In general, the well characteristics will govern the type of pumping completion and the selection of equipment. Various arrangements of equipment are discussed, such as two packer single string, single packer with either clipped or free running secondary string, hollow rod pumping, lower zone gas venting and triple completions. It is emphasized that attention to correct installation of all equipment will eliminate needless completion expense.

This paper will discuss the installation of High Density Polyethylene (HDPE) liners in existing cement-lined and bare steel water injection pipelines. Design criteria, economic evaluation, and HDPE liner installation details are included. Also, different types of HDPE liner systems, material properties, and internal corrosion protection will be discussed.

An instrument skid especially designed for fracturing data acquisition provides operator flexibility and choices that can help reduce costs of data acquisition and recording. The operator interface panel (OIP) associated with the skid can be viewed at the skid or can be remoted up to 250 ft distance from the skid. Information collected can be used by the on-board computer system and displayed on three screens of the OIP, or the digitized data can be communicated to other computer systems that may be on the job.

Shortly after the discovery of the Block 31 field in 1945, ARC0 Oil and Gas Company, then Atlantic Refining Company, started searching for ways to improve the ultimate recovery from the Devonian formation. Laboratory research showed that natural gas would become miscible with the crude at 3500 psi. Therefore, injection of the produced gas began in 1949. A processing plant was built in 1957 to extract liquids from the gas before reinjection. Eventually, the produced gas volume was not adequate to maintain miscibility pressure and additional gas was purchased to make up reservoir voidage. Further laboratory research showed that flue gas injection would maintain miscibility at a higher injection pressure. ARC0 began flue gas injection in the Block 31 field in 1966 at a rate of 40 to 50 MMSCFD. In 1980, a favorable decision was handed down from the U.S. Department of Energy relative to the recoupment of investments made in tertiary recovery projects. This provided further incentive for an ongoing development program. Since 1966, continuous flue gas injection has sustained the miscible flood and, being predominantly nitrogen, caused a constant increase in nitrogen content of the produced gas. The inlet gas to the processing plant currently contains from 30 to 45% nitrogen. The processing plant consists of three lean oil absorption trains for propane and heavier recovery. Residue gas from the processing plant, which is used for fuel, has declined in BTU content to below 800 BTU/SCF. All the fuel users were designed for 950-1000 BTU fuel. The fuel had to be "spiked" with a high ethane stream to maintain a 950 BTU fuel stream. This blending was satisfactory for several years, but variations in nitrogen content and momentary imbalances in this blending cause operational problems in the gas-engines, power boilers, and flue gas generators. Three alternatives were evaluated for solving the fuel problem: purchasing outside fuel, retrofitting existing equipment for low BTU fuel or building a nitrogen rejection facility. Nitrogen rejection was determined to be the preferred solution from an economic and reliability standpoint. The nitrogen rejection facility (NRF), built in 1983, handles 94 MMSCFD of the highest BTU (lowest N,) gas. This facility was designed to produce up to 38 MMSCFD of fuel gas while recovering 300,000 gal/day of NGL's.

The use of an intelligent ESP control unit (IESP) aids in remotely operated and "trouble" wells. Inputs from a number of end devices are used to determine the condition of the well bore and the equipment. Based on these inputs the mode of start-up or operation is "decided on" by the IESP. Control commands are then sent to the Variable Frequency Drive (VFD), switchboard controller, or back-pressure valve to achieve the desired mode of operation. This paper will discuss the concept and IESP design behind the initial project.

Petroleum Development Oman (PDO), working in close cooperation with several other companies, is developing and testing a remote, automatic, intelligent ESP system for Oman's challenging operations. This progress report describes the system concepts, expected benefits, and current status. PDO operates nearly 600 ESPs; this number is continuously growing. Many are located in very remote areas; many produce from sandy formations; many produce significant amounts of gas; most use fixed speed drives. These wells must be carefully started and operated to avoid damage from sand, inefficiency from gas, and safe and effective operation within the normal pump envelope. Currently, this is very labor intensive. Due to remote locations, it often results in excessive, hazardous desert driving, inefficient use of manpower, significant production deferment, and excessive operating costs. To optimize these wells, PDO is developing a system that includes downhole instrumentation to measure pump pressures and other key variables, a real-time sand production monitor, an automatic well-head control valve (for wells with fixed speed drives), and a full production automation (SCADA) system. The wells must be started and/or restarted slowly to avoid sand production problems or gas interference. Production must be ramped slowly enough to avoid these problems, but rapidly enough to avoid down-thrust or excessive motor heating. ESP Technicians are able to interact with the system from the field or corporate offices to optimize operational parameters and troubleshoot faults and shutdowns. Major benefits are expected to be up to 80% reduction in desert driving, significant improvements in production and equipment life, major reductions in deferment and ESP operating costs, and wider application of ESPs in preference to beam pumps and gas-lift. Initial field tests are underway in the Wafra Field in PDO. Implementation on more wells in PDO is anticipated when the field tests are successfully completed in early 2003.

Waxes accumulate as obstructions to the normal flow of crude oil systems. They do this by attracting molecules of like character (e.g., normal paraffin hydrocarbons) and combining through intermolecular forces to form aggregates of a crystalline nature. The aggregates thus formed interact mechanically and accumulate in constricted flow regions, pipe surfaces, and quiescent storage areas. Once it has been determined that paraffin wax accumulation has restricted the normal production, transport, and/or storage of crude oil, measures should be quickly undertaken to remedy the problem. Several remediation methods are available including, hot oiling, hot watering, combination hot water and surfactants, solvent, solvent/surfactant treatments, magnets, bacterial treatments, and crystal modifiers etc.. . Each method possesses strengths and weaknesses. Hot oiling and hot watering are known to be useful in helping to dislodge pumps that are bound up by wax, but their continued practice has also been shown to concentrate higher melting wax fractions in existing deposits thereby making the remaining deposit more difficult to melt in subsequent treatments. Solvent and solvent/ surfactant treatments are excellent means of wax deposit removal, but the extent of their wax carrying ability is limited by temperatures below the cloud point of wadsolvent combination. Crystal modifiers provide the most effective means of preventing deposits, and will in combination with solvents, or hot oil provide significant deposit removal, but they tend to be costly. The successful treatment of paraffin wax accumulations is largely dependent upon the proper identification and characterization of their chemical composition and their physical behavior under various environmental conditions.

Advances in enzyme technology and its application to hydraulic fracturing have brought enzyme breakers from low-temperature, low-pH applications to being used over a wide range of temperatures, pH's and fluid systems. Their potential as fracturing fluid breakers seems almost limitless as one obstacle after another has been swept away by advances in biotechnology. High-temperature enzymes, high-pH enzymes and controlled release enzymes have contributed to their widespread use as fracturing fluid breakers. Advantages of enzyme breakers over conventional oxidative breakers has been well documented. For example, oxidative breakers have many limitations including interferences and incompatibilities with other fracturing fluid additives. Enzyme breakers, too, have limitations including interferences and incompatibilities with other additives. Ignorance of these interactions can have dramatic effects on the success of a hydraulic fracturing job. With the new advances in enzyme applications, it is not always easy to keep abreast of the limitations of the new enzyme breakers. Interactions known for other enzymes are often just assumed to apply to new enzyme breakers. This is not always the case. Use of enzyme breakers under more extreme pH and temperature conditions can also cause or magnify interactions. This paper covers interactions between currently used enzyme breakers and fracturing fluid additives including biocides, clay stabilizers, and certain types of resin-coated proppants.

In most instances there will be no question as to whether or not a well should be placed on continuous flow or intermittent flow. However, there are cases of the so called "borderline well". Reference should be made to "The Power of Gas" by Mr. C.V. Kirkpatrick for a complete analysis of the borderline well. This procedure involves an analysis of injection pressure injection gas/oil ratio and horsepower requirements. The following types of intermittent flow installations utilized in the field today are: 1. Tubing flow with a packer only (semi-closed installation), Fig. 1; 2. tubing flow with a packer and a standing valve (closed installation), Fig. 2;, 3. Tubing flow from a chamber (closed installation), Fig 3; 4. Any one of the three preceding installations in combination with a "piston" or "plunger", Fig 4.

The purpose of this paper is to describe multipoint intermittent gas lift installation design. The application and advantages of this design technique are noted. The operating principal of multipoint gas injection, which includes fundamental valve mechanics, is presented. The maximum producing rates from the same high capacity well with a continuous flow installation and a multipoint intermittent installation are compared, and the reasons for the difference in producing capacity is reviewed.

Many of the thousands of wells produced by intermittent gas-lift experience similar problems. One problem is that the system is attempting to lift a static slug from the bottom of the well to the surface, which is quite inefficient. As the slug moves toward the surface, there is a frictional drag on the liquid slug along the inner walls of the tubing. That drag, coupled with the fact that the gas is travelling faster than the liquid, means that there is a tendency for the gas to outrun the liquid. The liquid that is outrun never reaches the surface, it falls back to the bottom of the well. By creating a fluid column in the bottom of the well, this "fallback" increases the back pressure on the formation, thereby reducing the effective average flowing bottom hole pressure. The net result is less production. Another common problem experienced in intermittent gas-lift is over-injection. In some operations the injection gas is intentionally over injected to help "sweep" out the falling liquid. While this could help, it is highly inefficient. On wells where the injection gas is controlled by a choke or orifice, over injecting in nearly impossible to avoid. Over injecting also keeps the tubing pressure of the well higher for a longer period of time. This has a negative effect on the flowing bottom hole pressure, and on liquid production. This report will address these common problems, and offer a sensible solution to both. The applications for this system are widespread, but cannot be automatically applied to every gas-lift well. As with all other artificial lift systems, each well must be studied individually to determine it's suitability. Plunger-lift offers the producer options, but cannot be viewed as a cure-all.

Cement-lined steel or iron pipe is not a new approach to corrosion prevention. In 1836 the French Academy of Science reported the successful use of cement-lined pipe. They reported that, "Hydraulic cement, applied about 2.5 mm (0.1 inches) thick, is of all compositions, combining facility of application and cheapness, that which adheres the best to the casting, is the most indestructible, and prevents most effectually all oxidation (Corrosion) and consequent formation of tubercles. Of course, it is well documented that the great Roman aqueducts were constructed of hydraulic cement, forerunner of modern Portland cement.

The use of internal protective coatings for oilfield pipe has greatly increased during the past few years. New coating systems and application techniques, quality control, engineered performance and successful field use have all contributed to this growth. This paper summarizes the history of the coating industry, surveys the present art, and defines the useful areas for coatings in oil and gas production.

Accelerated internal failures of gas gathering lines due to corrosion are creating more concern to operators. A review of the dissolved gasses which cause corrosion is significant from the standpoint of occurrence and prediction of corrosion. Dissolved oxygen when present with other corrosive gases causes severe corrosion. Experience shows that early detection of corrosion by the use of monitoring devices is essential. Corrosion in gas gathering lines can be effectively and economically inhibited with organic film forming amine corrosion inhibitors properly applied and monitored.

Paper may soon be eliminated from the well permitting process at the Railroad Commission of Texas ("Commission") by an electronic commerce system that captures, stores, and transmits oil or gas well permitting information. With a few computer keystrokes and mouse clicks, Burlington Resources filed and the Commission approved the first drilling permit electronically through the ECAP (Electronic Compliance and Approval Process) system in a demonstration on May 11, 2000. A collaboration among the U. S. Department of Energy, the oil and gas industry, and the Commission, ECAP is expected to save more than $17 million annually, improve communication, and streamline regulatory processes through the use of Internet-based technologies, relational databases, document imaging, and workflow software.

Stringent safety requirements imposed by major operators when fluid level measurements are performed offshore or in enclosed wellhead spaces such as in Alaska's North Slope create procedural complications, such as the requirement for hot permits, when performing fluid level measurements in producing wells. This need has been eliminated by the development of a small, self contained, fully digital, battery powered instrument that is approved for use in hazardous areas. The Echometer Model H electronics has been tested at various locations on the North Slope. It facilitates the acquisition and interpretation of the data through an advanced software package that virtually automates the analysis even in acoustically noisy environments. Results are observed immediately on the instrument screen then saved in the data base for eventual transfer to corporate records. This paper presents detailed information about the new system and reviews data acquired in gas lift wells, flowing gas wells and ESP installations

Safety in the workplace is one of the major considerations for selecting and applying instruments for use in conjunction with oil and gas operations. All companies, government and labor organizations have developed guidelines and regulations aimed at making the workplace as safe as possible. In particular, instruments that are used in a hazardous environment have to meet strict requirements and specifications and be certified for use in explosive atmospheres. API has developed guidelines that define the level of hazard in relation to oil and gas production locations where explosive gases are present. It is important that the user of certified instruments understand the meaning of certification of an intrinsically safe system, the process that the manufacturer must follow to obtain certification and the requirements and procedures that must be adhered to in order to achieve the required level of safety when installing and using the equipment. This paper presents the fundamental aspects of intrinsic safety certification with respect to fluid level instruments used in analyzing the performance of wells during drilling, production and workover operations.

This paper will provide a basic understanding of the Multiport Selector Valve (MSV) also known as Rotary Selector Valve (RSV), Controller, Environmentally-Friendly Spill Prevention Skid, Design Analysis, Usage and Dynamic Fundamentals; Highlighting the technical capabilities to manifold multiple wells from a single unit. Automation

This paper discusses the principle of plunger lift and it's possible applications. Typical applications are: 1. Removal of Liquids from Gas Wells 2. Hi-Ratio Oil Well Production 3. Paraffin and Hydrate Control 4. Increased Efficiency of Intermittent Gas Lift Wells Some advantages of this system are low initial cost, very little maintenance and that there is no external source of energy required in most cases. Limitations such as mechanical conditions, gas and liquid volumes and depths are also discussed. There will be a brief section concerning the various types of equipment available.

Inverted emulsion (water in oil) muds have long been used for formation protection and improvement of hole stability, but slow penetration rates often offset advantages. Recently, relaxation of control of mud properties-notably fluid loss-has led to significant improvement in penetration rate. A comparison of weIls drilled in the Delaware Basin shows that significant savings in total well cost can be obtained through the use of new generation invert muds.

A magnetic bailer has been designed to capture and remove metallic compounds that gather in the wellbore and downhole operating equipment such as an ESP unit. The tool can be used as a standalone, as the part of the tubing, or can be set in the tubing as a joint that stands on Y-tool. The tool can be installed above or below the ESP unit. It can be wireline or coil tubing operated. It is, a cost effective and convenient physical way of cleaning the well. It can save significant well shut-in times that are otherwise unavoidable due to pump failure. Many producing formations produce metal compounds along with oil, gas and water. These metal compounds often are iron-associated compounds, heavy and usually settle in the wellbore. Often iron compounds combine with hydrogen sulfide (H2S) and sulfur dioxide (SO), usually present in natural gas, to form iron sulfide in the wellbore. Iron sulfide is a very hard material (SG 5.1 +). It is not malleable and has crystalline and abrasive structures. When iron sulfide enters an ESP unit, it damages the impellers, diffusers, and shaft, thereby reducing the pump run time and causing premature pump failure. Most of the time, it juggles in the fluid that is being pumped and falls back when the pump stops. It is not carried to the surface due to its high specific gravity, it instead sticks to the tubing walls above the pump, and most of the time in the first tubing joint, and with time completely plugs the tubing. Chemical treatment is usually not effective since the inhibitor is pumped out of the well. In this paper the physical properties of iron compounds in general and iron sulfide in particular, along with common contaminant compounds found in crude oil and natural gas and problems associated with iron compounds and associated scale are investigated. Second, the first indications of their presence and the unusual solids in the pump are addressed, and finally the tool design is discussed in detail.

Iron control studies over the last 30 years have dealt primarily with iron control in acidizing operations. In fracturing operations, iron control has received much less consideration. Certain hydrocarbon producing zones contain iron compounds in both the rock composition and formation water. Fluids used in fracturing operations may be incompatible with the formation water or rock itself, if iron is present in them. Special consideration should be given to the design of fracturing fluids and fracturing techniques so that iron problems will be minimized. This paper presents: (1) data and treating information on 3 formations (Clinton Sandstone in Ohio, Granite Wash in Oklahoma, Limy Sand in Texas) that contain iron in the formation rock and formation water and were treated with an iron control fracturing procedure. (2) the new iron control fracturing procedure that helps maintain iron in solution and helps provide compatibility of the fracturing fluids with the formation. (3) treating techniques to control iron problems and (4) field results from jobs that utilized the modified fracturing fluid and procedure. Sharp production decline curves have plagued operations in the formations listed. The Clinton Sandstone, Granite Wash, and Limy Sand formations have responded well to fracturing treatments; however, in many instances the production increases have not been sustained as long as desired. Iron, a constituent of the reservoir rock, may well be a primary factor in this problem. Utilization of iron control additives and treating techniques as applied to the formations encountered in Pennsylvania, Michigan, Illinois, Indiana, Kentucky, West Virginia, Tennessee, Alabama, Texas, and Oklahoma should be considered for improving cleanup operations, production stimulation and rate of production decline in the same or similar formations in other areas.

Sludging is an ever present problem in the Permian Basin. Recent studies have shown the influence of iron by-products on the sludging process. Questions have emerged concerning effects of CO2 introduction into the overall reaction. An operator concerned with this over-all process began a study to determine the influence of CO2 on the over-all system. The results of this study involving a San Andres CO2 pilot program are evaluated. Included are compatibility testing of produced oil, produced water and acid systems. Testing was conducted with and without iron injected into the system. A representative cross-section of the field lease crude and produced water was utilized. Considerations for future CO2 flood testing are discussed.

The precipitation of iron compounds following well treatment is a common problem in most areas of Texas and New Mexico. This insoluble gelatinous precipitate is both an effective plugging agent and an emulsion stabilizing agent. Either condition damages permeability and greatly restricts production of oil and gas. In order to effectively deal with the problem, the chemistry and physical characteristics of iron as an ion and its subsequent reactions must be understood. Sources of iron, well conditions, types of iron control agents and their properties will be discussed and evaluated.

Productivity, safety, and health are major concerns for companies attempting to maximize profit and provide safe, healthy work environments. Human performance declines when people receive less than optimal sleep. As performance declines, the risk for accidents and health problems increase. Long hours of work, especially for a week or longer generally lead to increased sleep debt, reduced performance and increased risk of accidents and health problems. Costs increase as performance declines and risks increase. These changes in human factors associated with sleep management can be especially troublesome for companies attempting Six-Sigma quality standards. A web-based tool, SLEEP Model, has been developed that allows people to input sleep time and duration, caffeine and alcohol use, and age to evaluate performance and various risk factors, including increased accident and health risks. The presentation will demo SLEEP Model and will illustrate the numeric value of wise sleep management.