The oilfield use of resin coating on proppant such as sand, glass beads and ceramics began in the middle 1970's. Applications include downhole use in both onshore and offshore oil and gas wells. The initial idea was to pump a partially cured or curable resin coated proppant (RCP) in frac fluid into a well and let the elevated bottom hole temperature polymerize and bond the phenolic resin particles together. These bonded particles form a downhole filter or sheet of permeable sandstone in the fracture. The earliest use was for sand control where resin coated particles were injected as a gravel pack. In 1976 the resin coated particles were first used as a small tail-in proppant in a hydraulic fracture treatment. Starting with small volumes this use gradually expanded to larger volumes until today large volumes of the frac proppant in many wells are resin coated. Resin coated materials replace both sand and ceramic proppants and have now grown to a frac market of many million pounds per year.

The oilfield use of resin coating on proppants such as sand, glass beads and ceramics began in the middle 1970's.Applications include downhole use in both onshore and offshore oil and gas wells. The initial idea was to pump a partially cured or curable resin coated proppant (RCP) in frac fluid into a well and let the elevated bottom hole temperature polymerize and bond the phenolic resin particles together. These bonded particles form a downhole filter or sheet of permeable sandstone in the fracture. The earliest use was for sand control where resin coated particles were injected as a gravel pack. In 1976 the resin coated particles were first used as a small tail-in proppant in a hydraulic fracture treatment. Starting with small volumes this use gradually expanded to larger volumes until today large volumes of the frac proppant in many wells are resin coated. Resin coated materials replace both sand and ceramic proppants and have now grown to a frac market of many million pounds per year.

The design of traditional sucker rod pump plungers has taken several approaches to reducing plunger wear with the goal of extending reciprocating lift pump run times. These methods with their advantages will be reviewed, and the concept of flushing sand and other particulates from the plunger's leading edge will be introduced by explanation of the patent-pending Sand Flush Plunger.

This paper will present and explain new equipment designed to pump gaseous wells. The need for this equipment will be explained by showing slides of pump parts damaged by wells making gaseous fluid and being over-pumped or being operated in pump-off condition. Cut away model pumps will be displayed, illustrating the application of the new equipment and its installation on existing subsurface rod pumps. The presentation will include recommendations for coping with the problems of gaseous wells.

This paper presents the development and application of new techniques for predicting the sand bank geometry created by relatively thin, non-complexed fluids in fluids in vertical fractures. The theory utilizes the concept of equilibrium velocity combined with fracturing fluid efficiency. The development includes the effects of variable fluid leakoff along the extent of the fracture face due to sand bank build-up and also the effects of the sand bank on the fluid velocity profile along the fracture face. It is found that the slope of the sand bank decreases exponentially with penetration resulting in a bank that is shaped like an airfoil. The effects on controlling stimulation parameters such as fluid pumping rate, fluid loss, and equilibrium velocity are discussed as they pertain to sand bank geometry control. Finally, the implications of the sand bank geometry on more effective stimulation design are discussed.

Progressing cavity pumps have been used on an application-limited basis throughout the world for the past twenty plus years. A vast majority of these systems are deployed in Canada and South America producing heavy, viscous oil with high sand content. Product development and numerous specialty ancillary products have most generally favored heavy oil production. A few of the ancillary products such as spin-thru rod guides, torque anchors, heavy-duty wellhead drive, etc transcend across application boundaries, however, the heavy oil market dominates most of the research and case studies. This paper will focus on P C pump product enhancement and design changes for applications that are more typically encountered by US operators. These wells can be grouped into the following: secondary recovery, light oil, high water cut, high volume, or water source wells and coal bed methane applications. These wells require a different philosophy and certainly different pump geometries than what was previously available through the manufacturers. Continuing, the paper will report on several of the products that have been developed, tested and are now being used within the Permian Basin. We will share the results of field-testing on down hole pressure sensors and a specialty rotor coating as an alternative to chrome. Benefits of new elastomers that have been brought upon the market will be examined.

This paper discusses the utilization of microprocessors for level measurements in multiple sealed oil and water tank batteries that incorporate Vapor Recovery Units which cause pressure variations inside each tank. The application consists of the integration of two highly accurate pressure (level) transmitters, one low range vapor pressure transmitter, a microprocessor that utilizes specific gravity information and subtraction techniques, resulting in a highly accurate level measurement system for production stock tanks.

This paper discusses the utilization of microprocessors for level measurements in multiple sealed oil and water tank batteries that incorporate Vapor Recovery Units which cause pressure variations inside each tank. The application consists of the integration of two highly accurate pressure (level) transmitters, one low range vapor pressure transmitter, a microprocessor that utilizes specific gravity information and subtraction techniques, resulting in a highly accurate level measurement system for production stock tanks.

This paper offers a new approach to qualify proppant before fracture stimulation. Automated and patented flowing stream sampling technology, only recently available, is easily positioned between pneumatic trailer and field bin. Mobile labs are used to measure sample physical properties and correlate public domain or design data. Differences, which provide the basis for performance and engineering decisions, relate to mining anomalies, manufacturing defects, transportation abuse, and contamination. This is critical, as proppant is the primary construction material for a conductive fracture. To evaluate these supply chain issues API quality practices include long standing principles: 1) representative sampling from a flowing stream, 2) standardized testing with calibrated equipment, and 3) sample retention for follow-up evaluation. Since proppants are chosen to improve reservoir fluid recovery, evaluating quality and performance before the frac identifies deficiencies, assigns accountability, improves job design, and facilitates an opportunity for the best reservoir response. Case histories are included.

The TUBING CONVEYED Perforating and Well Completion Technique*, which was first introduced by Vann Tool Company in October 1970, has become an accepted and highly desirable method of perforating in southeastern New Mexico and is now being used in wells in West Texas, Oklahoma, Colorado, and Wyoming. Since its inception, many modifications and improvements have been made in the components and mechanics of the system. In this paper, specific attention is devoted to the following: 1. Accurate and exact depth control for inzone Perforating 2. The packer-actuated vent assembly* 3. The mechanical tubing release sub* 4. Safe and effective differential perforating using conventional perforating techniques 5. Communication detection markers for determining the existence of communication between zones.

This paper presents the results of a new treatment designed to improve the cleanup of horizontal/openhole completions. The wells evaluated in this study were drilled using either starch or cellulose polymers, xanthan polymer, and sized calcium carbonate or salt particulates. These clean "drill-in fluids" were introduced to minimize the damage to the wellbore when compared to that observed with conventional drilling fluids. Although used to minimize formation damage, testing and experience have shown that insufficient polymer degradation can significantly reduce flow capacity at the wellbore leading to reduced well productivity or injectivity. Acid treatments are typically applied in attempts to remove or "by-pass" the damage created by the filter cake. These acid treatments are often marginally successful, particularly when applied in extended length intervals. Previous studies were conducted to develop laboratory procedures to better simulate and characterize the damage attributable to these "clean" drill-in fluids. Various chemical breaker systems were subsequently applied to evaluate the effectiveness of their relative filter-cake degradation capabilities. Laboratory studies have demonstrated that drill-in fluid filter cake can be effectively removed through the application of a newly developed technique incorporating an enzyme-based polymer degradation system. The data show that through utilization of this new technology, smaller, less costly treatments can be used to treat entire openhole intervals to zero-skin potential with dramatically improved treatment efficiency. Much smaller, lower concentration acid treatments can then be effectively applied to stimulate the interval. Surveys following the field application of the new system have shown not only increased flow, but also flow throughout entire length openhole intervals.

A research project was undertaken to develop an iron sequestering agent which could be used to control the precipitation of iron in fracturing operations without affecting the rheological properties of the crosslinked gel. The control of iron in production comes in combine and can cause acidizing is well documented but it has only recently been recognized as a problem in fracturing. Problems occur when oxygen in the fracturing fluid contact with iron in solution in the formation water. The two components if conditions permit an insoluble precipitant will form. This precipitate severe permeability damage. In acidizing, sequestrants have been widely used for years to control iron. However, when fracturing with crosslinked fluids these same sequestrants will complex with the gel crosslinker as well as with iron. This reaction will prevent the fracturing fluid from crosslinking. Recently, a new selective sequestrant was developed which reacts only with iron and therefore does not affect the rheology of the crosslinked gel. This paper describes the problems associated with fracturing formations containing high amounts of in-situ iron and the manner in which this new selective sequestering agent can be used to prevent these problems. Rheology data will be presented to show the compatibility of the sequestering agent with the crosslinked gel system which was specifically designed to be used with the new sequestrant. Finally, its effectiveness as an iron control agent is demonstrated through lab flow tests and field case histories in which the compound was used.

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