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See discussions, stats, and author profiles for this publication at: https://www.researchgate.net/publication/337123710Real-Time Estimation and Management of Hydrate Plugging Risk During DeepWater Gas Well TestingConference Paper · January 2019DOI: 10.2118/197151-MSCITATIONS0READS276 authors, including:Some of the authors of this publication are also working on these related projects:hydrate risk management View projectGeothermal Exploitation View projectJianbo ZhangChina University of Petroleum- Huadong31 PUBLICATIONS 277 CITATIONSSEE PROFILEZhiyuan WangChina University of Petroleum – Beijing127 PUBLICATIONS 973 CITATIONSSEE PROFILEWeiqi FuChina University of Petroleum – East China22 PUBLICATIONS 177 CITATIONSSEE PROFILEShikun TongChina University of Petroleum3 PUBLICATIONS 1 CITATIONSEE PROFILEAll content following this page was uploaded by Jianbo Zhang on 22 November 2019.The user has requested enhancement of the downloaded file.SPE-197151-MSReal-Time Estimation and Management of Hydrate Plugging Risk DuringDeep-Water Gas Well TestingJianbo Zhang and Zhiyuan Wang, China University of Petroleum East China; Wenguang Duan, CNPC XibuDrilling Engineering Company Limited and China University of Petroleum East China; Weiqi Fu, Shikun Tong, andBaojiang Sun, China University of Petroleum East ChinaCopyright 2019, Society of Petroleum EngineersThis paper was prepared for presentation at the Abu Dhabi International Petroleum Exhibition & Conference held in Abu Dhabi, UAE, 11-14 November 2019.This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contentsof the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflectany position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the writtenconsent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations maynot be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.AbstractHydrate formation and deposition usually exist during deep-water gas well testing, which easily causeplugging accident in the testing tubing if it was not found and handled in time. A method to estimate andmanage hydrate plugging risk in real-time during deep-water gas well testing is developed in this work.This method mainly includes the following steps: predicting hydrate stability region, calculating hydratebehaviors, analyzing the effect of hydrate behaviors on the variation of wellhead pressure, monitoring thevariation of wellhead pressure and estimating hydrate plugging risk in real-time, and managing hydrateplugging risk in real-time. As hydrates continue to form and deposit, the effective inner diameter of thetubing decreases, and the wellhead pressure also decreases accordingly. The risk of hydrate plugging can beestimated by monitoring the variation of wellhead pressure. When the wellhead pressure decreases to thecritical value for safety at a given gas production rate, it is indicated that hydrate plugging is likely to occur.Under this condition, hydrate inhibitor is needed to inject into the tubing to reduce the severity of hydrateplugging, and real-time monitoring of wellhead pressure variation is also needed to guarantee the risk ofhydrate plugging in the testing tube is within safe range. By using this method, the real-time estimation andmanagement of hydrate plugging during the testing process can be achieved, which can provide basis forthe safe and efficient testing of deep-water gas wells.Keywords: Deep-water gas well testing, Hydrate plugging risk, Real-time estimation and management,Wellhead pressure variation, Hydrate formation and depositionIntroductionThe exploration and development of oil and gas is gradually shifting to the deep water regions where withabundant oil and gas reserves (Pang et al., 2004; Zhu et al., 2009). Owing to the specific environment ofdeep water, many safety risk factors appeared in the development of oil and gas, in which hydrate pluggingin pipes is one of the important factors, especially for the gas well testing process (Dai et al., 2015). Thisis because the riser is exposed to the seawater environment with low-temperature, hydrates forms more
easily in this process, which will result in hydrate deposition and flow obstacle in the testing tubing (Wanget al., 2018), as illustrated in Fig.1. When hydrate plugging occurs in the testing tubing, the planed testingschedule and the safety of equipment will be seriously affected (Arrieta et al., 2011; Zhao et al., 2017),and the removal of hydrate plug is also very difficult and costly (Freitas et al., 2005; Reyna and Stewart,2001; Trummer et al., 2013; Sloan et al., 2010). Therefore, it’s necessary to pay more attention to how toaccurately predict and avoid hydrate plugging for the safe and efficient testing of deep water gas well.Figure 1—Schematic diagram of hydrate deposition and flow obstacle in the testing tubing.Up to now, many methods for preventing hydrate plugging in transportation pipelines have beenproposed, such as inhibitor injection, insulation and heat preservation, heating, depressurization, lining,dehydration, etc. (Creek,2012; Sloan et al., 2010; Zhao et al., 2017; Liu et al., 2018). However, duringthe process of gas well testing, the commonly used method to avoid hydrates is to inject massivehydrate inhibitors to make hydrate stable temperature and pressure conditions completely out of thefluid temperature and fluid pressure ranges in the testing tubing (Dai et al., 2015). This method has thedisadvantages of high cost and environmentally unfriendly (Wang et al., 2016; Zhang et al., 2019a). In recentyears, researchers proposed some new methods for hydrate plugging prevention. Creek (2012) proposedthat hydrates can be allowed to form without influencing the original fluid flow, which can be realized byinjecting a small amount of kinetic inhibitors or anti-polymer agents, this method is called the hydrate riskmanagement method. Wang et al. (2016, 2018) established a new hydrate blockage prevention method basedon the critical plugging risk, which can obviously decrease the cost of hydrate blockage prevention. Theabove two methods both have high requirements for accurate prediction of hydrate formation, depositionand plugging.During the testing process for gas wells, if the real-time prediction of the hydrate deposition degree inthe tubing is realized, the risk of hydrate plugging can be controlled more efficiently, which can improvetesting efficiency and reduce the cost of hydrate plugging prevention.In view of the special environmental conditions in deep water regions, the formation and depositionof hydrates in the testing tubing is invisible and intangible, so it is difficult to accurately predict the riskof hydrate plugging in real time. Up to now, there is a lack of an accurate real-time method to predictand manage the risk of hydrate plugging risk in the testing process. Less parameters can be monitoredduring the testing process of deep-water gas wells, the wellhead pressure is an important parameter that is
available to reflect the fluid flowing in the testing tubing. Previous researches (Wang et al., 2017; Zhang etal., 2019a, b) suggested that the deposited hydrate layer grows to thicker as the formation and depositionof hydrates continue, which leads to the effective flow passage of fluid in the tubing decreases, and thefrictional pressure drop increases accordingly. This will result in the decrease of the wellhead pressure,which is crucial to the accurate prediction of hydrate plugging risk in the tubing. In 2014, during the testingprocess of a deep water gas well located in South China Sea, the wellhead pressure gradually decreased undera constant gas production grate when the inhibitor injection was stopped, which indicated that hydrate flowobstacle forms in the tubing. After two hours, hydrate inhibitor was injected into the tubing immediately,and then the wellhead pressure gradually returns to its original normal value. This means that the variationof wellhead pressure was closely affected by hydrate formation and deposition. Through the detection ofwellhead pressure variation, the degree of hydrate flow obstacle in the tubing can be estimated in real timein the testing tubing, and the injection of hydrate inhibitor to control the risk of hydrate plugging in realtime can be guided.Based on the researches on hydrate formation, deposition and its effect on wellhead pressure variationduring testing process, a method for estimating and managing the risk of hydrate plugging in real time isproposed in this work. In this method, the risk of hydrate plugging is estimated by monitoring the variationof wellhead pressure in real time. The proposed method can provide a basis for the efficient managementof hydrate plugging risk in the testing process of deep water gas wells.Development of the proposed methodHydrate formation and deposition influence the variation of wellhead pressure during the testing process.Based on the forecast of hydrate stability region, hydrate behaviors, the relation between hydrate behaviorsand wellhead pressure variation, a method for estimating and managing hydrate plugging risk in real timeis proposed in this work. The procedure of this method is illustrated in Fig.2.Figure 2—Procedure of the real-time estimation and management method for hydrate plugging risk.
Prediction of hydrate stability regionKnowing where hydrate formation would occur in the testing tubing is the first step to achieve the estimationand management of hydrate plugging risk in real time. The basic parameters, including water depth,gas production rate, gas composition, wellbore structure, ambient temperature, bottom temperature andpressure, etc., provides a basis for the prediction of hydrate stability region. By using these basic parameters,the fluid temperature and pressure (T-P) in the testing tubing can be obtained based on the conservationtheories of mass, momentum and energy. In addition, the formation condition of hydrates can be obtainedby hydrate phase equilibrium theory (Chen and Guo, 1998). Based on the calculated T-P in the wellbore andhydrate phase equilibrium conditions, the method established by Wang et al. (2014) was used to predict thelocations where hydrate formation would occur in the testing tubing. This provides a basis for the subsequentestimation of hydrate plugging risk during deep water gas well testing.Calculation of hydrate formation and depositionDuring the process of gas well testing, substantial amounts of gas and a small quantity of liquid flow in thetubing. Under this flow conditions, liquid exists in the form of dispersed droplets and continuous liquid film,which results in annular flow appears in the tubing. In annular flow, both droplets and film are contactedwith gas phase. In the calculation of hydrate formation rate, the formed hydrates in the liquid film on andthe entrained liquid droplets should be both considered. Compared with other flows (e.g., bubble flow, slugflow, etc), the heat and mass transfer rates between gas and liquid are faster in annular flow (Wang et al.,2017; Bassani et al., 2017; Sun et al., 2019), which results in a faster rate of hydrate formation. The usuallyused model for the calculation of hydrate formation rate gas-dominated systems is the kinetic model (Turneret al., 2005; Lorenzo et al., 2014):
In annular flow, only part of the hydrates deposit and adhere on the pipe wall to form a growing hydratelayer in the tubing (Wang et al., 2017). Based on previous researches (Wang et al., 2016, 2017), the depositedhydrates on the pipe wall consist of two sections: hydrates formed from liquid film and liquid droplets. Inliquid film, all of the formed hydrates will deposit to the wall owing to the strong adhesion between thewall and hydrates (Aspenes et al., 2010; Wang et al., 2016). However, due to the strong drag force of highvelocity gas, some hydrate particles generated by little droplets are carried by gas flow, and some of thatdeposited in the liquid film will return back to the gas because of the atomization effect of liquid film (Wanget al., 2017). This means that only a portion of hydrate particles in the gas will deposit to form a hydratelayer in the testing tubing. In summary, the total hydrate deposition rate in annular flow is shown as below(Wang et al., 2017):
Hydrate deposition leads to the appearance of a hydrate layer in the testing tubing, which will graduallygrow to thicker as hydrate formation and deposition continues. Because of the different rates of hydrateformation and deposition at various times, the thickness of hydrate layer in a unit tubing with a length ofdL for a given time is obtained by using Eq. (3):
Analysis of the effect of hydrate behaviors on the variation of wellhead pressureThe growth of hydrate layer will lead to the decrease in the fluid flow passage of testing tubing, whichresults in the increase of gas velocity. This will increase the frictional pressure drop in the tubing, and the
wellhead pressure decreases accordingly. The pressure loss in the testing tubing was mainly induced byfriction, gravity, fluid kinetic energy variation and Thomson Joule effect. Because the testing time is short,its effect on the variation of well bottom pressure can be negligible, so the well bottom pressure is assumedto remains constant during the testing process. According to the theory of momentum conservation, thewellhead pressure in the testing process with hydrate behaviors can be achieved by the follow equation:
During the deposition process of hydrate particles and droplets, the atomization of liquid film coexists,so the contents of the liquid film, hydrate particles and droplets are in dynamic exchange. This will lead tothe average density of the fluid that includes gas, liquid and hydrates varies at various positions and times,which can be obtained as follows:
In Eq. (4), the frictional factor, λ, is closely related to the interfacial roughness, Reynolds number andpipe inner diameter. A simple and explicit formula proposed by Haaland (1983) is adopted in this work tocalculate the frictional factor:
The throttling effect is another important factor affecting pressure drop in the testing tubing, whichis resulted by the variable effective inner diameters resulted from hydrate deposition. The pressure dropresulted by the throttling effect can be obtained as follows (Finnemore, 2001):
Through the above calculations, the relation between the wellhead pressure variation and hydrateplugging risk can be achieved. Different degrees of hydrate plugging risk in the testing tubing will results indifferent variations of wellhead pressure. For a deep water gas well with a formation pressure of 38.7MPa,hydrate formation and deposition occurred during testing process and the wellhead pressure decreasedaccordingly. As shown in Fig.3, the predicted wellhead pressure variation considering hydrate formationand deposition behaviors agree well with the monitoring data. Through calculating the effect of hydratebehaviors on the variation of wellhead pressure at the given gas production rate, the risk of hydrate pluggingcan be estimated in real time.
Figure 3—Comparison between the estimated results and the monitoring data.Real-time monitoring of wellhead pressure and hydrate plugging risk estimationDuring the testing process, the wellhead pressure can be monitored in real time by the pressure sensorinstalled at the wellhead. Based on the above obtained relation between hydrate behaviors and wellheadpressure variation, we can see that different wellhead pressure variations corresponds to different risksof hydrate plugging. The decrease of the monitored wellhead pressure implies the occurrence of hydratebehaviors. Through monitoring the change of wellhead pressure in real time, the risk of hydrate pluggingcan be estimated in real time, and the specific location and time of hydrate plugging can also be achieved.Zhao et al. (2016) modeled the variation law of pressure drop with hydrate layer growth, and the criterionfor hydrate plugging occurrence is proposed, that is, the maximum thickness of hydrate layer reaches halfinner radius of the pipe. The hydrate plugging criterion at different gas production rates corresponds todifferent critical values of wellhead pressure. Therefore, once the decrease of wellhead pressure exceedsthe critical value, it implies that hydrate plugging is about to occur and the related measures for controllinghydrate plugging should be taken immediately to prevent further deterioration of hydrate plugging.Real-time management of hydrate plugging riskBased on the above researches, the risk of hydrate plugging in the testing tubing can be managed in realtime by injecting hydrate inhibitor in real time. As we all known, hydrate inhibitors can not only inhibitthe formation of hydrates, but also decompose the formed hydrates. When the monitored wellhead pressurevariation resulted by hydrate formation and deposition behaviors is within the safe range, there is no need totake hydrate plugging prevention measures. But when the monitored decrease of wellhead pressure exceedsthe critical value, it is indicated that hydrate plugging is highly likely to occur. Under this condition, theinjection of hydrate inhibitor is needed to decompose the formed hydrates and relieve the risk of hydrateplugging. In addition, the decomposition situation of hydrates in the testing tubing can also be estimated inreal time by monitoring the wellhead pressure variation to ensure that the risk of hydrate plugging remainswithin the safe range. In summary, by using the proposed method in this work, the risk of hydrate pluggingduring testing process can be estimated and managed in real time, until the accomplishment of the testingprocess.
Case study and discussionIn order to investigate the applicability of the real-time estimation and management method for hydrateplugging risk during testing process proposed above, a case study is carried out in this section. The casewell is a vertical well with 1530m water depth, its basic data is shown in Table1.Table 1—Basic data of the case well
Parameter Value Parameter ValueWater depth 1500 m Sea surface temperature 23°CWell depth 3440m Gas production rate 30-60×104 m3/dWell bottom pressure 37.6 MPa Liquid production rate 20 m3/dWell bottomtemperature90.5°C Relative density ofnatural gas0.631Tubing inner diameter 85.6mm Casing inner diameter 216.8mm
Based on the balances of mass, momentum and energy for the flowing fluid, the distributions oftemperature and pressure in the tubing can be obtained using the above basic data, which are used todetermine the hydrate stability region in the wellbore. During the testing process, the fluids (includinggas and liquid) produced from formation need to flow through the low-temperature seawater section toreaches the wellhead in the tubing. Heat transfer occurs between the flowing fluid in the tubing and theexternal environment, and the fluid temperature decreases accordingly. For a given pressure, when the fluidtemperature decrease to a certain value, hydrate formation occurs. Fig.4 shows the distribution of hydratestability region at various testing rates. As shown in the figure, hydrate stable region decrease with theincrease in testing rate. Under the above-mentioned testing rates (30-60×104 m3/d), the hydrate stabilityregion are changed from 0-1578m to 0-634m in the tubing.Figure 4—Prediction of hydrate stability region at various testing rates.On the basis of the prediction of hydrate stability region, the formation and deposition of hydrates in thetesting tubing can be forecasted using the above-mentioned calculation model in Section 2.1, the calculatedresults are illustrated in Fig.5. In the figure, the hydrate layer growth in the tubing is significantly influencedby gas production rate. As the testing time increases under low gas flow rates, the deposited hydrates in
the tubing at a constant gas production rate accumulates gradually, which results in the formed hydratelayer grows to thicker accordingly. After a certain testing time (e.g., 12.6h for 30×104m3/d), the maximumthickness of the hydrate layer reaches the critical value of plugging, in which hydrate plugging is likelyto occur (Wang et al., 2016). However, under high gas production rate (e.g., 60×104m3/d), after a certaintesting time, the maximum thickness of the hydrate layer decreases with the testing time. This is mainlybecause the fluid temperature in the tubing increases with time, which decomposes the deposited hydratesin the tubing. The critical times of hydrate plugging for various production rates are different, which canbe obtained by the proposed method in this work.Figure 5—Profiles of hydrate layer thickness under different production rates.Hydrate formation and deposition during testing process is closely affected by the testing rate. On onehand, the lower the testing rate, the lower the fluid temperature and the higher the fluid pressure, which leadto a greater subcooling for hydrate formation that is propitious to the increase of hydrate deposition. On theother side, the lower the gas production rate, the lesser droplets entrained in the gas that is the main sourceof hydrate formation (Lorenzo et al., 2014), which is not conducive to the increase of hydrate deposition.Therefore, the growth of the hydrate layer is the result of the above two effects.The variation of the maximum thickness of deposited hydrate layer with gas production rate at differenttimes are predicted, as shown in Fig.6. For a given testing time, there exists a critical gas production ratefor hydrate layer growth (e.g., 50×104m3/d for 8h). When the testing rate is lower than the critical rate, theabove-mentioned second effect is stronger than the first effect, which results in the maximum thickness ofhydrate layer increases with the increase of testing rate. Contrarily, when the testing rate is higher than thecritical rate, the first effect is stronger than the second effect, which results in the maximum thickness ofhydrate layer decreases with the increase of testing rate. Therefore, the prediction of hydrate layer growthat different testing rates is crucial to the prevention of hydrate plugging during testing process.
Figure 6—Variation of maximum hydrate layer thickness with testing rate at different times.The wellhead pressure is an important available parameter during testing process, which can providebasis for the estimation of hydrate plugging risk. Using the above method, the variation of wellhead pressurewith hydrate layer growth at various testing rates can be achieved, as seen in Fig.7. In the figure, with theoccurrence of hydrate formation and deposition, the estimated wellhead pressure decreases with time, whichis mainly resulted by the increase of frictional pressure drop that is caused by the decrease of the effectiveflow passage. In addition, there exists a critical wellhead pressure drop for hydrate plugging occurrence ateach gas production rate. For example, the permissible decrease of wellhead pressure to ensure that there isno hydrate plugging at a gas production rate of 30×104m3/d is 3.28MPa, which can be regarded as a basis forjudging hydrate plugging in the testing tubing. Moreover, the laws of wellhead pressure decrease at variousgas production rates are different, and the permissible decrease values are also different, 4.47MPa at thetesting rate of 40×104m3/d. Hence, the accurate prediction of wellhead pressure variation at different gasproduction rates is crucial to the estimation of hydrate plugging risk during deep water gas well testing.Figure 7—Variation of wellhead pressure with hydrate layer growth under various testing rates.
Based on the obtained laws of wellhead pressure with hydrate behaviors, the situation of hydrate layergrowth in the tubing can be predicted through monitoring the variation of wellhead pressure in real time.When the decrease of wellhead pressure at a given gas production rate approximate its allowable criticalvalue, it is indicated that the maximum thickness of hydrate layer is about to reach its critical value, thatis, hydrate plugging is about to occur in the tubing. Under this condition, hydrate inhibitors need to beinjected immediately into the tubing to reduce the risk of hydrate plugging. Meanwhile, it’s still necessaryto monitor the variation of wellhead pressure in real time to guarantee the risk of hydrate plugging is withinthe safe range.ConclusionIn this study, a method for real-time estimating and managing hydrate plugging risk during deep watergas well testing by monitoring the variation of wellhead pressure in real-time is proposed. This methodis obtained on the basis of the prediction of hydrate stability region and the interaction between wellheadpressure variation and hydrate layer growth. By using this method, the risk of hydrate plugging can bepredicted and managed in real time in the whole testing process.During the testing process, the risk of hydrate plugging is closely related to the testing time and testingrate. Under low gas production rates, the longer the testing time, the greater the risk of hydrate plugging.However, under high gas production rates, the longer the testing time, the smaller the risk of hydrateplugging. In order to avoid hydrate plugging accident during the testing process, the maximum thickness ofthe deposited hydrate layer in the tubing should be controlled within the safe critical thickness.The wellhead pressure decreases with hydrate formation and deposition. The risk of hydrate pluggingcan be estimated in real time by the real-time monitoring of wellhead pressure variation, and a critical valueof wellhead pressure decrease at a given gas production rate is proposed to stand for the risk of hydrateplugging. When the decrease of wellhead pressure exceeds the critical value, hydrate inhibitor is neededto inject into the testing tubing to release the risk of hydrate plugging. Using the proposed method, theinjection of hydrate inhibitors can be guided in real time to ensure the safety and efficiency of deep-watergas well testing.AcknowledgeThe work was supported by the National Natural Science Foundation-Outstanding Youth Foundation(51622405), the Shandong Natural Science funds for Distinguished Young Scholar (JQ201716), theChangjiang Scholars Program (Q2016135), the Construction Project of Taishan Scholars, the NationalKey Research and Development Plan (2016YFC0303408), and the Program for Changjiang Scholars andInnovative Research Team in University (IRT_14R58).Nomenclature
=gas-liquid interfacial area, m2
=hydrate particle concentration, kg/m3
= droplet concentration, kg/m3
=tubing effective inner diameter, m
=control volume length, m
=gravity acceleration, m/s2
=hydrate layer thickness, m
=gas holdup, dimensionless
= liquid holdup, dimensionless
= hydrate holdup, dimensionless
=adiabatic coefficient, dimensionless
=kinetic rate constant, 2.608×1016 kg/(m2.K.s)
=kinetic rate constant, -13600K
=interfacial roughness, m
=gas molar mass, g/mol
=hydrate molar mass, g/mol
=pressure before diameter reducing, Pa
=wellhead pressure, Pa
= well bottom pressure, Pa
=throttling pressure drop, Pa
=gas consumption rate for hydrate formation, mol/s
=hydrate deposition rate, kg/(m2.s)
=droplet deposition rate, kg/(m2.s)
=Reynolds number, dimensionless
=time, s
=temperature, K
=subcooling, K
=scaling factor, dimensionless
=average velocity, m/s
=velocity before diameter reducing, m/s
=velocity after diameter reducing, m/s
=inclination, °
=frictional factor, dimensionless
=average density, kg/m3
=gas density, kg/m3
=hydrate density, kg/m3
=liquid density, kg/m3
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