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Many of us today are being confronted with a new and different problem, that of obtaining maximum production from a given well. This problem can arise from a number of different sources. Perhaps we are starting a waterflood program and we need to utilize our present equipment as far as possible in the life of the flood or perhaps we are finding that out wells are making as increasing volume of water and that we must handle increasing amounts of fluid to obtain maximum production. In addition, there is the everyday problem of those of us who are responsible for equipment selection.

Dynamometer Analysis Plots allow the display of various parameters; both acquired and calculated, during a complete pumping unit stroke. At a user-specified time frequency, the polished rod load, polished acceleration, electrical motor power, and current data are acquired a during a dynamometer survey at a sucker rod lift well.

In this day of high costs and high speed of operation in the petroleum industry, it has become necessary that every person in the industry have an exceptional set of data and information to exercise his best wisdom. It used to be that a man had to have a lot of experience to exercise wisdom. But in this hustle and bustle of high speed economy an employee does not have time to obtain the necessary experience in this fast changing industry.

An instrument for pressure analysis to be used in well analysis and study has been needed for some time. A new instrument which can measure differential pressures in the range of 1.25 psi to 28 psi per mm, and a chart speed with an accuracy of .002 of one second is being used in well analysis. This type of study has much to uncover in this field. It could be compared with the first studies of the dynamometer used in rod pumping studies, 30 years ago. The paper will have examples of some of the studies pertaining to tests made on various hydraulic pumping systems.

After the initial studies and decisions have been made and the flood is started, it is then a matter of continuous checking and adjusting of volumes of input water in order to attain optimum results at the producing wells. In order to show how the dynamometer fits into the picture, we will use illustrations of actual cases. However, in the discussion of fundamentals, we shall briefly explain what the dynamometer is and what it does.

A reduction in maintenance and operating costs on pumping well leases can be just as beneficial as an increase in production. Tremendous savings are possible on may leases if a practical dynamometer survey is initiated. The dynamometer and related test data can offer the basic requirements for lease cost analysis. This paper will discuss numerous ways that a dynamometer can be applied to lease studies and will present examples of the resulting improvements.

Oil produced by pumping wells is a major source of income to the petroleum industry. The continual increase in operating and repair costs of pumping equipment has required more efficient and economical operation, in order to maintain a satisfactory margin of profit. Since the pumping well problem is often complicated, accurate analysis requires an exact and complete test procedure, and a thorough study of well data and test results. In order to facilitate testing of the problem pumping well, an organized dynamometer test procedure is presented.

The DynaPump is a unique rod pumping system that is composed of the pumping unit and the power unit. While similar to a Rotaflex pumping unit, the long stroke feature, it uses hydraulics as the lifting mechanism. The DynaPump offers several benefits such as the use of more efficient motors, smoother rod reversals, internal pump-off controller (better reservoir inflow control), etc. The field performance of a DynaPump system was evaluated on a recent well installation.

During 1997 a customer in Montana called to say that the dynamometer cards produced by the Rod Pump Controller (RPC) were swelling slightly. A swelling or distortion along the vertical axis (load) was noticed compared to the reference card. The horizontal component of the card showing position was changed very little (slight rotation). Was the apparent change in load real, or was the equipment faulty? During each stroke the RPC collects samples from load and position inputs. Pairs of load and position values are sampled every 5 milliseconds.

This paper presents field procedure, calculation techniques, and results of two gas well reserve tests utilizing bottom hole pressure drawdown and buildup data obtained with short duration production testing immediately after initial completion. Results of tests are compared with reserves indicated by subsequent pressure-cumulative performance. Both wells were gas discoveries in one-well reservoirs with extremely limited reserves.

Historically, maximizing completion and stimulation effectiveness in wells with multiple productive zones was hampered by lack of robust data. It is now possible to assess early-time zone-by-zone stimulation effectiveness (apparent fracture half-length) and reservoir quality (effective permeability-thickness) without the need, cost or risk of in-well operations, such as a spinner survey. This is accomplished by employing a series of molecular markers in each stimulation stage, which can be quantitatively analyzed over a sustained period of time.

For decades producers have fought the problem of lost pump efficiency due to downhole gas interference. Downhole pumps can lose 20% to 100% of published efficiencies due to free gas problems. This is especially true when the pump is placed above the perforations. To correct this problem producers have tried a variety of remedies. Some of the remedies, such as knockers, spring-loaded balls and backpressure valves. do not directly attack the problem. Although these tools have proven to be helpful in pump operations they do not solve the root problem.

Power consumption of an electric submersible pump installation may be categorized into three components, the energy required to perform useful work which is equivalent to the net hydraulic load divided by the product of pump and motor efficiencies, the energy absorbed by tubing friction which is equal to the dissipated hydraulic energy divided by the efficiency product, and power cable electrical losses. An improved design technique is presented which brings the two preceding categories of energy loss into economic perspective.

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.

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.

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.

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.

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.

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.

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.