The Beam Pumping System, in onshore oil wells, is a major part of the artificial lift method. Utilizing the energy from the Pumping Unit, to operate, the BGC lowers the cost of compression and eliminates the emissions created by other compression systems. By utilizing the Pumping Unit as the BGC's prime mover, operators enjoy a steady increase in production with a "tried and true" compression system that is considered a GREEN MACHINE by the industry. The Walking Beam Compression System gives greater oil and/or gas production and at the same time consumes less energy than conventional compression systems without greenhouse gas emissions.

A discussion of the mechanics involved in gas lifting individual wells with a small rotary-compressor system. Technique, applications, and advantages are presented. Example installations and their costs are included.

In the geographical areas of North and West Texas, 94 percent of all oil wells produce by means of artificial lift, and most of the artificial lift installations consist of sucker rod pumping equipment. This percentage equates to some 100,000 rod pumping units in this area alone." With these facts in mind, there should be no doubt as to why the proper management and surveillance of pumping equipment are important. This paper is limited to a discussion of computer application in the management and surveillance of rod pumping equipment. When terms referring to artificial lift equipment are used in the paper, they are in specific reference to sucker rod pumping installations. Methods and techniques cited for the surveillance and analysis of sucker rod pumping installations are from those employed in Exxon Company, U.S.A.

Forty years ago there was little problem with the analysis of a well log. The only type of log that was available was an Electrolog. This survey was used to determine the depth of the pay zone, the thickness of the bed, and the location of the oil-water contact. As time went on, more and more different types of logs were developed and the analysis of each was fairly simple and straightforward. However, a problem was developing in the interpretation of wells. What could be done on a well which was logged with two, or three, or four different tools? Each tool required a different method of analysis because of the different theories and types of data that were being measured. Log analysis was rapidly developing into a highly specialized discipline. At the present time, one of the most important people in any oil company is the log analyst. The exploration people depend on him for information about the rocks in a wildcat and the exploitation group depends on him to tell them about the reservoir characteristics. Now, instead of one or two types of logs, he has to contend with about forty of them. Each of these logs responds differently in a sequence of different lithologies. Because of this distinctive response, certain combinations of logs may be used to determine characteristics of the rock through which they are recorded. In most cases, these logs are recorded as a line trace on film in a camera (Fig. 1). There are, however, certain specialized logs which are recorded on special equipment to facilitate their interpretation (Fig. 2). The modern log analyst uses all methods of interpretation that are available to him, from simple charts to computers. In today's oil field most wells are high cost, high risk ventures. A single zone can make the difference between putting a well on production and abandoning it. The responsibility of deciding on the location and quality of pay zones places such a burden on the log analyst that he cannot afford to leave anything to chance. The advent of computers has given him a tool which he can depend on giving a total uniform analysis of any section. At the present time there are many different types of programs, a great many of which are highly specialized. However, there are six programs which are in widespread usage - Shaly-Sand, Complex (carbonates), Elastic Properties, Coal, Diplog and Cased Hole Analyses. Each of these computer programs requires certain input data to calculate all of the output information. After the data has been converted to magnetic tape it is plotted on a graph-like chart. Because of the characteristics of the logs, distinctive patterns, which depend on the rock, are formed in these cross plots (Fig. 3). The log analyst then uses these cross plots to determine parameters for the computed log.

The Shell-operated Denver Unit of the Wasson Field consists of approximately 850 producing wells. Over 700 of these are being produced by sucker-rod pump. Average production is about 400 BFPD with an average water cut of 60 percent. Surveillance of the rod-pumped wells is being achieved with a computer-based pump-off control. Initial benefits of 4 percent increase in production and an I8 percent savings in electrical energy are being achieved. Other operational benefits which are realized are described.

The use of simulation in petroleum engineering is not new; pipeline and refinery simulation and simulation of reservoir performance have been widely used in the past. However, in recent years there have been major improvements in the ability to simulate rod pumping situations, such as the use of mathematical expressions and equations (derived from API RP 1lL) to capture succinctly complex interrelationships which heretofore could not be easily related. The model is then manipulated on the computer to see what might happen in reality if the relationships were fixed or varied in specific ways. Because every system is in some state of dynamic adaptation to its environment (everything outside the system boundaries that has some influence on the system), there will always be problems to be solved. This is where the use of an abstract system simulation model proves advantageous. Simulation is just a numerical method used as a means of finding successive states of a situation or system by repeatedly applying the rules by which the system is operated

Although it looks simple, rod pumping equipment requires complex simulation methods to mimic the variety of actual conditions encountered in the field. This paper describes such a method which relates the influence of unit geometry, prime mover slip, rod design and downhole pump condition. The method is mathematical, but non-technical means such as dynamometer cards and electrical terms are used to describe it. The intent of the paper is to study a variety of practical rod pumping questions that frequently arise. It has been found that the computer aided simulation has suggested performance phenomena not widely known or understood. Portions of the subject method have been under development for twenty years. Some of the theoretical details are shown in Reference 1. Recent additions to the technology have been in handling the effects of inertia on gearbox and prime mover loading (Ref. 4). Most recent has been simulation of electrical performance of motors.

Sun Exploration and Production Company (Sun) conducted an extensive five-year study into the costs and benefits of installing and operating a Supervisory Control and Data Acquisition (SCADA) system. Installed on the Southeast Levelland Unit (SELU), the SCADA system was operated as a full monitoring system. The SELU is a secondary recovery unit located in the Levelland Field in Hockley County, Texas. The five-year period included 30 months prior to the initial operation and 24 months following full operation of the system. One hundred thirty-four producing wells comprised the data base analyzed in the study. Through the capabilities of the system, Sun's personnel were able to reduce operating costs significantly in several areas. Reduction in subsurface failures per barrel of fluid lifted was 28.6%, and in power consumption per barrel of fluid lifted was 11.3%. An increase in oil and gas production ranging from 3.8% to 13.9% was realized. Actual and potential intangible benefits were also identified. All factors which could significantly influence the determination of the tangible benefits' true value were identified and considered. The factors considered were drilling effects, workover effects, percent water cut increase, increased water production per well, increased water injection, injection to withdrawal ratio (I/W), rod and tubing life, and the chemical program. This paper briefly outlines the Unit operations and the SCADA system installation, explains in detail the five-year study, and highlights other intangible benefits provided by the system.

Computer programs have been perfected for the design of continuous flow and intermittent gas lift installations. Calculations can be performed for all standard designs, for macaroni and annular flow installations, and for wells where wireline retrievable valve-mandrels were previously installed. Using the same well data, the computer calculates installation designs which duplicate accurate hand calculations using the same graphical procedure. The resulting printout provides a complete permanent report of all information pertinent to the design. This includes all the well data submitted, intermediate calculated results and the final design.

Marathon's Ezzaouia #8 well is located in the Ezzaouia concession in the Zarzis permit area of Eastern Tunisia. The well is completed as an oil producer in a 7300" Jurassic sandstone and has never sustained steady production with the existing 3-l/2" tubing. Systems analysis suggest that the well could flow, at least temporarily, with smaller tubing or could sustain production for a much longer time with artificial lift. Installation of a rod pumping system would be an easy decision in most parts of the world, but due to a lack of workover rigs in Tunisia a rod pumping system was not selected. Furthermore, the Jurassic reservoir is a depletion drive reservoir with a extremely limited water drive and thus was not a candidate for gas lift with wireline retrievable gas lift valves.. However, an innovative artificial lift approach utilizing a coiled tubing unit, 1.50" OD coiled tubing and a casing free hydraulic jet pump was selected for producing the well. See Table 1 for additional data on Ezzaouia #8.

The concept of continuous-rod pumping is nearly as old as the rod pumping system itself. However, there was a Three-fold problem with the concept. First of all, there was a problem of manufacturing the continuous-rod and finding a suitable means of heat-treating the rod. Secondly, after the rods had been welded together to the specified length for a given well, there was the question of transporting the rod string to the well. And finally, there was the difficulty of handling the continuous-rod in running and pulling the rod string in the well. The solution to this three-fold problem has been resolved, and the concept of the continuous- rod pumping system is now a reality.

Once primary oil recovery from a reservoir has been accomplished, secondary and enhanced oil recovery techniques have been used to further the life of the field. Some of the most commonly occurring problems encountered with these techniques are: 1. Lack of confinement to the section of interest 2. Permeability variations in the producing zone 3. Early water breakthrough due to fingering of the injection fluid through
the oil 4. Directional permeability from injection wells to producers

Design and implementation strategies for maximizing the economic rate of return for conformance-improvement polymer-gel treatments will be reviewed. These design and implementation strategies are based on 20 years of field experience and based on number of large field projects involving a single polymer-gel technology. The presentation will be limited to discussing gel treatments that are applied to reservoirs suffering from fracture and/or other high-permeability (>2 Darcy) reservoir flow anomalies. Strategies both for injection-well sweep-improvement gel treatments (primarily intended to generate incremental oil production) and for production-well water-shutoff gel treatments (primarily intended to reduce OPEX) will be discussed. Special attention will be paid to the volume sizing of such gel treatments. In addition, the often overlooked economically promising use of polymer-gel conformance-improvement treatments during CO2 oil-recovery flooding operations will be touched upon.

The Conroe Field contains 959 wells which produce primarily from the Cockfield and Main Conroe Sands. The Main Conroe Sand, encountered at about 5000 ft, yields an average oil production of 35,000 BPD. This field was discovered in 1932 and has a remaining life expectancy of more than 25 years. About 60 percent of the total wells are on gas lift. Gas production from the Cockfield zone plus oilwell residue gas from the Main Conroe Sand supply most of the gas lift gas. Two gasoline plants in the field gather the low pressure residue gas. Within the field, Getty Oil operates 10 leases that contain a total of 68 oil wells and 14 gas wells. In 1964, three ACT units were installed to serve all of these leases. During this first phase of modernization, tank storage and gauging were eliminated from each lease; but treating and separation facilities remained essentially unchanged. In 1968, the second phase of this program was commenced to modernize existing facilities and install supervisory control equipment. This paper discusses how Getty Oil automated these leases under digital computer control. Figure 1 is a map of the Conroe Field which shows the leases automated and the location of all battery sites, remote terminal units and ACT units.

Oil may be lost from a tank in the gas or vapor phase form, a phenomenon which is known as evaporation loss. The evaporation loss to the atmosphere from lease tank batteries is a definite loss of our natural resources. The question, is this evaporation loss great enough to have any monetary value at the present time? Are there economical methods for recovering these vapor losses and are such methods profitable to oil producing operations? To these questions the answer is definitely yes, in lieu of the expansion of Gasoline Plants, Product Pipelines and the Petro-Chemical Plants in the West Texas

Efficiency of primary and secondary oil recovery has become a major economic requirement for all crude oil producers. The phase of crude oil production this paper will consider is final gas-oil separation with the stock or surge tank and recovery of the resultant vapor. A basis for consideration of stock tank vapor recovery will require a gas sales outlet at a centralized location where crude oil is treated for pipeline sale or storage. The loss of tank vapor to atmosphere is familiar to most production personnel; thus, with the current trend of lease custody transfer and/or tank battery consolidation, the volume of vapor loss becomes a factor worthy of consideration.

This paper demonstrates the design and application of vapor recovery systems, including treating systems for boosting recovered liquids into plant line, crude stabilization, well casing pressure control, battery systems, and casing vapor recovery systems.

Most so-called gas reservoirs which produce liquid in the ratio of ten barrels per million or more are actually retrograde condensate reservoirs. As retrograde condensate reservoirs, they exhibit a dew point and condense liquid in the formation upon reduction in reservoir pressure. This liquid condensation in the reservoir adversely affects the production of liquid and gas at the surface. In extreme cases this retrograde condensation in the reservoir may result in the loss of as much as 75 to 80 per cent of the stock tank condensate initially contained in the reservoir fluid. With a knowledge of how the producing well stream characteristics may be expected to behave as reservoir pressure declines, several alternatives are available to minimize the effect of this retrograde loss. The decisions to be made are largely economic decisions based upon an accurate projection of both gas and condensate production over the life of the reservoir for various operating methods. This paper describes the type of study needed on the reservoir fluid to make intelligent decisions regarding the method of operation of the reserve, including decisions regarding the method of operation of the reserve, including decisions regarding the pressure maintenance versus pressure depletion and choice of surface separation equipment. In addition, the data are furnished to calculate the economics of gasoline plant operation considering either pressure maintenance or pressure depletion with lease separation of full well stream processing. With proper data, the reserve may be operated to obtain the maximum economic return.

The use of continuous coiled tubing to perform various types of remedial treatments or workovers has been well documented.1~2*3~4 Numerous successful treatments have been obtained with this device in oil, gas, injection and geothermal wells. However, the occurrence of and, more importantly, the causes of failures in operations involving coiled tubing have not been addressed by the industry. An examination of causes of failure should lead to a higher success ratio.

Having reliable and readily accessible relative permeability information is a problem for many reservoir engineers, particularly for waterflooding and other reservoir simulation calculations; currently, no central repository exists and data within a company is often not centrally organized. A large effort was required to collect data from public and private sources and modify it to fit a common format. The central database thus constructed maintains relative permeability data in a format that is easily retrieved and processed. Categorizing and modifying the original data for applicability to similar systems is considered, allowing for variations in connate water, residual oil, and critical gas saturations. The database must be easy to use and employ both tabular and graphical results. The software is menu-driven and selects data from central relative permeability files. Information such as fluid type, wettability, lithology, geographical location, and method of measurement is used to search applicable results. The program operates under W9X or NT 4.0 systems. The database may be downloaded at no charge from a University of Missouri-Rolla web page.

Fracturing has become a viable and important option for completing horizontal wells. This is especially true in case of tight gas formations. There are many fracturing processes and methods to consider for placement of these fractures. The optimization of the completion process including the number and size of fractures is still a challenging consideration. Fracturing of a horizontal well has unique aspects that require very special attention to obtain successful treatment. Differences between horizontal and vertical wells exist in areas of rock mechanics, reservoir engineering, and operational aspects. All of these aspects affect the optimization process for successful treatment placement and optimum asset performance. In this paper we will first discuss the various factors crucial to successful completion of a fractured horizontal well. We will discuss these factors in relation to both longitudinal and transverse fracture applications. Success factors will include the optimum perforation process, overcoming fluid flow convergence towards the wellbore in case of a transverse fracture, and the fluid flow and stress interference between multiple fractures. The paper will present field cases, laboratory, and numerical experimentations illustrating the impact of the various factors on the completion of the horizontal wells and the optimization of the fracturing process. The paper will also point to unique aspects that may be encountered during fracturing a horizontal well in tight gas formations.

This paper demonstrates lessons learned on a 5-year effort to improve and enhance field-wide influences on the Central Mallett and Slaughter CO2 WAG Units. The developments on data analysis, reservoir and production engineering, and solutions in these mature units have provided the opportunity to make major impacts on recovery and production rates, operation enhancements, and cost reductions. Focus on the total reservoir and development of a framework of data included information of the reservoir, completion design, drilling and workover history, production and well-test history, logs and diagnostic analysis, and placement options. An optimum conformance solution design for each injection well and the associated offset producers was the team's vision. This ongoing work's performance and evaluation for defining successes was through a review of the operator's economic drivers for sweep improvement, reduction of CO2, and water cycling-breakthroughs.

In straight or continuous gas lift, the flow is continuous, that is, not interrupted by intermitting nor aided by any artificial pumping method for obtaining submergence. This type of gas lift resembles a flowing well more than does any other type of artificial method in producing a well. Gas is injected at the top of the well through the tubing or casing, as the case may be, and the flow of the oil and gas takes place through the other pipe rather than the pipe through which the gas is admitted.

Commonly known as sour gas, hydrogen sulfide (H2S) is a highly toxic chemical agent found in petroleum drilling, production and refining operations. As secondary and tertiary recovery efforts are undertaken on older reservoirs, H2S is being found where previously it was not recorded. The gas is present in many crudes and is produced in common refinery processes such as cracking and desulfurization. Hydrogen sulfide is formed primarily by decomposition of organic matter containing sulfur. The gas occurs naturally in many geologic formations throughout the United States and is both toxic and corrosive. This colorless gas has the characteristic odor of rotten eggs and can be readily detected by the human nose. One can usually smell concentrations of less than 10 parts per million (ppm), with concentrations of 700 to 1000 ppm being fatal, even if exposure is brief. It is important to realize that continuous exposure to low concentrations of H2S (approximately 50 ppm) deaden the olfactory nerves, causing the sense of smell to become an ineffective detection tool. A variety of both federal and state regulations apply to the petroleum industry in areas known or suspected to contain sour gas. Federal regulations basically are designed to protect the employee and are handled through such agencies as the Occupational Safety and Health Administration (OSHA), the National Institute of Occupational Safety and Health (NIOSH), and the U.S. Geological Survey (USGS). Most state regulations are designed to protect the general public and require certain precautions be followed to minimize the chance of accidental public exposure to H2S. Probably the best known state regulation is Texas Railroad Commission Rule 36, whose degree of operator compliance depends on the radius of exposure based on the calculated concentration of H2S and the rate at which it is expected to flow from a well. Due to the occurrence and toxicity of hydrogen sulfide and the array of regulations concerning sour gas areas, a method of monitoring H2S becomes essential. Factors to consider in selecting a monitoring system include reliability and accuracy, ease of operation and maintenance, response time and expected lifespan of the system components. Another important concern of any H2S detector is proper placement of the sensor units, with special care taken to ensure all installation and location guidelines are clearly understood.

Most gas wells produce liquids that are often not removed from the well because of low gas velocity. Failure to produce these liquids severely restricts gas production. This paper discusses the continuous removal of these fluids from gas wells by gas lift. It will also discuss compressor installation and operation.