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. Every 50 milliseconds ten load and position pairs are digitally filtered and plotted to form a surface dynamometer card. For example, at 6 Strokes Per Minute (SPM) 200 points are collected to produce the surface dynamometer card plot. Load is plotted along the vertical axis, position along the horizontal axis to form a surface dynamometer card for each stroke. During RPC setup, a Base Card is collected for reference. A Current Card is drawn every stroke. Current Card load and position values are checked for both absolute value limits and rate of change violations. On-the-fly processing checks for conditions needing immediate response. End of stroke processing compares Current Card area to Base Card area, among other checks. The area enclosed by the surface dynamometer card is a measure of the polished rod workload for a complete stroke. Load measurements from beam mounted transducers, and position inputs from proximity switches supplied data pairs. The Base Card or reference card position input plot had been recorded during RPC setup using a continuous potentiometer. Prox switch position is fitted during RPC setup to permit comparing load and position values on Current Card with Base Card. Position data for Current Card is supplemented by SPM timing data to detect significant changes in stroke length. Beam mounted transducers do not directly measure rod string loads, but give a relative measure of beam deflection. The resulting measurements must be calibrated to provide useful data about rod string loads. Polished rod load cells can directly measure loads, but they are mounted in an area that is subject to damage (especially during workover). Polished rod load cells are also generally more expensive than beam mounted transducers. The acceleration and deceleration of long rod strings during a typical pumping unit stroke introduces more factors. Rod string dynamics introduce variables such as: momentum, vibration, rod stretch, buoyancy, valve pulsations, and noises both electrical and mechanical in nature. Load cells and beam mounted transducers challenge designers to produce consistent results needed for production analysis. Load spikes and other challenges need to be dealt with. Obtaining a reliable indication of rod loads during fluid production involves trade-offs. Beam-mounted transducers are mounted away from workover action. Welding or clamping is used to mount transducer on beam. Improper mounting can lead to inconsistent results. They are not as likely to be damaged as polished rod load cells. The joint investigation of customer concerns started by closely looking at the results to determine what was happening. The operation of the rod pump controller seemed to check out OK. The card swelling seemed to correlate with a real dynamic load increase. Further investigation by the customer showed that the well would need an emulsification treatment soon after the dynamometer cards expanded. The field results showed that results were somewhat consistent, and might be useful for scheduling emulsion treatments. Armed with this new information, the conditions were investigated to see what could be done to harness the observed changes and make a useful tool.

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. When used with the subsequent commingled total well production and the fracture closure flow periods, a pressure transient drawdown analysis provides the necessary descriptive knowledge. In many cases, additional information can also be gleaned regarding zone-by-zone free water contribution. Example stimulation results will show the effectiveness of this procedure. The paper will demonstrate the effectiveness of this technique and the value operators garner from it.

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. Gas interference in reciprocating pumps causes lost production. premature pump failure. rod parts and excessive wear on surface equipment. Other types of lift equipment are also affected by gas interference. Progressive cavity pumps require liquid to lubricate and cool the polymer sealing materials. Free gas will greatly decrease the efficiency and life of these pumps. This is also true with submersibles as they require a constant flow of fluids for motor coolant. The most common downhole separator is made from materials found in pump yards. A joint of pipe is perforated and orange pealed on the bottom. This is attached to the seating nipple or lower barrel coupling and a dip tube is attached to the pump. Gas separation takes place between the dip tube and inside diameter of the perforated sub. This tool is often called a "Poor-Boy" gas separator (Fig 1 ), The Fluid efficiency of this separator is limited to about 50 BPD due to the limited space between the dip tube and outer case. Pressure differentials created by the upstroke of the pump add to the tools inefficiency. On the upstroke a pressure differential is created between the inside of the separator and tube casing annulus and fluids flow into the gas separator. Fluids surrounding the separator often contain 75% free gas. Considerable mamounts of gas are drawn into the separator and very little separation takes place due to the pressure differential. In a conventional "Poor-Boy", most of the fluid and gas flow occurs on the tip stroke and most of the gas discharge occurs on the domnstroke creating low efficiency.

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. The interrelated effects of tubing friction, voltage drop and motor voltage on ESP power consumption are demonstrated, as is the degree of desirability for using a motor of the highest available voltage. An equation is developed for calculating power consumption for combinations of tubing size, power cable size and motor voltage, which is useful in making economic evaluations of alternatives. Variations of power consumption are illustrated graphically for various combinations of tubing size, power cable size and motor voltage. Also illustrated is the effect of the nature of a specific net hydraulic load, i.e. the product of rate, lift and specific gravity. Practical examples utilizing the design techniques herein developed are presented and comparisons are made to designs based on common practice.

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.