In this paper, an attempt is made to present, from a practical standpoint, factors which should be considered in selecting subsurface pumps. Emphasis is given to rod-actuated equipment with discussions on special application pumps and the uses of exotic materials. Some time is spent on conditions which would dictate the use of hydraulic and submergible systems.

Experience developed in the Midcontinent Division of Exxon Co., U.S.A. indicates that well corrosion problems in rod pumped wells are directly related to the water cut of produced fluids. In general, severe corrosion problems as measured by excessive rod, pump and tubing failures, are predominant in wells that produce in excess of 30% water. Further, embrittlement and pitting resulting in reduced rod life and fatigue failures are accelerated by the presence of hydrogen sulfide in the produced fluids. Corrosion in rod pumped wells is controlled by maintaining an inhibitor film on all wellbore equipment exposed to produced fluids. The film can be formed and maintained as a well is produced by maintaining an adequate concentration of inhibitor in the produced fluids. The film can also be created by a short contact time with fluids containing a high inhibitor concentration. The film thus formed can be allowed to dissipate using frequent retreatment to maintain protection. Four methods are used to treat rod pumped wells with corrosion inhibitors: squeeze, batch flush. continuous injection, and circulation. The labor and material costs, investment, and treatment effectiveness vary with well characteristics for each method. The purpose of this paper is to present information for selecting the "best" corrosion inhibition technique for a given set of well conditions. "Best" method is defined as the most economical when both well servicing costs and corrosion inhibition expense are considered. This paper also presents formulas and guidelines for design of an effective treatment once the appropriate inhibition technique has been selected. The information presented is grouped in three main sections: (I) Selection of treatment methods; (2) Treatment design; and (3) Application of automatic chemical injectors.

The intent of this paper is to cover various types of oil field engines, their advantages and disadvantages, their rating, equipment that is available, installation features, and preventative maintenance, in order that proper selection of the prime mover may be obtained. The proper selection of a prime mover involves many factors other than the make and size of engine required. Too often only these factors are considered.

The selection of lubricated plug valves in the production field has been handled rather loosely over the years

This paper presents some stimulating ideas and thoughts on self-analysis and its effect on self improvement and self development.

The use of various separator designs, internals, and/or internal configurations can significantly enhance separation. The use of centrifugal inlet devices, in some cases, has been shown to increase vessel throughput up to eight hundred percent. Also, internal baffling and various coalescing media, including matrix plate coalescing sections and serpentine vanes, can improve the separator efficiency by eliminating short-circuiting and reducing foam. Inlet devices and vessel intemals are often used in retrofit applications to de-bottleneck facilities or simply improve performance using existing equipment. Furthermore, centrifugal separation may be utilized in vertical recycling separators and horizontal, in line recycling separators. These separators utilize tangential inlets or fixed vanes to generate centrifugal force and push the heavier liquid droplets to the vessel wall, scrubbing the gas. These technologies can be used as either

Cement plugs are one of the most important types of cement jobs ever performed. Therefore, they deserve the very best effort we can give to a problem. A successful plug job requires more attention to detail than most other cement jobs; the reason most of them fail is because they do not get this attention. The following guidelines will not guarantee success but they will provide a higher ratio of successes if used every time! Plugs need properties different from most other cement systems because they are intended for a different application entirely. Failure of cement plugs is most often due to a lack of hardness in the set cement. This lack of hardness usually can be traced to one or more of these common mistakes: 1. Mud contamination of the cement during placement 2. Drilling out too soon 3. Cement not initially designed for enough strength 4. Strong tendency of all people involved to want extra pumping time, so slurry is overretarded 5. Inaccurate BHT information - well is colder than expected because circulation effect isn"t considered and temperature is guessed rather than measured 6. Not enough cement volume used. Proper planning can eliminate these errors. Do all possible to eliminate these problems.

Successful primary cementing of shale completions requires slurry design considerations that conventional cementing operations typically do not consider. The unique petrophysical and geological properties of shale must be factored into the design along with future stimulation plans to provide zonal isolation and casing support. This paper focuses on shale wells cemented in the Arkoma Basin. Cement slurry design is a critical part of any successful cementing operation. This is particularly true for shale wells where the unique nature of shale and its completion methodologies put additional demands on the cement. Slurry design considerations and successful slurry formulations for the area will be discussed along with an overview of primary cementing practices. Operational considerations as they apply to cementing vertical and horizontal shale wells in the study area will be discussed. Conclusions and recommended practices for optimum results will also be presented.

Fluid inertia forces can be large enough to be considered in sucker rod simulators. Fluid inertia forces are larger with shallow wells, large pumps, high stroke rates, and/or lower compressibilities. Texas A&M U has developed a fluid inertia model. This paper covers the primary assumptions, the equations, the boundary conditions, the initial conditions, a parameter study based on field data, the solution method, the discretized equations, the pump position, and the calculation sequence.

This paper presents a simplified fast means of determining synchronous and non-synchronous pumping speeds for tapered as well as straight strings based on the Sloneger formulas but using up-dated constants. Fast means of calculating API maximum allowable loads are presented. Other formulas are also given.

Short-cycle rod pumping, as accomplished by a pumpoff controller or percentage timer, offers several benefits over conventional program timer pumping. Field results show that 1-power savings are realized by reducing both the kilowatt-hour consumption and kilowatt demand, 2- the pumping unit may be properly counterbalanced and the pump spaced under dynamic conditions to realize maximum pumping efficiency and minimize gas interference, and 3- by stabilizing the individual well production, the lease production may be monitored at the battery.

Shot peening has been utilized for many years in a variety of industries as a surface conditioning process for metals. When properly performed, shot peening imparts beneficial residual compression stresses to the surface and subsurface of a metal which enhances the fatigue resistance and corrosion tolerance properties. Shot peening is primarily used on components that operate in cyclic loading environments. Since sucker rods are subjected to alternating loads, shot peening should prove to be a viable method of retarding the effects of cyclic fatigue, thereby extending the service life of the rod. This paper will encompass: the shot peening method, effects, control, and benefits, shot peening vs. shot cleaning, residual stress measurement test results, high cycle rotational bending fatigue test results, testing of peened vs. non-peened new sucker rods, testing of shot peened vs. shot cleaned used rods, and testing of single peened vs. dual peened new rods to compare different peening processes and formulae.

Commodities are defined relative to their application. There are dictionary definitions of the word commodity. There also are definitions of commodities related to the specific good or service that is being considered or traded on one of the many financial boards in the world. For these commodities, there is a "benchmark" that has been defined, standardized, and accepted for base price determination. However, there are multipliers that are used to differentiate the products that exceed or do not meet the benchmark requirements. This paper will discuss commodities and related benchmarks along with providing information related to the API Specification 11B and its requirements for standard sucker rods and couplings. Additionally, specific requirements in the standard are highlighted that provide quality and performance expectations but show dependency on the manufacturers" internal controls or procedures. Also discussed is that the oil and gas industry have not developed a benchmark for sucker rods and couplings (as well as many "standard" products) since each manufacture does not us
the same, standard processes and procedures. Thus, procurement/purchasing organizations should consider all the manufacturing processes and procedures to compare the equipment produced and not try to compare these products on price alone.

In the beginning we had an oil well! It was way out in the country where, at that time, therewas no paved road - only muddy roads and muddy locations or hot dusty roads and hot dustylocations. To a city dude, either was repulsive."At that time most thought that after a well was drilled and production hit the tank, that was theimportant thing and the only thing to do now wasto sell the oil. The only trouble was that all wells were not that good and some had to be pumped.Then they found that even though the oil was therein the ground it was difficult to produce enough to pay all the debts.

A new approach to pumping multiple completion oil wells with minimum surface equipment is by the use of a Siamese Dual pumping unit. Torque factor analysis, unit operation, and economic factors will be discussed.

Sidetracking systems, and more specifically whipstock technology, have evolved to the point where only one trip is required to accomplish the casing exit. However, most of these systems have been deployed in simple applications, where the formation outside the casing is relatively soft. More difficult applications, such as those where harder formations must be entered during the casing exit operation, have been bypassed, additional trips planned, or alternate cutting structures utilized to complete the operation. These contingent plans for sidetracking in harder and/or formations are often economically prohibitive in additional equipment and time. This paper will discuss the application, operation, and case histories of an alternate cutting structure used in window cutting where hard formations exist. It will also cover the economic benefit derived by using this special cutting structure opposed to past methods.

Silica fume is a pozzolanic material composed of extremely fine, amorphous spheres produced as a by-product in the manufacture of silicon metals. It has a high water demand and is more reactive than natural pozzolan or fly ash. When added to cement it makes an excellent extender and produces significant increases in compressive strengths. This paper examines the compressive strengths of low density slurries made with different blends of Portland cement, fly ash, and silica fume. Both Class C and Class H slurries, mixed at 11.5 ppg to 13.0 ppg, and cured at temperatures ranging from 80 to 170 degrees F were tested. These compressive strengths are compared with the strengths of conventional slurries extended with anhydrous sodium metasilicate or bentonite to the same density. The results show that silica fume is beneficial as a strength enhancer at low densities over a range of temperatures

The relative importance of certain data in the design of waterfloods and the effects of varying the more important factors influencing water flood recovery are discussed.

Charts are presented that simplify the design of intermittent gas lift installations for different surface control methods. These are: 1- 100% choke control at the surface. 2- Combination choke control and intermitter control at the surface. 3- 100% intermitter control at the surface.

This paper presents simplified methods of relating the following terms commonly used by the petroleum engineer in evaluating wellbore problem conditions of damage and of stimulation: 1. Well productivity 2. van Everdingen's skin factor, s 3. Permeability change-radial extent of change Mathematical relationships between these concepts were originally defined and applied by Muskat, l van Everdingen,2 Matthews and Russell," Hawkins,4 and Grubb and Martin.5 Since a well is generally considered to drain a reservoir by radial-type flow, each of the equations involve logarithms, and the usual graphical plots yield exponential-type curves which are difficult to extrapolate or to interpolate for intermediate values of interest. Straight-line forms of the three equations relating (1) well productivity, (2) van Everdingen's skin factor, s, and (3) permeability change-radial extent of change-were obtained by rearranging and regrouping of terms in the original equations. The straight-line graph of each equation is also presented in Figs. 1, 2 and 3. The practicing engineer and others interested in interpreting well production problems will find that the straight-line graphical representation is more accurately extrapolated and interpolated for intermediate values and also is considerably more easily drawn than the typical exponential curves usually given, for the relationships presented here. These should greatly assist the operations engineer in planning and designing completion, workover and stimulation procedures.

In order to select a compressor, or calculate the performance of a compressor, certain design criteria must be known. This criteria is listed below: 1. Gas analysis. A gas analysis is preferred, but if one is not available, then the specific gravity or molecular weight, n value, critical pressure and critical temperature of the gas can be used. 2. Capacity. This is generally given in either MSCFD or MMSCFD (Thousand Standard Cubic Feet Per Day or Million Standard Cubic Feet Per Day) at a given base pressure and temperature. (Example: 14.65 PSIA & 60_F). 3. Inlet temperature. At the compressor inlet. 4. Inlet pressure. At the compressor inlet. 5. Discharge pressure. At the compressor outlet. 6. Elevation. At the compressor location. Assuming values for the above design criteria, calculations can be made to either select a compressor, or calculate the performance of an existing compressor.

During the past few years a new method of checking the production of oil wells has been developed. This method is based on intermittent sampling and can be accomplished in two ways; by taking samples by hand from the bleeder at such times as are dictated by a watt demand meter, or by use of a mechanical device which will take a sample at equal intervals. In each method the production is obtained through analysis of the samples taken. Although the two methods are somewhat different, they do have this common characteristic

Texaco has been operating a CO2 flood in the Sundown Slaughter Unit in Hockley County, Texas since January of 1994.
The CO: flood was originally justified by analogy with an adjacent CO2 flood. A CO2 flood simulation was later done to predict and optimize the performance of the flood. With actual production data from the CO2 flood available, the simulation forecast was redone and updated. Specific objectives of this new, revised simulation study were to use geostatistical reservoir characterization to improve the representation of reservoir heterogeneity and to use more representative relative permeability curves and residual saturation values. A team was formed for the new simulation study which included both geologists and engineers with members both from the operating division and Texaco's research organization. Four new geostatistical reservoir models were developed, each with a
different level of effective heterogeneity. The basic idea was to adjust the reservoir characterization to improve the CO2 flood match and forecast. All the new models as well as the old model could be used to match the waterflood history equally well with moderate adjustments in the water-oil relative permeability curves. The correct level of reservoir heterogeneity was not needed to do a waterflood match. However, all the models were not equally valid in matching and predicting CO2 flood performance. The predicted CO2 flood performance was substantially different for these models and indicates that a good waterflood history match is not sufficient for a good CO2 flood prediction.
The reservoir heterogeneity in a model must be substantially correct for a successful CO2 flood match. Adjusting the gas relative permeability curve for a CO2 flood history match can compensate for moderate, but not large, errors in the reservoir heterogeneity. This paper describes the methods used for conducting the waterflood and CO2 flood history matches, for making the CO2 flood forecast, and for evaluating the different geostatistical realizations. In addition, the important sensitivities of a tertiary CO2 flood forecast to the reservoir description and the gas relative permeability are discussed and quantified.

The Pipe Inspection - Pipe Evaluation Logging System or P.I.P.E. Log is a valuable aid in determining casing deterioration due to wear and/or corrosion. The P.I.P.E. system combines a multi-finger mechanical caliper and an electromagnetic casing evaluation/caliper tool that are run simultaneously in the casing. Run in combination, the two systems complement each other in detecting single string casing corrosion.

The constant search for methods to increase the efficiency of production systems and to reduce operating costs has led to the development of a wire line tool which makes it possible to produce and control two separate reservoirs through a single string of tubing. This paper is a progress report of the experience that one company has, with this tool, gained in eight of its dually completed wells in Louisiana and Texas. Field tests have clearly demonstrated that this device can be used to maintain separation of production from two reservoirs, to control and determine the rate of production from each, and to change the rate of production as required. The advantages in simultaneous, one string multiple completions are enumerated, and various applications of the method are discussed.