Pressure transient tests are commonly used in production engineering to estimate reservoir pressure, well productivity, permeability and skin damage. In reservoir engineering, transient tests are also used to estimate the distribution of reservoir properties and presence of boundaries. During the last several decades deconvolution methods have been developed to remove wellbore effects and better estimate reservoir parameters using transient tests, but application for production evaluation have been scarce. In this paper deconvolution of pressure transient data is used to remove reservoir effects and determine inflow rates and wellbore fluid volumes, providing a better understanding of wellbore phenomena of interest in well maintenance, production engineering and artificial lift evaluation. The basic mathematical background is presented, along with real examples showing how the results add insight into better understanding wellbore performance, including the evaluation of pump-off controller or timer settings and wellbore integrity.

New wirelins logging services and procedures are supplying much needed answers to modeling CO2 floods in the Permian Basin. The new measurements of photoelectric absorptioncross section, gamma ray spectrometry and dielectric permitivity from LDT, NGT, and EPT are combined with CNL, BHC and resistivity measurements in a Synergetic log called VOLAN . Volan supplies the all important lithology, porosity, permeability and residual oil saturations needed for reservoir description. Cased reservoir description is now obtaining lithology, porosity, vertical permeability distribution, and oil saturations through casing. The GST CNL, NGT, and BHC are incorporated into a VOLAN PS.
Determining hydraulic isolation Hnd pipe integrity has become crucial because of the high cost of COs. New monitor techniques using CNL, TDT, and NGT show how CO2 flood can be accurately monitored to determine both vertical and areal sweep efficiency.

A system has been developed based on a powerful portable microcomputer and an integrated data acquisition package, connected to the computer's expansion slot, that allows real-time analysis and visualization of pumping well performance. The system integrates all the necessary elements to obtain a complete analysis of the performance of the pumping system which includes the pumping unit (beam or submersible), the wellbore, and the reservoir. The data acquisition package consists of the necessary analog and digital inputs to process data from standard transducers such as pressure, temperature, rod load, displacement. etc. so that detailed surface unit performance curves such as dynamometer, speed, acceleration, power etc. can be obtained and analyzed. When the instrument is used in conjunction with an acoustic pulse generator and receiver, it digitizes (1 KHz rate) and records the reflected acoustic signals which are digitally filtered and automatically processed to determine the liquid level. This is undertaken under program control so that a continuous recording of fluid level vs. time is obtained with the pumping performance parameters. Fluid level data is processed by the software to calculate bottom-hole pressure as well as flow into and out of the well bore. Changing the well from flowing to shut in conditions allows recording of pressure buildup data which is then interpreted in terms of reservoir parameters. Alternatively, pump start-up after shutting in the well in for stabilization, provides draw-down testing capability. The analog/digital electronic system contains output of a 12 volts relay driver for external control of a gas gun valve. Graphic display of the various diagnostic parameters allows complete visualization of the performance of the pumping system as a whole including the reservoir, wellbore and pumping unit. The system can be used as a diagnostic tool to optimize pumping well performance on a periodic basis. The present performance of the well is compared to the performance recorded previously and in the case where significant changes are noted a more detailed analysis is undertaken.

Problems which become apparent during a conversion from secondary production to tertiary production should be corrected to help ensure success of the proposed tertiary recovery project. Some problems are inherent to secondary recovery and will carry over into the tertiary project. These problems could be tolerated during secondary recovery, but may mean the difference between success and failure for a tertiary program. These problems can be generalized in two basic categories: Restrictions of Injectivity, Unfavorable Injection Profiles. Some processes will be discussed in detail to aid in combating the problems that will be presented in this paper.

Even with rapidly evolving technology, important issues that continue to challenge the oil and gas industry include conservation of hole size, hydraulic isolation of selected zones, maximization of well life, and economic feasibility. Addressing these issues with conventional tubular technology became more difficult, especially in deep drilling and extended-reach applications, in wells using liner hangers, and in aging wells containing deteriorating casing. Solid Expandable Tubulars (SET), a revolutionary technology, successfully addresses these issues in commercial applications. The basic piece of equipment that underlies SET technology is a mechanical expansion device known as an expansion cone that is propagated through downhole tubulars using hydraulic pressure. The movement of the cone expands the tubulars to the desired internal and external diameters in a plastic deformation process known as cold drawing. In drilling applications, a specially designed, expandable liner hanger conserves hole size by eliminating the need for a conventional liner hanger/liner hanger packer, and provides a superior pressure seal compared to conventional technology. In cased wells, expandable casing is clad to existing casing to repair or strengthen the existing casing with minimal decrease in wellbore inside diameter (ID) and flow potential. SET solutions have been successfully installed in the Gulf of Mexico, in U.S. inland wells, as well as in large-scale field trials. This paper briefly describes the technical concepts upon which SETS are based and gives an overview of their applications. The paper then focuses on two recent field installations where cased-hole liners were used to help increase well productivity.

Theory of CO2 treatment design and application is discussed. A detailed summary of past well treatments and results is presented.

Well testing, a broad general subject with as many different methods as there are operators, is a necessary part of determining the most efficient and conservative means of depleting an oil reservoir and the best method of completion to depletion. An effort will be made at this time to present some of the uses of data obtained from well tests, precautions that should be observed in order to obtain usable tests and a general look at test equipment. The presence or absence of a regulatory body may govern the number of requited well test in any given state. As Texas has a regulatory body in the Railroad Commission, a brief discussion of the test required in the State of Texas will be given. Other tests are left to the discretion of the operator for his use in efficient and economic depletion of the oil from his properties.

To assess the importance and "best practices" method to acquire, record and report the production characteristics of a mature (Spraberry Trend) rod pumping oil well. Where pump down condition is desired for best results and the importance of recognizing and controlling outside production interference of a rod pumping oil well before and during the test process.

The process of selecting or correctly sizing any artificial lift system involves many factors and relies on accurate and dependable data. This paper presents a cost effective method to determine the productivity of a well using electric submersible pumping equipment. A variable speed test is performed to provide the operator with sufficient information to properly design a permanent artificial lift system. The uncertainty of a well's response at higher volumes or lack of substantial data, prove the need for this test system. The application of the test unit and services provided will be discussed, as well as field results from actual tests.

There is no substitute for going out to a pumping unit and gathering data from a dynamometer, amp clamp, motor rpm, and fluid level in order to fully analyze a well and have as complete an understanding as possible. The physical act of stacking the well and attaching the horseshoe load cell along with the associated peripherals is becoming a lost art. In this study, we investigate the advantages in obtaining a thorough well analysis the old fashioned way and give examples of how a dynamometer and fluid level analysis outweigh any other type of study that can be performed on a well to obtain quantitative data on all the equipment, from the prime mover down to the pump.

Wellhead isolation tools can help operators control the high pressures often associated with well stimulation techniques. Fracturing requires the use of very corrosive and abrasive fluids under high pressure which can result in wellhead and tubing erosion. For safe well operation and other safety reasons, operators were usually forced to either change wellhead equipment for a fracturing job or to limit fracturing job design to the capabilities of their wellhead equipment. A wellhead isolation tool provides a means of isolating wellhead equipment from the high pressures and harmful fluids used in fracturing. This paper reviews the different wellhead isolation tools available and the advantages and disadvantages of each design. Suggestions to help ensure good fracturing job design are presented, and fluid flow through a wellhead isolation tool is reviewed and discussed. A discussion of the effects of fluid type on the wellhead isolation tool and tubing follows, and finally, some case histories help illustrate the use of this tool.

In spite of today's bargain prices for tubular goods, the recovery and reuse of existing tubing provides a highly cost effective pipe stock. Most operators appreciate the value of some screening process to remove unsatisfactory tubes before they can contribute to another workover shortly after being reinstalled in a well. Several techniques exist to assist the operator with this screening. They range from a simple visual examination of the tube to a very sophisticated ultrasonic rack inspection.

The first duals which were the direct forerunners of the present multiple parallel string technology, were set in the latter part of 1952 in the South Texas tidal waters near Matagorda Island. These were clamp type duals set at about 5000 feet. Since that time, multiple string completions have demonstrated their feasibility and economy and they have become almost mandatory for off-shore programs. The downhole features of multiple completions such as packers, slide valves, tubing joint clearance, and the like, have been adequately covered in previous papers and literature. However, due to the rapidly changing state of the art and the almost infinite variety as to pipe sizes, working pressures, and types of completions, little has been published to date concerning wellheads for parallel multiple completion. The purpose here is to outline major design considerations and describe generally the equipment available. Concentric dual hookups will not be covered since the wellheads and Xmas trees differ little from single zone arrangements.

The following is a brief review of the basic operation of the sucker-rod pump, of what fluid pound is, and of how fluid pound develops. Methods used with some of the commercially available wellsite-control systems to monitor and control and- the pumped-off well and the more prolific producers are also examined.

In 1989 water injection rates were increased in the North Cowden field. Lift revisions greater than 700 barrels per day required an ESP installation because of the capacity limitations of the existing beam equipment. The extended beam unit was designed to increase production rates to 900 barrels per day. The first unit was installed in July of 1993. Currently there are six units in service. This paper will discuss the evolution of the design and the learning process over the last three years.

The San Andres formation in the North Permian Basin in West Te.xas typically requires stimulation to be economically productive. Acid fracs are effective at increasing production but require frequent repetition due to steep declines. In the past, a comparatively small number of wells were sand-fraced and had limited success. The nature and degree of stresses in and bounding the productive zone typically result in frac treatments growing vertically into high mobility water zones. Techniques such as plugging back existing perforations and controlled fluid viscosity and pump rates combined with DataFR4Cs allowed the 35 wells covered in this paper to be fraced with controlled dimensions. This prevented the fracs from growing into adjacent water zones. The subject wells which were sand-faced since 1993 increased from an average production rate of 12.7 bopd to 35 bopd with an average 28.8% decline. The average water production increased from 25 to 50 bwpd which represents only a 2-fold increase in water compared to a 3-fold increase in oil production.

The use of rod guides in artificial lift applications has evolved to a level where accurate simulation of downhole conditions is necessary to evaluate various materials. K&M Energy Systems has designed and built a second generation plastic wear test machine that conducts tests in a heated fluid environment. A state-of-the-art data acquisition system collects all pertinent information. A standard procedure for establishing wear rates is proposed to enable end-users to compare wear characteristics of rod guide plastics in simulated downhole conditions.

LNS is simply natural gas condensed by refrigeration to a liquid -260 degrees F, a super cold or cryogenic liquid. As long as it is kept cold, it can be stored or transported like any other liquid. It is clear, colorless, odorless - in appearance not unlike club soda. Its density is about half that of gasoline and upon combustion it provides about half as much energy as gasoline. Godfrey L. Cabot, founder of the parent corporation of Distrigas, saw the advantages of liquefying natural gas for transportation as a liquid to areas not served by pipelines and he obtained a patent from the U.S. Patent Office in 1915. However, it was many years before Dr. Cabot's idea became commercially significant. The development of the LNG industry took two distinct paths: one in the United States as a peak having gas supply and the other in Europe and Japan as a baseload gas supply. Let's look at the history and see what these terms mean.

Issue management is a process everyone engages in everyday. You may not think of it as issue management but consider it problem solving or crisis management. Issue management, as discussed in this paper, is the process used to identify, analyze, evaluate, and act on regulations, legislation, public concerns, actions by others, and decisions that affect all aspects of your business. The process may be accomplished as "part of the job" or it may be a specific, deliberate action. Issue management is not limited to oil and gas operators. It is important for all oil and gas entities including service companies, independent contractors and processing facilities. Issue management is extremely important to business because internal and external actions affect the manner in which business conducts its activities, from day-to-day operations to long-range planning. Specific choices must also be made by each company as to whether it will take a proactive or reactive role in dealing with outside influences and challenges. Issue management, or the lack thereof, is an economic decision. It affects daily operations and profitability. How you choose to be involved in the issue management process will impact the effectiveness of your participation. Are you proactive or reactive? In general, most companies and their managers and employees react to arising issues that could affect how they operate. With respect to the oil and gas industry, proactive issue management has historically been left to major oil and gas companies with staffs dedicated to the process or independents that have chosen to be more involved. Many companies who are not directly involved in managing important issues affecting their business rely upon those in industry who are dedicated to preserving reasonable business practices and on the trade associations to represent them and their interests. Those who are uninformed or choose to not be part of the process react to the changes, often not realizing that they could have influenced the outcome.

A discussion of conventional beam pumping units. Factors you should consider before installing a pumping unit on your well. Advantages and disadvantages of air balanced units will be presented.

Every producer longs to get a well which produces by natural flow when he drills his well. The reasons are quite clear: the costs of installation, equipment and operation are considerably less than for any artificial lift method which could be installed. In spite of these obvious advantages, there are few references to be found that concern themselves with the flowing well. The paucity of material is probably due to two causes.

Fifty-six waterflood projects are grouped according to the producing water-oil ratios (WOR) in effect at the start of polymer treatment. A relationship between barrels of polymer oil, amount of polymer and water-oil ratio is developed over a range of WOR's from 1 to 50. Projects singled out for special study include conglomerate, sand, lime and fractured reservoirs. Hall Plots and input profile surveys are used to show injection side changes due to polymer treatment. Oil recovery/WOR curves and time/rate graphs illustrate production side responses. In all cases the polymer treatment was designed to improve volumetric sweep of the reservoir.

You are working on a problem that has been my problem for nearly 40 years

Drilling practices have changed considerably through the years. When rotary drilling first started, drill collars (as we know them today) were unheard of. Bits were not designed for heavy loads and only the weight of the drill pipe with a crossover sub (called a collar) between the drill pipe and bit, supplied the drilling weight. The search for more hydrocarbons required penetration of deeper and harder formations and brought about the development of improved rotary bits with the need for additional weight to make the bit drill. In an effort to put more weight on the bit, additional drill pipe weight was slacked off putting more drill pipe in compression. This resulted in an increased number of drill pipe failures. It was discovered that when drill pipe is run in compression for bit weight, it buckles and is subject to severe bending fatigue resulting in these failures. This is due to the stress reversals in the thin wall of the drill pipe created by rotating the pipe in compression while it is bent. Using this theory another person developed the idea of using heavy thick-walled pipe between the bit and drill pipe to furnish the necessary weight for the bit. These joints of heavy thick-walled pipe were called drill collars, named after the crossover sub that had been used in the same position in the string. Only a few collars were used initially, but the quantity increased rapidly with improved bit design and deeper drilling. Very few problems were encountered when only six to nine drill collars were used; but connection failures increased rapidly with the running of additional collars, because the drill collars buckled under the additional drill collar weight. Drill collars differ from drill pipe in that the highest points of stress are in the connection, due to the tube or body being much stiffer and stronger than the connection. The use of special bottomhole assemblies to centralize the collars and stiffen the connections was unheard of at this time. Initially, not much thought was given to deviation. It was believed that if the kelly were held straight up and down in starting the hole, it would continue straight. No one realized holes were being drilled crooked until the development of the Seminole Field in Oklahoma in about 1928 and 1929. People started to be suspicious when some wells required considerably more footage of casing to complete than others. Since the wells were assumed to be in the same producing horizon, the geologists were confused. It wasn"t until two offset drilling wells actually intersected one another, causing numerous fishing jobs, that people realized that crooked holes were possible. They began to be concerned about the cost of the additional tubing and casing to complete these crooked holes, and deviation from vertical became an important factor in the drilling industry. It was at this time that the acid bottle came into use as a means of measuring the hole inclination from vertical. A bottle of hydrofluoric acid was lowered into the well on a line and allowed to sit long enough for the acid to etch the inside of the bottle. This wasn"t very accurate, but the approximate deviation from vertical could be determined.

Water quality is becoming a larger issue for the producer, as water production increases. Poor water quality in injection water can create plugging and loss of injectivity. It also can result in a loss of revenue due to re-injection of hydrocarbons. This paper will discuss issues of water quality. It will also detail how to develop effective monitoring locations and how to interpret results of water quality tests to determine effective treatment. Examples of actual production data will be provided to illustrate how improving water quality will result in increased revenue to the producer.