When an operator is faced with the prospect of fracture treating large pay intervals, several options exist. The most popular technique appears to be single stage limited entry, followed by multiple stages with bridge plugs or baffle rings. With the growing acceptance of 3-D fracture simulators the technique of cluster perforating has provided a third option. The 3-D models often suggest that large intervals can be effectively connected to the wellbore using a single propped fracture initiated from a relatively small perforated interval. This technique is often unpopular with operators who feel that each foot of net pay must be connected to the wellbore with a perforation. Perforating large intervals may lead to the creation of multiple fractures, though, especially when the wellbore or fracture is not vertical. . This can be counterproductive to maximizing fracture lengths, particularly when the design assumed- a single fracture. Field examples are provided to support the theory of multiple fractures and small interval perforating. A model is then presented to aid in the staging and perforation design process.

This paper will review how the current electronic tubing inspection equipment and interpretative techniques are being applied on field tubing inspection and electronic scanning jobs.

The primary function of a well service rig during the well maintenance process is to retrieve and run drill pipe, tubing, and/or sucker rods. Producers recognize that the proper assembly of these well components is critical to maximizing the time between maintenance jobs, and to maximizing profitability. Producer and contractor management alike, have the expectation that rig personnel can meet optimum torque requirements specified by manufacturers of these tubular goods. However, the equipment available to crews to accomplish their work has not significantly changed in decades. Generally, there is a minimal understanding at any level of the many affects that various rig components have on the assembly process. This paper will describe and illustrate some of the factors affecting the critical process of torque application to both shouldered and non-shouldered connections.

Lockheed Petroleum Services Ltd. offers an oil and gas production system that allows operators to locate much of the producing equipment on the ocean floor, out of sight and far removed from shipping and weather hazards. Oil and gas wells are drilled from a drillship or semisubmersible drilling rig, and submarine flow lines carry produced fluids to a nearby platform. With this system. a large oil or gas field can be developed without using multiple platforms, as one will serve " an entire field when subsea well completions are used.

A faster downstroke in a beam and sucker rod pumping system, traditionally considered unfavorable to the best production practices, may have some surprising, beneficial side effects not readily apparent to the casual observer. This particular kinematic characteristic may increase productivity in several ways; reduce peak rod and structural load and maximum rod stress; deliver more safe work to the bottomhole pump; and in some cases even decrease rod load range and soften the impact resulting from fluid and gas pound. The following discussion illuminates some aspects of this often misunderstood characteristic of reverse geometry units like the air balance and Mark II.

With the increased use of polysaccharides in fracturing treatments, subsequent problems have been encountered with inadequate polymer hydration, weak or over crosslinked fluid, formation of fish eyes, low viscosity and uncontrolled breakout. Problems have also occurred due to inadvertent contamination from water supplies and fracturing tanks. In field studies of the Lost Hills and South Belridge areas in Kern County, Calif., field conditions and operational procedures were found to constitute critical factors in successful dispersion and in ideal cross-linking of polysaccharides. A comparison of field fluids with laboratory fluids was conducted with special emphasis on the quality of field water and on the effects of pH and temperature on the viscosity and sand fall rate. Laboratory tests indicate that fluid mixed in the field can exhibit a more effective cross-linking structure, a more stable viscosity strength and a lower sand fall rate if more control is exercised in the determination of pH range, in the selection of buffers and in the choice of treating water. Attention to these factors, as pointed out in this paper, can reduce lost time, save expense and increase well performance.

A safe and effective biological paraffin control technology, based on the use of a mixed culture of naturally occurring bacteria, has been developed by Kiseki Inc. A research program was undertaken to determine the main mode of action of the microbial paraffin control technology. From the initial phase of this study, the results from field studies on 26 oil wells in Alberta are discussed in relation to the use of bacterial counts in the produced fluid as an indication of effective paraffin control downhole.

A presentation of a three year field study covering 225 pumping wells from depths of 400 to 8000 feet utilizing electrical and internal combustion prime movers. Operational and maintenance costs, motor controls, accessories, record and inspection programs for both methods are discussed.

The primary purpose of this paper is to present a field evaluation of paraffin problems and to show how they can be alleviated by using certain plastic flow lines and plastic coated tubing. In order to more fully examine the advantages and disadvantages of the various methods available, a paraffin cost study of Field A and Field B is presented.

Diverting methods have been developed and used extensively to distribute treating fluids in a zone or to divert them from one zone to another. Diverting may be accomplished mechanically or chemically. Mechanical diverting with perforation-sealing balls is a common procedure, but conditions may exist which make it ineffective. The height of the zone, number of perforations, limited pump rate, and capacity of the formation to take fluid are factors which may lower fluid velocity so that it is not adequate to seat the balls on the perforations. Communication between perforations or behind the casing, or perforations that are not round also may limit the effectiveness of ball sealers. for an impermeable gel diverting system was recognized. A gel diverting system, in order to be used as a diverter in acidizing treatments, has to meet the following criteria: the gel has to have a low viscosity during placement, hydrate to form a solid impermeable gel in the formation, revert with time to a liquid for removal, and leave a minimum of permeability damage. Packers also have provided effective mechanical diverting. However, they are more difficult to use because their effectiveness is dependent on accurately locating the zone to be treated and accurately setting the packer to isolate this zone. Numerous soluble particulated solids, which are often referred to as temporary bridging agents, have been developed for fluid diversion. These are solid chemicals that have varying physical and chemical properties. An agent can usually be selected that is satisfactory for a specific treating operation. These diverting agents usually are transported in a viscous carrier fluid and are pumped between stages of treating fluid. The effectiveness is dependent on the strength and permeability of the bridge formed. Some solid diverters have a wide particle size distribution and form low permeability bridges, but their permeability is not, low enough to effectively divert treating fluids to zones having a permeability less than about 2 md, and the need Various chemical types of gelling agents were evaluated in order to obtain a feasible gel diverting system. On the basis of the gelation time and stability tests, only two gelling agents appeared to meet the necessary criteria. One of these gelling agents was a high-residue natural gum and the other was a low-residue modified natural gum. A gel diverting system using the low-residue gum was finally selected since the diverting-efficiency and permeability-recovery tests showed that using the high-residue gum resulted in permeability damage. So, only the data using the low-residue gel system are presented in this paper, except in the diverting efficiency and permeability-recovery tests, in which case the data from tests using both the high and low residue gums are presented. The procedure used on a field job is presented, and the results are described.

The oil and gas regulatory data mapping portal was introduced to New Mexico in 2009. The purpose of the mapping portal was to help oil and gas operators, natural resource environmental managers, and other related sector professionals evaluate natural resources and man-made features within a subject area. While initially designed for the New Mexico Pit Rule, the data provided by the portal has proven to be useful for other applications and beyond the borders of New Mexico. The mapping portal has been expanded to include data for surrounding states. Mapped natural resources include, but not limited to: depth to water and ground water elevation from USGS gauging stations; topography; aerial photos, digital elevation models; surface geology; karsts; and surface water. In addition, the mapping portal includes spatial search capabilities that allow querying data to determine proximity of natural resources to a subject site. The mapping portal is available at http://saturn.nmt.edu.

Success and progress in our industry depend upon a coordinated system of integrated activities seeking, but not always maintaining, a balance between production and consumption. We must continue to advance in the technology of finding, producing, transporting and refining petroleum, and, as well, in the transformation of the raw materials into useful products through petrochemical processes. We recognize, therefore, that a good job much be done up and down the line.

Better design, study of operations and planned maintenance of subsurface equipment can often result in reduced lifting cost per barrel of oil. A suggested graphical history of pumping operations will be presented which acts as a graphical records help to readily illustrate problem wells and are also good guides for determining remedial action when necessary. Field cases using the graphical form and results of remedial work will be presented. Normal pulling cost and pump maintenance at various depths will be discussed to emphasize the large sums of depths will be discussed to emphasize the large sums of money that are being spent and the need of monthly systematic well records to determine if operational problems exist.

The "Ultrasonic Cement Analyzer" (UCA) is the name given a new generation device (Fig. 1) that continuously monitors strength development of oil well cement compositions. A single sample of cement slurry is placed in the instrument under pressure and heated to simulate downhole conditions. Measurements of the cement's ultrasonic velocity are started during the fluid state and continue through initial set to any desired point of partial or final strength development. Strength values are continuously computed and displayed until the test is terminated. The result is a complete and precise history of initial set and strength development which can be plotted versus time at any point of interest. The UCA functions with little operator attention aside from start up and shut down. The same information from standard API compressive strength crush tests would require curing a multitude of specimens to preselected test times, with no guarantee that the first test would be short enough or the final test long enough to accurately provide the critical information for the job. Since its introduction some two years ago, the principal advantage of the UCA has been simply to speed collection of reliable compressive strength data. For example, one technician with an eight-chamber UCA can produce more data than eight technicians and 64 separate curing autoclaves. In addition, human error and the opportunity for bias is greatly reduced with the UCA.

In the 1940's neutron logging was commercially developed as an alternate method of determining porosity. The ability to respond to formations behind casing foretold a great future. Unfortunately, however, the same principles which allow a neutron log to predict porosity as a function of the hydrogen index of a formation also produce many undesirable effects. The principles of operation of the compensated neutron log represent the culmination of technology intended to overcome these undesirable effects and to provide a usable tool in the search for petroleum products.

Low-temperature (50F to 100F) wells present a special problem for the application of fracturing technology using current highly viscous water-gels. As the gelling-agent concentration increases, the gel/s require more time to effect a complete breakdown of the gel. This tends to slow turn-around time after treatment and, in some cases, inhibits complete clean-up. Techniques have been developed to circumvent this problem, but they involve lowering the gelling-agent concentration. This has also resulted in lowering the proppant concentration and increasing the pump rate. Several studies have shown the importance of high total prop volumes in good stimulation treatments and the importance of controlling pump rate for good frac height control. Thus, stimulation treatment performance has not been as good as it might have been in higher gelling-agent concentrations; higher propping agent concentrations and lower pump rates could have been used. A new low-temperature breaker for water based gels has been developed that allows the controlled breaking of gelled fluids over a temperature range of 50_F to 100_F. Field results are available to show that this breaker is effective in low temperature wells. A summary of this data will be presented.

The objective of most all waterfloods is to inject water at rates as high as possible without fracturing the formation. Sometimes fractures of limited length are required to reach beyond near wellbore damage of an injection well. However, a fracture that grows to larger distances may drastically affect the volumetric sweep efficiency of a waterflood pattern. As waterflood projects mature, increasingly higher water rates are necessary to maintain oil rates. Increasing water injection rates may exceed the fracture gradient and start or extend a fracture. A pressure falloff test conducted on an injection well provides an estimate of the fracture half-length, but the orientation of the fracture cannot be distinguished. A trial and error procedure is shown to determine the fracture orientation and possible affect on the volumetric sweep efficiency on Levelland area waterfloods by using the fracture half-length from a falloff test and a reservoir simulation program.

Maintaining hole gauge has always been a drilling concern and problem. Historically gauge protection above the bit has been accomplished by using hard metals that offer good wear resistance. There are limitations to this method for actually sustaining a quality gauge hole. Other methods for accomplishing a gauge hole are mechanical devices placed in the drilling assembly, such as reamers. These tools also have limitations in directional applications and hostile environments. This paper will discuss the development of a tool that strategically places Synthetic Diamond Enhanced Inserts to accomplish both hole gauge protection and reaming. The performance of this tool will be economically evaluated with offset data for a direct comparison to the drilling curve and the benefit it derives.

In a well bore, the cement sheath is subjected to pressure changes from various well operations such as changes in the densities of displacement fluids, pressure testing, fracturing, and remedial operations. Failure of cement sheath in annulus due to pressure changes can lead to debonding from the formation or the casing causing microannulus formation, and/or produce cracks in the cement matrix thereby providing flow paths for fluids such as oil, water or gas. Such failures lead to expensive remedial operations in a producing well, or continuous monitoring in an abandoned well. Designing cement slurries which can withstand cyclic pressure changes helps allow for extended periods of trouble free operations. However, experimental techniques to measure failure resistance of set cement in an annulus to pressure changes are not available. This paper presents a method of testing cement compositions using well bore models with pipe-in-pipe configuration in which cement was circulated in the annulus, cured and subjected to cyclic pressure loads by pressuring and depressurizing the inner pipe. The failure of the cement was measured by the flow rates during pressurization and depressurization cycles of a fluid containing a dye through the cement column as a function of applied pressure. The method was applied to several low density cement formulations. The failure mode at the end of the tests was investigated by cutting the models into several segments and inspection of the cement under fluorescent light. Effects of experimental parameters such as temperature at the time of failure testing, annulus pressure, and slurry design were tested. The results and their implications in designing slurries for long term cement performance are discussed.

Several methods of calculating downhole dynamometer cards from surface dynamometer cards have been presented in the literature. Each of the methods requires knowing the viscous damping coefficient. This paper presents a non-iterative method for finding this term. A new method for calculating-a downhole dynamometer card is also presented. This method is faster and more accurate than the fourier analysis and the finite difference method using the second order damped wave equation. In Gibb's patent, two methods of determining the damping coefficient are presented. One is empirically based and the other is an equation that requires knowledge of the pump horsepower. But to calculate the pump horsepower the damping coefficient must be known. Therefore, an iterative procedure is required. This paper presents a non-iterative method for calculating the viscous damping coefficient. An improvement of the method presented by Everitt is suggested and comments on variable damping are made. A coupled set of first order linear differential equations is solved using finite differences to obtain a pump card. A cyclic boundary condition called the wrap around is used to eliminate problems associated with the end points. The wrap around condition eliminates iterating and allows for direct solution.

The vast majority of hydrogen sulfide monitoring systems historically use the solid state, semiconductor, metal oxide film type sensor. This type of H2S sensor has some inherent traits which manifest themselves in the field as application problems. Examples of these application problems include lack of repeatability (span drift), partial or total loss of response with removal of power, frequent and complicated calibration requirements, desensitization with exposure to moisture and the need to subject the sensors to H2S gas between calibrations to prevent them from "going to sleep". The following is an in-depth explanation as to how and why these problems occur along with the hows and whys behind a recommended solution.

Gas passage performance of gas lift valves under dynamic conditions has only been studied in the last twenty years. Proper assessment of gas injection rates at valve operating conditions requires the use of sophisticated measuring and control equipment only a few companies possess; and involves tedious and time-consuming data acquisition procedures. As a result, many gas lift installations are designed even today without properly accounting for the dynamic behavior of operating gas lift valves. The authors applied a novel approach to the description of gas lift valve performance and used Computational Fluid Dynamics (CFD) techniques to determine the valve's gas passage characteristics. CFD calculations provide a numerical solution of the governing equations (like the conservation of mass, energy, etc.) that can be written for a flowing fluid. To facilitate the simultaneous solution of the governing equations the flow space (the inside of the valve available for gas flow) must be divided into sufficiently small final volumes i.e. cells. Since the accuracy of flow modeling greatly depends on the proper setup of these cells the paper fully describes their proper spatial distribution. After the cell structure of the gas lift valve was properly set up, CFD calculations allowed the calculation of the gas volume passed by the valve for different combinations of valve stem travels, injection, and production pressures; i.e. for static conditions. In dynamic conditions, however, valve stem travel is a function of the net opening force developing on the tip of the valve stem. Since this force can be found by integrating the pressure distribution on the valve stem tip, an iterative procedure was developed to describe the valve behavior. The final result of the proposed iterative calculation model is the dynamic performance curve of the gas lift valve i.e. the injected gas rate vs. injection, production, and dome charge pressures. The procedure developed by the authors gives gas injections rates very close to those received from the universally-applied RP

This paper deals with a new method of obtaining injection and producing well permeability profiles. The flow meter and nuclear fluid density tools and their use in analyzing reservoir behavior will be explained. Numerous logs obtained from secondary recovery projects and in producing wells for fracture evaluation and remedial planning will be discussed.

The present energy situation has required the oil industry to evaluate all feasible methods to sustain and increase production in order to keep pace with our energy needs. 'Lost production due to scale deposition has been a major problem in the oil industry and has plugged many a good well while reducing production in most others. Many different scale inhibition techniques exist today and all have varying degrees of success. It is well known that the most effective and least expensive way to protect against scale deposition is during the initial completion of the well before the problem occurs. Most well completions today include hydraulic fracturing operation using an aqueous crosslinked fluid. These fluids, however, do not lend themselves to the use of scale inhibitors due to compatibility problems. This paper discusses the incompatibility of crosslinked gels with scale inhibitors along with experimental results. This paper attempts to solve the incompatibility problem by proposing three models to run scale inhibitors in conjunction with aqueous crosslinked stimulation fluids. The three models proposed are based on computer studies using a "partial pad" approach. All models have been described in detail and the results of the study have been graphically illustrated. The paper also briefly discusses the different types of oilfield scales, their formation, deposition and mechanism of inhibition.

Long open-hole or heavily perforated intervals with stringers of varying porosities and permeability have always been difficult stimulation problems. In the majority of instances treatments have been staged, continuously, with various types of blocking agents. Only after the job was complete, could any down-hole evaluation of the success of the diverting agents be estimated. Obviously, critical information such as the extent of the formation treated per stage, communicated zones, channeling behind the pipe, etc. was unavailable until after the treatment was over.