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 includes drilling to total depth quickly, running affordable casing and successfully achieving zonal isolation in a severely under-pressured environment. Single stage production cementing is a must to maintain the economic viability of these wells. In order to maintain long term stability of the well-bore, cement must be brought above the top of the Spraberry formation (7000" to 7500") from TD (9500"-10,500") without fracturing the well. The Spraberry formation typically has a fracture gradient on the order of 0.43

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. The results of testing metal seals in Williston Basin horizontal drilling are presented along with recent metal seal performance in West Texas. Metal seal bits have shown to be much more reliable and consistent than elastomer seal bits in these applications. Longer hours and higher reliability have reduced the number of bits required and thus lowered the cost of wells drilled. The improved percentage of seal effective bits has also lowered the risk of costly fishing jobs due to bearing failure.

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. The results of testing metal seals in Williston Basin horizontal drilling are presented along with recent metal seal performance in West Texas. Metal seal bits have shown to be much more reliable and consistent than elastomer seal bits in these applications. Longer hours and higher reliability have reduced the number of bits required and thus lowered the cost of wells drilled. The improved percentage of seal effective bits has also lowered the risk of costly fishing jobs due to bearing failure.

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. Pore geometry is related to the quantity and distribution of storage space (porosity), and through capillary forces it influences the reservoir distribution of gas and water. The ability of a formation to transmit fluids (permeability) is also related to pore geometry. The native ability to flow can be decreased during completion operations by reaction of the rock with the completion fluids. In addition, an increase in effective overburden pressure typically occurs during production, and this also results in decreased flow capacity. Low permeability gas reservoirs are particularly sensitive to both these effects. The introduction of filtrate into a gas formation reduces gas flow capacity-even when no rock-fluid reaction occurs. This permeability reduction is controlled by relative permeability characteristics of the rock. This loss of flow capacity occurs whether the extraneous liquids are introduced in the zone from filtrate invasion during completion or workover operations, or by retrograde condensation. Influx of water into a gas reservoir traps a quantity of gas behind the water-gas front. This trapped gas is not recoverable and varies with rock type, and in some cases with permeability and porosity within a given formation. The magnitude of this trapped gas must be known and accounted for in order to estimate gas recoverable reserves in water-drive and gas storage reservoirs. Gas storage projects serve as accumulators of gas near the area of need. Storage capacity, capillarity, transmissibility, relative permeability characteristics, and trapped gas quantities are necessary in evaluating the potential of the storage zone. In addition, threshold pressure tests are required to evaluate the suitability of the caprock matrix that overlies the storage zone.

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. The deviated wellbore calculations are performed using a rod by rod force balance that considers deviation survey data. The rod buckling portion is based on static load tests of three rod sizes equipped with up to four guides per rod. The test results are compared to Euler's column buckling equations for different l/r (length/radius of gyration) ratios in an effort to determine a predictive equation. Tubing effects are considered using the methods proposed by Lubinski. Field verification tests were performed since 1991 for several rod strings equipped with rod guides in different producing environments. Also, a computer design program was developed and used to deliver this technology to the field.

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. Based on their correlations and test data obtained from an electrical analog study of sucker rod pumping systems, the design procedures outlined in API RP .llL were developed. Since its development, API RP 1lL has become widely used. In the past two years, it has been programmed for use on the personal computers. In general, API RP 1lL gives reasonably close answers on an average for conventional units for the assumed conditions. However, the answer for a specific case can easily exceed 7 percent for loads and 10 percent for peak torques. RP 11L does a good job of predicting the percentage change by altering pump conditions. Improvements that are predicted by the calculations will often be achieved in practice. The API RP 11L method has a number of simplifications and assumptions that must be recognized. The work was based on an "average" conventional unit geometry, running with only medium slip, having complete pump fillage, and having no abnormal dampening or friction. In addition the assumptions were made that fluid acceleration was negligible and that there were no mechanical problems. For simplification, one average set of design curves were developed

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. A summary of the findings from the companies in one producing region will be provided. These findings showed a wide variation in skills, training, and quality of the pump shop personnel. Additionally, the original requirements will be updated based on the latest technical requirements in the industry and so that the audit criteria can be used for more producing regions in the world.

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. [2] In the planning stage the following three factors must be evaluated: (1). the oil and gas production and revenue over well life, (2). the operating cost over well life, and (3). the capital cost of the equipment. Of these --the most significant is the revenue. To maximize revenue, the oil reserves should be produced in a timely fashion. Thus a design is required that will produce the well near its capacity or at a high rate throughout its life. The operating cost over life normally far exceeds the capital cost; thus, particular attention should be given to reducing recurring monthly costs (i.e. energy, maintenance, and repairs). Often the more efficient and trouble free equipment is initially more expensive. Good records must be kept and evaluated to determine the operating cost advantage of the installed equipment. Digging out the monthly costs may be a tedious process even in these days of data bases and computer manipulations. The capital cost is easy to obtain. The vendors and service companies will help in this endeavor. Bids are often obtained and, unfortunately, sometimes not carefully reviewed. The bid specifications should be carefully written and the received bid then thoroughly analyzed. Do not waste money by purchasing excessively large equipment or buying features that are not needed. Be sure all equipment will meet the objectives of being efficient and trouble free. Do not overlook the service required and its availability and quality in the planned location. This paper will discuss the more important considerations in rod pumping selection and design.

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. In the planning stage the following three factors must be evaluated (1). the oil and gas production and revenue over well life, (2). the operating cost over well life, and (3). the capital cost of the equipment. Of these

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). The test results are based on carrier bar loads versus output torque measured at the instant that slippage occurs at the frictional interface located between the worm gear or ratchet table and the cover cap of the various rod rotator designs. In addition, a case history involving a new, positive drive version known as a "T-302 No-Slip" Rod Rotator, for situations involving extreme wear on one side of rod guides, will be discussed. This new style of rod rotator uses special components to lock the worm gear to the cover cap and also to prevent the rod clamp from slipping on top of the cover cap.

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. It can be demonstrated that, with proper planning and design, a single rod string design can be made to accomplish these objectives with accommodations to changes in production parameters being performed without entering the well bore.

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. In the past, with lower electrical costs, these methods may have been ignored or not thought worthwhile to pursue. This paper will outline several simple and tested operating strategies, which improve uptime and minimize electrical costs.

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. The first step in evaluating the scope of arc flash hazards is developing a power system model with arc flash software (based on IEEE 1584) which calculates the levels of arc flash levels. Oil field distribution systems are unique in many ways and especially regarding arc flash. These typically weak radial systems present unusual challenges to developing solutions. Sometimes, the PPE requirements exceed existing technology. This paper will explain the hazards associated with arc flash and present several simple engineering solutions, which reduce the PPE requirements.

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. will and should provide immediate tinancia1 benefits to your organization. Downhole equipment that is properly designed - base upon experience. physically handled and made-up in accordance: with the recommendation of the manufacturer, and operated within acceptable design parameters Lvith an effective downhole corrosion control program should give ii long. satisfactory, and economical service lift:. Why Discuss Root Cause Failure Analysis And Solutions? "Survey results by the attendees at the Permian Basin Artificial Lift Forum (2000) indicated the top interest and concern was for additional discussion on this topic (see figure A) "Used with permission of PBOWG A. Overview B. Root Cause Failure Analysis Flowchart C. Pump Failures D. Make Up Flowchart & Presentation E. Rod Failures F. Tubing Failures G. Corrosion Flowchart & Presentation

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. RotaFlex balancing can be performed using electrical power measurements, and the amount of counterweight that must be added or removed from the counterweight box to balance the unit can becalculated directly by software using the power measurements and RotaFlex data. Power balancing does not require knowledge of the weight of the counterweight box and the auxiliary weights as is required with conventional mechanical balancing. An example of determining the electrical efficiency and of balancing a RotaFlex unit is given to further describe and explain the procedure for determining electrical efficiency and proper balance.

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. There needs to be a wider recognition that the drilling of wells is a joint Contractor-Operator-Service team effort. One of the most promising avenues in which to seek lower well costs is the scheduling of periodical division or regional conferences between these groups to critically examine problems, practices and policies. When conducted on a "frank talk" basis, such conferences will foster mutual cooperation and understanding, eliminate some costly practices and policies, create closer working relations, clarify responsibilities, and assure use of the most advanced hole-making skills and well programs. The overall result will be more economical operations for Contractors, Operators and Service companies. Some practices and policies in vogue today are examined for effect on over-all well costs.

The automation system was designed to provide accurate measurement and control of the CO2 injection process and to provide communications between the wells and a central terminal unit. The central terminal unit was to make automatic scans of the field and generate alarm/alert reports in the event of a malfunction at a well. In addition, the central terminal unit would provide historical
reports of injection volumes, rates and pressures from all wells. The planned injection pressure was between 1600 and 1700 psig and the expected temperature was between 40 and 70 degrees F. Under these conditions, the CO2 is in the critical phase. In this phase, the density and therefore the flow rate are sensitive to changes in temperature and pressure. It was determined that, in order to obtain accurate measurement, it would be necessary to compensate the flow equation for specific gravity based on process temperature and pressure and on composition of the CO2 injection stream.

Safety around Pumping Units is a basic overview of safety policies and procedures used by oilfield service companies to comply with federal regulations as well as requirements set forth by oil companies in order to achieve the overall goal of zero incidents and zero injuries.