The determination of the rheological behavior of cement slurries is essential for the proper evaluation of displacement pressures and flow rates for optimum cement placement. Several cement slurries have been examined, using pipe flow and concentric cylinder viscometers, in an effort to determine which method is better suited for determining such flow characteristics. Comparative analysis of the data indicates that the concentric cylinder viscometer may be inadequate for measurement of the rheological properties of cement slurries. Studies using a pipe-flow rheometer indicate that an apparent "slip" at the pipe surface occurs during rheological evaluation of cement slurries. This wall "slip" is attributed to particle migration when cement slurries are sheared. Field evaluation of the rheological properties of cement slurries flowing in large-diameter pipes confirm the results of the pipe-flow rheometer. Based on data obtained with a pipe-flow rheometer, a recommendation is offered as to which mathematical model most accurately describes the flow characteristics of cement slurries.

Ribbon rod is Continuous Carbon Fiber Sucker Rod which is in the configuration of a reelable "tape" or "ribbon" with current dimensions of 1.45 in. x .212 in. It can be wound on a 10 ft diameter reel, 6 in. wide. It is designed to be run with some steel rods on the bottom similar to fiberglass rods. Its performance can be designed and analyzed using wave equation type mathematical models. Ribbon rod has been successfully tested in the lab and field over the past ten years. It was conceived as a method requiring no couplings, using a corrosion resistant, light weight material. Recent material/construction/design modifications and lab plus field trials reported here, have resulted in a system that can extend beam pumping to production rates beyond that currently possible with beam pump systems using other rod alternatives.

Are your gas wells operating at peak performance? Are down-hole or reservoir problems unknowingly keeping your well from producing at its maximum capacity? This paper will address these problems by introducing quick methods of identifying underperforming gas wells and then diagnosing them to determine how to increase their productivity. The use of simple "production indicators" will be illustrated as a way of quickly sorting through large numbers of producing gas wells, and short listing those with potential problems and uplift opportunities. Some of the problems addressed include liquid build-up in the wellbore, skin buildup in the completion or near wellbore reservoir rock, paraffin, scale, or tubular restrictions. Quick ways of diagnosing these problems will be illustrated with examples. A brief review of techniques from the first paper on this subject, MULTI-WELL MANAGEMENT SYSTEMS, Part One

Historically, batch applications of corrosion inhibitors have been utilized to protect the downhole tubulars in oil and gas producing wells. Previously, a paper was presented which detailed the laboratory development and initial field evaluations of a new, unique corrosion inhibitor which enabled the Operator to extend the frequencies of his conventional batch treatments. This paper addresses the practical application of this chemistry, and the monitoring of its performance over the last year in several producing fields in the Permian Basin.

A considerable amount of money is spent annually on corrosion inhibition programs utilized in the production of crude and natural gas. Consequently, considerable time and effort is placed on monitoring these programs and on searching for the most cost effective, system representative monitoring tool. For many years, dissolved iron was used for corrosion monitoring, though we now realize the many errors of this process, particularly in "sour", or hydrogen sulfide bearing, production environments. Dissolved manganese has been discussed as a more effective monitoring tool, though early analytical techniques proved this method to be cumbersome with varying degrees of accuracy. This paper revisits the use of dissolved manganese as a corrosion inhibitor monitoring tool with the application of modern techniques and instrumentation.

Injection and production below the OWC and bottom thief intervals are common problems in many carbonate reservoirs. Conventional methods to remediate bottom water injection are expensive, largely due to well control costs. A method to repair bottom water injection with reduced or eliminated rig costs is presented, along with lessons learned from successes and failures utilizing this methodology. Specialized cements and techniques have been investigated to insure the needed capabilities and attributes for near wellbore repair as well as extensions into channels, fractures, and high permeability streaks. In addition to the injection well work, two successful examples utilizing a similar procedure on producing wells are presented.

In the Oil and Gas Industry, risk analysis is the attempt by industry to quantify the range of outcomes of real world events by means of mathematical models of the real world. In the real world of multiple economic decisions that industry must contend with every business day, there are multitudes of externalities, known and unknown, that act upon real world events. These externalities are in general called risk and uncertainty. The Oil and Gas Industry tries to measure, quantify, and account for risk and uncertainty using stochastic and statistical methods. The drilling of an oil or gas well is an uncertain venture--there are plenty of oil and gas producers that will attest to this fact. The usual method of evaluating an oil and gas drilling prospect is to first make a determination of the amount of hydrocarbon reserves that are to be found by the drilling of a well or a series of wells. If this prospect well is near other wells producing from the same target formation, one might be able to say, if the geology is similar, the prospect well will recover sellable hydrocarbons or reserves in an analogous quantity to the producing wells of the existing fields. If the above analogy can be assumed, a petroleum engineer can determine the estimated recoverable reserves (EUR) for each of the analogous wells or fields. Then using statistics the engineer can further determine the average EUR for the sample of analogous wells or fields along with a statistical property of the sample called the variance and standard deviation. The variance and standard deviation is a measure of the dispersion of the individual items in a distribution about the mean of the distribution. Table 1 is an example of how the average and standard deviation of a sample distribution of EURs can be determined. In some analyses of drilling ventures, a simple statement of the expected reserves to be found and maybe a range (a high expected value and a low expected value) of reserves is sufficient. However, a more sophisticated analysis would say that the expected reserves is the average or mean of the sample analogous wells, that the sample had a range of reserves, and that the standard deviation of the sample is some calculated value (6). At this point, the expected value of the reserves or mean and the low/high range quantities could be used to generate economic profiles of the proposed drilling venture. Very often, an economic profile of a drilling prospect based on the expected reserves is all that is presented to prospective participants. Something is still missing from the analysis: there has been no addressing of the risk associated with drilling the well with the expected reserves stated.

Risk is the potential for an adverse impact on the achievement of objectives. Environmental, health and safety (EHS) risks often threaten far beyond the EHS objectives. Risk management is the process by which risk is prevented, controlled or mitigated in a value focused manner, considering both benefit and cost sides of the risk equation. It is prudent to recognize that i) everything cannot be done at once, ii) some things are more important than others, and iii) it is best do the most important things first. The objective is to "Work the right issues - fund the right opportunities".

As gas wells deplete, it is very common for additional water and sometimes condensates to begin to accumulate in the flow path (tubing) of the well. This liquid loading reduces the gas flow rate and can even stop the flow rate completely. There are many solutions to the gas well de-watering problem, but what is the best solution? Solutions include smaller tubing, plunger lift, addition of surfactants, wellhead compression, smaller tubing, pumping methods such as beam pumping, possibly injection of liquids below a packer to an underlying zone, gaslifting of gas wells, and other methods. This problem is sometimes solved by fieldwide investigations of what has worked best in a particular field. Here considerations are presented for perhaps a newer operator, to allow a better selection of methods for lifting fluids from a gas well initially. Factors such as effectiveness, initial cost, continuing costs such as chemical costs or power costs, manpower or servicing needs, and well characteristics and other factors are examined to help an operator decide what method/s may be best suited for dewatering a gas well or a group of gas wells.

The largest volume waste stream associated with oil and gas production is produced water. Independent operators have identified produced water as a major constraint in the production of hydrocarbons. The costs of lifting, separating, handling, treating and disposing of this water are substantial. In addition to the economic burden it imposes, water can also directly reduce hydrocarbon production. With these thoughts in mind and as partial fulfillment of a Dept. of Energy contact, the Petroleum Technology Transfer Council (PTTC) developed a manual to assist independent operators in dealing with produced water. The manual addresses different technologies used for different water production issues operators face throughout the life cycle of a well. This paper will provide an overview of the information contained in the manual, including case studies of technologies operators are using to reduce water production and successful operating practices to reduce lifting costs associated with handling produced water.

This paper will report the results of a survey of the field methods that oil and gas operators are using to capture and transmit daily field production. The objective of the survey was to: (1) accumulate information on the techniques/methods operators in the Permian Basin were using to collect, record and transmit daily production (oil, gas, water) and other associated operational data; and (2) determine if the methods employed correlated with size of the operator and/or location (remote or centralized). The survey was conducted by interviewing office and field personnel, and other contact methods. The results show that there is a "mix" of methods being used by the operators surveyed. The method tends to be a result of the needs or the philosophies of the operators, the status of mergers, and buy-outs (who is the surviving entity) with new systems being tried, and communications between field and office personnel.

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. The tubing plunger used prior to the leak was considered impractical. The usual remedy would be rod pump and jack. A casing plunger was installed to recover both lost fluids and fluid entry after the failed casing repair. Restoration of production rates comparable to rates prior to the casing leak has been achieved. Technique modifications, production charts and economics will be presented.

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. Second, compare the overall production of casing plungers with rod pump and jack performance. Early results and successful installations indicate casing plungers can be considered as rod pump and jack replacements in many applications. Casing plungers might well be considered prior to rod pump and jack installation.

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