Gas Condensate Wells Research Articles

SPECIFICS OF KILLING THE WELLS WITH A LEAKY PRODUCTION STRING

In this paper a method is presented for gas and gas condensate wells killing in the complicated conditions, that is in the conditions of abnormally low reservoir pressures and with presence of casing string leaks.

Optimization of methods for liquid loading prediction in deep condensate gas wells

Liquid loading is a serious problem in hydrocarbon production from gas wells in the Yakela-Dalaoba deep condensate gas reservoir. The applicability of frequently-used methods for predicting liquid loading still needs to be demonstrated. For this purpose, the applicabilities of critical flow rate methods and the kinetic energy factor method are evaluated and optimized. The fundamental principles of each method for predicting liquid loading and differences among them are discussed. Different distributions of the critical flow rate and surface tension along the wellbore are considered in order to improve original critical flow rate models. For the Yakela-Dalaoba gas reservoir, the modified pseudo single-phase coupling model used for calculating the pressure and temperature distribution in high gas-liquid ratio wellbores is established, and methods suitable for calculating the pressure and temperature distribution in low gas-liquid ratio wellbores are optimized through error analysis. Results show that the modified pseudo single-phase coupling model is suitable for calculating the pressure and temperature distribution in high gas-liquid ratio wells, while Hagedorn-Brown's method and Hasan's method are suitable for low gas-liquid ratio wells. The modified critical flow rate models increase precision of liquid loading prediction compared to original models. The modified Li's model and the kinetic energy factor method which sets threshold value as 6 are of highest precision. Both of them are suitable for predicting liquid loading of gas wells in the Yakela-Dalaoba deep condensate gas reservoir.

The effect of gas-condensate reservoir depletion stages on gas injection and the importance of the aerosol state of fluids in this process

As one of the primary techniques for enhanced oil recovery, the gas injection method has been investigated widely. However, introducing “dry gas” into a gas-condensate reservoir is more than miscible flooding that maintains reservoir pressure and improves oil displacement. This method is associated with complex thermodynamic processes or phase transitions, such as the re-vaporization of heavy hydrocarbon ends and connate water, the reduction of the condensate/gas ratio and retrograde dew point (RDP) pressure, etc. In this paper, a laboratory study was conducted to estimate the effectiveness of the gas injection process during gas-condensate reservoir development. Specific laboratory equipment was constructed to conduct an experimental investigation by modelling the gas injection and reservoir depletion process.Detailed analysis of experimental investigations suggests the gas injection process might be more effective when the “reservoir” pressure is below the initial RDP pressure of the fluid. Thermodynamically, this pressure stage could be conducive for gas injection, by decreasing the condensate/gas ratio, re-vaporizing the liquid phase that dropped out and maintaining the system in a single gas phase.To further examine the process of the liquid or fog formation phase in the gas-condensate mixture, the fluid was investigated as a colloidal structure. Theoretical findings confirm that the fog condition is a well-matched feature of gas-condensate fluids with the properties of aerosol-colloidal systems. The correlation between fog up (FU), RDP pressures and temperature was investigated experimentally. The rationale for increasing the difference between the FU and RDP pressures with the increase of temperature and other physical and thermodynamic properties of gas-condensate systems is explained according to the fundamentals of colloidal systems.Based on these obtained results, conclusions were reached about the physical nature of the condensation under reservoir conditions. The results show that condensation in the reservoir condition can occur when the pressure in the interval creates the formation of liquid phase micro-embryos or aerosols. Thus, the fluid condenses due to surface forces between the sub-micron-sized condensate particles and the rock granules. This phenomenon can cause condensate blockage or condensate banking in the early stage of reservoir development when even the reservoir pressure is greater than the RDP pressure identified in the PVT cell. These results were used to explain the dynamic processes occurring within and influencing the operating characteristics of the gas-condensate wells. Because these colloidal features of fluid can play a significant role in reservoir development, we recommended considering these aspects when planning gas injection methods.

A semi-analytical method for forecasting wells completed in low permeability, undersaturated CBM reservoirs

Exploration and development of coalbed methane (CBM) reservoirs is ongoing in the Asia Pacific region, with low permeability, undersaturated coals being the target in some areas. Horizontal wells are typically required to produce low permeability CBM reservoirs at commercial rates, and may experience a period of single-phase (water) transient flow, followed by a transition to two-phase (water + gas) transient flow. Wells exhibiting this behavior are particularly difficult to model analytically, yet simple analytical and semi-analytical tools are desirable for making quick, but reasonably accurate forecasts. The purpose of this work is to therefore provide a new forecasting methodology for low permeability, undersaturated CBM wells.The new method for forecasting CBM wells introduced in this work is based on the concept of a dynamic drainage area (DDA), recently adapted to forecast tight black oil and gas condensate wells exhibiting two-phase flow. A critical advancement provided in the current work is modeling the transition from single-phase flow of water to two-phase flow of gas and water during the transient linear flow period, which was not attempted for the black oil/gas condensate cases. Above desorption pressure, material balance, performed on the dynamic drainage area to determine average pressure in the distance of investigation, is combined with the linear flow productivity index equation to forecast water production at each time step. For two-phase flow below desorption pressure, the two-phase version of the linear productivity equation and material balance equations for water and gas are solved iteratively for pressure, saturation and fluid production rate within the DDA. The gas material balance equation accounts for desorption effects. In order to calculate the DDA at each time step, the linear flow distance of investigation equation is used. Importantly, using the DDA method, variable operating conditions (flowing pressures) may be accounted for, which is critical for CBM wells during early stages of production.The new semi-analytical DDA model is used to history-match production data from an actual horizontal well completed in a low permeability, undersaturated, western Canadian CBM reservoir. Further, the match is compared to that obtained from rigorous numerical simulation. The history-match of the field data is reasonable with the new model and comparable to numerical simulation. The new model is however easier to setup and less data-intensive than numerical simulation, providing a practical alternative to CBM reservoir engineers who are responsible for generating a large number of forecasts.

PHASE BEHAVIOR OF GAS-CONDENSATE FLUIDS DURING WELL TESTING

Hydrodynamic studies in gas-condensate wells allow determining the features of fluids flow in the gas condensate reservoir by build-up curves. A variation in the shape of the build-up curve may reflect a behavior of fluids in the reservoir, that is the nature of the fluids motion in porous media. The possibility of identification of characteristics of the combined liquid and gas filtration zone by build-up curves, as well as the radius of the zone of gas-condensate blockage is shown. Based on the examples of the log-log build-up graph in Venezuelan and Russian fields the exis-tence of the characteristic shape part on the build-up curves was demonstrated, evidencing the retrograde processes occurring in the reservoir.

A new correlation for prediction of sub-critical two-phase flow pressure drop through large-sized wellhead chokes

Unacceptable errors resulted from utilizing the current correlations for investigating the behavior of sub-critical two-phase flow regime through wellhead chokes of south Iranian gas condensate reservoirs led us toward establishing a new Gilbert-type correlation capable of fitting the production data with minimum errors. The proposed model, which is a modification of Nasriani and Kalantariasl model, is able to predict the high flow rates of gas condensate wells under sub-critical conditions particularly in case of large choke sizes. In order to validate the new correlation, Genetic Algorithm and non-linear regression analysis methods are implemented to sixty seven production datasets of fifteen wells with large wellhead choke sizes (40/64–192/64 inch) gathered from 10 different fields. Then the proposed correlation in addition to two other models (1.Osman and Dokla 2. Nasriani and Kalantariasl) are conducted to each choke size to investigate the applicability of the new formula in comparison with the existing ones. Moreover, in order to evaluate the new model in other field data, 39 data points gathered from gas-condensate wells of Fars province of Iran are exposed to the proposed model, and the two other models. Finally, the main form of the new correlation is applied to dataset of each choke size.The results indicate that the non-linear regression technique is more accurate than Genetic algorithm in fitting the data to the proposed method. Furthermore, the new correlation has the minimum errors in comparison to other methods in both investigated areas. Finally, according to statistical error analysis for each choke size, the ability of the proposed correlation to predict gas flow rates of fluids passing through the wellhead chokes of gas-condensate wells under sub-critical conditions is found to be highly improved when applied to individual choke sizes.

DISTINCTIVE FEATURES OF HYDRODYNAMIC INVESTIGATION OF GAS-CONDENSATE WELLS

An equation is proposed for constructing a theoretical pressure build-up curve, which takes into account the effect of the well storage capacity, skin effect and presence of condensate in the bottomhole zone. A method was developed to determine the pressure variation during the gas-condensate well inflow and pressure build-up test, that reflects the effects of condensate dropout and retrograde transition to the gaseous phase.

Production forecasting of gas condensate well considering fluid phase behavior in the reservoir and wellbore

Retrograde condensation occurs when the reservoir pressure falls below the dew point pressure in gas condensate reservoirs. Complex fluid phase behavior in the reservoir and the wellbore makes it challenging to predict the productivity of gas condensate wells. To date, the gas rate in the deliverability equation of gas well is assumed the gas rate at surface condition converted from that at the reservoir condition by using the volume factor. However, because of the complex fluid phase behavior in gas condensate wells, the gas rate at the reservoir condition cannot be directly changed to that at surface condition by using volume factor. Hence, the development of a new analytical model to accurately calculate the productivity of gas condensate wells is still required and necessary.In this work, we propose a new deliverability equation of gas condensate wells with a consideration of fluid phase behavior in both the reservoir and the wellbore. Also, several pseudo-pressure functions for different condensate distribution and flow models are examined systematically; these include the model before condensation, the model after condensation, but without condensate flow, the model after condensation and with condensate flow, and the model after re-vaporization. Two synthetic numerical simulation cases and two field case studies are performed to validate these deliverability equations for gas condensate wells.Results show that the phase behavior of gas condensate fluid in the wellbore plays a significant role in the deliverability evaluation and in the forecasting of gas condensate wells. If neglecting its effect on the deliverability, gas and condensate production rates could not be accurately predicted. The data from the proposed model have good agreement with the simulation and field production data of wells in Yakela Gas Condensate Reservoir and Yaha Gas Condensate Reservoir in China. If the conventional deliverability equation neglecting the effect of phase behavior in the wellbore was used, the predicted gas production will be higher than the actual value; even 50% higher than the actual value at high flow rates. Through these case studies, it can be concluded that the effect of condensate-gas phase behavior in the wellbore cannot be ignored in the deliverability equation for gas condensate wells.This work can provide a more accurate method of forecasting the gas and condensate production for condensate gas reservoirs and also guide optimization of single well production rate and gas recovery rate for gas condensate reservoirs.

History-matching and forecasting tight/shale gas condensate wells using combined analytical, semi-analytical, and empirical methods

The primary focus of the majority of current, and foreseeable, natural gas drilling within North America is low-permeability liquid-rich gas and gas condensate reservoirs, where the liquid fraction is now a major source of revenue. Development of these liquid-rich resources is aided by the use of multi-fractured horizontal wells (MFHWs), and is at an early stage; further research is required to appropriately manage the resource for optimal hydrocarbon recovery.The appropriate forecasting methodologies to apply to these tight liquid-rich plays are a focus of current research. While numerical simulation is the most rigorous forecasting methodology, practitioners have turned to simple analytical and empirical methods because of their ease-of-use and requirement of less data. However, these analytical and empirical approaches have limitations that limit their applicability for unconventional resevoirs with complex reservoir, hydraulic fracture and fluid properties.In this study, the workflow of Clarkson (2013b) is applied to address the limitations of existing empirical and analytical methods for forecasting MFHWs producing from liquid-rich tight gas/shale. The workflow calls for constraint of analytical models by linking inputs to rate-transient analysis-derived reservoir and hydraulic fracture properties, and constraining empirical model forecasts to be consistent with analytical model forecasts. In order to address the range in reservoir/fracture properties observed in shales, a suite of analytical models is proposed. Similarly, a suite of empirical methods is used, and the models yielding the most accurate matches to the analytical models are selected for forecasting. Lastly, in order to bridge the gap between analytical and empirical methods, the semi-analytical method introduced by Clarkson and Qanbari (2015), which has as its basis the contacted gas-in-place calculations of Agarwal (2010), is also used for forecasting.An important contribution of this work is the demonstration of the applicability of the analytical and semi-analytical models used in this work for tight gas/shale gas condensate MFHWs exhibiting multi-phase flow in the reservoir. As demonstrated in this study using simulation cases, constant condensate gas ratios can occur for tight/shale gas condensate wells exhibiting transient linear flow and flowing at near constant flowing bottomhole pressure, even for relatively rich gas cases, rendering the single-phase forecasting methods useful for forecasting gas and condensate phases. The accuracy of these methods is tested using simulated cases, and practicality of the workflow demonstrated using an actual field example of a liquid-rich shale MFHW.This study will be of interest to those petroleum engineers who are faced with forecasting a large number of liquid-rich shale wells, and desire methods that can be simply applied to constrain forecasts and improve accuracy.

Preparation of the modified limestone possessing higher permeability of gas well based on fluorinated silica: Effect of catalyst

Abstract During natural gas production from gas condensate reservoirs, due to drops in bottom hole pressure below the dew point, liquids drop out and form condensate blockage which results in significant loss of gas and condensate productivity. A new method for stimulating gas–condensate wells is changing the rock wettability in near well-bore regions by chemical treatments. The aim of this study was to employ two comparative methods of chemical treatments for altering the rock wettability from strong liquid-wetting to intermediate gas-wetting. First the surface of rocks was modified by using sol–gel process under acid- and/or base-catalyzed conditions. Then the effects of two different chemical treatments were examined by various experimental tests such as Fourier transform infrared (FTIR), thermogravimetric analyses (TGA), electron dispersive analysis of X-ray (EDX) and scanning electron microscopy (SEM) followed by static contact angle, coreflood test and porosity measurements. The results showed that, such methods could alter the wettability significantly. It was noticed that there were some differences in the experimental results related to sol–gel structure. Compared to a base-catalyzed process which showed higher contact angle value, an acid-catalyzed process tended to produce more linear branched-polymeric networks with fewer cross-linkages and could penetrate into the limestone core easier. The final evaluation of the coatings in terms of their effectiveness by coreflood test showed that the improvement factors were 0.78 and 0.56 for the acid- and base-catalyzed treatments, respectively.

Choke Performance in High-rate Gas Condensate Wells Under Subcritical Flow Condition

Flow through a surface choke can be described as either critical or subcritical. Most of the correlations available to petroleum engineers are for critical flow but in a lot of high rate gas/condensate wells subcritical flow occurs in large choke sizes. Field data of 15 high rate wells producing from 10 gas condensate reservoirs located in Iran were used to extend two main approaches for high rate wells: a plotting technique proposed by Al-Attar to describe the subcritical flow behavior of gas condensates through wellhead chokes and a general Gilbert-type formula obtained by nonlinear regression of data points for high rate gas condensate wells. The present study extends the work of Al-Attar for high rate gas condensate wells flowing through different large choke sizes between 40/64 and 192/64 in. under subcritical flow conditions, in order to develop individual empirical correlations to be applied to predict gas flow rates under a wide range of flow conditions usually encountered during the flow of gas condensates through wellhead chokes in high rate wells .Also, a new Gilbert-type correlation was generated for high rate Iranian gas condensate wells using nonlinear regression based on the same data points. A comparison between these two approaches is done with five different errors parameters. According to five different errors analysis, the results of gas flow rates calculated by the general formula were compared with those calculated by the individual choke size formulae, and the latter were found to be more accurate. The results of this study could be considered in the design and implementation of deliverability tests, pressure transient tests, well control, and long-term well production of high rate gas condensates wells.

Impact of Gas–Condensate Composition and Interfacial Tension on Oil-Repellency Strength of Wettability Modifiers

Productivity of gas–condensate wells can significantly be declined as the condensate bank evolves around the wellbore. Wettability alteration of formation minerals from strongly liquid-wet to intermediate gas-wet conditions using liquid-repellent fluorinated chemicals has shown promising results to mitigate such liquid-blockage issues. This paper, for the first time, presents the results of unique contact angle measurements conducted on the treated carbonate substrates using synthetic gas–condensate fluids. The impact of hydrocarbon composition and interfacial tension (IFT) on the condensate wetting tendency was investigated using various binary and multi-component mixtures at ambient temperature. A high-pressure high-temperature (HPHT) drop shape analysis setup was customized to perform the static contact angle tests. The generality of the new findings from these measurements was also confirmed using dynamic unsteady-state flow tests. The results demonstrated that the wetting tendency of the condensate is significantly decreased as IFT increases and/or the hydrocarbon composition becomes heavier. The C1–nC4 condensate drop, for instance, completely wetted out the treated surface at both low- and high-IFT limits of 1 and 10 mN/m, whereas the C1–nC10 sample resulted in contact angles of 30° and 65° at similar IFT conditions, respectively. The oil-repellency strength of the fluorochemical was also evaluated at high temperatures of 50 and 100 °C with promising results. In this paper, the initial investigations on the impact of surface roughness on the solid surface wettability was carried out, demonstrating the positive impact of surface roughness on increasing the desired level of oil repellency achieved after the wettability alteration. The new findings from this work provide important guidelines in design and application of wettability modifiers for gas–condensate reservoirs.

The Effect of Water Vaporization on the Well Productivity of Gas Condensate Reservoirs

Well productivity is a crucial concern in predicting the performance of many gas condensate reservoirs. Accurate forecasting of gas-condensate well productivity usually requires fine-grid simulation to model the formation of the liquid bank and to account for high-velocity phenomena and changes in relative permeability at high capillary numbers. At early stages of production, the pressure drop in the near-wellbore region builds up the molar content of water in gas. This, in turn, results in water vaporization, and hence a drop in the connate water saturation. When water vaporization occurs, pores that were formerly filled by connate water now becomes occupied by gas and condensate only. This causes a change in gas and condensate saturations near the wellbore that can affect the well productivity. No lucid numerical simulation approach considering this effect is suggested in the literature. The authors investigated the effects of water vaporization on the near-wellbore region by compositional simulator of GEM. Enhancement of gas well productivity is observed.

Wettability alteration in gas-condensate carbonate reservoir using anionic fluorinated treatment

During gas production from gas condensate reservoirs, as the bottom hole pressure drops below the dew point pressure, the liquids drop out and form condensate banking resulting in significant loss of gas and condensate productivity. A new method for stimulating gas-condensate wells, is changing the rock wettability in near well-bore regions by chemical treatments. In this study, a new chemical treatment was developed to alter the wettability of carbonate rocks from water-wet to intermediate gas-wet in order to enhance gas relative permeability. The treatment involves the use of an anionic fluoro-surfactant mixture with an optimized concentration and a solvent. Contact angle and spontaneous imbibition experiments were run to measure the wettability alterations. Scanning electron microscopy (SEM), energy dispersive X-ray spectroscopy (EDAX) and adsorption isotherms were also performed to monitor the amounts of surfactant solutions which were adsorbed on the rock surface. The increase in gas relative permeability was quantified by comparing the permeability before and after chemical treatments. The contact angles were increased and water and oil imbibitions were reduced significantly after the treatments. Finally, core flood tests revealed that the optimized treatment could enhance the gas relative permeability by a factor of 1.7 which demonstrated the ability in wettability alteration at reservoir conditions.

A New Method To Predict the Performance of Gas-Condensate Reservoirs

Summary Gas-condensate reservoirs differ from dry-gas reservoirs. The understanding of phase and fluid flow-behavior relationships is essential if we want to make accurate engineering computations for gas-condensate systems. Condensate dropout occurs in the reservoir as the pressure falls below the dewpoint, resulting in significant gas-phase production decreases. The goal of this study is to understand the multiphase-flow behavior in gas-condensate reservoirs and, in particular, to focus on estimating gas-condensate-well deliverability. Our new method analytically generates the inflow-performance-relationship (IPR) curves of gas-condensate wells by incorporating the effect of condensate banking as the pressure near the wellbore drops below the dewpoint. The only information needed to generate the IPR is the rock relative permeability data and a constant-composition-expansion (CCE) experiment. We have developed a concept of critical oil saturation near the wellbore by simulating both lean and rich condensate reservoirs and have observed that the loss in productivity caused by condensate accumulation can be closely tied to critical saturation. We are able to reasonably estimate re-evaporation of liquid accumulation by knowing the CCE data. We validated our new method by comparing our analytical results with fine-scale-radial-simulation-model results. We demonstrated that our analytical tool can predict the IPR curve as a function of reservoir pressure. We also developed a method for generating an IPR curve with field data and demonstrated its application with field data. The method is easy to use and can be implemented quickly. Another advantage of this method is that it does not require the knowledge of accurate production data including the varying condensate/gas ratio (CGR).

How to Evaluate and Predict the Deliverability Change of Gas Condensate Wells

Condensate liquids retrograde below the dew point pressure and diminish gas relative permeability and thus reduce the deliverability of gas condensate wells. The deliverability varies due to the changes of gas effective permeability and other parameters; however, the present deliverability testing methods were not applicable to gas condensate wells because those methods were all based on the assumption that the formation properties such as permeability and fluid properties were constant. A new testing method for gas condensate wells is proposed in this work, by which the variable coefficient deliverability equation can be obtained. Case study shows that the variable coefficient deliverability equation obtained from the proposed deliverability testing method can represent changes of formation properties and fluid properties, thus the deliverability of gas condensate wells can be accurately evaluated and predicted by this testing method.

Study of Fluid Phase Behavior and Pressure Calculation Methods of a Condensate Gas Well

To date, researchers are still using the method used for conventional gas wells to calculate the wellbore flowing pressure of condensate gas wells, while the calculating accuracy cannot meet the demands of performance analysis and production management. From the analysis of wellbore phase behavior transition in the production process, combined with wellbore temperature distribution change, the pressure calculation model is established based on gas-liquid equilibrium calculation and solved with the four-point implicit difference scheme. The calculated result agrees well with the actual situation and can solve the problem that the pressure gauge could neither be put in the middle part of layer nor operate normally, in order to save a great deal of manpower and material resources.

Deliverability Prediction of Gas Condensate Wells Based on Statistics

The deliverability of gas condensate well can be calculated by using the modified deliverability equation of dry gas well and the pseudopressure deliverability equation. The modified deliverability equation of dry gas well, without considering the effect of condensate accumulation on the gas flow, results in a relatively large error; the practical application of the pseudopressure deliverability equation is not widespread because of the complex in calculating process of the pseudopressure function. The gas relative permeability and pressure is correlated based on the statistics of gas condensate wells, and an accurate and convenient deliverability equation of gas condensate well is derived. The results of case studies verify that the deliverability equation of gas condensate wells proposed is more appropriate to predict the production of the gas condensate wells.

Inhibited Gas Stimulation To Mitigate Condensate Banking and Maximize Recovery in Cupiagua Field

Summary Condensate banking has been identified as one of the most potentially damaging mechanisms affecting well productivity in Cupiagua Field. This gas-condensate giant field has reached an average recovery factor of 42%, with recovery values of approximately 60% in some layers of field. The mitigation of condensate banking phenomena, among the other important damaging mechanisms currently interacting along the entire productivity zones, has been one of the most relevant stimulation practices in the development strategy. The mitigation of condensate banking led to optimization of common stimulation practices to recover the productivity of gas-condensate wells. Massive hydraulic fracturing and matrix stimulation with inhibited diesel and alcohol have been the most common practices implemented and optimized to mitigate condensate banking in Cupiagua field. Because the field is being operated by Ecopetrol (as of June 2010), the mitigation of condensate banking was recognized as one of the most important stimulation challenges to be worked by the stimulation team. The effective mitigation of condensate banking is key to reaching and even exceeding the short- and long-term production targets set by Ecopetrol. This paper describes all the engineering work carried out to implement a new stimulation technique based on the injection of inhibited dry gas. The performed laboratory job, the simulation runs, the engineering design, and the field results are clearly described in the paper, the preliminary results showing that a successful stimulation technique exists to remove and mitigate condensate banking. At the moment, this stimulation strategy has been focused on removing liquid saturation (condensate and water) and organic solids (especially asphaltenes) by incorporating alcohol and surfactants inside the gas stream. Future engineering work will address the incorporation of a chemical blend that can improve the gas-treatment life, thus reducing critical liquid saturation or/and reducing the size of no-mobile condensate rings.

An Empirical Correlation Governing Gas-condensate Flow Through Chokes

Field production test data from 17 gas condensate wells in seven Iranian fields were used to develop an empirical correlation governing two-phase flow of gas condensate through wellhead chokes under sonic flow condition. In the new correlation liquid flow rate is a function of choke upstream pressure, choke size, and producing gas to liquid ratio. The predicted liquid flow rates using the new correlation are in excellent agreement with actual data. Statistical error analysis shows that results are statistically superior to those predicted by other published correlations considered in this work.