The purpose of this paper is to illustrate the application of pressure and temperature surveys to gas lift installations, not to discuss the mechanics of bottom hole pressure and temperature instruments. The advantages of pressure surveys prior to the installation of gas lift equipment are discussed. The procedure for running surveys in intermitting gas lift wells is offered. The determination of the operating valve or valves, using both the temperature and pressure survey in the same well, is presented. Examples of surveys in a gas lift well with a tubing leak and a well with leaky valves are given. Bottom hole pressure surveys for chamber installations are noted which show the minimum flowing bottom hole pressures obtained with low pressure versus high pressure operating gas lift valves. The paper concludes by illustrating the use of a pressure survey for estimating per cent fallback in an intermitting gas lift installation.

The Queen Sand of southeastern New Mexico is characterized as a sequence of laminated sandstones and shale, bounded by anhydrite seals. Good permeability is evident but still the Queen requires fracture stimulation to be successful. The case presented in this study is an injection well from Chaves County in southeastern New Mexico. For this stimulation study, surface treating pressure data from a fracture treatment was history-matched with a pseudo 3D fracture simulator. Fracture characteristics such as height and fluid distributions from the pressure match were compared with that from the radioactive and temperature tracers to analyze the fracture treatment in this formation. An additional complication is the existence of a compressible, friable sand bed, resulting in difficulties in hydraulic fracture effectiveness. Two fracture designs are compared: a vertical fracture with high proppant concentration in a restricted interval, and a horizontal fracture due to the shallow depth and high frac gradient.

Safety must be paramount to both the service provider as well as the service recipient as our industry is mandated to provide a safe work environment for all personal involved in the well service and maintenance industry. It is incumbent on our industry to develop, implement, and accept safety systems that as managers we insure all that can be done is being done to meet that safety mandate.This paper deals with recent technological developments dealing with rig systems that will enhance both the safe operation of a rig and protect the wellbore environment against catastrophic failures and or mistakes that lead to costly workovers and occasionally the loss of a wellbore. Discussion topics, actual field data, and technology introduction will be centered around: - Decreasing the likelihood of a crown or floor out incident - Preventing over pulling and stretching of rods and tubular - Alarming the rig operator when the rig is being operated out of the safe envelope of weight and speed relationships - Measuring and alarming when uneven derrick loading or tilt has occurred.

When crude oil is brought to the surface, various amounts of water, gas and other elements are mixed with the oil into a homogeneous mixture referred to as an "emulsion. " Before the oil is refined, the water, gas and other elements must he removed from the oil. This removal, or separation process, is referred to as "treating. " A combination of heat, settling and chemical treatment is used to affect "treating." A recent development adds the use of electrostatic grids to improve "treating. "

There are six basic API Loads critical to beam pumping. These loads interact during a complete pumping cycle. Fortunately these loads can be measured and compared against their respective counterparts. A building block approach which combines these basic loads aids in diagnosing operating and design problems. Standing and traveling valve actions tend to follow a fairly definite pattern during a normal pumping cycle. When abnormal pumping conditions occur, these valves may not conform to their respective normal patterns of opening and closing. A dynamometer is a useful instrument which can be used to record specific loads generated during the pumping cycle. Certain pumping equipment malfunction can be diagnosed by interpreting dynamometer cards. Normal and abnormal valve action can also be detected using the principles associated with dynamometer card interpretation. There are many basic components which must be considered when designing or operating beam pumping equipment. These must be in harmony with each other to have a relatively trouble free pumping operation. When one of these components malfunctions or is changed, it may be necessary to change other parts of the system to maintain the desired relationship. Certain operating parameters can be established to promote optimum operating conditions. The use of dimensionless speeds, dimensionless loads and acceleration factors aids in determining the most trouble free portion of the beam pumping "operating window". It is equally important to operate the equipment with the proper counterbalance. Over-pumping a well can aggravate an otherwise properly counterbalanced operation. In these situations it is necessary to bring the well outflow into a satisfactory relationship with the well inflow. Redesigning the producing equipment is one way to accomplish that objective. When changing the producing equipment might not be the practical thing to do, intermitting the pumping cycle is another often used and satisfactory method.

There are six basic API Loads critical to beam pumping. These loads interact during a complete pumping cycle. Fortunately these loads can be measured and compared against their respective counterparts. A building block approach which combines these basic loads aids in diagnosing operating and design problems. Standing and traveling valve actions tend to follow a fairly definite pattern during a normal pumping cycle. When abnormal pumping conditions occur, these valves may not conform to their respective normal patterns of opening and closing. A dynamometer is a useful instrument which can be used to record specific loads generated during the pumping cycle. Certain pumping equipment malfunctions can be diagnosed by interpreting dynamometer cards. Normal and abnormal valve action can also be detected using the principles associated with dynamometer card interpretation. There are many basic components which must be considered when designing or operating beam pumping equipment. These must be in harmony with each other to have a relatively trouble free pumping operation. When one of these components malfunctions or is changed, it may be necessary to change other parts of the system to maintain the desired relationship. Certain operating parameters can be established to promote optimum operating conditions. The use of dimensionless speeds, dimensionless loads and acceleration factors aids in determining the most trouble free portion of the beam pumping "operating window." It is equally important to operate the equipment with proper counterbalance. Over-pumping a well can aggravate an otherwise properly counterbalanced operation. In these situations it is necessary to bring the well outflow into a satisfactory relationship with the well inflow. Redesigning the producing equipment is one way to accomplish that objective. When changing the producing equipment might not be the practical thing to do, intermitting the pumping cycle is another often used and satisfactory method.

Care in handling either new or used tubing will result in fewer operational difficulties and less maintenance.

The care and maintenance of rod pumps may be considered under two categories; first, proper care, maintenance, and handling of the pump during its assembly, its delivery from the pump shop to the well and its installation in the well; and second, a careful analysis of the conditions of the well being pumped and operating the surface equipment to suit those conditions. We will discuss this subject of how we can prolong the life of pumps before the pump is installed and after it is run in the well.

The three phase squirrel cage induction electric motor built today is the most efficient electric motor that the industry has ever produced. It is the product of over one hundred years of evolution in materials and design of rotating electrical apparatus. Technology has allowed the manufacturer to reduce the physical size of the electric motor while increasing its efficiency. Concurrent with this reduction in frame size per horse power, we have experienced a product that is more sensitive to aberrant line, load and operating conditions than the more massively built product of previous generations. This paper will explore the conditions that compromise the electrical and mechanical life expectancy of the modern state-of-the-art electric motor. To illustrate the changes in NEMA frame sizes of electric motors, let us evaluate the evolution of a 5 HP 1800 RPM squirrel cage open drip motor over the last four decades. In 1950, this motor was in a 254 original NEMA frame and weighed approximately 195 lbs. With the NEMA redesign of 1952, this same 5 HP motor was condensed into a NEMA 215 frame and weighed 127 lbs. With the NEMA redesign of 1965, the 5 HP motor was further condensed to the smaller and current 184 frame weighing 88 lbs. The same 254 frame that was able to accommodate a 5 HP 4 pole motor in 1950, today accommodates a 15 HP 4 pole electric motor. The larger mass of the older apparatus represented a considerable heat sink for all the conditions that cause motor thermal failures. Consequently, the original NEMA and 1952 rerated motors were more forgiving of all the detrimental conditions that result in motor failures and particularly premature failure. The apparatus we use today is quite a different piece of equipment from that of yesteryear and a higher level of concern for its application and aberrant operational conditions must be considered if we are to maximize the design life and our return on capital investment. In order to preserve our investment in our rotating apparatus, it is incumbent that we understand the conditions that impact the electrical and mechanical life expectancy of the current vintage state-of-the-art electric motor. We will focus on five critical areas: 1.Electrical 2.Mechanical 3.Thermal 4.Environmental 5.Application

Although there are many different ways of artificially lifting oil from a well, the old beam type pumping unit is still by far the most popular means and probably the most reliable under all conditions. Most of these units are actuated by a gear reducer which is powered by some kind of prime mover. For years, the internal combustion engine was practically the only source of power. Recently, however, the electric motor is replacing engines to a large degree.

This paper discusses the common causes and effects of measurement error in LACT unit custody transfers. The discussion covers the major components of a LACT unit, and their effects on measurement accuracy. It also pinpoints how the neglect of each of these components causes the loss of millions of dollars to the oil industry through inaccurate measurement. Also discussed is how the failure to strictly observe API procedures, during the testing of the crude oil sample, can result in measurement error. Although these errors may be small percentage wise; when multiplied by monthly or yearly sales, the results can amount to a substantial dollar amount.

Schlumberger's Cement-Scan * log was offered to west Texas clients in June 1985. Since then, the product has greatly enhanced interpretation of cement conditions where standard cement evaluation techniques left unanswered questions. Specifically, the Cement-Scan log has provided superior answers in light (or foam) cements and in cements degraded by gas intrusion. The Cement-Scan log is a single presentation that combines information from both the CET* cement evaluation log and the CBL cement bond log. Through the use of a statistical gas logic system, Cement-Scan measurements can be used to discriminate between water channels and gas-cut cement behind the casing. Also, a new light-weight cement compressive strength algorithm is available for use when a known light or foam cement has been used in cementing operations. A cement map (from CET data) with shadings corresponding to acceptable cement, water channels, gas-cut cement, and free gas is presented. Additionally, a radial profile presents the four materials in terms of percent circumferential coverage of each. The above information is further enhanced by presenting a bond index curve and a Variable Density display from the CBL. The utility of the Cement-Scan log is illustrated by citing several examples from actual west Texas wells. Interpretation techniques, as well as gas logic verification, are described.

The oil and gas estate is the dominant estate, and the oil and gas lessee has the right to use so much of the leased premises and in such manner as reasonably necessary to comply with the terms of the lease and to produce the oil and gas. A landowner who seeks to recover money damages from the lease operator for damages to the surface or injury to animals has the burden of proving either specific acts of negligence or that more of the land was used than was reasonably necessary. It is not ordinarily contemplated, however, that the utility of the surface for agricultural purposes will be destroyed or substantially impaired. Further, there will be an accommodation of the conflicting interests of the surface owner and the mineral owner in deciding what limitations will be imposed upon the use of the surface by the operator. These conflicting statements of the law determining the rights of user of the surface have been recently made by the Supreme Court of Texas in the appeal of one case. They are well calculated to confound and confuse the lease operators and their supervisory landmen, production foremen, geologists and engineers. They illustrate the changes lately being made in this field of oil and gas law so important to the economy and well-being of the oil and gas industry.

A complete program of screening inhibitors, monitoring field results, corfehating lab results with the results from the Plate Bending Corrosion Fatigue Machine ' and defining service availability was initiated in the Ford Geraldine Unit CO2 Flood. The new downhole inhibition program has resulted in corrosion inhibitor treatment savings up to forty-five percent and a noticeable decline in corrosion related well servicing failures.

The corrosometer method for measuring corrosion involves insertion of a special probe into the corrosive environment to be studied, and following the progress of corrosion on the probe electrically by means of a special meter.

Over the past several years, numerous laws have been passed and regulations adopted directed toward protecting or improving the environment. Unfortunately, many of these laws and regulations were promulgated in an emotional atmosphere created by the outpourings of well meaning, but often ill-advised, consumer advocates and environmental activists. Branley Allen Branson, for example, in an article "Stripping the Appalachians" (Natural History, November 1974).

The design of a distribution system that will anchors, and crossarms can be used to keep the provide adequate and reliable service at a system in operation in destructive weather. The reasonable cost is becoming increasingly selection and coordination o f automatic protective important. The system should be engineered from equipment can reduce down-time and the loss of the source to the last motor, to provide an optimum production. Power factor and load factor are also a system that will not only serve the load adequately large part of the economical operation of the with minimum line losses but eliminate as many system. The selection of the proper protective sources of trouble as possible. equipment, such as lightning arresters and fused This paper will consider the factors that go into disconnects, is a necessary part of this system. such a system. The proper sizing of conductors to Formulas useful in the design of electrical eliminate excessive line losses can conserve distribution systems are show.

This paper presents a discussion of the merits of various treating systems with recommendations as to when and where they should be used. A series of composite graphs are included for sizing the various components of the systems.

The search for oil and gas has led to the exploration of deeper, hotter, and tighter formations. Producing zones which would have been considered non-commercial a few years ago are being stimulated to produce commercial quantities of hydrocarbons. This paper deals with the design of fracturing treatments in this type of reservoir.

Hydraulically induced fractures have been used to stimulate oil and gas wells for the past 25 years. Hassebroek and Waters" summarized the advancements in fracturing technology through the first 15 years. During this period, great strides were made in the understanding, engineering and mechanical aspects of hydraulic fracturing. In the last few years, interest in hydraulic fracturing has gained a renewed momentum. The combination of declining domestic reserves and increased prices for oil and gas has turned the petroleum industry's attention toward the recovery of hydrocarbons from tight reservoirs. In these low-permeability formations, hydraulic fracturing treatments are routinely performed upon initial completion. Successful stimulation depends upon creating a fracture, which can be propped for the desired length, using a fluid that does not substantially reduce the formation permeability next to the fracture. The selection of the fluid, therefore, is usually the key to designing a successful fracture treatment. One of the more recent innovations in fracturing technology is the use of foam as a fracturing fluid.2" Foam, which is a mixture of gaseous nitrogen, water and a surfactant, has been used for many years as a drilling and workover fluid. The properties of foam, such as low hydrostatic head, low water content and excellent suspension of solids, make it an ideal fluid for drilling into or working over low-pressure, water-sensitive reservoirs. These same properties led to the development of foam as a fracturing fluid. The viscosity of foam was investigated by Mitchell.7 His experimental findings confirmed the existing theories that foam flow could be predicted using single-phase flow theory. Blauer, et a1.8 extended Mitchell's work by investigating foam flow in oilfield-size tubulars. The results of their work have been successfully applied to the design of hundreds of stable foam fracturing treatments during the past two years. The properties of foam as a fracturing fluid have been well documented.2"3 In both Refs. 2 and 3, sections were included which discussed the design procedure for fracturing with foam. The purpose of this paper is to present a computerized approach to the engineering design of stable foam fracturing treatments. A computer program, which is available for industry use, has been written which calculates the behavior of the foam in the tubulars and the resulting fracture dimensions. The effects of specific changes in fracture treatment design can be easily analyzed, which allows the engineer to optimize the treatment design.

The effect of depressed oil and gas prices on investors' confidence has been reflected by the low activity levels in the Permian Basin as elsewhere. Yet, even during the 1986-87 period viable projects were available to the industrious and imaginative. One example is the Wentz (Clearfork) Field where a small independent operator recognized potential in what appeared to be a very marginal waterflood prospect. Through data gathering and engineering, the potential was documented to the point that investor funding became available. A cooperative waterflood plan was agreed to with the field's other operator. The project was installed with an emphasis on practicality, cost savings and attention to details. injection, production response is exceeding expectations

The Downhole Video Service provides a real time and on-site image of wellbore conditions in both the open and cased hole environments. In the open hole environment, the video service may 1) record images of hydrocarbon entry from the formation into the wellbore, 2) show the presence of natural fracture systems that intersect the wellbore and 3) reveal the placement of hydraulically induced fractures. Because of these features, the Downhole Video Service can be used for making pipe setting decisions and for optimizing the stimulation techniques.

The downhole video camera provides an on-site and real-time image of wellbore conditions in both the open and cased hole environments. In the cased hole environments the camera is utilized for such conventional applications as the following: -to inspect for the condition of the casing, -to view the presence of the various fluid phases, and -to determme the location and orientation of obstacles in the wellbore. In the open hole the applications have involved: the visualization of both natural and hydraulically induced fractures, and the identification and location of hydrocarbon entry into the wellbore where previously undetected by conventional wireline logging analysis. With these many features and benefits. the downhole video camera provides an expeditious solution to many problems encountered in the Permian Basin.

Since the perfection of a process for producing artificial or manufactured diamonds in 1955, attempts have been made to adapt their use for stone cutting. The original stones were commercially applied to manufacturing processes for grinding and polishing as they did not exhibit resistance to abrasion sufficient for stone cutting. Additional improvements in manufactured diamonds have resulted in a high enough abrasion resistance to utilize them in stone and masonry cutting applications. Drill bits utilizing natural diamonds have individual stones as the cutting element. Manufactured diamonds are of such a small size as to make the use of individual stones as cutters impractical. The introduction in the early 1970's of a polycrystalline aggregate of manufactured diamonds produced a cutting element that became practical for use in drill bits. Laboratory and field tests began on drill bits with P.D.C. cutting structures in 1973. Continual efforts have been made since that time to produce a drill bit that is economically feasible for use in petroleum drilling operations.

This paper presents what one pipeline company is doing in the automation of its operations in the West Texas gathering area and on its mainline systems. It will cover briefly the automation in its gathering system and a possible future operation. The mainline systems will be discussed covering the controls of both electric and gas operated pump stations and the telemetering equipment now used.