Although not recognized as a definite acidizing technique, fracture acidizing has probably occurred in a majority of acidizing treatments throughout the history of the process. Injection rates of most early acidizing treatments were high enough to cause fracturing, and it was common practice to "breakdown" the formation at the beginning of the treatment. Since the introduction of hydraulic fracturing, fracture acidizing has been recognized as a fracturing process, and it is now commonly used in an effort to increase live acid penetration into the reservoir rock. Extensive studies have been made to evaluate the effect of many variables (temperature, pressure, concentration, etc.) on acid penetration. Data from these studies have been incorporated into acid treatment design programs so that the operator will have a tool to use in planning more effective and economical acid treatments. The industry has long recognized, however, that actual results obtained by acidizing carbonate formations were not equal to increases predicted by the design programs. During the past decade, considerable research has been directed toward shortening the gap between actual and predicted results. Some of the approaches taken have been: 1. Acid retardation 2. Increased acid concentration 3. Increased fracture width to decrease the area volume ratio 4. Improved matrix leakoff control 5. Improved computer calculations. All these approaches had one basic purpose to increase live acid penetration of the reservoir rock. Each improvement did provide better response, either separately or when used in various combinations. Too large a gap still remained, however, between the predicted and actual results. The problem with these improvements was that each of them was based on the assumption of flow conditions with matrix leakoff: It is now recognized that such conditions do not exist due to natural hairline fractures that exist in most carbonate formations. In an undisturbed state, these fractures exert little influence on overall permeability, but leakoff of acid during an acid fracturing treatment not only occurs into the matrix but also into these hairline fractures. Calculations can be made to show that very small volumes of acid can enlarge these hairline fractures so that they can increase the average permeability from less than 1 md to more than 900 md. Large volumes of following acid can then leak off into these fractures, and penetration will then be much less than predicted by design programs assuming only matrix leakoff. A new acid fracturing technique using alternating stages of pad fluid and acid has been proven highly successful in achieving results that approximate predicted results of acid fracturing treatments. This success is believed due to the fact that the technique reduces leakoff into the hairline fractures as well as the matrix. A description of fluid flow behavior during acid fracturing will show how the new technique provides better penetration and better results from such treatments.

The use of nitrogen to enhance the recovery of oil and gas reservoirs is becoming increasingly attractive. Recent examples highlight projects where large-scale nitrogen injection has been successfully implemented to increase both the production rate and recoverable reserves of oil and gas. Nitrogen-based techniques for improving oil and gas recovery include gravity drainage pressure maintenance, gas cap production, cycling of condensate reservoirs. attic oil production, driving gas for miscible slugs, and miscible nitrogen displacement. Methods for enhanced production employing nitrogen are discussed along with economics relative to the use of other gases, such as hydrocarbons or carbon dioxide. In many cases, project economics can be further enhanced by integration of the air separation (ASU) process with other processes on site (power plant, gas treatment, etc). The advantages of such an integration of nitrogen-based processes are discussed.

Plunger lift is, in its best form, a method that uses only the power from the existing well to produce liquids from the well and bring them to the surface using gas pressure that has built up in the well during a time when the surface production valve is closed. One type of a typical installation is shown Figure 1.

In order to assist the pumping unit user in the use of nodular (ductile) iron the manufacturing processes from the foundry cupola to the finished gear are presented. Points of interest such as quality control, heat treatment, metallurgical properties and field tests are included.

Liquid or gas flowing in a well generates a complex group of audible sound frequencies. Twophase flow, which was gas bubbling through water behind uncemented casing, produced the frequencies shown on the curve in Fig. 1. An output signal from a piezoelectric transducer placed inside the casing has an alternating frequency waveform. The waveform is a composite of all the frequencies shown on the graph. Each frequency has a millivolt amplitude, varying with time, which contributes its relative amount to the total millivolt amplitude of the waveform. Using the optimum time interval, it is usually possible to obtain a good average amplitude measurement of these changing frequencies. The area under the curve in Fig. 1 is proportional to the millivolt amplitude for all of the frequencies above 200 Hz. Extending a vertical line through 600 Hz, all of the area under the curve to the right is proportional to a milli-volt amplitude of all frequencies above 600 Hz. These same comparisons can be made for 1000 and 2000 Hz. It is readily seen that, as filters remove frequencies from the amplitude measurement, the subsequent amplitude levels will always be less. These four filtered amplitude measurements are the four points which are plotted versus depth on semi-log paper to produce a four-curve noise log. Most of the interpretation involves a relative comparison which makes it desirable to establish fluid flow and "dead well" intervals. With reference to Fig. 1, comparing the area under the curve on the low frequency end to the area for those frequencies above 600 Hz indicates two-phase flow has more energy associated with the low frequencies. The single-phase curve has more area associated with the 1000 and 2000 Hz end. The higher the differential pressure the greater the area under the high-frequency end. The conclusions from these data are that separation of the 200 from the 600 Hz curve indicates two-phase flow, and pronounced peaks on the 2000 Hz are an indication of differential pressure. The high noise level associated with wireline and tool movement requires that all data be recorded during a time when the tool is stationary. To facilitate the interpretation for a shut-in run, it is necessary to eliminate all lubricator, wellhead and wing valve leaks.

Deep holes and high pressures with their related problems have created a demand for better quality tubular goods unknown but a few years ago. The author outlines recent approaches to inspecting. However, no single non-destructive test can be expected to reliably measure all the properties. Further, the inspection must insure adequate service life, and it must have a proven correlation between the properties inspected and the performance properties of the pipe. Defects and defect evaluations are explained along with their effect on pipe quality.

It is generally accepted that the control and removal of paraffin deposits is a costly operating problem in many fields. A great variety of methods have been and are being used to combat paraffin formation and deposition and to facilitate paraffin removal. The purpose of this paper is not to present any new control methods, but rather to discuss generally the current practices and the status of the industry's thinking regarding paraffin control in wells. A logical starting point for this discussion would be the composition of that material commonly referred to as paraffin.

The history of hydraulics is a fascinating story dating back to about 1650, when Paschal discovered the fundamental laws of physics upon which all modern hydraulic equipment is based. About 1795, Joseph Bramah developed the first hydraulically operated press using water for power transmission. Since then many changes have been made, so that today there is scarcely a product which does not utilize hydraulics at some phase in its production. Hydraulic power is unique in the ease with which it may be controlled. The amount of force is almost unlimited and any practical stroke length is available.

The processing of streams containing high concentrations of carbon dioxide (CO21 is becoming more commonplace as enhanced oil recovery (EOR) projects come to reality. The process begins with production from naturally occurring CO2 reservoirs in New Mexico, Colorado, Wyoming, Texas, and Mississippi shown in Figure 1, or with the recovery of CO2 from vent or flue gases in chemical plants and power plants. These streams must be processed to produce a relatively pure stream of about 95% CO2 to meet purchaser specifications. Once the CO2 has been purified, it will typically be transported long distances to oil fields in West Texas, Oklahoma, New Mexico, North Dakota, or Mississippi where it will be injected into the oil bearing formations. The CO2 mixes with the reservoir fluid to expand it and produce a less viscous mixture that flows through the formation more easily, resulting in increased crude oil recovery. The components of the produced fluid, water, crude oil, and gas (hydrocarbon and CO2), are separated into three phases. The produced gas, which contains varying amounts of CO2 must be processed before it is suitable for further use. Figure 2 shows a simplified Block Diagram for some process options. The water content of the gas makes it too corrosive to simply compress and reinject into the formation, and the high CO2 content makes it unsuitable for sale to a natural gas pipeline. Several process schemes are available to separate and purify the components of the gas stream, but the simplest approach is to dehydrate the stream, to make it less corrosive, and then reinject it. As more complicated processes such as membranes, chemical solvents, physical solvents, and fractionation are used, the design problems become more complex. The purpose of this presentation is to highlight a few of the areas of non-process concern and offer possible design approaches. Some of the subjects discussed are specific to CO2 processing units, and others, such as sparing and compression selection, apply to other types of facilities as well.

A discussion of the causes of common defects in new and used tubular goods and sucker rods. Inspection techniques utilized in detecting these defects are described.

There has been the concept that a long stroke and slow pumping speeds are the best way to design sucker rod lifted wells. Typically, longer fatigue life is one of the reasons to rationalize this practice. Additionally, slow versus fast pumping speeds are relative numbers. This paper will discuss the various operating concepts, the background on pumping equipment capabilities, maximum design considerations and provide rod string design comparisons showing rod loading and power comparisons resulting in new considerations for optimizing sucker rod lifted wells.

For a number of years, controversy has arisen as to the most efficient way(s) to accelerate the rate of reserve recovery from ultra-low permeability carbonate reservoirs. Efforts were undertaken to locate and study a sufficient number of wells that would be representative of this issue, and that would clearly distinguish naturally occurring reservoir parameters from man-induced processes. The production from a localized group of Strawn wells in Crockett County, Texas was examined and normalized by permeability, porosity, initial static reservoir pressure, and productive height to establish the impact of various completion methodologies. Flowing pressure transient analysis was performed on each well to determine permeability, effective fracture half-length, drainage area, and aid in the normalization process. Stimulation of the Strawn was divided into three categories: propped fracture stimulation, crosslinked acid treatments, and all other acid treatments. For each of these categories, average fracture half-lengths and normalized production are compared and contrasted.

Steam Assisted Gravity Drainage (SAGD) processes have been shown to produce extremely stable reverse (oil-in-water) emulsions. Although Invert Emulsion Polymer (IEP) technology has proven to be cost effective, IEPs pose application challenges requiring make-down water and auxiliary equipment, incurring additional cost and logistical challenges. A novel reverse emulsion breaker (REB) has been developed and implemented successfully that offers reduced application monitoring, reduced equipment needs, improved handling and product stability over IEPs. Extensive synthesis efforts and on-site bottle test development resulted in a breakthrough chemical treatment with high demonstrable efficacy in multiple SAGD commercial plants in Northeast Alberta, Canada. The new product met and exceeded all the key performance indicators (KPI) with respect to quality of oil, water, and oil-water interface. Other benefits included a reduction in equipment and handling requirements. This technical presentation summarizes the development and the successful field trials conducted in 2006 and 2007

Follow me on a venture through the mystic of the "black box" in the chemical business. A portion of the paper will be directed toward the process of selecting a chemical company that will provide the most effective way of solving problems. The cost of chemical is insignificant compared to the side effects resulting from a poor chemical program. The following topics will be directed toward the process of selecting a chemical company that will provide the most effective method of solving problems through Continuous Quality Performance. l Increase service from chemical suppliers. l Decrease chemical costs. l Get best results from the chemical process. l Evaluate the cost of a poor chemical program. l Get chemical companies to compete for the business. l To Bid or Not to Bid- There is no question.

Significant gains in production can be realized by reducing crude oil and natural gas processing costs. One area of the production process where significant economic gains can be realized is in the incorporation of enhanced processing technology into the surface production equipment used to process crude oil and natural gas to pipeline standards. One such product specifically developed to minimize the amount of energy required to process a barrel of oil to pipeline standards will now be discussed. It was recently recognized by the Department of Energy through issuance of a Special Recognition Award under their National Awards Program for Energy Innovation.

A major decision often confronting an individual while planning his or her estate involves the disposition of their oil and gas properties. Many people elect to place the future management responsibility of their property in the hands of an individual or corporate fiduciary. In order to provide a total management service to their clients and customers, many banking institutions, particularly in the Southwest, have assembled a staff of experienced professional personnel to oversee property held in trust. The functions of this grow, including engineers, landmen, and accountants, are similar in many respects to that of an independent producer. This paper will discuss the various aspects of oil and gas property management by the corporate fiduciary.

EOG Resources, Inc., in cooperation with surface management agencies, has pursued numerous methods to help minimize potential adverse environmental impacts and to improve reclamation of well locations, access roads, and pipeline routes. Among the primary issues when considering the location of well pads, roads, and pipelines are slopes, drainage patterns, and vegetation. An attempt is made to utilize existing pads, roads, and pipeline corridors whenever possible to minimize additional disturbance and also to provide the opportunity for improved reclamation of old, inadequately reclaimed disturbances. Location sites with slopes greater than 24% and access roads that would require slopes greater than 10% are avoided. Every effort is made to eliminate the need for severe cuts, which inevitably leave unsightly topographic scars and potentially result in severe erosion on the slope face. It was not unusual in the past to lose significant amounts of soil from these cut areas. In addition, areas that would create unmanageable watershed issues or create excessive damage to critical winter range vegetation are also avoided.

Stage separation as applied to oil production is a process in which the oil and gas mixtures, flowing from producing wells, are separated into liquid and vapor phases by two or more equilibrium flashes at consecutively lower pressures. The ideal method of separation, to retain the maximum amount of fluid flowing from an oil well, would be that of true differential liberation of the gas by a steady decrease in pressure from that existing at the well head to the atmospheric, or near atmospheric, pressure maintained in the storage tanks. With each differential decrease in pressure, the gas evolved would be immediately removed from the crude oil from which it is being separated. To carry out such a differential process would be impractical. A very close approach, however, towards differential liberation of gas can be accomplished by putting the mixture of oil and gas through several series connected separators, in each of which flash vaporization takes place. In this way the maximum economical amount of liquid flowing from the well can be retained in the stock tanks. The application of the process of stage separation, indeed, offers to the oil producer a means of increasing ultimate oil or distillate recovery, and also increasing revenue from property now in operation.

Spills of oil and hazardous substances are one of the primary concerns of EPA. Presently, an estimated 15,000 spills of oil and hazardous substances occur annually in the navigable waters of the United States. These spills are expected to significantly increase over the next 30 years, if left unchecked, as a result of greater production, transport, storage and transfer. It is estimated, based on existing reporting functions, that of the 15,000 total spills, approximately 75 percent involve petroleum products. These include the large and devastating-type spills such as the Santa Barbara offshore oil well blowout, the Louisiana offshore oil well platform blowouts and fires, and the large tanker and barge collisions and groundings. Added to these large incidents, there are numerous lesser events affecting practically every body of water where oil transport, transfer, pipeline crossing, onshore storage or related activities take place. In addition to spills or accidental discharges of oil and hazardous substances, large quantities of these pollutants enter the water environment every day as a result of continuous effluent discharges from refineries, chemical and petrochemical plants, factories, etc. These continuous discharges may have a more detrimental long-term effect than the large, one-time accidental spills.

The routine use of minimum density cement slurries (4-11 lb/gal) in oil field applications has been limited in the past; primarily because no convenient, cost-effective process existed which could provide useful compressive strength development at low densities. The careful selection and use of surfactants and foam stabilizers in addition to the use of properly designed field equipment has enabled the mixing and placement of stable foam cement slurries with instantly variable, but controllable downhole slurry densities from 3.5 - 14 lb/gal over a wide range of conditions. Typical physical properties such as compressive strength, porosity, and permeability for foam cements of various densities are presented. Foamed cement slurries have been successfully applied in the oil field on squeeze jobs, leaking LPG underground reservoirs, salt-zone wash-outs, as well as primary cementing jobs. Job histories covering 31 field jobs will be discussed.

There are approximately 600,000 producing crude oil wells in the United States, the majority of which use electricity to meet their production needs. Of these wells, approximately 75 % are classified as "Stripper Wells", producing an average of 2.34 barrels per day [I]. Many of these wells are only marginally economic, and an efficiency improvement project may make the difference between continuing to extract oil from a well and having to shut it in. In addition to the pump jacks, electric motors are used for water injection, pipeline pumping, steam production, and other operational necessities. In all, roughly 95% of all electricity used in an oil field operation goes into operating electric motors. The University of Wyoming Electric Motor Training and Testing Center (WEMTTC) has conducted an extensive study of electric motor efficiency at the DOE's Naval Petroleum Reserve #3 in Casper, Wyoming. Approximately 500 motors were tested for operating efficiency, many of which were determined to be oversized and operating inefficiently. This paper discusses the test method and instrumentation developed by WEMTTC, estimated results for energy-efficient motor retrofits. and actual results of several retrofits. The economic benefits of the retrofits are discussed, as well as a protocol for improving electrical energy efficiency in the oil field.

Lightning damage costs the oil industry millions of dollars each year in lost production, replacement equipment and service. Simple compliance with the National Electric Code is not sufficient because oil field operations involve concentrated electrical loads widely separated from each other. To efficiently serve these loads three-phase power is typically distributed at 12,470 volts. Installing lightning arresters only at poles having or feeding equipment is simply inadequate. Ground resistance, ground lead inductance, lightning arrester connections, power system grounds, shield wires, slack spans, ground bonding and transformer connections should all be considered in a comprehensive lightning protection plan. The intent of this paper is to strive for some consensus in equipment connections and grounding techniques which will produce the best reliability in rod and sub pump operations.

Types of plastics available, their uses and mis-applications. Quality control of plastic materials and the applied coatings.

Flow back and produced waters in the oil field are heavily laden with contaminates including insoluble iron sulfides,
poisonous hydrogen sulfide, residual gels, friction reducers, and other chemicals. In this paper we will look at chlorine dioxide (ClO2) as one possible solution to these problems. As a powerful, yet selective oxidizer, ClO2 has the ability to break up the residual gels and friction reducers while removing the insoluble iron sulfide and killing the hydrogen sulfide. As an additional plus, ClO2 is an EPA approved biocide that kills the bacteria which are the root cause of many of the problems with water reuse.

A system is described which utilizes a strain gage dynamometer permanently attached to each well for sensing well operation. The system also utilizes standard aerospace telemetry techniques and telephone lines for gathering the well data to a central office where individual wells performance may be monitored and simple control functions provided.