in reservoir simulations. We demonstrate the implementation of the assisted history matching workflow coupled with EDFM to history match a real field case of shale gas condensate reservoir in Duvernay Shale, Canada. In the workflow, the EDFM preprocessor is fully coupled with a commercial reservoir simulator and proxy-based Markov chain Monte Carlo (MCMC) algorithm. Moreover, to further reduce the computational cost, the single-fractured submodel is used to represent the full reservoir model for this case study. Using the proposed assisted history matching workflow and the appropriate submodel enables efficient and successful uncertainty quantification of this shale play.

Characteristics of scale deposition in gas-condensate wells

Formulation of the problem. The article deals with one of many possible complications that may occur in the process of gas and gas-condensate wells operation. In fact, scale deposits can be observed in wells at all stages of field development. Scale deposition inside the tubing has a negative impact on hydrocarbons production. This causes the decline of gas production rate. The major factor of scale deposits formation is overtreatment of water solution with different salts and the effect of field hydrogeology. Thus, special methods are used in practice to prevent scale deposition and combat this complication.The purpose of the article. To define the causes of scale deposition, the detailed analysis of well operation should be performed that will help to take the appropriate prevention measures. Methods. The authors’ own achievements as well as the research results of domestic and foreign investigators made the methodical basis for the article.Results. The production data of the wells from different fields have provided the information about scale deposition. Many of the described ways of combating and eliminating scale deposits are expensive, their use causes well downtime and production decline. Therefore, it has been proposed to take easy-to-use preventive measures.Scientific novelty and practical significance. During investigation of the production researches results and calculations the specialists of UkrNDIgas proposed to classify the wells with reduced production capacities within the field into groups and categories according to the degree of total salinity of formation water. It has been proposed to control the process of scale deposition by the results of water analysis, taken from the wells. Each well has the set limit values of salinity.Based on the operation analysis of wells in different fields, the calculated predicted results of scale deposition in wells according to the existing procedures and their comparison with the factual data from production fields, the specialists of the institute have developed the efficient complex multi-faceted measures.

Gas Condensate Wells Simulation to Optimize Well Flow Performance Using Tubing Equations Coupled with Inflow-Performance-Relation (IPR) Curve

Wells performance is evaluated by IPR curves that show the relationship between bottomhole pressure and inflow rate. This curve and its outcome equation can be applied for production schedule and maintenance management of well and reservoir. But, the measuring of bottomhole pressure to approach these curves needs much time and high expenses and also running special tools in wells. In these operations, the probability of catastrophic failure such as well damage or well complete lost may exist. However, these difficulties in offshore wells like production platform in the South Pars gas field that are installed tens kilometers far from lands are harder than any places. Therefore, nowadays by considering these difficulties, there is a high tendency for using wellhead test data that are very inexpensive as well as these data are less accurate than in well data. Moreover, pressure drop due to the existence of gas condensate in well fluid causes the flow regime to be more complicated. Wide researches have been applied to two-phase flow pressure drop in the wellbore and a lot of equations are considered. Anyhow, these equations and their accuracy should be studied in each special case. In this study that is on the south Pars gas condensate field wells, widespread of equations are utilized for calculation of pressure drop in the tubing and they are applied for tubing performance curve as well. In the south pars field wells, the well data of bottomhole pressure are not being measured during production. In this paper, we try to calculate bottomhole pressure by using PIPESIM software and simulating reservoir fluid and wellbore. For calculating this pressure, with the combination of effective conditions, the best equation of flow regime in that well will be selected. Eventually, by simulation of the reservoir fluid, different parameters like in well performance and proper tubing size is calculated.

Восстановление и повышение производительности газовых и газоконденсатных скважин физико-химическими методами

Восстановление и повышение производительности газовых и газоконденсатных скважин физико-химическими методами

Selection of the rational periodic operation mode for gas and gas-condensate wells

The article describes the periodic operation of gas and gas-condensate wells at the final stage of field development. The operation of such wells is characterized by complications in the process of hydrocarbons production. The authors have proposed the ways to automate the periodic operation of wells by means of installing the control system at the inlet gas line of gas treatment unit. In case of pressure rise or drop at the inlet of gas treatment unit the control system regulates bringing wells into production or their shutdown. The introduction of the proposed method will help to control the well production conditions.

A semi-analytical solution to compositional flow in liquid-rich gas plays

Liquid-rich gas (LRG) reservoirs can exhibit complex phase and flow behavior due to gas condensation and re-vaporization and differences in phase mobilities that results in compositional variations inside the system. To date, the analysis of composition variation in liquid-rich wells has been largely limited to numerical modeling. This work uses a similarity-based analytical approach to study the in situ and flowing fluid composition of gas condensate wells producing under infinite-acting linear and radial flow under constant bottomhole pressure (BHP) condition. We propose a semi-analytical solution to the governing partial differential equations (PDEs) written in terms a compositional fluid formulation for multiphase (gas, oil and water) flow system in liquid rich gas reservoirs. The proposed solution is developed using similarity-theory (i.e. Boltzmann’s transformation) and is validated by both analytical development and numerical simulation data. Using proposed method, pressure and overall composition are solved simultaneously and rigorously without any kind of simplification or approximation, from which producing fluid composition can be fully predicted prior to the availability of field production data. Moreover, results corroborate that when LRG wells are producing under 1D linear regime – a commonly-observed flow condition for hydraulically-fractured horizontal wells completed in unconventional formations – and against a constant BHP constraint, the producing wellbore fluid composition remains constant as long as the system remains infinite acting, leading to a constant producing gas-oil ratio (GOR). For radial flow, however, producing wells team composition and GOR are shown to be time-dependent before stabilization at a nearly-constant value.

A new fast approach for well production prediction in gas-condensate reservoirs

Prediction of gas-condensate well production is significant for sensible decision making for the reservoir development plan, infrastructure investment, and produced gas and condensate sales contract. Typically, time-consuming numerical simulation with fine grids or local grid refinement around the well is implemented in order to capture the effects of condensate blockage and predict gas-condensate well deliverability. In addition, in the commencement of the reservoir lifetime, the numerical simulation predicts erroneous results due to high uncertainty in reservoir data. A simple analytical model can estimate gas-condensate well production reasonable with a limited number of input data. On the other hand, uncertainty studies require repetitious usage of the analytical calculation. Therefore, a faster and more practical method for calculation of gas-condensates well flow rate has a precious value. In this paper, a fast analytical method is introduced for prediction of gas and condensate production profiles based on the two-phase pseudo-pressure integral and material balance equation. Proposed analytical model in contrast to previous ones, predicts the exact plateau time. As the result, it does not need iteration in each reservoir pressure step to compute the relevant flowing bottom-hole pressure during the constant gas production period. The model is expanded to take into account the high-velocity phenomena in near the wellbore region. It is also extended for the first time for different well geometries including vertical, deviated, horizontal, and hydraulic-fractured wells. Additionally, the analytical model is validated using fine grid numerical simulation for a wide range of rock and fluid properties. The developed analytical model can be used as a fast engineering tool for evaluating the uncertainty in well and reservoir data to choose the best strategy for reservoir development.

English

Sand production is a major concern during petroleum exploitation from unconsolidated sandstone reservoirs. For efficient management, sanding predictive tools are necessary. While several models have been developed for sanding in oil reservoirs, gas and gas condensate reservoirs have received little attention because of the widespread belief that such reservoirs are not prone to sanding. This study utilized erosional failure mechanism concept to formulate a model for predicting the volume of sand produced from gas and gas condensate reservoirs. The model showed that sanding in weakly consolidated gas reservoirs is influenced by flow rate, fluid density and viscosity, density of sand, particle size and borehole radius. Key words: Sand production, mathematical model, gas well, gas-condensate wells, cavity arch radius

Impacts of Condensate Blockage and the Effectiveness of Technical Solutions to Improve Well Deliverability in Gas Condensate Wells in Vietnam

Impacts of Condensate Blockage and the Effectiveness of Technical Solutions to Improve Well Deliverability in Gas Condensate Wells in Vietnam

DETERMINATION OF THE GAS STREAM FLOW AT CONDUCTING HYDRODYNAMIC INVESTIGATION OF WELLS. PART 3

The paper presents a method for calculating the gas stream flow rate during well tests of gas and gas condensate wells using a diaphragm gauge of critical flow. The above method compensates the disadvantages of the described in the scientific and technical literature gas stream flow rate calculation methods during its flow through the diaphragm in the critical regime. For the proposed method are presented the testing results on gas and gas condensate wells of the north of the Tyumen region.

Application of a water based nanofluid for wettability alteration of sandstone reservoir rocks to preferentially gas wetting condition

Condensate and water banking around gas condensate wells result in vital well deliverability issues. Wettability alteration of near wellbore region to gas wetting condition is known to be the most novel and the only permanent method, to improve condensate well productivity. In this work, a water based nanofluid is used to change the wettability of sandstone reservoir rocks from strongly liquid wetting to intermediate gas wetting condition. Static contact angle measurements demonstrated significant increase of liquid phase contact angle as a result of chemical treatment with SurfaPore M nanofluid. The characteristics of SurfaPore M adsorption on sandstone rock are quantified through kinetic and equilibrium adsorption studies, as well as the stability of the used chemical against NaCl brine salinity in ambient condition,. Air/liquid spontaneous imbibition tests along with core flooding experiments were utilized to study the effect of wettability on two phase fluid flow through porous media. It has been concluded that kinetic behavior of SurfaPore M-sandstone system conforms pseudo-second order, while Freundlich isotherm matches the equilibrium adsorption data; these results eventuate multilayer chemisorption of NPs on sandstone surface. The results of spontaneous imbibition tests showed remarkable decrease of the ultimate amount of imbibed liquid by factors of 0.09 and 0.17 for n-decane and water, respectively. Also, the results of water injection experiments demonstrated the increase in liquid phase mobility by a factor of 3.2 as a result of surface modifiers in high permeability sandstone core plug. Furthermore, it is concluded that the utilized nanofluid is better to be used in high permeability sandstone rocks. The results of this research pave the way for possible future field applications of SurfaPore M nanofluid chemical in gas condensate reservoirs to alleviate production difficulties.

A simplified model for churn and annular flow regimes in small- and large-diameter pipes

This paper presents an improved model for gas-liquid two-phase flow in the churn and annular flow regimes for small- and large-diameters in vertical and near-vertical pipes. Many investigators consider churn flow to be the least understood flow regime in upward gas-liquid flows in vertical pipes. Nevertheless, this flow regime occurs commonly in several applications in the oil and gas industry, such as: gas-lift operations, production of gas-condensate wells, and two-phase flows with high gas-liquid-ratio in general. Additionally, the accuracy of two-phase flow models for large pipe diameters, irrespective of flow regimes, is still questionable. Only a limited number of studies can be found in the open literature that validates two-phase flow models for pipe diameters larger than 0.203m (8in.).The model developed in this study proposes a modification to an approach originally proposed in previous studies for pipe diameters smaller than 0.0508m (2in.). These modifications have proven to improve accuracy in the prediction of pressure gradient and liquid holdup for small and large pipe diameters under churn and annular flow conditions. The absolute average error in the prediction of experimental pressure gradient decreases from 155% (for the original model) to 36% (for the modified version). This study validates the proposed model with field and laboratory experimental data from several different studies from the literature, in terms of pressure-gradient and liquid holdup results, for pipe diameters ranging from 0.0318 to 0.279m (1.25–11in.), pressures from 1 to 613bara (14.6–8900 psia), and fluids types such as air-water and oil-natural gas systems.This study also compares its results with other widely accepted models in the commercial packages. When compared to field and laboratory data, the simulation results show that this new model has an overall better performance compared to other models widely used in the oil and gas industry.

A regression model for estimation of dew point pressure from down-hole fluid analyzer data

Accurate knowledge of dew point pressure is important in understanding and managing gas condensate reservoirs. Without a correct assessment of dew point pressure, an accurate description of phase changes and phase behavior cannot be achieved. Numerous models for predicting gas condensate dew point pressure from surface fluid data have been proposed in the literature. Some of these require knowledge of the full composition of the reservoir fluid (based on laboratory experiments), while others only need field parameters that are relatively easy to obtain. This paper presents a new model for predicting the dew point pressure from down-hole fluid analyzer data. Such data are now measured (usually in real time) while obtaining down-hole fluid samples. The new model predictions give a quick estimation of dew point pressure for wet gas and gas condensate reservoirs. Since it relies only on down-hole measured data, the model provides an estimate of dew point pressure without the need for laboratory analyses. During down-hole fluid sampling, the model can be used to ensure whether the sample is still in single phase, or whether the dew point was crossed during the sampling operation. An early estimate of dew point pressure is also valuable in designing further tests for gas condensate wells. The new model, constructed using a fluid database of nearly 700 gas condensate samples, was devised using sophisticated statistical/machine learning methods, and attained a mean absolute relative error value of 2% for predicting the logarithm of pressure. In comparison with other dew point estimation models (that use surface fluid data), the chosen model was found to attain a similar level of accuracy when tested on samples not used in the model building phase.

Investigating the factor influencing the flow behavior and performance of condensate gas reservoirs

Well productivity is an important issue in the development of most low and medium- permeability gas-condensate reservoirs. However, accurate forecasts of productivity can be difficult because of the need to understand and account for the complex processes that occur in the near-well region. When the well pressure falls below the dew-point, a region of high liquid saturation builds up around the well, impairing the flow of gas and reducing the well productivity. It is essential to take account of this condensate-blockage effect when calculating well productivity. Most of the pressure drop in a gas condensate well occurs close to the well walls. Because of the increase in pressure drop and the increase in flow rate, two additional phenomena get involved in gas flow control: The effect of positive coupling (due to increased capillary number) and the effect of inertia (due to non-Darcy flow). In many gas-condensate wells, the final result of these two parameters is improving well productivity, reducing the impairment caused by condensate blockage. Another phenomenon that can take place in high temperature gas reservoir is water vaporization. Pressure drop near well wall causes molar content of water in gas-phase to increase, therefore connate water starts to vaporize near the well walls. This change in connate water saturation near the well wall can influence well productivity by changing saturation of fluids near well walls. The effect of water vaporization on well productivity of gas and gas - condensate reservoirs are investigated by considering a single well one dimensional radial model simulation. The simulations show that water vaporization increases productivity of well by increasing gas saturation and relative permeability near the well walls and improving the mobility of gas; and this effect is stronger in rich gas condensate reservoir than the lean ones.

INVESTIGATING THE EFFECTS OF WATER VAPORIZATION ON THE PRODUCTION OF GAS CONDENSATE RESERVOIRS

Well productivity is an important issue in the development of most low and mediumpermeability gas-condensate reservoirs. However, accurate forecasts of productivity can be difficult because of the need to understand and account for the complex processes that occur in the near-well region. When the well pressure falls below the dew-point, a region of high liquid saturation builds up around the well, impairing the flow of gas and reducing the well productivity. It is essential to take account of this condensate-blockage effect when calculating well productivity. Most of the pressure drop in a gas condensate well occurs close to the well walls. Because of the increase in pressure drop and the increase in flow rate, two additional phenomena get involved in gas flow control: The effect of positive coupling (due to increased capillary number) and the effect of inertia (due to non-Darcy flow). In many gas-condensate wells, the final result of these two parameters is improving well productivity, reducing the impairment caused by condensate blockage. Another phenomenon that can take place in high temperature gas reservoir is water vaporization. Pressure drop near well wall causes molar content of water in gas-phase to increase, therefore connate water starts to vaporize near the well walls. This change in connate water saturation near the well wall can influence well productivity by changing saturation of fluids near well walls. The effect of water vaporization on well productivity of gas and gas - condensate reservoirs are investigated by considering a single well one dimensional radial model simulation. The simulations show that water vaporization increases productivity of well by increasing gas saturation and relative permeability near the well walls and improving the mobility of gas; and this effect is stronger in rich gas condensate reservoir than the lean ones. Keywords: Well, Gas, Pressure Drop, Vapor pressure of water

Investigating the effects of water vaporization on the production of gas condensate reservoirs

Well productivity is an important issue in the development of most low and mediumpermeability gas-condensate reservoirs. However, accurate forecasts of productivity can be difficult because of the need to understand and account for the complex processes that occur in the near-well region. When the well pressure falls below the dew-point, a region of high liquid saturation builds up around the well, impairing the flow of gas and reducing the well productivity. It is essential to take account of this condensate-blockage effect when calculating well productivity. Most of the pressure drop in a gas condensate well occurs close to the well walls. Because of the increase in pressure drop and the increase in flow rate, two additional phenomena get involved in gas flow control: The effect of positive coupling (due to increased capillary number) and the effect of inertia (due to non-Darcy flow). In many gas-condensate wells, the final result of these two parameters is improving well productivity, reducing the impairment caused by condensate blockage. Another phenomenon that can take place in high temperature gas reservoir is water vaporization.Pressure drop near well wall causes molar content of water in gas-phase to increase, therefore connate water starts to vaporize near the well walls. This change in connate water saturation near the well wall can influence well productivity by changing saturation of fluids near well walls. The effect of water vaporization on well productivity of gas and gas - condensate reservoirs are investigated by considering a single well one dimensional radial model simulation. The simulations show that water vaporization increases productivity of well by increasing gas saturation and relative permeability near the well walls and improving the mobility of gas; and this effect is stronger in rich gas condensate reservoir than the lean ones.Keywords: Well, Gas, Pressure Drop, Vapor pressure of water

Simulation-based optimization of gas condensate wells to mitigate the heavy hydrocarbon condensation through supercritical CO2 injection

−In gas-condensate reservoirs suffering from condensate banking, the supercritical CO2 injection process is regarded as one of the most effective technical remedies to reduce the liquid formation and achieve higher quality gas production. With proper well configuration and spacing designs, the injected CO2 can decrease the loss of heavy components effectively. The main goal of this study was to minimize the loss of heavy components during CO2 injection by implementing a proper well configuration. The results show that the integration of pressure maintenance and chemical reactions, including reduced viscosity and interfacial tension, improves the C7+ component recovery by 42.9, 49.4, and 49.3% for the base five-spot, inverted five-spot, and line drive cases, respectively. The total recovery is the highest for the line drive pattern with a recovery factor of 72.7%. The results also indicate that there is a critical length maximizing the effect of gas cycling.