Vogel's inflow performance relationship relates the flowing well pressure to production rate for solution-gas drive reservoirs. Because two-phase flow exists, the graph of bottom-hole flowing pressures versus oil production rate results in a curved line. This trend accounts for the decrease in production as more gas comes out of the solution. Vogel assumes the initial reservoir pressure is the same as the bubble point pressure for the starting point of the IPR curve. This implies no gas has initially come out of the solution, i.e. the reservoir is at bubble point pressure. Saturated reservoirs, as studied in this paper, are initially under-saturated reservoirs with average reservoir pressure below the bubble point pressure. Traditionally, Vogel's inflow performance relationship has been applied to these reservoirs using the reservoir pressure as the starting point for the curve. However, due to the presence of gas at the reservoir pressure, this is not an accurate assumption. This paper modifies the Vogel IPR curve for use in wells within reservoirs that are below the bubble point pressure.

Over a number of years, the reference tool developed by Grant, White, Smith & Miller" and commonly referred to as "White's Injection Scale" has been widely accepted as a useful mechanism for planning and execution of cement squeeze processes in shallow and low pressure formations worldwide. In early 2001, refinements to the injection scale were developed that focused on applying many of the same concepts to two Permian Basin peculiarities: 1) The nearly exclusive usage of API Class C cement in squeeze operations shallower than 10,000 feet, and, 2) the high incidence of fracture gradients so excessively low that a full column of nearly any liquid is not supportable by the formation being squeezed. The modified injection scale is presented and explained. Incremental improvements provided by the modified scale are examined, and application case histories are described.

In rod pumping wells, the downhole data can be computed from the surface data by solving the one dimensional damped wave equation. Currently, the modified Everitt-Jennings method uses finite differences and an iteration on the damping factor to solve the one dimensional damped wave equation. The iteration on the damping factor allows for an automatic damping factor adjustment, which can be a valuable tool when dealing with large fields of wells. The damping factor pertaining to this method is a common damping factor for both the upstroke and downstroke. In this paper, a new iteration on the damping factor is presented, in which the algorithm is split such that the upstroke and the downstroke damping factors are refined separately. Results are presented.

Currently, API specs on 7/8" couplings allow for a wide variation in coupling face widths. The face width is critical when trying to achieve good rod makeup. For example, a larger face width is less likely to rotate due to the larger surface area i.e. more friction. As a result of the high number of rod pin-coupling failures, especially in the 718" section, a coupling with a more effective face width was developed.

Fiberglass sucker rods have proven to be an economical solution to many sucker rod beam pumping problems. Two important parameters that contribute to the effectiveness of FRP sucker rods are effective modulus of elasticity and fatigue life. Using established computer predictive techniques, it has been shown that FRP sucker rod installations can benefit from using rod designs with a lower modulus of elasticity. Fatigue life of sucker rods is an important consideration for any sucker rod pumped oil well, for both steel and fiberglass rods. Fatigue life predicitons for steel sucker rods can be routinely determined from API publications and recommendations. Fiberglass sucker rod fatigue life predictions are determined from guidelines supplied by FRP sucker rod manufacturers. The fatigue life of fiberglass sucker rods cannot be reliably predicted using methods developed for predicting steel sucker rod fatigue life due to the difference in fatigue behavior of the two materials. Therefore, test programs have been developed to generate reliable fatigue life guidelines for field applications.

With changing industry drivers, current petroleum industry needs and emphasis are on developing shorter, less costly, and environmentally-friendly well testing procedures. Several techniques have been presented to address this need. Although these vary in procedure and method of analysis, all rely on basic principles of fluid flow through porous media. In this paper, comprehensive evaluation of general closed-chamber tests, including general surge tests, and comparison with special tests such as impulse and slug tests will be provided. For each technique, the review will examine: - Hardware requirement, test design, testing procedure - Theoretical background - Method of data analysis. Similar techniques are compared using computer-simulated examples to determine expected degree of accuracy compared to conventional testing, with a significant portion devoted to field examples that show techniques to analyze the well-testing data from surge testing, closed-chamber DST, slug testing of oil wells, under balanced perforating and testing, and back-surge perforation cleaning.

Money saving ideas can be initiated by the analytical study of a dynamometer card obtained from a pumping well. This is illustrated by presenting methods of calculating polish rod horsepower, peak torque, and volumetric efficiency from typical dynamometer cards obtained from wells in West Texas and New Mexico. A brief discussion of the basic fundamentals of a dynamometer card in relation to the pumping cycle is presented and followed by the analysis of cards that have resulted in money saved. This analytical approach can be utilized to reduce the lifting cost per barrel of oil by applying it to three major problems. These are: (1) the initial design of a pumping installation, (2) modification of pumping conditions, hence, eliminating the expense of equipment changes, and (3) improving the efficiency of present pumping equipment. In essence the dynamometer card can be used to ascertain the optimum pumping conditions for any pumping well.

When the money requirements for drilling and production for the petroleum industry are considered, the sums involved are indeed staggering. According to information compiled by a joint effort of the American Petroleum Institute, The Independent Petroleum Association of America and the Mid-Continent Oil and Gas Association, the average cost per well in 1953, including drilling, casing, tubing, and well head connections, but not including tanks, flow lines, separators, treaters or other surface equipment, was approximately $78,700 for wells drilled in the Texas portion of the Permian Basin. The average depth of wells in this area in 1953 was 5,400 feet. Since costs in general and also average depths have gone up since 1953, it seems reasonable to assume that the actual average cost per well at present is probably close to $90,000.

Pump off controllers have earned a place in the technology of rod pumping. Many methods exist for sensing when a well has pumped off. Most widely used are techniques based on the surface dynamometer card or motor speed or production rate. This paper describes several methods for sensing pump off using the downhole pump dynamometer card. These include areas inside of the pump card, areas outside of the pump card, set point and liquid fillage, among others. Procedures for calibrating the controllers are described together with provisions for high fluid level recovery. Combining the liquid fillage method with variable frequency drives and eddy current drives is presented as a way of performing variable speed - no stop control. Pump card monitors (PCMs) hold promise of being useful devices which are easy to apply and comprehend.

Computer programs are being developed to identify wells that are not responding to the current chemical corrosion control program. Computer corrosion monitoring programs are a method to quickly and effectively process large volumes of data that are necessary to document changes in well conditions and chemical inhibitor programs. Decision support software is also being used to competently select corrosion inhibitors by correlating existing system parameters with a data base of inhibitors and their associated characteristics. Computer programs have been developed to select treatment program inhibitors based on the particular corrosion problems and well characteristics identified at a given well site. Through the use of these computer programs, an operator can implement a customized treatment program that is continually monitoring itself for optimum performance and cost savings.

The monitoring of injection, disposal, and produced waters involves complex preparation, studies, evaluations, and interpretations. This paper presents the objectives and requirements of an effective monitoring program. Those aspects of monitoring that most frequently result in misleading data are covered and the means to prevent such data and misinterpretations that are drawn there from. The presentation is made of over 50 categories of conditions that deserve careful observation and consideration in a continuous monitoring program.

Because of the susceptibility of the Morrow Sandstone formation to fluid damage, improved completion techniques have been demanded by industry. A new look at old ideas has resulted in the development of unique procedures especially adapted to well completions in sensitive dry-gas sandstone reservoirs. In this paper is presented a historical account of the development of completion practices in Morrow wells located chiefly in Eddy and Lea Counties, New Mexico. Special emphasis is given to the Tubing Conveyed and the Maximum Differential techniques developed by Vann Tool Company.

This paper discusses behavior and motivation patterns in the development of management personnel. The working relationships existing between managers and their subordinates is also presented. The need for individual recognition and mutual trust and appreciation is stressed.

A power/current transducer for measuring both power and apparent current permits an operator to obtain a more complete analysis of the performance of a motor powered pumping unit system. Power and apparent current are acquired and displayed during a single stroke to aid in the analysis of pumping unit efficiency, cost of electricity, proper balance and torque. Power measurement, for induction motors, showing both consumption and generation are much easier to analyze than apparent current data from a conventional clamp-on amp meter which does not distinguish between consumption and generation. Power transducers require the measurement of current in two legs of a 3-phase system. In addition, voltage probes must be attached to each of the three phases. The phase relationship between the current and voltage is processed electronically to obtain a voltage signal proportional to power. This signal is digitized at a rate of 20 times per second and displayed as a plot of power per single pumping unit stroke. Apparent current is also obtained and plotted for additional analysis. The power data is easily processed to obtain gearbox torque without the need for pumping unit geometry nor polished rod loads. Field data are given for examples of motor performance including cost of electricity with and without generation credit, an under balanced unit, an overbalanced unit, an under loaded motor and other conditions.

An increasingly energy conscious world is seeking not only alternate energy sources but also more efficient methods of production. The drive for energy independence has created an atmosphere conductive to innovations in oil recovery. Enhanced oil recovery methods, such as water flooding, chemical treatment, and steam injection are being used to increase the production of low yield wells, which were considered
non-profitable years ago. Along with new enhanced oil recovery methods is a new and innovative artificial lift method. The Moyno Downhole progressing cavity pump has been sucessfully applied to downhole pumping applications. The pump has only one moving part, the rotor, which attaches to and is driven by the sucker rod string, while the mating stationary part, the stator, is attached to the production tubing string. The rotor is a singleT;ireaded helical gear with a circular cross section and an off set or eccentricity. stator is a double threaded internal helical gear which has a diameter equal to the rotor, but an eccentricity and pitch twice of the rotor. When the rotor and stator are meshed together, a series of sealed cavities, 180" apart, are formed, that progress from suction to discharge as the single helix rotates. The result is a pulsationless positive displacement flow. This unique progressing cavity feature enables the pump to handle high gas-oil ratio crudes without gas locking. Due to inherent low internal velocities heavy crudes of high viscosity can be easily handled. An abrasion resistant elastomer stator and plated rotor offer long life in sand laden crudes. The rotary design lends itself to low profile surface equipment allowing better utilization of the land for agriculture. These futures give the production engineer another alternative method for artificial lift,

The Multi-Phase pump was designed in 1998 to attempt to pump wells that exhibited very foamy, compressible fluid mixtures which are inherently hard to pump with a conventional sucker rod pump. The design of this pump varies from traditional rod pumps whereby the standing valve is re-positioned at the top of the pump barrel. This factor, along with a specially designed set of seals and poppet assembly have led to the success of this pump. An area of west Texas was targeted to try this pump after a very successful introduction to the oil patch in western Canada.

The rapid expansion of horizontal drilling in unconventional gas plays such as shales and tight sandstones has lead to large increases in the number and size of fracturing treatments. Successful fracturing treatments on these wells require multiple stages and proper zonal isolation between the intervals being treated. Zonal isolation and completion techniques typically take the form of either a cemented casing/liner string and stage fracture treated using a perf and plug methodology or a system of packers and sliding sleeves fracture treated in a continuous
operation. Each completion technique has its own set of advantages and disadvantages and is typically viewed as mutually exclusive of each other. A case study showing a combination of these techniques being implemented in successful fracturing treatments in central and western Oklahoma will be shown. The application of these combined techniques on future remedial stimulations will also be discussed.

Use of new software for management of low volume oil and/or gas wells will be presented showing how graphical discovery tools and knowledge of field operating conditions, best practices and failure data can be used to efficiently manage large numbers of wells under stripper market conditions. A multi-well management system for a large stripper gas well field well be demonstrated.

This paper explains the contributing elements of a new formula developed for more accurately predicting the performance of those gas wells which include a high permeability zone interbedded with one or more low permeability zones. The theory assumes the existence of three conditions: that the well depletes without water encroachment; that each zone remains discreet from every other --that is, without cross flow among zones when the well is producing; and that each zone has either a hydraulic fracture or some skin effect. As a practical matter in using the model, however, only one of these reservoir conditions need be strictly met: freedom from water encroachment. The model developed herein does adapt to reservoirs that have limited cross flow between zones; it also adapts to those with a hydraulic fracture in only some of the zones. Finally, it includes equations which help to calculate matrix permeability whenever a known hydraulic fracture does exist. We illustrate the functions of this model by assuming the existence of a shaley-sand, six-zone reservoir and by ascribing to it certain characteristics. We examine how the model uses this data and then discuss the results.

Drilling multi-laterals is a preferred method to increase production from a single wellhead. Getting baack into these laterals can be difficult and costly. But without proper treatment, say for example acidizing the lateral, the well can not produce as well as it should. There are pressure activated tools that can get your coiled tubing back into the laterals and with different attached tools, cleaning or acidizing the lateral is very possible at reasonable pump rates. This paper will discuss how a tool works, the therory behind its use, case histories, successes, problems encountered and how to avoid problems in advance.

Drilling multi-laterals is becoming a preferred method to increase production from a single wellhead. Coiled tubing's role continues to grow as a well intervention system, but is limited in its capacity for selective entry into multi-lateral completions. Without a practical method to selectively enter multi-lateral completions to perform workovers and stimulation operations, these wells are not achieving their full production potential. A tool has been developed, tested and proven that allows CT to selectively enter each leg of a multi-lateral completion. The tool finds and enters the desired juncture or window and signals the operator at surface that it has done so. The Lateral Entry Guidance System is being used reliably for conventional CT stimulation or cleanout applications, and it has been adapted to run on the end of other specialized tools. This paper will discuss the tools development/testing and case histories of successful operations in the Permian Basin.

Multiphase Pumping has been gradually expanding its niche as a tool for coaxing additional production from wells. In the past it was seen as a discipline for saving capital costs, such as saving on additional subsea lines, or, in the case of Venezuela, reducing the surface treatment equipment needed to gather and move heavy, gassy crude. Today it has become a specialty tool that can lower back pressure of wells that otherwise have difficulty in producing into established production systems, or it can be used in conjunction with other down hole methods to optimize gas lift, jet pumping, and even augment the performance of PCP or ESPs. Confidence has grown among the users as they have learned how to apply this equipment effectively. This paper defines common terms used when sizing and applying multiphase equipment, and briefly describes the types of pumps available today, including the new reciprocating types of pumps that have met with recent successes. Some of the new techniques and applications are described along with considerations to keep in mind when installing such systems.

The competitive position in which oil companies now find themselves -- with other energy suppliers as well as in their own industry -- has demanded that they deliver, to the market, oil products as efficiently and cheaply as possible. This position has required a look at all phases of the industry: exploration, drilling, production, transportation, refining, manufacturing, and marketing. One factor which has received considerable study and development has been multiple zone completions. Because of its normal application in producing oil, hydraulic pumping has many desirable features as applied to multiple zone completed wells, when artificial lift is required. This paper will discuss some phases of this application.

This paper will provide a comparison between multistage horizontal pumping systems and reciprocating positive displacement pumping systems. We will compare their applications, costs and advantages and disadvantages.

A new surface energy mechanism, based on recent joint industry-university research using nanoparticle dispersions (NPD) is now available to the oil and gas industry, and is being laboratory and field tested for improving stimulation fluid recovery, remediating wellbore damage issues such as paraffin, waterblock and deep induced imbibition, as well as for enhancing the recovery of oil, gas and water following their application by a variety of intervention methods. Also being readied for implementation, is the use of NPDs to provide increased hydrocarbon production
and injection efficiency from waterflooding and other improved hydrocarbon recovery operations. Increasing injectivity into saltwater disposal wells (SWD) has been accomplished in beta test field trials. Graphic experimental demonstrations of these mechanisms will be shown and discussed, with emphasis on their current and potential field treatment applications, and with comparisons to another successfully utilized additive technology.