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.

There are many ways that sucker-rod systems can be improved. Performance and utilization of available equipment can be increased without the installation of larger units at greater costs. The use of rod guides is an inexpensive method for optimizing machinery already on the lease. This method keeps capital expenditures to a minimum and also reduces pulling costs up to 50 percent. Rod guides were originally designed to combat crooked-hole wear, but operators have been quick to find other money-saving uses for them.

This presentation is directed toward providing application guidelines for hydraulic pumping systems, in an effort to improve the performance of the system which in turn should make the system more acceptable to the operator. In the last 20 years the manufactures of down well hydraulic pumps have invested a great deal of time and money in research and development programs to improve both reciprocating and jet type products that they offer to the industry. However, the success or failure of the system depends largely on the equipment being properly applied as is the case with the application of any method of artificial lift. The presentation will deal with (1) When hydraulic systems can or should be considered. (2) What types of production units and surface equipment are available. (3) Where can the different production units be best applied. (4) How can the system be installed to maximize its performance. A summary of the information provided puts forth the contention that given equal consideration with other systems and being properly applied, hydraulic pumping systems is a viable selection for artificial lift equipment.

The North Concho Bluff Field produces from the upper Guadalupian tidal-flat sandstone play of the Queen Formation. Recently, the waterflood production from the field had decreased to a point where it was barely generating a positive cash flow. A reservoir simulation model was constructed in an attempt to improve earnings by identifying areas of potential oil bypassed during waterflooding. However, the spatial coverage of modem well log and core data within the field was inadequate in describing the reservoir for the simulator study. A better method of describing the reservoir heterogeneity was needed. A 3-D seismic volume, having a uniform density distribution of data, was interpreted across the field. The reservoir interval consisting of four elastic cycles, encased by evaporites produces a classic trough-over-peak seismic response. Seismic attribute mapping of a portion of the seismic volume was used to better define the reservoir characteristics within the inter-well region. Final seismic-guided average porosity and average permeability grid files were used as inputs into a single layer reservoir model. History matching using these grids was accomplished with only minor adjustments to the model, as compared to using well data alone. The model identified an additional potential recoverable reserve target in excess of 2 MMBO. A limited drilling program was initiated to verify the model, resulting in better than predicted production. Using seismic-guided reservoir properties improved the reservoir description for the simulator, allowing for a strategic drilling plan to be developed. The method presented advances the application of seismic-guided reservoir properties from reservoir description to operational reservoir management. Through strategic drilling, the North Conch0 Bluff Field had gone from a stage of potential divestiture to adding significant cash flow from a

This paper presents an improved sucker rod pumping design method similar to the API RP 11L but provides more accurate answers. The design is based on developing look-up tables or graphs for the desired unit geometry and pumping conditions by using a wave equation program. The wave equation and simulation techniques are used to mimic pumping conditions and calculate the loads and displacements. Such an approach makes it possible to compare, on a general basis, the different pumping geometries.

A solution now exists for problems attributable to gas interference in down-hole rod-pump assemblies. With the patented Solution Valve (SV), designed and manufactured by Eagle Advanced Oil Field Technologies, gas entering the pump chamber as either free gas or initially as dissolved gas, can be effectively displaced. Positioned on bottom of the conventional plunger, the SV performs in conjunction with conventional standing and travel valves such that the pump chamber is charged with fresh well bore fluids during each pump cycle. Gas locking cannot occur, because all fluids entering the pump are displaced on each stroke, thus eliminating the buildup of residual, high-pressure gas bubbles below the plunger or between the SV and an upper travel valve positioned atop the plunger. Improvement in fluid displacement efficiency, with resultant lowering of fluid levels in the tubing-casing annulus, can increase the production of oil and gas. With the SV it is not necessary for the pump to tag bottom in an attempt to mechanically jar balls off seats and thereby stimulate pump performance. Redistribution of fluids within the SV can often eliminate fluid-pounding topic. Consequently, rod-parts, rod-cut tubing, failures of valve-rods and valve-rod guides can often be eliminated. Unlike conventional pumps, down-hole debris such as particulate sand, silt, iron sulfide, etc., cannot prevent closing of the SV. Uninterrupted fluid flow through the pump, in conjunction with a constantly rotating seal surface between ball and seat, prevent the accumulation of stagnant fluids and associated settling of debris above and beneath the plunger. Another ideal application of the SV is in wells where gas cannot be vented up the tubing-casing annulus and where it becomes necessary to pump below a packer. By being able to pump gas as well as liquid, and thus invulnerable to gas locking, the SV functions quite satisfactorily. The permanently centered and stationary bail and movable seat of the SV are also well suited for applications in deviated and horizontal well bores where non-vertical orientations can delay ball seating. Similarly, for installations where heavy, viscous crude oils are pumped, the positive and instantaneous opening and closing of the SV eliminate inefficiencies due to ball floating.

Field results of limited entry treatment through pin point perforating and controlled injection rate in 201 wells are presented. A comparison with conventional treatments is made.