Auto Rotating Plunger SRP

7/30/2019 Auto Rotating Plunger SRP

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PE 46217:6iii? m ,:~ Society of Petroleum Engineera

proved Pump Run Time Using Snow Auto-Rotating Plunger (SARP) PumpE. Houghton, SPE, Aera Energy LLC, and J.M. Snow, Snow Well Services, and R.B. Holland, Aera Energy LLC, andGib;on, Pool California Energy Services, Inc.pyr ight 1S98, Society of Petroleum Engineers, Inc

paper waa lxepared f or preaent at iam at t he 1998 8PE W estern Reg iona l Meeting held inersf ield, California, 10-13 May 1998

paper was selec ted fw present at ion by an SPE Progr am Committee fo llowing r ev iew ofm ati on w ntarted i n an a bstract su bm itted by the aul hor(s) Ccnten ts of the p aper, a sent ad , have not bean r ev iewed by t he %cialy o f Pet ro leum Engmeer a end are sub ject t o

ractl on by th e authw( s), Th e ma le ria l, a s pra sanl ed , d cm s not n ece ssa ril y refl ect an yt lon of t he Soc ie ty o f Pet ro leum Engmeer a, i fs o ff icers , o r members Paper a present ed a t

E m eeti ng s are a ubj ec f to pu bl ic atio n revi ew b y Edi torial C om mittees of the Scc ie ty ofoleum Engineers Electronic reproducllon, dktribution, or stc$age of any part C#this papermmmercial purposes without the written consent of the Society of Petroleum Engrneers isibi ted Per m! ssum 10r eproduce m print IS restr ic ted t o an abstr ec t o f not mor e than 300

ds, Illustrations may not be copied The abstract must mntain ccospicuousowledgment o f wlwre end by whom the paper was present ed Wr ite L ibra rian , SPE, POx 833836, Richardson, TX 75083-3836, USA, fax 01-972-952-9435,

ow Auto-Rotating Plunger (SARP) pumps improved suckerpump performance at Aera Energy LLCs North Midway-nset Field. A program to install the SARP (a patentedapter that hydraulically rotates the pump plunger on eachwn stroke) was instituted in order to reduce subsurfaceintenance costs associated with pulling and repairing wornn-hole pumps. The SARP induces random rotation of thenger on each stroke promoting uniform wear. The pumpsility to wipe sand from between the plunger and barrel ishanced by the rotation of the plunger, reducing the odds ofe plunger galling or becoming stuck because of solids. Whene pilot test was initiated in April 1995, the well pullingequency was 2.04 pulls/well/year. In two years, pullequency was reduced by 51% and pump repair costs were

3T0/0.

The Midway-Sunset field, located in western Kern County,alifornia, is one of the super giant fields in the San Joaquinlley of central California. The field has produced morean 1 billion barrels of oil since its discovery. Aera EnergyLC operates about 1300 wells in the North Midway-Sunsetrtion of the field. The project area used for the initialsting of the SARP pump included 540 wells producing one Alberta, Finley, Shale, and Soudan leases.A combination of steam drive and cyclic steam stimulatione used to produce the 110API gravity oil in the project area.e wells produce from the unconsolidated Potter sandstoneservoir at an average depth of 1500 that often yieldsbstantial sand production even from gravel packed wells.eservoir permeability is 1,000-5,000 md and reservoir

pressure in the gravity drainage reservoir is about 100 psi.In early 1995 a review of yearend expenses in the projecarea revealed that subsurface maintenance expenses accountedfor 14% of the total non-energy expenses in 1994. This wasidentified as an area with high potential for cost reductionExpense reports indicated down-hole pump failures were amajor component of the subsurface maintenance expense. Ousubsurface maintenance tracking records indicated groovingand galling of the pumps due to steam and sand productionwere the primary cause of failure leading to reduced run timeA benchmark study pointed out that pump failures/well/year ithe project area were high compared to other areas.Sand control processes used at other leases wereinvestigated and several methods for reducing failure weretried with limited or no success. Wiper rings were found towear out too quickly to provide long-term benefit in theerosive environment. Filters run below the pump tended toclog with sand and restrict entry into the pump. Rod rotatorsdont provide sufficient movement of the plunger to preventhe pump ilom wearing or sticking in sand. Plungers withhorizontal grooves were tried but failed to prevent scoring othe plunger and barrel. Sand buster pumps were tried budid not show significant improvement over a standard pumpconfiguration. Sand consolidation treatments did not providean attractive solution either.The SARP pump was developed to address the pumpproblems associated with sand production in this area. JerryMark Snow, a toolpusher for the rig contractor in the projecarea at the time, developed an adapter that fits on top ofstandard down-hole pump plunger that forces the plunger torotate on the down stroke. His theory was that the rotatingplunger would prevent grooving and galling of the pump bconstantly changing the contact area between the plunger andthe barrel.How It WorksA typical sucker rod pump configuration (Fig. 1) usesplunger inside a pump barrel to swab fluid ffom the wellboreto the surface. A traveling valve and standing valve (Fig. 2control fluid entry into and out of the pump barrel. Typicallythe plunger is connected to the lower end of the rod string andno provision is made for allowing the plunger to rotate withinthe pump barrel. This failure to rotate the plunger within th


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J.E. HOUGHTON, J.M. SNOW, R.B. HOLLAND, H.L. GIBSON SPE 4621

ump barrel has the potential to cause several undesirablensequences. Abrasive materials (such as sand or scale) thatecome lodged between the plunger and the barrel can causevere localized wear to both the plunger and the barrel. Sandan even cause the plunger to become stuck within the barrel.alling, caused by friction and heat, can cause the plunger tose to the pump barrel and prevent the normal movement ofe plunger inside the pump barrel. This is a common cause ofilure in areas using thermal recovery techniques. Underrtain conditions the rod string can even become unscrewed.The SARP pump (Fig. 3) induces random rotation of theunger on each stroke promoting more gradual, uniform wearound the circumference of the plunger and barrel instead oflowing severe wear in a localized area. The pumps abilitywipe sand fi-ombetween the plunger and barrel is enhancedy the rotation of the plunger, reducing the likelihood of theunger becoming stuck because of solids or galling.As stated in the Patent*, oil enters the plunger on the downroke through a port that is sealed on the upstroke by theaveling valve. The oil flows upward through a passage ine plunger into the cage which is thick-walled but hollow.he outside diameter of the cage is less than the insideameter of the pump barrel. The plunger is rigidly connectedthe cage. Helical grooves in the outer surface of the cagemmunicate with the space inside the cage through theOn the down stroke, the oil inside the cage flows outrough the passages and into the grooves and the upwardlocity component of the oil reacts against the upper edges ofe grooves to produce a torque on the cage. The torque is in airection to produce clockwise rotation of the cage andunger as viewed from above. Rotation of the plunger issired, but rotation of the rod string is not desired.herefore, the rod sting is attached to the cage by means of aivel coupling. After being discharged from the cage, the oilntinues to move upward through the space between theivel coupling and the pump barrel and between the rodring and the pump barrel. In this way, on the down stroke,e plunger and the cage rotate, but the rod string does nottate. The rotation distributes the wear on the plunger moreiformly around the circumference of the plunger, therebyeatly extending the life of the pump. On the upstroke, no oilows through the plunger and the cage, and accordingly, norque is produced. Therefore, the plunger rotatestermittently during each down stroke.A second, more recent design has a different cage andper plunger. As before, oil enters the port on the downroke and travels upward through a passage in the plungerto the cage. The cage includes apertures through which theflows upwardly and outwardly into the space surroundinge cage. The apertures extend in the axial direction anderefore no torque is produced as the oil flow through theertures. The upper plunger is rigidly connected to the cage,hich in turn is rigidly connected to the plunger, so that theseree elements rotate as a single piece. As the oil travelsward beyond the cage it must pass through the helicalooves in the outer cylindrical surface of the upper plunger

which makes a loose sliding fit with the pump barrel. Thgrooves impart a horizontal velocity component to the oleaving the upper plunger that urges it to rotate clockwise aseen from above. The upper plunger is rotatably connectedthe swivel coupling, which permits the upper plunger, the cagand the lower plunger to rotate as a unit, without exertinsubstantial torque on the rod string. Rotation of the uppeplunger and of the lower plunger serves to distribute wear othese parts more evenly around their circumference.A model of the pump shows a vortex is created by throtation of the plunger, which appears to entrain solids in thproduced fluid and prevent them from lodging between thplunger and barrel.Testing MethodsThe first Snow Auto-Rotating Plunger (SARP) was testein one well (Finley 487) in April 1995. Finley 487 had aaverage pump run time of 23 days and an average pump repacost of $550. By early 1995, pump run times had beereduced to less than one day in some cases. The weproduced at an average daily rate of 60 bopd when it waproducing, so there was a lot of potential for increased revenufrom avoided down time, reduced pump repair cost anreduced rig costs associated with pulling the sucker rods anpump. The first SARP pump ran for 431 days and the pumcost only $36 to repair when it was pulled in July 1996 tincrease pump size.Once Finley 487 had pumped for a few weeks withoutpump change, a pilot program was initiated on selecteproblem wells. Problem wells were defined as those wellwith more than three pump failures per year. In May 1995sixteen SARP pumps were ordered and installed for the piloprogram.After it became clear that improvements were being seein the results tlom the pilot, SARP pumps were installed iadditional wells when the conventional pumps were pullebecause of failure. The success of the pilot led to a program tconvert all problem wells to the SARP. By the end of 1995SARP pumps had been installed on 97 wells. A 10OAeductioin subsurface maintenance costs was realized in 1995, despitthe fact that the SARP pumps were purchased using expensdollars and were charged to the subsurface maintenance costsThe program was expanded in 1996, when 103 additionaSARP pumps were installed. A 37% reduction in subsurfacmaintenance costs was directly attributable to this projecresulting in annual expense savings of $474M in 199compared to the subsurface maintenance cost in 1994. Whethe pilot test was initiated the well pulling frequency was 2.0pullsfwelllyear. In two years, pull tlequency was reduced t0.99 pulls/weIl/year, resulting in reduced well pulling anpump repair costs, and allowing additional production due treduced well down time.Of utmost importance in this undertaking was the overafinancial impact of the project. Investment in SARP pumphas totaled $ 120M while the expense savings realized durinthe installation period has amounted to $612M, a net saving omore than $492M during 1995 and 1996. More important]y


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SPE 46217 IMPROVED PUMP RUN TIME USING SNOW AUTO-ROTATING PLUNGER (SARP) PUMP

the project area is currently positioned to realize fhture savingsof approximately $500M/year from avoided subsurfacemaintenance costs.Initial installations concentrated on problem wells (thosewells requiring more than three pump changes per year) butresults were better than expected. As pump run times inproblem wells with SARP pumps exceeded run times forconventional pumps in non-problem wells, many conventionalpumps in non-problem wells were replaced with SARP pumpswhen they failed.Development for New ApplicationsThe SARP was originally designed for a 2 insert pump,which was a common configuration in the project area. As thesuccess of the SARP became evident its use was expanded tolarger and smaller pump sizes. The initial SARP pump designhas been simplified and made more reliable, eliminatingmechanical failures in the SARP assembly for all pump sizes.While there were no equipment failures in the original designapplication, there were a few failures of the early equipment asits application was expanded.In the smaller pumps the lug nuts which attached the cageto the sucker rod string would occasionally part. In largerpumps a few of the cages parted. The design was changed toprevent future failures. The cage was made thicker and thelug nut was eliminated and replaced with a solid assembly.The latest configuration is stronger than many othercomponents of the system. Designs are now available thatallow retrieval of standing valves and plungers from tubingpumps without pulling the tubing.Individual Well ResultsThe SARP pump improves the economics of producingwells by reducing the operating costs of the wells andincreasing the amount of oil produced by the wells byreducing down time. In some cases it allows production fromwells that would not ordinarily be able to produce at alI.One example, Soudan 10R, was an idle well that wasgoing to be abandoned because it was uneconomical toproduce with conventional pump run times of less than twodavs. The first SARP was installed June 6. 1995. SevenSARP pumps were installed during a 28-month period. Netproduction averaged over 25 bopd. The cost of the SARPadapter was $400. This single well provided sufficientincremental revenue to pay for the purchase of all the SARPpump adapters installed in the project area.Many of the wells in the project area develop sandproduction problems over time as the produced sand erodesthe liner slots and increases their size, allowing sand to beproduced through the slots. However, many of the older wellshave had their longest run times since the installation of theSARP pump. Some individual well results are shown below.Finley 132 was a problem well, sanding frequently.Average run time was 20 days. On August 17, 1995, an SARPwas installed and ran for 441 days.During the period from March 1994 to November 1994, atotal of six conventional pumps were installed in Finley 179

with an average run time of 44 days. The first SARP wainstailed in 1995 and is still running.Finley 242 standard pump run time was 10I days. Thfirst SARP was installed December 14, 1995. The pump wapulled for steam on 4/5/96. The same SARP pump was ruback in the hole and is presently at 628 days, the longest ruever for this well. Six pulls have been prevented to date.Finley 373D average run time was 165 days and thlongest run time for a standard pump was 282 days. A swivepump was installed October 18, 1996, and is still running afte479 days.Finley 416 had an average run life of lOOdays. An SARPwas installed September 19, 1995 and is still pumping afte874 days. Eight pump replacements have been avoided so farFinley 424 had three pump pulls between February 199and Februruy 1996 for an average run time of 121 days. Thfirst SARP was installed February 27, 1996, and is stilrunning after 713 days. Six pulls have been avoided so far.Finley 426 had an average pump run timeof71 days. Thefirst SARP pump was installed June 21, 1995, and ran 11days. The second SARP was installed December 29, 1995 andran 393 days with 5 pulls prevented to date.Finley 487 was a problem well, average run time was 213days. Sanding and plunger grooving were causing the failuresThe first SARP was installed April 26, 1995 and ran until July1, 1996. There was no grooving on the barrel or plunger whenthe pump was pulled to replace the 2 pump with a 2!4 pumpThe pump has been lowered from 30 to 12 off bottom withno sanding problems.A horizontal well, Shale 250H, was drilled in Augus1996. The well was originally completed with a 3 X 2% X20 RWA pump with an SARP pump. The pump ran untiDecember 1996 with no slip. At that time the pump wapulled to increase the displacement of the well. A largepumping unit was installed and a 3-3/4 tubing pump wasinstalled. No 3-3/4, SARP adapters had been built at thatime, so a conventional pump configuration was run. Thepump began to slip shortly thereafter and was pulled forfailure after 17 days. The pump was grooved beyond repair.A 3-3/4 SARP cage was manufactured and installed with thenext pump. The new pump ran for 337 days.Observed AdvantagesRunning the SARP allows the pumps to be lowered closerto the bottom of the hole without sanding, allowing more headin the low-pressure reservoir. The wells now experience lesdowntime over the life of the well that allows oil to beproduced sooner. Pump repair costs are reduced, number oactive rigs used in subsurface maintenance was reduced tiomfive to two or three. The SARP pump has allowed wells thawould otherwise have been left idle or abandoned to beproduced; reduced the incidence of multiple pulls subsequento a huff-n-puff steam cycle being injected into a well; andhas virtually eliminated pump galling. With the solid SARPabove and below the plunger it can be used to hone the pumpbarrel to keep it free of scale buildup. The SARP has reducedthe incidence of sucker rods coming unscrewed because of the


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J.E. HOUGHTON, J.M. SNOW, R.B. HOLIAND, H.L. GIBSON SPE 46217

lockwise torque on the rod string. The ability of the pump to Referencesotate makes pulling the pump free after it has sanded much 1. Snow, M.J.: Rotating Plunger for Sucker Rod Pump, Uniteasier than with a conventional pump. States Patent Number 5,660,534, August 26, 1997.

A pump shop that supplies and services pumps typicallythe SARP pump. The pump shop can make a smallofit fi-omthe sale of the adapter when it is initially installed.owever, since the SARP adapter is virtua[ly indestructabtend it has the potential to dramatically increase pump run lifend reduce pump repair costs it can cost the pump shop moneythe long run. Another obstacle is that it adds to the cost ofe initial installation of the pump. It requires an initialvestment to reduce fbture costs. While at North Midway therogram paid out in the same year it was implemented, otherreas, with longer pump run times, may experience longermes to payout their initial investment. That may be astacle if an operator is focused strictly on short-term cost.

panded ApplicationSince the success at North Midway-Sunset, Aera has usede SARP in the San Ardo, South Midway-Sunset and Lostills fields in California. Other operators are also using theARP at the Lost Hills and Kern River fields. The SARPstem is a more robust pumping system that can be applied tony wells where entrained sand in the produced fluids is a

Subsurface maintenance costs (which include productiong costs, pump repair costs, contract labor costs and materialosts) were reduced in the project area by 37?40rom 1994 to996. When the project to implement the SARP pump atorth Midway began in April 1995, the number of pumpspaired per month was 83. By the end of 1996, the number ofump repairs was reduced to 24 per month (Fig. 4). As asult, 578 pump pulls were avoided from April 1995 tocember 1996 (Fig. 5).Pulling frequency in the project area was reduced from04 pttlls/well/year in 1994 to 0.99 pulls/well/year in 1996 forreduction of 51A. Pump repair costs were reduced from3M per month to $12M per month for a savings of 48%.he number of rigs required to provide subsurfaceaintenance was reduced from five in 1994 to less than three1996.The SARP pump configuration does not have any knownsadvantages compared to the conventional pumping systemd is a more robust pump that can withstand wear better thanconventional configuration in any producing environment.s a result, the SARP pump is now the standard pumpnfiguration in the project area and a SARP pump is installedall new wells. Nearly all of the wells on the Finley leaseve been converted to the SARP pump. To date, more thanSARP pumps have been installed in the project area in therth Midway-Sunset field.


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rawing Labels for Fig. 1- Fig. 3Pump. Sucker Rod StringTubingBarrelPlungerCasingPerforations. Standing Valve. Traveling Valve. Upper End of PlungerSwivel Coupling. Plunger PortHelical GroovesHelical GroovesPassagesPassages. Space Between Swivel Coupling and Pump Barrel. CageAperturesApertures. Space Around Case. Upper PlungerHelical Grooves. Helical GroovesHelical Grooves

PUMPING UNIT 1~

ROOBoxINES

1-- m - - , +,w:%.&+$~.CASING

TUBING20

PUMP

d

l-Conventional Sucker Rod Pumping System

RAVELING VALVE

PUMP BARREL

TANDING VALVE

1+UPSTROKE DOWNSTROKE

Fig. 2-Position of traveling and standing valves on upstroke andown stroke of typical sucker rod pump

74

Fig. 3 Two designs of Snow Auto-Rotating Plunger (SARP) Pump


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9080706050403020100

~ uPumpsRepaired1 I

. 4-Pumps repaired per month in project area

. 5-Pump pulls saved after installation of SARP pumps

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Auto Rotating Plunger SRP