In order to select the appropriate inhibitor for a given application, two outstanding pieces of information need to be known. They are: "How much corrosion will occur in a given length of time under the specified conditions?" and "How much corrosion can be accepted?" The amount of corrosion that will occur in a given length of time can be determined by running a test which will duplicate the desired conditions; but, the amount of corrosion that is acceptable is somewhat arbitrary. In this paper, an attempt will be made to give the reader an understanding of how tests are run to determine the amount of corrosion that will occur and to help develop a feel for the amount of corrosion that can be accepted. However, before going further, we should review the fundamental definitions of "corrosion" and "inhibition".

This paper briefly summarizes the laboratory studies that have led to the development of the new, high-strength bauxite proppant, describes field applications of the proppant, and discusses the results of a detailed economic analysis for a particular field. We expect that wide-spread use of the new proppant will be economically justified in the future.

There are, at present time, eight sucker rod manufacturers in the United States. They all manufacture sucker rods and coupling according to the specifications set forth by the American Petroleum Institute. In view of this, any discussion of the care and handling for sucker rods and couplings would quite naturally apply to any and all makes of sucker rods and couplings, regardless of the manufacture.

The purpose of this discussion is to present some of the factors involved in the design, operation and maintenance of field compressor installations and to point out some of the advantages of using the packaged compressor units for this service.

This paper will examine the design, economic factors, field installation, performance, and field testing of regenerators(exhaust heat recovery systems) installed on existing industrial gas turbines. The information contained in this paper was primarily derived from the conversion in the field of four industrial gas turbines of the 10,750 brake horsepower (ISO) range from simple cycle to regenerative cycle operation.

It is important that all electrical contractors on location perform quality work. The end product of their work must meet OSHA regulations, NEC and API code standards. OSHA regulations are enforced by the federal government, whereas, industrial codes do not generally have the force of regulations. Reduction of field operating expenses will be achieved by upgrading the electrical systems. Better electrical systems will reduce field downtime and this will generate more production. During the electrical upgrades, all deenergized powerlines must have a phase-phase fault and a phase-ground fault established. These faults change the characteristics of the powerline, which is an OSHA regulation. The major cause of damage to electrical equipment is incorrect fuse sizing and improperly wired control panels. An alternative to relocating powerlines is to place fused cutouts with attached lightning arrestors on the conductors. This will allow the powerline to be deenergized during well workovers. Upgrading the electrical systems will improve workplace safety for the employees.

The advantages and techniques of extended period batch treating as compared to conventional treatment are presented. Results of field tests in central Kansas are reported.

A new gelled acid was evaluated in the West Texas, Southeast New Mexico and Oklahoma areas. The purpose of this evaluation was to determine how successful a gelled acid, prepared from xanthan polymer, would be in the following formations: Ellenburger, Blinebry, San Andres, Clearfork, Canyon Lime, Strawn Lime, Grayburg, Devonian, Drinkard Dolomite, Viola and Chester. Treatment depths vary from 4,000 to 22,000 ft. Treatment temperatures vary from 70_ to 310_F. Treatments were performed on both oil and gas wells. The age of the wells stimulated varies from new to 30 yr old. The concentration of gelled acid remained constant at 15% HCl. The concentration of gelling agent remained constant at 60 lb/1000 gal. The size of the treatments varied from 5,000 to 80,000 gal of gelled acid. More than 20 treatments are summarized. Several types of acidizing techniques were employed using gelled acid. These treatments vary from one to nine stages with and without diverting agents and with and without leakoff control additives. These treatments vary from 2 to 15 BPM. Some of these treatments contained 20/40 Sand, N2 and/or radioactive tracers. Production figures for the wells treated are discussed, as well as pertinent related information.

Initially, the waterflood operator must establish that he has a biological problem. This evaluation is best accomplished by a complete microbiological examination, made in the field, or of the waterflood system. If such a problem is found to exist, then the choice of a chemical as an effective bactericide depends upon economics, compatibility with water, plugging tendency, and toxicity.

An acidizing technique has been developed for treating carbonate reservoirs that will give deep penetrating fractures with high flow capacity. Production results from these treatments have been excellent. The technique uses the principle of hydraulic fracturing with a thickened fluid. Instead of using a proppant in the fluid, acid is used to produce flow capacity by controlled etching of the fracture system. Overall treatment success has been good. New and old producers with varying productive capacity have been treated. New wells have performed at least equal to and in most cases better than conventionally treated offset wells. Some old wells have performed exceptionally well; others indicated no favorable increase in production. The advent of complex fracturing fluids led to the idea of using a viscous pad to control leak-off of acid for more fracture height and width. These factors, it was theorized, would give greater acid penetration. The method was first tried in a well where conventional treatments had been unsuccessful. Results, which were good, led to laboratory work to determine possible reasons of success. This work indicated that the fingering of thin acid through a viscous fluid was the key to the treatment. Figures 1, 2 and 3 show laboratory models illustrating what occurs in this treatment. An analytical procedure for treatment design followed this investigation. Figure 4 is a typical computer-designed treatment.

Previous methods to detect and locate fluid flow behind well casings such as temperature, radioactive tracer, or acoustic noise have been successful but often difficult to interpret. An alternative method which is specific for detecting water flow (or CO2 flow) is the oxygen activation log. This paper presents field examples from West Texas of the Water Flow Log which is based on a new approach to oxygen activation logging. Each example demonstrates the importance of this measurement in obtaining a conclusive interpretation to difficult production problems caused from channeling fluids behind pipe.

Previous methods to detect and locate fluid flow behind well casings such as temperature, radioactive tracer, or acoustic noise have been successful but often difficult to interpret. An alternative method which is specific for detecting water flow (or CO2 flow) is the oxygen activation log. This paper presents field examples from West Texas of the Water Flow Log which is based on a new approach to oxygen activation logging. Each example demonstrates the importance of this measurement in obtaining a conclusive interpretation to difficult production problems caused from channeling fluids behind pipe.

This paper presents three years of field experience showing dramatically improved rod string performance, resulting in lower intervention costs.
There are three key factors in achieving this improved performance. First and foremost is the rigorous application of best practices for rod handling, connection cleaning, preparation and lubrication. Second is the use of a fully automated rod tong which delivers accurate CD control on every connection in the string. She third factor is a secondary measurement of true torque for each connection, giving further assurance that proper pin tension is achieved.
This experience has demonstrated that API 11BR does contain the proper recommended practices for successful rod makeup. Suggestions are presented for future topics which could be considered for further enhancement of API 11BR.

During the past 10 years, methods have been developed to adequately and economically protect lease surface vessels fabricated from mild steel and subject to corrosion. In general, these methods have fallen into 2 categories

The South Cowdeu (San Audres) Unit was selected as the site for one of three mid-term projects to be conducted under the DOE Class II Oil Program for Shallow Shelf Carbonate Reservoirs. The $21 million project was designed to demonstrate the technical and economic viability of an innovative carbon dioxide (CO2 flood project development approach. The new approach employed cost-effective advanced reservoir characterization technology as an integral part of a focused development plan utilizing horizontal injection wells, where appropriate, and centralization of production/injection facilities to optimize CO2 project economics. This paper will review actual implementation and field performance in the first eighteen months of the project, focusing on key issues of timing, stimulation, injection profile monitoring, reservoir pressure reduction, and conformance control A comparison will be presented of initial simulation model results with current predictions.

Fluid loss into the formation matrix can be a serious problem during overbalanced workover operations, Invasion by the completion fluid can cause near-wellbore damage and can also cause problems associated with poor wellbore cleanout and loss of hydrocarbon reserves. In addition, fluid loss can increase costs associated with rig time and treatments devoted to restore the initial condition of the formation. Traditional techniques to minimize fluid loss use solids or viscous pills, although it has been amply documented that these systems can damage the formation if not properly removed after the treatment. This paper presents the laboratory development and validation of a novel solids-free fluid-loss (SFFL) system used during overbalanced workover operations. This system relies on an ionic polymer that decreases matrix permeability to aqueous fluids, limiting leakoff into treated zones. This polymer immediately adsorbs to the surface of the rock,
eliminating the need to shut the well in. In addition, this system does not require the use of breakers, which eliminates negative impact on post-stimulation well productivity. Laboratory test data show the capability of the material to control fluid leakoff and achieve high levels of regained permeability to hydrocarbons. To date, about 110 jobs have been performed with this novel SFFL system. The paper discusses field results from the application of this system during overbalanced workover operations and other applications where maintenance
of a hydrostatic column is necessary for well control. This system has been proposed for solving partial and total loss to full circulation in overbalanced operations such as: (1) lost-circulation events occurring during cementing, fracturing, and drilling, (2) well intervention cleanouts by coiled tubing (CT) and hydraulic workover (HWO), (3) gravel packing, (4) replacement of artificial lift equipment (i.e., electrical submersible pumps), and (5) overbalanced tubing-conveyed perforating (OTCP), among others.

To investigate the causes of fluid migration behind the casing after primary cementing, pressure and temperature measurements were made in the annulus of seven wells during cementing operations. Sensors were attached to the outside of the casing as it was run into each well; in this way data were obtained from several depths. A logging cable, also clamped to the casing, was used to bring data from the sensors to the surface. In some of the wells these annular measurements were continued during subsequent completion or workover operations. The pressure data could be used to determine conditions that either prevented or allowed fluid entry into the wellbore. Generally, pressure in the cement column began to decrease shortly after the cement was pumped. The success of the cementing operation depended on the cement attaining sufficient strength to exclude pore fluids from the cement before the pressure somewhere in the cement column declined to pore pressure at that depth. Pressure in the cement generally appeared to decline to the pore pressure in adjacent formations after the cement had set. In one well, however, pressure in the cement opposite a "tight streak" steadily declined to far less than a water hydrostatic gradient as the cement set.

Production of natural gasoline and other liquefied petroleum gases from casing head or oil well separator gas and gas distillate is the primary function of a natural gasoline plant. In this role, it demonstrates just another step taken by our industry toward achieving maximum utilization and deriving maximum benefit from one of our country's important resources, natural gas.

In the beginning of this project the primary goal was to compare IPC and Bare tubing and discern which was more effective in lowering tubing failures and which was more economical. In this project, a sample of 62 wells was examined from the Sprabeny area as well as an additional 152 wells from the Preston Spraberry Unit "Best Practices" program. All wells were evaluated from January of 1996 to July of 2002. The question in concern was if IPC should be part of the optimizing process. During the research for the answer to this question it became evident that more conclusions could be drawn from the information gathered than was originally expected. Not only was the IPC question to be answered but the effects of other optimization techniques were seen as well. In this report, one will see the final decision on the effectiveness of IPC as well as the parameters needed for it to be effective. One will also see the benefits of Sinkerbars and Pump off Controllers (POC).

Numerous articles have been published on field application of dynamometers. However, dynamometers are not widely used. Use of dynamometers has been limited by the difficulty of interpreting dynamometer cards. This paper deals with recognizing rod-pumping problems through field analysis of qualitative dynamometer cards.

Scale and paraffin problems cost the oil industry billions of dollars in prevention, maintenance and repair each year. A new and innovative approach to well management, using a physical fluid treatment device, will be presented showing how it reduces well interventions and, correspondingly, improves production efficiency. Over 45 wells in West Texas were treated for scale and paraffin using a unique physical fluid treatment device over a period of 24 months. Specific case histories will be highlighted identifying prior operating issues and comparing favorable use incorporating the physical fluid device. The device, operating at 120 khz, is conveniently attached at the surface of the well and causes the scale to nucleate in the produced fluid rather than on the walls of the well tubulars. Paraffin is attracted to the scale and other inorganics and also remains in the produced fluid. Paraffin and scale are carried away with the produced fluids.

Newly drilled water injection wells in the Shell operated Jordan University Unit in the Jordan(San Andres) Field of West Texas exhibited thin intervals of high permeability (and poor profiles) soon after injectivity began (Fig. 1). The wells had been selectively acidized (straddle packers were used to isolate each perforation while acidizing) with surface pressures of not more than 500 psi. Since fiberglass casing was cemented across the entire injection interval, the use of cement to squeeze off selected perforations (prior to reacidizing perforations not taking water) was not feasible because of its high density and hard set. A plugging material with a low viscosity and a specific gravity approaching that of fresh water was needed in order to plug the rock matrix near the wellbore. A crosslinked polymer was used because its specific gravity and viscosity approach that of fresh water, and it is a non-particulate. Therefore, the polymer could be used without hydraulically fracturing the rock or "plating out" on the wellbore face. The use of polymers in injection well profile control has been well-documented in previous publications. A different method of application of a crosslinked, stiff gel polymer (American Cyanamid Company AM-9 Chemical Grout) was successfully used to alter injection profiles in the three San Andres dolomite water injection wells. Proven fluid design techniques were successfully used to premix a gel solution and a catalyst solution at the surface ("on the fly") for a downhole (3800 ft) setting time of approximately 20 min. at 90" F. The resulting solution had low viscosity pumping characteristics, yet rapidly increased in viscosity at the desired setting time. Consequently, the solution pumping characteristics were also similar to fresh water. In addition, an under displacement gel placement technique was utilized to assure that uncontaminated polymer was gelled in the pore network (within a radius of 6 to 8 ft) and back into the wellbore. The under displacement technique and reacidizing of old tight perforations were the keys to injection well profile change in the Jordan University Unit. Production history data from wells surrounding the three injectors reflect an increase of approximately 550 BOPD over an 18-month period. The increase in oil production is a direct result of injection well profile improvement. See Table 1 for an economic analysis of the cost of the three worked-over injection wells and of the production results associated with the 16 surrounding producing wells.

One of the more extensive uses of directional drilling anywhere in the world has been in the development of the East Wilmington Oil Field in Long Beach, California. The average well achieves a deviation from vertical in excess of 50' and wells with a build-up in the 70 to 80 range are not uncommon before they are dropped off to 50 or less when penetrating the completion interval. Over 780 wells have been drilled in this field to date, requiring the highest degree of control and accuracy in order to avoid intersection of other wells and to obtain proper bottom hole spacing. The Measurement-While-Drilling (MWD) directional system has been tested on several wells and proven to provide the required accuracy along with many advantages over past methods used in the field development. Accurate transmission by MWD of bottom hole measurements to the surface is provided by mud pressure pulses generated in the drill pipe downhole and detected by a pressure transducer mounted on the standpipe. Surface equipment includes the means for detecting, recording and processing these pressure pulses, to translate the information from the pressure pulses to rig floor displays useable by the drilling crew.

The McKinley afterflow method has been successfully used to interpret drill-stem tests (D.S.T.) and short-time production tests where conventional analysis methods cannot be employed, or are difficult to apply." Although the afterflow method has other applications, this study will be limited to pressure buildup behavior. Throughout this paper the McKinley afterflow buildup method will be referred to as simply the afterflow method. The Horner method is the most commonly used technique for interpreting short-time test data, so the following examples will be compared to this method.2 Effective permeability, wellbore damage or stimulation, radius of investigation, and expected production rate are the reservoir parameters obtainable by the afterflow method. Exact numerical values are not obtained by this or any curve-matching procedure, but the order of magnitude of the answers is sufficiently close to help make decisions that are normally made from a short-time test. Six examples have been selected to illustrate the application of the afterflow method. These examples are typical of many tests analyzed from producing areas around the world. They hav,e been selected because of the large amount of followup data made available by Henry Engineering and other industry companies. Reference 1 describes the analytical treatment of the afterflow method. Utilization of the afterflow method to D.S.T. and short-time production tests has previously been described by Milner and Warren in S.P.E. number 4123. Our contribution through this study is to present verification, by actual field results, of the afterflow method to certain types of problems.

With existing demands for oil and gas at continued higher prices, there has become a greater interest in previously uneconomical reservoirs. The Cisco and Canyon formations in Sterling County, Texas fall into this category. In particular, the Conger (Penn) area has enjoyed rapid and continuous development since 1977. Hydraulic fracturing has been required to stimulate for commercial production. Stimulation practices have been reviewed and a more efficient approach developed to provide maximum productivity at an optimum cost.