The prudent design of good salt water disposal systems requires consideration of all reservoir conditions and economic factors.

A discussion pertaining to the design, construction and operation of salt water disposal systems from supervisory and record maintenance viewpoints.

This patented system consists of a typical chemical pump, chemical chamber fitted atop a modified lubricator cap, all on the surface and a modified plunger available in any configuration currently on the market. The entire system has only 4 moving parts, not including the plunger. This system is capable of transporting liquid chemicals each plunger cycle. The entire system can be installed with common tools typically, during the shut-in segment of the well cycle. Field trials in two different wells in So. Louisiana over 168 days showed a reduction in metal loss (corrosion coupons before and during field trials) of 17% in one well and 3% in another well.The system incorporates non-metallic components to reduce metal loss caused by abrasion. The system can be set up to deploy multiple chemicals with a single system, i.e., corrosion inhibitors, foaming agents, oxygen scavengers, biocides, etc. The system is more efficient than capillary strings and much more economical to install and operate. It works in wells with packers in place and requires no service rig to install. There is no interruption in production during installation. The entire system, installed cost less than one application where chemical laden diesel is "bull headed" down the tubing, installation of a velocity string or batch treating down the "backside".

This paper provides five examples of pumping well buildups and the pressure transient analysis of the buildup data. The bottomhole pressure data is also included for each test. All of the buildup data was collected through the use of automatic acoustical fluid level machines. When the examples were picked an attempt was made to show typical buildup responses from Permian basin wells. Some of the buildups selected are from wells that are tight and have three phase flow. The tight wells have been stimulated, and do not fit the standard reservoir response models. The samples consist of a classic homogeneous buildup response, a well that has suffered a local reduction in permeability over time, a new drill from the same field, a well that sees interference from offset production during the buildup, and a well that has a changing storage; due to the fill up of a hydraulic fracture.

After many years of producing a lower zone in the Conger FMT Chevron recompleted existing wells in an upper zone. The lower zone was closed off with a cast iron bridge plug. Severe problems with sand production were encountered and various methods were used to produce the well and deal with the sand. This paper will review the problems and solutions encountered when these changes were made. It will also review the different pump designs that were used and which were successful.

The presence of clay minerals within a sandstone reservoir is a major factor in the sensitivity of that reservoir to treatment fluids. The exact type of fluid sensitivity (acid, fresh water, etc.) depends on the exact type of clay mineral present in the reservoir. In recent years, X-ray diffraction analysis has been extensively used to determine the type and amount of clay minerals present in reservoir sandstones. There is a problem in designing a well stimulation on the basis of X-ray diffraction analysis or any other type of analysis which evaluates the properties of the reservoir sandstone in bulk. The problem is that clay minerals may be of two distinct origins which produce different distributions of clay minerals within the reservoir and different degrees of exposure to completion and stimulation fluids.

This paper describes savings which are realized by the use of lower temperatures in oil treating.

A new promising CO2 cocktail enhanced oil recovery technology has developed. The technology involves in-situ generation of carbon dioxide to recover trapped residual oil from reservoirs. This technology has two at least unique features that set it apart from existing technologies. First, CO2 is injected as part of a dense liquid phase (not simply compressed CO2). Because the injected fluid is a dense liquid at ambient conditions, there is no need for the expensive compression costs that are associated with convention CO2 injection processes. The gravity head associated with the fluid column allows CO2 to be injected in a more cost-effective manner. This proprietary technology allows CO2 to be released in-situ after injection into the reservoir. A second unique feature of this new technology is that a proprietary surfactant formulation forms foam when the CO2 is generated in situ. The slim tube and core experimental results demonstrated advantages of the new technology. GTT, Inc. is leading commercialization of this technology in North America.

The purpose of this paper is to share the authors" experiences in applying SCADA technology to the oilfield. This paper discusses some currently available SCADA technologies, how SCADA technology is typically applied to onshore oil and gas production, and the practical considerations of implementing oilfield SCADA. This is based on the authors" experiences as control system engineers in oil and gas producing operations. The intended audience is people familiar with onshore oil and gas production operations. The manufacturers mentioned in this paper do not represent all of the available devices on the market, nor are they necessarily the best, but are included as examples from our experience that have been popular in the oil patch and that the reader might find familiar. Topics covered in this paper are: -RTUs including Electronic Flow Meters, Pump off Controllers, PLCs Communication protocols (Modbus, Ethernet, others) - Human Machine Interface (HMI) options - Communication pathways (Wireless, Cable, Fiber Optic) - Project economics - Project implementation strategies - System purpose vs. reliability

Scale is a term commonly used in the petroleum industry to define insoluble, inorganic salt deposition in water or water-containing systems. Normally this deposition is composed of the salts of calcium, magnesium, iron and barium. Oil field brine water contains many and varied inorganic salts are increased or the solubility of the salts is decreased, the equilibrium is upset and precipitation takes place. This precipitation is commonly called scale. The physical factors which may cause precipitation are temperature, pressure, evaporation and condensation. Temperature variations and pressure changes are the two most common causes. The solubility of most salts increases with an increase in temperature. A sudden drop in pressure can cause an upset of equilibrium and may result in precipitation.

This paper deals with a dual subject concerning scale and paraffin problems encountered in the production of petroleum. Scale formation is caused by an upset in equilibrium conditions within a given system and this is explained in detail. Several methods of control are discussed and optimum conditions of control outlined. Chemical treatment for scale control is discussed at length since this is the most practical method of control in the production of oil. Paraffin or wax formation in oil production equipment is explained as to types and different areas of these occurring types. Chemical treatment for removal and prevention is discussed at length.

For years, all oilfield scales were called gyp, and gyp meant trouble. Times and methods may have changed, but gyp, or scale, still means trouble. Scale can be anything that precipitates from water. We have seen scale deposits that were pure rock salt and others that were much more exotic, such as zinc phosphates, sodium carbonate, and occasionally minute traces of gold and silver, but these are unusual. Everyday oilfield scales are calcium carbonate, calcium sulfate or gypsum, and barium sulfate. Strontium sulfate is occasionally found, usually in conjunction with barium sulfate. Corrosion products, too, can be found in scale-like deposits. Scale deposits are the result of water instabilities-supersaturated solutions are dropping out some of their burden of dissolved salts in order to approach equilibrium. Precipitation will continue until stability has been achieved. In a flowing system with continual replenishment of water, scale deposits can continue to grow, in some cases completely blocking the flow line (Fig. 1).

Calcium sulfate scale deposition in oil producing wells in West Texas is a serious and expensive production problem. A great deal of time and money has been devoted to this problem but, as yet, no completely satisfactory solution has been found. Mechanical removal of the scale followed by fracture treatments or acidizing have been partially effective in restoring production capacity. Squeeze treatments using scale inhibitors have considerable promise, but will require refinements in the placement techniques. Fracture treatments spearheaded with scale inhibitors have given the best results to date. This paper will discuss these treating procedures with particular emphasis on formation squeeze techniques.

Downhole scales commonly encountered in producing operations are often calcium carbonate and calcium sulfate, less frequently barium sulfate and strontium sulfate. The problems vary in severity, the deposits sometimes being sufficient to cause pump failures and

The anticipation of scaling conditions before they have commenced or before the deposits have become excessive is a vital prerequisite to the preventative maintenance of any oil field equipment handling water. The author's current procedures and means of using water analyses for the prediction of scaling are reviewed. Other methods that are also available, and some of which have been proposed, are also briefly reviewed. In view of their appearing more prevalent in the oil field, the attention is focused on calcium sulfate, calcium carbonate, and barium sulfate.

Scaling of oil wells, injection wells, equipment and flow lines is a serious production problem. The scales, which are formed from the produced brine, may be one of many chemical compounds or a mixture of several. The effect of scale deposits can be noticed in many ways, but all are factors which will show up in the economics of production.

Wellbore flow barriers, such as scale deposits, can be pulverized by a new technique that utilizes high-intensity sonic shock waves of microsecond duration. Improvements in well productivity have been realized in field tests at costs substantially below those of conventional remedial services. The Sonic Shock Tool is lowered in the well on a wireline. It is powered by a high-voltage arc whose shock waves in well fluids hammer the casing walls and openings with a high-intensity impact of microsecond duration. Mineral deposits, such as barium sulfate, gypsum and calcite (alone or mixed with each other or with oily residues), are susceptible to these high-intensity shock treatments. The tool can operate in acid or organic solvents if special conditions warrant their use. The rarification following the shock wave causes a large part of the scale in the casing perforations to fall down inside the casing. These pulverized deposits are bailed out of the well. Due to reductions in pressure and temperature as reservoir fluids enter a producing well, solid deposits of minerals and/ or asphaltic or waxy materials tend to build up in the openings into the wellbore and inside the well. Serious interference with well productivity often results. About five years ago, Sonics started working on a downhole tool aimed at breaking up these deposits and restoring productivity with shock waves produced under liquid opposite the perforations. First efforts were with a high-power ultrasonic transducer which produced a strong cavitation and shock waves. This did successfully break up the scale. However, it had two fatal shortcomings: ambient pressures above about 200 psi stopped the cavitation - and the shock waves - and the cleaning. Also, when the power was increased, it began tearing up the surface of the transducer. Efforts were then changed to the use of repetitive high-voltage shocks to break up the wellbore restrictions.

A series of tests measuring power consumption were conducted at the Texas Tech Red Raider Test Well. This test facility is located 5 miles northeast of the campus of Texas Tech University in Lubbock, Texas. This paper introduces the Red Raider Test Well and all of it's abilities for testing various components of a rod pumping artificial lift system to unprecedented level of accuracy. This test measured the power consumed by the beam pumping system with all variables held constant except the surface stroke length and rodstring design. The result of this test was a 14.9 % power savings utilizing a Fiberglass

The enhanced oil recovery processes discussed in this paper fall in the general areas of recovery of oil by thermal, gas drives, polymer flooding, and chemical flooding processes. General descriptions of the most widely used processes are given. Also, the conditions under which each process has been found to be likely successful (screening criteria) are included for each process. This helps the engineer to match processes to specific reservoirs.

Multiphase flow in pipes is defined as concurrent movement of free gases and liquids in the pipes. Flow may be in any direction. The gas and liquid may exist as a homogeneous mixture, or the liquid may be in slugs with gas displacement (which is pushing behind slugs). The liquid and gas may flow parallel to each other, or other combinations of flow patterns may be present. The gas may be flowing with two liquids (normally oil and water), and the possibility exists that the two liquids may be emulsified. The prediction of pressure gradients occurring during the simultaneous flow of gas and liquid in pipes is necessary for the proper tubing size selection, design of artificial lift installations and many other production systems in the petroleum and chemical industries. Petroleum engineers encounter multiphase flow more frequently in well tubing and flowlines. The ability to accurately and analytically predict the pressure at any point in a flow string is essential in determining optimum production string dimensions and in the design of gas-lift and other kinds of production equipment installations. This information is invaluable for predicting bottomhole pressure in flowing wells. As with any correlation, the correlations developed are often misused and applied to cases outside the range of the database from which it was developed. Even though the range of the correlation's application can be extrapolated, it must be used with caution. Hence, a decision has to be made as to which correlation should be used to suit the given set of well data. The importance of being able to assess the accuracy of calculating methods or previously developed correlations is demonstrated in this paper. In fact, their range of validation in the light of the variety of conditions is discussed. These set of tested ranges are used as tools for obtaining a criteria in order to determine the suitability of different correlations towards the given data. This paper is an extraction of work done in relation to the masters" thesis by Palisetti.

Laboratory Screening Tests are suggested to evaluate potential enhanced oil recovery projects. Standardized procedures are used to study the feasibility of (1) miscible/CO2 projects, (2) thermal processes, and (3) chemical processes. The Screening Tests are divided into four sections: crude oil characterization, injection water studies, reservoir core characterization, and displacement studies in porous media. These Screening Tests augment geologic and engineering studies and supplement (but do not replace) the more commonly known core analysis programs.

The success or failure of secondary recovery efforts is largely dependent upon the proper analysis of downhole and reservoir fluid movement characteristics, and control of these conditions to maximum displacement efficiency. The indigent reservoir reactions under secondary efforts differ dramatically from normal primary production systems. These differences generate a need for individualized analysis and correction of each problem. Many tools, materials, and techniques have evolved or have been adapted to assist with these controls; but as in all efforts, the application must suit the need lest experimentation or "trial and error" methods result in added costs that render the total economics undesirable or prohibitive. The variety of monitoring and control methods available through the service industries suggests that selective application must be made, but the tendency to assume the "single method panacea" is encouraged by individual competitive sales efforts. Problems are frequently aggravated by the misapplication of services, the least consequence being failure of the specific effort, if not irreparable damage to the project. A general awareness of the specific nature and field of limitations of these many "special services and materials is needed to aid in the selection of the proper tool or technique for the job to be done.

The widespread use of waterflooding has presented many new problems to the petroleum industry. Most of these problems are directly related to the physical process of pumping great volumes of water at high pressures into water injection wells. Until the past few years, methods of increasing or maintaining injectivity were limited to the conventional techniques of acidizing or fracturing. Within the past three or four years, however, stimulation techniques have been developed primarily for problems related directly to water injection wells. The first involves the use of sodium hypochlorite solutions followed by acid solutions to remove permeability damage caused by bacterial activity. Such activity can result in creation of large amounts of organic material and tremendous loss in permeability. The second new stimulation technique is the use of micellar dispersions. These fluids remove most of the residual oil saturation near the wellbore and greatly increase the formation permeability to water. Both new injection well stimulation methods have been widely used and have been proven highly successful. The purpose of this paper is to describe these new techniques and point out how and when they should be used. Treatment design is also discussed; case histories are presented to show the success of these types of treatments as well as to point out some of the conditions that can contribute to their unsuccessful use.

Primary separation methods (such as free water knockouts, gun barrels and skim tanks) often leave substantial amounts of oil and solids in waterflood injection water. Removing oil and solids from produced and supply water streams by secondary separation techniques such as corrugated plate inceptors (CPI) and gas flotation units can provide four benefits: 1. Increased oil sales. 2. Improved water injectivity. 3. Improved waterflood sweep efficiency. 4. Lowered injection pump discharge pressure.

Inaccuracies in hydrocarbon measurements can cause significant revenue losses for a company. This paper will discuss the problems associated with hydrocarbon measurements and the preventive measures a company can take to correct the inaccuracies. Historically, exploration and production companies have adopted a casual attitude to the necessity of accurate hydrocarbon measurements. All too often this author has heard, "Our measurements are pretty close: anyway what's a few barrels between friends". These types of attitudes can cause significant revenue losses for a company as the examples below demonstrate.