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SPE 124195

Simulation of Liquid Unloading From a Gas Well With Coiled Tubing Usinga Transient SoftwareP. Salim, and J. Li, BJ Services Company

Copyright 2009, Society of Petroleum Engineers

This paper was prepared for presentation at the 2009 SPE Annual Technical Conference and Exhibition held in New Orleans, Louisiana, USA, 47 October 2009.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not beenreviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, itsofficers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission toreproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

AbstractUnloading gas wells is one of the most common applications for coiled tubing (CT). Despite the large number of jobs

completed, fundamental questions about the optimum gas lift rate, run-in-hole speed and how much nitrogen is required

remain. This is because the unloading process is not steady state, and the commonly used CT computer simulations can only

model steady state flow.

This paper describes transient software that has been developed and used to determine the nitrogen volume and cleaningtime required when optimizing the process of liquid unloading from a gas well with CT.

Based on experimental test results with a full scale flow loop, a critical gas velocity model was developed. This model

determines how much liquid can be lifted for a given gas rate under varying operating conditions. It also determines theminimum gas rate required for complete liquid unloading. Several examples are presented which illustrate the transient

characteristics of the liquid unloading process. A few field cases illustrate the benefits of using the transient model and some

problems with conventional design methods.

IntroductionUnloading gas wells is a common operation in the oil industry. After workover operations the liquid used to kill or stimulate

the well must be unloaded from the tubing string to return the well to normal operation. Some wells naturally liquid load and

require a gas lift to put them back on production. Two techniques are commonly used to unload wells. One method wouldbe to use gas lift mandrels in the completion and pressurized gas in the area. Another is to inject nitrogen in the completion

with CT. The CT method will be our focus in this paper.

There are a few steady state design methods which can be used to design the liquid unloading process. One methodinvolves the generation of a family of curves comparing bottom hole pressure (BHP) and gas injection rate for various

assumed produced liquid rates, while holding CT size and circulation depth constant. Based on these curves, the potential

liquid unloading rate can be estimated at different injection rates for a particular condition. In order to estimate the liquid

unloading rate at other conditions, similar curves can be generated. However, with such conventional steady state designmethods, the transient behavior of liquid unloading process, i.e. pressure/fluid rate changing at the surface or at the bottom of

hole, can not be captured and the unloading time is poorly estimated. It will be shown that simulating transient behavior of

liquid unloading process is very important for the design and execution of that process.

Process design includes the determination of CT size, tripping speeds, nitrogen rate and surface choke setting. A good

design will bring the well back to production in a timely manner with minimal nitrogen consumption but sometimes thesegoals are compromised by surface fluid rates and dynamic BHP. Surface fluid rate can be crucial when there is limited

surface handling equipment as is common in many offshore operations. Dynamic BHP can be critical as some reservoirs are

very sensitive to fluid losses during the liquid unloading process.This paper describes transient software that has been developed and used to optimize the process of liquid unloading in a

gas well with CT. The transient model is validated with Lages (2000) full scale well test data and field operational data. The

transient feature of the unloading process is clearly captured by the software. The model tracks how the whole systemdynamically responds to changes in major operational conditions such as the variation of pump rate, choke size, and

downhole conditions. A critical gas velocity model was developed and incorporated into the software.


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Experimental Setup and Data CollectionThe flow loop, shown in figure 1, was used throughout this project. The loop consisted of a 20ft-long transparent lexan pipe

with a 5-inch inner diameter simulating the open hole and a 2-3/8-inch steel inner pipe simulating a gas lift pipe. The innerpipe was positioned on the bottom of Lexan pipe to simulate the worst case for the liquid removal (eccentricity = 100%).

The loop was mounted on a rigid guide rail and could be inclined at any angle in the range of 0 o-90ofrom vertical. A

schematic of the flow loop system is shown in figure 2. The annular test section is first filled with liquid after which the

centrifugal pump is shut down. Nitrogen is then flowed into the test section. After a steady state is established, pneumatic

actuating valves isolate the test section. The liquid and gas volumes in the annulus of the test section are then measured.From this information, the liquid holdup and the average in-situ velocity for gas phase can be determined. This liquid holdup

was called the zero net liquid flow (ZNLF) holdup. Tests were conducted at increasing gas rates until we reached the criticalgas rate at which the liquid from the test section was completely removed.

The flow rate was measured by two mass flow meters. The mass flow meters were equipped with a densitometer feature

that could measure the density of gas and liquid phases. Water, two different densities of brines and two different biopolymer

fluids were used to conduct the tests. Results were used to investigate the effect of liquid density and viscosity on the ZNLFholdup and the minimum critical velocity. For each liquid the tests were conducted at several different deviations. The

pressure inside of the test section could be controlled with a back choke. The maximum pressure inside of the test section was

150 psi. Most of tests were conducted with the choke fully open and a pressure of roughly 20 psi. A set of tests were also

conducted to investigate the effect of pressure on the critical velocity using the maximum test section pressure of 150 psi.

Test results showed that the ZNLF holdup increased with deviation angle reaching a maximum at about 55o, it thendecreased as the deviation angle increased. This was similar to the other investigators observations. For the same gas

velocity, the ZNLF holdup increased as the fluid density or viscosity increased. There was less ZNLF holdup when bottomhole pressure was increased due to increased gas density with pressure. More than 300 test data points were collected and

compiled into figure 3. It is shown that the ZNLF holdup could be correlated with a single curve as a function of the velocity

ratio between the gas superficial velocity and the gas critical velocity. A generalized correlation was developed to predict the

critical gas velocity at which all the liquid can be removed completely from the wellbore. Based on this correlation, the liquid

holdup can be predicted when the gas velocity is less than the critical velocity.

Transient ModelThe mathematical model of liquid unloading is based on the conservation of mass and a drift-flux model. One momentum

equation is solved and the slip velocity between gas and liquid phases is determined with steady state equations that considerthe flow regime. A steady-state isothermal temperature profile is assumed in the wellbore. The space domain is assumed to

be one dimension in axial direction and is discretised intoNnodes.

The conservation of mass is divided into two parts: (1) the conservation of mass for each gas and (2) the conservation ofmass for each liquid. The conservation of mass for gasjin node iis given by:

jigijigjig

Ft

V,

,,

=

(1)

and the conservation of mass for liquid kin node iis given by:

kilikilkil

Ft

V,

,,

=

(2)

11

,

1

, =+ =

=

=

=

lg nk

k

kil

nj

j

jig (3)

In Eqs. (1) to (3), jig, is the density of gasjin node i, kil, is the density of liquid kin node i, jig, is the volume

fraction of gas j in node i, kil, is the volume fraction of liquid k in node i, iV is the volume of node i, t is the time

variable, and jigF , and kilF, are respectively defined as the mass transfer of gasjand liquid kin node i:

jigoutijigigjiginijigigjigjig SAuAuF ,,,,,,,, = (4)

kiloutikililkilinikillikilkil SAuAuF ,,,,,,, = (5)


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SPE 124195 3

where igu , is gas velocity in node i, ilu , is liquid velocity in node i, iA is the flow area of node i, jigS , is the mass

source of gasjentering node i, and kilS , is the mass source of liquid kentering node i. igu , and ilu , in Eqs. (4) and (5) are

computed from the drift-flux model shown in Eqs. (6) and (7):

idimimig uucu ,,,, += (6)

im

idim

im

im

im

igil

c

uu

c

c

c

uu

,

,,

,

,

,

,,

+

=

= (7)

where imc , and imc , are distribution coefficients in node i, idu , is drift velocity currently assumed as zero, and imu , is

the mixture velocity in node iand is computed by means of the Bernoulli equation. In single phase flow, both imc , and

imc , are set to unity. In gas-liquid flow, imc , and imc , are estimated from a gas-liquid model (such as Taitel-Dukler

model, Duns-Ros model, etc.depending on the flow regime), but for particular cases in which the superficial gas velocity

becomes less than the critical gas velocity, imc , and imc , are estimated from the correlation generated from figure 3 to

account for the ZNLF holdup. After some mathematical manipulations for Eqs. (1) and (2), a Transient Pressure Equation is

generated and shown as Eq. (8) below:

( ) ( )t

VFF

t

PKKV i

lnk

k kil

kilgnj

j jig

jigilnk

kkilkil

gnj

jjigjigi

+

=

+

=

=

=

=

=

=

=

= 1 ,

,

1 ,

,

1,,

1,,

(8)

where: jigK , is the compressibility of gasjin node i, kilK , is the compressibility of liquid kin node i, and iPis pressure

in node i.Eqs. (1), (2) and (8) are categorized as an initial value problem and are solved from an initial condition where the initial

masses of each phase and the initial pressure and temperature of each node are known. For the computation stability and

speed, the equations are solved by using thefully implicitorbackward timenumerical scheme, in which a set of simultaneouslinear equations are solved at each time step.

The initial condition was obtained from asteady-statesimulation described by Craig (2003), Li et al.(2002), Misselbrook

et al.(1991), Nasr-El-Din et al.(2006), and Ovesen et al.(2003). Thesteady-statesimulation runs in Windows on a standardPC and is a powerful analytical tool that provides a complete evaluation for both flow and force analyses at each control

volume. The simulation has three main parts:

1. Input Parameters: Any well path, completion and CT combination can be described. Non-Newtonian and Newtonianfluids in single phase and energized mixtures can be considered. Reservoir pressure is specified, its flow rate can aid the

cleanout or not at the users discretion. Inputs are run through hundreds of validations prior to being sent to the

calculation algorithms. Extensive hints help guide the user to fix validation errors.2. Job Design: Typically one varies flow rates, fluid types, penetration rate, circulation and trip times to optimize the job.3. Output Information: The simulation generates outputs of all pertinent variables in both tabular and graphical formats. The

output includes pressure distribution, velocities of liquid and gas, liquid holdup and flow regimes both inside the CT and

in the CT/completion annulus. Information on shear rates, effective viscosity, flow regime, friction gradients and

hydrostatic gradients are also provided. Numerous warnings and messages are also generated to alert and guide the user

about potential problems.

The modeling for both the steady-state and transient flow with single or two-phase fluid in the coiled tubing application,pipeline application and other applications has been extensively validated with the full scale experimental data, field data, and

other data available in the public domain.

Simulation Results and Case StudiesFour cases related to the liquid unloading process are chosen for discussion in the following section. In case #1 the model is

compared to full scale well test data where a well is unloaded but continues to produce water. Case #2 discusses the effect of

main parameters (i.e. gas rate, the rate of penetration of CT, CT size, and wellhead pressure) on the unloading time and liquidreturn rate. This case study also shows some typical features of the transient unloading a gas well and how to utilize the

software to optimize the unloading process. In case study #3 the transient software was used to help design the job.

Simulation and field results are compared. In case #4 we again compare field results to the transient simulation but this job

design did not benefit from the transient simulation and relied only on conventional steady state methods.


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Case Study # 1: Model validation with the Full-Scale Well Test Data

A full-scale investigation was executed by Lage (2000) in a 1278 m vertical well with a drill pipe of 3.5 OD x 2.764 IDplaced inside a casing of 6.276 ID (seen in figure 4). Detail of the well setup was included in Lage (2000). Initially the well

is full of water. Water is then injected into the drill pipe at the rate of 160 gpm. 13 minutes later, nitrogen is also injected at

the rate of 300 scfm through a parasite string located at 760 m. The drill pipe remains stationary at 1262 m. The downhole

memory gauges were attached to the drillstring to record annular pressures at 998 m, 605 m and 185 m. The end of the

drillstring was open, this enabled the pressure sensor in the logging tool to be used as a real time monitor of the conditions at

the bottom of the drillstring.A transient simulation was conducted based on the Lages test condition. Choke size at wellhead was assumed to be fully

open and was set at 100 in./64. Figures 5 to 7 show the comparison between the simulation results and experimental data forcompletion pressures at 1262 m, 605 m and 185 m. During the simulation, u-tubing phenomena (Kalessidis et al., 1994) was

encountered in the drill pipe after 15:50 minutes. Pressure oscillations shown in figures 5 to 7 are related to how the transient

simulation handled the u-tubing phenomena. In general, the transient model is shown to reproduce the experimental results.

Case Study #2: Optimizing the Unloading Process with Transient Model

We were requested to optimize a well kickoff operation for a 10600 ft. vertical well. Perforations were located at 10,000 ft,

BHT is 250 oF, and WHT is 80 oF.

Reservoir characteristics:

7.022

10000.5

=

BfG

ppQ Mscf/D; Gas gravity = 0.65; Oil-to-Gas Ratio = 100 bbl/MMscf;

The well is filled with brine to 3200 ft and has a wellhead pressure of 150 psi (1 Mpa). During the liquid unloadingprocess, the coiled tubing is run into hole from 3000 ft to the bottom of the well (10600 ft) with a fixed rate of penetration

(ROP) and a fixed nitrogen pump rate. Once stable well production is achieved, nitrogen is stopped and the coiled tubing is

pulled out of hole. The affect of varying coiled tubing ODs (1.25, 1.5 and 1.75), coiled tubing ROPs (10 to 100 ft/min)and nitrogen pump rates (100 to 1500 scfm) on the time required to achieve stable well production was recorded.

For this comparison, the start of stable well production was arbitrarily defined as the first time that the bottom hole

pressure falls below 2700 psi. To illustrate some of the challenges in this case study detailed results were generated for onescenario. 1.25 OD coiled tubing is run into the well at 50 ft/min while pumping 700 scfm nitrogen, results are shown in

figures 8 to 11. The time to reach stable well production was recorded when the bottom hole pressure reached 2700 psi, this

occurred at approximately 71 minutes. At 71 minutes nitrogen pumping was stopped (shown in figure 8) and the coiled

tubing was pulled out of hole at the rate of 30 ft/min (shown in figure 9). Figure 8 also shows how transient delays can affect

the job design. N2was halted at 71 minutes but it took another 50 minutes for the reservoir and surface gas rates to reach a

steady-state.Figure 10 shows the pressure response versus time at key points in the well. You will notice that the initial pressure at the

perforations is 3300 psi, giving a 300 psi overbalance. Hence the reservoir is initially charged with kill fluid. Figure 11

shows reservoir and wellhead liquid rates versus time but excludes the initial charging rate. This was done to focus thegraph on some interesting details that occurred later. As the perforation pressure started to decline below pf (3,000 psi),

reservoir production increased as expected but then dropped around 59 minutes. This drop reflected the last of the kill fluid

and the fact that it could be produced back more easily than the produced fluids. A liquid slug around 90 minutescorresponded to the gas break through at surface (comparing figures 8 and 11). It was encouraging to note that the simulation

predicted the liquid rate would spike before the gas rate on surface, this has been observed in many field operations. All the

parameters (i.e. pressures and surface rates of liquid and gas) approached a steady state 100 minutes after the initial unloading

process.

This scenario was then modified to test the affect of coiled tubing ODs (1.25, 1.5 and 1.75), coiled tubing ROPs (10 to100 ft/min) and nitrogen rates (100 to 1500 scfm). The typical results for the runs are presented in figures 12 to 14.

Figure 12 shows the time to reach stable well production for coiled tubing 1.25 OD at various ROPs and nitrogen pumprates. As observed in experiments the liquid unloading required a critical minimum gas velocity. Figure 12 shows thatnitrogen rates just above the critical gas velocity needed more time to reach stable well production. Also increasing the

nitrogen rate did not always result in reduced unloading times. Once an optimum N2rate is achieved the unloading time is

roughly constant. The optimum value changes with ROP. At an ROP of 10 ft/min, a nitrogen rate of 300 scfm appeared to

be the optimum. At 30 ft/min, a nitrogen rate of 500 scfm was required. At 70 ft/min, the optimum nitrogen rate was 900. Infigure 12 we can see that the slope of the total consumed N2 volume changes around the optimum N2 rate. In addition,

increasing ROP from 10 to 30 ft/min showed remarkable reduction in liquid unloading time, but ROPs beyond 30 ft/min did

not.

Figure 13 plots the average liquid unloading rate for various gas rates and ROPs. For a given injection gas rate, a higher

ROP results in a higher liquid unloading rate at the surface. Similarly for a given ROP, the higher the injection gas rate is, thehigher the liquid unloading rate will be. Figure 13 indicates that the reduction in kick off times with increasing nitrogen rate

tends to flatten off in all ROP curves. This trend also indicates that there is an optimum gas rate for a given ROP curve.


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Figure 14 shows how the CT size affects the average unloading liquid rate at the surface. For a given injection gas rate, a

larger CT would result in a higher unloading liquid rate. However, it seems that the CT size would not affect the optimum gasinjection rate and for this scenario in figure 14, it is about 700 scfm. The optimum gas injection rate is mainly affected by the

RIH speed.

In general the surface equipment (separator, choke size and surface return line) is selected according to normal well

production rates. However unloading operations usually required significantly higher rates. If the surface equipment is

undersized, dramatically higher well head pressures (WHP) can result. Figure 15 shows how increasing WHP affects the time

to reach stable well production. Higher WHPs result in longer unloading times as the pressure increases gas density which inturn reduces gas velocity and hence the efficiency of the whole process

After considering CT availability in the operating region and other logistical issues, it was recommended to use 1.5 CT,a RIH speed of 50 ft/min and a nitrogen rate of 700 scfm.

Case Study #3: N2Well Unloading and Cleanup Assistance

A subsea water injector in the Caspian Sea was completed with an expanded sand screen and downhole flow control devices

to inject water between two isolated sands in the formation. The well profile and wellbore information are plotted in figures

16 and 17, respectively. The well is 3924.2 m MD with a maximum deviation of 57o. After swapping the well bore fluid over

to base oil it was planned to assist the well flowback and cleanup using coiled tubing N 2circulation. While cleaning up, the

N2rate is adjusted to generate the desired drawdown across the sand-face/screens.

The BHA included a down hole memory gauge which collected the down hole pressure and temperature near theBHA/circulation point during the liquid unloading process. Downhole completion pressure was recorded with a transducer

installed in the well at 3648 m MD.

Job Details:Figure 18 shows operational details recorded in the field. The flowhead valves were opened and CT was RIH

circulating N2.The N2rate used was the minimum critical gas rate determined by the transient software. At 210 m the CT was

stopped and it was confirmed that the fluid quantity recovered in well test surge tanks was equivalent to the landing stringvolume. With the fluid unloaded from the landing string confirmed, CT continued to RIH and N 2was circulated at a rate

lower than the critical rate.

After 200 min the coil reached 850 m (30owellbore deviation) and fluid returns were lost at surface. After shutting down

the N2 rate was again increased to its critical value and fluid returns were re-established. CT was then RIH as the well

started to flow. Real time downhole gauges confirmed reservoir drawdown.With the CT parked at 2500 m N2rate was changed in an attempt to control the drawdown on the well. BHP stabilized at

approximately 2500 psi and the decision was made to RIH with CT to 3000 m. It was hoped that running to 3000 m would

increase drawdown on the well.At 3250 m the N2supply was exhausted by circulating at 900 scfm for a further 14 hours. During this period, the desired

500 psi drawdown was generated downhole and controlled by adjusting the surface choke in the range of 54/64 60/64.With this drawdown, the well flowed an average of 4500 bbl/day (3500 bbl/day low 5500 bbl/day high). CT pull tests were

conducted continually throughout the duration of the well flow period.CT was pulled out of the well without circulating N 2. The flowhead swab valve and surface choke were closed. The CT

reel was clamped and the well was monitored for 8 hours. Injectivity tests were conducted on both zones and a tracer

chemical was displaced into the formation. CT equipment and surface iron were rigged down.

Job Modeling: It was unknown if 1 CT could unload a 9-5/8 riser. It was believed that the well would flow with N 2

assistance after being kicked off, but first the hydrostatic column had to be reduced enough to initiate reservoir flow.

Extensive transient modeling was carried out and the results indicated that liquid unloading was indeed possible. Intermittentor slug flow was predicted at the start of the unloading process but this would change to continuous flow once the well

drawdown was established. Surface flows during the job confirmed this prediction.

After the job the actual data run with the transient software and the results are shown in figure 19. A reservoir PI of 9.4

bbl/day/psi was calculated from the well test data and was used in the modeling. A few observations: Figure 19 indicates continuous flow is established after 250 minutes, this was confirmed by the well test package.

Figure 20 shows that predicted pressure trends (WHP, CTP, BHP and BHAP) match well with job data.

The model accurately predicted the critical gas velocity required for unloading the 9-5/8 riser. After running through the

riser and stopping at 210 m the volume of fluid returned was equal to the riser volume (60 bbls).

As seen in figure 19 the model predicts flow slugging after 150 min. This was noted on the job and after 200 min the CTwas halted at 850 m and the N2 was shut down. After some discussion the N2 rate was again increased beyond the

predicted critical gas rate. Both the simulation and job observations confirmed that continuous returns were re-established

and maintained. A 10-20 minute delay between changing N2rate and BHP change was predicted by the model and confirmed by job data.

In the end the well was flowed back for approximately 28 hours with 4600 bbls of oil being recovered from the reservoir.

The average drawdown generated downhole during the flowback was 500 psi. This method of cleanup resulted in far greater

fluid volumes being recovered from similar wells using well surge methods.


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Although not used here another approach to well clean up involves tripping to total depth (TD) first. Figure 21 shows the

surface return rates for both liquid and gas phase when N2is not circulated during the CT RIH but is circulated at 1500 scfmonly when CT reaches TD (3250 m MD). The liquid return rate when N 2is not circulated during CT RIH is almost double

that when N2is circulated during RIH (see figure 21). In this case the higher return rate would have caused a problem for the

surface separator. The model also predicted that the time to unload the well is less when circulating only on bottom and not

during RIH. Again the potential for a severe slug determined that unloading as the CT was RIH was the safest option.

Actual well performance parameters (BHP gauge data, CT BHA memory gauge data, CTP, WHP, N 2circulation rate,

well flow rates) were measured and compared closely with the results of the transient software. Given the model is the onlymeans of evaluating the feasibility of future well unloads, it was important to gain an understanding of actual versus

predicted well behavior. Having the real time downhole pressure gauge data displayed in the CT cab was very beneficial inhelping control the drawdown being placed on the well. The quickest way to control bottom hole pressure is by adjusting the

returns choke. Changing the N2rate was much slower. There was a delay of 10-20 minutes between changing N 2rate and

noticing a change in the bottom hole pressure.

Case Study #4: N2 Lifting the Post Acidizing Liquid

A horizontal gas well with TMD of 6255 m and TVD of 4306 m was drilled in the Canadian Turner Valley formation. The

well profile and the detail wellbore information are plotted in figures 22 and 23, respectively. The BHP was about 1885 psi

and the BHT was roughly 110 oC. The well is completed with a 3-1/2 production tubing to 4329 m, 3-1/2 slotted tubing to

4674 m and left open hole in the horizontal section to 6255m MD. The objective of this operation was to displace the acid inthe open hole section with a 2 tapered CT. After displacement of the treatment fluids, N2was used to unload the well.

Job details of the acid stimulation and cleanup are shown in figure 24. This paper will focus only on the unloadingprocess which started 4260 minutes into the job. At this time the CT is at 5000 m and acid displacement is finished. Acid is

assumed to occupy the last 2000 m of the well giving it a fluid top of 4250 m. The unloading process was modeled using

field data for CT movement and nitrogen rates.

The unloading stage consisted of the following steps.1. Set choke size to 25 in/64.2. CT RIH from 3000 m to 4928 m at the rate of 30.48 m/min, N2rate small at 1 scm/min.3. At TD the simulation was given 260 minutes to achieve a steady state. Equilibrium between acid in the reservoirand that in the wellbore was achieved, but no acid was returned to surface.

4. Nitrogen pumping was varied as presented in figure 25.5. CT was moved to different location as seen in figure 25.Figure 25 shows how pressures at the BHA (pressure at the circulation point) varied in time with CT depth and N2pump

rate during the liquid unloading process. It indicates that the computed BHAPs are in fair agreement with the measuredBHAPs. The pressure spikes at the BHA due to the changes nitrogen rate and the CT depth are clearly captured by the

transient simulation. The dynamics of liquid going in and out of reservoir are shown in figure 26, as are the surface liquidoscillations that result. In figure 26 it can be seen that the predicted and measured reservoir flows didnt match. The

productivity index, bottom hole pressure and temperature and the choke schedule were all estimated or unknown. Bymaking changes to key bottom hole parameters theres a possibility that post simulation matching could lead to valuable

insights about the current reservoir state.

In this case the job design was conducted in the conventional steady state manner without the benefit of a transient

simulation. Both the actual job data and simulated results indicate that liquid was squeezed back into the reservoir during theunloading process. Obviously this was inefficient, future designs conducted with the transient software should help avoid or

at least mitigate this behavior.

ConclusionA sophisticated transient software for the CT application has been developed and used to study the transient behavior of

liquid unloading process. The following conclusions are drawn:

1. The simulation can accurately predict the transient behavior of the liquid unloading process with the proper inputinformation. The interaction between the reservoir and the wellbore could significantly affect the simulation results of the

transient behavior.

2. For a given wellbore condition, there is a minimum gas velocity above which all the liquid can be removed from thewellbore. This critical velocity is a function of liquid properties, wellbore deviation angle and the downhole pressure.

3. For a given RIH speed and CT size, the time to reach the start of stable well production could not be reduced once acertain N2rate was achieved, this is defined as the optimum N2rate.

4. For a given size of CT, a higher RIH speed would result in less time to unload the well with the same N2rate. Larger CTdiameters give higher liquid return rates when holding N2rate and RIH speed constant.

5. The transient simulation can be used to optimize the unloading process and generate a guide for the field engineer toexecute the job. Surface equipment, CT size, N2pump rate and a RIH/POOH procedure all have a significant affect on the

outcome.


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SPE 124195 7

AcknowledgmentsThe authors would like to express their appreciation to BJ Services Company, for the opportunity to present this paper. Wewish to further thank colleagues: Simon Smith and Bill Gavin to provide the field operation information; Manfred Sach, Bill

Aitken and Lance Portman for their valuable input and the time spent to edit the manuscript. The contribution of Dr. Marco

Teixeira, our previous colleague from 2000 to 2006, on the initial development of transient multi-phase simulation is highly

appreciated. Last but not least, the transient simulations user-interface would not have been as user-friendly without the great

contribution of Ee Ker who has initiated and maintained the user-interface codes since 2000.

NomenclatureBHA = bottom hole assemblyBHAP = pressure at the BHA or the circulation point

BHP = bottom hole pressure

BHT = bottom hole temperatureBHAT = temperature at the BHA or the circulation point

CT = coiled tubing

CTP = pressure at CT injection pointgpm = US gallon/min

ID = internal diameter

MD = measured depth

OD = outside diameterp

B= bottom hole pressure

pf= formation/reservoir pressure

PI = productivity indexPOOH = pull out of hole

QG= produced gas flow rate

RIH = run in holeROP = rate of penetration

scfm = standard cubic feet per minute

TD = target depth

TMD = total measured depth

TVD = true vertical depthVcrit= critical gas velocity below which the liquid can not completely removed

Vsg= superficial gas velocityWHP = wellhead pressure

WHT = wellhead temperatureZNLF =zero net liquid flow

SI Metric Conversion Factorsbblx159 E +00 = liter

gpm x 3.7854 E +00 = literftx0.3048 E +00 = m

inch x25.4 E 03 = m

psix6.895 E +03 = Pa

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Li, J., Walker, S., and Aitken, B.: How to Efficiently Remove Sand From Deviated Wellbores with a Solid Transport

Simulator and A Coiled Tubing Cleanout Tool, SPE 77527 presented at the 2002 SPE Annual Technical Conference

held in San Antonio, TX, USA, September 29-October 2, 2002.

Misselbrook, J., Wilde, G., and Falk, K.: The Development and Use of a Coiled-Tubing Simulation for HorizontalApplications, SPE 22822 presented at the 66thAnnual Technical Conference and Exhibition of the Society of Petroleum

Engineers held in Dallas, TX, USA, October 6-9, 1991.


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8 SPE 124195

Nasr-El-Din, H.A., Al-Anazi, M.A., Balto, A.A., Proctor, R.J., and Saleh, R.M.: Challenging Wellbore Cleanouts with

Coiled-Tubing Made Easy with Computer Modeling Technology, SPE 100129 presented at the 2006 SPE/ICoTA CoiledTubing and Well Intervention Conference and Exhibition held in the Woodlands, TX, USA, April 4-5, 2006.

Ovesen, M., Sach, M., Laun, L., Gill, G.E., Juel, H.: Efficient Sand Cleanouts in Larger Wellbores Using Coiled Tubing: A

New Approach Making An Old Problem Simple, SPE 81727 presented at the SPE/ICoTA Coiled Tubing Conference

held in Houston, TX, USA, April 8-9, 2003.


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SPE 124195 9

Inner pipe

Lexan pipe

Water tank

1 m3

Check

valve

Checkvalve

Liquid N2

tank

N2 pump

& heating unit

PressureRelieve valve

Pressure

Relieve valve

Mass flow

meter

Mass flow

meter

Water line

N2 line

Separator

tank

Gate valve

Centrifugepump

Test section

H2O bypass

valve

vent

valve

valve

valve valve

valve

valve

Mass flow

regulator

valve

N2 bypass

valve

Figure 1 Photo of full scale flow loop Figure 2 Schematic of the flow loop system

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0.01 0.1 1

Vsg/Vcrit

Liquidholdup

Figure 3 Data compilation of liquid holdup under Figure 4 Well configuration for the full-scale tests in case #1

the zero net liquid flow condition (Courtesy of Lage, 2000)

1100

1200

1300

1400

1500

1600

1700

1800

1900

15:21 15:28 15:36 15:43 15:50 15:57 16:04 16:12

Time

Pressure,psi

Experimental Data (Lage, 2000)

Simulation Results

400

500

600

700

800

900

1000

15:21 15:28 15:36 15:43 15:50 15:57 16:04 16:12

Time

Pressure,psi


Simulation Results

Figure 5 Pressure at 1262m for case #1 Figure 6 Pressure at 605m for case #1


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10 SPE 124195

0

50

100

150

200

250

300

15:21 15:28 15:36 15:43 15:50 15:57 16:04 16:12

Time

Pre

ssure,psi


Simulation Results

0

500

1000

1500

2000

2500

0 50 100 150 200 250 300Time [min]

Wellhead Gas Rate Reservoir Gas Rate Pumped Gas Rate

Figure 7 Pressure at 185m for case #1 Figure 8 Simulated gas rates for case #2

Figure 9 Position and speed of the BHA for case #2 Figure 10 Simulated pressures for case #2

0.0

0.5

1.0

1.5

2.0

2.5

3.0

0 50 100 150 200 250 300Time [min]

Wellhead Liquid R ate Reservoir Liquid Rate Pumped Liquid Rate

0

50

100

150

200

250

300

350

400

0 200 400 600 800 1000 1200 1400 1600

Nitrogen pump rate, scfm

Timetoreachthestableproduction,min

0

20

40

60

80

100

120

140

ConsumedN

2,

Mscf

Consumed N2 with ROP=10 ft/min



Time with ROP=30 ft/min



Figure 11 Simulated liquid rates for case #2 Figure 12 Effect of N2rate and ROP on the unloading time

and N2consumption for 1.25 CT for case #2


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SPE 124195 11

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

0.5

0 200 400 600 800 1000 1200 1400 1600


Averageliquidretu

rnrateatthesurface,

bbl/min

ROP=10 ft/min

ROP=30 ft/min

ROP=70 ft/min

0

0.1

0.2

0.3

0.4

0.5

0.6

0 200 400 600 800 1000 1200 1400 1600


Averageliquidreturnrateatthesurface,

bbl/min

1.25"CT @ ROP=50 ft/min



Figure 13 Effect of N2rate and ROP on the average Figure 14 Effect of N2rate and CT size on the average

unloading liquid rate with 1.25 CT for case #2 unloading liquid rate at 50 ft/min of ROP for case #2

0

100

200

300

400

500

600

0 500 1000 1500

Well head pressure, psi

Timetoreachtheincipientofstablewellproduction,min

Figure 15 Effect of wellhead pressure on the liquid Figure 16 Wellbore profile for case #3unloading time for case #2

0

500

1000

1500

2000

2500

3000

0 500 1000 1500 2000 2500 3000 3500 4000

Measurement depth(m)

Verticaldepth(m)

0

10

20

30

40

50

60

70

Deviationangle(o),CompletionID

(in)

Vertical depth

Deviation angle

Completion ID

0

500

1000

1500

2000

2500

3000

3500

4000

0 100 200 300 400 500 600 700 800 900 1000 1100

Elapsed Time, min

WHP(ps

i),

CTP(psi),BHAP(psi),BHP(psi),CTDepth(

CirculateN2 to generatedesired drawdown, moveCT frequentlyRIHunloadingwellwith N2

CTdepth, m

Bottomholepressure(BHP), psi

Pressureatwellhead (WHP),psi

Pressureat CTinjection point (CTP), psi

PressureatBHA(BHAP), psi

Figure 17 Wellbore information for case #3 Figure 18 Field operation condition for case #3


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12 SPE 124195

Elapsed time [min]

0

500

1000

1500

2000

2500

3000

3500

4000

0 100 200 300 400 500 600 700 800 900 1000 1100

Elapsed Time,min

WHP(psi),CTP(psi),BHAP(psi),BHP(psi

Measured BHP

Predicted BHP

Measured BHAP

Predicted BHAP

Measured WHP

Predicted WHP

Measured CTP

Predicted CTP

Pressure at circulation point (BHAP), psi

Bottom hole pressure (BHP), psi

Pressure at wellhead (WHP), psi

Pressure at CT injection point (CTP), psi

Figure 19 Simulation results for case #3 Figure 20 Comparison of simulation results and field datafor case #3

0

1

2

3

4

5

6

7

8

0 200 400 600 800 1000 1200

Time, min

LiquidRate[bbl/min]

0

500

1000

1500

2000

2500

GasRate[scf/min]

Wellhead Liquid Rate

Wellhead Gas Rate

Pumped Gas Rate

Figure 21 Simulation results of fluids return at the surface Figure 22 Wellbore profile for case #4for case #3 without gas lifting during RIH period

0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

0 1000 2000 3000 4000 5000 6000 7000

Measurement depth (m)

Verticaldepth(m)

0

10

20

30

40

50

60

70

80

90

100

Deviationangle(o),CompletionID

(in)

Deviation angle

Vertical depth

Completion ID

0

1000

2000

3000

4000

5000

6000

7000

1000 2000 3000 4000 5000 6000 7000 8000 9000

Elapsed time, min

WHP(psi),CTP(psi),BHAP(psi),CTdepth(m)

0

100

200

300

400

500

600

N2rate(m

3/m

in),Liquidrate(LPM),BHAT(oC)

N2rate, m3/min

Pressure at the circulation point(BHAP), psi

Temperature at the circulation point(BHAT),oC

CT depth, m

Liquid rate, LPM

Unloading well with N2RIH/POOH and acidizing

WHP, psi

Pressure at CT injection point (CTP), psi

Figure 23 Wellbore information for case #4 Figure 24 Field operation condition for case #4


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SPE 124195 13

0

1000

2000

3000

4000

5000

6000

4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000

Time, min

BHAP(ps

i),

CTDepth(m)

0

5

10

15

20

25

30

35

40

45

N2Pump

Rate(scm/min)

Field Data - BHAP

Simulated BHAP

Field Data - CT Depth

Simulated CT Depth

Field Data - N2 Pump Rate

Simulated N2 Pump Rate

0

2

4

6

8

10

12

14

16

18

4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000

Time, min

Simulatedormeasured

liquidreturnrateatsurface(gpm)

-200

-150

-100

-50

0

50

100

Simulatedliqu

idrateatreservoir(gpm)

Simulated reservoir liquid rate

Simulated surface liquid rate

Measured surface liquid rate

Figure 25 Comparison of simulation results Figure 26 Simulated liquid rates for case #4

and field data for case #4

SPE 124195 MS(Encrypted)

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