A short history of the development of ground water sources for waterflooding programs is given. The gradual trend from deep brine sources to shallower fresh or brackish water sources is discussed. A review of the development of the concept of a royalty, or in-place value in acquisition of water rights is presented. Finally, an analysis of cost data in developing, producing and transporting water is discussed in relation to present level of delivered prices for fresh and/or brackish water.

All factors involved in waterflooding, as in any business venture, are influenced by economics. Obviously, consideration of each is essential to a successful operation, for without complete comprehension of each, a failure may result that otherwise could have been foreseen. The factors are complex and interwoven within each other; however, they can be generally categorized into three areas of major delineation, i.e. (1) evaluation and/or acquisition, (2) cost estimation, and (3) effects of restricted production as impose by insufficient financing and/or state regulatory body control. This paper will attempt to briefly discuss the constituent parts of these factors and present certain average values resulting from actual field operations. Some of the values may serve as useful criterion in evaluation of a prospect's flooding potential, but the engineer is forewarned that "rules of thumb" figures such as these are useful only in specific application and are not intended for any other use. The individual factors vary considerably due to features such as depth, well spacing, well density, field symmetry, geology of pay zone, water supply, power supply, etc.; however, it is hoped that some of the figures will be useful to the engineer when applied to comparable floods.

There are usually two or more methods by which any well can be lifted. Proper artificial lift selection requires an objective economic comparison of all possible methods. Too often one or more methods are eliminated because of prejudice, ignorance, or fear of new or different types of lift. When a well first requires lift, any type lift selected will, of course, show a quick payout; however, a comprehensive study may result in several thousand dollars savings during its productive life. As it becomes necessary to "pump" from deeper and deeper depths, the necessity for proper lift selection become more important. The production engineer has two goals in the selection of artificial lift equipment. His primary purpose is to select equipment which will deplete a specific well. His second aim is to select equipment which will result in the most economical depletion. The lift with the cheapest first cost is not necessarily the cheapest depletion.

The Beam Gas Compressor (BGC) casing pressure reduction system is now being utilized as a low cost gathering system for leases that respond to a reduction in back pressure on the formation or needs low pressure gas forced into the sales line. The BGS is installed on a centrally located Pumping unit in the field and lines from adjacent wells are laid from their casings to the casing of the Pumping Unit where the BGC is installed. The accumulated gas from all these wells is pulled into the BGC and compressed into the flow line or directly into the sales line. Utilizing the energy derived from the Pumping Unit to drive the BGC to compress these wells saves on the utility cost of compression and the reliability of the Pumping Unit as the prime mover gives a steady day to day compression system.

The application of electricity for oil field power is becoming more prevalent each day. It is used by rod pump wells, triplex pumps for hydraulic pumping, circulating pumps, automatic lease control systems and various other equipment. It is the purpose of this paper to discuss certain factors affecting the economical use of electric power by rod and hydraulic pump wells.

The use of hydraulic pumping equipment to artificially lift producing wells is on the increase because of new equipment being developed; multiplicity of wells requiring lift; and new operating concepts. Certainly for overall acceptance the artificial lift method must be economically advantageous for the operator. Specific examples will be included to show the economics which favor hydraulic pumping. As important; and one of the factors which reflect savings in initial installation of equipment and monthly operating costs, is the extreme flexibility offered by hydraulic pumping. Installation of equipment can be staged and need be made only at the time it can be fully utilized; therefore, there is no need for expensive changes for equipment obsolescence during lift life. The flexibility is further illustrated with the centralization of battery equipment to gain more effective use of available horsepower and directing high pressure power to wells through satellite stations. This paper will also discuss closed power oil hydraulic pump systems as this method is receiving increased attention and acceptance. The cost of the additional tubing string required can, in many instances, be offset by a reduction in treating facilities. The many advantages of closed power oil systems will be outlined and current installation practices reviewed.

Developments forcing attention to testing

As the search for new and more petroleum reserves forces the oil companies to drill deeper wells and to operate in more remote areas of the world, the cost per foot of drilling holes naturally increases. In order to continue to supply industry and the public with economic energy products, the petroleum industry must continually search out means of lowering and controlling drilling costs. One means of lowering drilling costs is to increase the on-bottom rotating time per day by reducing the number of trips required to change out bits. This has been accomplished in many fields around the world with the use of long-life diamond bits. Diamond bits are being used today to drill less expensive and safer wells. Downhole motors play an important part in many diamond drilling situation. A quick and easy method for determining the drilling economics for diamond bits will be discussed in this paper. Included will be the use of diamond bits in conjunction with downhole motors as well as with conventional rotary.

Production people occasionally have to calculate the most economical way to lift oil. This study is designed to discuss the factors involved and some typical cost figures of oil production. The factors here are the common ones. For a specific case some special factors may need to be considered. Each case is unique, and, as such, should be studied.

A discussion of the economic considerations involved in vapor recovery unit design, including basic design criteria, economic analysis, and case histories.

Considering today's high operating costs most producers are constantly in search of ways to save money. Downhole production tubing represents one of the more sizable investments that the operator will make when putting a well on production. Often the costs involving the tubing string does not end with that original investment. During the service life of tubing, it is subjected to various environments and stresses which result in degradation of the integrity of the material. Tubing frequently fails in service due to development of various types of defects, such as those found in Fig. 1. This necessitates the investment of more monies in workovers and material replacement. While the well is down, the producer suffers with loss of production.

In February 1955, the first water was injected into the Grayburg Dolomite in the South Cowden Field. Four injection wells and one producing well on the Paul Moss et ux Lease of Forest Oil Corporation formed the first 40-acre 5 spot. In the past ten years additional injection wells have been drilled and several wells converted to injection service for a total of 49 active injection wells (includes 17 line injection wells with offset operators) in the 3,354.3 acre Paul Moss et ux lease waterflood. The successful performance of the waterflood, which is operated under the proration rules of Texas, is attributed to the planned development rate, the pattern chosen and experienced waterflood operation. The economic picture which is presented in the paper, shows that profitable development and operation will continue for at least 18 more years; the cost of producing waterflood barrels is greater than for primary barrels on the basis studied.

Presentation of a simple graphical method of retaining all the advantages of a balanced rod string design and still obtaining maximum economy through full utilization of allowed rod stresses.

After selection of the most economical type of prime mover to operate a pumping unit is made, is it not true that we sometimes fall short of our duty to see that equipment we select does the most economical job for us? For the purpose of this paper, let us consider the economic aspects of only electrified leases. The reason for properly supervising a lease are many, and it usually is the small things, as well as the large things, that count. For convenience let us divide the economic problem into three general categories. First, "Mechanical Resistance Present", second "Electrical Characteristics Present", and third, the proper application of equipment, power, and knowledge to have at our disposal.

Wide varieties of solid chemical sticks, when properly used, can be cost effective and increase production of gas wells. Determination of the right solid chemical stick is crucial for all applications. Analysis of water, oil, and determination of fluid column height, hydrocarbon content, chlorides, and bottom hole pressure and temperature are used to determine the proper formulation of solid chemical sticks. For economic reason you can follow the 25-30% removal principal when using soap sticks. It is not unusual to find that if 25-30% of the water column is removed by soap sticks, an equal amount of back psi (25-30%) is eliminated from the formation. This allows a surge of gas that helps remove some additional water for a period of time. This is again achieved by proper selection of solid chemical sticks.

Life long learning doesn"t stop with the high school or college diploma. In the high tech fast paced petroleum industry training is a must. Traditionally research organizations within operating, service and supply companies have been the primary source of this continuing education process. There are numerous outstanding alternatives for updating ones skills. The petroleum service, supply and education sectors have committed training resources to fill the gap left by operators. Enhancements to this education process acknowledge that individuals learn best by incorporating all senses - hearing, sight, sound, touch, and smell when ever possible. The use of computer and web-based training allows users to go at their own pace. As the aging workforce (currently 49+ years) leaves, more training will be demanded to supplement the lost experience. This paper will survey currently available petroleum sources of learning and by three examples project future directions of this vital sector of the industry.

Whenever any piece of equipment is overloaded or abused, some degree of deterioration is inevitable, and this same principle will apply to pumping unit reducers. This paper will outline and illustrate the effects of abuse from the standpoint of seeing a result and then establishing a cause.

Experience in the Jameson (Strawn Reef) Field has shown that back pressure imposed by inadequate flowlines, unnecessary valves and fittings and high trap pressures can be very detrimental to intermittent gas lift production and efficiency. As a result of minimizing back pressure, individual wells in this field have shown substantial improvements in production and injection gas-liquid ratios. Various methods of reducing back pressure are discussed, and a guide is presented to aid in selection of proper flowline sizes for intermittent gas lift wells.

This report documents results of a study to determine whether brine and CO2 injection significantly changes total porosity in a dolomite reservoir. Pre- and postpilot cores from closely-spaced wells in the Shell Western E&P Inc. Denver Unit CO, pilot provided the necessary data. We concluded that only minor porosity enhancement resulted from brine dissolution of anhydrite. Detailed petrographic examination of thin sections provided the modal composition (bulk mineralogy, total porosity and pore types) of 112 samples. This data was evaluated by statistical methods (t test) to determine the significance of any change in porosity at a given confidence level. Large vugs, channels or other evidence of high permeability thief zones, created by carbonic acid dissolution of the dolomite, were not observed in the postpilot core located 25 feet from the pilot injection well. However, minor anhydrite dissolution is documented from both chemical analyses of the pilot flood water and thin sections. These results are significant when one considers the large brine and CO2 injection volumes (approximately 90 pore volumes of brine and 30 pore volumes of CO,) that contacted the postpilot core. In addition, minor amounts of solid hydrocarbon were observed to occlude porosity in seven thin sections from the postpilot core. As a result of anhydrite dissolution, total point-counted porosity is slightly higher in the postpilot core but not statistically significant. Our results appear to refute Chevron's (SACROC) concerns that carbonic acid would aggravate reservoir heterogeneities and cause channeling detrimental to area1 sweep.

The purpose of this article is to review the effect of fluid buoyancy has on rod stresses and rod loads. The hydrostatic pressure caused by the tubing fluids has an impact on rod stresses at the rod element level. Use of the Downhole Load Cell data can help resolve the question: What is the magnitude of the loads displayed as the downhole pump card? The efkkive force on the rods is the ideal method to display of the downhole pump cards. Some discussion will be based on dynamometer data collected on an Amerada Hess well in conjunction with SANDIA using the Glen Albert Downhole Dynamometer. The purpose of this paper is to dim the true/effective load versus stress argument for display of downhole dynamometer data and analysis of stresses on a rod element.

The process of hydraulic fracturing has been used extensively for well stimulation by the petroleum industry for over two decades. During this time the ability to successfully execute a fracturing treatment has increased to the point where very few mechanical failures currently occur. In addition, the development of treatment design and evaluation procedures has evolved to the point where fracturing is now considered a science rather than an art. As the science progresses, new problems concerning the design and evaluation of optimum fracturing treatments arise frequently. One of the most pertinent of these problems is what effect incomplete fracture fill-up at the wellbore has on productivity ratio. Solution of this problem will be useful in treatment planning to accomplish desired production goals. The purpose of this paper is to evaluate the effect of incomplete fracture fill-up at the wellbore on productivity ratio, and to present the findings of a controlled screen-out fracturing program which was initiated for the purpose of obtaining field results to substantiate the theory presented in the paper.

When interpreting the output of wave equation based computer programs, one must be able to accurately detect problems and recommend solutions. Several papers have been published describing techniques for calculation of gearbox loading, rod stresses, and downhole pump dynamometer cards. Included in these papers are downhole dynamometer card shapes corresponding to common pump problems that can be compared with calculated pump dynamometer cards to determine what is wrong with the pump* However, these techniques assume that the input data is correct. This paper addresses interpretation errors that occur due to wrong input data. It discusses the effect of input data errors on key calculated parameters and how the analyst can detect them.

Subsurface equipment such as sucker rods and pump parts are subjected to the combined action of cyclic service loads and corrosive fluids simultaneously, often causing failure due to corrosion fatigue. Organic inhibitors are widely used to prevent failure resulting from corrosion fatigue. There is, however, little or no data to show the nature and the extent of the effects they produce on the course of corrosion fatigue per se. This investigation deals with some of the variables that affect the corrosion fatigue performance of carbon steels in the presence of organic inhibitors.

Slurry transport and settling experiments were conducted to improve current descriptions of proppant transport. Results of these experiments were used to formulate a new slurry transport model which was incorporated in a fully three-dimensional fracture simulator. The model was tested and verified against experimental observations of slurry transport in a 4 foot by 16 foot slot model. Results of the study indicate that proppant slurry transport can be accurately modeled when the effects of single particle settling, density driven flow, particle velocity profiles, and slurry rheology are accounted for. When the generation of fracture geometry is fully coupled with slurry transport, major alterations in the predicted final propped fracture are observed. Examples are provided to demonstrate the importance of proppant scheduling in controlling the final placement of proppant in hydraulic fractures.

Foams used as fracturing fluids for formation stimulation are mixtures of compressed nitrogen gas and a base liquid. The quality of a fracturing foam refers to the volumetric gas content of the foam and is usually in the range of 65-95 percent. The addition of sand to a fracturing foam can have a significant effect on the actual flow rate of the base liquid at the surface. This effect on the surface will change the foam flow rate and foam quality desired down hole. The hydrostatic pressure exerted by the fracturing foam will also be effected as sand concentration changes. Using the true volume of sand as a basis, several equations are presented in this paper which will compensate for the effects of sand concentration in foam. A well designed foam frac job is necessary for proper implementation of the stimulation treatment.