A project was undertaken to utilize plunger lift in wells with abnormally low bottom hole pressures. This was accomplished through the use of coiled tubing for side-string injection (see schematic). This application has a wide range of applicability for high water cut low-pressure reservoirs.

It is the purpose of this paper to provide some assistance whether or not plunger lift is an economically viable alternative production method for specific wells. An evaluation spread sheet has been developed to assist in determining whether or not a rod pumped well is a likely candidate for plunger lift. The paper seeks to describe the assumptions and derivations of the equations in the spread sheet to provide a through understanding of the methods used in developing the spread sheet.

With the increase of horizontal drilling for oil and natural gas, the problem of keeping liquids removed from the wellbore becomes more evident. Several methods of artificial lift have been implemented to resolve this problem with varying results. This paper will discuss the use of plunger lift to resolve this problem and the mechanical requirements associated with plunger lift.

Plunger lift Technology has been with us for decades, no one knows for sure who first developed the idea, but we have seen the technology evolve from a rough guessing game to a near absolute science. The introduction of the electronic controller has brought the technology further than any other single development. This paper will cover one of the many areas, where electronics have allowed us to refine the technology

To unload liquid from a conventional plunger lift well requires that sufficient pressure builds during the shut-in time period as the plunger falls through gas, liquid and then rests at bottom on the bumper spring. Industry rule-of-thumb criteria to determine when the well should be opened to unload the liquid include building casing pressure, CP, to 1 _ times the line pressure, LP, or also using the tubing pressure, TP, in the Load Factor (CP-TP)/(CP-LP) calculation to be less than one-half(_). The best technique to predict the maximum casing build pressure may be to use the Foss and Gaul1 model to predict the rise velocity within a range of 500-1000 fpm, more optimally at 750 fpm that will unload plunger and liquid to the surface. These criteria are compared to one another and several well examples are analyzed using all three methods. Analysis of the results allow an operator to determine the shut-in casing pressure a plunger lift well should be allowed to build to before opening the valve to unload the liquid.

We could easily think of Plunger Lift as the ultimate in long stroke pumping. This is true because we have an expanding piston operating the full length of standard A. P. I. tubing without direct connection with surface mechanical energy. Rather than using the term "Pumping," we might think of Plunger Lift as a refinement of gas lift. plunger Lift operations are a form of intermitting gas lift, gas lift here referring to both natural flow and where additional gas is being injected, with the plunger constituting a seal between well liquids and propulsion gas. In performing this seal, the plunger minimizes the slippage, the fallback of liquids through the ascending gases, which is encountered when gas lifting low volume wells. The plunger is especially effective in deep wells with small production. It is in such wells that conservation of energy through the use of the plunger is most apparent. This, in most instances, permits a bigger degree of effectiveness and efficiency than has ever before been possible.

Plunger Lift operations are oftentimes not optimized due to lack of knowledge of plunger location and changes in tubing pressures, casing pressures and bottomhole pressures. Monitoring the plunger location in the tubing helps the operator (or controller) to optimize the production of liquid and gas from the well. In low liquid volume wells, the plunger position can be tracked from the surface by monitoring acoustic signals generated as the plunger falls down the tubing. When the plunger falls through a tubing collar recess, an acoustic pulse is generated. These acoustic pulses, generated at the tubing collar recesses, travel through the gas in the tubing and can be monitored at the surface to obtain plunger depth. These acoustic pulses are converted to an electrical signal by use of a microphone or pressure transducer. The signal is digitized, and the digitized data is stored and processed in a computer to determine plunger depth. In some high liquid volume wells, the acoustic pulses generated as the plunger falls past the tubing collar recesses may be masked and not detectable due to liquid accumulation around the plunger. However, in both low and high liquid volume wells, the plunger depth can be determined by generating an acoustic pulse in the tubing at the surface, and then, by monitoring the acoustic reflection from the top of the plunger. Multiple shots are taken, so the plunger descent rate can be determined throughout the plunger fall. Software processes this plunger depth data along with the tubing and casing pressure data to display plunger depth, plunger velocity and well pressures vs. time. Plunger arrival at the liquid level in the tubing, and plunger arrival at the bottom of the tubing are identified on the data plots. Well inflow performance is calculated and plotted. Software displays the data and analysis in several formats including a pictorial representation of the well showing the tubing and casing pressures, plunger location, gas and liquid flow rates in the tubing and annulus, and also, inflow performance relationship at operator selected intervals throughout the cycle. A field case is presented to show how this field data analysis is applied to optimization of Plunger Lift operations.

Fluctuating line pressures and liquid loading are a bad combination and in the Moxa Arch field in Southwestern Wyoming they presented the operator and Weatherford Artificial Lift Systems with a perplexing problem. Can conventional plunger lift be effective in an area with severe line pressure fluctuations? Can it provide for efficient removal of accumulated fluids while reducing or eliminating the need to vent the well and minimizing the time that the lease operator has to spend at the well location? Finally, can this be accomplished with limited resources of field personnel who are unfamiliar with the workings of plunger lift? This paper will discuss a 90 well plunger lift project in the Moxa Arch field that was successful in positively answering all these questions. It will describe the field history, the well candidate selection process, the initial pilot project and the total turnkey installation of plunger lift into 90 wells in a 3 month period of time. It will discuss the advantages of using an Integrated Solution Team approach to the project which provided for fixed installation costs and increased stabilized production, without placing additional burdens on the limited field personnel pool available.

The advent of "smart" microprocessor based plunger lift controllers has produces a renewed interest in the application of plunger lift to remove fluid from both oil and gas wells. While a great deal of information regarding the economics of plunger lift installations and operations exist there is little information available to assist in the design and evaluation of new plunger lift applications. This paper seeks to provide an approach to determining the operational feasibility of plunger lift operations in advance of equipment installation.

With today's economics in the oilfield, many operators are searching for ways to cut lift costs. Plunger lift is often considered. However, if it is projected that a particular well does not have sufficient gas to operate a plunger, this means of artificial lift is no longer considered. For instance, if a particular well shows to be 10 MCF per day below operating requirements, an operator may spend upwards of $50,000.00 to rod pump this well. An alternative would be to add 10 MCF per day to this well through gas injection. Many operators have high pressure gas available without realizing. Many have compression for gas sales, some have gas plants, and others have high pressure gas wells. All these examples are avenues that should be explored. This paper examines such scenarios in two West Texas fields.

After decades of trial and error, and frustration, plunger-lift finally has become widely accepted as a legitimate solution to producing many wells. As the experience level has increased, so has the success. As the equipment has been improved, so have the applications. This paper is to describe an application, coupled with new technology that is allowing producers to use plunger-lift systems on wells never before possible. The limiting factor for most plunger-lift wells is gas. It is now possible to take advantage of the low lifting costs of plungers on some of these wells.

As gas wells are produced and reservoir pressures decline, it is often necessary to install wellhead compression to maintain production. As the well continues to decline, gas rate and velocity in the tubing will decrease to the point where liquids cannot be lied out of the wellbore. Even on compression, liquid loading will become a problem and production impairments will result. One remedy to the problem of liquid loading is to install a plunger lift system coupled with compression. With new

Developed is an analytical analysis from which a synthesized dynamometer card can be calculated and plotted from generally known oil well parameters. The analysis preserves the time of displacement variable necessary for the calculation of instantaneous loads at any time or any position of the polished rod throughout the pumping cycle. The nonlinear boundary conditions introduced by the fluid pump are linearized and result In the applicability of superposition of loads in proper phase relationship. From the synthesized dynamometer cards various pumping conditions may be investigated; surface and subsurface equipment selected; and malfunction of system components determined.

The polished rod carries the weight of the entire rod string plus the fluid load and the imposed dynamic loads. This paper will show that polished rod failure is caused by fatigue-type stress due to improper installation. It will also review how to recognize the alignment problems and what steps can be done to prevent polished rod failure.

The polished rod is the uppermost joint in the string of sucker rods used in a rod pump artificial-lift system. Polished rod related failures take time to manifest themselves but early simple preventive maintenance can significantly reduce them. This paper will discuss typical failures related to the polished rod, their causes and possible remedies.

Practically all sucker rod breaks are fatigue failures. These breaks are brittle type fractures which occur at a stress much below either the ultimate strength or yield strength of the metal after a great number of stress reversal cycles. This type of failure is common to all metals and all kinds of metallic structures subjected to cyclic loading. To design a structure so that such failures cannot occur, we must determine the fatigue endurance limit of the metal we are using, then limit the working stresses to a safe value below this figure.

During the past three years, regulatory agencies and industry have given increased attention to protection of surface and ground water from all types of pollution. Because of this publicity some may think that water pollution is a new problem. This certainly is not the case. In many instances, the pollution problem has been masked by the geographic size of the State, the availability of water for dilution purposes, and the lack of exploration for and use of ground water. Therefore, more cases of pollution are being identified as greater development of water resources occurs. Historically, several State agencies had been involved in varying degrees with pollution control activities. These agencies had specific areas of responsibility, and generally worked independently of each other. In an effort to coordinate the pollution control activities of the various State agencies, House Bill 24 (Article 7621d) was passed by the Texas Legislature in 1961 to establish the Water Pollution Control Board. This law represents a new approach to pollution control administration and enforcement.

The disposal of produced oilfield brines and the associated problems have been studied closely for the past several years. The change-over from open pit disposal to underground disposition has been nearly completed. The paper includes steps taken by the Railroad Commission to eliminate pollution of surface and subsurface waters by produced oil-field brine and details some of the problems still to be solved. The paper concludes that much progress has been made over the past several years and expresses optimism that the ingenuity of the oil and gas industry and its technical staff will overcome the inherent problems of salt water disposal.

The salt water disposal and control problem is discussed in relation to the fresh water needs of the State, and information is presented as to the present status of the situation. The Railroad Commission program for control is outlined and its record of past and present activity is discussed. The use of earthen pits as a means for the disposal of produced salt water has repeatedly been found to be a source of pollution to various water supplies. The commission field staff is engaged in a long-range program to investigate all producing areas of Texas to determine where and how pollution is occurring or could occur from oil and gas operations. The effect of fluid injection and salt water disposal systems on the pollution problem is reviewed. Guidelines are submitted for the operation and control of salt water with emphasis on effectiveness.

Polyethelene pipe is a petroleum-base product. It is highly resistant to corrosion from all forms of acid with the exception of banana oil. Polyethelene pipe is effective from approximately 0 to 325 pounds of working pressure, depending on the size of the pipe, the well thickness of the pipe, and the temperature. The main ingredient in polyethelenepipe is resin. The quality of the pipe is determined by the type of resin used. Two of the main advantages of polyethelene pipe over steel pipe are that it can be produced for about one half the cost of steel pipe and that it is resistant to minerals in the soil. Whereas minerals will eat steel from the outside in, even though it is chemically treated on the inside, the minerals from the soil will eventually eat through from the outside. Polyethelene pipe will not be deteriorated by minerals. Polyethelene pipe compares to most other pipes of equal size and strength to be about 20 to 30 percent lighter. Tools for operation include a 110 volt AC generator for heating facers necessary to fuse the pipe together, a depth gauge, a facing tool, and an alignment jig. There is a constant struggle for capitol to invest in drilling programs and therefore we must constantly seek new ways to save money and time. Polyethelene pipe when used in its proper perspective is one of the answers to this problem.

Fasken Oil and Ranch has been using Western Falcon Polylined tubing for over 9 years in production and injections wells. This paper will address updated and additional case studies since the original paper presented in 2005 titled "Cost Effective Option Using Poly Lined Tubing". The combination of lower priced energy prices with tubular goods prices on the rise, many operators are looking at ways to reduce tubular replacement and workover costs due to corrosion and rod on tubing wear failures. Further case studies demonstrate the cost savings in tubular corrosion and a dramatically reduced failure rate in beam pumped wells. The liners have been particularly effective in solving tubular performance problems in highly deviated and doglegged wells. Poly liners have been installed in over wells 11,000 wells amounting to over 20 million feet of lined tubulars. Reducing production and injection costs is much more important today than it was in 2005, when the original paper was presented.

The use of a polymer gel to reduce large volumes of water production in an aquifer-supported oil reservoir will be presented. Water invasion from the underlying aquifer had begun to water out the completion and repeated plug backs and cement squeeze attempts failed to block the water movement into the wellbore. A vertical permeability channel to the upper perforations in the near wellbore region was suspected to be the cause. A polymer gel treatment through the bottom perforations was selected to shut-off or divert the water. The gel (developed by Marathon Oil Co.) reduces the permeability thus creating a "blockage" in the formation channel. The job was successfully performed, and resulted in an 87% decrease in water production with no impact to oil production.

This paper discusses the use of Polymer Gelled Block (PGB) as a diverting agent in staged acid stimulations performed in the San Andres Formation of the Slaughter Field in Hockley County, Texas. Improved results were obtained using this new material as compared to rock salt and benzoic acid flake blocks that were previously used. Several clear advantages of low residue PGB mixed "on the fly" over solid type blocking agents are discussed. Included are viscosities of the PGB during placement in the formation and then after the gel system has set up following the required 30 minute shut-in time. This demonstrates its capability of achieving a high extrusion pressure which tends to divert the subsequent treating fluid.

The word "polymer" is used almost every day in discussions concerning the oil field. However, even though polymers are used in almost every phase of the drilling, completion, and production of oil and gas wells, they continue to mystify many oilfield personnel. Few people in the industry understand what constitutes a polymer or the properties exhibited by these polymers. This paper discusses naturally occurring," modified naturally occurring, and synthetic polymers* with application in drilling, lost circulation, cementing, damage removal, stimulation, water and sand control, and secondary and tertiary recovery. Polymer properties defined and discussed include rheology, viscosity, solubility, shear and temperature stability, chemical reactivity, adsorption, solids-suspending characteristics, and salt sensitivity.

As a part of the reservoir characterization and for calculation of original oil in place, it is necessary to correct the porosity logs to the core data. The Mabee field has 800+ logs with a majority of them consisting of old gamma ray neutron logs. The modern porosity logs were calibrated to core porosity by crossplotting log porosity against core porosity. Linear regressions were constructed which are defined by the slope and the y-intercept. The linear regressions demonstrated excellent linear correlation. It was observed that location of the well or geology appears to be more important in the relationship between core porosity and log porosity than the logging company. A logging company utilizing the same tool and logging boreholes the same size across the field exhibited varying slopes and y-intercepts. Conversely, one well logged by two different companies obtained nearly identical linear regressions. Maps of slopes and y-intercepts were used to obtain the transforms for converting modern porosity logs to core porosity. The cased hole neutron porosity logs indicated that location was important, but that the logging company was equally as important. The slopes and y-intercepts were mapped by logging company. The old neutron logs demonstrated a good inverse linear relationship between core porosity and the logs of the neutron deflection. Linear regressions were done for the log,, neutron deflection vs. core porosity over the gross pay. Linear regressions of the mean and maximum neutron deflection vs. the mean and field minimum porosity generated nearly identical slope and y-intercept. Thus, any of the neutron deflection curves could be transformed to porosity if the mean porosity was known. Mean porosities were mapped using all core and transformed porosity logs over gross pay. These contoured values of mean porosity were used to generate a slope and y-intercept that would define the transform to convert log,, neutron deflection to porosity.