GEOMETRY/STRUCTURE:

Figure A Components of Sucker Rod Pump

A motor and gearbox supply power to turn the power shaft. There is a counterweight at the end of the crank. A pitman arm is attached to the crank and it moves upward when the crank moves counterclockwise. The Samson arms support the walking beam. The walking beam pivots and lowers or raises the plunger. The  rod attaches the plunger to the horsehead. The horsehead (not rigidly attached) allows the joint (where rod is attached) to move in a vertical path instead of following an arc. Every time the plunger rises, oil is pumped out through a spout. The pump consits of a four bar linkage is comprised of the crank, the pitman arm, the walking beam, and the ground.

EXPLANATION OF HOW IT WORKS/ IS USED:

Figure B: Operational Detail of Sucker Rod Pump

Here the plunger is shown at its lowest position. The pitman arm and the crank are in-line. The maximum pumping angle, denoted as theta in the calculations, is shown. L is the stroke length. After one stroke, the plunger moves upward by one stroke length and the walking beam pivots. The crank also rotates counterclockwise. At the end of the upstroke the pitman arm, the crank, and the walking beam are in-line.

For name and location of parts, see Figure A.

1. A motor supplies power to a gear box. A gearbox reduces the angular velocity and increases the torque relative to this input.

2. As shown in Figure B, (the crank turns counterclockwise) and lifts the counterweight. Since the crank is connected to

the walking beam via the pitman arm, the beam pivots and submerges the plunger. Figure B also shows the horsehead at its lowest position. This marks the end of the down stroke. Note that the crank and the pitman arm are in-line at this position.

3. The upstroke raises the horsehead and the plunger, along with the fluid being pumped. The upstroke begins at the point shown in Figure B. At the end of the upstroke, all joints are in-line. This geometric constraint determines the length of the pitman arn.

4. Figures C(a) and C(b) show the plunger and ball valves in more detail. These valves are opened by fluid flow alone. On the upstroke, the riding valve is closed and the standing valve is open. Fluid above and within the plunger is lifted out of the casing while more fluid is pumped into the well. On the down stroke, the riding valve is opened and the standing valve is closed. Fluid flows into the plunger and no fluid is allowed to leave the well.

Figure C(a) Figure C(b)

DOMINANT PHYSICS & DESIGN:

Figure D: Variable Descriptons For SRP

Table 1: Variable Descriptions, Values and Units

Variable Description Typical Value Units

Full Pump Angle --- degrees

Fl Total Force Pump must exert

--- lbs

Ff Weight of Fluid --- lbs

Fr Weight of the Rods --- lbs

Fc Weight of counterweight

--- lbs

Fb Buoyant force on rods --- lbs

w Rod weight per unit length

--- lbs/ft

Lr Length of one rod 25 - 30§ ft

Nr Number of Rods --- ---

Pi Input Power 4000§§ psi

h Depth of Well 10,000§§§ ft

Fluid Density --- lbm/in^3

g Gravitational Acceleration Constant

~9.8 m/s^2

L Stroke Length 16 - 192§§§§ in

T Required Pumping Torque

6,400 - 912,000§§§§§

in-lb

Vf Fluid Volume per Stroke

--- ft^3

Ar Rod Cross sectional area

--- psi

Sy Yield Strength of Rod --- psi

Ap Plunger Cross Sectional Area

--- psi

§           Reference 1, pp. 9.279

§§        Reference 1, pp. 9.277

§§§      Reference 1, pp. 9.277

§§§§     Reference 1, pp. 9.282

§§§§§  Reference 1, pp. 9.282

To design a sucker rod pump, the depth of the well must first be determined. This value is then used to calculate the amount of fluid

that can be pumped per stroke. This amount is the volume of fluid that fits in a cylinder of height L and cross sectional area Ap.

Vf = Ap L

This volume is then multiplied by the density of the fluid and by the g to find the weight of the column of fluid the pump must lift.

Ff = Mf g

The pump must also provide enough power to lift the sucker rods (see Figure A). Manufacturers specify typical values of weight per unit length, w, for the rods they make. This number is multiplied by the length of one rod, Lr, and by the number of rods, Nr.

Fr = w Lr Nr

Since the rods are submerged in fluid, a buoyant force is present. This force is found using Archimedes’ Principle. It states that the buoyant force a submerged object feels is equal to the weight of the fluid it displaces. Therefore, the volume of displaced fluid is equal to the submerged volume of the rods. The weight of this fluid is equal to this volume multiplied by the fluid’s density and g. To obtain the volume of the rods, we multiply their cross sectional area by their total length.

Fb = Ar Nr Lr g

Now the total load the pump must lift can be calculated.

Fl = Ff + (Fr – Fb)

Two things must be noted. First, the above analysis is very rough and does not include additional factors such as impulse forces. For more detail, see Reference 1, page 9.283. Also, the forces described above vary with time and this must be taken into account.

The stroke length of the pump is the vertical distance the plunger travels in one stroke. This length depends on the amount of fluid being pumped. Once the stroke length is known, the geometry of the four bar linkage can be determined. To avoid excessive wear of the machinery, it is good engineering practice to reduce the number of cycles the pump completes per unit of time. In order to do this more fluid should be pumped per cycle. In order to increase the fluid displacement, the stroke length should be maximized. Typical values for stroke length vary from 16 to 192 inches (see Reference 1, pp. 9.282). The stroke length can be used to calculate the torque required to pump the oil according to the following formula.

T = C L Fl

Here, C is a function of the geometry of the four bar linkage and the force the counterweight exerts on the crank (see Reference 1, pp. 9.283). Typical values for torque range from 6,400 to 912,000 in-lb (see Reference 1, pp. 9.282).

On the upstroke, two forces help pump the oil from the well. The first is the "force" supplied from the torque produced by the motor and gearbox. The second force comes from the weight of the counterweight as it falls (see Figure C).

LIMITING PHYSICS:

Care must be taken to choose a cross sectional area large enough so that the rods do not yield. This area can be found by dividing the total tensile load by the yield stress of the material.

Ay = Fl / Sy

The area of the rods must be greater than this area.  This is a minimum.  Fatigue affects (function of material and loadking) will require a larger value.

EFFICIENCY:

The efficiency of the sucker rod pump can be defined as the volume of oil it actually pumps divided by the volume it can theoretically pump. When the well is initially drilled, the oil contains a lot of gas. This gas displaces a small volume of oil at the beginning. This volume decreases eventually. The volumetric efficiency of this type of pump is rated at about 80%. (see Reference 1, pp. 9.277)

PLOTS/GRAPHS/TABLES:

None Submitted

WHERE TO FIND SUCKER ROD PUMPS:

Sucker rod pumps are used primarily to draw oil from underground reservoirs. The mechanisms it employs however are found in a wide variety of machines. The four bar linkage can be found on door dampers, on automobile engines, and on devices such as the lazy tong. The Sterling engines manufactured in 2.670 also use a linkage similar to the one used by the pump.

REFERENCES/MORE INFORMATION:

1) Karassik, Igor J. et al, Pump Handbook. pp. 9.278-9.285, McGraw-Hill, New York, 1986.

2) Sucker Rod Pump (From the Internet Glossary of Pumps)

URL: http://www.animatedsoftware.com/pumpglos/suckerro.htm

PUMPING SYSTEM DESCRIPTION  

Beam pump

The pumping system is controlled by a beam-balanced unit, with an API designation of 16-53-30. Polished rod stroke = 24 inches Dimensions     A = 38 3/4 in                         C = 31 in                         K = 67 1/4 in                         P = 60 3/4 in                         R = 9 1/2 in                         I = 30 in                         H = 70 1/2 in                         G = 9 1/2 in  

Wellbore and rods  

     

Rod String: Top:           1 ea 8 ft x 1-1/8 inch polished rod                    3 ea 8 ft x 5/8 inch pony rods                    1 ea 4 ft x 5/8 inch pony rod                    1 ea 8 ft x 1-1/8 inch sinker bar (polished rod)                    1 ea 2 ft x 5/8 inch pony rod Bottom: Plunger

Distance from Stuffing box to seating nipple = 43- 1/2 ft Oil specific gravity: 0.81 Oil viscosity: 3.46 centistokes at 25 deg. C.    

This displays the polished rod above the load cell.    

Pump  

     

Tubing Pump Pump plunger diameter: 1.765 inch

Pump barrel length: 4 feet  

Schematic of the Sandia Sucker-Rod Pump  

   

  Here the traveling valve is at top stroke position.

At the left is the pressure tap for measurement

 of pump discharge pressure.        

This displays the standing valve inside with the

landing nipple at the bottom of the pump. The pressure taps

measure pump intake pressure and the pressure inside

 the pump.    

Clear plastic casing with the traveling

valve inside the transparent tubing pump.            

                   

Downhole Gas Separator Data acquisition

Pressure, load and position data are acquired using National Instruments Labview.

PROJECT PLAN

Construct Instrumented Clear Plastic Pump Installation and well workover Data acquisition system, specification, purchase and

installation Instrumentation specification. Acquisition, installation and

calibration Software Development

o Data acquisition o Data reduction and presentation o Data archiving

Experimental Plan

o Preliminary testing, procedure definition o Effect of pumping speed

Full pump Partial fillage Pump intake

o Effect of spacing

PROGRESS REPORTS

WEEK 1 (Jan. 31 - Feb. 4, 2000)

Data Acquisition was obtained for three different speeds;  6 strokes per minute (spm), 9spm, and 12spm.

The following graphs (Excel format) were done for the three different speeds:

o Position vs Time o Intake Pressure vs Time o Discharge Pressure vs Time o Barrel Pressure vs Time o Annular Pressure vs Time o Load vs Time

                                                                                      

Data file in text format.  

WEEK 2  (Feb. 21 - Feb. 25, 2000)

Data acquisition at speeds from 6 to 16spm for both full pump and pumping off.

Data acquisition at different speeds for both full pump and pumping off.  Videos were taken during the test.

WEEK 3  (Feb. 28 - Mar. 3, 2000) An additional load cell was installed.  A test was done in

order to check the "zero readings" for both the load cells and pressure gauges.  Data for the second load cell was acquired with the "Echometer TWM" system.

Valve checks were recorded as well as sets for one minute pumping with full pump.

Web page was updated with new video clips.

WEEK 4  (Mar. 20 - Mar. 24, 2000) The position of Beam Pump Unit was corrected to

improve the alignment with respect to polished rod.

WEEK 5  (Mar. 27 - Mar. 31, 2000) Stuffing Box assembly was replaced with "O" ring seals

to reduce friction. A test was done to check the behavior of measured

parameters after the modifications done on stuffing box and Beam Unit.

WEEK 6  (Apr. 1 - Apr. 9, 2000) Tests were run at two speeds and variable pump fillage. Leak was discovered at fitting on Standing Valve. 

Workover is now needed.

DATA ARCHIVE            Date, Test Description, Format, number of sets, filename

PUMP DYNAMICS VISUALIZATION  

To view the following video clips, your computer must have Quicktime.   Download Quicktime

Clip of Standing valve - Click here

                                                                         View plunger motion - Click here

                                                                        

Clip of Beam Pump - Click here

                                                                        

Clip of Traveling valve - Click here

                                                                        

Warning: The next four clips are 13.0 MB in size and may take time to download

Clip of gas flow through pump and into tubing. Gas slugs are rising in tubing. - Click here or Winzip

                                                                        

Clip of gas flow through the standing valve and pumped off. - Click here or Winzip

                                                                        

Clip of gas flow through traveling valve and the plunger. The traveling valve opens before the plunger hits the fluid. - Click here or Winzip

                                                                        

Clip of return to full pump. - Click here or Winzip

                                                                         

Basic API Downhole Pump Nomenclature

RHA RWARSA

RHB

RWBRSB

RHT RWTRST

TH TP

Thin-Wall, Metal PlungerRWA - Stationary Barrel, Top Anchor

RWB - Stationary Barrel, Bottom AnchorRWT - Traveling Barrel, Bottom Anchor

Thin-Wall, Soft-Packed PlungerRSA - Stationary Barrel, Top AnchorRSB - Stationary Barrel, Bottom AnchorRST - Traveling Barrel, Bottom Anchor

Heavy-Wall, Metal Plunger (Deep Wells)RHA - Stationary Barrel, Top AnchorRHB - Stationary Barrel, Bottom AnchorRHT - Traveling Barrel, Bottom Anchor

API TUBING PUMPSTH - Heavy-Wall Barrel Pumps with Metal Plungers

TP - Heavy-Wall "Working Barrel" Pumps with Soft-Packed Plungers     (Often referred to as a "standard pump" in Western Kentucky.)

Sucker Rod Pump Gas Lock

Almost a decade ago, Robert M. Parker, a well analyst for Texaco USA, wrote a World Oil article entitled "How to Prevent Gas-Locked Sucker Rod Pumps".  Mr. Parker's insight forever changed the way many of us think about

downhole pumps.  He described two kinds of gas lock.

Type 1 Gas Lock occurs only if the fluid level is greater than 1/3 the total depth to the seating nipple or if a bridge is present that gives the effect of pumping from below a packer (rare).  Expanding gas bubbles "tickle" the balls and seats (valves), and the well comes to equilibrium pumping at very low efficiency and with an elevated fluid level.  The cure for Type 1 gas lock is to use either a snubber cage or a backpressure valve.

Type 2 Gas Lock occurs when a volume of gas is trapped between the valves in a pump.  In a Type 2 gas lock, the peak pressure of the trapped gas on the downstroke is insufficient to overcome the hydrostatic head on the traveling valve.  Then, the pressure is not reduced enough on the upstroke to allow the standing valve to open and admit new fluid.  Both valves are effectively stuck in the closed position and the pump refuses to pump.  This is essentially the opposite of the Type I gas lock, but the results appear the same.  Using a backpressure valve is not the cure for Type 2 gas locks; the practice will actually make the problem worse.

The secret to avoiding Type 2 gas locks is to configure your pumps such that they pump gas nearly as well as they pump liquid.  The key phrase is "unswept volume"...you want as little of it as possible.  Avoid "travel tube" pump designs; stationary barrel designs are inherently better with respect to compression ratios.  Traveling valves should be on the bottom of the plunger, never on top, and use a flush hex seat retainer plug instead of the traditional type.  When spacing the stroke, the traveling valve should come as close as humanly possible to the bottom of the pump at the bottom of the downstroke.  The pull rods in most pumps are too short and should be replaced.  Avoid double ball and seating (it

does not accomplish what it is touted to do anyway).  When the pump closes up, there should be as little void space (unswept volume) as possible, and if you do a good job you will have little trouble with gas lock.  Such nicely designed and executed pumps are frequently referred to as "high compression" pumps.

This is not an academic exercise.  We have increased oil production from wells using this simple technology.  We have been able to pump wells from below packers without a venting scheme.  In general, wells pump better if these easy rules are followed.

In recent years, the high compression concept has stimulated the development of a number of new products.  There were a dozen or more producers of low unswept volume cages; however, most of these entities seem not to have survived the last couple of years of low oil prices.  The major pump manufacturers of course make their own versions of various gimcracks; most of which do not perform particularly well.

But the best and most economical high compression cage is made by EvisonTM Manufacturing Corporation and is available from Poor Boy Supply Company on this very website.  Click here to learn about the Evison TM Oil King TM "OK" HP/P High Compression Open Barrel Cages.

A Shallow Well Pumping Philosophy

Over 25 years of playing with shallow stripper wells has led to a few conclusions (and much less money than other

pastimes might have yielded).  The shallow wells under discussion here are typically less than 1000 feet in depth, but the same principles can probably be applied to wells somewhat deeper.  One fundamental assumption that can be made about most stripper wells is that fluid yield is head sensitive.  That is to say, as the fluid level or head builds up, the oil production rate goes down, until the well reaches equilibrium and is yielding no fluid to the well bore.  It is not unheard of for stripper wells making a barrel or two of oil per day, to almost completely cease to produce when the tubing is raised less than one joint (your author once consulted on a well where less than ten feet made the difference between three bopd and almost no production).

Logically then, we must maintain as low a fluid level in the well bore as possible to maximize production.  The shallow wells under discussion can be pumped continuously if they make more than ten or so bpd total fluid with no damage to the pumping equipment.  Fluid pound will not harm surface pumping structures on such shallow wells, and in fact the "pop in the stroke" used by pumpers of shallow wells to tell if the well is pumping properly is fluid pound.  It is common practice in old shallow waterfloods to pump producing wells 24 hours a day.  In wells making small amounts of total fluids, the same logic applies.  Try a 15 minute time clock and pump the well a few minutes several times a day as opposed to say one hour, once a day; the difference in daily production can be considerable.

A more recent revelation has been the importance of using pumps configured for the highest practical compression.  Except in unusual circumstances, double ball and seat pump configurations should be avoided; double balls and seats generally cause more problems than they cure.  For more detailed information on high compression technology, see

Sucker Rod Pump Gas Lock.  Almost all wells benefit in some way from configuring pumps to maximize compression, but in some cases it can make a big difference in production.

It is common practice in this area to set the pump intake just above the shot hole in open hole completions, or just above the perforations in more modern style completions.  The underlying logic is to prevent atmospheric contact with the formation or perforations.  Minimizing such contact may reduce scale growth and biological fouling.  There are opposing opinions.

We generally recommend against closed bottom mud anchors unless you actually intend to tag bottom with the anchor.  Closed end mud anchors are another "innovation" that typically cause more problems than they cure.

Please contact the Pump Guy if you have ideas, opinions, or experiences relating to this page

"K" Factor - Theoretical Pump Displacement

An incredibly useful engineering calculation for sucker rod pumps is theoretical pump displacement.  This is important information for sizing pumping equipment.  And if we know the theoretical barrels per day (BPD) a particular sucker rod pump installation can lift, we can use this information to diagnose problems.  One simple procedure is to compare the theoretical capacity with the actual production using a simple bucket test.

The calculation is very simple; multiply the "K" factor for the particular sucker rod pump (from the table below) by the pumping unit stroke length in inches by the pumping unit speed in strokes per minute (SPM).  Measure the stroke length in inches at the polished rod / polished rod liner and time the speed with a watch (SPM refers to a complete cycle or revolution of the pumping unit crank).

The formula is expressed as:  P = K x S x SPM

Where P is lifted BPD, K is the pump constant (or "K" factor), S is the stroke length in inches, and SPM is the strokes per minute with one stroke taken as a full rotation of the pumping unit crank.

Note:  For metal plunger pumps, a slip factor must be used to correct for volumetric inefficiency.  For deep wells, rod stretch becomes an issue in the calculation.  However, for shallow wells, especially with soft-packed plungers, this simplified calculation is remarkably accurate.

Example:  A shallow stripper well equipped with a 1-1/2 inch insert pump has an old Jensen D-4 pumping unit with a stroke length of 18 inches, and is pumping at 12 strokes per minute.  Look up the "K" factor for the 1-1/2 inch insert pump - .262.  Multiply .262 times 18 times 12 and find you can lift a maximum of 56.6 barrels per day of total fluid (.262 x 18 x 12 = 56.6 BPD).

Bucket Test

The bucket test is a very useful and "low tech" test method.  It consists of simply timing the filling of a vessel of known volume, and doing the math to determine a flow rate.  It can be used to measure the fluid production from wells (settling time may be necessary to get accurate readings).  As a pumping well diagnostic tool, it can be used in conjunction with calculations of theoretical pump displacement.

The formulae for different size buckets are as follows:

For a 5 gallon container  10,285.8 ÷ T = BPD

For a 3 gallon container   6,171.5 ÷ T = BPD

For a 1 gallon container   2,057.2 ÷ T = BPD

Where T is the time to fill in seconds, and BPD is the calculated flow in barrels per day.

Over the years, we have developed a preference for a three gallon test bucket since nice plastic ones are readily available (plastic buckets must be supported such that they do not distort, which distortion affects accuracy).  The following table applies to three (3) gallon test buckets:

Bird Netting

Several federal laws have been enacted to protect migratory birds, a few dating back to very early in the last century (some of the earliest environmental laws).  These laws are administered by the U.S. Fish & Wildlife Service (FWS), but there are also state laws administered by various state and local agencies.  Oil lease operators can run afoul of the Migratory Bird Treaty Act (MBTA), and potentially other laws, if open tanks or pits result in the accidental death (take or taking) of protected migratory birds.  See A Guide to the Laws and Treaties of the United States for Protecting Migratory Birds, see the MBTA Synopsis, and see Birds Protected by the Migratory Bird Treaty Act for a list of protected birds.  Much additional information is available at the U.S. Fish & Wildlife Service (FWS) Division of Migratory Bird Management website.

The FWS does not distinguish between intentional illegal take of migratory birds (as in illegal hunting), and the unintentional or accidental take, also called incidental take.  A minority of courts have sided with defendants in incidental take prosecutions under the MBTA, but the majority apply strict liability.  The judge in U.S. v. Moon Lake Electric produced a lengthy opinion denying the defendant's motion to dismiss, which opinion should convince any oil operator to take this issue seriously.  It seems unlikely, given the debate at the time, that congress originally intended incidental or accidental take be a prosecutable violation, but that is how the FWS has subsequently twisted this well-meaning law.  The current FWS position turns every motorist who ever hit a bird, and nearly every building owner with a plate glass window into a criminal under the MTBA (it is estimated that between 100 million and one billion birds die annually in

collisions with glass windows).  The bottom line is that the incidental take of a migratory bird in a pit or open tank is now viewed by the FWS as a criminal offense carrying possible jail time and up to a $15,000.00 fine for each bird taken.  The FWS issues permits of course, but not for incidental take on oil and gas leases.

The FWS has been citing oil facility operators in other parts of the country for years (see this FWS Region 6 webpage), but only recently became active in Kentucky.  Because Kentucky operators are not familiar with solutions to this problem, this webpage was created.  Calls to area oilfield suppliers revealed none were even familiar with the concept of netting pits.  Some regulators urge the closing of all pits, but there are situations where pits, lagoons, and impoundments serve a useful or necessary purpose (settling lagoons or impoundments used pursuant to a surface discharge permit, for instance).  In thirty years of oilfield experience, we have never seen a demonstration of an effective method of removing every trace of oil from the surface of pits, and it is a futile exercise in settling lagoons or ponds anyway; even a skim of oil is said to pose a hazard to birds.  Further, because of a lack of a reasonable pit closure methodology in Kentucky* (unlike other oil states), netting of existing pits or impoundments is the only reasonable alternative at this time in Kentucky.

Netting of pits, lagoons, and impoundments can be done fairly inexpensively.  Our friend Gary Brown at American Netting, LLC was a pioneer in working out economical ways to do bird netting (he has been at it for 30 years).  American Netting, LLC is the outfit to call!  We believe the use of high tensile strength fence wire in place of the more traditional wire rope or soft steel wire is the key to an even more economical installation.  Kencove is a major supplier of high

tensile fence materials.

Of course one can ponder why FWS does little or nothing about the millions of birds killed by plate glass windows, but is quick to prosecute selected industries, forcing substantial expenditures that can at most save a handful of birds.  Obviously, while the public would balk at homeowners being prosecuted when a bird accidentally collides with a widow, prosecutions involving the "evil" oil industry, and the equally despised electrical utility industry (accidental bird electrocutions) are common.  Further, it has been our experience that many FWS agents are capricious and vindictive, and some outright lie.  In a case that garnered considerable attention, the Department of the Interior's inspector general (IG) amazingly found that FWS biologists who planted and submitted false hair samples of Canada lynx fur for laboratory analysis broke no laws.  They did, however, demonstrate "a pattern of bad judgment," according to IG Earl Devaney, who criticized the agency for not meting out "more meaningful punishment" to the biologists who were actually paid bonuses, displaying what he called "a cultural bias against holding employees accountable for their behavior."  Closer to home, two FWS special agents were overheard discussing how they were not surprised at the "killers" owned by a local oil producer; the fellow has a few farm cats.  One of these same two special agents actually attempted to provoke a physical altercation with an attorney representing that same oil producer.  Not much chance of a fair shake from government employees with this kind of attitude.

*This has produced some bizarre outcomes, including the "illegal" closure of hundreds of pits, even a few closed by US EPA contractors that the state has declared improperly closed.

Vehicle and Rig Battery Trivia

Over the years I have become frustrated with the confusing battery rating systems and an inability to get straight answers from vendors about lead-acid storage batteries.  The material presented below was accumulated over a period of time from many sources, and has simplified dealing with vehicle and rig batteries for us.

Battery Ratings

There are a dozen or more vehicle battery rating methodologies.  The Society of Automotive Engineers (SAE) has established two ratings for domestic made batteries - Reserve Capacity (RC) and Cold Cranking Amperes (CCA).  The Cranking Amps (CA) rating is also still commonly used.  Industrial batteries often specify Ampere Hours (AH) and marine batteries may carry a Marine Cranking Amps (MCA) rating.  Definitions of these more common rating systems are given below:

RC - Rating in minutes a battery will carry a 25 amp load at 80ºF and maintain a minimum terminal voltage of 10.5 volts.

CCA - Rating in amps which a new, fully charged battery at 0ºF can continuously deliver for 30 seconds and maintain a terminal voltage equal to or higher than 1.20 volts per cell.

CA - Rating in amps which a new, fully charged battery at 32ºF can continuously deliver for 30 seconds and maintain a terminal voltage equal to or higher than 1.20 volts per cell.

AH - (@ 20 hours) a battery having a 100 AH rating must carry a 5 amp load for 20 hours and maintain a terminal voltage of 10.5 volts at 80ºF (100 ÷ 20 = 5 amps).

MCA - Rating in amps which a new, fully charged battery at 30ºF can continuously deliver for 30 seconds and maintain a terminal voltage equal to or higher than 1.20 volts per cell.

Ratings Conversions:      RC = 1.75 x AH          AH = (RC ÷ 2) + 15.5

OpinionModern "maintenance free" batteries do not tolerate abuse as well as older style batteries.  If you are experiencing shorter battery life on your oilfield equipment than you think reasonable, try an older style "maintenance" type battery (one where you actually have to check the fluid level).  If you routinely run down batteries and charge them in the shop (as on old rigs with non-functional charging systems), consider a marine / RV battery; they will take abuse that will kill automotive maintenance free batteries in a fraction of the time.  Finally, if you like maintenance free batteries, consider something other than the maximum CCA rated battery available in a given package size.  To get 1000 CCA out of a small automotive battery, manufacturers use a variety of tricks, like making the plates very thin.  This results in a more fragile battery.  The same package size in a 650 or 700 CCA

rating is likely to be a tougher battery and to last longer in oilfield service.

CHARGING CHEAT SHEET

Charge State

    Charge    Specific Gravity (Sg)      12v  6v       Freeze     100%        1.265 - 1.285       12.6 - 12.68     6.3      -71°F      75%        1.220 - 1.225       12.4 - 12.45     6.2      -33°F      50%        1.175 - 1.190       12.2 - 12.24     6.1      -15°F      25%        1.140 - 1.155       12.0 - 12.06     6.0      + 4°F     Dead        1.110 - 1.120       11.8

Charging Time

1. Down and Dirty Charge Rate Method - Chargers with Ammeters

Charge the battery until the charge rate (as indicated by the charger ammeter) has dropped and stabilized at 1/3 to 1/2 of the charger's full output rating.  For example, a 10 amp charger will stabilize at 3 to 5 amps.  This is an inaccurate method and care must be

taken not to overcharge.

2. Down and Dirty Bubble Method

When the battery fluid is gently bubbling, the battery should be considered charged. 

This is a very inaccurate measure of charge state and care must be taken not to

overcharge.

3. Voltage Method

Charge the battery until an accurate digital voltmeter indicates the following end of

charge voltage:

 Temperature         Conventional      Maintenance Free

95°F              14.2 volts              14.5 Volts

75°F              14.4 volts              14.7 Volts

0°F              15.1 volts              15.4 Volts

4. Specific Gravity Method - Not for Maintenance Free Batteries

Charge the battery until reaching the 100% charge specific gravity (Sg) shown in the Charge State table above.  Disconnect the charger before testing.  Older batteries or batteries with sulfated plates will reach full charge at a lower Sg; continued charging may result in damage.

5. Calculation Method

Determine the percent of charge needed (use either a hydrometer or voltmeter, and refer to the Charge State table above).  An approximate charge time in hours, "Time", can be calculated as follows:

                      Time = .667   (RC)   (Charge   Needed)                                   Charger Rating

                                       or

                      Time = 1.6   (AH)   (Charge   Needed)                                   Charger Rating

Some Cementing ProblemsHISTORY

In 1824, Joseph Aspdin, a British bricklayer, was granted a patent for making a cement he called Portland cement after stone quarried on the Isle of Portland in Dorset, England.  However, this original Portland cement, was actually an artificial hydraulic lime similar to a material called Roman cement, a crude formulation of lime and volcanic ash used as early as 27 BCE (pozzolanic materials are still used in oil well cementing to this day).  It is sometimes reported that Aspdin did his original experiments with his kitchen oven.  The first true Portland cement is believed to have been made in Germany around 1867.

Dealing with water intrusion into oil wells, and the use of cement to prevent such movement, led to the birth of petroleum engineering.  Some primitive oil well cementing may have taken place as early as 1883, but the use of Portland cement to seal casing began in 1903 in the Lompoc Field in California.  Almond A. Perkins was the father of the two plug method of well cementing.  In 1916, Perkins employed Earl P. Halliburton, and in 1919, Halliburton set up shop on his own as the New Method Oil Well Cementing Company, changing the name to the Halliburton Oil Well Cementing Company (HOWCO) in 1920.  Perkins later sued Halliburton for patent infringement, but the case was settled with Halliburton being granted a license to use the Perkins methodology.  Halliburton eventually even licensed inventions to Perkins, but in the end Halliburton wound up buying Perkins.  Halliburton perfected the use of the measuring line and the jet mixer among other well cementing innovations.  Interestingly, over the course of the first 30 years of well cementing, waiting on cement time gradually shrank from 28 days to a mere 72 hours.

BACKGROUND

Most oil well and injection well cementing in the Illinois Basin (and other relatively shallow well areas) is done with common Portland Cement.  Portland cement is made from limestone (or other materials high in calcium carbonate) and clay or shale (iron or aluminum oxides are added if not present in sufficient amounts in the clay or shale).  These basic constituents are finely ground and mixed in the correct proportions either dry (dry process) or mixed with water (wet process).  The raw material is then fed into a rotary kiln and fired at between 2600 and 2800°F causing certain chemical reactions between the raw materials.  The output of the kiln is called clinker, and is ground finely with up to about 2%

gypsum to form the product we all know as Portland cement.

The American Petroleum Institute (API) sets the standards for cements used in the petroleum industry.  Here is a brief listing of the API cement designations:

Class A   Intended for use to 6,000 feet where special properties are not required.  Similar to ASTM Type I (common Portland cement).  Use 5.2 gallons of water per 94 pound sack for neat slurry*.Class B   Intended for use to 6,000 feet where moderate sulfate resistance is required.  Similar to ASTM Type II.  Use 5.2 gallons of water per 94 pound sack for neat slurry*.Class C   Intended for use to 6,000 feet where high early strength is needed (regular or sulfate resistant).  Similar to ASTM Type III.  Use 6.3 gallons of water per 94 pound sack for neat slurry*.Class D   Intended for use from 6,000 to 10,000 feet (retarded).Class E   Intended for use from 6,000 to 14,000 feet (retarded).Class F   Intended for use from 10,000 to 16,000 feet (retarded).Class G   Intended for use to 8,000 feet, and similar in composition to API Class B.  Use 5.0 gallons of water per 94 pound sack for neat slurry*.Class H   Intended for use to 8,000 feet, and similar in composition to API Class B.  Use 4.3 gallons of water per 94 pound sack for neat slurry*.*Water requirements per API for a slurry that will exhibit no water separation upon setting.

A sack of Portland cement can be hydrated with as little as 2.3 gallons of water, but the mixture cannot be pumped.  The minimum water that can be used to mix a 94 pound sack of API Class A / ASTM Type I cement, and it be pumpable, is

3.9 gallons; it will have a density of 16.85 pounds per gallon, will exert 876 psi per 1,000 feet of column, and will yield 1.0 cubic feet of slurry per sack.  The maximum water that can be used to mix a 94 pound sack of API Class A / ASTM Type I cement where there will be no settling of particulate material and no water separation is 5.5 gallons; it will have a density of 15.36 pounds per gallon, will exert 799 psi per 1,000 feet of column, and will yield 1.22 cubic feet of slurry per sack.  API recommends 5.2 gallons of water per 94 pound sack of API Class A / ASTM Type I cement; it will have a density of 15.6 pounds per gallon, will exert 811 psi per 1,000 feet of column, and will yield 1.18 cubic feet of slurry per sack.  Following the API 5.2 gallon guideline results in a requirement of 4.76 sacks of cement per 42 gallon barrel of slurry.

Garden variety Portland cement mixed with over 5.5 gallons of water per sack, and with no bentonite or other suspension additives used, will always exhibit settling.  (Note the addition of bentonite a/k/a drilling mud does not add strength to a light cement mix, but merely keeps the cement suspended until setting.  There are legitimate reasons for doing this, but not typically in shallow wells.)  Neat Portland cement mixed with 5.2 gallons of water per sack will achieve a compressive strength at 60°F (typical shallow ground temperature) of about 2050 psi after 72 hours.  That same cement mixed with 10.4 gallons of water will achieve a compressive strength of a mere 425 psi under the same time and temperature conditions.  Further, the latter mix would require around an 8% bentonite addition to prevent solids settling prior to setting, or some other approved additive.

PROBLEMSIt is apparent most cement mixed in Kentucky, and in perhaps a few other jurisdictions, is being mixed with far

more than 5.5 gallons of water per sack.  The biggest problem with this practice is that the resultant set cement will have a compressive strength much lower than properly mixed cement.  In the majority of these cases, no bentonite or other appropriate additive is being used, so there will be settling.  Further, the cement column weight will be lower than anticipated, and that can be a problem in wells that need the fluid column weight to kill the well for proper setting.

Wells should be plugged and completed with the highest density cement practical under the particular circumstances.  In the shallow wells here in Kentucky, that would almost always be 5.2 or at the most 5.5 gallons of water per sack neat cement.  While I have no statistics, it is likely there have been plugging failures due to improperly mixed cement.  There is no doubt there have been completion failures, but these do not show up on the regulatory radar here as much as they would in say Texas due to differences in the rules on completions (every Texas completion must have a pressure test, a bond log, and the compressive strength of cement is specified).  Notably, in overpressured wells, the heaviest practical cement slurry may be crucial to even get a successful plugging job absent setting a bridge plug.

It is customary practice to catch cement samples in little Styrofoam cups during the cement job, but many times I have seen the cementing contractors pour off the separated water before handing the sample to the oil operator or to the resident regulatory inspector (it takes a few minutes for separation to occur and it will not be evident at the mixing unit itself).  I think the problem here is a lack of recognition of the significance of separated water.  If the mix has 5.5 gallons per sack or less, there will be no free water separation (or only a trace), and the entire mass will gel / set

in the sample cup (this assumes a neat cement with no additives).  The assumption seems to be if the stuff gels / sets at all it must be mixed properly.  In fact much of the settling seen in wells in the field is likely attributable to settling of slurries mixed with more than 5.5 gallons of water per sack.  And inspectors do not generally hang around long enough to really determine what the ultimate settling will be, an additional potential problem.

Ignorance of proper procedures is a large factor here, but there is a darker side to this problem.  Contractors using bulk cement equipment have the opportunity to sell the same cement more than once.  For instance, a 5.2 gallon mix will yield 1.18 cubic feet per bag, while a 10.4 gallon mix will yield 1.92 cubic feet per bag.  Since everyone uses the Halliburton cement tables in the Halliburton cementer's bible, and the tables are based on a 5.2 gallon mix, the contractor has an opportunity to charge for much more cement than is really used, and oil operators are none the wiser.  Further, contractors using centrifugal pumps, tend to mix thin to save wear and tear on equipment (and if they are using a bulk truck, they get to play the selling it twice game as well).  I want to make it clear that this is not an argument against the use of centrifugal pumps for cement mixing because I have personally mixed 15.6 pound per gallon and even a little thicker neat cement with my own centrifugal pump cement mixing rig in years gone by.  If concrete suppliers engaged in this practice, it would be noticed since it is well known that skimping on cement or using too much water results in weak concrete, but oil well cement goes down a hole and is never seen again.This practice persists because oil operators and inspectors lack the equipment and/or knowledge to catch the problem.  A true neat slurry mixed with 5.2 gallons of water per sack of cement will have a density of 15.6 pounds per gallon (the

API preferred mix).  But a slurry mixed with 10.4 gallons per sack will still weigh 13.1 pounds per gallon, and even to the trained eye looks quite heavy and thick (plain water is 8.33 pounds per gallon).  The "finger test" used by some inspectors cannot distinguish between these two examples with any degree of reliability.  Putting this example in perspective, the 5.2 gallon neat mix will exhibit compressive strength at least five times greater than the 10.4 gallon mix, and the 10.4 gallon mix will undergo some settling.  Stated bluntly, absent the use of a cement / mud balance or a hydrometer, nobody can be certain of cement density (some of the big cementing companies have continuous reading densitometers on their mixing units, but this would not likely be encountered in Kentucky).  Oil operators and regulators alike have been at the mercy of cementing contractors, and they do not always mix cement as they should.

Both the EPA Region IV Underground Injection Control (UIC) Program with jurisdiction over injection wells in Kentucky, and the Kentucky Division of Oil and Gas (DOG) with jurisdiction over oil wells, need to adopt standards that require cement to have a preferred density of no less than 15.36 pounds per gallon (this corresponds to the maximum 5.5 gallons of water per sack ratio mentioned above).  Under no circumstances should cement be pumped with a density of less than 14.0 pounds per gallon, but it is being done every day in Kentucky at present.  Inspectors should also be equipped with inexpensive drilling mud balances to make field measurements of cement slurry density.  I would hazard a guess that the majority of the cement mixed for well plugging, remediation, and new completions in Kentucky has been mixed with far too much water for optimal results.  Granted, light cements are sometimes used in deep wells, but that is seldom the case in Kentucky to date.  The major service companies like Halliburton do not play these games,

but the majority of the smaller independent service companies seem to, some with a vengeance.  Why has this been allowed to go on for so many years?

See our Cement Bond Logging Overview for basic information on cement bond logging technology.  Contact us if you need more detailed information.

Water injection, or waterflooding, is the oldest enhanced recovery method.  Waterflooding was born over 125 years ago near Pithole City, Pennsylvania.  As is often the case with new technology, the earliest water injection for enhanced recovery was almost certainly an accident.  Water from a shallow aquifer leaked into an abandoned well, or possibly leaked around an early packer, entering the oil bearing rock formation (pay zone).  While this was disastrous to future oil production from the affected well, it was noticed that oil production rates increased in nearby wells.  In a published report in 1880, John F. Carll had already observed that water injection not only increased oil production rates, but appeared to increase ultimate oil recovery.  By the 1890s, waterflooding was very successful in the Bradford, Pennsylvania area.  Water injection for enhanced recovery was slow to expand outside Western Pennsylvania, in part because the practice was rendered illegal in many jurisdictions by early oil conservation laws.  This gave rise to some clandestine waterflooding during the first quarter of the twentieth century.  But waterflooding slowly gained in popularity with many pilot projects started in

the 1940s, and by 1955, there were nearly 2,300 water injection projects in 17 states.

A Few Tips

We have over 30 years of experience with shallow waterfloods in the Illinois Basin, some less than 300 feet deep.  Here are a few things we have learned along the way.

Water Meters are necessary to effectively and properly operate a waterflood.  See our Water Meter Trivia page, with its links to additional water meter service notes pages, for some useful information on water meters.  If pressures are not too high, it is possible to use relatively inexpensive domestic (household) meters.  It is a trivial matter to modify these low pressure meters to read out in 42 gallon barrels.  There are also some newer multi-jet meters on the market in various pressure ratings that look promising for waterflood applications.

PVC Piping has long been used for oil flow lines, but it is an attractive injection line piping material if operating pressures permit; it is essentially immune to corrosion.  One inch Schedule 40 PVC will safely work to 450 psi conveying cold water, and one inch Schedule 80 PVC pipe will safely work to 630 psi conveying cold water (published industry numbers).  If you can find it, the bell end pipe is much more dependable than the stuff with factory glued on couplings.  We like Oatey brand All Purpose Cement (red label); it does a better job under adverse conditions than any other solvent cement we have tried.  Use PVC pipe cleaner for best results, but the primers (often purple) are a waste of time and money (and try not to get too high off the glue and cleaner fumes).

Copper Tubing makes a nifty connection from the water

supply line to a water meter attached to the well head.  Rather than hard plumbing the well head to the water supply riser pipe, we use a loop of 1/4 inch OD ACR (Dry Seal) copper refrigeration tubing connected with flare fittings.  1/4 inch OD ACR copper tubing is good for 1,406 psi up to 100 degrees F, and good for 1,125 psi at 200 degrees F.  This approach simplifies the pipe fitting job, but it has another big advantage.  In the event of a water meter or other mechanical failure associated with the well, the loop of small diameter copper tubing will limit water flow to some extent, preventing the complete collapse of the injection system, but still allowing easy detection of individual well problems for wells taking no more than a couple of hundred barrels per day (shallow injection wells often take less than 100 barrels per day).  Incidentally, copper pipe used in the air conditioning industry is always referred to by its outside diameter, but copper pipe made for use by plumbers is referred to by its nominal inside diameter (do not bother asking why).

Plastic Tents make a cheap and effective injection well cover.  Kenneth Ingle, our good friend and "poor boy" oil field innovator, began using polyethylene contractor plastic film as an injection well cover over two decades ago.  The idea is to drape 6 mil black polyethylene film, available at any builders supply store, over the injection well and to anchor the perimeter on the ground with a few shovels full of dirt.  We often make a slit that fits tightly around the top of the water meter so readings can be taken without uncovering the well.  This scheme provides just as good freeze protection as fancy boxes placed over the well (short of a heater in the enclosure, no cover will protect against freezing if the waterplant fails on a cold night).  Do not use clear plastic or you will create the greenhouse from hell, and it does not weather well absent the carbon pigment.

100 Barrels Per Day (BPD) is close to 3 gallons per minute (gpm).  The actual conversion factor is 2.917, but for most practical purposes the 3 gpm approximation can be used.  This incredibly handy "rule of thumb" conversion factor is helpful in estimating injection rates, production rates, and just about any situation involving flowing liquids in the oil patch.

Water Meter Trivia

In any waterflood project, every injection well should be equipped with its own water meter (flow meter).  It is impossible to evaluate waterflood performance without individual well injection rate and cumulative injection data.  Further, we have no better tool to evaluate the ongoing mechanical integrity of injection wells than careful monitoring of the injection rate (not to be confused with  periodic mechanical integrity tests performed usually every five years).  EPA has underestimated the value of individual well flow monitoring allowing the use of manifold monitoring, presumably based on bad information (see Water Meter Mistakes and Manifold Monitoring).  At the very least, a few water meters should be rotated between wells to get a reasonable idea of individual well injection rates.

Many different water meters have been used in the oilfields.  The oldest meters were mostly of the nutating disc variety.  The measuring element in such a flow meter consists of a disc mounted in a circular chamber.  A partition or division plate that extends in from the chamber wall separates the inlet and outlet ports.  Said plate fits in a notch in the disc

and prevents rotation of the disc about its axis.  The flow of liquid through the meter imparts a wobbling action to the disc, called nutation.  This nutating action of the disc is such that the upper part of the shaft on which it is mounted travels in the shape of a cone with the apex pointed down.  The lower face of the disc is always in contact with the bottom of the chamber on one side while the upper face of the disc is always in contact with the top of the chamber on the opposite side.  Thus the chamber is divided into separate compartments of known volume, and as the flow of liquid actuates the disc, these compartments are successively filled and emptied, providing smooth continuous measurement.  Connection between the disc shaft and a spindle dog transmits the motion to the register.  Some models have an internal gear train and some have a magnetic coupling scheme that eliminates the need for a stuffing box.

The following is a collection of information on nutating disc water meters that have been historically used in the oil patch, followed by a brief discussion of other meter types:

Niagara Meters

See our Buffalo / Hersey One Inch Niagara Water Meter Service Notes.

The Niagara water meter was very popular during the first big waterflood boom.  Literally thousands of these meters were sold in Kentucky alone in the 1950's.  The Niagara industrial meter dates back to 1859, and was originally manufactured by the Buffalo Meter Company of Buffalo, New York.  Buffalo's domestic (household) version was called the American water meter, and some parts a re interchangeable with the Niagara.  The one inch Niagara meter uses the same measuring chamber as the old 5/8 inch American

domestic meter.  Hersey acquired the American and Niagara lines, and now the Niagara line belongs to Venture Measurement.  One of the Niagara products is the good old Niagara nutating disc water meter, with accuracy of ±1.5% and repeatability of ±0.25%.  Niagara water meter repair parts are available from Venture, but they are sky high!

The Niagara water meter was offered in a high pressure version good for 1,440 psi.  The standard six bolt version was offered in iron with a cold water pressure rating of 300 psi, and in bronze with a cold water pressure rating of 200 psi.  These pressure ratings were very conservative, and these meters have been routinely used at higher pressures (AnaLog Services, Inc. does not endorse or recommend exceeding manufacturer pressure ratings).  Historically the repeatability of Niagara meters has always been stated as ±0.25%, but the accuracy has varied in company literature from 2% down to ±0.5%.  Accuracy of Niagara meters was historically expressed as a percentage variation over the full recommended flow range, not as a percentage of full flow.  It was therefore stated that the percentage variation is improved as actual operating flow range is reduced.

We have repaired hundreds of Niagaras, but it would be a fib to say we like to work on them.  The best thing that can be said about them is that their measuring chambers look like tiny flying saucers.  But those measuring chambers are more delicate than most, and they seldom survive a freeze without irreparable damage, even when the meter housing bottoms do not crack.  The Niagara meter has a host of other problems, including a very short lived open gear train when used in oilfield service (there is a closed gear train that is a little better).  We have a considerable stock of complete Niagara meters and repair parts, but we do not generally recommend Niagara meters.

Five Pointer / 504 Meters

See our 504 Water Meter Service Notes.

The original "Five Pointer" water meter was a big heavy beast manufactured by Rockwell (do not drop this one on your foot).  It dates back to at least the 1940s, and there was still a version of it in production into the 1960s.  It is immediately recognizable by its large size, antique styling, and its eight bolt housing closure with 1-1/4" male pipe connections (the literature indicates there was a 1/2 inch and one inch version, but we have only seen the one size).  We have a few of them in our collection of water meters, but have not repaired one in 15 years or more.  There was also a 5,000 psi rated "Five Pointer", but it seems to use a different measuring chamber than either of the other two mentioned herein.

Around 1960, Rockwell introduced the Model 504, an excellent design they also referred to as a "Five Pointer".  Rockwell's domestic (household) version was called the Arctic water meter, and some parts are interchangeable with the 504.  The 504 can use the measuring chamber from the 5/8 inch Arctic domestic meter (there was a Tropic domestic meter also, but its measuring chamber has the wrong taper for the 504).  By the early 1970s, Brooks, a division of Emerson Electric Company, had acquired the 504 meter from Rockwell.  In late 1981, Brooks threatened to discontinue the 504, but reconsidered and raised the list price to $492.00.  A few years later they kept their promise and ceased to produce the 504.  Blancett, Inc. produced a 504 clone, their Model 500 water meter with a published accuracy of ±2%, listing for $545.00 in 2001.

The Rockwell / Brooks 504 and the Blancett 500 have a bronze case rated at 2,000 psi.  The Rockwell / Brooks 504

has a Nickalloy measuring chamber and internal gear train.  The Blancett 500 has a magnetic drive with no stuffing box, but it uses a less desirable plastic measuring chamber.  Blancett also sold a retrofit kit to convert old 504 meters over to their magnetic drive mechanism and their plastic measuring chamber for $224.00 in 2001.

The 504 is a good meter for waterflood applications, and they are reasonably easy to service.  They have decent freeze survivability.  The metal measuring chambers are becoming difficult to find.  We have a few complete 504 water meters in stock, and a fair stock of repair parts. called the Well-Flood water meter.  It was produced in a 5/8" x 3/4" and a 5/8" x 1" configuration rated at 2,000 psi, and in a larger one inch version rated at 1,000 psi.  These meters were based on the famous Trident domestic (household) meter line, probably the most successful water meter design in the history of that industry.  Tridents were made in two versions, the cast iron bottom (CIB) for areas subject to freezing, and the split-case version for the deep south and for basement installations.  Nearly all the parts from the Trident can be used in the Neptune Well-Flood meter, but only the measuring chamber from the spit-case version will work due to the required chamber taper.  These meters are workhorses, and a pleasure to work on.  Unfortunately, not many are around.  The Well-Flood meter is apparently no longer available, but the Trident line has lived on as the Type S (Green Seal) industrial meter.

We have had good luck using the old Trident, and the newer Triseal / Trident 8 (an upgrade of the Trident with magnetic

coupling and no stuffing box) as shallow waterflood water meters.  The CIB Trident and Triseal will easily function to 300 psi, and higher with special steel bottoms (though the inherent freeze protection of the CIB is lost).  We use the CIB version outside because of its better freeze survivability, and the split-case version inside (in water plant buildings).  Parts are still available to some extent.  Though countless Tridents and Triseals have been scrapped for their brass, many are still in circulation, and quite a few are still in use by water utilities.  We have been servicing Trident / Triseal meters for shallow waterflood service for over two decades.  We have a considerable stock of complete Trident and Triseal meters and repair parts.

Other MetersMore recently, impeller and turbine meters have become commonplace for waterflood applications.  Brooks sold many 792A and 793A vane meters prior to abandoning the market.  Blancett's Model 900 impeller meter is still available and listed for $570.00 in 2001.  Multi-jet water meters (long the standard in Europe) look promising, but have had little application in waterflooding.

Also see Injection Well Notes.  Contact us if you have water meter questions or needs

Neptune MetersSee our Neptune / Trident Meter Service Notes.

Neptune Meter Company produced a high pressure water meter for the oil fields

Strategies for Combating "Gas Lock"

 Type 1 Gas Lock   (World Oil June 1992 Vol. 213 No 6) occurs only if the fluid level is greater than 1/3 the total depth to the seating nipple or if a bridge is present that gives the effect of pumping from below a packer (rare).  Expanding gas bubbles "tickle" the balls and seats (valves), and the well comes to equilibrium pumping at very low efficiency and with an elevated fluid level.  The cure for Type 1 gas lock is to use either a snubber cage or a backpressure valve.  I prefer the backpressure valve

because it is easier to adjust and repair.       Type 2 Gas Lock (World Oil June 1992 Vol. 213 No 6) occurs when a volume of gas is trapped between the valves in a pump.  In a Type 2 gas lock, the peak pressure of the trapped gas on the downstroke is insufficient to overcome the hydrostatic head on the traveling valve.  Then, the pressure is not reduced enough on the upstroke to allow the standing valve to open and admit new fluid.  Both valves are effectively stuck in the closed position and the pump refuses to pump.  This is essentially the opposite of the Type I gas lock, but the results appear the same.  Using a backpressure valve is not the cure for Type 2 gas locks; the practice will actually

make the problem worse.      (Paraphrased with the Authors Permission)      The picture at the left shows a bottom hold down insert pump in the fully closed position as it would  normally be       sent out from

most shops before 1992.  It has a conventional seat plug and traveling valve assembly.  The red area is that part of the   pump where a TYPE 2 gas lock would occur.  The best strategy would be to decrease the volume in the "red" area.  That would give a higher compression ratio to the pump and the pressure on the gas could conceivably raised to a point where it would overcome hydrostatic load on the traveling valve. (Compression of this pump would be about 28:1 and it would gas lock easily at depths below 3000 feet and stroke lengths less than 120 inches)  As pumps are run ever deeper the hydrostatic load becomes greater and the value of increased compression rises.  Common methods of increasing compression include (1) Longer valve rods, i.e. cut the valve rod such that TV to SV distance is 1/2" or less. (2) Install "hex type seat plugs".  These plugs add a small amount of length to the valve rod.  (3) Use "high compression" standing valve cages.  Standing valve cages designed for maximum compression are available from

such suppliers as HIVAC .       Of course the most common method of increasing compression is lowering the rods until the pump "bumps".  If you incorporate the mechanical advantages outlined above you will have better success even when you do have to "bump" the pump.      As an aside it is much faster to adjust rod spacing on wells that have a "solid" spray metal polished rod than it is with the more common "liner" on a polished rod type.