foss & gaul.pdf

lmance Criteria with Operating Experience -

ABSTRACT Recent work performed with plunger lift in the Ven-

t u r a Avenue Field has indicated a much wider range of applicat~on for this method of lift than was hitherto believed possible. This paper presents the results of field work performed with plunger I ~ f t , cliscusses oper- ational techniques utilized, and describes the perfonn- ance characteristics of wells on plunger lift A correlation between theoretical computations and actual field da ta IS cleveloped and a techniclue devised for predicting lift gas and operating casing pressure recluirenients fo r a broad range of conditions w ~ t h several tubing sizes

INTRODUCTION A t the present time, over 100 wells out of some 600+

on Shell's productive leases In the Ventura Avenue Field a re being produced with plunger lift. Some 50 plunger-lift installations have been added in the last 3 years a s a result of the re-evaluation of the advan- tages and growing appreciation of t h ~ s inethod of lift, and a s many a s 40 more a r e contemplated in the n e s t few years. The majority of the new plunger-lift installations resulted from the conversion of chamber-lift and gas-lift wells to plunger lift, with the balance coming from high gas-liquid ratlo flowmg and rod or hydrau- lically pumped wells. Wells a r e being considered for plunger lifting a s they a r e pulled for ecluipmeiit repair, etc., or a s shortages of compressed gas develop because of additional high-volume wells being put on gas lift. This report analyzes the performance of a group of 85 plunger-llft wells on whlch considerable data had been gathered. The remaining wells so ecluipped hare essen- tially the same characteristics a s the group included in this report.

The Ventura Avenue Fleld 1s located on the central, structurally highest portion of the coinplesly faulted Veiitura anticline. The procluctive Pliocene measures a r e made up of thick sections of low-PI, interbeddecl silty sands ancl shales with producing depths ranging from 4,000 to 14,000 f t . The producing wells generally take in all o r par ts of one or more different zones ranglng in thickness froin 700 f t to 2,000+ f t A large number of the wells a r e blessed with high produced gas- licluicl ratios and it has been the desire to utilize this natural forinatlon energy tha t has prompted the exten- slve application of plunger l i f t to reduce: a, capital outlay for compressor capacity and well ecluipment; and R , operating costs fo r lifting the oil to the surface.

Ranges of application of plunger lift in Shell's portion of the Ventura Avenue Field a r e presented in Table 1 in terms of some of the significant nlechanical and resen70ir parameters

'Shell 011 Comi>ans, Ventura. Cahf +Presented at the s lmng nleetlng of the Pacific Coast Dlstr~ct. API Ulvlslon of Productlon, May 1965

- Ventura Avenue Field? Table 1

Depth, ft* Gross B/D Percent cut 1-90 Cycles per clay Gas-licluld ratlo, Mcf/Bbl Static bottom-hole pressure, psl 300-3,000 Operating casing pressure, psi Gross PI, B/D/psi

"Wells generally esu~pped wlth 7-111 caslng to top of the ~ r o d u c l n g zone. 5-ln perforated llner through the prodpcing zone, and 2%-1n tublng (EU to the llner top and buttress, Seal-Lock" etc. In the I~ner)

TYPES O F PLUNGER-LIFT OPERATION Three basic variations of plunger l i f t a r e used in the

wells under cl~scussion : a Conventional plunger l i f t without packer. b. Plunger-gas lift with packer and gas-lift valve. c. Plunger lift with packer and standing valve, open

inandrel on bottom A summary description of each of these types and a

discussion of the basic differences in operating techniques within each group follows.

Conve~~t~oi ia l Plunger Lift without Packer This is the most common inethod of the three men-

t~oned and takes 111 over 90 percent of Shell's plunger- lift wells 111 the Ventura Avenue Field slnce this per- inlts nlasiinuni pressure clrawdowil to the bottom of the zone These wells a re tubed down In the liner to within 100 f t of bottom or top of fill and can be equipped with outside-mounted unloading gas-lift valves to the top of the liner where necessary. The surface ecluipment con- sists of a plunger-lift b u ~ n p e r housing, pressure recorder, adjustable choke, motor valve, Fisher 4107U or Harold Brown DAP plunger- l~ft controller (or equivalent), and mechanical o r magnetic trigger to allow plunger arrival to override the controller. The operation used In the Ventnra Avenue F ~ e l d is based on the pressure-to-open, trigger-to-close principle, with a pressure- to-close safety cl~fferential shutoff to take over if the plunger ever falls to surface. A sketch of the surface equipment requlretl f o r this type of application is presented in Fig. 1, and some typical well charts a r e shown in F ig 2

Cycle frequency is determined by the P I of the well, tubing back pressure, plunger travel time, and available gas energy The greater the number of trips, the smaller the slug size, the lower the required operating casing pressure, the greater the dra~vdown, and the greater the product~on. Operating pressures attained with this

PLUNGER-LIFT PERFORMANCE CRITERIA WITH OPEI ZATING EXPERIENCE-VENTURA AVENUE FIELD 125

method of plunger l i f t a r e presented ~n graphical form in Fig. 3.

Plunger-Gas Lift with Packer and Gas-lift Valve This 1s a n effective Interim producing method f o r

medium-to-high volume, low gas-llqulcl ratio, high water- cut, high static bottom-hole pressure, hlghly elnulsified wells o r a n ultimate producing method for wells with relatively short producing intervals and/or productivity iildlces where little adclltlonal production would accrue from increasing pressure drawdown by tubing the wells to bottom. There a re currently two wells so equipped on Shell's Ventura leases.

The principal appllcation f o r this method of plunger lift is found in wells where the fluld is produced In such a n enlulslfied s tate tha t satisfactory gas-lift rising velocities cannot be obtained and excess~\~e gas break- through and subsequent fallback occurs even with the most efficient gas-lift valves. A plunger will In this case provlde a solld interface between the produced fluid and the l i f t gas.

Surface equlpinent fo r t h ~ s appllcation of plunger lift includes a bumper housing, without a trigger (since the tubing s tays open all the time), and a time-cycle controller with motor valve on the gas line. The cycle frequency is then determined by the "drop" and "up" time of the plunger and the time i t takes fo r all of the "tail" gas In the tubing behind the plunger to dissipate and enable the plunger to s ta r t fo r bottom.

Plunger Lift with Packer and Standing Valve, Open Mandrel This is a novel technique f o r converting low-PI, high

gas-liquid ratio wells (or those wlth short llners where tubing to bottom cannot be justified) from gas l l f t to plunger l l f t to save compressor capaclty by utilizing the natural fornlatlon energy to lift the fluid. The packer and standing valve serve no useful purpose in the plunger-lift operation, but do protect the well bore agalnst possible damage resulting from casing leaks.

Plunger L i f t Bumper Kouaing 7

P~essure Recorder

Overshot f o r Equalizi Casing md Tublng

Controller and

Conversion to plunger lift in this case is a simple matter and entails installing a conventional plunger- llft surface assembly, pulling the operating valve, b roach~ng the tubing using wlreline tools, and setting a n Otis (or equivalent) stop and footpiece on bottom. Thls procedure then provldes low-pressure gas storage capacity in the casing with communication through the empty mandrel - ln effect a conventional plunger-lift mstallatlon from the hner top.

TYPES O F PLUNGERS In order to meet the stringent demands of rapid cycle

frequency \vith sinall liquld loads in the Ventura Ave- nue Field, it has been found tha t plungers must incor- porate the followi~lg deslgn features ' 1 , ability to fall rapldly through gas and 11quid; 2, ability to effect a good seal against the tubing during the upward travel; 2, high degree of repeatability of valve operation; and 4, high shock and wear resistance. F ig 4 depicts three types of plungers In common usage i n the Ventura Avenue Field.

STARTING (UNLOADING) PLUNGER-LIFT WELLS An esternal source of gas is available a t Ventura

and 1s necessary to s ta r t up most of the plunger-llft wells, especially a f te r well pulliiig, prolonged shut-in periods or killing with load oil. The available kickoff and static pressures limit the type of \ire11 tha t can be unloaded without unload~ng valves This presents no problem, however, since convent~onal (outside-mounted) unloading valves can be run in high static pressure wells tha t cannot be unloaded by "rocking" or displacing sufficient fluld out of the well bore with gas.

DISCUSSION O F VENTURA AVENUE FIELD OPERATIONS

Fig. 3 shows how plunger llft compares with chamber llft In wells producing less than 20 bbl daily gross where the back pressure can be reduced by allowing the well to produce into the lower (atmospheric) pressure system The availability of a n adequate low-pressure system can, therefore, broaden the application of plunger llft to where ~t can cover the entire range of gross production rates from just a few to over 100 B/D. From the esperience gamed in producing into the "atn~ospheric" system (as shown in Flg. 3) ~t has been deduced and substantiated by actual field experience tha t proportionate improvements in plunger-lift performance can likewise be achleved by reducing the back pressure a t the well by other means, e.g., Increasing tubing size, eliminating sharp bends and tu rns in the cellar and/or t r a p farm, etc The effect of a 2-in. flow line (instead of 3-111.) on plunger-lift performance, is demonstrated in panel B of Fig. 5 Any saving In the time it takes f o r the tubnlg pressure to bleed down results in the plunger being able to make more cycles per day, picking up smaller loads each time. This, in turn, would allow the operation to be conducted a t a lower caslng pressure, hence lower bottom-hole pressure and increased pressure drawdo\vn, yielding inore

Fig. 1 -Surface Equipment for Plunger Lift I production.

126 D L. Foss AND R R. GAUL

Fig. 2a - Tubing lntake 7,578 Ft; Gross 22 BID; Cut 7 Percent; 200 Mcf/D Gas

Pig. 2b - Tubing lntake 8,305 Ft; Gross 33 B/D; Cut 1 1 Percent; 130 Mcf/D Gas

Fig. 2c -Tubing lntake 7,278 Ft; Gross 75 BID; Cut 28 Percent; 450 Mcf/D Gas

Fig. Id -Tubing lntake 8,632 Ft; Gross 50 BID; Cut 24 Percent; 290 Mcf/D Gas

PLUNGER-LIFT PERFORMANCE CRITERIA WITH OPERATING EXPERIENCE-VENTURA AVENUE FIELD 127

Fig. 2e-Tubing Intake 11,164 Ft; Gross 92 BID; Cut 6 Percent; 650 Mcf/D Gas

Fig. 4 - A. Conventional National Plunger B. Combination National - Turbulent-seal

Plunger C. Combination National - Turbulent-seal

- Friction Lock-ball Plunger

C.L. Average

0 1 I I I I I I I I I I 0 20 40 60 f3J 100

Cmss Pmduction, BID Legend:

X = wells in atmospheric system not corrected to 100 psi tubing pressure

P. L. = plunger lift (2.441 in.) C. L. = chamber lift (2.441-in. ID chamber with

1 %-in. dip tube)

*G~lbert, W E Flowing and Gas-l~ft Well Performance, API Drllllng and Productron Pracf~ce, 125 (1954).

Fig. 3 - Plunger-lift Bottom-hole Operating Pressures Compared with Other Gas-lift

Methods - Ventura Avenue Field (Corrected to 100 psi tubing pressure)

CASING

I TIME

low Line Valve opens

@ Fluid Arrives @ 10" Line Valve Closes @ Highest Tubing Pressure Minimum @ Plunger Failed t o Surface Differential Pressure Shut Off @ Slow Bleed O f f IXle t o 2" Flow Line or Other Restriction

Fig. 5 - Pictorial Representation of a Performance Chart

PERFORMANCE CRITERIA Plunger-llft wells can be operated wlth several meth-

ods of control ancl wlthin each method exlsts a broad range of posslble operating conditions which affect the fundamental plunger-lift parameters, viz , average casing pressure, tubing pressure, load size, gas requirements, and cycles per day. F o r these reasons the range of appllcatlon of plunger lift has been unclear and criteria fo r the optimum operation have not been well- established.

A method 1s developed here whereby the fundamental parameters can be predicted with a reasonable degree of accuracy for the pressure-open, tngger-close type of control where the flow-line valve is opened a t a preset casing pressure and is closed immediately when the plunger arrives a t the surface. Thls method 1s the most wldely used since gas reclulrements per cycle a r e mini- mal when compared with the other methods of control. Relationships a re developed and performance charts fo r 1.995-111 , 2 441-in, ancl 2 992-in. ID tubing a r e presented which a r e suitable fo r use in most typical oil fields in the 2,000- to 16,000-ft range, 0- to 6-bbl load size range, and 0- to 200-pslg tubing pressure range. (See Flg. 6-23, ~ncl. , 11. 132 to 140.) F o r fields which produce liqulds and gas which devlate froin the typical to a n y great extent, corrections should be applied to the fundamental formulae used. I n particular, a correction should be made for liquids of significantly higher viscosity than the typical 30-API crude used in the analysis. Although the method developed 1s theoretical, it is complemented with field experience where theory IS lacking. Data from 85 Ventura field wells equipped wlth 2 441-in. plungers correlate closely with the analysis.

The method developed describes the mechanical parameters of plunger lift wlthout reference to Inflow performance relationship or productivity index. The omission was purposely intended ~n order to prevent inisconceptlons regarding posslble llquld-production rates As indicated by W. E. Gilbert,' Inflow perfonn- ance relationship ( IPR) is a function of the type reservoir rather than method of lift and inclusion of the varlety of reservoir parameters would unduly compli- cate the technique However, a s shown by Example 2, the englneer can readily adapt the charts to predict production rates provided he supplies a n I P R relation- s h ~ p .

In the development of the performance charts, ~t was necessary to assume average or typical values f o r cer- tain of the well conditions in order fo r the charts t o have broad application. An effort was made to select values such tha t the prudent operator wlll be able t o achieve the predicted performance without unreasonable effort Should he have difficulty in achieving such performance, he is advlsed to check the operation f o r sub- standard, malfunctioning, or incorrectly operated equipment.

Determination of Average Casing Pressure A general pressure-balance equation for plunger-lift

'References are at the end of the paper.

operation when the plunger is a t any polnt In the tubing s tr lng and IS ascending wlth ~ t s liquld load can be es- pressed a s follows :

C n s i j ~ g presszire + presszcre Ace to we igh t o f gas col?tnzn - gas frlctzon pressztrc loss (crcsz~~g-tztbzng ctnn7tllts) =

gris f?.~ctlon press7tre loss V L t z t b~ng unclerneatl~ the plztngcr + press~cre due to w e z g l ~ t of gas colzo,zn 7 ~ 7 ~ - c lernec~t l~ plz~7tger + p l~ tnger frtctzox IJressltre loss + pressure reqltzrecl to lzft w e ~ g l l t o f pl7inger + pressure reqjizrecl to lzft w e ~ g l ~ t of lzqzizd + lzqziid f r~c t zon pressure loss + gas frtctlon p re s s~ t r e loss above plltnger + prcssltrc cl~te to wezqht o f g r ~ s colzinzn ribove the ~~17tnge)- + S I L ~ ~ C I C C tz~bzltg bclck pressltve + prcssztre to accozcnt for e7ztry o f prodztced lzqlctd zin- dewzeath plzcnger. (1)

During the period of time when the plunger travels upward, most of the foregoing factors a r e in a s tate of change, interacting with one another to satisfy the equation. Significant among these a re :

1. Tublng pressure decreases drastically from a pressure equal to (or nearly equal to) maslmum casing bulldup pressure to a minimum pressure which is controlled by separator pressure, a length of flow line, and a relatively low g a s flow rate.

2. Gas flow ra te decreases from a relatively high value (durlng tubing bleed-down) to a n ever- decreaslng rate a s the plunger nears the surface.

3. Casing pressure ordinanly decreases from a masimum to a minimum pressure (wlth 2%-in. tubing, 7-in. casmg, the change averages about 10 percent).

4. Plunger and liquid velocity changes from zero to approximately 1,000 ft/min average velocity. Also, i t seems possible t h a t the plunger with liquid may exceed the average velocity while st111 near bottom and then de-accelerate steadily until the plunger surf aces.

Wlth a glven set of well conditions, ~t is posslble to operate with a wide range of average casing pressures, but ~t is desirable to operate a t the lowest possible casing pressure in order to achleve the greatest well drawdown, since the bottom-hole operating pressure is a direct functlon of casing pressure. Further , a s seen In the performance curves, gas requirements per cycle decrease wlth decreaslng caslng pressures. I n order to establish the value of the mlnimum posslble average casing pressure i t is necessary to know a t which point In the plunger's upward travel a stallout is most llkely to occur. If thls polnt is known, then Equation (1) needs to be solved only once in order to deternllne the nllnlmum casing pressure required.

It seems llkely tha t the most crltical polnt in the plunger's upward travel would be either when the plunger is nearing the surface w ~ t h the liquicl load or when the fluid is surfacing and is passing through the well head. A t this time the caslng pressure is a t its lowest value and the gas-column pressure benefit in the casing-tubing annulus is nearly cancelled by the gas-

PLUNGER-LIFT PERFORMANCE CRITERIA WITH OPERATING EXPERIENCE-VENTURA AVENUE FIELD 129

column pressure effect in the tubing under the plunger. This theory is borne out by the fact tha t In field operations gas flow rates a r e consistently observed to be decreasing a s the plunger nears the surface, indicating the ever-decreasing energy available f o r 11ft. Further- more, a t this time the greatest pressure effect from

llquld procluctlon (in the tu l~ ing under the plunger) could be espected.

Assuming t h a t the critically low casing pressure occurs when the plunger is nearing the surface with i ts liquid load, Equation (1) can be restated and s~mplified a s follows :

Mznzn~u~a casing presszsre = g a s friction presszsre loss 171 entire l e l ~ g t l ~ of tz~bzng + presszsre requzred to lzft weight of plunger + presszcre ~eqlizred to lzft wezght of lzq~szci + ltq~szd frzction pressure loss + szirface tzsb~ng bcickp+esszire. (2)

This equation ignores the pressure effects of plunger friction, slight gas-column pressure differences between tubing ancl casing-tubing annulus, the pressure effect of liquid entry beneath the plunger, and casing-tubing annulus gas frlction pressure loss. These factors, though present, a r e considered to be of small effect when the casing-tubing annulus cross-sectional area is relatively large compared to the tulling cross-sectional area, and gas flow rates a r e hlgh enough to sustain annular r ing or mist flow. E. C. Babsoa' has indicated tha t a n ap-

p ros~wate ly lnlnimum gas flow rate whlch will sustain these types of flow is 225 Mcf/D f o r 2.441-111. tubing and 500 Mcf/D f o r 2.992-111. tubing. Gas flow rates In plunger-lift wells a r e well 111 excess of these minimum rates except In the small load size range with low tubing pressures

Restating Equation (2) in t e r n ~ s of average casing pressure ancl su1)stitutmg a n approsimation for gas frictional pressure losses :

TVherein PC = caslng pressure, psig L = load size, bbl P, = pressure required to lift weight of plunger PI = flow-line pressure, pslg Plh = pressure required to lift weigh^ of Iiclulcl, per D = depth of tublng, f t

barrel K = constant PI, = liquid frictional pressure loss, per barrel

Assuming a constant temperature and liquid velocity, the term ( P l h + PI,) becomes a constant fo r a given tubing size and liquid type. Substituting average or

typical values f o r the varlal~les, Equation (3 ) can be restated a s follows:

Wherein . ( P l h +PI,) and A have values a s follo\vs.

1995-1n 2 441-111. 2 992-in. (PJ~ +PI,). 165 102 63 K . . 33,500 45,000 57,600

and other assumptions a r e a s follows : Liqzizcl. 30-API crude with 15-percent water cu t ;

pressure gradient 0.39 ps i l f t ; kinematic viscosity, 11 cstk a t 60 F , 1.0 cstk a t 200 F

Plzsnger and liquid veloczties 1,000 ft/min Tentperat~sre : 150 F Presszsre ~eqzswed to lift wetgl~t of plzsnger. 5 psi Casing pressure range . 10 percent (corresponds to

2 7/s -in. tublng in 7-in. caslng) Flow line: free from restrictions and ID equal to or

greater than ID tubing with length 2,000 f t o r less

A4pprosimate Equation (4) evolved from more rig- orous calculations whlch more correctly ascertain gas and oil frlction pressure losses ancl more accurately correct fo r temperature effects a t various depths. Ordi- narily, Ecluatlon (4) was found to compare within 2 percent of these more complex calculations and was used to construct Fig. 6-23, incl.

In order to calculate the liquicl and gas frictional pressure losses, a plunger ascending velocity of 1,000 ft/min was used. Average ascending plunger velocities of 1,070 ft/mln were measured in 24 wells. The veloc- itles ranged between 700 and 1,400 ft/mln with most of the wells ranging between 900 and 1,200 ft/min. These velocities were determined by measuring the total time lapse between Aowline control valve opening and arrival of the plunger a t the surface, and a r e probably higher

130 D. L. FOSS AND R. B. GAUL

than actual near-surface plunger velocities. Correspond- ingly, the use of the 1,000-ft/min velocity IS conserva- tlve in t h a t i t predicts higher gas and 011 friction pressure losses than would be predicted with lower velocities. These higher-than-actual pressure losses should compensate to a degree for the pressure losses t h a t a r e not accounted for in Equations (2) , (3 ) , and (4).

Determination of Gas Requirements The fundanlental volume of gas required per cycle

can be considered to be the sum of: a , t h a t volume of gas which is contained within the tubing just before the flowline valve opens; b, t h a t volume of gas which slips past the plunger and liquid during the u p t r ip ; and c, t h a t volume of gas which slips past the plunger a f te r plunger arrival a t surface before the control valve closes. I n practice, c can be reduced to insignifi- cant quantities a s control mechanisms a r e available- which close the control valve within 5 sec a f te r plunger arnval .

The volume of gas contained in the tubing, a, is a t a surface pressure equal to maximum tubing buildup pressure which is usually equal to o r somewhat less than maximum casing bulldup pressure Masimum tubing buildup pressure may be somewhat less than masimum casing buildup pressure because of the presence of a higher colun~n of liquid m the tubing than is present ~n the casing-tubing annulus.

F o r 85 Ventura field wells, actual gas usage per cycle (determ~ned from routine field orifice-meter measure- ments) was compared wlth the calculated volume of the gas-filled tubing a t surface pressures equal to maximum tubing pressure and equal to maximum casing pressure. An average Ventura field gas gravity of 0.72 was used with a gas temperature gradient of 100 F a t surface, 198 F a t 8,000 f t , and 341 F a t 12,000 f t . When compared wlth the volunles a t inasilnum tubing pressures, the actual gas usage averaged 25 percent greater than calculated When compared with the volunles a t maxi- inum casing pressures, the actual gas usage was 15 percent greater than calculated. Interestingly, 31 of the wells eshibited actual gas usage very nearly equal to the calculated volunles (casing-pressure basis) ; and In only 7 cases did the actual volumes esceed the calculated volun~es by greater than 50 percent. Actual gas usage for the 85 wells averaged 4 6 Mcf/cycle with a range from 1 9 to 10 7 Mcf/cycle

Based on the foregoing correlation, the performance- chart basls (Fig. 6-23) used for the Mcf gas required per cycle IS 1.15 tnnes the gas contained wlthin the

tubing a t a surface pressure equal t o maximum casing bulldup pressure. Maximum casing buildup pressure was assumed to be 5 percent greater than average casing pressure. Average gas gravity used was 0 72 and the average gas temperatures used were a s follows: 2,000-ft well: 113 F; 8,000-ft well: 150 F; 16,000-ft well: 200 F.

Fig. 6-23 ~ndica te g a s requirements to be a function of depth and load size fo r a g v e n tubing size. The load size thus indicated corresponds to the finite caslng pressure ascertained from the left-hand sections of Fig. 6-23. I f the gas-requirement sections of Fig. 6-23 a r e used in abnormal situations where casing pressures do not correspond with load slze, ~t is necessary t o use a pseudo load size which corresponds to the actual casing pressure.

Additionally, gas requirements a r e based on the total volume of the gas-filled tubing wlthout correction f o r the space occupied by liquid. Thus, a t the lesser depths \nth large loads (where the volume of liquid is a significant percentage of the tubing volume), Fig. 6-23 may predict greater gas requirements than a r e actually needed.

Determination of Maximum Cycling Frequency The minimum time required to complete one cycle is

the sum of the times required for the plunger to rise t o the surface, f o r the plunger to fall through the gas- filled tubing, and for the plunger to fall through t h e accumulated liquid in the tubing. As noted by Beeson, Knox, and Stoddard? rlsing velocities of 1,000 f t /min and falllng velocities (through gas) of 2,000 ft/min appear reasonable.

Ventura field experience (2%-in. plungers) close1 y substantiates rising velocities of 1,000 ft/min. Falling velocities (through gas) were measured between 900 and 3,000 ft/min depending upon plunger configuration. Therefore, a 2,000-ft/min value for plunger-fall velocity (through gas) appears reasonable.

To establish fall velocities through liquid, several 2.441-in. plungers were tinied on surface while falling through a 60-ft length of 2 441-111. tubing filled with 30-API Ventura field crude. Velocities ranged between 165 and 265 ft/min depending upon plunger configuration. Therefore, a value of 172 f t / n ~ i n appears suitable (using this value, approsimately 1 min is required f o r a plunger to fall through a barrel of liquid i n 2.441-in. tubing).

Using the preceding values, a n equation f o r maximum cycling frequency can be expressed a s follows:

Maxi1r7.ztsrt cycles/day = 1,440 d e p t h leszgtl~ o f 1 bbl load x load stze, bbl

172

On the performance curves (Fig. 6-23) approximate masinlum cycling values can be determined by noting the load-size value a t the intersection of the proper depth and procluction-rate curves and dividing this value

into the production rate. The load size thus determined is the smallest possible a t the given production ra te and depth.

PLUNGER-LIFT PERFORMANCE CRITERIA WITH OPERATING EXPERIENCE~ENTURA AVENUE FIELD 131

EXAMPLES O F USE O F PERFORMANCE CHARTS Example 2

a F o r snaxzmum pro~l.ticzng-rate cot~dztions * Enter 2.441-in., 100-psig chart (Fig. 15) a t 9,300 f t and proceed to the rlght until the 50-B/D curve

Example 1 Well conditions: 50 B/D producing r a t e , 5 Mcf/bbl

produced gas-llquid ratio; 8 441-in. tublng, 9,300 ft depth; 100 psig flow-line pressure

is intersected. From this point observe on the top scale a predicted average casing pressure of 195 psig (this is the lowest average casing pressure possible). Also, a t t h ~ s point observe the load size of 0.5 bbl (this is the minimum load size possible). Proceed to the right a t the 9,300-ft level t o the r~ght -hand section of chart to a load size of 0.5 bbl. Observing t h e - t o p scale a t this ~ntersection, read 5.0 Mcf gas required per cycle.

A 6,000-ft well is found operating with the following conditions 50 B/D production ra te ; 3 Mcf/bbl gas- liquid rat lo; 2.441-in. tubing; 190 p s ~ casing pressure; 30 psi tubing pressure, 40 cycles/day, and inflow performance relationshiu tha t results in a uroduction

From these data : Average casing pressure: 195 psig

= 100 cycles/ day Total gas required = (100 cycles/day) (5 0 Mcf/

cycle) = 500 Mcf/day

Gas required from outside source = 500 - (50 B/D) (5 Mcf/bbl)

= 250 Mcf/day

b F o r condzt~ons req?~zmng no ozitszde source of gas: A trial-and-error solution is required. A total of 50 B/D x 5 Mcf/bbl = 250 2lfcf /D is available to produce the well. Assuming, say, 8 Mcf/cycle will be required, then 250/8 = 31.2 cycles/day would be possible which would result in a load size of

Ente r Fig. 15 (right-han'd portion) a t 9,300 f t and a t the intersection of 1.6-bbl line read 8.7 Mcf gas required per cycle Because thls value is greater than the assumed value, a second approximation of, say, 10.5 Mcf/cycle is made. With this approxi-

mation, 250 Mcf/D = 25.5 cycles/cla2/ a r e pos- 10.5 Mcf/cycle

sible resulting in a load size of 50 B/D - - 23.8 cycle/day

2.1 bbl. Referring again t o the right-hand portion of Fig. 15, a t the intersection of 9,300 f t and 2.1 bbl is read the value of 10.4 Mcf/cycle. This value results In 10.4 x 23.8 = 248 Mcf/D gas usage which is close to the 250 Mcf/D available. Proceed- ing to the intersection of 9,300 f t and 2.1-bbl load on the left-hand chart is read a n average casing pressure of 403 psig.

change of 0 2 B/D/psi (casing pressure). It is desired to ascertain if production can be Increased from this well by decreasing the casing pressure.

a. F o r ~ I ~ Z L ~ Z L ? ) L l~rodzlc~ng ra te col~dztions . By trial-and-error methods it will be found from Fig. 13 tha t the well can be operated a t a casing pressure of 95 psig which results in the following corresponding conditions Producing rate, 50 + 0.2 (190-95) = 69 B/D Produced gas, 69 Y, 3 = 207 Mcf/D Required load size (from Fig. 13) = 0 46 B/cycle

69 Required cycles/day, - = 150 0.46

Required gas/cycle (from Fig. 13) = 1.6 Mcf/cycle Total gas required, 1.6 x 150 = 240 Mcf/D Gas required from outside source,

240-207 = 33 Mcf/D

b. F o r co?~cI.Ltzo?m reql~zring no olbtszde source of gas: By trial-and-error methods i t will be found from Fig. 13 tha t the well can be operated with a casing pressure of 110 psig which results in the following corresponding conditions : Producing rate, 50 + 0.2 (190-110) = 66 B/D Produced gas, 66 x 3 = 198 Mcf/D Required load size (from F i g 13) = 0 6 Bbl/cycle

66 Required cycles/day, - = 110 0.6

Required gas/cycle, (from Fig 13) = 1 8 Mcf/cycle Total gas required, 1.8 x 110 = 198 Mcf/D

SUMMARY The very successful application of plunger l i f t in over

100 wells in the Ventura Avenue Field has created a renewed Interest In this rather neglected method of producing oil wells. Based on a theoretical analysis and i t s correlation with actual well data, a method has been developed to predlct plunger-lift performance for a wide range of well conditions.

I I REFERENCES

'Gilbert, W. E : Flowlng and Gas-lift Well Perform- ance, A P I Drzl l~ng und Prod~(ctzon Practice, 125 (1954).

'Babson, E . C: The Range of Application of Gas Lift Methods, APZ Drllkny and Pvoc71~ctuon Practtce, 366 (1939).

3Beeson, C. M ; Rnos, D G ; and Stoddard, J. H: Plunger Lif t Correlation Equations and Nomographs, Papel' 501-G presented a t AIME Petroleum Branch Meeting, New Orleans, Oct. 1955.


AVERAGE SURFACE CASING PRESSURE lPSlGl MCF GAS REOUIRED PER C Y C L E

LOAD SIZE - BBL Fig. 6 - Approximate Casing-pressure and Gas Requirements for 1.995-111. Plunger Lift

MCF GAS REQUIRED PER C Y C L E

0 5 10 15 20 25 30

I I I I I I I

LOAD SIZE- BBL

Fig. 7- Approximate Casing-pressure and Gas Requirements for 1.995-In. Plunger Lift

LOAD SIZE - BBL Fig. 9 - Approximate Casing.pressure and Gas Requirements for 1.995-In. Plunger Lift


AVERAGE SURFACE CASING PRESSURE [ P S I G ) M C F GPS REOUIRED PER CYCLE

LOAD S I Z E - B B L

Fig. 10 - Approximate Casing-pressure and Gas Requirements for 1.995411. Plunger Lift

MCF GAS REQUIRED PER CYCLE

0 5 10 15 2 0 25 30 I I I I I I I

LOAD S I Z E -BBL

Fig. 1 1 - Approximate Casing-pressure and Gas Requirements for 1.995-111. Plunger Lift

PLUNGER-LIFT PERFORMANCE CRITERIA WITH

AVERAGE SURFACE CASING PRESSURE (PSIG)

lr 7 0 3 r 4 r 5 r


LOAD SIZE- BBL

Fig. 12 - Approximate Casing-pressure and Gas Requirements for 2.441-In. Plunger Lift AVERAGE SURFACE CASING PRESSURE (PSIGI

0 100 200 300 400 500 600 700


O n

LOAD SIZE - BBL

Fig. 13 -Approximate Casingapressure and Gas Requirements for 2.441-In. Plunger Lift

136 D. L. FOSS AND


LOAD SIZE - BBL Fig. 14-Approximate Casing-pressure and Gas Requirements for 2.441-111. Plunger Lift

M C F GAS REQUIRED PER CYCLE

O O

LOAD SIZE - BBL Fig. 15 -Approximate Casing-pressure and Gas Requirements for 2.441-111. Plunger Lift

M C F GAS REOUIRED PER CYCLE

LOAD S I Z E - EEL

Fig. 16 - Approximate Casing-pressure and Gas Requirements for 2.441411. Plunger Lift AVERAGE SURFACE CASING PRESSURE (PSIGI

200 300 400 500 600 700 BOO 900

MCF GAS REOUIRED PER CYCLE

Fig. 17 -Approximate Casing-pressure and Gas Requirements for 2.441411. Plunger Lift

138 D. L. Foss AND R. B. GAUL

AVERAGE SURFACE CASING PRESSURE ( P S I G I I 2 3 r 4 5b M C F G A S R E Q U I R E D P E R C Y C L E

L O A D S I Z E - E E L

Fig. 18 - Approximate Casingpressure and Gas Requirements for 2.992-In. Plunger Lift

AVERAGE SURFACE CASING PRESSURE ( P S I G ) MCF GAS R E Q U I R E D P E R C Y C L E

0 5 10 15 20 25 30

L O A D S I Z E - E E L

Fig. 19 -Approximate Casing-pressure and Gas Requirements for 2.992-In. Plunger Lift

PLUNGER-LIFT PERFOR~IANCE CRITERIA WITH OPERATING EXPERIENCE-VENTURA AVENUE FIELD 139

AVERAGE SURFACE CASING PRESSURE (PSIG)

0 100 2W 3 0 0 400 500 6 0 0

I

Fig. 20 - Approximate Casing-pressure and

AVERAGE SURFACE CASING PRESSURE (PSIGI

1 2 3 4 r 5 0 I 0 O r

Gas


O o

LOAD S l Z E E E L

Requirements for 2.992-In. Plunger Lift


2[ 2, 3[

LOAD S l Z E - EEL

Fig. 21 -Approximate Casing-pressure and Gas Requirements for 2.992-In. Plunger Lift

140 D. L. Foss AND R. B. GAUL

AVERAGE SURFACE CASING PRESSURE (PSIGI

W ' " i , o . % ' r, "+, " Oo

Fig. 22 - Approximate Casing-pressure and Gas

0 100 200 300 400 500 600 70 0


O o

LOAD S I Z E - E E L Requirements for 2.992-In. Plunger Lift

5 6- LOAD S IZE-EEL 0 1 2 3 4

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