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.

Manufacturers of down-hole sucker rod pumps have developed materials, coatings and treatments for barrels and plungers. Some of these have become standards in the industry while others have been tested and either did not meet expectations or were not economically viable. This paper will review historical, current and new materials, coatings and treatments for down-hole sucker rod pump barrels and plungers.

Completions for thermal recovery installations are closely related to the many new and sophisticated approaches to well design which have come of age during the last decade. This writer likes to compare them with completions in the 15,000 - 20,000 ft range, to high pressure gas completions in corrosive environments. perhaps to wells on platforms in deep water or completed by TFI methods. This comparison is made not because the magnitude of engineering difficulty in each instance is equal, but because the total probIem content of each of these completion techniques represents a distinct engineering challenge and required unique solutions. Finding these solutions in turn required the use of classical methods and theories mixed with original thinking. Let us then examine why thermal recovery wells qualify for a position amongst difficuIt and sophisticated technological accomplishments

In 1972 a carbon dioxide/water injection project began in the SACROC Unit, Kelly-Snyder Field in Scurry County, Texas. The injection of CO2 and the highly corrosive produced water has created some very unique problems with downhole equipment. New materials of construction, new design parameters, and new treatment methods have been developed to deal with these problems. The paper describes the corrosion problems encountered with submersible pumps, sucker-rod pumps, tubing, sucker-rods, and other downhole equipment, and it describes the solutions found for these problems. Chemical treatments, coatings, and monitoring programs are discussed. Finally,, the effect CO2 injection on downhole corrosion is evaluated.

The Downhole Diverter Gas Separator increases the liquid capacity and gas separation capacity over conventional poor boy or Improved Collar Sized downhole gas separators. The increased separation capacity of the diverter gas separator is provided by using the larger tubing-casing annulus for both gas separation and liquid separation. A simple movable rubber seal is used to divert the flow of liquids and gas vertically from below the rubber seal through a central tube approximately 5 feet in length. When the fluids exhaust into the tubing-casing annulus above the seal, the large annulus flow area reduces the annular gas velocity which allows the liquid to fall back through the large area tubing-casing annulus into the pump intake. Larger tubing-casing annular area below the diverter exhaust port provides high liquid capacity. Large tubing-casing annular area above the diverter exhaust port reduces the gas velocity, reduces liquid holdup and provides high gas separation capacity.

The Downhole Dynamometer is a tool designed primarily for the acquisition of sucker-rod load and position data at any point in the rod string. The tool is completely sealed, battery-operated, and microprocessor-controlled to sample the various parameters at specific times and sampling rates and to store the data digitally in a nonvolatile memory for later retrieval. Other parameters sampled are temperature and pressure and, with the present design, bending data is also collected. Axial position is derived from acceleration. At the time of this presentation two-dimensional lateral accelerations may also be available. While used predominantly for code validation the tool could be an effective well-diagnostic device as well.

The Downhole Dynamometer is a tool designed for making dynagraph measurements at any point in the rod string. The tool is completely sealed, battery-operated, and microprocessor-controlled to sample axial load, position, lateral acceleration, fluid pressure, and temperature at preprogrammed times and sampling rates and to store the data digitally in a non-volatile memory (Figure 1). Load is measured at three points spaced radially equidistant around the body of the tool enabling the derivation of bending and buckling loads. Rod velocity and acceleration are also measured. The tool is used in the industry as a diagnostic device and to validate predictive and diagnostic codes. Any number of tools can be used simultaneously at different points in the string. 1994 was a maturing year for the tool. This presentation one year ago was devoted to the evolution of the downhole device. The focus this year is on the present state of the tool, calibration, accuracy and how to use it.

Downhole Oil Water Separation (DOWS) is becoming one of the key technologies of the oil industry and to reap the benefits promised by this concept, a new system has been developed to separate oil and water in the wellbore. The first test of the system - the Triple Action Pumping System (TAPS) - will be described in this article. The new system has accomplished a number of industry firsts in oil/water separation. The potential of DOWS to improve revenues, reduce expenses and investments, and protect the environment when the right conditions exist has been described in previous article. By virtue of its capability to inject at high pressure, TAPS opens the door for DOWS to provide a whole new (less costly) method of waterflooding. The successes of this test are primarily attributable to two conscious efforts: 1) commitment at all levels - from the field to management and 2) true team effort involving an operator, vendors, and government agencies. As the DOWS acronym suggests, the TAPS is capable of economically separating and injecting water downhole while producing only a fraction of the water to surface with the hydrocarbons. TAPS has extended the applicability of DOWS to "hard rock country" where high injection pressures are common. The TAPS is believed to have accomplished a number of industry firsts: -It showed that oil and water segregation occurs even when the pump is placed below the well's producing perforations. This is significant when it is important to minimize backpressure on a well. -It employed produced water recycling to achieve environmentally friendly "zero discharge". That is, any water produced to surface was dumped back down the annulus and injected so that no water hauling was necessary. This process is a closed system that reduces discharge opportunities and facilitates chemical treating. -A pseudo-permeability log4 (created using neural networks) was used to select the optimum injection interval for a DOWS application. -A water-soluble, oil-dispersible chemical was used to protect both the producing and injection zones. This treating method appears to be far more successful than previous approaches.

A novel image acquisition system has been developed that will enhance our knowledge of downhole pumps. This system, comprised of a video camera, digital frame grabber and image processing routines, has been integrated to the downhole pump test fixture at the University of Texas at Austin where in the past pressure at various point of interest around both the standing and travelling valves have been recorded. As the images and pressure information have been recorded at the same exact time, one can now look at the picture of the pump to see the actual valve movement for each interesting

With today's economic condition, competitive market, and customers world wide clamoring for lower prices, the need to maximize the economic operation of an oilfield has never been greater. This paper is directed toward abrasive wear and increasing pump barrel life. The first step in increasing the life of a pump barrel is to understand why it wears out. After we grasp the cause of wear we can design or select a product that wears slower. Wear cannot be stopped but only slowed. The user must examine worn out parts, keep records, and have a working knowledge of available materials in order to select a barrel most economic for the task. The cost you notice most is when you have to pay for another barrel, but the more significant costs are those of pulling, repairing and reinstalling the pumps, and the lost revenue when the oil stops flowing. Those costs tend to get lost in the general aggravation of being in business in the first place.

The Drill Stem Test (DST) is a temporary well completion, which is made in the early production life of a potential reservoir to determine both the quality and quantity of produced reservoir fluids. This can be done prior to completing the well. The drill stem is used to lower the packer(s), downhole valve assemblies and other auxiliary tools to the bottom of the hole. The packer is a device which expands and effects a seal with the wall of the hole and isolates the zone to be tested from the drilling fluid in the annulus. The surface-operated downhole valve assemblies are devices used to relieve the hydrostatic drilling fluid pressure from the face of the formation to be tested, allowing the produced fluids to enter the drill pipe and be trapped so that they may be recovered and measured at the surface. An upper tool valve allows the formation to produce into the drill pipe for a specified time. The tool can then be closed and the formation buildup pressure can be recorded again for a specified time. The opening and closing of the downhole valve can be repeated for two or more flow times and closed-in times. Other tools and accessories are also used in modern drill stem tests. Accurate pressure data are very necessary for the interpretation of the test and analysis of the tool behavior. During DST"s, two or more subsurface pressure recorders should be used. These provide the means for obtaining accurate reservoir pressure records. One recorder should be located below the packer, in a blanked-off position. Since no fluid should flow past this recorder during the test, it will record the pressures directly from the annulus. The other recorder is in the flow stream above the packer but below the tools and bottomhole choke. This arrangement of recorders is necessary to help insure the detection of any anchor, tool and/or choke which could cause plugging, and for obtaining accurate pressure data. Most downhole pressure recordings are under dynamic rather than static conditions.

Damaged pipe, especially in horizontal applications, is costly. The large number of planned horizontal drilling projects
coupled with the expense of pipe replacement and fishing operations made it imperative that Mobil E&P gain a better understanding of drillpipe life. Previous internal studies of failure flurries have shown that excessive doglegs, high H2S environments, and improper specifications or makeup on tubing connections can accelerate fatigue leading to failure. The effect of high bending stresses on drill pipe connections is also a concern. Inspections, typically used to determine pipe condition, prove only obvious defects and not fatigue. The goal is to evaluate DPLIFE2's ability to predict failures by comparing the program result with actual failures. Another objective is to evaluate the overall consumed life of the tubing and determine a "best practice" for replacing pipe before failures occur.

Prior to the 1973-74 Infill Program, the Shell operated Denver Unit, Wasson San Andres Field, Gaines and Yoakum Counties, Texas (Fig. 1) included over 900 producing or injecting wells. Upon project completion in October 1974, the 1973- 74 Denver Unit Infill Program added 120 wells (14 injectors, 3 replacement wells, and 103 new producers) to this total. The 1973-74 program was sufficiently different from previous Denver Unit programs to require some changes in techniques and equipment. The most significant differences were cementing production casing to surface and drilling "intown" and/or directional wells. These changes and the large number of wells necessitated the review of all drilling program facets to optimize performance and reduce costs. This paper presents the more significant points of this review and was prepared to document the cost reduction methods and the experience gained for use in future programs. The items discussed individually represent small cost reductions but collectively resulted in reducing 1973-74 Denver Unit Infill Program expenditures by $250,000.