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.

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 log 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.

To efficiently and economically operate a plunger lift well one of the most important requirements is to: KNOW THE PLUNGER LOCATION AT ALL TIMES, otherwise the operator has to guess, even when using electronic controllers. Except for when the plunger is at the surface, detected electronically or by ear, it has been difficult to determine the position of the plunger inside the tubing during the plunger fall and when it reaches the bottom of the tubing through the liquid column that has accumulated during the flow period. This new portable system can be used on plunger lifted wells to record the acoustic and pressure signal produced by the plunger during the operating cycle. The very sensitive acoustic monitoring system coupled with a user-friendly graphical software application, it is possible to virtually "see" the plunger at all times during a cycle, determine its precise fall velocity, and determine the volume of liquid accumulated at the bottom of the tubing. Software processes this plunger acoustic 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 well bore picture representation showing the tubing and casing pressures, plunger location, gas and liquid flow rates in the tubing and annulus, and inflow performance relationship at operator selected intervals throughout the cycle. Field data collected from various plunger lifted wells are presented to show how to identify operational problems such as holes in the tubing, fast or slow plungers and plungers sticking not getting to bottom. Field cases are presented to show how this recorded information can be used to optimization, analysis and trouble shooting of Plunger Lift operations.

Users of electric energy, especially in the field of power applications, sooner or later become interested in power factor and methods used in correcting bad power factor conditions. This interest is usually brought about by the bill presented to the user by the power supplier. On this bill the user will observe an energy charge, a demand charge, and a charge or penalty for low power factor. Usually, he can easily understand the energy charge and the demand charge, but he may not understand the power factor charge or penalty. He may not understand what he is being asked to pay for, what benefit, if any, he has received, or what he has done to justify such a penalty. We shall then consider in some detail the meaning of the term "power factor", why the electric supplier makes a charge on the basis of power factor, and what the user can do to eliminate or reduce this charge.

On average, two-thirds of the world's oil wells are produced by sucker rod pumping installations. Therefore, it is of utmost importance to ensure that these systems work at their peak efficiencies. Thus, calculating the energy efficiency of sucker-rod pumping is a very important task of the production engineer. To accomplish this task, one has to define the in-, and output powers of the system and the different kinds of losses occurring in the various parts of the downhole and surface equipment. A review of the literature on the subject revealed that the useful power of the sucker rod pump is calculated by a widely accepted formula that gives inconsistent results. The formula, of which several variants are known, predicts different powers under the same conditions on the same well if the wellhead pressure is varied. Since this behavior does not allow the comparison of different scenarios.

This presentation discusses the use of electrical power in oilfield lifting and injection systems. Paramount to efficient power usage is the maintenance of proper power factors. Included are remarks pertaining to causes of "poor" power factor, its cost in equipment and money and the best way to correct a "poor" power factor. A typical oilfield distribution system, with colored slides, will be discussed in this presentation.

In recent years the cost of electrical energy to pump oil wells. has become a prime concern. The terms Kilowatt costs, Kilowatt demand, Fuel adjustments and Power Factor Penalties are showing up on monthly power bills. Utilities have numerous methods to influence the bills which have caused some misunderstandings of the true meaning of each of these. Power Factor and the methods to obtain a desired Power Factor may be the least understood. Power Factor may be improved by connecting capacitors to the load side of motor contractors or connected in the primary line of electrical distribution systems. This paper will be limited to the discussion of Power Factor improvement of induction motors by capacitors connected to the motor terminals.

Energy Economizer Technology (EET) introduces a new approach to motor control. 50 granted USA and International patents say it provides power management that is truly different from familiar old-technology motor-control processes. The vital role AC electric motors play in profit return on investment is universal. They are the "motive resource" that turn the wheels of productivity in every industry; the Petroleum Industry's dependency on motors is a prime example. When pump motors stop, profit stops and "downtime" costs begin. This condition spans the globe. It is as true in developing countries as it is in Texas. Every country depends on electric motors for internal operations and growth by export dollars. As is true with other resources, motors that are managed are the most productive. Unmanaged motors start with avoidable electro-mechanical stress and full voltage is applied during light loads where a lesser current would reduce energy waste, life-shortening heat damage and increase production "uptime." A large percentage of "downtime" cost could be avoided by supervisors who turn power off to protect motors and conserve energy by making manual adjustments. Manual control for hundreds of millions of motors by "human" supervisors is not feasible. Most AC motors waste some energy as life shortening heat and rely on thermal devices or fuses for protection. Even though such means prevent single-event catastrophic failures, some motor damage inevitably occurs with each over-current fault; especially with mechanical locked-rotor events. Controlling power is an improvement over direct-on-line operation. But familiar voltage ramp "soft" starters, even new ones upgraded with the latest microprocessors, are limited by the "design approach" that earned the name: Motor Controller. The old familiar approaches literally control power to the motor. Prior technology relies on measurements compared to arbitrary software or hardware references the designer believes will control motor performance under conditions that are "anticipated". The motor becomes a "design-controlled" item. Energy Economizer Technology relies on natural properties of standard induction motors as the controlling elements of a "power management system" that: (1) commands start acceleration, (2) adjusts run torque in proportion to work demand and (3) includes diagnostics that protectively respond to electro-mechanical faults. The EET approach empowers THE MOTOR to command current in response to conditions and work of a moment without comparison to programmable, arbitrary references; "designer anticipation" of such conditions is not a performance factor. A novel communications and power control system are united by the EET process.

In 1985, a silicon-controlled rectifier (SCR) device was installed on a sucker rod pumping well in the North Hobbs Unit, New Mexico, to eliminate a potentially severe structural shaking on unit start-up. On the basis of limited tests on this unit that indicated possible power savings and load reductions, a joint Shell-MagneTek test program was carried out in 1988 on seven pumping wells in West Texas and near Ventura, California. The SCR device was used to turn the motor off for one or two intervals during each pumping stroke. The motor was turned off for as much as 60 percent of the time in some of the tests. Tests were conducted on conventional and Mark II units and on NEMA "D" and ultra-high slip motors. Using the SCR device reduced rod loads and peak gearbox torque, or power consumption, by 5 to 15 percent on most of the wells tested. If the power generated during the stroke was ignored, power reductions were 10 to 25 percent. However, we were unable to achieve the maximum rod loads/gearbox torque reduction and maximum reduction of power consumption using the same SCR cycle. On the basis of the initial tests, a microprocessor controlled prototype unit is being designed and tested. The controller has four operating modes to a) minimize energy consumption; b) minimize rod/gear box loading; c) maximize pumping efficiency, or; d) improve overall performance by optimizing the above modes.

Powerwave has been employed in three injection wells for 24 months to improve oil recovery from this field. Excellent results have been realized from the significant production and economic oil volume benefits that have been realized during this period:
Overall Project Results: 68% drop in Oil Production Decline. Oil production decline from the three production patterns dropped from a pre Powerwave value of 3.4% per month to 1.1% per month with Powerwave. This represents a 68% reduction in the decline rate.
170% Increase in Oil Production. Oil production from three production patterns (16 oil production wells) increased by 85 barrels of oil per day over the established base production decline trend of 50 barrels of oil per day. Over 51,700 barrels of incremental oil to date has been attributed to the Powerwave installations. 240% Increase in Oil Cut. The average oil cut after 24 months of Powerwave stimulation has increased to 3.54% compared to 1.05% on the previously established decline trend.

Hydraulic Perforating has opened many new avenues in remedial and completion techniques. This paper contains a discussion of the advantages and disadvantages of this process and the economic factors involved. Research data are incorporated which define performance that may be expected. Examples are given of most favorable applications.

This paper discusses the theory, operation and practical application of automatic net oil computing systems in lease commingling and well-testing operations.

Produced water is the aqueous liquid phase that is co-produced from a producing well along with the oil and/or gas phases during normal production operations. Usually, the fluids that are removed from the reservoir by the producing well are brought to the surface and separated into an oil stream, a gas stream and a water stream. The main components of the water stream that is separated are: Water, Suspended oil, Dissolved oil, Suspended solids (scale, corrosion products, sand, etc.), Dissolved solids, Dissolved Gases (CO , H2S, O2 ), Bacteriological matter, & Added materials (treating chemicals, kill fluids, acids, etc.). It should be noted that, over the life of the well or field, the volume of water produced will exceed the volume of oil produced by a factor of 3-6 times. Unfortunately, at the present time, the produced water is not a saleable product of the operation. Hence, an operator is faced with a serious challenge of how to handle relatively large amounts of produced water at the lowest possible cost. In many land-based production operations, the produced water is either injected into a disposal well or the water is injected into a producing formation for enhanced oil recovery purposes via waterflood or steamflood operations. Before being injected for either disposal or enhanced recovery, the produced water must undergo treatment to render the water suitable for use. The purpose of this paper is to present a general, but practical, overview of the equipment and technology involved in water treating for a produced water injection project. This paper is not meant to present an exhaustive coverage of the material but to provide basic, general information with which an operator can become familiar with the primary decisions required to properly treat produced water for injection. To be covered are produced water treating objectives, produced water treating technology and equipment, and a thought process for the practical application of this equipment to land-based injection operations.

Extreme overbalanced perforating and surging has been used in many types of reservoirs as a completion method since the June, 1990. This method of completion is not a panacea for the petroleum industry, but it does address many of the problems associated with low pressure and/or low permeability reservoirs. This paper will present some of the more practical applications for today's completion practices. The cases presented include skin removal, massive hydraulic fracture replacement, and treatment volume reductions. The possible application of this process for coal seam wells will also be discussed.

In recent years there has been a great deal of interest in the use of propellants to generate high pressure gas pulses for fracturing hydrocarbon bearing formations. Mulch of the R&D effort in these Dynamic Gas Pulse Loading (DGPL) techniques has centered around their ability to induce multiple radial fractures in naturally fractured reservoirs, thereby greatly increasing the probability of intersecting fractures. Servo-Dynamics, Inc. has taken a somewhat broader approach to DGPL and through several thousand practical field applications, has also shown the process to be a valuable aid in the workover and completion of conventional cased-hole wells. By inducing multiple fractures with very limited vertical growth, DGPL has proven to he very effective in the breakdown of tight zones, overcoming skin damage, and stimulation of zones water, among other things. In most applications success rates of over 90% have been achieved, at times permitting the production of zones which-otherwise could not have been completed. Following a review of the state-of-the-art this paper presents the basic principals underlying DGPL stimulation, its strengths and weaknesses, and documents its effectiveness in various applications through case histories. Finally, basic guidelines are presented for evaluating if a well could benefit from a DGPL treatment.

As often discovered, determining downhole pump conditions by visual interpretation of a surface dynagraph card can be very difficult even for highly trained personnel. In addition, visual surface interpretations are more qualitative than quantitative. With the computerized method, surface measurements (load and displacement versus time) are used to calculate a downhole dynagraph card that is quantitative and much more easily interpreted. Basically, the computer program takes surface rod loads and displacements and removes rod weight, dynamic effects (harmonics) and rod stretch. The result is a pump card. Intermediate downhole cards are also calculated at critical stress points in the rod string such as at the junction points in a tapered rod design. Thus, rod taper designs can be easily evaluated. Besides calculating downhole conditions, measured data are also used to analyze surface equipment loading such as gearbox torque, prime mover loading and structural loading. All calculations can be made in a matter of minutes on the well site. Thus, conclusions can be drawn and changes can be initiated immediately for increasing production and/or reducing operating costs.

The full scope of two-phase producing problems extends from sand-face to separator, offshore to onshore. Both operational and design decisions are being made daily which require a thorough understanding of two-phase flow. The purpose of this paper is to highlight some of the major problems in each area und discuss current solutions or applicable technology. This paper describes gathering systems, terrain effects sphering sonic flow (pressure relief). black oil versus compositional liquid dropout, slug catchers, flow regimes slugging risers, gas lift deliverability, and flow splitting.

Since the early days of the petroleum industry, chemicals have been used to treat oil-field emulsions. These chemicals affect the surface properties of the oil and water so that the small dispersed droplets will coalesce into droplets large enough to settle out. Since crude oils, produced waters, and the type of emulsion formed vary widely the most effective chemical for any given area must be determined by field testing.

Modern mobility control polymers provide the petroleum engineer with a powerful tool for increasing oil production. Successful applications, however, are likely to result only from sound project engineering and careful attention to operating methods. This paper emphasizes a practical understanding of the properties of mobility control polymer solutions as they are likely to affect the success or failure of a project in a given fold. Many unsuitable applications can be identified through reference to some simple guidelines. Further selectivity results from an appreciation of the flow patterns of polymer solutions in specific reservoir situations. Good reservoir engineering maximizes the chances for incremental production; methods appropriate to the use of polymers in both waterfloods and surfactant polymer floods are surveyed. Even the best engineering efforts can be negated by careless or uninformed operations in the field. Particular attention is given to potential operational problems and the means available for dealing with them or avoiding them altogether.

A successful foamed cement job results from careful planning and precise control of densities, rates, and pressures. This paper discusses practical methods of obtaining unfoamed slurry densities, chemical injection rates, and nitrogen injection rates. It also discusses the continuous monitoring and logging of these parameters with a high-tech van. The importance of backside control, hole size, and volume calculations are presented.