The science of business management has progressed as rapidly in recent years as the science of engineering. However, much of this knowledge has been utilized by only the larger businesses with professionally trained managers. The manager of a small business has frequently come from another profession, such as engineering, and was not exposed to management training during his formal education; and since going into business for himself, he has had neither the time nor the financial resources to m-educate himself in the field of business management. Fortunately, many of these managers by experience, observation, or perhaps native intelligence have acquired and put to use much of this new knowledge. Because this knowledge is essential to survive in competition with larger and better-financed competitors, the more successful small companies have acquired the knowledge through some source. The purpose of this paper is to present some of these new management practices and show how they apply to a small business. Since many of the readers are from the consumer side of the oil industry, I shall also point out some recognition symbols of a well-managed company. This will assist the buyer of goods and services in identifying the well-managed companies to use, because good management results in fair prices, good service, and a quality product.

Flowmeters available to the petroleum industry fit into a wide range of operating principles and are diverse in the physical phenomena employed. Flow measurement may be made from (1) velocity, (2) mass transfer rate, (3) volumetric transfer, or (4) interference. Our industry pumps fluids that range from (1) clean, homogenous newtonian to (2) heterogenous non-newtonian slurries. Application of flowmeter type to fluid type requires more than casual attention. This paper presents a summary of flowmeter types currently available and gives advantages and disadvantages of each. Included in this technology survey are (1) flowmeter types, (2) operating principle, (3) range of accuracy, and (4) proper application of each. The conclusion is reached that flowmeter choice is not as straightforward as users may have been led to believe, however, an informed user can select a meter that will give the best available service.

An experimental paraffin control technique has been developed and tested in several West Texas Chevron operated leases producing from the Spraberry formation. The results were encouraging. The methods described below provide a structured framework for testing and analyzing paraffin control and for applying the procedures developed.

A recurring problem in foam fracturing is sand suspension; i.e., the suspension of high sand concentrations in the liquid phase of a foam frac system. A process has been developed which enables the liquid phase to be pumped directly from the blender to the high-pressure pumps without recirculating to suspend high sand concentrations. This process for foam frac is improved by using a unique gel-gel breaker system for the liquid portion used in generating the foam. The advantage of this system is that more sand may be carried in the liquid portion, which means that more sand can be delivered downhole, which in turn delivers more sand to the fracture. resulting in more of the created fracture being propped. The liquid portion of the fluid is divided into two portions. The main liquid portion which carries the sand is modified by hydrating a cellulose-type polymer in water to form a viscous gel. The viscosity of this gel is such that high sand concentrations can be carried without recirculation. The other smaller portion carries a foaming agent and a gel breaker. When the two liquids are combined, the viscosity of the gel breaks immediately. Nitrogen gas is then added downstream to generate the foam as shown in Fig. 1.

Pressure buildup analysis has been used for many years to evaluate the performance of wells and estimate the properties of reservoirs. Usually, the application of pressure transient theory to the evaluation of well tests requires that accurate bottomhole pressure measurements be made. In the case of a well producing by beam pumping, the direct measurement of bottomhole pressures is impossible, since the presence of the pump in the tubing physically precludes the use of wireline pressure gages and permanent downhole pressure installations are usually not economically attractive. For this reason, indirect bottomhole pressure measurements are usually made by measuring the annulus pressure at the surface along with the fluid level in the annulus. From these measurements and the fluid densities, the bottomhole pressure may be estimated with an accuracy depending on the accuracy of the estimated fluid properties and the measurement accuracy. This procedure has been criticized, since the pressures being analyzed are not directly measured and the accuracy of the data and estimated fluid properties limits the analysis precision. This report documents an improved evaluation method for wells producing on beam pumps. Instead of indirectly calculating the bottomhole pressure, the wellbore is modeled and the analysis is performed directly on the measured data. Since both casing pressure and fluid level are measured, the number of data points is essentially doubled over standard well testing and the accuracy of the analysis can be judged by comparison with the actual measured data. In addition, since the casing pressure appears to be mainly affected by wellbore effects, the evaluation accuracy is improved even more than would be expected from statistical considerations alone.

Cement squeezes have been used for many years for various operations such as casing leak repairs, sealing of thief zones, and zonal isolation. While they have been successful in many of these operations, they often require more than one attempt before success is achieved, or they are not successful at all. This paper presents the development of a system based on a combination of a porosity-fill sealant with particulates. The particulates provide leakoff control, which leads to shallow matrix penetration of the sealant. The main advantage of this system over cement is that the gel remaining in the wellbore can be washed out of the hole, and does not need to be drilled out as is the case with cement. While this system has previously been reported, this paper presents improvements in the fluid-loss system as well as additional information on case histories.

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In the past, in wells that were candidates for fracturing or acidizing treatments, it was found that the use of temperature and radioactive material were very beneficial in evaluating where the fluid and propping agents, if any, were located in the formation. Both of these methods had their drawbacks. This paper deals with overcoming some of the problems associated with radioactive material only. An automatic system has been designed for pumping fluid into the frac line (pressure side) using an ion exchange resin as the isotope carrier to improve evaluation of the fluid and or proppant-laden fluid moving into the zone. Also, this procedure eliminates some downhole contamination problems which have caused difficulty in interpreting staged stimulation work.

Over the last thirty years various polymers have been added to water to create the base fluid used in fracture stimulation treatments. Advances in improving these base fluids have been concentrated on developing polymers which are relatively free from damaging residue, while retaining the properties required to achieve the designed viscosities. Little attention has been focused on the effects of mixing these polymers under field conditions, where the majority of the hydration process is taking place in the low shear environment of large frac tanks. Recently, a method has been developed to improve the actual hydration process of standard fracturing polymers. Through this process, a higher quality and more predictable base fluid can now be delivered to the well site. The mixing of the base fracturing fluid is now much less susceptible to the harsh mixing conditions found in the field. As a result of better control of the base fluid quality, better overall fracturing designs can be successfully pumped.

The vast majority of new wells being drilled for both oil and gas production are horizontals. At some point most of these wells will require artificial lift to produce the liquid hydrocarbons and/or dewater the gas wells, but artificial lift of horizontal wells presents many challenges. Artificial lift can be particularly challenging in the shale assets in which the wells are often deep with long lateral sections.
To address these challenges, the Artificial Lift R&D Council (ALRDC) invited a large number of companies to form a Consortium to develop new methods and understanding for advancing artificial lift of these wells. This Consortium is being led by the University of Tulsa. This paper discusses the status of this effort and presents some of the challenges that the members of the Consortium
are facing.

In the oil field industry drilling, completion, and production are all the responsibility of different departments. Each phase in the life of an oil or gas well is being scrutinized and restructured as an independent event. Oil and gas wells are typically drilled, completed, and put on production with an emphasis on completing each task in a manner to minimize costs. If a problem is created in either the drilling or completion operation, the production department will be forced to deal with results of the problem which can last for the well's lifetime. This paper deals with a novel approach that treats the well for production issues during the completion/stimulation stage of the well. There will never be a better opportunity in the well's lifetime to treat production issues before they occur. This is true for both wells with a single set of perforations and multi-perforated completions. However the production problems are magnified in wells producing from multiple sets of perforations. This process has been applied to the Wolfberry which is typically a multi-stage completion, but is applicable to essentially all wells. The formation during this treatment is in as near a virgin state as is possible. Never again will the opportunity exist for treating the well in this state.

Gas problems can cost a company valuable time, money and resources. The presence of gas in the pumping zone causes various problems like gas lock, gas pound and gas interference resulting in reduced pump efficiency and pump failures. In order to overcome these problems the in-house research department developed and patented an innovative design called the Don-Nan Gas Separator, which diverts the gas away from entering the pump intake and thus reducing pump failures and improving the pump efficiency. The major topics of discussion are: 1)Review of the problems that are encountered in gaseous wells. 2)Working principle of "Don

The use of permeability tensors is required for modeling fluid flow in anisotropic and heterogeneous reservoirs that present multiple zones of directional permeability or those categorized as naturally fractured reserv0irs.A general procedure for characterizing complex reservoirs by integrating data and methods from different disciplines, and utilizing the permeability tensor is presented. Permeability tensors for geologically defined fracture patterns are derived, and these small-scale descriptors are incorporated into a reservoir simulation program capable of handling full tensor permeabilities. A series of numerical experiments are designed and conducted to observe what would be the influence, over a typical waterflood process in terms of fluid distribution and water break-through times, when variations to the properties that define the permeability tensor are intr0duced.A correct definition of the geometry and the permeability tensor distribution of the fracture system results in a more accurate reservoir simulation model.

Infill drilling of wells on a uniform spacing, without regard to reservoir performance and characterization, must become a process of the past. Such efforts do not optimize reservoir development as they fail to account for the complex nature of reservoir heterogeneities present in many low permeability carbonate reservoirs. These reservoirs are typically characterized-by: -Large, discontinuous pay intervals -Vertical and lateral changes in reservoir properties -Low reservoir energy -High residual oil saturation -Low recovery efficiency. The operational problems we encounter in these types of reservoirs include: -Poor or inadequate completions and stimulations -Early water breakthrough -Poor reservoir sweep efficiency in contacting oil throughout the reservoir as well as in the near-well regions -Channeling of injected fluids due to preferential fracturing caused by excessive injection rates -Limited data availability and poor data quality. Infill drilling operations only need target areas of the reservoir which will be economically successful. If the most productive areas of a reservoir can be accurately identified by combining the results of geologic, petrophysical, reservoir performance, and pressure transient analyses, then this "integrated" approach can be used to optimize reservoir performance during secondary and tertiary recovery operations without resorting to "blanket" infill drilling methods. New and emerging technologies such as cross-borehole tomography, geostatistical modeling, and rigorous decline type curve analysis can be used to quantify reservoir quality and the degree of interwell communication. These results can be used to develop a 3-D simulation model for prediction of infill locations. In this work, we will demonstrate the application of reservoir surveillance techniques to identify additional reservoir "pay" zones, and to monitor pressure and preferential fluid movement in the reservoir. These techniques are: long-term production and injection data analysis, pressure transient analysis, and advanced open and cased hole well log analysis. The major contribution of this paper is our summary of cost effective reservoir characterization and management tools that will be helpful to both independent and major operators for the optimal development of heterogeneous, low permeability carbonate reservoirs such as the North Robertson (Clearfork) Unit.

A cooperative study of the Grayburg"San Andres reservoir is being conducted in response to the United States Department of Energy's (DOE) Class II Oil Program. The project is cost shared by Laguna Petroleum Corporation (operator) and the DOE. The purpose of this study is to preserve access to existing, wellbores by identifying additional reserves. Production problems associated with shallow shelf carbonate reservoirs are being evaluated by a technical team integrating subsurface geological and engineering data with 3-D seismic data. Engineering analysis. subsurface control from wireline logs. and 3-D seismic data will be integrated using a network of state-of-the-art software on a high performance computer workstation. The results of the integrated effort will be a recommendation for infill drilling locations and the design of an effective waterflood. It is expected that this study will demonstrate a methodology for reservoir characterization and subsequent development of the Grayburg and San Andres reservoirs that is feasible for even small independent operators. The integrated multi-disciplinary approach of reservoir evaluation is relevant to many shallow shelf carbonate reservoirs throughout the United States. Furthermore, this study will provide one of the first public demonstrations of the enhancement of reservoir characterization using high resolution 3-D seismic data. This paper discusses the geological makeup of the Grayburg and San Andres reservoirs and the acquisition, processing,. 0 and interpretation of the 3-D seismic data set acquired for the project. The 3-D seismic volume will be utilized for optimization of a reservoir simulation model through a quantitative study to extract reservoir properties from seismic attributes.

A cooperative two-phase study of the Grayburg/San Andres reservoir is being conducted in response to the United States Department of Energy's (DOE) Class II Oil Program. The study's purpose is to preserve access to existing wellbores by identifying additional reserves. Phase I was an integrated Geological, Geophysical, and Engineering study to determine if state-of-the art technologies, including 3D seismic and sequence stratigraphy, could be integrated into a reservoir simulation to enhance oil recoveries in this 66 year old field. At the end of Phase I, recommendations for new drills, deepenings, and workovers were made. Data gathering in Phase II included taking cores in three new drills to evaluate stratigraphy, running pressure buildup and production tests and injection profiles in existing wells, and RFT's and modern log suites in new drills and deepenings to evaluate reservoir conditions. Attribute analysis of the 3D data was integrated into the decision making process during Phase II. The results of three new drills, one deepening, four workovers, and two conversions to injection were to increase production by 50%. Injection water quality has been improved and a waterflood realignment implemented.

A detailed study of fluid mechanics in well stimulation is presented in this paper. The importance of density, viscosity, friction loss, compressibility, fluid loss or leak-off and sand carrying ability (gel strength) in designing and performing fracturing treatments will be discussed.

In recent years, the cementing industry has embraced the concept of right-angle-set as a desirable feature in the thickening time set profile of oilwell cements. Right-angle-set can be characterized as the rapid thickening of a cement slurry from a stabilized viscosity to a final set of 70-l 00 Bearden Units of Consistency (Bc). This is a dynamic-state phenomenon that usually takes place in the final 30-45 minutes of thickening time. Cement slurries exhibiting right-angle-set thickening time profiles were generally thought of as being preferable over slower "gel" type sets. However, within the practicalities of field operations, rarely is the cement still being placed while right-angle-set is occurring. More commonly, the cement slurry is mixed and displaced in only a fraction of the designed thickening time. How then does right-angle-set, a dynamic-state event late in the pumping history of the slurry, influence the static-state properties of the slurry, when placement is completed before the onset of right-angle-set? Presented are the results of conventional, low shear, and modified-hesitation-squeeze thickening time testing, combined with operating ultrasonic strength analysis, to quantify the differences in right-angle-set slurries as compared to cement designs with slower setting profiles.

An easy-to-understand method of analyzing the performance of existing waterfloods is presented and its is demonstrated with examples from West Texas and other areas. Example projects having both favorable and poor performance are shown. The recommended technique requires a detailed description of reservoir properties such as net thickness, porosity, oil and gas saturation, and compilation of individual wells' production and injection history. Graphic displays are used to define efficiency of individual flood elements. Comparison of elements within a waterflood are made to determine relative efficiency and further, which elements need an overhaul or are candidates for infill drilling. The calculation procedures are based on a simplified material balance, decline curve analysis , water-oil displacement efficiency, and pressure performance of injection wells, but are easily hand done, not requiring computer assistance.

A basic decision faced by all oil field investors, since reserves are continually being depleted through production, is to either add reserves through drilling, enhancement and/or acquisition, or go out of business. The data available on finding costs indicate that it has usually been cheaper to buy rather than drill for reserves in recent years. This comparison may be distorted since the true finding cost is not known until the discovery is fully developed, which usually takes years. However, it is obvious from the data that the current decision is normally to buy, not drill. Hence, the drastic drop in rig count continues, while the number of acquisition transactions continues to be strong.

Electric Submersible Pumping Systems are being specified more frequently as the means of artificial lift for both new and existing wells. With this increased use, many operators may not understand the proper selection, installation, operation, maintenance and troubleshooting related to the Electric Submersible Pumping System. This understanding is important in assuring a successful Submersible Pump operation. The purpose of this paper is to give an overview of some of the recently published Recommended Practices on Electric Submersible Pump installations and also to comment on additional work currently being done in this area.

In recent years, the use of foam has proven to be successful in drilling underpressured formations where conventional drilling fluids have been unsatisfactory. On the E. 0. Reed Well No. I-A, foam was successfully used by Getty to drill and complete an underpressured formation at a depth of over 22,000 ft. This presentation includes a discussion on the background of the E. 0. Reed I-A and how foam was selected as a drilling fluid. Also discussed are foam characteristics, foam components, planning and design considerations, foam drilling operations, results of the well completion and conclusions of this study.

Failure control is a critical path to optimizing operations in today's petroleum industry. Failure control in its simplest form is failure analysis with the goal of achieving corrective action. Accurate records and meaningful reports are a key part of any failure control program This paper is the third in a series involving the data gathering and processing system used by Atlantic Richfield to optimize production operations and discusses the new PC system version. Application is demonstrated by identifying some rod pumping problems, suggested solutions, and results.

A full-scale, transparent, laboratory, instrumented sucker-rod pump has been constructed to aid in designing a downhole, instrumented pump. The laboratory pump has demonstrated that key to the understanding of sucker-rod pumping is compression-chamber pressure. Laboratory data will be used to demonstrate real-time analysis techniques that will be used with the downhole, instrumented pump to differentiate between a gas-locked or a pumped-off well using compression-chamber pressure. For a gas-locked well, the pressure is symmetric between the upstroke and downstroke; where as, for a pumped-off well there are high and low pressure plateaus when the valves are open. A method will be demonstrated to determine sucker-rod pump fillage by cross plotting (Pressure)-1/r versus stroke (g is the heat capacity ratio). The intercept of the compression line and stroke gives pump tillage. Theintersection of decompression and discharge pressure can be used to determine the residual gas trapped between the standing and traveling valves at the end of the downstroke.

The oilfield has long been known for doing things "the way we have always done it". This approach can change dramatically using new technologies and analysis methods. New technologies and analysis methods can be used to determine what is wrong with an artificial lift system; the operator no longer need to assume and take action based on a faulty assumption. Fluid level data is acquired throughout the patch, only proper analysis and use of the data allows the operator to exploit the well to its fullest potential. Typically dynamometer data is not requested until an operator has pulled and replaced the pump with no improvement. Acquisition and analysis of fluid level and dynamometer data can be used to determine if: 1) the well is producing to its maximum potential, 2) the down hole pump is operating as expected.
Examples well data collected on various wells will show opportunities for improvement, more production, more effective operation and fewer pulling jobs.