Hydrate Risk Assessment and Restart-Procedure Optimization Of
Hydrate Risk Assessment and Restart- Procedure Optimization of an Offshore Well Using a Transient Hydrate Prediction Model
L.E. Zerpa, E.D. Sloan, C.A. Koh, and A.K. Sum, Colorado School of Mines
Summary This paper focuses on the application of the gas-hydrate model A produced-hydrocarbon stream from a wellhead encounters for- to study the hydrate-plugging risk of an offshore well with a typ- mation of solid gas-hydrate deposits, which plug flowlines and ical geometry and fluid properties from the Caratinga field located which are one of the most challenging problems in deep subsea fa- in the Campos basin, Brazil. Three different periods of the well cilities. This paper describes a gas-hydrate model for oil-dominated life are considered: an early stage with low production gas/oil ratio systems, which can be used for the design and optimization of facil- (GOR) and low water cut, a middle stage with an increased GOR, ities focusing on the prevention, management, and remediation of and a late stage with higher GOR and higher water cut. The hy- hydrates in flowlines. Using a typical geometry and fluid properties drate-plugging risk is estimated from the calculation of three per- of an offshore well from the Caratinga field located in the Campos formance measures (pressure drop along flowline, hydrate volume basin in Brazil, the gas-hydrate model is applied to study the hy- fraction in pipe, and hydrate-slurry relative viscosity) in an attempt drate-plugging risk at three different periods of the well life. Addi- to quantify the plugging risk. Once the hydrate-plugging risk is tionally, the gas-hydrate model is applied to study the performance estimated for the three different periods of the well life, the gas- of the injection of ethanol as a thermodynamic hydrate inhibitor in hydrate model is used to optimize the concentration of thermody- steady-state flow and transient shut-in/restart operations. The ap- namic hydrate inhibitor (THI) to be injected in order to reach a safe plication of the transient gas-hydrate model proved to be useful in operation condition. In this study, ethanol is considered as the THI determining the optimal ethanol concentration that minimized the because it is the typical hydrate inhibitor used in South America hydrate-plugging risk. (because of the large industrial production of ethanol in the region). Additionally, the gas-hydrate model is used to study the effect Introduction of hydrates in transient shut-in/restart operations of the offshore Offshore explorations in deeper and colder waters impose more- well and the performance of hydrate inhibition in terms of ethanol challenging scenarios to the flow assurance of the produced concentration. In general, ethanol injection decreased the hydrate- streams. High pressures and low temperatures of operation of pro- plugging risk in steady-state and transient operations. The appli- duction facilities with longer subsea tiebacks will promote the for- cation of the transient gas-hydrate-prediction model proved to be mation of natural-gas hydrates: crystalline compounds formed by useful in determining the optimal ethanol concentration that mini- hydrogen-bonded water molecules in a lattice structure that is sta- mized the hydrate-plugging risk. bilized by encapsulating a small guest molecule (e.g., methane and ethane) (Sloan and Koh 2008). Gas hydrates form in the pres- Description of the Hydrate Prediction Model ence of appropriate quantities of gas and water, and are considered The hydrate-prediction model was specially designed for oil-dom- one of the most challenging problems in deep subsea facilities be- inated systems on the basis of the conceptual model presented in cause of their rapid formation compared with other solid deposits Fig. 1, which represents an approximation to the mechanism of hy- (Sloan 2005). drate-plug formation and is divided into four main stages. A transient gas-hydrate model that predicts when and where hy- 1. Water entrainment: The water droplets are dispersed in the drate plugs will form in flowlines will have significant utility for the continuous oil phase as a water-in-oil emulsion. flow-assurance engineer in the oil and gas industry. By predicting gas- 2. Hydrate growth: A hydrate shell forms at the interface be- hydrate formation and transportability, the gas-hydrate model can be tween the water droplets and the surrounding oil phase. applied to design and optimize oil/gas-transport facilities, focusing on 3. Agglomeration: The hydrate-encrusted water droplets can ag- prevention, management, or remediation of gas hydrates in flowlines. glomerate, increasing into larger hydrate masses or agglomerates. This paper briefly presents a gas-hydrate model specially designed 4. Plugging: The agglomeration of hydrate particles leads to an for oil-dominated systems, which has been incorporated as a plug-in increase in the slurry viscosity, which can eventually result in a module in a transient multiphase-flow simulator (Turner et al. 2005). plug. The gas-hydrate model developed for oil-dominated systems follows The model assumes that all the water is dispersed into the contin- the conceptual model presented in Fig. 1, where hydrates form at the uous oil phase as water droplets of fixed diameter, where the surface interface of water droplets entrained in the continuous oil phase. In area between water and hydrocarbon phases is calculated by a tran- the oil phase, these hydrate-encrusted water droplets can agglomerate sient multiphase-flow simulator using the Hinze correlation (Hinze into larger hydrate masses, leading to an increase in the slurry vis- 1955). Hydrate nucleation is assumed to occur immediately after cosity, which can eventually result in a plug (Turner 2006). a specified subcooling (DTsub=Thyd_eq-Tsystem), and the hydrate growth is calculated using the following intrinsic kinetics equation of first order with an adjustable rate constant (Boxall 2009), Copyright © 2012 Society of Petroleum Engineers This paper (SPE 160578) was revised for publication from paper OTC 22406, first presented at the Offshore Technology Conference Brasil, Rio de Janeiro, 4–6 October 2011. Original dmgas k2 manuscript received for review 14 September 2011. Revised manuscript received for review =−uk1 exp. ATs ()∆ sub ...... (1) 1 December 2011. Paper peer approved 9 February 2012. dt Tsys
PB Oil and Gas Facilities • October 2012 October 2012 • Oil and Gas Facilities 49 Water Entrainment Hydrate Growth Agglomeration Plugging
Gas
Oil
Water
Fig. 1—Conceptual model for hydrate formation in multiphase-flow systems consisting of water, oil, and gas; adapted from Turner (2006).
0 TABLE 1—PROPERTIES AND COMPOSITION OF Platform CARATINGA CRUDE OIL (SJÖBLOM ET AL. 2010) 500 Wellhead Density (g/m3) 0.914 1000 Viscosity dead oil (Pa·s) 0.262 Viscosity live oil (Pa·s) 0.0095 1500 IFT (mN/m) 23
Depth (m) 2000 Asphaltene content (%) 6.2 Well Saturates content (%) 39.8 2500 Flowline and riser Aromatic content (%) 39.8 3000 Resin content (%) 14.3 0 5 10 15 Horizontal Distance (km) Then, the relative viscosity of the hydrate slurry to the viscosity of the continuous oil phase is calculated using Mills’ equation Fig. 2—Geometry of well, flowline, and riser, based on typical (Mills 1985): geometries from the Caratinga field located at the Campos Ba- sin in Brazil.
1− φeff µr = 2 ...... (4) The intrinsic kinetics equation gives the rate of gas consump- φ 1− eff tion during hydrate formation as a function of the intrinsic rate φmax constants (k1 and k2) regressed from the data of Vysniauskas and Bishnoi (1983), the surface area (As) between water and hydro- A hydrate plug is identified by a large viscosity increase, which carbon phases, and the subcooling as the thermal driving force. causes an unacceptably large pressure drop in the line, prohibiting flow. Once the hydrate particle has formed, the size of the agglomer- ates is calculated using a steady-state balance between the interpar- Offshore-Well Hydrate Risk Assessment ticle cohesion force and the shear forces (Camargo and Palermo This section presents the approach followed to estimate the hy- 2002), assuming a constant interparticle cohesion force as follows: drate-plugging risk in an offshore well using the gas-hydrate-pre- diction model described in the preceding section. The simulation case consists of a typical well/flowline/riser geometry and fluid 3− f 2 φ d properties from the Caratinga field located at the Campos Basin F 1− hyd A 4− f a in Brazil. Fig. 2 shows the geometry in terms of horizontal length d φmax dP A − = 0, ...... (2) and depth from sea level, which consists of a slanted well with a di- 3− f dP ameter of 5 in., a departure of 2000 m, and a depth of 1800 m. The 2 d A dPµγ0 1− φhhyd well is connected to a straight flowline with a slight uphill slope, d P a diameter of 0.1524 m, and a horizontal length of approximately 13 km, followed by the bend into the riser that leads up to the plat- where dA is the hydrate-agglomerate diameter, dP is the hydrate- form or FPSO. Table 1 presents a summary of the Caratinga crude- particle diameter, fhyd is the hydrate-particle volume fraction, fmax oil properties and composition measured by Sjöblom et al. (2010). is the maximum packing fraction (assumed to be equal to 4/7), f is As a first approach to estimate hydrate-plugging risk, a pressure/ the fractal dimension (assumed to be equal to 2.5) that accounts for temperature diagram, shown in Fig. 3, was built overlying the flow- the porosity of the aggregates, Fa is the interparticle cohesion force line operation conditions under steady-state flow with hydrate-equi- (assumed to be equal to 50 mN/m), m0 is the oil viscosity, and γ is librium curves at different ethanol concentrations. Wherever the the shear rate. flowline-operating-conditions curve lies to the left of the hydrate- Because of the fractal structure of the aggregates, the effective equilibrium curves is considered a region for hydrate formation. It volume fraction of the agglomerated hydrate particles is calculated as can be observed that a portion of the flowline-operating-conditions curve is located inside the hydrate-formation region, confirming 3− f the feasibility of forming hydrates in this system, and that more d A ...... (3) than 30 wt% ethanol is required to totally inhibit the system. How- φφeffh= yd . dP ever, this diagram does not provide information about the amount
50 Oil and Gas Facilities • October 2012 October 2012 • Oil and Gas Facilities 51 14 60 Ethanol concentration (wt%) 40 30 20 10 0 Hydrate equilibrium temperature 12 50 System temperature Flowline operation conditions 10 40
30 8 Wellhead 20 6 10
Hydrate equilibrium curve Temperature (ºC) Pressure (MPa) 4 Steady-state flow conditions 0 2 Topsides -10 0 5 10 15 0 Pipeline Length (km) -20 0 20 40 60 Temperature (ºC) Fig. 4—Temperature distribution along the flowline length, Fig. 3—Diagram of pressure vs. temperature showing flowline showing system temperature and hydrate-equilibrium temper- operation conditions during steady-state flow and hydrate-equi- ature corresponding to the steady-state flow predicted by the librium curves at different ethanol concentrations. transient gas-hydrate model for Case 1.
• Low-risk: DP <300 psi, f <0.10, m <10. At this level, 1 flowline hyd r formed hydrates are considered to be easily transported through the flowline and up to the riser. Gas 0.8 • Intermediate-risk: 300 psi
Volume Fraction Note that the performance-measure values used to delimit the 0.2 three levels of hydrate-plugging risk in this study were determined from the current version of the gas-hydrate model, and may or may not underestimate the effect of hydrates in the fluid flow. These 0 values could be adjusted by improving the accuracy of the model 0 5 10 15 with further knowledge of the mechanisms of hydrate formation Pipeline Length (km) and transportability from future studies.
Fig. 5—Fluids distribution in terms of volume fraction along the Case 1: Low Production GOR and Low Water Cut. Case 1 repre- flowline length, corresponding to the steady-state flow predict- sents an early stage in the well life characterized by a liquid loading of ed by the transient gas-hydrate model for Case 1. 90 vol%, a water cut of 30%, and a production GOR of 570 scf/STB. The calculated temperature distribution along the flowline length is pre- of hydrates formed and hydrate transportability; hence nothing can sented in Fig. 4 with the hydrate-equilibrium temperature. The warm be said about the actual plugging-risk level of this system. fluids flowing from the well cool down at the beginning of the flowline The gas-hydrate model coupled with a transient multiphase-flow because of heat transfer to the ocean (ambient temperature of 4°C) until simulator can be used to determine the flowline operating condi- a subcooling temperature of 3.6°C is reached when hydrates nucleate. tions and estimate the amount and transportability of gas hydrates The hydrate heat of formation raises first the temperature of the system, at different periods of the well life. During the well life, an increase then the heat transfer to the ocean balance with the heat of formation, in the GOR and in the water cut is expected, which represents the making the system temperature equal to the hydrate-equilibrium tem- feed of fundamental components for the formation of gas hydrates. perature in a condition known as heat transfer limited until all the gas This means that different periods in the well life are characterized is converted completely into hydrates and the hydrate-formation reac- by different magnitudes of GOR and water cut, resulting in dif- tion stops. The system cools down until the seabottom temperature is ferent amounts and transportability of hydrates in the system. On reached, with no further hydrate formation. Then, the system tempera- the basis of this information, hydrate-remediation techniques can ture increases and hydrates dissociate flowing up the riser. also differ for different periods in well life. In this study, we con- The plot of fluids distribution shown in Fig. 5 supports the expla- sider three different scenarios representing periods in the well life: nation previously presented for the system-temperature behavior. It (i) an early stage with low production GOR and low water cut (Case can be observed at the beginning of the flowline that the liquid volume 1), (ii) a middle stage with an increased GOR (Case 2), and (iii) a fraction started at 0.9 (i.e., 90 vol% liquid loading) and increases up late stage with higher GOR and higher water cut (Case 3). to a 100% liquid loading in the flowline; at the same time, the gas The hydrate-plugging risk is determined from the calculation of volume fraction is reduced because of a decrease in temperature and three performance measures (DPflowline is the pressure drop along its consumption during hydrate formation. Some hydrates accumulate the flowline, fhyd is the hydrate volume fraction in pipe, and mr is at the base of the riser, but then are transported and melted up the riser. the hydrate slurry relative viscosity) and is classified in three quali- Fig. 6 shows the ratio of hydrate-slurry viscosity to the viscosity of tative levels as follows: the continuous oil phase; a maximum hydrate-slurry viscosity of 3.4
50 Oil and Gas Facilities • October 2012 October 2012 • Oil and Gas Facilities 51 3.5 60 Hydrate equilibrium temperature 50 3 System temperature 40 scosity
Vi 2.5 30
lative 2 20 Re
ry 10 Temperature (°C)
ur 1.5
Sl 0
1 -10 0 5 10 15 0 5 10 15 Pipeline Length (km) Pipeline Length (km)
Fig. 6—Hydrate-slurry relative viscosity along the flowline Fig. 7—Temperature distribution along the flowline length, length, corresponding to the steady-state flow predicted by the showing system temperature and hydrate equilibrium temper- transient gas-hydrate model for Case 1. ature corresponding to the steady-state flow predicted by the transient gas-hydrate model for Case 2. 1 10
Gas 0.8 8 Liquid Water 0.6 Hydrate 6
0.4 4 Volume Fraction 0.2 2 Slurry Relative Viscosit y
0 0 0 5 10 15 0 5 10 15 Pipeline Length (km) Pipeline Length (km)
Fig. 8—Fluids distribution in terms of volume fraction along the Fig. 9—Hydrate-slurry relative viscosity along the flowline flowline length, corresponding to the steady-state flow predict- length, corresponding to the steady-state flow predicted by the ed by the transient gas-hydrate model for Case 2. transient gas-hydrate model for Case 2. times the oil viscosity can be observed, with a location that coincides because of a decrease in temperature and gas consumption during hy- with an accumulation of hydrates at the base of the riser in Fig. 5. drate formation. In this case, water is consumed almost completely In general, Case 1 is considered to have a low risk of hydrate during hydrate formation because of the increased GOR from the plugging because the calculated flowline pressure drop of 230 psi well. Hydrates are melted on their way up the riser. But now a greater is less than the specified limit of 300 psi, the maximum hydrate amount of hydrates, when compared to Case 1, is present in the flow- fraction in pipe of 0.09 is less than 0.10, and the maximum hydrate- line, and could represent a higher risk of accumulating, jamming, and slurry relative viscosity of 3.4 is less than 10. plugging during flow through a restriction or change in flow direction. Fig. 9 shows the ratio of hydrate-slurry viscosity to the viscosity of the Case 2: Increased GOR. Case 2 represents a middle stage in the continuous oil phase along the flowline length; a maximum hydrate- well life characterized by a liquid loading of 79 vol%, a water cut slurry viscosity of 8.9 times the oil viscosity can be observed. of 32%, and a production GOR of 894 scf/STB. Fig. 7 shows the Case 2 is considered to have an intermediate risk of plugging calculated-temperature distribution along the flowline length and with hydrates because the calculated flowline-pressure drop of 398 the hydrate-equilibrium temperature. In a fashion similar to that psi is between the specified lower limit of 300 and the upper limit of Case 1, the warm fluids flowing from the well cool down at the of 500 psi, and the maximum hydrate fraction in pipe of 0.30 is beginning of the flowline until a subcooling temperature of 3.6°C greater than 0.10. is reached when hydrates nucleate. The hydrate heat of formation Considering the previous results and the estimated hydrate-plug- raises the temperature, and the system becomes heat-transfer-lim- ging risk, the gas-hydrate model was used to study the performance ited until all the additional gas is converted into hydrates, consum- of THI injection, with the objective of determining the optimum ing the free water. When the hydrate-formation reaction stops, the ethanol concentration needed to lower the hydrate-plugging risk of system cools down, reaching the seabottom temperature with no Case 2 to a low-risk level. Fig. 10 shows three plots of the per- further hydrate formation. Then, the system temperature increases formance measures (DPflowline, fhyd, and mr) used to establish the and hydrates dissociate, flowing up the riser. hydrate-plugging risk as function of ethanol concentration. It can Fig. 8 shows a plot of fluid distribution along the flowline length. be observed that the injection of ethanol reduces the performance It can be observed at the beginning of the flowline that the liquid- measures up to an ethanol concentration of 30 wt%. The pressure volume fraction started at nearly 0.8 and increases until the flowline is drop along the flowline has a minimum value at 30 wt%, while the filled by liquid; at the same time, the gas-volume fraction is reduced hydrate-volume fraction in pipe and the hydrate-slurry relative vis-
52 Oil and Gas Facilities • October 2012 October 2012 • Oil and Gas Facilities 53 2.75 0.4 10
2.7 8 0.3
2.65 6 0.2 2.6 4
0.1 2.55 2 Hydrate Volume Fraction
2.5 0 Hydrate Slurry Relative Viscosity 0
Pressure Drop Along Flowline (MPa) 0 10 20 30 40 0 10 20 30 40 0 10 20 30 40 Ethanol Concentration (wt%) Ethanol Concentration (wt%) Ethanol Concentration (wt%)
Fig. 10—Performance measures (ΔPflowline, fhyd, and μr) used to establish the hydrate-plugging risk as a function of ethanol concen- tration, predicted by the transient gas-hydrate model for Case 2.
40 1 Hydrate equilibrium temperature Gas 30 System temperature 0.8 Liquid Water 20 0.6 Hydrate
10 0.4 Volume Fraction Temperature (°C) 0 0.2
-10 0 0 5 10 15 0 5 10 15 Pipeline Length (km) Pipeline Length (km)
Fig. 11—Temperature distribution along the flowline length, Fig. 12—Fluids distribution in terms of volume fraction along showing system temperature and hydrate-equilibrium tempera- the flowline length, corresponding to the plugged conditions ture corresponding to plugged conditions predicted by the tran- predicted by the transient gas-hydrate model for Case 3. sient gas-hydrate model for Case 3. Case 3: Higher GOR and Higher Water Cut. Case 3 represents 4 a late stage in the well life characterized by a liquid loading of 10 67.4 vol%, a water cut of 52.5%, and a production GOR of 1,677 scf/ STB. Fig. 11 shows the calculated-temperature distribution along the flowline length and the hydrate-equilibrium temperature at the 3 10 plugged condition. A great portion of the flowline length is at very low temperatures. The system temperature increases and follows the hydrate-equilibrium temperature in the direction of the riser. 2 10 Fig. 12 shows the plot of fluids distribution along the flowline length. It can be observed that the liquid loading remains fairly high and the gas volume fraction decreases slightly, but the water 1 volume fraction decreases from the beginning of the flowline until 10 it is completely consumed in the hydrate-formation reaction, re-
Slurry Relative Viscosity sulting in a massive accumulation of hydrates in the middle of the flowline. Fig. 13 shows the ratio of hydrate-slurry viscosity to the 0 10 viscosity of the continuous oil phase (in a logarithmic scale) along 0 5 10 15 the flowline length; it can be observed that the maximum hydrate- Pipeline Length (km) slurry viscosity reaches values greater than 1,000 times the oil vis- cosity, confirming the formation of a hydrate plug. Fig. 13—Hydrate-slurry relative viscosity along the flowline In Case 3, the viscous hydrate slurry formed prevents the fluid length, corresponding to the plugged conditions predicted by the transient gas-hydrate model for Case 3. from flowing to the flowline plugs. This case has a high risk of plugging with hydrates because the calculated flowline-pressure drop of 1,303 psi is greater than 500 psi, the maximum hydrate cosity become constant, indicating a complete dissociation of hy- fraction in pipe of 0.55 is greater than 0.40, and the maximum hy- drates. The ethanol injection reduces the hydrate-plugging risk to a drate-slurry viscosity is too high. safer operation point if the injected concentration is greater than or The gas-hydrate model was used to study the performance of equal to 30 wt% of ethanol. THI injection at the conditions of Case 3, with the objective of de-
52 Oil and Gas Facilities • October 2012 October 2012 • Oil and Gas Facilities 53 4 10 0.8 10
3 8 0.6 10
2 6 0.4 10
1 4 0.2 10 Hydrate Volume Fractio n 0
2 0 Hydrate Slurry Relative Viscosity 10
Pressure Drop Along Flowline (MPa) 0 10 20 30 0 10 20 30 0 10 20 30 Ethanol Concentration (wt%) Ethanol Concentration (wt%) Ethanol Concentration (wt%)
Fig. 14—Performance measures (ΔPflowline, fhyd, and μr) used to establish the hydrate plugging risk as function of ethanol concen- tration, predicted by the transient gas-hydrate model for Case 3.
30 1 Hydrate equilibrium temperature Gas 25 System temperature 0.8 Liquid 20 Water Hydrate 0.6 15
10 0.4
5 Volume Fraction Temperature (°C) 0.2 0
-5 0 0 5 10 15 0 5 10 15 Pipeline Length (km) Pipeline Length (km)
Fig. 15—Temperature distribution along the flowline length, Fig. 16—Fluids distribution in terms of volume fraction along showing system temperature and hydrate equilibrium tempera- the flowline length, after 50 hours of shut-in, predicted by the ture, after 50 hours of shut-in, predicted by the transient gas- transient gas-hydrate model for Case 2 without ethanol. hydrate model for Case 2 without ethanol. measures. The pressure drop along the flowline exhibits a minimum 1 value at 10 wt% of ethanol injected, and increases with further in- crease in ethanol injection, which could be related to the increase in liquid content and the released gas from hydrate dissociation that 0.8 changes the multiphase-flow regime. The hydrate-volume fraction in pipe and the hydrate-slurry relative viscosity decrease with in- creasing injected ethanol concentration up to an ethanol concentra- 0.6 tion of 30 wt%, where hydrates are completely dissociated. Ethanol injection prevents formation of a hydrate plug and remediates the hydrates completely if the injected concentration is greater than or 0.4 equal to 30 wt% of ethanol, reducing the hydrate-plugging risk. Well-Restart-Procedure Optimization
Valve Opening (fraction) 0.2 Considering Case 2, which showed an intermediate risk of plug- ging with hydrates, the gas-hydrate-prediction model is used to study the effect of hydrates in transient shut-in/restart operations and the system performance as a function of THI concentration in 0 0 20 40 60 80 100 120 the shut-in/restart procedure. Two valves are included in the model Time (min) to control the shut-in and restart operations, one valve located at the wellhead and another located at the platform end. Fig. 17—Fig. 17—Valve-opening schedule used during the During the shutdown of production, the valves are closed for 50 restart of production. hours, allowing the gravitational segregation of fluids in the system toward a hydrostatic and thermal equilibrium. Fig. 15 shows the termining the optimum ethanol concentration needed to lower the system temperature distribution after 50 hours of shut-in and the hydrate-plugging risk to a low risk level. Fig. 14 shows three plots of corresponding hydrate-equilibrium temperature for Case 2 without the performance measures (DPflowline, fhyd, and mr) used to establish ethanol injection. A maximum subcooling of 12°C is observed over the hydrate-plugging risk as function of ethanol concentration. It can a great portion of the flowline. However, the amount of hydrates be observed that the injection of ethanol reduces the performance formed during the rearrangement of fluids in the flowline following
54 Oil and Gas Facilities • October 2012 October 2012 • Oil and Gas Facilities 55 5 0.25
4 0.2
3 0.15
2 0.1
1 Hydrate Volume Fraction 0.05 Pressure Drop Along Flowline (MPa) 0 0 0 500 1000 1500 0 500 1000 1500 Time (min) Time (min)
Fig. 18—Evolution of the production restart in terms of pressure drop along the flowline (left plot) and hydrate volume fraction (right plot) at a point in the middle of the flowline with respect to time, predicted by the gas-hydrate model for Case 2 with 20 wt% ethanol injected before the shut-in and during the restart.
the shutdown of production is not significant, as shown by the fluid- remains nearly constant between 10 and 20 wt% ethanol, then in- distribution profile in Fig. 16, which is similar to the one presented in creases, showing a local maximum at 25 wt% ethanol, and decreases Fig. 8 for the steady-state operation of the well. An accumulation of with further increase in ethanol concentration. The hydrate-slurry rel- water toward the low spot near the wellhead and the migration of the ative viscosity shows a behavior similar to that of the hydrate-volume gas toward the topside in the riser can be observed; some accumu- fraction, exhibiting a local maximum at 25 wt% ethanol. Ethanol in- lation of unconverted water also takes place at the base of the riser, jection improves the system performance upon restart, reducing the which is separated from the gas by an oil layer. hydrate-plugging risk. A concentration of 20 wt% ethanol seems to be After 50 hours of shut-in, the production is restarted following the optimum concentration to use in transient operations. the valve-opening schedule shown in Fig. 17. This valve-opening schedule is similar to an optimized valve-opening schedule de- Conclusions signed to minimize hydrate formation upon restart by Zerpa et al. A gas-hydrate model that predicts the formation and transportability (2011) using the same hydrate-prediction model, where production of hydrates in flowlines can be used for the design and optimization is restarted using a valve opening of 1% for 60 minutes, then in- of subsea transport facilities; can aid in the development of safe op- creasing progressively until the valves are fully open. erational procedures; and can be used for the prevention, manage- During the restart of production at different THI concentrations ment, and remediation of hydrates in flowlines. This paper presents (from 0 to 40 wt% of ethanol), it was found that an accumulation of a gas-hydrate model specially designed for oil-dominated systems, hydrates was formed by the initial movement of fluids, and this ac- which is coupled with a transient multiphase-flow simulator for the cumulation is transported through the flowline by a wave front. Fig. prediction of gas-hydrate formation and transportability in pipelines. 18 shows the evolution of the restart of production in terms of pres- The gas-hydrate model was used to estimate the hydrate-plugging sure drop along the flowline as a function of time (left plot) and the risk of an offshore well with geometry and fluid properties typical of hydrate-volume fraction at a fixed point in the middle of the flowline those in the Caratinga field located in the Campos basin, Brazil, al- as a function of time (right plot), for Case 2 with 20 wt% ethanol in- lowing the estimation of the hydrate-plugging risk at three different jected before the shut in and during the restart. It can be observed that periods of the well life. The hydrate-plugging risk was estimated pressure drop increases with time, exhibiting a large peak at approxi- from the calculation of three performance measures (pressure drop mately 200 minutes, which coincides with the large peak of hydrate- along the flowline, hydrate-volume fraction in pipe, and hydrate- volume fraction. This peak represents the hydrate accumulation that slurry relative viscosity) in an attempt to quantify the plugging risk. travels along the flowline transported by the wave front and is fol- The hydrate-plugging risk depends on the amount of water and gas lowed by a bank of fluids with no hydrates; then, the system equili- flowing from the well; therefore, the hydrate-plugging risk could in- brates, reaching a stable value. This hydrate accumulation that moves crease with well life because different periods in the well life are through the flowline upon restart represents a critical condition and characterized by different magnitudes of GOR and water cut. is used to quantify the hydrate-plugging risk. The gas-hydrate model was applied to study the performance of The system performance during the restart procedure is evaluated ethanol injection in steady-state flow and transient shut-in/restart for different ethanol concentrations using, as performance measures, operations. In general, ethanol injection decreased the hydrate- the maximum values reached during the initial stage of restart of the plugging risk in steady-state and transient operations. The appli- following variables: pressure drop along the flowline, hydrate-volume cation of the transient gas-hydrate-prediction model proved to be fraction, and hydrate-slurry relative viscosity. Fig. 19 shows three useful in determining the optimal ethanol concentration that mini- plots of the performance measures (max{DPflowline(t)}, max{fhyd(t)}, mized the hydrate-plugging risk. and max{mr(t)}) used to establish the hydrate-plugging risk as a func- tion of ethanol concentration. It can be observed that the injection of Nomenclature ethanol reduces the performance measures. The maximum pressure As = surface area between water and hydrocarbon phases drop along the flowline exhibits a minimum value at 20 wt% eth- per unit volume, L2/L3, m2/m3 anol injected, and increases with further increase in ethanol injection, dA = hydrate-agglomerate diameter, L, m which could be related to the balance between the decrease in hydrate- dP = hydrate-particle diameter, L, m slurry viscosity and the increase in liquid loading by the inhibitor in- f = fractal dimension 2 jection. The maximum hydrate-volume fraction in pipe decreases and Fa = normalized interparticle adhesion force, m/t , mN/m
54 Oil and Gas Facilities • October 2012 October 2012 • Oil and Gas Facilities 55 3 5.5 0.4 10
0.35 2 5 10 0.3
0.25 1 4.5 10
0.2
0 4 Max. Hydrate Volume Fraction 10 0 10 20 30 40 0 10 20 30 40 0 10 20 30 40 Max. Hydrate Slurry Relative Viscosity
Max. Pressure Drop Along Flowline (MPa) Ethanol Concentration (wt%) Ethanol Concentration (wt%) Ethanol Concentration (wt%)
Fig. 19—Performance measures—max{ΔPflowline(t)}, max{fhyd(t)} and max{μr(t)}—used to evaluate the hydrate-plugging risk as a function of ethanol concentration in transient restart operations, predicted by the transient gas-hydrate model for Case 2.
2 2 k1 = intrinsic Rate Constant 1, m/L /t/T, kg/m /s/K Turner, D.J. 2006. Clathrate Hydrate Formation in Water-in-Oil Dispersions. k2 = intrinsic Rate Constant 2, T, K PhD thesis, Chemical Engineering Department, Colorado School of mgas = mass of gas, m, kg Mines, Golden, Colorado. t = time, T, s Turner, D., Boxall, J., Yang, S., et al. 2005. Development of a Hydrate Kinetic Thyd_eq = hydrate equilibrium temperature, T, K Model and its Incorporation into the OLGA2000® Transient Multi- Tsystem = system temperature, T, K phase Flow Simulator. Proc., 5th International Conference on Gas Hy- u = scaling factor to include transport resistances to the model drates, Trondheim, Norway, Paper No. 4018, 1231–1240. 2 D Pflowline= pressure drop along the flowline, m/L/t , MPa Vysniauskas, A. and Bishnoi, P.R. 1983. A kinetic study of methane hy- DTsub = subcooling, T, K drate formation. Chem. Eng. Sci. 38 (7): 1061–1072. http://dx.doi. γ = shear rate, 1/t, 1/s org/10.1016/0009-2509(83)80027-X. mO = oil viscosity, m/L/t, Pa.s Zerpa, L.E., Sloan, E.D., Sum, A., and Koh, C. 2011. Generation of Best mr = relative viscosity of the hydrate slurry to the viscosity Practices in Flow Assurance Using a Transient Hydrate Kinetics Model. of the continuous oil phase Paper OTC 21644 presented at the Offshore Technology Conference, feff = effective volume fraction of the agglomerated hydrate Houston, 2–5 May. http://dx.doi.org/10.4043/21644-MS. particles fhyd = hydrate-particle volume fraction Luis E. Zerpa is a PhD candidate with the Center for Hydrate Research at fmax = maximum packing fraction the Colorado School of Mines (CSM). His research interests are natural gas hydrates in flow assurance and multiphase flow modeling. Before Acknowledgments attending CSM, he was an assistant professor at the University of Zulia, We acknowledge the support from DeepStar and the CSM Hydrate Con- Venezuela. He holds BS and MS degrees in mechanical engineering sortium (currently sponsored by BP, Chevron, ConocoPhillips, Exxon- from the University of Zulia. Mobil, Nalco, Petrobras, Shell, SPT Group, Statoil, and Total), and thank Alexandre Mussumeci de Freitas (formerly at Petrobras) for providing the E. Dendy Sloan, Jr., is University Emeritus Professor of the Chemical and typical geometry and fluid properties from the Caratinga field. The first Biological Engineering Department and Co-Director of the Center for Hy- author acknowledges the support of the Roberto Rocca Education Pro- drate Research at CSM. His research interests are natural gas hydrates gram through the Roberto Rocca Fellowship Award. in flow assurance and science. Before joining CSM, he was a Senior En- gineer with E.I. DuPont deNemours, Inc. In 2011, Sloan was given the References Lifetime Achievement Award by the International Conference of Gas Hy- Boxall, J.A. 2009. Hydrate Plug Formation from <50% Water Content Water- drates, and is a Fellow of the American Institute of Chemical Engineers. in-Oil Emulsions. PhD thesis, Chemical Engineering Department, Col- orado School of Mines, Golden, Colorado. Carolyn A. Koh is a professor of the Chemical and Biological Engineering Camargo, R. and Palermo, T. 2002. Rheological Properties of Hydrate Sus- Department and Co-Director of the Center for Hydrate Research at pension in Asphaltenic Crude Oil. Proc., 4th International Conference CSM. Her research interests are natural gas hydrates in flow assurance, on Gas Hydrates, Yokohama, Japan, 19–23 May, 880–885. energy storage and transportation, and applying molecular and meso- Hinze, J.O. 1955. Fundamentals of the hydrodynamic mechanism of split- scale tools to hydrate science and engineering. Koh holds BS and PhD ting in dispersion processes. AIChE J. 1 (3): 289–295. http://dx.doi. degrees in physical chemistry from the University of West London, U.K., org/10.1002/aic.690010303. and postdoctoral training at Cornell University in chemical engineering. Mills, P. 1985. Non-Newtonian behavior of flocculated suspensions. Journal de Physique Lettres 46: 301–309. http://dx.doi.org/10.1051/ Amadeu K. Sum is an assistant professor of the Chemical and Biological jphyslet:01985004607030100. Engineering Department and Co-Director of the Center for Hydrate Re- Sjöblom, J., Øvrevoll, B., Jentoft, G. et al. 2010. Investigation of the Hydrate search at CSM. At present, Sum is also a research associate professor Plugging and Non-Plugging Properties of Oils. J. Dispersion Sci. Technol. at Keio University as part of the Global COE Program. His main inter- 31 (8): 1100–1119. http://dx.doi.org/10.1080/01932690903224698. ests are in hydrates in flow assurance. Before joining CSM, Sum spent 4 Sloan, E.D. 2005. A changing hydrate paradigm—from apprehension to years as an assistant professor at Virginia Tech. He holds BS and MS de- avoidance to risk management. Fluid Phase Equilib. 228–229 (Feb- grees from the CSM and a PhD degree from the University of Delaware, ruary): 67–74. http://dx.doi.org/10.1016/j.fluid.2004.08.009. all in chemical engineering. His postdoctoral studies were at the Uni- Sloan, E.D. Jr. and Koh, C.A. 2008. Clathrate Hydrates of Natural Gases, third versity of Wisconsin, Madison. Sum is a recipient of the DuPont Young edition, Vol. 119. Boca Raton, Florida: Chemical Industries, CRC Press. Professor Award.
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