109.1 Beam Summary Recommendations

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Beam Summary (Read if you operate B Beam P Pumps))

Best Practices Design Rate = Desired Rate x 24 hr/day (Using POC) .80 80 VE x 20 hr/day Example: Well can make 300 bfpd so what do you rate do you design the well for?

Design Rate = 300 bfpd x 24 hr/day = 450 bfpd .80 VE x 20 hr/day Or in other words, if you design for POC, design for about 1.5 times what the well makes. If no POC, design des g for o what at well e will make a eo or s slightly g t y less ess if gassy. ®

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Predictive Design Runs: Default Inputs 1. Design with no additional load on pump 2. Use default dampening factors 3. A low pumped off level of about 50’ should be used. This will ill give gi e maximum ma im m load on pump. p mp 4. 100 % pump load should be input. This also gives max loads on unit, unit and rods. rods 5. Use motor option for speed variation and use defaults for inertial values, etc.

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Rod String Design 1. Use Grade D rods with T couplings or Spray Metal couplings if wear and economics dictate. Grade “C” rods can be used in sinker bars larger than 1” 1 in diameter. diameter 2. High strength rods should only be used when absolutely necessary. EL high strength rods do not have high strength pins. Use high strength couplings with high strength rods. Be cautious of slim hole couplings with high strength rods. rods Be cautious of high strength rods when H2S is present. 3. All rods should be designed with loadings using your 3 field established service factor but if below .9 consider solving problems (better inhibition , better handling, etc) i t d off going instead i to t lower l SF. SF ®

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Rod String Design 4. Molded rod guides should be placed on any rods below the anchor or run weight g bars. 5. Use steel as opposed to fiberglass unless it can be shown to be economical to do otherwise. 6. Use lighter % loading with Fiberglass (~ 80%) using lowest temperature rating . This usually shown h in i predictive di ti program input/output. i t/ t t 7. With Fiberglass, shear tools should be run on all wells that have shown any tendency to sticking pumps.

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Pump Best Practice 1. Somewhat larger pump diameter without overloading the unit and 1 rods will result in more energy efficient installation. 2. Use simple design. More complicated pumps fail more and cost more. 3. Use heavy wall pumps. Thin wall pumps have less corrosion and pressure resistance. Look at the X pump option. 4. All pumps should be designed and built where the traveling valve is within 1” of the standing valve when pump bottoms out on the clutch at the top… but if NO gas this does not matter. 5. Pump leakage should be in the range of 2-5% of production. High water cut wells should/could have more pump leakage. Deep wells can have pumps with smaller clearances clearances. Use new leakage equation with calculated downhole clearances. Be careful of large clearances as you can loose a LOT of production and wonder why?

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Unit Best Practice 1. The gearbox and the unit structure should not be loaded more than 100%. 2. Use a predictive program to help size the motor. If program says a 32 HP motor is needed and the next bigger available size in stock is 50 HP, HP then use the 50HP. In general you loose significant energy only when the motor size exceeds about 2X the correct size. Use only NEMA D motors. 3. Polish Rods: Spray metal polish rods without liners should h ld be b used d in i all ll CO2 flood fl d beam b lifted lift d wells. ll Water flood and primary wells can use either a liner on the polish rod or a spray metal polish rod.

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Tubing Best Practice 1. Use J55 tubing on producing wells with depths no greater than 8500’. For deeper wells, calculations must be made. made Use couplings of same grade as the tubing 2. Run the seating nipple as deep as possible. 3. Minimize the distance between the tubing anchor and the seating nipple. In open hole , the tubing anchor should be as close to the casing g shoe as possible. In cased hole, the tubing anchor should be out of the perforated zones.

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Gas Separation 1. The pump intake should be below the gas entry point to the well. If this is not possible, consider the new Echometer collar size i gas separator t instead i t d off the th poor boy b separator. t 2. For Horizontal wells, many using beams use a packer type separator above the kick off point or the Don-Nan or perhaps the new Echometer separator 3. A typical poor boy separator can only be used for low rates ((~75-150 75 150 bpd). For 2 7/8 7/8’s s tubing, a 1 1/4 1/4” stinger and velocity between the gas and mud anchor of 1/2 ft/sec, the max fluid rate is 177 bfpd. If 30% is gas, the max fluid rate is only 124 bfpd. p 4. An improperly sized gas separator is worse than no separator as it breaks out more gas and also becomes gas locked.

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Tubing 1. Use API modified no lead thread sealant spread over complete l t thread th d area. 2. Tubing below the anchor should be inspected for excessive wear on each pull and replaced if worn worn. 3. Use thread protectors until tubing in derrick. 4. No wrench marks are acceptable on tubing anchors. Use only ISO 9000 replacement parts. 5. A non API seating 5 ti nipple i l should h ld be b used d only l on 2 7/8’s tubing strings. The API nipple can cause the pump to stick.

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Beam Unit

The unit should have the concrete base set on 5/8’s river stock. Sand can wash out. Alignment is critical Maintenance schedule should be observed Belts should be covered. Fence around unit is good safety idea. Alarm when POC comes on

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Maintenance 1. The unit must be aligned correctly so the polish rod pulls out straight each time 2. Each week the unit should be inspected for abnormal sounds, grease or oil leaks, or rust stains at metal joints. joints 3. On a six month interval, grease all bushings, inspect unit and g gearbox oil for contamination,, check tightness g of all bolts, follow check list and keep records. 4. Check stuffing boxes daily. Don’t over tighten which can cause wear on polish rod and load motor unnecessarily.

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Fluid Level Detection 1. Shooting fluid levels regularly is recommended, especially p y on wells that aren’t on POC. Echometer’s AWP program can be used to correct foamy fluid levels. Dynamometer cards can indicate if a well is pumped off and pounding fluid. fluid 2. Shoot fluid levels when the well is being tested. 3. B 3 Based d on well ll analysis l i and d fluid fl id level, l l consider id lift revision to increase the pumping unit capacity if indicated.

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Casing Pressure

1. Lower is better 2. Check casing side check valves to be sure it is operating properly. 3. Compression p on casing g to lower pressure p is possible… beam mounted compressor or other.

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Corrosion 1. Target is treating with 25 ppm of oil soluble filming amine. The total chemical treatment volume is based on wells total production with the minimum treating volume of 1 gallon. Treating schedules are 1/week for the most part. For normal water flood wells, flush a volume of 3 bbls water with the treatment. For wells with a gas rate of 100-200 mscfd, use 5 bbls and for greater than 200 mscfd, use 8 bbls of water with the treatment. These recommendations for W. Texas area. 2. Check your chemical program or check with your chemical supplier. 3. See included slides of specific types of corrosion and if questions ti contact t t corrosion i group to t see what h t is i causing i corrosion. ®

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Treatments after Workovers

1. Before running pump and rods, it recommended that 15 gallons of oil soluble filming amine and 15 bbls of lease crude be pumped into the tubing after a workover. This should be done on wells that have been killed with heavy brine or on wells that have exhibited severe pitting on tubulars t b lars or rods. rods It is optional on less severe se ere situations.

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Summary Recommendations I many cases, beam In b pump should h ld be b the th artificial tifi i l lift method chosen unless it can be shown another method is more cost effective. However see depth/rate p charts, advantages/disadvantages, and other materials provided here to initiate selection process. F il Failures are many times i due d to the h following f ll i reasons: 1. Design problems 2. Use of improper materials 3. Manufacturing defects 4. Assembly or installation problems 5. Use in conditions which were not considered in the d i – i.e., design i corrosion i nott designed d i d or treated t t d for. f ®

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Chemical Treatment Review treatments every 3-6 months. Try to standardize on one corrosion inhibitor for down-hole use for the entire field. The below typical treatment is for W W. Texas area area. Typical is 1 gallon of inhibitor per week for each 100 bfpd, which is equal to about 30 ppm on a continuous basis. If a batch treatment exceeds five gallons of inhibitor per treatment, then divid into two treatments per week. These are starting points and should sho ld then be optimized. optimi ed Use continuous contin o s treatments for 1000 bpfd production. Continuous treatment is equipment intensive and expensive. Flush is extremely important. A corrosion inhibition treatment typically consists of pre-wetting the casing (typically one b barrel) l) , pumping i the th inhibitor, i hibit then th flushing fl hi with ith volume l off ½ barrel/1000’ (2 barrel minimum). An oil is best flush. ®

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Corrosion Treatments Producing wells in CO2 miscible injection projects should be flushed with oil when the CO2 content of the gas exceeds 20%> Circulation of the well after batch treating is always a good idea especially on high fluid level wells, and always on the fi t treatment first t t t following f ll i the th well ll having h i been b pulled. ll d Oxygen should be kept out of the system: Flush water should be from gas blanketed tanks tanks, or treated with O2 scavenger. scavenger Treat rods before run-in: Use 5 gallons of inhibitor into the tubing prior to running the pump and rods. rods Circulate one tubing volume when the well is returned to production. Look at rods to see if inhibition p program g is working. g If rods out of hole rust and turn red, then they have no inhibitor film. They should stay black. ®

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Pump Summary Lift selection is determined on what system is most economical. Systems must deliver the rate from the well depth, operate with low failure frequencies, have low energy costs, and other considerations. See depth/rate charts, advantages/disadvantages, do PV analysis or other economic analysis as well as consider operational and supply factors and more. Try y to select a heavy y wall insert p pump p with a stationary barrel and a solid plunger. Cup type anchors are adequate for most wells but for deep wells and those frequently unseated to for tubing treatments should use a mechanical anchor or use a mechanical anchor for high temperatures as well.

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Down Hole Pump Summary The basic pump metallurgy should consider a barrel that has a surface hardness greater than that of the plunger to the plunger will wear out first. In absence of experience, one could choose the below metallurgy for pump materials and refine with time. Plunger-spray metal carbon steel Barrel-chrome plated carbon steel Balls cobalt alloy steel Balls-cobalt Seats-Tungsten Carbide Select pump materials with consideration of the environment in which they will operate. See pump selection chart in pump section for detailed materials selection chart. chart ®

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Down Hole Pump Summary Tubing pumps have many advantages for shallower wells producing solids or corrosive fluids. Tubing pumps (larger diameter) are required when high volume production is desired. Larger diameter pumps result in system that conserves energy providing no components off the system are overloaded. Big pumps do add to peak loads and peak gearbox p g torques q so be sure unit and rods are not overloaded. Special purpose pumps are more costly and may fail more frequently. f tl Use U only l if there th are unusuall operating conditions or after conventional pump designs have been found to not work.

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Tubing Al h th bi with ith a tension-type t i t h Always anchor the ttubing anchor as close to the pump setting depth as practical to avoid tubing movement and deflection, and loss of downhole stroke. stroke Avoid setting the anchor within a perforated interval. Install rod guides where repeated tubing splits and/or excessive rod coupling wear occurs occurs. One recommendation is to install four factory installed rod guides on each of the first few rods on top of the pump ( minimum of 2 guided rods). rods) More recent studies would tend for use of sinker bars over the pump (Spread Sheet provided to help design) When the tubing is pulled, move two joints of tubing from the bottom to the top of the tubing string to change the wear pattern. Install new or inspected tubing on the bottom.

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Tubing The rod string design should include several pony rods, of various lengths, at the top of the rod string with an overall length that is three times the stroke length. When the well is pulled, move a stroke length of the pony rods from the top of the string to the bottom but above the guided rods. When all have been moved to the bottom, reverse the procedure and when servicing, move a stroke length of the y rods to the top of the string. g pony Install rod rotators to distribute coupling wear around the circumference of the couplings and rod guides if wear is present. Remember rod rotators do not distribute wear on tubing. Design for pumping at slow SPM if possible. Wear increases with speed. speed Also slow pumping increases energy efficiency drastically. ®

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Gas Handling The natural gas anchor should be employed wherever it is possible to do so. Poor boy gas anchors are less effective for production rates of about >100-150 BFPD. The Echometer Collar size separator, oversized anchor designs or a packer type gas anchor should be considered as a “poor boy” improvement. The packer separator separates gas well but could stick or clog with solids production. See Echometer rate limitations in the notes. Do not allow pounding or improper spacing. Fluid pounding is the incomplete fillage of the barrel. Tapping occurs on the downstroke or upstroke due to improper spacing of the pump. Tapping indicated at surface may be a very heavy blow downhole. ®

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Rods / PR / Coatings The Modified Goodman Diagram serves as a guide in selecting the grade of steel sucker rods to be used, although it may be conservative. K and KD rods should be considered where corrosion is a problem. C rods are adequate for low stress ranges and minor corrosion. Grade D rods should be used for stresses over 30,000 psi. Fiberglass rods can be used to increase capacity if the pumping unit gearbox is approaching capacity. Use T type couplings g unless wear or corrosion make the spray y metal coupling (more expensive)more cost effective. Use a smooth-finished polish rod that is 1/4 inch larger than the p rod. Use a polish p rod coupling p g to install the polish p rod top (unless the PR is a flanged type). Be sure the clamp rests squarely on the carrier bar and the PR pulls straight up and y used above the p pump p and down. Sinker bars are commonly rod guides are used above the pump and in high wear areas, but justify before using them. ®

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Rods / PR / Coatings The Modified Goodman Diagram serves as a guide in selecting the grade of steel sucker rods to be used, although it definitely is conservative. K and KD rods should be considered where corrosion is a problem. The MGD is very conservative but covers other areas of possible failures There is evidence that higher strength rods are more notch sensitive, so consider using K or KD rods or even D rods with SF of more than one, before going t higher to hi h strength t th rods. d

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Rods / PR / Couplings R d pins i need d to t be b lubricated l b i t d before b f k D Rod make-up. Do not use pipe dope. One recommendation for corrosive service, is to use a combination of lubricant/oil soluble corrosion inhibitor ( 80% oil, oil 20% inhibitor mixture is recommended). Spray of dip the pins to provide a light coating. Do not pour lubricant into the couplings. Some use a grease with corrosion inhibitor. Lube only the threads. Once the threads are damaged , then discard the rods. Do not try y to re-thread. Threads are rolled and not cut and you shouldn’t try to cut them. Power tongs are recommended for all rods but 5/8’s rods. However do not use with 5/8’s rods. 5/8’s rods are not really recommended. Any coupling with evidence of hammering or with wrench marks should be replaced. Lay down or pick up rods in singles. ®

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Rods D ’t replace l d string t i one rod d att a time. ti Wh the th Don’t rod When pulling cost due to rod failures exceeds the cost of a new rod string, within a short period of time, then the rods should be replaced replaced. When a well had had three rod failures within a two year period, then the rod string should be replaced on the fourth failure. If the rod failures are all within a taper (one rod size) then change out only that section of rods. Good practice could result in 75 months for rods, 40 months for p pumps, p , and 100 months for tubing. g Another way of looking at the situation is try to achieve a failure frequency of 0.25-.35 failures per well per year or less… depends drastically on field conditions diti however. h Care in running running/pulling and operating sucker rods can be equally or more so as important as design considerations and can be responsible for 50% of all failures. ®

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Units / Motors I mostt cases conventional ti l type t i units it are In pumping satisfactory. Specialty units should be justified based on their ability to reduce operating cost through size reduction reduction, efficiency efficiency, lower maintenance cost, etc. Lufkin however sells about as many Mark II units as conventional units now. NEMA D electric motors motors, rated for 440 volts and 1200 rpm synchronous speed are usually the best choice. Use of oversized motors should be avoided (2x) because they y will be less efficient. Also oversized motors may require capacitance correction to avoid possible power factor penalties set by the power company. Also oversized motors are “stiff”, add to rod d and d unit it loading l di due d to t effectively ff ti l less l slip. li It may be un-economical to replace a large motor unless it is more than twice the HP of what is needed needed. ®

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Motors / Belts / Design Select a new motor so that the brand chosen will have the highest operating efficiency in the range in which it will be operated. Selection of a NPHP of about 2 x PRHP usually sizes the HP correctly. Replace belts as sets and not individually. Measure belt tension on installation and during operation. Premium cog belts are used as replacement drive belts on p pumping p g units by y some operators p Although the API method is accurate within method limitations, a wave equation predictive computer program is i more flexible fl ibl for f design d i considerations. id ti Use surplus and used equipment when appropriate g a beam pump p p system. y to reduce costs of using ®

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POC All beam pumped wells, and even those that don’t pump off, should be considered good candidates for wellsite control. A central surveillance system will further enhance performance of beam pumped wells and should be strongly considered for all fields. Good surveillance and cause-of-failure cause of failure record keeping is the key to efficiently operating beam pumped wells. Accurate well tests are needed for any monitoring program to be successful. Shooting fluid levels is needed to assess the loading of the beam system, especially for wells that don’t don t pump off off. Also possible extra production may be indicated with high fluid levels. Use the Echometer method of analysis when considering effects of fluid levels to correct for the effects of gas coming through the fluid level. ®

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POC Increase idle time between pumping cycles until an impact is noted from well tests especially in well with high reservoir pressures and low PI’s. PI s. This will reduce the number of starts and stops per day. Starts and stops may adversely affect the motor and the drive train although this is not documented by anyone. Too much idle time will reduce production. Try y to understand the p physical y cause of failures and take action to prevent a recurrence, or you may be accepting that the same failure will happen again. D Documentation t ti off previous i failures f il will ill help h l in i the th diagnosis of future failures and lead the way to less frequent failures/(year-well).

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Definition of Problem Well T k failures f il b type t ( d tubing, t bi t ) Track by (rod, pump, etc.), location (pin body, barrel, plunger, etc.) and cause (abrasion, stuck, corrosion, split, plugged, etc.). With this data base base, failures can be trended with time time. Analysis will point problems with chemical treatment, specific equipment components, body or end connection failures for rods, or tubing failure is corrosion or rod wear related. Have periodic meetings to discuss failure data bases. One definition of a Problem Well: Pump failure in less than 12 months Tubing failure in less than 12 months Two rod failures (pin (pin, coupling coupling, body) in last 12 months Or combination of any three failures in last 12 months ®

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Problems found by Down Hole Cards Loose Tubing Anchor TV Problems SV Problems Pump p Leakage g Pump Sticking

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Over Travel Under Travel Fluid Load Friction Gas Interference Pump-off Tagging

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