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.

This paper is directed toward field operating personnel for the purpose of acquainting them with the objectives, the methods employed and the operating problems encountered in the injection of water to increase oil production. Included herein are brief discussions of the history of water flooding, why water flooding is helpful in increasing oil production, requirements of good water flood, importance of well test information, problems encountered in water flooding, types of water handling facilities, typical production history of water flood and injection of water during the early years in the life of a field.

One of the common oil-field wellbore problems is paraffin deposition. Even though hot oiling or hot watering is usually the first method tried for removing paraffin, few operators appreciate the limitations of "hot oiling" and the potential for the fluid to aggravate well problems and cause formation damage. Field tests have shown that the chemical and thermal processes that occur during "hot oiling" are very complex and that there are significant variations in practices among operators. Key issues include: (1) During a typical hot oiling job, a significant amount of the fluid injected into the well goes into the formation, and hence, particulates and chemicals in the fluid have the potential to damage the formation. (2) Hot oiling can vaporize oil in the tubing faster than the pump lifts oil. This interrupts paraffin removal from the well, and thus the wax is refined into harder deposits, goes deeper into the well, and can stick rods. These insights have been used to determine good "hot oiling" practices designed to maximize wax removal and minimize formation damage.

Reduction of operating cost is of vital concern to the oil industry. Repair expense of insert pumps is often overlooked in the overall picture of production cost control. This presentation discusses failure analysis, pump design, parts analysis, repair shop selection, and repair specifications as they relate to length of pump run and repair cost. Examples of several types of pump failure will be shown and solutions discussed.

In an environment of low oil prices, rod pumping system optimization is more important than ever before. This is especially true for high water cut wells that account for the vast majority of rod pumped wells in the Permian Basin. To maintain profitability, rod pumping wells must be well designed to start with, and analyzed on a regular basis to detect and correct problems as soon as possible. This requires accurate data and the right tools. One of the most powerful set of tools for this purpose is modem diagnostic analysis and design software. The purpose of this paper is to present practical optimization techniques that anyone can use to optimize the operation of rod pumping wells. These techniques, although easy to understand and apply, require the use of modem rod pumping software with unique capabilities. The procedures described in this paper have been proven to work, and when applied correctly, will result in measurable improvements in system efficiency, reduced lifting costs, and extended equipment life. The computer programs used to develop these techniques are: RODSTAR - an expert system predictive computer program, RODDIAG - a diagnostic analysis wave equation computer program, and CBALANCE - a tool for obtaining counterbalance information and for aiding in pumping unit balancing.

Recent advances in the area of two-phase flow allow very accurate predictions of pressure traverses for vertical flow and reasonably accurate predictions in horizontal flow. Typical curves showing the effect of gas-liquid ratio are presented. For wells whereby the maximum production rate is desired, a method is presented that will allow this determination by making use of both vertical and horizontal pressure traverse curves. The tubing size and length as well as the surface flow line size and length must be considered along with production rate, gas-liquid ratio, fluid properties and separator pressure. Typical examples of both a flowing and gas lift well are presented.

The removal of paraffin deposition in rod pumping wells has cost the industry billions of dollars over the years in direct and indirect costs. Once deposited, indirect heating of the paraffin by using a hot oil truck is the most common treatment. However, since hot oiling typically has been proven to be ineffective below about 500', solvents are a useful alternative. This paper summarizes some of practical field aspects of solvent treatments and basic economic considerations. Preliminary evaluation of hot oiling effectiveness, melting point testing, solvent selection procedures and field pumping concerns will be addressed.
For many wells, these procedures will identify areas where hot oiling is ineffective and solvent treating is the preferred method for removing paraffin that is already deposited.