The "advanced fluid level gun and system" described in this paper is exclusive
to WellSonic LC and describes their patented AGR, programs and systems.
For Monitoring and Control Systems to function this effectively and reliably, cutting edge innovations were required in several disciplines. This paper deals with the unique properties of the advanced pressure wave required to ascertain solid information from a wellbore. Future papers will deal with a series of new concepts and devices required to create such a wave, the ultra sensitive and selective microphone and acoustical reception chamber, and the beyond "state of the art" processing of the received and recorded data. In the interest of advancing the art, a series of six papers is planned for release to coincide with public disclosure of the related topics.
Automated Continuous Fluid Level Monitoring
This technical Paper was authored and presented by Stephen A. Lieberman PE at the 2005 SPE Production Symposium. Mr. Lieberman is president of American Energy Advisors in Denver, Colorado.
Most well controllers require a pumping unit installation and difficult data analysis to determine and regulate for optimum well productivity. Wells with ESP's, PCP's or no pump (such as flowing wells, gas wells, etc.) require complicated and expensive equipment to accomplish the same goal. However, a wellhead-mounted, remote-operated, high-sensitivity acoustic fluid level "gun" has been developed which propels a "pressure wave" into the casing up to 100 times per day and sends the information (including casing pressure and other essential data) to any location (if desired).
Based on the information gathered (and automatically or manually analyzed), the units can be set to: regulate pumping speed; shut a well on and off ("time-clock" a well); trigger pump-off or other alarms; shut in safety valves; regulate chokes. In addition, the instrument's advanced "wave form" generation combined with an ultra-sensitive microphone can accurately detect the fluid level, perforations, holes in casing and tubing, paraffin/scale buildup, as well as down-hole equipment location within 5-10 feet in wells up to 20,000 feet depth.
Unlike most fluid level data, the information can be presented digitally on any computer, and adjusted to any sensitivity to maximize the accuracy of as well as the amount of data that can be gathered and utilized. Third-party analysis and monitoring can be arranged for companies that have minimal or no technical support. Important to note is that this technology is available for approximately the same cost as the well controllers offered by the industry today. Now one truly CAN "stick your head down there" and see just what's going on, as often as desired.
The advantages are obvious: minimize expensive electrical use; maximize life of well equipment; produce everything that enters the well; true determination of well productivity; prevent or quickly identify downhole problems; control wells safely onshore and offshore; identify gas well loading; minimize labor costs and human error.
Record hydrocarbon prices as well as increasing world demand have placed unprecedented pressure and responsibility on oil producers to maintain maximum production from existing wells. At the same time the attention of most company's already "lean" engineering and field staffs are primarily diverted to drilling and developing new reserves. Automation of field operations has increased dramatically as a result. In short, oil company staffs more increasingly utilize a hands-off approach to conduct existing field operations efficiently whenever such methods are available, while delegating most daily field problems to non-technical field personnel.
There are more than 880,000 wells actually producing in the world, of which approximately 830,000 (94%) utilize artificial lift of various kinds. More than 560,000 (67%) of these are located in the US and Canada (REF 1) , and are responsible for the vast majority of the 11 MMBOPD produced there. The maintenance and optimum production (maximum rate, minimum cost) of these wells is essential to maintaining this domestic production.
Most artificial lift methods are installed using original well completion production parameters. Occasional maintenance such as pumping speed changes, repairs, etc., is conducted, otherwise the wells are left to produce whatever they can. As production declines well timers are routinely installed to maximize equipment life and lower operating costs where electricity is available, and most field personnel are quite adept at identifying and repairing problems with surface equipment. However the only down hole diagnostic tools available are (1) dynamometer readings or occasional acoustic fluid level measurements performed by contractors, and (2) dynamometer-based well controllers and fluid level tests performed by company field personnel with varying experience levels of using and interpreting such methods. Without a dynamometer - based controller there are no methods to continuously inform the engineer or field personnel that a down hole problem is developing or exists, and the problems that ARE identifiable are limited to those related to down hole rod pump installations and gas interference. Most other common down-hole problems such as casing holes, tubing holes, and paraffin and scale problems, can't be identified without costly and invasive procedures. In addition, nothing is available to determine whether a gas or oil well has the potential to produce more gas and/or fluid.
MAXIMIZING WELL PRODUCTIVITY
Simply put, well productivity is maximized in (1) an oil well by producing all fluid that enters a well bore, in (2) a gas well by eliminating any back pressure on the formation in the form of fluid over the perforations, and (3) in all wells by first determining bottom hole pressure and then utilizing the resulting pressure data in established formulas to determine well productivity. If the calculated productivity is approximately equal to actual production and a well is "pumped off", the well is producing at maximum well productivity. If the calculated productivity is more than actual production, stimulation should be considered.
GATHERING PRODUCTIVITY DATA
GAS WELLS: In a gas well it is generally accepted that when fluid over the perforations is removed, the well will produce its maximum productivity against existing pressure restrictions (valves, sales line pressures, etc.). The existence of fluid over the perforations is determined by acoustically measuring (taking a fluid level survey) the distance to the fluid in the well, if such measurement can be accurately taken. If fluid exists above the deepest perforations, artificial lift is usually necessary to remove it. However, such gas wells regularly unload and "kick out" fluid, and many fluid levels would have to be taken to ultimately make the decision to invest in equipment. Many times this fluid level cannot be accurately determined, so equipment is not installed and maximum productivity suffers. Of course the operator can perform a bottom hole pressure analysis using a pressure bomb, and then the determination to stimulate and/or add equipment can be made. When fluid levels CAN be determined, and if the expenditure for equipment can be justified, regular fluid levels must still be taken to determine if the equipment is sized correctly and fluid removal is complete. Again a bottom hole pressure analysis should also be performed using fluid level data (REF 2,3,4) or a pressure bomb to determine maximum productivity.
OIL WELLS: In an oil well, most down hole diagnostic data for wells with artificial lift is gathered using acoustic fluid level measurements, assuming the well can be surveyed accurately with an acoustic wave-generating tool. When a fluid level survey IS possible (sometimes noise, packers, foam, depth restrictions, acoustic velocity variations, etc. interfere), and if a fluid level exists above the perforations, more fluid can be produced, and normally should be to maintain maximum productivity. However this fluid level may exist for any number of reasons such as undersized equipment, gas interference in the pump, mechanical problems, setting the pump depth above the perforations, etc. If resizing is the problem, either a pressure bomb or acoustic fluid level measurements can be used to determine static and producing bottom hole pressures. The resulting pressure data can be used to determine productivity index (PI), and PI is then utilized to determine if artificial lift equipment can be economically resized. As described above, this pressure data is also used to determine maximum well productivity by deciding if the well is a stimulation candidate.
A major drawback to this method is that many fluid level surveys are necessary, at significant cost and personnel time. In addition, most operators cannot afford extended down time to determine the necessary shut in pressure data. If fluid level surveys cannot be accurately determined, a wireline pressure bomb is again needed. As a result, maximum well productivity is generally unknown for most oil wells.
AUTOMATIC WELL CONTROLLERS
Use of well controllers has been increasing as oil field operations progress into hands-off operations and automation develops. Today's controllers generally consist of "dynamometer-based" technology for rod pumps only. These detect certain surface problems (under or over loaded motors, downtime, gearbox wear, etc.) and some down hole mechanical problems (worn, broken, or stuck rod pumps, gas interference in the pump, etc.). Calibrated load cells that are permanently installed on the polished rod provide extremely accurate data, assuming the technician can read and understand it, and the hole is straight. Clamp-on load cells have always been questionable as to their accuracy due to rough surfaces in polished rods, adding additional load to the system by simply claming on the cell, variability in care taken by the operator (or rig crew) to place the cell on the polished rod, and the simple fact that the polished rod was not designed to be the spring element of a precision load transducer (REF 5) .
Beam well controllers are also used to a lesser extent, which have transducers that detect surface problems as well as infer downhole problems based on varying motor loads, walking beam movements, and gearbox problems. Both controllers are used to time the pumping cycle to assure that the pump is always filled (if possible), or shut the unit down if there is a problem. If a problem does exist, the operator must interpret the information stored or transmitted from the controller and find the problem. Hopefully they can all read dynamometer cards, or have field or office personnel who have the time and are experienced enough to diagnose the problems associated with varying rod load and run time, as well as pump card anomalies.
The most advanced controllers are linked to sophisticated computer programs. The data can be analyzed with extreme accuracy, and stored messages and analysis results can be gathered by the field operator to help with well diagnosis after certain problems develop. Further advancement in field communications along with the expanding use of the internet allows these messages to be organized in any manner desired and sent to a central field office for action, or even to operator's offices in the form of morning reports and e-Mail notices of daily emergencies.
For the most part however, all controllers either stop the rod pump if a problem has occurred (or sometimes is developing), or accurately time the pump cycle to control pounding. There are no controllers that give a daily determination of whether or not a fluid level exists in the well (which could indicate a problem is developing), or that give a quantitative determination that a well is simply capable of making more production.
Some companies are developing expensive and delicate controllers for electrical submersible pumps (ESP). These can be installed using down hole sensors and motor speed regulators that help eliminate pumping off and the resulting motor burnouts. If the static fluid level in the well is known (or can be accurately determined), the sensors can then be set around this data to keep the fluid level within a desired range. The same communication devices referred to above can be utilized to advise field or office personnel of most problems. Reports from the vendors indicate that these controllers work well and ultimately save money if the sensors are not damaged when running in the hole, if down hole conditions do not affect their operation (CO2, H2S), and if rig crews have placed them accurately.
Controllers for other forms of artificial lift have not been developed, however the development of some of the communications devices using radio or Internet can serve as controllers "in effect". An operator can have most of the important operational data from control boxes on progressive cavity pump instillations (PCP), gas lift wells, plunger lift installations, and hydraulic installations transmitted regularly or even continuously to their central or desktop computer. Therefore, if a problem develops necessary personnel can be advised. Some of the operation of the equipment can be controlled from the office on plunger lift and gas lift controllers, and alarms can be sent to advise as to whether the wells are producing or not. Again, none provide down hole advice as to maximum productivity.
FLUID LEVEL DIAGNOSTICS FOR MAXIMUM WELL PRODUCTIVITY
Fluid level surveys have been accepted as the primary diagnostic tool for down hole monitoring and problem confirmation. The level of fluid in a well is the first thing an operator checks if production drops. In stripper wells and rod pumps that pound fluid, fluid levels are run at some time in the well life to determine if the well is really pumped off, or if gas interference in the pump is a problem. Occasional fluid levels are taken to identify pump problems as they develop, and/or to monitor bottom hole pressure and fluid entry variations such as in water floods, water drive reservoirs, and most other secondary or tertiary recovery operations. Acoustic fluid level measurement is the cheapest and least invasive way to determine bottom hole pressures for reservoir evaluation. It is the main tool used to determine if a well controller is necessary, or once installed, is working properly. They are also routinely used to confirm manual pumping cycles when well timers are used. In fact, if used within current acoustic wave generation technology limitations, fluid level surveys can be used to diagnose problems in any well with a packerless completion, and for any type of packerless artificial lift method. The type of production does not matter.
Many companies own their own acoustic wave generators (fluid level" guns") and survey machines. Most do not. Those that do generally set up evaluation cycles with field staff to visit the wells on a certain schedule to determine if the wells are pumped off, assuming each well is evaluated correctly based on its unique characteristics, and that the well can be surveyed at all using existing technology. Those companies that do not own equipment depend on contractors to run fluid level surveys at a cost of $40.00 to $300.00 per well, per shot. Some companies consider this data essential to efficient operations and perform contract surveys as frequently as weekly. The vast majority considers this cost too expensive, and use surveys as a diagnostic tool only when production has dropped. As a result maximum productivity is not usually known for most wells.
FLUID LEVEL SURVEY LIMITATIONS
Today's fluid level survey equipment has limitations. Some of these limitations are commonly known, some are not, and an error in a fluid level measurement can cost an operator a lot of money in workover costs or equipment revision. Most limitations or inaccuracies are due to acoustic velocity variations, acoustic wave generation capabilities, and "noise".
ACOUSTIC VELOCITY: Many operators do not know what acoustic velocity is or how it affects their fluid level survey results. When a well is acoustically surveyed, a pressure wave (having the same characteristics as a sound wave) is created by an acoustic wave generator (commonly referred to as the "gun") attached to the casing. This wave travels down the well bore, either bouncing off variations in diameters (collars, anchors, casing hangers, scale, paraffin, etc.) or being absorbed by holes in tubing or casing (including perforations). It eventually reflects off the fluid level in the well (or TD) and travels back to the surface along with any other reflections. Most of the time these reflections are "heard" by a microphone in the gun. They are then either printed out on a strip of paper for the field operator to evaluate, or fed into sophisticated computer programs for more detailed evaluation by the field operator or office personnel. Acoustic velocity is how fast this wave travels in the well bore environment. Pressure waves, like sound waves, travel faster or slower depending on the density, pressure, and temperature of this well bore environment, however they are not strong enough to penetrate fluid.
Why is this important? In short, the distance to the fluid level in a well is based on a simple function:
Where: D = Distance to fluid (feet)
T = Time from generation of the pressure wave until it hits something and is reflected back to the microphone (seconds)
V = Acoustic velocity (feet/second)
The function is divided by 2 because the pressure wave is not received by the "gun" until it travels to the object (or fluid level) and back , which is twice the distance. The survey machine attached to the "gun" measures "Time" in this function. The time to a certain reflection can be determined by looking at the survey machine's paper survey strip (assuming it is accurately marked in milliseconds) or the computer output. However, acoustic velocity must be measured in some way. If one knows the gas gravity, pressure, and temperature of the casing environment of every well surveyed, it can be determined from charts [REF 6]. It can also be measured in a lab from a gas sample. But how useful is the acoustic velocity obtained from these sources? A simple example using typical "field" assumptions can illustrate the potential inaccuracies:
Assume an average 7000 foot well with the pump intake set at 6900 feet. Measured surface temperature is about 70 F and surface pressure from an accurate gauge on the casing is 100 psia. Gas gravity is commonly assumed about .6 unless it is actually measured by a gas purchaser or a lab. If only this data is used, which is quite commonly the case with contract services, the acoustic velocity according to published charts at surface is 1375 ft/sec. Assuming for this example that the time to a fluid level indication ("kick") and back that is read from the fluid level surveyor strip chart is about 9.5 seconds (a little faster than the speed of sound in air), the fluid level is located at 6531 feet. Conclusion: About 369 feet of fluid over the pump. It is possibly time to speed up the unit or resize the equipment, so proceed to gather productivity index data.
However, the pressure of a uniform gas column with a gravity of .6 increases with depth, and pressure is about 116 psia at 6900 feet. The estimated temperature (from well logs) at pump depth is 140 F. Using the charts again, the acoustic velocity at pump depth is now 1460 ft/sec, and the fluid level is calculated to be at 6935 feet. Conclusion: There is no fluid over the pump.
Further, however, it is possible that the specific gravity of the gas at depth is close to .8. Unless the well is flowing and the gas column is uniform, heavier gas settles in layers, and higher gas gravity near pump depth is probably more realistic. The new pressure at pump depth is 122 psia, the new acoustic velocity from the same charts is 1240 ft/sec, and the fluid level is located at 5890 feet. Conclusion: there is 1010 feet of fluid over the pump. Or is there? The gas gravity was probably approximately .6 at the top of the well, but closer to pump depth it could be closer to .8. Is integration now necessary to estimate an average specific gravity? Where do the "gas layers" start? The answer is unknown.
This example shows the sensitivity of acoustic velocity to true fluid level measurement. Since pressure and temperature varies with depth and gas gravity can vary according to the gas constituents, the cost to build a chart using gas samples in a lab to account for all conditions, most of which are assumed or averaged or assumed anyway, would be prohibitive and inherently inaccurate.
How IS acoustic velocity accurately determined then? Most acoustic waves generated by today's guns can clearly show tubing collars to a depth of about 4500' to 6000'. If an average tubing joint length is known from a tubing tally, the actual distance to the fluid level reflection can be physically measured on the paper strip output (or computer readout) by counting ALL the collars to determine how many joints to a fluid level reflection, and multiplying by the average length per tubing joint. Since the time is (usually) marked on the paper strip, the survey machine gives a true well bore measurement of acoustic velocity in feet of tubing per second while considering actual variations in gas gravity, temperature, and pressure.
ACOUSTIC PRESSURE WAVE GENERATION : It must be emphasized that to consider all of the possible casing environment variations, ALL of the collars must be measured from the top of the well being surveyed to the fluid level "kick". Most contractors and operators use the paper strip chart or computer program to locate ten tubing collars near the top of the well, multiply "ten" by an average tubing joint length of 31 feet, and then use dividers (or computer program "markers") to measure the time for the wave to travel the distance of the ten joints using the chart data. Tubing joints at the top of the well are used because they are close to the "gun" where the pressure wave is "new" and "strong", and therefore reflections are clear and easy to see. Current acoustic wave generators create a wave that dissipates as it travels deeper into the well until their microphones can no longer see the collar reflections, and the strip output degrades into "rounded bumps" or eventually a flat line. Beyond a depth of 4500' to 6000' (depending on well conditions), collars usually cannot be counted. In addition, the operator has usually not been given a tubing tally to determine a more accurate wave travel distance. Although the average tubing joint usually IS about 31 feet, assuming an average tubing length of 31 feet when the true average is 30.5 feet would affect the fluid level measurement by 100 feet in the above example. In reality tubing joints vary from 28.5 feet to 32 feet.
NOISE : No fluid level survey can be taken if "screaming" gas production, "banging" or "clunking" pump equipment, or any other ambient or continuous noise is "heard" by the microphone in the acoustic wave generator, which masks the frequencies of the wave reflections.
The inherent inaccuracies become evident. As shown in the example above, using the acoustic velocity of the wave at the top of the hole can affect the true measurement of the fluid level by hundreds of feet (or more), or even give a false indication that there is additional fluid to be produced when there essentially in none. Therefore it can be concluded that current fluid level surveys are only accurate and dependable when:
casing gas is being produced while surveying so that the casing environment is uniform;
the well depth is such that ALL collars in the well can be counted (usually 4500' to a maximum 6000');
a tubing tally is known so an average joint count can be accurately determined;
ambient "noise" is minimal or nonexistent.
In short, today's fluid level surveys can be accurately used in quiet, shallow oil wells that continuously produce gas up the casing. On other wells the measurements may be "close enough", but cannot be depended on for accurate bottom hole pressure measurements, productivity measurements, or well bore diagnostics.
ADVANCES IN FLUID LEVEL SURVEYING
Acoustic wave generators (fluid level "guns") have recently advanced to a new level. The shortcomings of the existing guns have been analyzed and improved.
ACOUSTIC WAVES: It has been determined that the quality of an acoustic pulse, or wave, generated by a compressed gas charge or release, released through an opening into a well (usually a casing valve) can be measured and evaluated by the three areas of distinction described below. These wave characteristics can be clearly illustrated by generating the waves and reading them within the commonly used frequency ranges (see Exhibits A1-3, B1-3, C1-3, D1-3) (REF 7) :
Intensity - defined as the initial power release rated in decibels. Obviously the more intense a wave is the longer it will last, and more collars can be seen deeper in a well. This allows accurate acoustic velocity readings to be determined.
Elapsed time - defined as the precise amount of time (in milliseconds) from the instant a single wave is generated to the end of the generation of the same wave. A single wave generated within a minimum amount of time eliminates secondary waves generated during the same power release that can commingle with other down hole readings and make them difficult to decipher. Current wave generators produce multiple waves.
Flatness of wave face - a high angle, "crisp" wave is preferred. Such waves result in clear reflections on objects and "sharp", easily readable results at any depth and within most casing environments.
"Advanced" wave generators create waves with all of the above desired characteristics.
FREQUENCY RANGE: As referenced above, in order for an acoustic wave generator to be accurate in the oil field, the pressure wave generated must perform within the frequencies commonly used for well sounding, so that the frequency of the "sounds" are in a range below most of the other pumping or producing sounds. The frequency range standard in this industry that has been used for decades is 10 Hz to 70 Hz. The low end of this range, 10 Hz to 20 Hz, is used to read fluid levels. The upper end of this range, 40 Hz to 70 Hz, is used to find tubing collars. All existing wave generators as well as the advanced wave generators operate in these ranges.
MICROPHONES: "Gun" microphone designs and sensitivities have continued to evolve. New, "ultra-sensitive" microphones not only clearly detect fluid level reflections, but can also read reflections that have traveled through some foams. They can also detect many minor frequency changes which can be interpreted as: fluid moving down casing and tubing (from holes), paraffin and scale buildup, and other developing problems.
AUTOMATED WELL CONTROLLERS USING FLUID LEVEL MONITORING
The use of new, ultra sensitive microphones, along with the optimum wave characteristics described above, now allows ALL collars to be read at any existing well depth under most conditions. An accurate acoustic velocity can always be confidently determined (assuming a tubing tally is available). In fact, measurements can be accurate to about 10 feet, and as long as pump depth and average tubing length is known, the survey equipment can identify, calculate, and read out an accurate fluid level without human intervention or interpretation. If this is the case, this technology can now be used for well control. An acoustic generator (gun) can be permanently mounted on a casing valve and connected to a well controller box. Important information relevant to identifying down hole problems can be organized into morning reports or status alarms and communicated to operators. The technology already exists within controllers to start and stop or adjust the speed of an electrified well. By accurately determining the amount of fluid in a well and taking such surveys at regular intervals (for example every 30 minutes) fluid level-based controllers can be used for the following applications:
ELECTRIFIED ROD PUMPS -
If equipment is sized to pump off a well, turn the well on when fluid builds to a certain point, and turn the well off when it pumps down to a certain point. The well is thereby shut off before the fluid level reaches the pump and the pump begins pounding due to incomplete filling (only pumping when there is fluid lengthens equipment life);
Speed up or slow down a well (if the horse power is available) using a variable speed drive.
Provide accurate bottom hole pressure measurements for reservoir evaluation under most conditions; determine static levels whenever a well is off; take surveys at preset intervals whenever desired to determine fluid buildup rate; determine drawdown for productivity measurement.
Alarm operators when a fluid level is increasing to give notice that a down hole mechanical problem is developing or bottom hole pressure is increasing;
Keep gas wells completely fluid free;
Give immediate indication of pumps with gas interference by showing pounding wells with high fluid levels
Eliminate the "guessing" with manual timers - no adjustment necessary by field personnel.
ELECTRICAL SUBMERSIBLE PUMPS ("ESP'S")
Control pump speed on larger ESP's to keep a minimal fluid level, yet maximize productivity by producing as much as possible; "See" a fluid level through certain foams.
Shut ESP's down before they pump off;
On smaller ESP's, such as those used on coalbed methane (CBM) wells and water wells, power can be turned on and off without harm to the pump. Therefore the pump can be produced only when fluid is present, thereby minimizing electrical use and maximizing pump life.
PROGRESSIVE CAVITY PUMPS ("PCP'S")
Identical protection as rod pumps: shuts down the well before the well pumps off and causes polymer failure;
Speed or slow PCP surface motor to keep fluid at a certain, desired point in the well bore;
Send an alarm if well goes down or fluid level increases above a predetermined point.
Optimize plunger performance by opening plunger only when there is liquid to produce.
Shut unit down (if desired) as soon as fluid is removed from the casing to preserve gas for the next lift (extended "open" times can be regulated by the plunger lift controller)
Acoustic waves can be "heard" when directed down tubing as well as casing, allowing tubing fluid levels to be monitored so that supply gas can be turned on only when tubing fluid level is in a desired range.
Monitor casing fluid for casing holes, bad valves, etc.
Monitor packerless flowing wells to determine if casing fluid is dropping.
Regulate chokes using motor valves to keep the fluid level in a predetermined area to maintain casing-side pressure and extend natural flow life.
Accurately determine artificial lift equipment size when required.
Open and close well head valves when fluid builds to a certain height in the casing instead of guessing when to turn the well on based on well head build up pressure (keep wells unloaded).
Control safety valves with an active view down hole, so as to avoid certain spills or disasters.
The use of radio, cell phone, and Internet communications provides many other advantages for these types of controllers:
The controller can be remotely and regularly adjusted (or loaded with accurate data) to assure accurate results and make revisions as well conditions change (new completions, moving controllers, etc.).
Alarms for any number of problems can be immediately communicated to the operator, giving advance time to act before more severe problems develop.
Operator can focus on the problem wells only, allowing more time for other operations, reservoir evaluation, and golf.
Third party service contractors can be hired that continuously monitor and evaluate survey results and therefore identify problems such as paraffin build up, scale problems, holes in casing and tubing, and effectiveness of chemical treatments for corrosion, paraffin, and scale.
Limitations of fluid level-based controllers would be few (primarily "noisy" wells), and most of the down hole problems interpreted by existing controllers would also be identified by a fluid level-based controller. Important additional information NOT provided by current controllers such as bottom hole pressure data, holes in tubing or casing, etc. could be determined that could be used for well productivity evaluation. The same operational controls available on current controllers would still be available. The result of installing controllers that utilize automated continuous fluid level monitoring for most wells would be maximized productivity and minimized operating costs.
WorldOil.com - Special Focus: "World Crude/condensate Production and Wells Actually Producing", Aug 2001.
McCoy, J.N., Podio, A. L., Huddleston, K.L., B. Drake: "Acoustic Static Bottomhole Pressures", SPE 13810, Production Operation Symposium, Oklahoma City, OK, March 10-12, 1985.
McCoy, J.N., Podio, A. L., Huddleston, K.L.: "Acoustic Producing Bottomhole Pressures", SPE 14254, Annual Technical Conference and Exhibition, Las Vegas, NV, September 22-25, 1985.
Hasan, A.R. and C.S. Kabir: "Determining Bottomhole Pressures in Pumping Wells", SPE 11580, Production Operations Symposium, Oklahoma City, OK, February 27-March 1, 1983.
Lufkin Automation - SAM Quick Dyno, February 2005.
Thomas, Harkinson, & Phillips, "Determination of acoustic Velocities for Natural Gas", SPE 2576 of AIME.
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