Download Papers

A typical "PAL" casing plunger application was modified to recover fluid invasion after the unsuccessful repair of a casing leak. An Oklahoma Panhandle well experienced a casing leak and shut off gas production. Typical repair attempts to squeeze cement the leak were only partially successful. A small leak was evident due to pressure tests, but an injection rate could not be achieved for further attempts to squeeze cement the leak. Extensive swabbing failed to recover lost fluids and invasion of foreign fluids into the well bore.

Recent innovations in "PAL" casing plunger cup design and mechanical actuation indicated success in artificial lift applications currently using a conventional rod pump and jack. Several wells, previously produced by tubing plungers with limited success, and subsequently equipped with conventional rod pump and jack, were chosen for field testing fluid removal using casing plungers. The objective was two-fold. First, test the feasibility of a casing plunger as a possible replacement of rod pump and jack, and thereby reduce lease operating expenses.

As the gap between supply and demand continues to increase for oil and gas, operators are challenged to develop wells in various economic environments. Because of the cyclical nature of the commodity market and the constant change in commodity prices, operators reduce the overall cost while pursuing more and more challenging wells. One such environment is the "Wolfberry" play in West Texas. Because of the rapid early production decline in these wells they must be drilled and completed as efficiently and cost effectively as possible.

This paper describes new rock bit bearing seal technology that is just beginning to be applied to difficult drilling applications in West Texas. The conventional elastomer seal may have limitations in applications where there is elevated temperature, oil based mud, or high bit rotar speed. The use of hard metal rather than an elastomer as the primary sealing element improves bit performance in these environments. High temperature, oil mud and high RPM associated with downhole motor drilling are present in horizontal drilling in the Williston Basin of North Dakota.

This paper describes new rock bit bearing seal technology that is just beginning to be applied to difficult drilling applications in West Texas. The conventional elastomer seal may have limitations in applications where there is elevated temperature, oil based mud, or high bit rotary speed. The use of hard metal rather than an elastomer as the primary sealing element improves bit performance in these environments. High temperature, oil mud and high RPM associated with downhole motor drilling are present in horizontal drilling in the Williston Basin of North Dakota.

Voids within the rock matrix form the container in which gas accumulates; therefore, knowledge of the quantity and distribution of these voids (pore space) is essential in assessing the quantity and distribution of gas present. The shapes, variety of sizes, and distribution of the pore space on a microscopic scale are referred to as pore geometry. This geometry differs widely because of the varying depositional environment of reservoir rocks, and subsequent diagenesis.

Wellhead inspection of tubing should be the starting point for reducing tubing leak frequency. Based on inspection results, an operator may be able to identify trends. The trends may allow an operator to reduce well head inspection and move to a program of rotating tubing and or laying down sections of tubing when tubing leaks occur. Rod inspection can reduce overall rod repair costs.

Rod Counterbalanced hydraulic pumping offers a means of producing wells of almost any depth and fluid rate, and of utilizing the recognized advantages of long, slow strokes, with minimum initial investment and subsequent operating costs.

A major maintenance expense for rod pumped wells is sucker rod induced wear on the tubing string. In most cases this wear is due to 1) deviated wellbores, 2) rod buckling on the downstroke and/or, 3) tubing buckling on the upstroke due to unanchored tubing. In order to address these problems operators frequently rely on rules of thumb gained after years of trial and error experience. This paper describes a systematic approach for predicting when rod/tubing wear is significant and offers recommendations to help reduce its detrimental effects.

Design calculations for sucker rod pumping systems (conventional units) using the API RP 1lL Recommended Practice is now the "standard" for the oil industry. Prior to the RP 1lL publications, the Mills, Marsh, and Coberly formulas were used. It was obvious to many designers that a more accurate method was needed. In 1954 a group of users and manufacturers undertook a study of the complex problems associated with sucker rod pumping. The services of Midwest Research Institute were retained to study these problems.

As part of the effort to select an alliance company for handling domestic, downhole, rod pump manufacture, and repair, an audit program was developed. This program was conducted to evaluate six different pump companies that were available at the time. Audits were conducted on over 150 pump shops. The results were used as part of the selection criteria for Conoco's domestic rod pump alliance. This paper will provide the list of quality, performance, and technical requirements that were originally used to perform these audits.

As new wells are brought on many times a great deal of sand is coming back through he rod pump. The pump may also experience has interference then or later on as the fluid level has been drawn down. This paper will discuss many different rod pump designs and why they would be an effective design, a possible design, or a poor design for sand and gas producing new drills.

The selection and design of the artificial lift equipment will continue to be a significant event in the life of most oil wells. The resulting profitability will either be increased or diminished by the artificial lift equipment choices, and the credibility of the designer will be enhanced or lowered. The designer should be aware that the system efficiency is becoming increasingly more important, since energy costs continue to rise. The best artificial lift selection and design will make the greatest amount of money (highest present value cash flow) over the life of the project.

The selection and design of the artificial lift equipment will continue to be a significant event in the life of most oil wells. The resulting profitability will either be increased or diminished by the artificial lift equipment choices, and the credibility of the designer will be enhanced or lowered. The designer should be aware that the system efficiency is becoming increasingly more important, since energy costs continue to rise. The best artificial lift selection and design will make the greatest amount of money (highest present value cash flow) over the life of the project.

A method is presented for the overall design of rod pumping systems. This method takes the reservoir as its starting point and carries the design into the field operation of the system. Included in the general discussion of this method will be a review of the basic design principles which are presently being used throughout the industry.

In the last several years, the question has been frequently raised as to how much torque can a typical rod rotator transfer to a rod string. This is an especially important consideration for fiberglass rods. This paper discusses testing on three popular rod rotator models, the T-164TM, T-252TM, and T-302TM, plus an optional version, designated as T-302SGTM (slow gear version).

Current API RPllL rod taper percentages are based on empirical formulas which were used to simplify the system calculations so that they could be made manually. The trend toward deeper, high volume pumping has resulted in higher rod loads and stresses so more accurate taper percentages are needed* The availability of the personal computer now makes it possible to design accurate rod tapers for each individual well. This paper presents a method for the determination-of rod stresses in the intermediate tapers of the rod string and an improved criteria for taper design.

This paper describes the derivation of rod string design for use over a range of production parameters. The concerns in achieving said design include: (a) reduction of tubing failures, (b) reduction of rod failures, (c) use of small pumping units and prime mover motors, (d) ease of adaptability to accomplish needed production change(s), (e) operation of system elements within rated capacities, and (9 optimization of system efficiencies.

Supplements and expands upon the paper presented at the previous meeting and stresses additional case histories and discussion of problems and unusual applications encountered during the past year with the rod-counterbalance method. Also deals with some of the basic calculations used in design and application of these units, particularly those calculations which are different from those encountered with more conventional equipment.

Description, comparison, and usages of ball and roller bearings. Operational maintenance, lubrication, and troubleshooting are reviewed.

The rising cost of electricity underscores the importance of operating any business at optimum efficiency. While producers cannot control the cost of electricity, they can reduce the amount that they use. Additionally, production that is unnecessarily down due to electrical events and failures can significantly affect revenue. There are proven methods to reduce electrical energy usage and to minimize electrically related downtime. Often, these methods are not implemented or maintained because the value is not well understood.

The danger of arc flash hazards is present at plants, facilities, beam pump and electrical submersible pump installations. Over the last decade, recognition of the effects of electrical arc flash hazards (severe burn injuries, hearing loss and death) has created industry and OSHA requirements to minimize arc flash exposure hazards to workers. Compliance with NFPA 70E is the bare minimum; however it can be overkill or even inadequate, especially when dealing with oilfield electrical systems.

In the fall of2000 a team was formed to capitalize on the experience and knowledge of each and to continue work previously done by Bobby 'Turner (Pool Company). This paper is only, an excerpt of the Work completed by the team. How Will This Add Value To Your Operations The high cost of downhole equipment. combined with the additional requirement to pull the rods. pump and tubing place a high priority on reducing these failures. A thorough understanding of equipment failures. including both their root cause and potential solutions.

The RotaFlex pumping unit has a unique geometry that results in a constant torque arm (or torque factor)on most of the upstroke and downstroke. The geometry promotes high electrical efficiencies. Electrical efficiency can be measured by comparing the work required to raise the produced liquids from the net liquid level depth to the input electrical power. Also, electrical generation with the RotaFlex pumping unit is minimized compared to conventional beam pump units, which is favorable for high electrical efficiencies.

Inexorable economic pressures demand that ways be found to reduce the cost of approximately $2.5 billion annually is too great a financial burden. Neither a reversal of economic tides nor dramatic new drilling techniques can be anticipated to bring sudden needed relief. Therefore, the solution must be sought through refinement and improvement of known basic practices, policies and concepts. Despite these limitations, some surprisingly large reductions probably can be achieved in the over-all cost of new wells.