SIMULATION OF TEMPERATURE-PRESSURE PROFILES AND WAX DEPOSITION IN GAS-LIFT WELLS

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1 Available on line at Association of the Chemical Engineers of Serbia AChE Chemical Industry & Chemical Engineering Quarterly Chem. Ind. Chem. Eng. Q. 23 (4) (2017) CI&CEQ SNEZANA SEVIC BRANKO GRUBAC PM Lucas Enterprises, Kać, Serbia SCIENTIFIC PAPER UDC 622:66: SIMULATION OF TEMPERATURE-PRESSURE PROFILES AND WAX DEPOSITION IN GAS-LIFT WELLS Article Highlights Temperature-pressure profiles in gas-lift wells can be simulated by Aspen HYSYS Matching simulated with measured profiles depended on the number of pipes representing tubing The more pipes included in the model, the better matching with measured data was achieved The model can be used to determine wax deposit thickness distribution vs. well depth Wax deposit profile can be used to plan wax cutting depth and frequency Abstract Gas-lift is an artificial lift method in which gas is injected down the tubing- -casing annulus and enters the production tubing through the gas-lift valves to reduce the hydrostatic pressure of the formation fluid column. The gas changes pressure, temperature and fluid composition profiles throughout the production tubing string. Temperature and pressure drop along with the fluid composition changes throughout the tubing string can lead to wax, asphaltenes and inorganic salts deposition, increased emulsion stability and hydrate formation. This paper presents a new model that can sucesfully simulate temperature and pressure profiles and fluid composition changes in oil well that operates by means of gas-lift. This new model includes a pipe-in-pipe segment (production tubing inside production casing), countercurrent flow of gas-lift gas and producing fluid, heat exchange between gas-lift gas and the surrounding ambient ground; and gas-lift gas with the fluid in the tubing. The model enables a better understanding of the multiphase fluid flow up the production tubing. Model was used to get insight into severity and locations of wax deposition. The obtained information on wax deposition can be used to plan the frequency and depth of wax removing operations. Model was developed using Aspen HYSYS software. Keywords: gas-lift; oil well; pressure-temperature profile; simulation; wax deposition. Gas-lift is a method that uses an external source of high-pressure gas for helping formation gas to lift the well fluids. The compressed gas is injected down the production casing-tubing annulus, entering the tubing through the working gas-lift gas valves. As the gas-lift gas enters the tubing, it forms bubbles, lightens the formation fluids by reducing fluid density Correspondence: S. Sevic, PM Lucas Enterprises, Kać, Serbia. s.sevic@pmlucas.com Paper received: 14 October, 2016 Paper revised: 7 February, 2017 Paper accepted: 10 February, and lowers the flowing bottom hole pressure, creating a drawdown that allows the fluid to flow into the wellbore. During fluids flow through a tubing string in oil producing well, pressure, temperature, phase s ratio, composition of phases change. These changes are the result of different effects, such as the frictional loss, fluid lifting, and heat transfer from the surroundings. At the same time, the Joule-Thompson effect takes place. Typically, gas lift designs are based on natural gas as the injection gas. Early gas lift operations were conducted using air as the injection gas. Nitrogen and carbon dioxide offer good alternatives to natural gas for gas lift [1,2]. 537

2 One of the first theoretical models which described single-phase fluid flow temperature as a function of well depth and producing time was given by Ramey [3]. Sagar et al. [4] extended Ramey s method for wellbore with multiphase flow. A unified model for temperature distribution with approximate method to calculate the Joule-Thompson coefficient for two phase mixture with a black oil in wellbore was presented by Alves et al. [5]. Hasan [6] developed analytical model for the flowing fluid temperature in the drill pipe/tubing and in the annulus as a function of well depth and circulation time. Hasan and Kabir carried out research on the heat transfer in wellbore [7,8] and fluid temperature profile in gas-lift wells [9]. They also developed method for predicting two-phase gas/ /oil pressure-drop in vertical oil wells [10,11]. The effect of tubing temperature and injection gas-lift gas temperature on the gas-lift valve dome temperature were studied by Bertovic [12] and Faustinelli [13]. Xu [14] made experimental study of three-phase flow in a vertical pipe in order to investigate the influence of gas injection and the average in situ phase fraction and pressure gradient. Cazarez et al. [15] developed a model able to predict pressure, temperature and velocity profiles and volumetric fraction of the components. Bannwart et al. [16] done research on pressure drop and pressure gradient in wells in three phase fluid flow. Temperature and pressure distribution versus well depth in gas, gas-condensate and oil wells was extensively examined [17-19]. At the beginning of the 21 st century, two artificial neural network (ANN) models were developed to predict the temperature of the flowing fluid at any depth in flowing oil wells [20]. The presence of multiple phases greatly complicates pressure drop calculations. This is due to the fact that the properties of each fluid present must be taken into account. Also, the interactions between each phase must be considered. Mixture properties must be used, and therefore the gas and liquid in-situ volume fractions throughout the pipe need to be determined. In general, multiphase correlations are essentially two-phase and not three-phase. Accordingly, the oil and water phases are combined, and treated as a pseudo single-liquid phase, while gas is considered a separate phase. Modeling and simulation of multiphase system, even under steady-state condition, is complex [21-24]. There are a few tools, such as PipePhase, PipeSim, OLGA and Aspen HYSYS, designed specifically for simulation and analysis of complex multiphase systems. Li [25] developed dynamic model for sensitivity analysis of gaslift wells using a commercially available OLGA dynamic multiphase flow simulator to simulate the transient dynamic gas-lift unloading process. Flow assurance in oil and gas production is considered as the ability to produce fluids economically, from the reservoir to a production facility over the life of a field and in any environment. Deposition of any sort may lead to operational difficulties and production loss. Gas-lift application can influence flow assurance issues. Temperature drop can cause wax deposition. Gas-lift gas can extract H 2 S and CO 2 out of the oil and water phase and by that effect can shift ph to greater values and support CaCO 3 formation and sulfate reducing bacteria activity. Gas bubbling causes intensification of water and oil leading to increased emulsion stability. Introduction of light gas components can cause asphaltenes precipitation. Corrosion in a tubing-casing annulus and increase of hydrate formation temperature are often recorded in gas-lift operations. Temperature reduction is the most common cause of wax deposition because wax solubility in hydrocarbon fluids decreases as the temperature drops. Pressure changes usually have a very small effect on wax precipitation temperatures and amounts. Wax deposition may cause operational problems in production tubing string and surface pipelines during oil flow from the perforated/open hole interval to surface and further down the oil pipeline. Numerous wax deposition models have been developed [26-29]. These models differ in the number of phases that were considered, wax formers, properties of components. There are a few tools designed specifically for modeling wax deposition such as pvtsim nova, PipeSim, OLGA, Aspen HYSYS, etc. Simulators can be divided into static and dynamic. In the static models, the conditions of a system do not change with time, opposite from the dynamic model. The authors of this paper could not find references that deal with use of Aspen HYSYS in simulation of temperature and pressure distribution in wells that produce oil by means of gas-lift. This paper presents a new model developed using Aspen HYSYS which can sucesfully simulate temperature-pressure profiles, fluid phase behavior, composition change and wax deposition as a function of well depth in the gas-lift wells. This new model included pipe-in-pipe segment (tubing-casing), countercurrent flow of gaslift gas and producing fluid, heat exchange between gas-lift gas and the surrounding ambient-ground; and gas-lift gas with the fluid in the tubing. 538

3 MODEL DEVELOPMENT Model Boundaries and Streams To develop a model, it is necessary to define the inlet and outlet boundaries of the model, to establish the process flow along with the process parameters and to define inlet and outlet streams. The model inlet boundaries were: bottom of the well and the inlet of the compressor for gas-lift gas. The model outlet boundary was the wellhead of the production well. The inlet stream consisted of the following: hydrocarbon fluid at the bottom of the well, water stream at the bottom of the well and gas-lift gas. The outlet stream was producing fluid from the well. Figure 1 presents the scheme of gas-lift well operation. Figure 1. Scheme of gas-lift wells operation. Aspen HYSYS Software version 8.8 was used for simulation. Peng-Robinson equation of state package was used. Process flow modelling Process of gas-lift wells operation included the following elements relevant for the targeted simulation: 1. Pipe-in-pipe system which includes: Production tubing the inner pipe. Production casing the outer pipe. Annulus A - space between the production tubing outer diameter and production casing inner diameter, tubing-casing annular space. The tubing was modeled as a circular pipe with a given diameter. Annular space was modeled as a circular pipe with hydraulic diameter corresponding to an annular section. Hydraulic diameter of a circular tube with an inside circular tube was calculated as: d = 2( r r ) (1) h o i where d h is a hydraulic diameter (mm), r o is an inside radius of the outside tube (mm), r i is an outside radius of the inside tube (mm). 2. Countercurrent fluid flow: Producing fluid from the well, along with the accompanied gas-lift gas flows from the bottom of the well up, toward the wellhead, through the tubing (inner space). Gas-lift gas flows from the top of the casingtubing annulus to the bottom and enters the tubing through the working gas-lift valve. 3. Heat exchange takes place as follows: Gas-lift gas exchanges heat with the surrounding ambient - ground and with the fluid in the tubing. Fluid in the tubing exchanges heat with the gas-lift gas in the annular space. Heat transfer between gas-lift gas and ambient was modeled by the heat transfer option Estimate heat transfer coefficient (HTC) (pipe wall, inner HTC, and outer HTC were included), taking into account ground thermal gradient, as no other data were available [30]. Heat transfer between inner pipe and annular space was modeled only at nodes of a desired number of elements, and using estimated heat flow to obtain measured temperature at the end of a pipe segment. For this, the overall length of the pipe was broken down into a desired number of elements, and the end of each node was accounted for the heat flux using a mixer. If the overall heat transfer coefficient and the ambient temperature are specified, then the outlet temperature is determined from the following equations: Q = UAΔT LM (2) Q = Q Q (3) IN OUT where Q is an amount of heat transferred per unit of time (W), U is an overall heat transfer coefficient (W/(m 2 K)), A is an outer heat transfer area (m 2 ), ΔT LM is a log mean temperature difference (K), Q IN is a heat flow per unit of time of inlet stream (W) and Q OUT is a heat flow per unit of time of (W) [30]. 539

4 RESULTS AND DISCUSSION Model validation Available production and process data were tested to verify the reliability of developed model. The inlet parameters for the simulation were as follows: Oil, gas and water production rates on the date when measurements by production logging tool (PLT) were performed. Oil and gas composition at bottom hole conditions from the pressure, volume, and temperature (PVT) analysis. Gas-lift gas injection rate, composition, injection temperature and pressure on the date when measurements by production logging tool (PLT) were performed. Ground thermal gradient for the region in the vicinity of the wells. Existing well completion. Flow rates of producing fluids and gas-lift gas on the date when measurements by production logging tool (PLT) were performed were accepted. To develop and verify this approach, actual field multiphase-flow data points were obtained from the existing measured data of temperature-pressure profiles. Case study Sales gas was used in the gas-lift operation. Gas was compressed to 125 bar, and transported through the pipeline to the distribution manifold. The compressed gas-lift gas was redirected towards producing oil wells at the gas manifold via separated pipelines. Calculations on gas-lift performance have shown that gas pressure for the Well D should be around 74 bar. Therefore, pressure was reduced to 74 bar through the choke. Gas was injected into the annular space of the well, and entered the tubing through the working gas-lift valve. Gas-lift gas, along with the fluid from the well, flowed up through the tubing to the wellhead, and was transported by the pipeline to the main gathering station. The main process parameters used in the simulation are shown in Table 1. Table 1. Process parameters used in the simulation Parameter Unit Value Well production data Oil production rate t Gas production rate S m Water production rate S m Bottom hole conditions Bottom hole temperature C Bottom hole pressure bar Gas-lift gas Injection rate S m Pressure at the top of the casing bar 73.5 Temperature at the top of casing C 4.45 Figure 2. Process flow diagram of gas-lift gas transportation to the casing-tubing annular space and from the wellhead to the oil treatment plant. 540

5 Process flow diagram (PFD) is shown in Figure 2. Producing well tubing-casing, gas-lift gas and producing fluid streams, are presented by subflowsheet, abbreviation T. Temperature-pressure profiles In the first model, the tubing consisted of 2 (two) pipes: the first pipe represented a part of the tubing from the bottom of the well up to the working gas-lift valve. The second pipe represented the part of the tubing from the working gas-lift valve to the wellhead. The annular space was presented as a single pipe. All pipes were divided into 3 segments, and each segment was divided into 5 increments. All multiphase pressure drop correlations for vertical flow of gas-liquid systems available in HYSYS were checked. Measured pressure and temperature profiles were used as a reference. Results showed poor matching of calculated temperature-pressure profiles with measured values no matter which of the correlations were used. Some pressure drop correlation overestimated and some of them underestimated measured pressure and temperature distribution. The same results were obtained if pipe was divided in more segments and increments. Figure 3 shows results of temperature-pressure profiles obtained by 4 different multiphase pressure drop correlations for vertical fluid flow. In the next model, tubing was presented with 3 (three) separate pipes, one from the bottom of the well to the working gas-lift valve depth, and 2 (two) from the working gas-lift gas valve to the wellhead. The annular space was presented with 2 (two) pipes (Figure 4). The idea was to improve matching with the measured data. All available pressure drop correlations for vertical flow were tested again. Simulation was performed in two ways: The same pressure drop correlation for all pipes. Different correlations for pipes. The result showed better matching of calculated temperature-pressure profiles with measured data compared to the first model. In the case when a single pressure drop correlation was accepted for all pipes, the best matching was achieved using Hagedorn and Brown correlation. Results are shown in Figure 5. It was noticed that different correlations applied to each pipe provided better pressure loss estimates than a single-correlation for the entire tubing. It could be explained by the fact that along the tubing, due to the temperature and pressure changes, liquid/vapor phase ratios changed, and by that phases superficial Figure 3. Measured vs. calculated profiles for 2 pipes case: a. pressure; b. temperature. 541

6 Figure 4. Process flow diagram of fluids flow through the tubing and the annular space. Figure 5. Measured vs. calculated profiles for 3 pipes case: a. pressure; b. temperature. 542

7 velocities changed, which affected flow regime and pressure drop. Further improvement of matching between measured and calculated temperature-pressure profiles using one multiphase pressure loss correlation was obtained by dividing tubing and annular space into more independent pipes. The best matching was obtained when the tubing was divided into 10 (ten) pipes. Temperature and pressure profiles are shown in Figure 6. Wax deposition simulation Wax deposition simulation was carried out using available models: Pederson, Conoco, Chung and AEA [30]. Results of wax deposit thickness profile versus well depth and wax deposit volume calculated by different models are shown in Figures 7 and 8. Software took into account deposited wax thickness to calculate temperature - pressure profiles when wax deposition calculation module was active (checked), leading to different temperature and pressure at the outlet of the pipe compared to the case when calculation module was inactive (unchecked). All other parameters, i.e., vapor fraction, liquid holdup, friction gradient, Reynolds numbers of gas and liquid phases (and their velocities) differed, too. On the other hand, no changes of the overall fluid Figure 6. Measured vs. calculated profiles for 10 pipes a. temperature; b. pressure. Figure 7. Wax deposit thickness profile calculated by different models. 543

8 Figure 8. Wax deposit volume calculated by different models. composition at the outlet of the pipe were observed although deposition took place inside the segments of the pipe. Thus, it was concluded that overall fluid compositional changes due to wax deposition along the pipe were not transferred between the pipes. Differences in ratios and compositions of present phases (vapor, liquid, aqueous) at the inlet and the outlet of the pipe depended on the temperature and pressure conditions. It is strongly recommended to check the validity of PVT reports and composition analysis due to the fact that fluids composition data may be a source of errors in multiphase flow calculations. CONCLUSIONS A model using Aspen HYSYS software to simulate fluid phase behavior and temperature-pressure profiles in wells that operate by means of gas-lift has been developed. This model was tested against the measured temperature-pressure data for wells depth up to 4600 m, pressures from 8 to 120 bar and temperatures from 5 to 110 C. The developed model can be used for wells without PLT data to obtain temperature-pressure distribution and phase compositions along the tubing. The results showed that matching of calculated temperature-pressure profiles depended on the number of pipes representing tubing and annular space and the type of multiphase pressure loss correlation. Different multiphase pressure loss correlations applied provided better pressure loss estimates than a single correlation for the entire tubing. The developed model can be used to get insight into severity of the wax deposition and is helpful in planning frequency of removing operations. Overall compositional changes along the pipe were not transferred between the pipes, regardless of if wax deposit was formed inside the pipe. Impact of the angle of inclination, liquid viscosity, water cut, gas density, gas/liquid interfacial tension, the average superficial gas and liquid velocities on temperature-pressure profiles was not included in the developed model. REFERENCES [1] H.W. Winkler, J.R. Blann, Production Operations Engineering, SPE, Richardson, TX, 2006, pp [2] G.Takacs, Gas Lift Manual, PennWell Corporation, Tulsa, OK, 2005, pp.1-5 [3] H.J. Ramey Jr., J. Pet. Technol. 14 (1962) [4] R. K. Sagar, D.R. Dotty, Z. Schmidt, 1989 SPE SPE Annu. Tech. Conf. Exhib., San Antonio, TX,1989, paper SPE [5] I.N. Alves, F. J.S. Alhanti, O. Shoham, SPE Prod. Eng. 7 (1992) [6] A.R. Hasan, C.S. Kabir, SPE Prod. Facil. 11 (1996) [7] A.R. Hasan, C.S. Kabir, 1991 SPE SPE Annu. Tech. Conf. Exhib., TX, 1991, paper SPE [8] A.R. Hasan, C.S. Kabir, Western Regional Meeting, Anchorage, AK, 1993, paper SPE [9] A.R. Hasan, C.S. Kabir, J. Pet. Sci. Eng (2012) [10] A.R. Hasan, C.S. Kabir, J. Pet. Sci. Eng. 4 (1990) [11] A.R. Hasan, C.S. Kabir, J. Pet. Sci. Eng. 72 (2010) [12] D. Bertovic, Production Operations Symposium, Oklahoma City, OK, (1997, paper SPE [13] J.G. Faustinelli, D.R Doty, SPE Latin American and Caribbean Petroleum Engineering Conference, Buenos Aires, 2001, paper SPE [14] X.J. Z Jing-yu, L. Hai-fei, Int. J. Multiphase Flow 46 (2012) 1-8 [15] O. Cazarez, D. Montoya, A.G. Vital, A.C. Bannwart, Int. J. Multiphase Flow 36 (2010) [16] A.C. Bannwart, O.M.H. Rodrigez, F.E. Trevisan, C.H.M. de Carvalho, J. Pet. Sci. Eng. 65 (2009) 1-13 [17] X. Zhao, J. Xu, World J. Modell. Simul. 4 (2008) [18] I. Alves, F. Alhanati, O. Shoham, SPE Prod. Facil. (1992)

9 [19] M.F. Zhou, X. Zheng, Asian J. Earth Sci. 26 (2015) [20] A. Zamani, P. Pourafshari, F. Rabiee, Gas Process. J. 2 (2014) [21] F.F. Farshad, Engin. Comput. 17 (2000) [22] I.Y. Mohammed, Int. J. Curr. Engin. Technol. 4 (2014) [23] A.P. Szilas, Production and transport of oil and gas, Development in Petroleum Science 3, Elsevier Scientific Publishing Company, New York, 1975, pp ; [24] H. Hamedi, F. Rashidi, E. Khamehchi, Pet. Sci. Technol. 29 (2011) [25] L. Mengxia, R. Liao, Int. J. Heat Technol. 33 (2015) [26] K.S. Pedersen, P.L. Christensen, J.A. Shaikh, Phase Behavior of petroleum Reservoir Fluids, 2 nd ed., CRC Press, Boca Raton, FL, 2015, pp [27] M. Stubsjøen, M.Sc. Thesis, Petroleum Norwegian University of Science and Technology, Oslo, 2013, pp [28] J.A. Svendsen, AIChE J. 39 (1993) [29] E.D. Burger, T.K. Perkins, J.H. Striegler, J. Pet. Technol. 33 (1981) [30] HYSYS 8.8 Operations Guide, AspenTech SNEZANA SEVIC BRANKO GRUBAC PM Lucas Enterprises, Kać, Srbija NAUČNI RAD SIMULACIJA PROFILA TEMPERATURE I PRITISKA I TALOŽENJA PARAFINA U GAS-LIFT BUŠOTINAMA Gas-lift je mehanička metoda eksploatacije naftnih bušotina u kojoj gas utisnut u međuprostor između proizvodnog tubinga i proizvodnog kezinga, ulazi u proizvodni tubing kroz gas-lift ventile, čime se smanjuje hidrostatički pritisak stuba ležišnog fluida. Gas-lift gas utiče na promenu profila pritiska, temperature i sastava fluida u proizvodnom tubingu. Pad temperature i pritiska, uz promenu sastava fluida u tubingu, mogu da dovedu do taloženja parafina, asfaltena i neorganskih soli, povećanja stabilnosti emulzije i formiranje hidrata. Ovaj rad prikazuje novi model koji se može uspešno koristiti za simulaciju promene profila temperature, pritiska i sastava fluida u stubu naftne bušotine koja radi u gas-liftu. Novi model uključuje protivstrujni protok gas-lift gasa i proizvedenog fluida kroz cev; razmenu toplote izmedju gas-lift gasa i okoline zemlje, te gas-lift gasa i fluida u tubingu. Prikazani model omogućava bolje razumevanje multi-faznog protoka kroz proivodni tubing. Model je korišćen da se dobije uvid u nivo i mesto stvaranja taloga parafina. Dobijene informacije o taloženju parafina mogu se koristiti da se planira učestalost i dubina operacije uklanjanja parafina. Model je razvijen korišćenjem programa Aspen HYSYS. Ključne reči: gas-lift, naftna bušotina, profil pritisak-temperatura, simulacija, taloženje parafina. 545