It is the purpose of this paper to (1) present a partial list of the types of data required and indicate their sources and applications and (2) to impress all personnel concerned with obtaining data that their work is extremely valuable since most calculations made by engineers and many decisions made by management are based on the reliability of their work.

Presents pumping unit geometrical and torque factors and how they are affected by direction of unit rotation. Permissible load calculations and diagrams are shown confirming conclusions.

Is the proper orientation of an orifice plate with a bevel important? The importance depends upon whether gas is being bought or sold. Volumetric gas rates were measured at two meter tube pressure levels using orifice plate bore sizes from l/2- through 1-l/4-inch in two 3-inch commercial meter tubes in series. The orifice plates were tested in the correct orientation with the sharp edge upstream and then reversed with the bevel upstream. The differences in the calculated gas rates for proper and improper orifice plate orientation are significant.

Through the drilling industry's efforts to drill faster and deeper has come the application of three types of mechanical separators for processing drilling muds-the fine-screen shaker, hydrocyclone separator and the decanting centrifuge. These mechanical separators are necessary in today's drilling to maintain both low and high-weight drilling muds economically. With proper application, installation and operation, these machines can help reduce overall drilling costs by improving penetration rate and reducing mud treating costs.

Proper consideration of all pertinent factors when designing a pump station, especially pump suction requirements, pays big dividends throughout the life of the project. Savings will be realized through increased pump efficiency and reduction of maintenance expense. This paper deals primarily with suction head requirements, suction and discharge piping and pulsation dampeners and is aimed particularly at reciprocating pumps; however, most of the engineering principles and practices described should be observed in the design of any pump installation.

A new and patented technology has recently been introduced to the petroleum industry that reduces the lifting cost per barrel of fluid by containing the abrasive particles that damage the rod pump. This technology is a stainless steel membrane (screen), with specifically tailored micron openings. The membrane is engineered specifically to the pump manufacturers tolerance between the plunger and barrel under operators field conditions. A durable down hole pump protector can now provide more pumping days between workover cycles. Although experts agree that abrasive sand particles (frac sand or sand from the reservoir) will damage the rod pump, there has been little consideration given to understanding the micron size of particles that actually do the damage. This new technology includes a reusable stainless steel down-hole tool that allows the pump to do its work over a planned predetermined period of time with minimum damage to the plunger and barrel. Stren Company developed this special down-hole tool with a specific micron opening (15 to 75) micron) for containing the abrasives particles before they enter the pump. This engineered tolerance between the membrane and pump has proved to be the most economical approach to maximizing the pumping days for each well.

A computerized system has been developed for acquisition, processing and analysis of acoustic data used to determine the distance to the liquid level in the casing annulus of a well. The system utilizes a gun-microphone assembly such as has been used in the past. However, the analog signals from the microphone are digitized by a high speed analog to digital converter and stored in a lap-top computer, allowing much greater versatility in signal processing and analysis. The computerized system processes the acoustic digital data to automatically identify the liquid level reflection pulse and counts the number of collar reflections to the liquid level signal. After acquiring the acoustic data, this system first determines the collar reflection signal rate or frequency. Then, the digital signal data between the initial pulse and the liquid level pulse are filtered with a narrowband filter centered at the collar reflection frequency, in order to improve the signal to noise ratio. Using this narrow-band filtering, the collar reflections can be distinguished much further down the wellbore. The program uses a cross-correlation technique to automatically count the number of collar reflections to the liquid level depth is calculated utilizing the number of collar reflections and the average tubing joint length. Digital filtering and signal processing allow the automatic interpretation of the level position in the majority of the field cases, even those where conventional analog recording and broad-band filtering were inadequate for accurate measurements. The system also provides additional processing techniques, under operator control, to obtain accurate results in those wells where conditions are very unfavorable: shallow liquid levels, gaseous liquid columns, noisy well bores, annular constrictions, etc. A number of field cases are presented to illustrate the primary application to optimization of pumping wells. The system also acquires the casing pressure, determines the casing pressure buildup rate, converts it to an equivalent annular gas flow rate and calculates the effective gradient of the gaseous liquid column in the annulus. The annular liquid level depth and casing pressure distribution determine the producing bottom- hole pressure which is combined with a well data base that contains the production rate, static reservoir pressure and other parameters used in the generation of a well performance analysis for the operator.

A computerized system has been developed for acquisition, processing and analysis of acoustic data used to determine the distance to the liquid level in the casing annulus of a well. The system utilizes a gun-micro hone assembly such as has been used in the past. However, the analog signals from the microphone are digitized by a high speed analog to digital converter and stored in a lap-top computer, allowing much greater versatility in signal processing and analysis. The computerized system processes the acoustic digital data to automatically identify the liquid level reflection pulse and counts the number of collar reflections to the liquid level signal. After acquiring the acoustic data, this system first determines the collar reflection signal rate or frequency. Then, the digital signal data between the initial pulse and the liquid level pulse are filtered with a narrowband filter centered at the collar reflection frequency, in order to improve the signal to noise ratio. Using this narrow-band filtering, the collar reflections can be distinguished much further down the wellbore. The program uses a cross-correlation technique to automatically count the number of collar reflections to the liquid level depth is calculated utilizing the number of collar reflections and the average tubing joint length. Digital filtering and signal processing allow the automatic interpretation of the level position in the majority of the field cases, even those where conventional analog recording and broad-band filtering were inadequate for accurate measurements. The system also provides additional processing techniques, under operator control, to obtain accurate results in those wells where conditions are very unfavorable: shallow liquid levels, gaseous liquid columns, noisy well bores, annular constrictions, etc. A number of field cases are presented to illustrate the primary application to optimization of pumping wells. The system also acquires the casing pressure, determines the casing pressurebuildup rate, converts it to an equivalent annular gas flow rate and calculates the effective gradient of the gaseous liquid column in the annulus. The annular liquid level depth and casing pressure distribution determine the producing bottom-hole pressure which is combined with a well data base that contains the production rate, static reservoir pressure and other parameters used in the generation of a well performance analysis for the operator.

A new acoustic instrument has been developed for measuring the distance to the liquid level in the casing annulus of a well. The instrument features modem analog/digital technology to acquire and record acoustic reflections on a strip chart. The dual channel instrument accents the liquid level on a low frequency channel. Collars are accented and recorded on a second channel using automatic gain control to ease the counting of the number of tubing collars from the surface to the liquid level. The collar amplifier/filter response can be selected to accent sharp upper collar reflections or to accent lower collars in a deep, low-pressure well. Another feature of this instrument is the use of an automatic mode for selection of gain on both channels. The instrument automatically acquires and processes acoustic noise data before generation of the acoustic pulse and preselects the proper gain. In the automatic mode, the operator must turn on the amplifier power and the chart drive. These are the only instrument functions required for most tests. The sensitivity controls are not adjusted by the operator unless special recording is desired. Analysis forms are printed on the strip for entry of liquid level depth, casing pressure and casing pressure buildup rate. Software is supplied for use with a separate computer to determine bottomhole pressures even in wells which have gaseous liquid columns. The operator inputs the proper well parameters into the software and the program calculates the producing bottomhole pressure, the formation producing rate efficiency and the maximum production capability of the well. The results of the software analysis are manually entered in an additional form printed on the strip chart which serves as a permanent record and analysis of the acoustic test. A microprocessor, clock and timing circuit records a time and date stamp on each record to ease bookkeeping. The time between tests can be determined from these time stamps. If the casing pressure is measured during each test, the casing pressure buildup rate can be determined which aids in the calculation of casing annulus gas flow rate and producing bottomhole pressures. Additionally, one second time marks are placed on the strip chart which aid in chart analysis and the calculation of the gas specific gravity. This new system improves the ability of the operator to determine an accurate liquid level depth and analyze the liquid level depth with casing pressure data to obtain the bottomhole pressure and perform a better well performance analysis.

Cement bonding to the formation and subsequent isolation of productive intervals from non-productive intervals are essential to achieve the optimum results in stimulation and production of oil and gas. This paper describes a number of factors which cause poor bonding to pipe and formation and which can contribute to poor zone isolation and therefore ineffective stimulation treatments. A cementing system is described which combines the advantages of expansive properties with the other desirable properties of conventional cementing systems. The expansive properties of this system help to overcome the factors which contribute to poor bonding.

Poor bond logs and high water production have plagued a certain development field. Introduction of a unique expansive admix has brought a dramatic switch from failure to success in this trouble area. This has resulted in good bond logs, reduced water production, and is expected to decrease future problems with casing corrosion. All components necessary for chemical expansion are included in the admix to make it more versatile than standard chemical expansion additives. Field results will be used to document the positive results achieved in this development field. Case histories will be given for a number of these wells as well as a discussion of cementing techniques used.

Two of the major factors affecting cement slurry performance are the concentration of additives and their distribution throughout the dry cement blend. Consisto-meter thickening time tests on one or two batches of the cement are used to monitor the cement blends. Studies conducted have proven that these tests do not necessarily reflect the uniformity or the correct concentration of additives in the blend. To improve the quality of the bulk blending of cement, researchers developed on-site methods to verify the additive concentrations of each batch blended for uniformity and accuracy. They also investigated the effects of the current dry blending procedures, transportation, and air blending on the distribution of such additives as retarders, fluid loss agents, weighting agents, and salts.

This work focuses on the testing of foamed cements which resulted in the determination of the relationship between compressive strength and acoustic impedance for foamed cements. Tests conducted on API standard cubes of varying composition and density indicated a significantly different trend for foamed cement as compared to standard cement slurries. Measurements of acoustic impedance and compressive strength led to the development of an improved algorithm for predicting compressive strength in foamed cements using PET logs. A point representing the acoustic impedance of water may be used as a calibration point to define compressive strength when cement composition changes. Experimental results and log examples show improved accuracy resulting from the use if the presented algorithm for compressive strength evaluations of foamed cements.

The increasing emphasis on enhanced oil recovery is producing the need for improved methods of monitoring and controlling the injection process. The economics of injection materials, personnel and equipment reinforce the requirement for efficient management of injection systems. The application of existing technology in combination with improved hardware and new developments provides the basis for a viable injection control system. The ability to meet the stringent requirements of field control is due in a large part to developments outside the oil industry. Future improvements and enhancement-3 to injection control and monitoring will be possible through the imaginative application of current and developing technology.

The theoretical efficiencies of slow, long pump strokes have been discussed for over 40 years, and at least ten companies have attempted to market some form of slow, long stroke pumping unit, being either mechanical, hydraulic, pneumatic, or a combination of these. These units have generally been unsuccessful due to rather complicated designs which often incorporated short life components or required considerably more maintenance than did beam type pumping units. Unique engineering and simplicity are the reasons for the success of this 100% mechanical slow, long stroke pumping unit. This unit will allow the operator to move a downhole pump through a slow, long stroke of 24 feet, resulting in better pump fillage, less fluid pounding, and more effective high volume or deep well production where rod stretch inefficiencies have formerly been greatly multiplied. By reducing rod stretch and requiring fewer pump cycles per barrel, this unit reduces downhole wear on pumps, sucker rods, and tubing, thus reducing downtime and increases life span of individual components. This slow, long stroke pumping unit features short torque arm drive element, hence smaller gear reducer, fewer reversals, near constant polished rod velocity, shock absorbing load belt, and direct counterweight connection. The unit's unique design avoids inefficient power demand peaks and allows the use of smaller prime movers. Results of studies comparing NEMA D motors in conventional units and slow, long stroke units will be shown. Studies comparing NEMA D and NEMA B motors operating a slow, long stroke unit are also included. This paper will discuss how higher surface equipment efficiencies and higher overall pumping efficiencies are obtained from this slow, long stroke pumping unit. This unique pumping unit extends the limits of sucker rod pumping to volumes and depths previously not possible with traditional sucker rod pumping.

This paper will discuss how higher surface equipment efficiencies and higher overall pumping efficiencies are obtained from this slow, long stroke pumping unit. This unique pumping unit extends the limits of sucker rod pumping to volumes and depths previously not possible with traditional sucker rod pumping.

Hundreds of wells have been tested using power measurement equipment, dynamometers and acoustic liquid level instruments. Many of these wells were operating at less than 30% efficiency. Often, the main cause of inefficient operations is an inefficient downhole gas separator. Inefficient gas separators can be identified by obtaining an acoustic liquid level test which indicates a high gaseous liquid column above the pump and the analysis of dynamometer data which indicates incomplete pump fillage. Periodic acoustic liquid level tests and dynamometer measurements should be performed to verify that the downhole gas separator is operating efficiently. Tapping bottom with the pump, running the pumping unit at excessive speed, operating the pumping unit for excessive periods of time, increasing the tubing pressure or increasing the casing pressure is not the proper procedure for correcting inefficient downhole gas separation. To correct inefficient downhole gas separation, the first attempt should be to set the pump below the fluid entry zone if feasible. This is the most efficient method of downhole gas separation. However, if the pump is set above the fluid entry zone, a gas separator should be used below the pump that offers an efficient gas/liquid separation chamber with low dip tube friction loss which results in complete pump fillage if sufficient liquid inflow into the wellbore is available. In this article, downhole gas separators are divided into two types that are very different. If the gas separator is placed below the fluid entry zone, a single dip tube type of gas separator should be used below the pump seating nipple. If the gas separator is placed in or above the fluid entry zone, a gas separator assembly should be used that consists of an outer barrel having ports at the top of the barrel with a dip tube extending from the pump inlet down into the outer barrel and opening below the ports. An operator should be able to tell whether a gas separator is being used above or below the formation after viewing the gas separator. They should be built differently. In this paper, the outer barrel of the gas separator to be used above the formation is called outer barrel. It is sometimes called a mud anchor. The inner tube is called a dip tube and it is sometimes called a gas anchor. Clegg discusses many types of gas separators and the principles of gas/liquid separation.

Recently, AI-K decided to update the technology in use to collect and analyze sucker rod load data. Data was being collected with Leuterts, Amerada Hess Corp. Portable Well Analyzer I (AHC PWA I) or AHC PWA II systems. Even though the Leuterts were easy to install, the data was difficult to analyze. The AHC PWA I is an older and obsolete digital dynamometer developed ten years ago. The AHC PWA II utilized load cells, but the electronics did not hold up. AI-K approached Echometer Co. to develop a portable well analyzer system, utilizing modified Leutert heads.

Analysis of conventional and pressure cores taken with stable foam from the San Andres formation within the Bennett Ranch Unit of the Wasson Field provides a better means of formation evaluation. The pressure core data were used to correct conventional core oil saturations to in situ conditions. This oil saturation adjustment method corroborates similar procedures cited in the literature. The pressure at the bit was controlled during the coring operation to minimize the possibility of core fluid saturation alteration. Nitrate was used as a tracer material and the nitrate analyses of the core waters confirmed the lack of filtrate invasion. Calculations of pressure at the bit obtained during foam coring operations provides an accurate method of measuring the vertical cross section of bottomhole pressures in a thick formation consisting of lithologies of variable quality. This procedure provides another means of evaluating the volumes and paths of the injection waters for estimating the quantity of oil that may be contacted during tertiary recovery operations.

Hydraulic fracturing as a well stimulation technique has been in widespread usage since its introduction to the oil industry in 1948. Lease oil was used predominantly as the fracturing fluid for the first decade. Technical advancement in developing surfactants, friction reducers, and effective gelling agents stimulated greater interest in water frac as early as 1958 and increased its popularity. Today approximately 60% of all fracturing jobs are performed with water-base fracturing fluids. During the past two years, the economic structure of the oil industry has dictated that close attention be given to development costs. Again, lease oil comes to the forefront; it offers the advantage of being economical, provides for rapid clean-up of the well, is compatible with well fluids, and will not damage formation due to clay swelling. New technical developments in gelling or complexing oil-based fracturing fluids strengthen the choice of operators, as evidenced in the strong comeback of oil-based fluids, Some of these new technical advances offer the following: 1. Friction reduction of oil equal to or better than that of gelled water 2. High viscosity for wider fractures 3. Deeper placement of proppants 4. Ample viscosity to carry larger mesh and high concentrations of proppants. TWO of the newest concepts in oil-base hydraulic fracturing technique are offered to the oil industry in the following systems: 1. ALLO-FRAC 2. .OILBASE ULTRA FRAC (OBUF)

The purpose of this paper is to explain what load factor is, show how it will affect the power bill, and provide a few ideas on how to improve the load factor. Also, rates will be discussed briefly. The rates used here are Southwestern Public Service Company's rates; however, the principles will apply to most other power companies. Available rates and a basis for selecting the most favorable rate will be provided.

One of the problems encountered in stimulating low pressure and/or low permeability sandstone reservoirs is recovery of the treatment fluid. Some wells have low bottomhole pressures and in many cases these pressures are so low as to give little or no aid in treatment load recovery. Reservoir permeability is determined by the relative number and size of pores as well as by the size and continuity of the pore intersections. Permeability is unique to a particular reservoir and cannot be altered by stimulation. Sandstone pores often contain water, creating capillary pressure which effectively prevents or restricts the passage of fluids. The interaction of aqueous based stimulation fluids and low pressure and/or low permeability reservoirs often results in less than desirable recovery of treatment fluids. A new surfactant technology has been developed to improve load recovery percentages.

Beam pumping units have been the principal means of artificial lift in the oil field for many years. In recent times, stimulation in secondary recovery projects and encroaching water in water-drive reservoirs have made it necessary to lift more fluid than ever before. There have been several improvements in beam pumping equipment, causing it to remain the best method of artificial lift in most of our wells. A few of these improvements are unique pumping unit geometry, high-slip motors, rolled sucker-rod threads, and sprayed metal couplings. In several heavily loaded wells, Union Oil Company noted a large percentage of rod failures occurring in the lower section of the tapered rod strings. This triggered an evaluation of the current methods of tapered rod string design to see if improvements could be made in this area.

Most of the improved, or enhanced, oil recovery methods in use today are described in this paper. It is designed to provide definitions of the terminology used in the literature for describing various types of recovery processes and to provide an overview of each process. The general areas covered are thermal methods, chemical flooding, miscible gas drives, and improved water flooding using polymers.

This paper describes experiences with a new water-base drilling mud system that has been utilized in diverse geographic locations, formation lithologies, and environments such as temperature, density, salinity and total hardness. In addition to providing versatility in wide-ranging conditions, the original goals of the development were to create an easy-to-engineer mud system that would produce good hole stability and improve rates of penetration with the use of either conventional or polycrystalline diamond composition (PDC) bits. Background of the technical development of the system will be presented, and case histories from wells where the system has been applied will be documented. It has been observed in the field that this new drilling fluid has achieved the desired increased rates of penetration with both conventional and PDC bits. This has been accomplished while maintaining good hole stability and fluid properties in even harsh chemical and thermal environments. The system's enhanced performance features and explanations for them are discussed.