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Produced water is the aqueous liquid phase that is co-produced from a producing well along with the oil and/or gas phases during normal production operations. Usually, the fluids that are removed from the reservoir by the producing well are brought to the surface and separated into an oil stream, a gas stream and a water stream.

Extreme overbalanced perforating and surging has been used in many types of reservoirs as a completion method since the June, 1990. This method of completion is not a panacea for the petroleum industry, but it does address many of the problems associated with low pressure and/or low permeability reservoirs. This paper will present some of the more practical applications for today's completion practices. The cases presented include skin removal, massive hydraulic fracture replacement, and treatment volume reductions.

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.

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 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.

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.

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.

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.

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 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.

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.

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.

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.

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).

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.

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.

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.

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.