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.

This presentation discusses the utilization of the digital computer for load-flow analysis and optimization in computer-owned electrical distribution systems. Discussed are: A) Program Utility, B) Program Construction, C) Input Format, D) Output Format, E) Interpretation, F) Options.

This paper focuses on such energy alternatives as fossil fuels, municipal and agricultural wastes, solar energy, and nuclear energy. It also describes recent choices of alternative energy resources selected by Southwestern for close examination.

Applying horizontal well technology to improve oil recovery in reservoirs undergoing active water flooding continues to evolve with improving success. Development of remaining unswept oil reserves with horizontal wells as a method to improve conformance is a significant challenge. Evaluating and optimizing well performance to achieve economic results in a waterflood setting is a critical step in maximizing the success of a horizontal well project. Horizontal laterals expose large amounts of productive reservoir rock, benefiting certain reservoir applications while adding a major risk component to well designs planned for heterogeneous, water flooded carbonate reservoirs. Long laterals increase potential of exposing undesirable geologic conditions such as waterfilled fracture networks, zones of high water saturation and extreme permeability of thief zone intervals. A significant negative impact on well performance from high water production rates can result in lower oil rates and excessive lifting costs. This paper summarizes methods and experiences in mechanically evaluating and diagnosing fluid entry in newly drilled horizontal wells, efforts and results to control water entry and optimize well performance. Also discussed are field test results of a new tool design combining re-settable, inflatable packers and a hydraulic jet pump. Early field test results suggest this method will be a promising advance toward efficient diagnosis of fluid entry in both vertical and horizontal wells.

Since the day of its inception, artificial lifting of crude oil has confronted producers with many and varied problems. In the early days of oil production a special type sucker, or wooden branch, fitted with iron connections, was used in pumping operations. Many shallow water wells use similar equipment even today. Failures in this type of sucker rod invariably resulted from rotting, swelling, unscrewing of connections and splitting in the bradded areas.

Placement of plugging agents or stimulation fluids by mechanical means is usually unsuccessful. Fractures, erosion, behind-pipe communication delimit in-hole packers. Diverters often seal the formation face but permit unwanted vertical fluid movement. Temperature and R/A techniques provide "after the fact" data. Plugging and squeeze operations often damage the zone, requiring recompletion of the well. This paper presents the adaption of an otherwise obsolete injection profiling technique that allows continuous monitoring and control of fluid placement resulting in a properly conditioned well. Experience with over 200 wells has verified the technique.

Log-derived determination of residual oil saturation (ROS) for enhanced oil recovery projects requires accurate and reliable techniques. Therefore, special considerations have to be given to both the logging operation and associated interpretation methods. Since the statistical uncertainty limits of conventional open - and cased - hole logging techniques are not sufficient for reliable ROS values, a key parameter in the evaluation of EOR candidates, several log-inject-log (LIL) techniques based on multiple repeat logging runs are available to provide more reliable ROS values. Advantages and possible constraints of several LIL techniques will be discussed.

Formidable technical and operational problems arise in the course of drilling, testing, and producing wells which contain appreciable amounts of hydrogen sulfide. Though not the worst of such problems, wireline operations are certainly rendered more difficult and dangerous. Logging equipment is designed to perform properly in the high temperatures and pressures found in oil and gas wells. The presence of hydrogen sulfide has thrust forward a new hostile environment problem. The troubles are twofold: the threat of personnel overexposure, and the deterioration of metal components which are exposed to HS. Industrial plants have long known of the dangers to personnel who are exposed to hydrogen sulfide. Steps were taken to learn the procedures necessary for personnel safety. These procedures were then adapted for use by our logging crews, and have been effective in that no case of hydrogen-sulfide poisoning has been reported. The downhole problem created by the presence of hydrogen sulfide is harder to correct. The solution to the problem was evidently either to protect vulnerable steels from contact with the gas, or to use other materials which were not vulnerable. Both measures have been successfully applied. Protective coatings are good enough to permit the use of standard cables and downhole tools in cases of low HlS concentration, but special H2Sresistant cables are needed for severe conditions. In no case, however, should sour-gas logging operations be looked upon as routine. HS-resistant pressure-control equipment is also available. Pressures to 15,000 psi can be controlled.

Mineral scale formation is a problem for oil and gas operators that can result in deterioration of assets, increased lifting costs and lost production. Scale which forms in or at the perforations can only be prevented by placing scale inhibitor in the producing formation via some type of reservoir displacement technique commonly referred to as a squeeze. Operators desire inhibition that will last as long as possible and minimize the production interruption for treatment. In reservoir formation types that exhibit known scaling problems, scale inhibition treatment can be initiated during the completion stage using a solid inhibitor integrated into the hydraulic fracturing program. Treatments of this type can result in deep reservoir placement of inhibitor without large amounts of introduced water frequently needed with traditional squeeze treatments. Data presented in this paper illustrate the superior performance and longevity of these types of treatments.

Loss of drilling fluid to the formation is one of the most costly problems that drillers face during well construction. Common methods used in the past involved incorporating materials in the fluid or in pills to bridge permeable or fractured formations and create filter cake over these bridges. Current technology enables a comprehensive approach that complements these methods but emphasizes other aspects of the drilling operation. These include making use of drilling fluids that inherently reduce the rate of loss of fluid through modification of fluid properties like low-shear-rate viscosity; minimizing fluctuations in the fluid's equivalent circulating density; accurately modeling the rock mechanics of the formation; and strengthening the wellbore. Implementation of these techniques will be discussed, along with their impact in current drilling operations.

The Lovington San Andres Pool is located in central Lea County, New Mexico, approximately 10 miles northwest of the city of Hobbs. The 2400-acre pool was discovered by the completion of Skelly Oil Co.

Data gathering and alarm systems have historically been priced out of reach of the small oil producer. This paper deals with systems affordable to the independent operator. It explains specifications offered by suppliers and requirements needed to operate different applications. It also touches on different types of software and when it should be incorporated into the system.

Cementing production casing in partially depleted reservoirs is a common problem in the Permian Basin. The industry is continually looking for alternative slurry designs to lower annular pressures during cementing while maintaining the material properties needed for stimulation and zonal isolation. In order to be viable, the resulting technology must decrease density while preserving compressive strength, fluid loss and free water properties of the cement. Cement slurries using foam or hollow spheres are capable of meeting these requirements. The additional equipment and material cost required usually prevent these systems from being economical when mixed between 13.5 and 14 ppg (lbigal). Recent technical developments have lead to the creation of slurries weighing 13.8 ppg containing 60% pozzolan and 40% API cement. These economical slurries exhibit mechanical properties comparable to standard API slurries having much higher densities. Laboratory testing and bond logs are presented and compared along with recommended applications.