In recent years there has been a great deal of interest in the use of propellants to generate high pressure gas pulses for fracturing hydrocarbon bearing formations. Mulch of the R&D effort in these Dynamic Gas Pulse Loading (DGPL) techniques has centered around their ability to induce multiple radial fractures in naturally fractured reservoirs, thereby greatly increasing the probability of intersecting fractures. Servo-Dynamics, Inc. has taken a somewhat broader approach to DGPL and through several thousand practical field applications, has also shown the process to be a valuable aid in the workover and completion of conventional cased-hole wells. By inducing multiple fractures with very limited vertical growth, DGPL has proven to he very effective in the breakdown of tight zones, overcoming skin damage, and stimulation of zones water, among other things. In most applications success rates of over 90% have been achieved, at times permitting the production of zones which-otherwise could not have been completed. Following a review of the state-of-the-art this paper presents the basic principals underlying DGPL stimulation, its strengths and weaknesses, and documents its effectiveness in various applications through case histories. Finally, basic guidelines are presented for evaluating if a well could benefit from a DGPL treatment.

As often discovered, determining downhole pump conditions by visual interpretation of a surface dynagraph card can be very difficult even for highly trained personnel. In addition, visual surface interpretations are more qualitative than quantitative. With the computerized method, surface measurements (load and displacement versus time) are used to calculate a downhole dynagraph card that is quantitative and much more easily interpreted. Basically, the computer program takes surface rod loads and displacements and removes rod weight, dynamic effects (harmonics) and rod stretch. The result is a pump card. Intermediate downhole cards are also calculated at critical stress points in the rod string such as at the junction points in a tapered rod design. Thus, rod taper designs can be easily evaluated. Besides calculating downhole conditions, measured data are also used to analyze surface equipment loading such as gearbox torque, prime mover loading and structural loading. All calculations can be made in a matter of minutes on the well site. Thus, conclusions can be drawn and changes can be initiated immediately for increasing production and/or reducing operating costs.

The full scope of two-phase producing problems extends from sand-face to separator, offshore to onshore. Both operational and design decisions are being made daily which require a thorough understanding of two-phase flow. The purpose of this paper is to highlight some of the major problems in each area und discuss current solutions or applicable technology. This paper describes gathering systems, terrain effects sphering sonic flow (pressure relief). black oil versus compositional liquid dropout, slug catchers, flow regimes slugging risers, gas lift deliverability, and flow splitting.

Since the early days of the petroleum industry, chemicals have been used to treat oil-field emulsions. These chemicals affect the surface properties of the oil and water so that the small dispersed droplets will coalesce into droplets large enough to settle out. Since crude oils, produced waters, and the type of emulsion formed vary widely the most effective chemical for any given area must be determined by field testing.

Modern mobility control polymers provide the petroleum engineer with a powerful tool for increasing oil production. Successful applications, however, are likely to result only from sound project engineering and careful attention to operating methods. This paper emphasizes a practical understanding of the properties of mobility control polymer solutions as they are likely to affect the success or failure of a project in a given fold. Many unsuitable applications can be identified through reference to some simple guidelines. Further selectivity results from an appreciation of the flow patterns of polymer solutions in specific reservoir situations. Good reservoir engineering maximizes the chances for incremental production; methods appropriate to the use of polymers in both waterfloods and surfactant polymer floods are surveyed. Even the best engineering efforts can be negated by careless or uninformed operations in the field. Particular attention is given to potential operational problems and the means available for dealing with them or avoiding them altogether.

A successful foamed cement job results from careful planning and precise control of densities, rates, and pressures. This paper discusses practical methods of obtaining unfoamed slurry densities, chemical injection rates, and nitrogen injection rates. It also discusses the continuous monitoring and logging of these parameters with a high-tech van. The importance of backside control, hole size, and volume calculations are presented.

This paper is directed toward field operating personnel for the purpose of acquainting them with the objectives, the methods employed and the operating problems encountered in the injection of water to increase oil production. Included herein are brief discussions of the history of water flooding, why water flooding is helpful in increasing oil production, requirements of good water flood, importance of well test information, problems encountered in water flooding, types of water handling facilities, typical production history of water flood and injection of water during the early years in the life of a field.

One of the common oil-field wellbore problems is paraffin deposition. Even though hot oiling or hot watering is usually the first method tried for removing paraffin, few operators appreciate the limitations of "hot oiling" and the potential for the fluid to aggravate well problems and cause formation damage. Field tests have shown that the chemical and thermal processes that occur during "hot oiling" are very complex and that there are significant variations in practices among operators. Key issues include: (1) During a typical hot oiling job, a significant amount of the fluid injected into the well goes into the formation, and hence, particulates and chemicals in the fluid have the potential to damage the formation. (2) Hot oiling can vaporize oil in the tubing faster than the pump lifts oil. This interrupts paraffin removal from the well, and thus the wax is refined into harder deposits, goes deeper into the well, and can stick rods. These insights have been used to determine good "hot oiling" practices designed to maximize wax removal and minimize formation damage.

Reduction of operating cost is of vital concern to the oil industry. Repair expense of insert pumps is often overlooked in the overall picture of production cost control. This presentation discusses failure analysis, pump design, parts analysis, repair shop selection, and repair specifications as they relate to length of pump run and repair cost. Examples of several types of pump failure will be shown and solutions discussed.

In an environment of low oil prices, rod pumping system optimization is more important than ever before. This is especially true for high water cut wells that account for the vast majority of rod pumped wells in the Permian Basin. To maintain profitability, rod pumping wells must be well designed to start with, and analyzed on a regular basis to detect and correct problems as soon as possible. This requires accurate data and the right tools. One of the most powerful set of tools for this purpose is modem diagnostic analysis and design software. The purpose of this paper is to present practical optimization techniques that anyone can use to optimize the operation of rod pumping wells. These techniques, although easy to understand and apply, require the use of modem rod pumping software with unique capabilities. The procedures described in this paper have been proven to work, and when applied correctly, will result in measurable improvements in system efficiency, reduced lifting costs, and extended equipment life. The computer programs used to develop these techniques are: RODSTAR - an expert system predictive computer program, RODDIAG - a diagnostic analysis wave equation computer program, and CBALANCE - a tool for obtaining counterbalance information and for aiding in pumping unit balancing.

Recent advances in the area of two-phase flow allow very accurate predictions of pressure traverses for vertical flow and reasonably accurate predictions in horizontal flow. Typical curves showing the effect of gas-liquid ratio are presented. For wells whereby the maximum production rate is desired, a method is presented that will allow this determination by making use of both vertical and horizontal pressure traverse curves. The tubing size and length as well as the surface flow line size and length must be considered along with production rate, gas-liquid ratio, fluid properties and separator pressure. Typical examples of both a flowing and gas lift well are presented.

The removal of paraffin deposition in rod pumping wells has cost the industry billions of dollars over the years in direct and indirect costs. Once deposited, indirect heating of the paraffin by using a hot oil truck is the most common treatment. However, since hot oiling typically has been proven to be ineffective below about 500', solvents are a useful alternative. This paper summarizes some of practical field aspects of solvent treatments and basic economic considerations. Preliminary evaluation of hot oiling effectiveness, melting point testing, solvent selection procedures and field pumping concerns will be addressed.
For many wells, these procedures will identify areas where hot oiling is ineffective and solvent treating is the preferred method for removing paraffin that is already deposited.

Stable foam has been used to drill large diameter near-gauge holes at increased penetration rates in low and high temperature formations and in top hole drilling in West Texas. The use of stable foam in conjunction with hydraulic snubbing units and reeled pipe units has been successfully used for a variety of well servicing operations under substantial wellhead pressure. Jobs are completed at less cost than those where killing fluids are used; and formation damage is minimized or eliminated.

Injection of liquid carbon dioxide with treating fluids has been used for many years to improve results and to eliminate some of the problems associated with the stimulation of oil and gas wells. One purpose is to promote faster cleanup without the need of swabbing. When the pressure is released at the wellhead after the treatment, the carbon dioxide vaporizes and forces the treating fluids from the formation. Presence of this gaseous carbon dioxide in these fluids reduces the weight of the fluid column so that normal reservoir drive can then help unload the fluids from the well. Rapid recovery of the stimulation fluids is normal. Under certain conditions, dissolved carbon dioxide and calcium salts can react to form a calcium carbonate precipitate. This paper discusses the conditions of temperature, pressure, and pH under which calcium carbonate does not precipitate.

Until recently, there has not been an effective method for effective proppant fracturing of horizontal wells initially completed using uncemented liners, whether pre-perforated, slotted, or perforated after installation. A new technology that incorporates hydrajetting, fracturing, and simultaneous injection down the treating string and the annulus now allows the operator an opportunity to fracture stimulate such completions, placing separate propped fractures at specific selected locations along the lateral. This process is also applied in wells completed with barefoot openholes as well as cemented liners, but this paper will specifically address its use in non-cemented liner application. In some instances, the hydrajet-fracturing technology has been applied as a last-hope effort to make poor producers into economic completions. After the technology proved successful, operators have been able to continue drilling in areas that were at or near the point of abandoning the drilling program due to ineffective stimulation results.

Crosslinked polyacrylamides have proven themselves to be successful, when properly applied, in shutting off water-producing zones and thief zones in a variety of formations. The same principles that allow polyacrylamides to inhibit water movement effectively in pay zones should also be helpful in controlling fluid movement in a variety of situations such as: 1. Low injection rates of 0.25 to 1.5 BPM 2. Microannulus leaks 3. Casing shoe and liner top leaks 4. Mechanically induced holes or corrosion in casing 5. Potential bridging of solids in commercial squeeze fluids which may result in limited penetration or several attempts before a successful squeeze is achieved 6. Fresh water-sensitive formations requiring controlled pH.

Various types of scales have long been a harassing problem throughout the oil field. Their buildup in the formation as well as along the wellbore decreases production by blocking the flow of oil, either by skin damage in the formation or by plugging off the perforations and lowering pump efficiency. If a tendency for the formation of scale can be predicted, it may save time as well as money in the treatment of that well. The basic types of scale encountered are calcium sulfate (CaSOd), barium sulfate (BaSOd), and calcium carbonate (CaCOq). Their precipitation is mainly due either to the mixing of two different formation waters or the mixing of injected water with formation water, the latter being the more frequent case. Scale is not always found downhole; frequently, it may be found in flowlines, separators and other surface equipment. Scale deposits are usually deposits of inorganic salts that result from the combination of a few parameters. Changes in pressure, temperature and mineral compositions of the waters are the parameters that affect the rate at which scale precipitates. Time is another factor often overlooked; the chemical reactions that produce scale are not spontaneous.

Plunger lift excels at producing high GLR oil wells and removing liquid accumulations from gas wells. As reservoirs deplete and flowing rates decline, the gas phase becomes less efficient at lifting the liquid phase to the surface. Allowed to continue, the flowing gradient will become heavier until the well loads up with liquid and stops flowing. In gas wells, smaller tubing (siphon tube), a compressor, rod pumping, or plunger lift is installed to maintain flowing status. Neither the smaller tubing nor a compressor is a permanent solution. They increase the gas velocity initially so that the liquid will be carried out; however, at some time in the future the gas rate will again fall to an inadequate level and the liquid will not be removed from the well. Rod pumping is a permanent solution but an expensive one. Plunger lift provides a permanent solution like rod pumping, however, and at a lower price than any other method. Another alternative is a subsurface liquid diverter. A comparison of plunger lift and the subsurface liquid diverter will be presented in the section on intermittent gas lift. In oil wells, plunger lift may be installed in lieu of other types of artificial lift when the well stops flowing (if the GLR is high enough) or earlier in an effort to lighten the flowing gradient and increase draw-down. In most cases where plunger lift is applicable it will produce a well at a rate equal to or greater than that obtained by pumping, because a high GLR, while necessary for plunger lift, reduces pump efficiency due to gas interference. Once installed and operating, plunger lift can be expected to produce a well to depletion. As reservoir pressure (and thus maximum available casing pressure) declines, so do the producing rate and the need for a high casing pressure. There are a number of plunger lift wells operating with 70-100 psi casing pressure. There are no absolute maximum producing rates for plunger lift as there are none for flowing wells. The limiting producing rate in both cases is as much dependent upon the inflow performance of the well as it is upon its outflow performance. Thus plunger lift should not be automatically ruled out at high producing rates. If high rates are required, the larger diameter plungers should be considered. Plungers can also be used for paraffin removal and have been used in attempts to decrease GOR. A plunger does make a most efficient and economical paraffin scraper and several have been installed for this purpose alone. The attempts at GOR control are often unsuccessful. When the GOR does decrease, it is not due to decreased gas production, but rather increased oil production without an associated change in gas production. The economy of plunger lift is one of the most appealing factors. The capital and operating costs of other alternatives almost always exceed those of plunger lift. The total cost of installing plunger lift is $1500 to $3000.

Sub-surface plungers are finding a wider acceptance over the last few years. Some operators such as Sell Oil in the Ventura Field in California have gathered considerable data to prove that plungers have a wide range of applications. This paper presents a tabular method of determining the suitability of a well for plunger application, and whether the most efficient plunger lift will require additional gas from an outside source or the production of excess gas from the casing. Tables are developed for tubing sizes of 2-3/8 in. and 2-7/8 in. each to a depth of 12,000 ft. Various downhole and wellhead equipment arrangements are given, with application recommendations for each, depending on well conditions.

This paper discusses the role of power cost in the economics of artificial lift. It is specifically directed to the application of electrical submersible pumps (ESP's). A method for estimating the power required by an ESP is presented along with a computer program to assist in the calculations. This paper is directed toward the Engineers and supervisors whose responsibility include the specification of the type of lift systems to be employed and the sizing and selection of equipment.

This paper presents a method to predict the life of sucker rods. It is based on the standard of maximum and minimum stress on a rod as these stresses describe the fatigue life of the rod. The result is a Constant Life Diagram for the rod (sometimes referred to as a Haigh Diagram). The step wise procedure used to construct the diagram is described as well as contrasting the other possibilities for predicting the life of the rod. The Constant Life Diagram can be constructed from laboratory data, but a more practical diagram can be constructed using field data.

Due to recent trends in hydraulic fracturing with very high proppant concentrations there has been a substantial increase in the frequency of screen outs. The present paper discusses methods of predicting screen outs both during the fracture treatment design stage as well as during the actual performance of the treatment. Different types of screen outs are presented with examples. Reservoir data is used in presenting screen out prevention methods. Procedures to handle screen outs along with several remedies are suggested and the merits of each method are discussed. Lab data on formation and sand pack damage due to mishandling screen outs are also shown.

The petroleum engineer is often required to estimate the pressure production performance of an oil well in order to determine its productive capacity. This paper discusses various methods that have been proposed in the literature for describing individual well performance in solution-gas drive reservoirs. The forms of the oilwell deliverability equations will be presented as well as methods for predicting future performance. An example will be used to illustrate and identify data requirements for each method.

The petroleum engineer is often required to estimate the pressure production performance of an oil well in order to determine its productive capacity. This paper discusses various methods that have been proposed in the literature for describing individual well performance in solution-gas drive reservoirs. The forms of the oilwell deliverability equations will be presented as well as methods for predicting future performance. An example will be used to illustrate and identify data requirements for each method.

Recent developments in stimulation practice have resulted in two or more fluid systems being used continuously during a treatment. Fracture acidizing, for one, has involved the use of a highly efficient pad fluid preceding the acid into the fracture. In the use of the crosslinked gels, it is common practice to precede the gel-sand slurry into the fracture with a pad fluid of an entirely different character. Where these techniques are used, it is useful to know the rate at which one fluid is displacing another and the location of the interface between these two fluids. The importance of this information is as follows: 1. In fracture acidizing, the location of the fluid interface indicates the farthest point that the acid has reached into the fracture. 2. In using the crosslinked gels with proppants, the location of the interface pinpoints the leading edge of sand-laden fluid and hence, propped fracture length. It can also provide valuable information concerning sand scheduling. 3. Where overflush volumes are used behind high strength acid treatments, this information is valuable in sizing the volume to be used as overflush. The gross, averaging techniques used in the past have not allowed the location of the interface between two fluids or stages of the same fluid. In order to develop a method to accurately predict the interface location it was necessary to go back to the basic fluid mechanics of fracturing. In this analysis a greatly simplified expression was developed which predicts fracture area within 10% (or less) of the Howard, Fast, and Carter equation." This simple equation has greatly simplified fracturing and fluid displacement analysis without introducing significant errors in accuracy.