Sucker-rod pumping system is the most numerous among all artificial lift methods used in the Permian Basin. Therefore. continued efforts to improve and optimize sucker-rod performance are imperative for successful operation in this area. The Artificial Lift Energy Optimization Consortium (ALEOC) was formed by eleven oil companies operating in the Permian Basin with the primary goal of improving oil field operations through sharing experiences. The consortium members provided beam pump related data from about 25.000 wells, which is about a quarter of sucker-rod pumped wells in the entire Permian Basin. A database has been developed to combine these data into a single, uniform and consistent format. The database can be queried and analyzed either via the Internet or in the desktop environment. From the query results, one can calculate failure frequencies of pump, rod, and tubing, and summarize the results in various ways. Such analysis will suggest answers to questions like what component is the most/least likely to fail. which operating areas have typically high/low failures, and what is the performance of a company relative to the other companies. Knowing these facts should greatly benefit each company in making engineering and business decisions.

Marked advancements have been made during the past four decades since the first commercial hydraulic fracturing treatment was performed in 1948. The high sand concentration fracturing process is one of the most dramatic of the advancements that have been realized. The central thesis of this paper is the evolution of the high sand concentration fracturing process, and the paper is composed of the following three categories. 1. Development. The high sand concentration fracturing process is presented from its conception in 1960, thru the first experimental treatment in 1972 and the first complete successful treatment in 1976, to the present status of the process. 2. Design. An overview of the procedures and mechanics required to design and perform a successful high sand concentration fracturing treatment is presented. 3. Results. Initial and long-term production increases are presented for high sand concentration fracturing treatments, and where possible, they are compared to conventional sand concentration treatments.

There are a variety of sucker rod grades available today for different pumping environments. In order to optimize the run time of an oil well, it is very critical to choose the correct sucker rod grade for a particular application. There are a lot of physical attributes (engineering attributes) which need to be considered for design aspects of a rod string. Some of the engineering concepts are yield, tensile, load carrying capability, stress-strain curves, elongation, reduction of area and toughness. The first segment of this paper addresses these sucker rod concepts using stress-strain curves. One of the most well known practical problems faced in the field is the selection of sucker rod grade in a high load and corrosive environment. The obvious choice becomes a KD grade sucker rod because HS (High Strength) rods due to their mechanical properties should not be used in corrosive environments. As a result of this, the end users had no choice except to overload KD rods in corrosive environments. UPCO, Inc. has developed and tested a new grade of sucker rod which can be used in higher load wells where high strength rods are not an option due to corrosive nature of the well. The second segment of this paper addresses the development of the new grade of
sucker rod (SD). SD grade of sucker rods fills the application gap between KD and HS rods. SD rods have better load carrying capability than a KD rod and a better toughness than a HS rod.

In a potential gas-bearing Woodford shale reservoir (Ro% = 2.62 and MI = 11.3 DRY GAS) with a standard logging suite [Array Induction

The removal of accumulated liquids from the wellbores of gas wells is a problem which has faced operators for as long as natural gas has been produced. The reduction of deliverability resulting from these liquid accumulations and the expenditure of cash and energy to remove the liquids are at best expensive nuisances, and at worst, economic catastrophes. Many approaches have been taken toward the solution of this liquid removal problem with varying degrees of success. The type of approach taken depends upon a number of factors including the type of liquid to be removed, available reservoir energy, and economic considerations. With adequate available reservoir energy and optimized production practices, expenditures for artificial lift aids may be minimized or eliminated; With slightly less energy to draw upon, these aids may take the form of gas lift or cycled pulsing or purging of the wellbore liquids. The worst conditions, from an economic standpoint, involve those wells which due to pressure decline, excessive liquid influx, or low permeability, require mechanically lifting an unsalable product. This is recognizable as pumping water from gas wells, and is not a new idea to many operators including El Paso Natural Gas Co. which has been operating pumping units on gas wells since 1964. One of the most recent entries in the field of pumping equipment is the pneumatic pumping unit. The units which El Paso now has in operation are proving to be a valuable addition in dewatering low-pressure gas wells. At present El Paso operates some 69 pumping units in the East Panhandle Field in Texas and the South Erick Field in Oklahoma. Of these, six are pneumatic units and the remainder are conventional beam-type units powered by gas-fueled engines or electric motors

In the effort to raise more hydrocarbons to the surface, production practices have evolved which aggravate certain corrosion related problems. One of these problems, corrosion fatigue, is usually associated with rod pumped wells because it has a stress component plus a corrosion component; as wells are pumped harder, stresses are higher and corrosion fatigue becomes more prevalent. Another of the problems becoming more frequent is an indirect result of both harder pumping and depletion of gas pressure in oil reservoirs, and a direct result of certain stimulation methods; oxygen can enter production fluids and alter the mechanism of corrosion in oilfield fluids. This paper outlines diagnosis of these two problems and describes their control with corrosion inhibitors.

The proper and economical operation of pumping wells may be simulated to a good safety program. The problem is always changing, inasmuch as reservoir conditions immediately around the well bore change from month to month.

Diagnostic methods and programs for rod pumping commonly assume that the wellbore is vertical. Applying these methods to deviated wells will result in distortions and inaccuracies when calculating the down-hole pump card. This paper describes a new method for analyzing pumping efficiencies in deviated wells. The method requires a deviation survey for the 3-D borehole trajectory that incorporates the dogleg effect (rod/tubing drag forces) into the solution of wave equation. The program is applicable to wells with bare rods, molded-on rod guides, and wheeled-rod guides or a combination of these. Real examples are shown to compare results from both programs. The deviated program improves the accuracy of the pump card and the card is easier to interpret. Thus, the producing pressure and pump displacement rate based on the pump card are more precise. In addition, the deviated diagnostic program can generate data that can be used to improve the accuracy of the deviated predictive program.

The petroleum industry's need to reduce cost challenges users to select the most effective tubular goods inspection for each individual job to minimize the large expense normally incurred with replacement or repair of defective tubular goods. Several diagnostic tools are necessary to meet the many variable inspection requirements for the different grades of new and used tubing, casing, drill pipe, line pipe, and sucker rods. Inspection methods are available which, if properly employed, should detect defects currently considered hazardous. Those associated with ordering and using tubular goods inspections should insure that each inspection dollar earns a profit; this requires selection of the applicable inspection method for each job and economic considerations to determine if the inspection should reduce cost by minimizing possibility of failure or premature retirement of pipe or rods from service.

Diamond Enhanced Hammer Bits in conjunction with Down-the-Hole Air Hammers have been utilized throughout the 1990's to improve penetration rates in hard formations as well as to reduce deviation and improve overall drilling costs. Significant improvements in bit life have been made by utilizing the 3rd Generation Impax Hammer Bits along with the current Best Drilling Practices that have been developed in the Val Verde Basin. This paper will review these Best Drilling Practices as well as discuss the new technology that was developed for these Percussion Drilling applications.

This paper compares the costs of diatomaceous earth filtration and sand filtration.

The following discussion will be mainly concerned with diatomite filtration of salt water and industrial waste streams and subsequent subsurface injection. Filtration usually follows other treatment methods that may be used. Diatomite filtration is one of the most versatile, reliable and economical methods available to remove undissolved solids from liquids. Expenditures of several million dollars have gone into the careful design of filtration equipment and proper selection of filter aids. New ideas and techniques are continuously being developed to aid adequately in insuring safe and trouble free underground injection.

Directional Drilling is a service that assists Exploration and Production companies reach their intended geological target by drilling and deviated wellbore. Slanted, directional and horizontal wells are types of deviated wellbores. The rationale to directionally drill a wellbore are economics or environmental. Directional drilling is performed with tools that intentionally deflect the drill string from the existing wellbore using measuring or surveying tools to determine the path and wellbore placement.
Directional Surveying is a service that determines the spatial positioning of a wellbore by processing survey tools raw sensor data and computing it into survey stations. Directional surveys determine the distance to a geological target, a legal or field boundary, or another wellbore or wellbores nearby. Surveys provide inclination, direction and tool orientation from gravity, magnetic or gyroscope sensors. Single-Shot, Electronic Multi-Shot, Gyro and MWD are types of directional surveying tools. In this paper we will explain the basics and terminologies for Directional Drilling and Directional Surveying.

The use of hot oil as a paraffin removal technique has existed almost as long as the production of crude oil. It is still one of the most commonly used methods for the removal of paraffin deposits from the wellbore, tubing, flowline and tankage in the oilfield today. The relative simplicity of application, immediate results and low cost per application have made hot oiling an accepted, if not traditional form of paraffin removal. This paper discusses the disadvantages of hot oiling that have been overlooked in the past, but should be considered with our present knowledge concerning paraffin and asphaltene deposition. Topics discussed include the following problem areas; source of oil, loss of oil during hot oiling, formation damage, tubing plugging, flowline plugging, surface equipment problems and tank bottoms. Suggestions for minimizing each of these problems are made and an alternative to hot oiling is presented. These topics are presented for practical application on most rod pumping systems.

The use of hot oil as a paraffin removal technique is still used today in spite of its ineffectiveness in most wells. In 1982, the original paper on hot oiling recommended hot watering with chemical, which did not turn out to be the best alternative. In the past 30 years, we have learned much more about the paraffin problems we are trying to treat. A computer program from a Sandia National Laboratory Study, which was written in the 1990s, shows that you cannot melt most paraffin out of the tubing of wells. We learned that hot oiling and watering down the tubing of wells will reduce production. This paper will discuss other problems caused by hot oiling and cost-effective treatment methods that have been developed to take the place of hot oiling on most rod pumping systems. Case histories will be presented on the replacement of hot oiling with other treatment methods.

The use of automatic custody transfer equipment is growing rapidly after several years of intensive trial and development. The purpose of this panel discussion today is to explore these many questions that face our industry on ACT. Two members of our panel represent pipeline companies and two members represent producing companies.

We will start on the subject of Sucker Rod Pumping, since it is the oldest, about 3500 years old. Then we will go to Hydraulic Pumping, which is not so old, the go to Gas Lift, then to Reda pumps.

It is the purpose of this paper to summarize various displacement procedures which are currently in use and to discuss briefly the advantages and disadvantages of each. It is further intended to discuss certain trends in multi-string operations which tend to offset the economic advantage to this type of completion.

This paper discusses electric power systems and equipment for utilizing electric power. Included is a comparison of 12.5 KV and 22 KV primary systems, 480-Volt and 762-Volt secondary systems, and various types of motor protective devices. The application of the National Electrical Safety Code to oil field electric systems is also discussed.

In 1992 and 1993, Huber began working with problem-solving teams of production supervisors, well attendants, engineers and buyers from major and independent oil companies to find ways to reduce operating costs by improving the performance of stuffing boxes. Huber, which has since become Flow Control Equipment, Inc. (FCE), a wholly-owned subsidiary of Huber, began research in 1993 to support this project. Most of the stuffing box improvements identified by the focus groups fell into one of six categories shown below: 1. Longer-lasting packing 2. Less demand on the well attendant's time 3. Better lubrication systems 4. Less inventory to support stuffing box maintenance 5. Reliable leak detection and fail-safe options 6. Rapid pay-out for investments in new equipment Early in the research project, it became apparent that improvements could be achieved in almost every one of the six categories by reducing the coefficient of friction between the stuffing box packing and the polished rod. Rubber, the most widely used packing material, was ideal for its flexibility and memory, but very undesirable for its high coefficient of friction. High coefficients of friction generate heat and result in more frequent stuffing box leaks. Progress to reduce the coefficient of friction was first reported at the 1994 Southwestern Petroleum Short Course at Texas Tech by Larry Angelo in a paper titled "Metal Film-Coated Stuffing Box Packing". Larry Angelo reported partial success using the MagionTM process to apply a molecular layer of metal over conventional cone rubber packing to reduce the coefficient of friction between the polished rod and stuffing box packing. Since then, Huber and subsequently FCE, has continued to pursue this objective and this paper is the second report on the progress of this research. The need to evaluate various stuffing box packing materials led to the development of laboratory test equipment shown in Figure 1 which could be used to measure the friction between the polished rod and packing. Tests were conducted on this equipment in non-lubricating environments - the most challenging of all conditions for testing the performance of packing. Metal film-coated rubber was partially successful. Combining PTFE with rubber, which is the subject here, was more successful.

Tank Batteries can emit VOC's (volatile organic compounds) or gas vapors. Quantities of gas are directly proportional to the volume of crude oil present at the Tank battery sight. Other factors effecting gas vapor volumes include line pressures, separation equipment pressures, and ambient temperatures. These vapors can be recovered and sold if sufficient volumes are present.

There has long been felt the need for a rod insert pump which would fit in the interim from the point in the life of a well where conventional insert type pumps become incapable of handling increasing fluid in the well bore beyond the anticipated requirements of the original equipment. In numerous instances, either for economy or from miscalculation, equipment too small for final depletion of the reservoir is installed. This could be either in the well bore, surface equipment or both.

Flowing/pumping transient analysis was performed on a group of wells scattered across the Permian basin that had been re-stimulated with relatively large volumes of brine and an ultra-lightweight proppant with substantially the same specific gravity as the brine. The results of these analyses are presented, and effective infinite conductivity fracture half-lengths are reported and compared to offsets that were stimulated with more conventional techniques.These analyses, along with other parameters that were recorded off several hundred treatments performed, were utilized to develop a set of guidelines for optimum candidate selection for future work. The candidate selection parameters are presented, and practical guidelines for exploiting and optimizing the process are explained.

The oil occurring in oil reservoirs is associated with varying quantities of water and gas. Both the water and the gas entering the well bore must be produced in order to produce the oil. In the early life of a field, when the reservoir pressure is high, the gas is used as a means of lifting the fluid. This is generally accomplished by shutting in the casing and permitting sufficient pressure to build up in the annulus between the casing and the tubing. When this occurs, oil, gas and water rise up the tubing in a frothy mixture and pass through the flow bean into the lead line. In this case, an actual bottom hole mixing rather than a bottom hole separation occurs.

This application was done in Manantiales Behr Field, REPSOL YPF, well AEA-507. This is a field located 30 miles northwest of Comodoro Rivadavia City, in Chubut's Province. The field's characteristics are heavy oil, very high viscosity, low production (1 5-60 m3/day), medium water cut, medium depths (1200 meters) and sand. Besides, the weather conditions are very harsh during the winters, getting below 0C.