Laboratory studies have been made to determine the oil recovery by displacing the Levelland and Wasson crudes by carbon dioxide at various pressures. For the case of the Wasson crude it has been found that a slug of carbon dioxide equal to ten percent of the hydrocarbon pore volume pushed by nitrogen resulted in an oil recovery of 96% of the original oil in place. The use of a slug of carbon dioxide of five percent hydrocarbon pore volume pushed by nitrogen resulted in an oil recovery of 90%. The cost of carbon dioxide brough in from Colorado or New Mexico is expected to be $1.00 to $1.25/MCF. The cost of nitrogen is expected to be less than 50 cents/MCF delivered at high pressure. At Wasson or Levelland reservoir conditions one MCF of nitrogen will occupy three times as much pore space as one MCF of Carbon Dioxide. The cost of nitrogen at reservoir conditions is estimated to be only 15% of the cost of Carbon Dioxide at reservoir conditions. It appears the nitrogen-driven carbon dioxide slug oil-recovery method may have application to various West Texas crudes.

This paper describes a new pumping system for low-volume/marginal oil wells and deliquification of gas wells to extend well life by reducing the economic limit. The economic limit is reduced by decreasing capital, installation, and operating costs of low-volume artificial lift. Many low liquid volume gas wells cannot justify the current cost of artificial lift. Although beam pumping is typically the lowest cost lift method, its inefficiency at low rates requires a much higher lift capacity than the well actually produces and requires a minimum +/- 25 horsepower. This new pumping system can operate on as low as +/- 0.5 horsepower, significantly reducing capital, installation, and operational costs.

This paper presents the results of a successful application of a new-generation polymeric selective water reduction (SWT) that reduces water production without requiring zonal isolation. The SWT can be bullheaded into open intervals without the need for isolating water zones from hydrocarbon zones. As a result of this treatment, the productive life of a well can be extended, with a gradual increase in water cut. This translates to a high potential profitability value for mature fields with a high water cut. It can increase the hydrocarbon recovery percentage in formations that otherwise would be destined for abandonment. Previous papers have discussed the laboratory development of the SWT based upon the use of a hydrophobically modified polymer. This paper will focus upon the field implementation results of this technology. Specifically, this paper will focus upon candidate selection, job design, and summary of the results of treatments performed.

Pumping Solutions Incorporated has developed and tested a new type of Electrical Submersible Pump that uses a positive displacement, hydraulically activated diaphragm pumping mechanism in place of the traditional centrifugal pump. This paper presents the field trial results and lessons learned from over 80 real world field installations in coal bed, conventional gas, and conventional oil wells, with data documenting solids handling, gas characteristics, electrical efficiency, and pump performance. Test results show significant improvements over conventional rod, PCP, centrifugal and other types of artificial lift in solids handling, gas lock characteristics, electrical efficiency, production economics and low volume/deep pump performance. The paper also discusses the issues associated with the use of this new technology, and the basics of the pumping system itself.

This paper discusses field results of a fracture-stimulation treatment that includes a relative-permeability modification (RPM) chemical agent. The design objective was for the RPM to leak off into portions of the created fracture during the stimulation treatment and help prevent water production. Initial treatments were performed in April 1997 in the Brushy Canyon formation in southeastern New Mexico. The selected candidates treated were in the Delaware sand reservoir. Previous fracture treatments in this interval had resulted in water cuts greater than 60%, and the continued production of these wells had been uneconomical because of the presence of damaging scale and a subsequent decline in total fluid production; the water cuts would remain at 60 to 70%, but the total fluid production would decline.

Electronic Downhole Load Cells (DKLC) have been used to quantify rod loadings calculated by predictive and diagnostic wave equation programs. Test results to date show that software calculations agree closely with DHLC measurements. However, there is a difference in how software programs account for buoyant forces which results in discrepancies in reported loads and placement of the zero load line. The overall impact of this difference in the tests run to date. has not been large and may only be critical in the most demanding rod pumping conditions.

Gunbarrel tanks, which are also known as wash tanks, are one of the primary pieces of equipment used to separate oil and water, in oil producing operations. To improve the hydraulics and residence time of fluid in gunbarrel tanks, they are usually outfitted with some type of internal fluid flow control system. There are numerous designs of internal fluid flow control systems. These designs include spreader pipes, spreader tables, inverted troughs, baffles, etc. An uncommonly used design, is the installation of parallel vertical baffles to achieve a serpentine shaped path of fluid flow within the tank. The serpentine style internals are simple, and are one of the more foolproof systems being used to reduce the possibility of fluids channeling or short circuiting through a gunbarrel tank separator. This paper presents: a brief discussion of the purposes of oil/water separation in oil producing operations; the factors that affect the oil/water separation process; a basic review of mechanical separator equipment used for primary and secondary oil/water separation; a review of gunbarrel tank internal designs, and the benefits and/or drawbacks of these designs; and a review of the flow performance tests on different gunbarrel tank designs.

Design of casing and liner strings grows more critical as well depths and bottom-hole pressures increase. Service conditions, economics, material properties, and stress-inducing parameters must all be considered to arrive at an optimum casing or liner design. A practical approach to considering the three basic load conditions, i.e., internal pressure, collapse pressure, and tension, and how they affect casing string design decisions is presented here. Safety factors that have wide industry acceptance and use are discussed. Actual practice is then reviewed by comparing the "ideal" to the "

The Morrow Formation is one of the main targets of the drilling activity in Southeast, New Mexico. The paper presents background information including formation lithology derived from X-ray diffraction data and scanning electron micrographs. Formation rock characteristics such as frac and temperature gradient, Young's modulus, permeability, porosity and formation water properties are also presented. Completion techniques such as cementing practices, casing programs and perforating programs are reviewed in detail. The stimulation fluids, volumes, injection rates and types of proppant used are presented to provide an optimum completion program.

A review of assumptions, fundamental procedures and applications of several methods utilized in measuring pressure gradients in gas lift wells. The common parameters of each method are discussed with special emphasis on limitations and errors imposed by the techniques and available data.

To bridge the gap between supply and demand companies must institute new technologies to aid in the exploitation of remaining reserves. The PowerwaveTM process is an injection technology that improves the flow of fluids in geological materials. When effectively implemented, it is the most efficient way to accelerate fluid flow and disperse a liquid through a porous medium. The technology works in a wide range of geological materials, including sedimentary soils and fractured rock. These materials are composed of a solid matrix and pore structure, which contain fluids such as gas and oil. These fluids move through the pore networks or preferential flow paths established during the formation of the geological material. The process generates a fluid pulse that causes momentary elastic flexure of the pore structure; which allows fluid to move into and out of a larger number of pore networks thus obtaining a more uniform injection front. The paper will review the science and engineering of the technology as well as several field results.

The pitot pump first appeared in U.S. patent history at the turn of the century. The first forms were of the open ring rotor type which had many performance limitations. During the 1920"s, the basic closed rotor form was described in patents, such as shown in Fig. 1. This closed form was extensively studied in Germany in the years 1939 - 1945 (Ref. 1) for use in aircraft and rockets, and in Britain during the late 1940"s. Development on this pitot pump study was stopped when it was found the design did not lend itself to being extended to flows over 5 GPM. It was also determined by this group that the pump was prone to air-locking 2 and airbleeding methods were patented. 3, In 1959, a pitot pump study was completed and reported by the U.S. Office of Naval Research 4 in which a number of pitot pumps were built and tested. They also suggested additional research be carried out, although no research has been reported at this time. In this study, test efficiencies were reported of 25 - 30%, and head coefficient of 1.10. In 1962, development work was started in the United States that led to the enclosed rotor spin-up passages and other concepts that form the basis of the Roto-Jet form of pitot pump. These closed rotor passages and grooved spin-up slots result in efficiency increases of 5 to 10 points and are described by Patent Nos. 3,384,024 and 3,795,459. The special diffuser construction in the pitot tube increases the efficiency by 15 points. Another unique feature that has been developed is the ability to operate with very high inlet pressures, as the rotor can be completely pressure-balanced.

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.