In this paper, the behavior and analysis of rod pumped wells are studied. In particular, the theory and practice of determining motor mechanical and electrical loading are investigated. The results from these measurements can be used to acquire further information regarding the system, including mechanical and electrical system efficiencies. The methodologies discussed in this paper are used to design rod pumping systems with correctly sized motors as well as analyze specific cases from the field.

This paper will cover NBIC Code requirements of proper materials, welding procedures, and documentation in the repair and / or modification of ASME Code pressure vessels.

For West Texas and Eastern New Mexico producing areas, analog pump off controllers are widely employed by numerous operators to optimize fluid recovery and reduce equipment failures for beam pumped producing wells. With the development of supervisory pump off control (SPOC) systems, pump off control technology can provide engineering and operations personnel with a more complete well surveillance package that includes diagnostic capabilities. In addition, SPOC system hardware configurations are deployed so that individual well site controllers send alarm signals, digitized dynamometer cards, and other pertinent operating data to a host computer when a lift equipment failure or anomalous operating condition occurs. Besides providing for an immediate response to an upset well condition, the stored data allows for more accurate determination for the problem source. Effective lift design modifications can then be accurately developed. Amoco Production Company (Amoco) had implemented analog pump off controllers, to work in conjunction with a proprietary lease automation system, for the vast majority of beam pumped producing wells. With the availability of SPOC systems on a commercial scale, pilot testing was initiated to determine whether this enhanced technology could provide sufficient benefits to allow for pump off controller retrofit. In addition, experiences of other operators were reviewed to augment what developed to be favorable pilot test applications. Based upon this cumulative information, SPOC systems were implemented for non-automated producing properties and as upgrades for some key producing properties. Following implementation of SPOC systems for 671 wells that were previously equipped with analog pump off controllers, a post installations appraisal was completed to identify average economic benefits. Documented lift equipment failure reductions and fluid production increases were found to provide significant incentive to justify continued SPOC system proliferation.

For West Texas and Eastern New Mexico producing areas, analog pump off controllers are widely employed by numerous operators to optimize fluid recovery and reduce equipment failures for beam pumped producing wells. With the development of supervisory pump off control (SPOC) systems, pump off control technology can provide engineering and operations personnel with a more complete well surveillance package that includes diagnostic capabilities. In addition, SPOC system hardware configurations are deployed so that individual well site controllers send alarm signals, digitized dynamometer cards, and other pertinent operating data to a host computer when a lift equipment failure or anomalous operating condition occurs. Besides providing for an immediate response to an upset well condition, the stored data allows for more accurate determination for the problem source. Effective lift design modifications can then be accurately developed. Amoco Production Company (Amoco) had implemented analog pump off controllers, to work in conjunction with a proprietary lease automation system, for the vast majority of beam pumped producing wells. With the availability of SPOC systems on a commercial scale, pilot testing was initiated to determine whether this enhanced technology could provide sufficient benefits to allow for pump off controller retrofit. In addition, experiences of other operators were reviewed to augment what developed to be favorable pilot test applications. Based upon this cumulative information, SPOC systems were implemented for non-automated producing properties and as upgrades for some key producing properties. Following implementation of SPOC systems for 671 wells that were previously equipped with analog pump off controllers, a post installations appraisal was completed to identify average economic benefits. Documented lift equipment failure reductions and fluid production increases were found to provide significant incentive to justify continued SPOC system proliferation.

This paper presents the practical and the theoretical benefits of running a sucker rod - beam lift system as slowly as possible. The slowest speed possible is defined as the speed required to pump all the liquid the reservoir will flow into the well on a continuous basis. Operational changes to create any desired speed are shown and several field examples are used to illustrate the point. The potential savings using these methods are a greatly expanded run time, the system does the minimum amount of work and requires the minimum amount of power, the reservoir is allowed to produce at maximum rates with a minimum of down time for repairs to the rods, tubing, and pump.

As today's artificial lift equipment becomes more sophisticated and provides greater rates of return it is more important than ever to strive for 100% reliability. Since the equipment is often deployed in harsh electrical environments it is important to take effective measures to protect this equipment from damaging electrical surges. This paper will explore various methods that have been used to protect artificial lift equipment in the harsh electrical environments where they are often deployed. It will focus on practical applications, and solutions that are simple to install and have proven effective over multiple years of deployment. The paper will include a case study which demonstrates the economic benefits of using sustainable electrical protection systems to maintain production and protect artificial lift equipment from damaging electrical disturbances. The material will be presented in a very straight forward manner and should be of interest to all.

The optimization software and automation principles discussed in this paper have been implemented in fields with as few as 20 wells to fields with well over 3,000 wells. These installations have been made in primary recovery fields to tertiary recovery fields undergoing water, C02, or steam flooding. These systems have been installed in new fields with no automation in place and in mature fields, which have been automated for over a decade. Over the history of all these installations, we have documented the benefits and rationale for implementation of these types of systems. The paper describes the cash flow enhancement benefits of implementing a comprehensive production automation optimization System.

Deliquescing desiccants have been used for gas dehydration for over 40 years. Historically this technology had limited applications due to poor desiccant quality and integrity, equipment design problems, operational difficulty, and limited drying ability. Recent advances in dry material blending and tableting, formulation, and equipment design have greatly expanded the application range of deliquescing desiccants. Deliquescing desiccants are now used to dry sales gas, fuel gas, sour gas, excess or "peak" gas, and for hydrate control. Operating and capital costs compare favorably to traditional TEG systems. Field data verifies the drying ability and performance of deliquescing desiccant systems. Because of the operational simplicity and closed system design, deliquescing desiccants offer many advantages over traditional drying methods such as triethylene glycol, including: no VOC or BTEX emissions, no ground contamination, no fire hazard, low capital expense, low maintenance, no "turn down" concerns, and simple operation. Used for hydrate control in gathering systems, desiccants offer a simple and inexpensive method to dry below pipeline dewpoint thereby allowing trouble free gas flow from wellhead to processing plant. At the plant, gas is further dehydrated to meet pipeline requirements. Desiccants have substantial advantages for drying sour gas both for hydrate control and pipeline sales. There are no emissions, odors, or glycol contamination, and vessels can be over-sized to extend service interval to only several times per year, greatly reducing employee exposure to hydrogen sulfide. Because of its simplicity and small footprint, desiccant drying of fuel gas yields increased revenues by using suction gas, not sales gas for compressor fuel. The entire compressor throughput capacity can be sold, instead of a portion being used for fuel. Desiccant dehydration is well suited for remote, unmanned locations, which are not visited daily. Because operation is simple and service intervals long, operators can schedule maintenance and service weekly or even monthly. This reduces total operating costs and labor requirements.

This paper will describe a new, patent pending sucker rod pump for gas separation and fluid/gas production. The Gas Vent Pump

There are three methods available to the operator to determine the net torque loading of a pumping unit's gearbox. Two dynamic methods determine the instantaneous torque throughout the pumping cycle: method I ) uses measured motor power, motor and drive efficiencies and the pumping unit speed to determine gearbox torque and method 2) Combines the measured surface dynamometer card and calculated torque factors together with measured or calculated counterbalance moments from the crank and weights. Performing a counter balance effect, CBE, test is a direct method of determining net gearbox torque at a specific crank position to estimate the counterbalance moment; this static test is where the cranks and counter weights are held level until no upward or downward movement is noticed when the break is released. Field case studies of applying all three methods to determining gearbox torque are presented in this paper. The pros and cons of using each method are discussed.

Proper reservoir management and production optimization require timely knowledge of formation pressure, permeability and well bore skin factor. To this effect, pressure transient tests using wireline conveyed pressure gauges are commonly run in flowing wells. The presence of artificial lift equipment complicates and often precludes the use of wireline conveyed devices so that conventional pressure transient tests are seldom performed in these wells, resulting in poor reservoir and production management. Since the 1980s, the industry has used programmable equipment for calculation of bottomhole pressure from surface pressure and acoustically measured liquid level data in pumping wells. Advances in electronics, computer software and transducer technology have vastly improved the data quality and the usability of this equipment to the point that routine determination of BHP using surface measurements is reliable, cost effective and provides real-time data with the quality necessary for pressure transient analysis

During the last several years the Petroleum Industry has adopted the term

I am going to take you deeper and deeper into the "whys" and "wherefores" of efficiency, other means of improving efficiency, and finally into reasons that business in the United States has become increasingly efficient and has contributed so much to this country. This is a hard trip and an unusual one for this type of meeting. I approach this job with some fear but with great hope that I can convey my ideas to you and that you will feel rewarded.

This paper discusses several studies undertaken by Mobil's Bakersfield, California, operating unit to better understand the operating limits of oilfield pumping unit gear reducers. Theoretic information was secured from several manufactures, both domestic and foreign, about gear reducer, gear and bearing life expectations. Limited testing was conducted in an effort to validate four manufactures' claims. Inspections were also conducted on about 200 pumping units to gain a wider information base on gear reducer operating life. From these data it was determined that some manufacturers' information could be proven while others could not. A compilation of the theoretical information was developed and reports were distributed that provide Mobil with the ability to more accurately determine the maximum allowable operating limits for several brands of pumping units.

For years questions concerning problem wells have been answered thru well analysis. Current RPC technology can predict well problems, manage pumping wells, and control cycle times via the downhole pump card. This leap in technology goes beyond normal pump-off control to total well management. Guesses can be made viewing the surface card. Decisions are made viewing the pump card. Utilizing diagnostic software within the control providing the operator both the surface card and downhole pump card is like having a dynamometer and analyst on the well 24 hours a day. This downhole card detecting pump fillage will assist the operator in detecting problems in the well in advance of equipment failure, aid in diagnosing downhole conditions while maximizing production. Why control a well with peak and minimum load violations when you can MANAGE the entire beam pumping system from electric motor to downhole pump. In addition, enhanced historical data and analysis capability are available. This paper will review the anomalies of the surface card with answers provided by the downhole pump card. Actual well analysis comparisons, computer predictive comparisons, and data from Pump-off controls currently using pump card technology will be used in making operating decisions.

The negative effects of microbial activity in oil production are well-known to the petroleum engineer. Formation plugging problems or corrosion problems, especially in waterfloods, are undesirable characteristics of microbial metabolism which have been the subject of considerable expense to the industry. On the other hand, microbial activity has potential for enhanced oil recovery. The use of microbial agents to improve oil recovery is not a new idea. It has long been noted that certain microbes are capable of attacking complex hydrocarbons and producing less complex molecules.6-x Bacterial strains have been shown to produce light hydrocarbons from crude while others can produce carbon dioxide as a part of their metabolic activity. More recent developments have shown that biopolymers capable of being used as viscosifiers may be produced by a fermentation process.

This paper discusses the application of biological mixtures for prevention of paraffin deposits in oil wells. Three biological mixtures were field tested. Statistical data on test results in Canada and the United States are presented outlining application parameters. Several case histories are presented including some Thermal Chromatography-Mass Spectrometry (TC-MS) work on treated wells. Theoretical mechanisms of the paraffin control process are discussed.

Bioremediation is a new technology for which the time has arrived. This paper presents an overview of various products and processes to reclaim sodium-damaged and hydrocarbon-contaminated soils, to manage tank bottoms, and to biologically clean up sludge pits. The processes include the pre-evaluation analysis, the treatment and the follow-up procedures. Bioremediation is a costeffective way to handle the aforementioned problems in an environmentally sound manner.

Attention is being focused on more and better advance planning in drilling operations to minimize the rise in drilling costs. This paper describes one procedure for evaluating and improving drilling performance. In our study, penetration rate is not considered the sole basis for drilling efficiency but attention is focused on the more important aspect of incremental cost per foot of hole drilled.

As America's energy demands increase, major new responsibilities are placed on the industry to find new reserves. Hundreds of thousands of dollars, sometimes even millions, are spent on a single well. These high costs, coupled with limited equipment sources, make it critical that we use drilling equipment, especially rock bits, efficiently. Several years ago the cost and importance of the rotary rock bit were considered relatively insignificant to the overall cost of drilling an oil well. However, with the development of tungsten carbide inserts and sophisticated lubrication and bearing designs the rock bit has become expensive. Even though these bits can now drill through thousands of feet of rock, selection of each bit has become a very important factor in the cost of drilling operations. The proliferation of bearing designs and cutting structures since 1967 caused the International Association of Drilling Contractors (IADC) to adopt in 1973 a standard coding for rotary rock bits. This coding is summarized in Fig. 1. the new classification system was initiated to help eliminate some of the confusion among contractors and operating company personnel arising from different coding systems of the various manufacturers. The IADC selected a three-digit numerical system which classifies: 1. Cutting structure (milled tooth or insert) 2. Formation hardness, and 3. Design features. The first digit relates to the cutting structure of the bit. Series 1,2 and 3 in this position describe milled tooth bits for soft, medium, and hard formations, respectively. Series 5,6,7, and 8 describe insert bits for soft, medium, hard, and extremely hard formations respectively. The second digit is a formation hardness subclassification with numbers 1 through 4 designating formation hardness. The final digit, the bit feature classification, indicates mechanical or design features such as gauge inserts, sealed or frictiontype bearings. The IADC classification of l-l-4, for example, refers to a milled tooth bit (1) used to drill the softest formation (1) and having a standard mechanical feature of the sealed bearing (4). The IADC classification of 7-4-7 indicates an insert bit (7) designed to drill hard formation (4), and having friction bearing and gauge inserts (7).

The popular image of surface coal mining is changing. Highly trained and well-compensated mining technicians operate modern equipment in pleasant surroundings to extract low-sulfur coal from the ground. Scientific methods are used to reclaim the mined-out land, and even the needs of the native pronghorn antelope are not overlooked. The purpose of this paper is to describe Atlantic Richfield's first surface coal mine Black Thunder and some of the features that we feel make it unique.

The use of plunger lift to deliquify gas wells is an important artificial lift method to maintain and increase production. The efficacy of a plunger installation is based on several factors: the ability to confirm loading and the applicability to an individual well; the choice of the proper equipment for the most effective operation; and the maintenance of the system for optimum performance. This paper deals with (1) various methods to identify the aspects of loading, for example, by the observation of critical velocity and the use of fluid gradients, (2) the correct choice of plungers and control equipment, and (3) the proper maintenance of the equipment (plungers, wellbore, etc.) to effect proper operation.

In the Permian Basin, failure of the borehole wall while drilling vertically (wellbore instability) is seldom a problem. In horizontal wells, however, this is not the case. The imbalance between vertical and horizontal earth stresses, and the fluid pressure in the rock, can lead to problems if insufficient mud weight is used. This can lead to tight-hole and stuck-pipe problems that can escalate into losing the wellbore (and, sometimes, the BHA), requiring a sidetrack.

In this presentation the causes of wellbore instability are reviewed and the methodology for predicting a safe mud weight is described. In contrast to vertical wells, mud weight requirements in horizontal wells are more exacting. An approach to update required mud weight while drilling and geosteering will be described. Case history examples of applying this approach to wells drilled in the Permian Basin will be presented which integrate borehole stability with hole cleaning and geosteering requirements.

The paper will discuss and analyze BHP data that was recorded during actual horizontal fracturing work. The data will demonstrate isolation from one fracture point to the next. The paper will also discuss production results from 11 horizontal wells that were completed using an innovative open hole horizontal completion technique. In addition, the paper will compare production results from these horizontal wells to others in the same field that were completed using different techniques. This paper is a follow-up to the paper SPSC entitled "Innovative Stimulation Technique helps Pin-Point Fractures in Open Hole Horizontal San Andres Wells".

Bottom hole pressures have been measured for many years in the oil industry, primarily for use in productivity and future production predictions. More recently, it has become apparent to petroleum engineers that the pressure transients measured during build-up or draw-down tests contain much quantitative information about the well and the reservoir. Each year more techniques for analysis of these pressure transients become available in the literature, giving the petroleum engineer more opportunities to make money for his company through application of these techniques. This paper presents briefly the theory of some of these techniques and will explain their use by means of field examples.