Formidable technical and operational problems arise in the course of drilling, testing, and producing wells which contain appreciable amounts of hydrogen sulfide. Though not the worst of such problems, wireline operations are certainly rendered more difficult and dangerous. Logging equipment is designed to perform properly in the high temperatures and pressures found in oil and gas wells. The presence of hydrogen sulfide has thrust forward a new hostile environment problem. The troubles are twofold: the threat of personnel overexposure, and the deterioration of metal components which are exposed to HS. Industrial plants have long known of the dangers to personnel who are exposed to hydrogen sulfide. Steps were taken to learn the procedures necessary for personnel safety. These procedures were then adapted for use by our logging crews, and have been effective in that no case of hydrogen-sulfide poisoning has been reported. The downhole problem created by the presence of hydrogen sulfide is harder to correct. The solution to the problem was evidently either to protect vulnerable steels from contact with the gas, or to use other materials which were not vulnerable. Both measures have been successfully applied. Protective coatings are good enough to permit the use of standard cables and downhole tools in cases of low HlS concentration, but special H2Sresistant cables are needed for severe conditions. In no case, however, should sour-gas logging operations be looked upon as routine. HS-resistant pressure-control equipment is also available. Pressures to 15,000 psi can be controlled.

Mineral scale formation is a problem for oil and gas operators that can result in deterioration of assets, increased lifting costs and lost production. Scale which forms in or at the perforations can only be prevented by placing scale inhibitor in the producing formation via some type of reservoir displacement technique commonly referred to as a squeeze. Operators desire inhibition that will last as long as possible and minimize the production interruption for treatment. In reservoir formation types that exhibit known scaling problems, scale inhibition treatment can be initiated during the completion stage using a solid inhibitor integrated into the hydraulic fracturing program. Treatments of this type can result in deep reservoir placement of inhibitor without large amounts of introduced water frequently needed with traditional squeeze treatments. Data presented in this paper illustrate the superior performance and longevity of these types of treatments.

Loss of drilling fluid to the formation is one of the most costly problems that drillers face during well construction. Common methods used in the past involved incorporating materials in the fluid or in pills to bridge permeable or fractured formations and create filter cake over these bridges. Current technology enables a comprehensive approach that complements these methods but emphasizes other aspects of the drilling operation. These include making use of drilling fluids that inherently reduce the rate of loss of fluid through modification of fluid properties like low-shear-rate viscosity; minimizing fluctuations in the fluid's equivalent circulating density; accurately modeling the rock mechanics of the formation; and strengthening the wellbore. Implementation of these techniques will be discussed, along with their impact in current drilling operations.

The Lovington San Andres Pool is located in central Lea County, New Mexico, approximately 10 miles northwest of the city of Hobbs. The 2400-acre pool was discovered by the completion of Skelly Oil Co.

Data gathering and alarm systems have historically been priced out of reach of the small oil producer. This paper deals with systems affordable to the independent operator. It explains specifications offered by suppliers and requirements needed to operate different applications. It also touches on different types of software and when it should be incorporated into the system.

Cementing production casing in partially depleted reservoirs is a common problem in the Permian Basin. The industry is continually looking for alternative slurry designs to lower annular pressures during cementing while maintaining the material properties needed for stimulation and zonal isolation. In order to be viable, the resulting technology must decrease density while preserving compressive strength, fluid loss and free water properties of the cement. Cement slurries using foam or hollow spheres are capable of meeting these requirements. The additional equipment and material cost required usually prevent these systems from being economical when mixed between 13.5 and 14 ppg (lbigal). Recent technical developments have lead to the creation of slurries weighing 13.8 ppg containing 60% pozzolan and 40% API cement. These economical slurries exhibit mechanical properties comparable to standard API slurries having much higher densities. Laboratory testing and bond logs are presented and compared along with recommended applications.

Two West Texas pumping gas wells were equipped with belt drive high efficiency C-25-30-54 pumping units, small diameter fiberglass sucker rods, and small diameter downhole pumps set at 3300 feet. These installations where originally powered by 1hp 460 volt electric motors to determine the exact power requirements. Two sources of alternative electrical energy are being tested, one is solar and the other is a thermocouple system burning well head gas. The experience gained will provide technology to go to deeper depths and larger volumes. These alternative power sources and related equipment offer advantages over the traditional gas engine for dewatering remote location gas wells.

Beam pumping systems are now operated in high speed and corrosive environments due to the ever increasing demand to produce oil in a faster and more efficient manner. Customer feedback indicates failures due to over, under, and loss of displacement. There has been significant amount of issues raised regarding the displacement values, the choice of lubricant used, and other critical factors affecting the displacement values. This paper describes the testing of various thread lubricants for Sucker rod/Coupling make up. The project uses the core engineering concepts of stress, strain, torque, and circumferential displacement. A comprehensive engineering analysis was conducted in the laboratory using an exclusive displacement testing machine which led to a selection of the best lubricant for field application. A total of 13 tests (12 lubricants + 1 no lube) were conducted under laboratory conditions.

The Levelland and Slaughter fields combined have produced over 1.6 billion bbls from 6000 wells and currently produce 6% of the oil in Texas. Most of the field is under water and CO2 flood operations. This paper investigates reservoir and petrophysical characteristics of various areas in the Levelland Slaughter field in order to assess relation to performance of secondary and tertiary recovery. The benefits would be to use this relationship to identify depositional environment/facies and relate them to flood performance. In areas where no flood has been installed, the relationships developed herein could assist in the ability to predict flood recovery and the method of development. The first objective was to divide the field into areas of like depositional environments. Once subdivided, relationships between petrophysical properties and secondary recovery rates are developed utilizing Lucia's rock fabric classification and production plot methods demonstrated by Reza Fassihi of BP.

This is a 1-hour presentation to meet the 1 hr. ethics requirement for re-certification for Professional Engineers as required by the state of Texas Board of Professional Engineers. The course covers several aspects of ethics pertaining to the engineering profession and directs the attendee to additional sources of ethics information. Basic guidelines suggested by the National Society of Professional Engineers (NSPE) and the Society of Petroleum Evaluation Engineers (SPEE) will be presented along with case histories.

The primary object of this paper is to stress the importance in obtaining, through proper maintenance programming, the proper engine operation, performance, and reliability. For these operational problems to be seen one must have a thorough understanding of multicylinder engines. The two basic categories that should be emphasized to insure trouble-free performance with a minimum of down time are operational procedure and engine components maintenance.

The purpose of this paper is to provoke a discussion with field operating personnel in the hope of providing constructive instruction relative to low speed gas engine operation. An internal combustion engine is composed of several complete systems, all of which contribute to the engine's operation. Breaking down these systems into general headings will simplify the discussion and present field problems which you, as an operator, control.

When it becomes necessary to put an oil well on the pump, the operator is usually faced with an investment of many thousands of dollars in some means of artificial lift. By far the most successful and the most generally accepted type of artificial lift is the beam type pumping unit. Many years of research and testing have gone into the design and development of the modern pumping unit. Advancements in metallurgy and the most up-to-date machine tools go into its manufacture. All these improvements in design and technique of manufacture are of little value if the equipment is installed improperly on the well, operated incorrectly, or is poorly maintained.

Codes and standards as promulgated by the various agencies governing oil and gas production equipment have changed so dramatically since 1934 that most manufacturing companies and production companies have little or no idea what is required. These changes started with the advent of OSHA as passed into law in 1970. This paper will address the changes that have occurred since the advent of OSHA to the present day as pertaining to pressure vessels.

Tubing make-up involves the joining of two threaded joints of tubing to form a leak tight structural connection. This activity is recognized as being an important part of the effort required to produce hydrocarbons. This paper seeks to identify factors that can affect the success of the make-up process. Having identified these factors, a brief review of their impact on connection make-up is presented. With this understanding, an effective running procedure can be developed. Considered are connection design, vertical alignment, connection cleanliness the power tong, connection monitoring, the thread compound and weight transfer.

More often than not, the most difficult part of any change is "Making the Decision to Change." Corporate change is
cultural in nature, as it must be done on a level-by-level basis to become effective. It must be inclusive of all and any change must be universally embraced and implemented to be effective. Corporate change speaks to and helps define the personalities of the corporation and ultimately its leadership. This paper blends the technical aspects of defining the needs, visualizing the system, designing, building, and marketing a "clean sheet, automated, and robotic well service system" with the research-development-bottom line anatomy of corporate America. Clearly, the mission is to build the safest, most efficient, and the most accurate system to service oil and gas wells. The associated risks and rewards, as well as the "Why do it" and "How to do it" from both the service company and the oil and gas operator perspectives are discussed in this paper.

Several software programs are available to calculate a pump downhole load-position card from dynamometer data. Most of these programs use the wave equation, with various solutions (Fourier Series, Method of Characteristics, Finite Differences, etc.) to help set damping conditions. A downhole tool with strain gauges is available to measure the actual forces at the pump as well as mid-string. Use of this tool has led to providing actual downhole values much less than those predicted by the software programs. This paper will present the actual data collected by this downhole lead cell. This data will then be compared to load values calculated by these commercially available software programs.

Historically, Electric Submersible Pumps were designed and manufactured for large volume applications producing from moderate depths. Low volume production (less than 400 bpd) was considered rod pump territory. Unfortunately, due to depth limitations inherent to sucker rods, rod pumping low production wells at deeper depths often becomes uneconomic due to high failure rates. Utilizing new control technology, the advent of wider vane designs, and high pressure housings, low volume ESP's have proven successful in replacing conventional and non-conventional pumping units in today's oil industry.

Rising oil and gas prices mean more revenue for Texas producers, but they also cause electricity costs to increase. Because electricity is one of the highest costs most producers face, managing electricity costs can significantly reduce LOE. This paper will focus on the primary mechanisms producers can employ to mitigate electricity costs including procurement options, interruptible power programs and enabling technologies. The paper will compare what one producer could have paid for electricity over the last year to what it actually paid.

Many Texas operators benefited from interruptible electric rates before deregulation in 2002. Several operators are now participating in a similar program called Load Acting As a Resource (LaaR) and saving 5-10% on monthly electric bills. In the last 30 months only four interruptions have occurred, each lasting between 7 and 22 minutes. LaaR requires onsite monitoring and control equipment along with suitable communication (telemetry) equipment or services, the cost of which often pays out in 1-6 months. Real-time telemetry needed for LaaR can augment or underwrite SCADA deployment. Web-based tools enable customers to participate, monitor and respond to LaaR events with minimal impact on critical production operations.

As our Industry places an increasing emphasis on natural gas, it is imperative that it's production be maximized. As reservoir pressures fail, many gas wells experience difficulty producrng to their fullest potential. This paper discusses a diagnostic "tool", which was developed to help detect gas wells with the opportunity to increase production. This paper will familiarize the reader with a Lotus spreadsheet, which was developed to evaluate several gas wells in South East New Mexico. Easy to obtain data from each well is entered into the spreadsheet. The spreadsheet then calculates several parameters that are used to evaluate the performance of each well. Using this spreadsheet "tool", the Engineer as well as the Lease Operator can identify wells that have the potential to increase production. Low pressure gas well production is often hampered by pressure restrictions and liquid loading problems. As the reservoir pressures continue to decline, eliminating these restrictions are even more critical. The "Gas Well Spreadsheet" is one way to help combat these operational concerns.

In May 1992, Marathon Oil Company implemented a San Andres waterflood on the Kloh Lease in the Howard-Glasscock Field, Howard County, Texas. The San Andres formation is a multi-layered carbonate reservoir characterized as having moldic porosity enhanced by natural fractures. Water injection into the various intervals was initially managed by mechanical isolation equipment. Due to high permeability zones, water cycling became a major concern. An interwell tracer program was initiated to identify which injection and production wells were in direct communication. Results from the tracer survey indicated the presence of thief zones in the lower injection interval that were responsible for rapid water breakthrough. This paper illustrates how polymer gel technology was used to further manage water injection in a multi-layered reservoir. Six injection wells and five producing wells were treated with polyacrylamide gel. Results from the injection well polymer treatments indicate an initial incremental response of 125 BOPD. Producing well polymer treatments showed an incremental response of 55 BOPD and a reduction in water production by almost 5,000 BWPD.

A survey of 328 executives in the top echelon in petroleum companies, including personal interviews with 82 of them, provides a definite picture of what makes a petroleum manager. The case study shows educational background, environment, operational route of advancement, motivation, etc. This is the only study of the kind ever made of petroleum industry leaders. The survey reveals a fairly even pattern for present managers but the interviews pointed to the changing needs of modern companies for professional executives. The steps up the ladder are broader and steeper and demand more preparation and more dedication. Our objective is to show clearly the preparation and attributes and effort needed to become a manager in the petroleum industry. An understanding of the responsibilities and rewards permits an engineering student to make an early choice either to seek management levels or to devote his energies and purpose to a technological career.

In this paper, Marathon's experience with the use of Cr(III)- carboxylate/acrylamide-polymer (CUAP) gel technology for use in oilfield conformance-control, sweep-improvement, and fluid-shutoff treatments, is discussed. Marathon has performed this technology on over 250 production wells resulting in the reduction of nearly 500,000 barrels per day of produced water. The CC/AP gel technology, which was conceived in late 1984, is characterized as having robust gel chemistry and as being insensitive to petroleum reservoir environments and interferences. This gel technology has been employed in over 1,600 conformance-control treatments worldwide. Highlights of field applications and results involving the CUAP conformance-control gel technology are presented.

Flowback of proppant and formation sand often become nuisance for operators as these solids cause equipment damage, costly cleanup treatments, and potential loss of production. These flowback problems are often compounded in severity in wells with high temperature and high pressure. Operators seek reliable solutions to (1) eliminate the need for frequent remedial cleanouts and surface equipment replacement, and (2) to maximize revenues by increasing and maintaining production rates. This paper presents a field case-study that discusses the remedial treatments and lessons learned in more than 20 wells in south Texas that the operator has encountered with proppant and formation sand flowback problems. It also discusses the development and treatment processes using low viscosity consolidating agents to be applied in the treatments. Examples show how these problems were successfully overcome in these high temperature wells. Field cases histories are presented with detailed descriptions of the treatments, challenges, and recommendations during the course of the treatments. Field results indicate that over 90% of these consolidation treatments have effectively stopped the flowback of proppant and formation sand while allowing the production rates of the wells to be increased. These treatments have drastically decreased the number of workovers as compared to the period before their treatments, or compared to the offset wells in the same field that consolidation treatments were not performed. This study has demonstrated that an effective coating of a curable resin on the proppant and formation sand close to the wellbore is necessary to help maximize the consolidation bonding between grains within the pack while minimizing any reduction of its permeability. Additives included in the liquid resin system permit good consolidation properties in the proppant pack, allowing it to effectively handle the shear forces of high production rates and the effect of stress cycling as the well undergoes producing and being shut in. This new remedial treatment process greatly enhances the effectiveness of fluid placement into the propped fractures, regardless of the number of perforation intervals and their lengths, without mechanical isolation between the intervals. The simplicity of treatment helps make remediation economically feasible, especially in wells with marginal reserves.