Waterflooding in the Caprock Queen Field began with a pilot waterflood initiated in 1956. Today, essentially the entire field is under waterflood. There are 13 different projects in operation; eleven are units while two are of the cooperative type. All P3 projects have utilized 80- acre five-spot patterns. This case history is presented in order to depict the general performance of 13 successful Queen Sand waterfloods, and should be helpful in predicting the performance of other waterfloods that may be initiated in similar reservoirs. In many cases the engineer, is forced to use experience factors or "rules of thumb" in order to predict the performance of a proposed waterflood. When adequate reservoir, data is available he should, of course, make use of it in predicting performance. However, even after making calculations and the corresponding predictions, the engineer should attempt to compare his predictions with actual performance of other floods, either in operation or depleted, which are similar to the flood he is proposing. Quite often there are floods in the same field or in the same formation in a nearby field that are comparable to the proposed flood. A review of the performance of similar floods can be helpful, not only in designing the injection system and selecting a pattern, but also in making a reasonable predication of the performance that can be expected. The data used in preparing this case history was taken from reports published by the New Mexico Oil and Gas Engineering Committee.

This paper reviews the history of pilot waterflood projects in the Panhandle. It discusses specific floods and results obtained from them.

A waterflood pattern realignment project in the Grayburg / San Andres McElroy Field is improving the waterflood performance. This paper presents a case history of a 640-acre [259 ha] section of the field that was realigned in 1988. Irregular and widely spaced patterns were developed into smaller and more uniform patterns. The results of the realignment are proving the economic viability of realignment work at McElroy and are improving reservoir characterization.

Surveillance, in order for it to be effective, should be implemented through an organization with adequate staffing and technology. Engineering and field operations organizations should be complementary, providing for specific lines of communications, and yet at the same time encouraging informal personal exchanges between both groups. Surveillance of a waterflood project requires constant cooperation between the two groups in order to collect, document, and analyze an immense quantity of data, and carry out an efficient operation.

The Grayburg formation in the Johnson field, Ector County, Texas, is a more complex reservoir than originally believed. Poor response from waterflooding the J. L. Johnson "AB" lease with 40-acre five-spots led to development with ZO-acre line-drive patterns. This caused a substantial production increase. Infill drilling has lead to the discovery of random, anhydrite-filled sections which act as barriers to flow. They are probably interconnected and may be the cause of poor response to injection on wide spacing. Anhydrite barriers may exist both in other parts of the Johnson field and in surrounding fields. These barriers could play an important role in determining how other waterfloods are designed.

Electronic equipment is available for installation on electric motor driven beam pumping units which provides load and displacement data for a complete well analysis including rod stress, gearbox torque and downhole pump card calculations. The electronic equipment also monitors the load and displacement and shuts the well down for a predetermined amount of time when a pumped-off condition occurs and also shuts the well down and sets an alarm when a rod part is detected. When well data is needed for analysis the load and displacement data can be plotted on a dynamometer and at the same time the load and displacement data is recorded on an electronic memory card for replay into a computer. The electronic memory card records one full cycle of the pumping unit in equal time increments for use in gearbox torque and downhole pump card calculations.

When a well kicks, most well control methods recommend that the well be shut in to observe surface pressures. Many times this is not feasible. An operator must use judgment to determine when he cannot shut in. Underground blowouts can be created by merely closing in a well. To property control a kick, surface control equipment should be capable of handling large volumes of gas for a relatively long period of time. Bottom-hole circulating pressures can be calculated while circulating out a kick on the chokes. These calculations #en relieve the operator from having to shut a well in for pressures when loss of circulation is expected. Well control methods must be simple to be used infield work. Complicated methods requiring computers for solutions will never be entirely satisfactory for the field. A simple well control method readily usable in the field will be discussed. Calculations allow the operator to estimate the producing potential of a gas well while killing it. Use of proper gas handling equipment and good well control practices allow the operator to safely use underbalanced drilling to cut well costs.

Pioneer Natural Resources is currently undertaking a study of well casing failures in the Spraberry (Trend Area) Field located primarily in Midland County, Texas. Failure trend studies indicate a high incidence of external casing failures in the San Andres formation, a known saltwater-bearing and saltwater disposal formation that generally has substantial H2S content. Several well casings were selected as candidates for down-hole inspection logs to determine if cathodic protection could be a viable solution to the external corrosion problem. "Test" cathodic protection systems were installed and down-hole tools were utilized both prior to and after energizing the systems to assess the external condition of the well casing. Anodic/cathodic areas and axial current flow patterns identified on the logs were correlated to previously conducted cement bond logs, casing inspection logs and gamma ray/neutron logs as well as areas of externally coated casing. Based on logging results and economic evaluation, implementation of a cathodic protection pilot project commenced on November 27, 2001

In as much as those attending mar not be too familiar with the design and operation of a gas turbine, it would appear that a brief introduction to the unit would help the general understanding of the discussion. Having described the unit in some detail we find that the turbine lends itself to the oilfield industry primarily because it is a continuous duty unit most compatible with the continuous operation of the industry. Being air cooled, light weight, multi-fueled, simply controlled and easily packaged it is easily installed in virtually any location.

Increased drilling depths with resultant high pressures and multiple completions demand the well head manufacturers furnish equipment which is versatile and economical for all types of completions and pressure ratings. This paper discusses the various available well head components, and also presents a brief history of the evolution of the Christmas Tree from its early beginning to the present unitized well head.

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.