In a few short years the delivery of chemical products has been one of the fastest growing technologies in the oil and gas industries. From acid sticks, corrosion inhibitors, and specialty soap sticks, an evolution of several generations of chemical delivery has evolved into near total automation that has proven to be safe, efficient, and cost effective. From dismantling equipment and using laundry detergents to automated chemical stick launchers, the new generation dispenses chemicals according to the gas wells needs and predetermined chemical protocol for individual gas wells. Oil and Gas producers have available to them the future of solid chemical launchers and automation for increased production and reduction of costly man hours.

Well tests are crucial to managing rod pumped wells, and operators struggle to get tests as frequently as they desire. A method has been developed using the down hole pump card generated by a Rod Pump Controller that has proven to be accurate and reliable. The method will be explained and data will be presented from field tests showing actual well tests compared to the well test from the Rod Pump Controller.

The use of curable resin pre-coated proppants was often applied in the Permian Basin area to control proppant flowback. However, these pre-coated proppant materials continued to allow propopant to produce back, especially during production surges because they did not provide sufficient consolidation strength to handle high drawdown. Since early 2005, a low-temperature curable liquid resin system was selected to treat the proppant on-the-fly mainly during the tail-in stages in most of 1,500 hydraulic fracturing treatments. This paper highlights how the proppant back-production problems were successfully overcome through the application of this curable resin system. Detailed descriptions of the treatments, challenges, and lessons learned during the course of these fracturing treatments are presented.

The deregulation of the Texas electric utilities has created many opportunities and challenges for oil and gas producers. Questions continue to be asked regarding how oil & gas producers will purchase power. With the enactment of 1999's Senate Bill 7, electricity buyers are beginning to find out the "devil is truly in the details". Challenges when purchasing electric power include reviewing contract terms and conditions; determining (deciding on (or selecting)) the most suitable contract duration; analyzing complicated pricing proposals and their links to gas markets; determining the optimum pricing options. The buyer's challenges continue with billing and collection issues such as ancillary charges, profiling, bill formatting and delivery options, and procedures for contesting billings. As Retail Electric Providers fight to establish market share, more creative and innovative pricing options will become available. Minimizing power costs will require producers to keep both eyes open: One eye on the power markets to make the best power purchases they can, and the other eye on their operations to optimize power use.

Companies with large geographically dispersed networks, such as those in the oil and gas industry, can select one technology, one source, one vendor, to collect, retrieve, report data, and to assess the health of the network. Sometimes, this type of approach makes sense. However, other times integrating other types of technologies offer significant benefits that can easily and more cost-effectively be incorporated into one cohesive network. In fact, the days of building large, unmanageable networks are behind us. Building large, elaborate radio networks is a way a company might demonstrate its vast expertise and deep knowledge base. However, there are options that allow us to consider better manageability, expandability, cost and speed.

The 2.8 Billion Barrel (Original Oil in Place) SACROC Unit is located in Scurry County, Texas and produces from the Pennsylvanian-aged Cisco and Canyon Formations of the Kelly-Snyder and Diamond M Fields. This Unit has had a colorful history, with discovery shortly after World War 11, nearly half a century of waterflooding, three decades of tertiary development, and a wide variety of operators and philosophies. Since the time of SACROC's early CO, efforts, local experience and industry practices have contributed greatly to our knowledge of CO, flooding in general. Today, Kinder Morgan CO, Co., L.P. (KMCO,) is CO, flooding an area in the central portion of the Unit (using new techniques and philosophies) with great success. Unit production is now at a nineyear high, with average monthly production exceeding 13,000 BOPD. Tertiary recovery efforts are very expensive and require a great deal of reservoir understanding to reduce risk and increase efficiency. So, KMCO, has initiated a dual-pronged approach to the continued development of SACROC Unit, with flooding efforts currently focused on "less risky" areas, and with more intense geologic study focused on understanding the more complex, higher risk, and greater potential areas. However, even in the low risk areas this reservoir is extremely complex and data is sometimes scarce, misleading, of low quality, or ambiguous. Relatively few modern logs exist, and unique situations can cause confusion about log responses. Correlations are difficult in certain areas due to complex geometries associated with mound buildups, erosional contacts, and local depositional geometry. Because the reservoir's internal architecture is so complex, strange fluid flow responses sometimes occur in areas that appear rather simple at first glance. That said, the Unit can still be divided into northern, central, and south-western regions for general comparisons. A thick, north-south trending platform, with karst features that increase in intensity to the north and higher in the section, dominates the northern area. The central region is a broad, gently arching plain broken by steep-sided pinnacles, gentler mounds, intermittent sinuous lows, and localized depressions. The southwestern area is the most structurally complex region of the Unit, with a series of faults and channels that contribute to small, isolated compartments. Success at SACROC can be credited to the geology and hydrodynamics of the reservoir, the technical feasiblity of tertiary recovery with CO,, and the efforts of a multi-disciplinary team providing input from field, reservoir, and corporate levels.

THERE ARE CURRENTLY SEVERAL THOUSAND CASING PLUNGER LIFT SYSTEMS INSTALLED IN VARIOUS PARTS OF THE COUNTRY. THEY RANGE FROM VERY SUCCESSFUL TO FAILURES. THIS PAPER IS AN ATTEMPT TO EXPLAIN WHY THIS HAS BECOME THE CASE AND TO DELINIATE ISSUES OF WHERE TO APPLY THIS TECHNOLOGY. THE APPLICATION OF THIS TYPE OF artificial lift DESIGN MUST REQUIRE THE USE OF SOME PLANNING THAT IS NOT COMMON TO THE NORMAL TUBING PLUNGER LIFT DESIGNS. THERE ARE FEW SIMILARITIES BETWEEN THE TUBING PLUNGERS AND THEIR CONCEPT OF OPERATION AND WHAT OCCURS WITH THE CASING PLUNGER AND ITS OPERATIONAL CONCEPT. THE USE OF THE TUBING PLUNGER LIFT SYSTEM IS BASED IN FACT THAT THERE IS SUFFICIENT GAS FLOWING AT A HIGH RATE TO BRING THE COLUMN OF LIQUIDS ACCUMULATED IN THE TUBING STRING TO THE SURFACE. THE FLOW RATE IS AN ISSUE OF SUFFICIENT PRESSURE AND VOLUME TO ALLOW THIS TO CREATE A VELOCITY THAT CREATES A GAS/LIQUID SLUGGING. THE BALANCE OF THE VOLUME AND PRESSURE MUST BE ABLE TO DEVELOP THIS RATE AND OVERCOME THE HYDROSTATIC PRESSURE OF THE LIQUID COLUMN. THE INACCURATE BALANCE OF EITHER THE LQIUDI COLUMN OR THE VOLUME OF THE GAS OR THE PRESSURE OF THE GAS IN THE WELL OR IN THE VARIATION OF LINE PRESSURE CAN LEAD TO FAILURE. THE UNDERESTIMATING OF LIQUID OR AVAILABLE GAS OR FLUCTUATION OF LINE PRESSURE LEADS TO THE FLOW RATE BEING INSUFFICIENT OR THE FLOW BEGINNING BUT FAILING TO MAINTAIN THE TRAVEL TO HE SURFACE OF THE COLUMN AND PLUNGER. EXCESSIVE LIQUID OR DROPS IN WELL GAS VOLUME AND PRESSURE OR AN INCREASED LINE PRESSURE CAUSING PARTIAL LIQUID REMOVAL CAN BE TERMED PLUNGER "STALL". OPERATORS PURPOSELY, YET UNDERSTANDABLY, AVOID THIS INBALANCE THAT CAN LEAD TO NO FLOW OR NO LIQUID UNLOADING FROM THE WELL. THE ACTUAL REQUIREMENTS OF THE CYCLE ARE OVERESTIMATED BY FACTORING IN TOO MUCH GAS FOR THE ACCUMULATED LIQUID COLUMN AND THEN ASSURING THE LIQUIDS AND PLUNGER WILL ARRIVE.

There are several ways to reduce the lifting cost of a sucker rod pumping unit. One way is to reduce maintenance. Another way is to "tune-up" the unit. A simple way to "tune-up" the unit is to balance it properly. A unit that is balanced properly will produce fluids more economically by reducing the electrical power loss. Therefore, by balancing all the units in a field the electrical power loss will be reduced but the maintenance will be increased. Consequently, a method that minimizes the maintenance needed to balance a unit is desirable. This paper presents a method that will minimize the maintenance needed to dynamically balance a unit. This efficient balancing method uses the motor current, the unit geometry and the dynamometer card to reduce the magnitude of current or power fluctuations experienced by an electrically driven system. In other words, the closer the RMS current approaches an average current, the smaller the electrical power loss. Therefore, reducing the power loss with a minimum amount of maintenance will in turn reduce the lifting cost of a sucker rod pumping unit.

There are several ways to reduce the lifting cost of a sucker rod pumping unit. One way is to reduce maintenance. Another way is to "tune-up" the unit. A simple way to "tune-up" the unit is to balance it properly. A unit that is balanced properly will produce fluids more economically by reducing the electrical power loss. Therefore, by balancing all the units in a field the electrical power loss will be reduced but the maintenance will be increased. Consequently, a method that minimizes the maintenance needed to balance a unit is desirable. This paper presents a method that will minimize the maintenance needed to dynamically balance a unit. This efficient balancing method uses the motor current, the unit geometry and the dynamometer card to reduce the magnitude of current or power fluctuations experienced by an electrically driven system. In other words, the closer the RMS current approaches an average current, the smaller the electrical power loss. Therefore, reducing the power loss with a minimum amount of maintenance will in turn reduce the lifting cost of a sucker rod pumping unit.

Most light weight systems are produced by increasing the amount of water used with each sack of cement. To produce a uniform slurry with this additional water: pozzolans, clays or silicates may be added or fine grinding of the cement composition may be used. These systems, using water as the light weight ingredient have similar ultimate strengths and permeabilities for similar densities. Early strength development as well as ultimate strength and permeability depend on the temperature to which the cement is subjected. Cements in which the density is reduced by using light weight particles instead of water have somewhat different properties. Those using light weight hollow bubbles produce high early strength and improved ultimate strength at an increased slurry cost. Care must be taken that hydrostatic pressure does not crush the bubbles.

The well stimulation process of hydraulic fracturing has existed in the oil & gas industry for over 50 years. During this time, many innovations and technologies have been employed that have substantially enhanced the process. In recent history, the industry has focused on the creation of cleaner fracturing fluids, while propping agents have remained relatively unchanged. Recently, water frac treatments have found success in some niche areas. The widespread use of water fracs has lead to the research of improved proppant transport and the subsequent development of lightweight proppants. This paper will discuss lightweight proppants, their development, what they are, and why they work. The paper will also examine the settling velocity of proppant in a hydraulic fracture and the positive effects of reducing this velocity. Additionally, improvements in overall proppant transport will be documented. Case histories will also be provided which will support the claims made by the authors.

This paper discusses the occurrence and characteristics of lightning-related phenomenon, and the damage which it may cause to commonly used oilfield equipment such as tank batteries, power lines and transformers, ESP systems, drilling rigs and pulling units. The paper provides some considerations when deciding if a lightning protection system is warranted for a given facility and it presents some guidelines in the design of practical "Brute-force" protection methods, using a blend of published research from non-petroleum industries and operational experience in the oilfield. Case histories, illustrating both effective and ineffective designs are given.

For many years, the problem of protecting electrical systems from lightning discharges has plagued power and communications engineers. Only within the past few decades has lightning been a problem to engineers dealing with electrical power systems in oilfields. The problem of lightning protection in West Texas oilfields is unique due to the high concentration of elevated high-voltage lines above flat plains that attract lightning discharges. Most modern, electrically operated oilfields have power-distribution systems that are well protected from lightning discharges; in many cases, the systems are isolated by sectionalizers and other devices. Even if a portion of a field is disabled by lightning damage, the remainder of the field continues to function normally. This paper, therefore, concentrates on protecting the low voltage electronic-instrument systems that are very susceptible to even minor voltage surges caused by lightning. In the last several years, the tremendous expansion of oilfield automation and electronic surveillance equipment has required increased emphasis on protecting low-voltage instrument systems from lightning discharges. These systems use direct-current voltages of 1 to 50 volts with 120 volt alternating-current power sources. This paper deals with methods used in a major oilfield automation project to protect various parts of the system from lightning damage. The lightning protection devices discussed are used to protect two computer-monitored oilfield automation projects located on the South high plains of West Texas near Levelland, Texas.

This paper is a report of methods used by Southwestern Public Service Company to reduce momentary interruptions due to lightning. This required the determination of the optimum spacing of arresters to protect distribution lines from lightning by applying arrester stations to two different locations in the same area. Each line represents a different average spacing of arrester stations. These lines are compared to a shielded line and an unprotected line, also in the same area.

The LRP

The Long Life Technique is a revival of an old cementing practice whereby cement slurry is placed in the well and casing is then lowered into the cement. Recent development of cement additives has appreciably widened the range of well conditions in which this technique can be employed. Difficulties are often encountered when planning and performing liner primary cementing jobs in projects where the annulus is unusually small and in projects where the open hold portion of the well is not sufficiently competent to support the hydrostatic weight of a high fluid column. Problems inherent to these two types of liner jobs are often minimized by the application of the Long Life Technique.

A liner is any string of casing with its top below the surface of the well. Previous papers have been written on the subject of liner cementing, but most of these papers on liners have emphasized their use in deep wells. Simpler uses of liner cementing equipment should also be discussed, since greater numbers of liners have been run in shallow-to moderate depth wells than in deeper wells. A discussion on conventional and special liner cementing jobs with illustrations of the equipment for these jobs is included in this paper. Problems concerned with liner movement during cementing are discussed.

Twice before, at the 1977, and 1981 Southwestern Petroleum Short Course I presented papers on liner cementing equipment and techniques. In the first paper I explained a method of rotating liners while cementing and reported that not many liners were being rotated; probably about 1 in 30 jobs were rotated or reciprocated. In 1981 I gave a paper explaining why a new sealed bearing made the rotation of liners more reliable; but still only 10% or less liners were being moved while cementing-rotated or reciprocated. Now, five years later, probably more than 20% of all liners are rotated and/or reciprocated during cementation. Liners have been rotated successfully even in directional holes offshore in the North Sea. One recent job was successful in a 47o deviated hole on a floating drill ship. This paper will attempt to show how new state-of-the-art liner rotation equipment has made this increase in popularity possible. We have listed the six major categories of causes for unsuccessful liner rotation jobs and have given some suggestions how they might be prevented.

While liquid additives are used in offshore & international cementing operations, land-based operations use a bulk-drybatch- mixed process. Additives control cement volumetric yield, thickening time, compressive strength, free water, rheology, and fluid loss control. Computerized closed-loop control of liquid additives 1) allow unused, uncontaminated cement to be hauled off location after an operation, 2) promote environmental responsibility by reducing the volume of waste cement hauled to a landfill, and 3) provide better quality control of slurries pumped "on-the-fly"" due to better distribution of additives in the slurry and tighter computerized tolerances. Surface slurries utilizing liquid sodium silicate in API Class C cement were designed to meet or exceed Texas Railroad Commission Rule 13 requirements for "zone of critical cement" "extended cement" systems. Slurries were tested for thickening time, free water, compressive strength, and rheology for various combinations of weight, water, yield, additive concentration, and adherence to TRRC (Texas Railroad Commission) Rule 13 specifications.

Over the years, considerable work has been done in evaluating wellhead equipment options available to the producer which will optimize the recovery of hydrocarbon liquids from Gas-Distillate wells. The value of these have been such that reasonable payouts of the liquid recovery facilities have been generally attributed to the various types of wellhead processing schemes. As these liquids become more valuable, some options which require additional capital investment may now present satisfactory amortization which a few years ago would not have. This paper deals with information regarding the relative merit of various processing options and estimates of the amount of increased liquid recovery attributable to such options. No attempt to present actual payouts will be made herein since there are always variables in such determinations which are beyond the scope of this paper however, incremental increases in recovered liquids are illustrated which will assist the producer in making economic decisions.

The liquid level recorder saves time and labor and insures more accurate data. A general utility recorder, it is simple to operate, inexpensive, yet extremely sensitive and accurate. It is used in the oil field for the primary purpose of recording the production of oil and/or water into the test tank or stock tank. During the life of an oil well it may be called upon to do the following: detect loss of circulating mud during drilling; measure load oil and formation oil during swabbing and initial testing; record the potential test; record fluids produced on a productivity index test and; determine the producing cycle of a gas lift or pumping operation.

The use of polymer additives to obtain lower friction pressures in tubular goods has long been an accepted practice which has focused attention on friction-pressure drop as a major factor in job design," Pressure limits set by pipe strength, as well as economic limits on horsepower, often determine the maximum obtainable rate. This rate may not be sufficient to give the most efficient stimulation treatment. The effective use of these polymer friction reducers has allowed higher rates within pipe pressure limits, leading to more successful stimulation treatments without increases in horsepower costs. Many treatments being performed today would be impossible without the use of friction reducers. The most widely used friction reducers are guar gum and cellulose derivatives, i.e., HEC, and polyacrylamides. The polyacrylamides are superior as friction reducers.2"3"4"5 However, guar gum and cellulose derivatives offer the added advantage of viscosity control of fracture leak-off at moderate concentrations. Leak-off control and proppant placement techniques6 led to the use of highly viscous gels and eventually to the development of the high viscosity complexed gels. The increase in viscosity, however, was generally observed to be accompanied by an increase in friction pressure. Although these fluids offered high viscosity, fluid loss control, perfect proppant support, thermal stability, etc., an improvement in friction properties was desired." Even with 50-60 percent friction reduction, desired injection rates are difficult to achieve within pressure limits of tubular goods or at acceptable horsepower costs, especially in small diameter tubing. Earlier attempts to improve the friction properties of these viscous fracturing fluids were directed toward the addition of the more efficient polyacrylamides to these fluids. Such attempts were unsuccessful. This lack of success was attributed to materials-handling problems and hydration problems. Recent advances in polymer technology have offered the polyacrylamides in liquid form. Unlike the traditional powdered polymers, the liquid polymers are prehydrated. They do not form lumps when added to water; thus handling and mixing are facilitated. Furthermore, the addition of liquids can be more uniformly controlled. With the advent of these new polymers, experimentation was resumed. Recent field trials have shown that these liquid polymers can significantly alter the friction properties of both complexed and non-complexed fracturing fluids.

Efficient removal of liquids from gas wells is accompanied by a system using gas lift valves and a subsurface liquid diverter. The mechanics of the system make it adaptable for use in high ratio oil wells. Case histories are used to illustrate the effectiveness of the system in several areas and well types. Surface and subsurface pressure records are used to explain the operation of the system and its components. Application limits of the system and design criteria are described.

A San Andres Task Force Group was initiated by Halliburton Services in January 1972, with the primary objective being to improve production stimulation results for the San Andres formation of the Permian Basin. A scientific approach was envisioned to combine lithology with engineering, laboratory and field date to determine the best type of treatment for San Andres wells. This study was divided into three parts. Phase I of this project was an organizational and data-gathering phase. Phase II was primarily a data and sample analysis phase. During this period, data and information were analyzed to define variations in rock type for one particular geographical area. The objective was to determine if a relationship could be found between depositional environment and rock type. Methods for determining basic rock type were to be investigated in this phase of the San Andres formation study. The purpose of Phase III was to make a study of the results of various types of stimulation treatments for the different rock types in the San Andres formation. The purpose of this study was to determine if certain types of treatment might be more effective for a specific rock type. If this were true, the best general type of stimulation for a particular area producing from the San Andres formation might be selected once the rock-type of the formation had been determined.

With the advent of large volume frac treatments, interest has increased in obtaining in situ rock properties for use in well-treatment design. Also studies have been made relating acoustic properties of formations to lithology." When techniques are being applied for these purposes using well logs, the presence of gas is observed to distort the usual relation between compressive and shear velocity for the particular lithology.