Analyzing well performance is an important step toward increasing profits by improving production techniques. Generally the analysis is made by field observations and examination of well data. The acoustic liquid level instrument offers valuable supplemental information since downhole pressures can be determined from the depth to liquid measurement.

Three significant conditions existed in the oil industry in 2000. First we had the best oil prices we had seen in years, second we didn't know how long they were going to last and third many of the major oil companies were investing in overseas growth opportunities leaving less capital for domestic projects. Aggressive operators, with the ability to respond quickly, wanted to take advantage of the high oil prices by increasing production (make hay while the sun shines). Discerning operators wanted to hedge their spending on projects that would payout before the price fell back. Many major oil companies had to use only "expense" type funding for the short-term production enhancing projects.The Aneth Unit is a 320 well waterflood/CO2 flood in Southeastern Utah. This paper discusses how Reliability Engineering was used on the Aneth Unit to select projects that increased production, paid-out in six months, used no capital funds and required no increase in the annual expense budget. The paper is intended for field engineers, field supervisors and operations technicians. The paper will cover how we assembled a team to define a mission statement that accounted for the uncertain oil prices and the lack of a capital budget. The paper steps us through the Reliability Engineering process of brainstorming for ideas, culling and prioritizing ideas, defining and assigning action items and assessing results. The paper discusses how our prudent spending resulted in increased cash flow, increased earnings, improved return on capital employed, increased production and decreased lifting costs.

A review of the many types of gas anchors and their principles should be of interest to those who are concerned with pumping oil wells. The fact that free gas reduces pumping efficiency was discovered early on. An obviously better way to produce most such wells was to flow the gas up the casing annulus and pump only the liquids (oil and water). Some down-hole equipment arrangements were found to be better than others. As a result, many operators began investigating ways to improve pumping. A U.S. patent for a gas anchor was issued in 1881 to Crowley. Many more patents on gas anchors have since been issued; however, not all of them necessarily increase pumping efficiencies. The name "gas anchor" is a misnomer -- it is actually a down-hole gas and liquid separator. There are many types and their use is often misunderstood.

We will look at the advantages of the vee-wire sand screen, which is a well known as well as popular in the filtration industry. It is easily adapted for down-hole rod pumps. We will look at it use on the Pump itself as well as it's use on the tubing. In rod pumps it is used in replacement of the gas anchor, which can reduce sand failures by eliminating the heavier frac sand from our production tubing. The Vee-wire screen can be manufactured in different lengths, sizes and slot sizes.

A new type of anti-biofoulant corrosion inhibitor (ABF) has been developed that lays down a unique, smooth film that resists the adhesion of sessile bacteria and iron sulfide, thereby reducing the formation of biomass that initiates under deposit corrosion cells. This inhibitor, formulated with special surfactancy, can help penetrate existing biomass and lay down an inhibitor film. The ABF corrosion inhibitors coupled with a practical methodology can control corrosion due to sulfate reducing bacteria.

If gas and particulates (sand & iron-sulfide) are becoming a problem for your API Pump, consider the rugged Two- Stage Hollow Valve Rod Pump. Which is the most popular and successful pump ever produced. This pump has several benefits and can be designed for numerous pump configurations. This paper will give a basic understanding of the sequence of operation of the Two-Stage Hollow Valve Rod Pump and its application.

Presents latest API standard 11E. Explanation is given of ratings on structure as well as gear reducers. Design considerations and safety factors included in current designs are presented.

American Petroleum Institute (API) proposed Recommended Practices (RP)' present standards of performance to be used in testing of floating equipment that is used in oil and gas well completions. Extensive laboratory testing has been done following API proposed procedures. Testing at levels beyond API standards have also been accomplished. A paper has been prepared to present data resulting from API tests conducted. Procedures used and test results gained from testing at more stringent standards are also presented. Data reported include (1) impact and pressure force tests exerted through the cementing plugs to floating equipment, and (2) flow tests in which a large volume of lost circulation material was passed through floating equipment. Subject paper also presents statistical data from an extensive body of cementing work performed in domestic operations in the United States. Many pipe sizes are represented in this information. Data include pipe size, flow rates, circulation times, and cementing times. Results presented justify the need for and the severity of the standards in the API proposed RP.

The successful application of threaded and coupled rods (i.e. sucker rods, drive strings, etc) to provide power to lift downhole fluids is critically dependent on using proper makeup procedures. This is applicable whether the pump is a reciprocating, positive displacement, subsurface pump or a rotary driven, progressing cavity pump. Torque by itself has been discredited with being able to provide consistent connection pin preload stress or pre-stress due to a variety of factors related not only to the setup procedures but also due to the equipment that is used to provide the power to the power tongs. This presentation will review the various parameters that affect proper connection pin preload and provide a discussion of the new revisions to the industry's API recommended practices for sucker rod driven pumps as well as newly developed draft recommendations for progressing cavity pump installations.

This paper discusses the techniques used to size available submersible pumping equipment to pump in a variable speed, constant head mode. Effects of variable speed, constant head operation on the pump and motor are described with their relation to optimum system performance. Energy-usage calculations for a conventional, constant-speed submersible pump and a variable-speed, constant-head submersible pump are compared. Finally, the economics of the variable speed submersible system are analyzed.

While not applicable to all existing well conditions and requirements, submersible pumps, properly selected and applied, offer a useful tool to the oil industry. Ultimate economic efficiency

A non-intrusive flow meter which directly measures mass has been commercially available for seven years. This meter, sometimes known as a Coriolis or gyroscopic flow meter, measures the force imparted to a vibrating tube by the mass of a fluid as it passes through the tube. This allows the measurement of mass flow without compensation for fluid properties. This paper will present the operating principles of this device and its applicability to the measurement of carbon dioxide, with methods and techniques for mass calibration.

The Mesa Verde formation is highly naturally fractured and varies in depth from 5500" to 6200". Low recoverable reserves make wells in this area marginally economical. The lower hole is air drilled and cemented back to the intermediate at 3700 feet. Historically, the production casing has been cemented with a 50/50 Poz/H blend mixed at 13.2 ppg. Bond logs were often marginal and fall back was a problem. This paper reviews the development of a lightweight cement system with the ability to develop high compressive strength to enhance the mechanical seal. This slurry needed to have plating lost circulation material (LCM) to prevent fall back and minimize node buildup due to high fluid loss. Compressive strength, fluid loss and rheological properties for various formulations are presented. The results of over forty jobs are summarized with operation and bond log results reviewed in detail from two typical wells.

When the Underground Injection Control Regulations were promulgated in 1980, existing oilfield (Class II) injection wells operating at the time that the regulations became effective were excluded from Area of Review requirements. The Environmental Protection Agency has expressed its intent to revise the regulations to include the requirement for Area of Reviews for such wells. A methodology developed for obtaining Area of Review variances has been applied to oilfields in Gaines County, Texas. The work is part of a broader effort to apply the variance methodology throughout areas of the West Texas Permian basin. The work is being conducted under sponsorship of the American Petroleum Institute. The general concept of the variance methodology which has been developed uses basic variance criteria that were agreed to by a Federal Advisory Committee, but expands upon those to provide a greater range of variance options. In this study, the geology and hydrogeology of areas within Gaines County were defined with respect to petroleum production and groundwater occurrence. Oilfields were identified using several databases from the Texas Railroad Commission . Only fields with significant injection were investigated. Ten fields were identified for study. These included Cedar Lake, Flanagan, G-M-K, Harris, Riley North, Robertson North, Russell, Seminole, Seminole East, and Seminole West. The results of the study with respect to the opportunity for variance for injection field in Gaines County are presented. The implications of the Gaines County study for other Permian basin counties are also discussed.

Carbonate environmental concepts have been applied to a typical Permian dolomite reservoir. The Monahans Clearfork field, Ward and Winkler Counties. Texas, was selected because the initial development was completed and the secondary recovery project was installed prior to the development of the carbonate environmental concept as an operational tool. The problem in the Monahans Clearfork Secondary Recovery Project is twofold. First, oil response to water injection has been less than originally anticipated. Second, as a result of early evaluation techniques, some productive zones were either cased off or not penetrated. The Clearfork reservoir was divided into five zones. The environmental dolomite types within each of the five zones ranged from supratidal to marine both vertically and laterally. Several marine dolomite types were found to be productive white the intertidal and supratidal were nonproductive in most cases. When leached. However, the supratidal becomes an effective but limited reservoir. Net pay isopachs for each zone were constructed and serve to define field limits, pay quality, and continuity. The isopachs indicate the anticipated waterflood performance of each zone, the distribution oj suspected thief zones, and wells and/or areas with additional hydrocarbon potential. A drilling and recompletion program currently underway should complete the evaluation of the Monahans Clearfork reservoir. If" success continues, the program should result in a significant improvement in supplemental recovery performance as well as an increase in field reserves.

This paper presents catalytic heating techniques, their application in the field and theory of operation. The use of these heaters in freeze protection of valves, chokes, regulators, meter runs, and other field equipment is explained. The paper contains the effects of sour gas, liquids, explosive atmospheres, and ambient temperature on catalytic heaters. The author's statements come from studies of actual usage, experimentation with controlled conditions, and research of literature.

A method has been developed and successfully applied to generate a high quality foam with nitrogen and concentrated chemical for treating down the annulus. The advantages of the foam method are that the total liquid volume required to completely fill the annular space of a well is very small compared with the bulk volume of the foam. The low hydrostatic loading does not adversely affect production. The chemical can be applied in a concentrated form which favors faster and more complete adsorption onto reactive surfaces After application to the annulus the foam breaks leaving a thin liquid film on the tubing and casing and excess chemical drops to the standing liquid level and is available to coat the inside of the tubing during normal production. This method is being successfully applied in low-pressure coal bed methane wells.

Drilling optimization can be defined as the application of all the forces available in drilling to a desired depth, with a minimum total cost. If this optimum is to be approached, the drilling supervisor must have accurate data, timely interpretations and confidence in its application. This paper will concentrate on data collection and interpretive systems as technical support to the drilling supervisor.

A method has recently been developed for evaluating the Delaware Mountain group of West Texas by using electromagnetic propagation, photoelectric effect, and neutron density measurements. The Delaware Mountain group is a series of sand-shale sequences deposited in the Delaware Basin of West Texas and Southeastern New Mexico during the Guadalupian Age. For a variety of reasons, conventional interpretation methods based on resistivity measurements have not always been definitive in these formations for distinguishing between oil and water. An interpretation technique using electromagnetic propagation data, specifically porosity derived by comparing electromagnetic propagation measurements to porosity from neutron-density logs, has been used with considerable success in identifying traditional pay zones and locating new pay zones in the Bell Canyon and Cherry Canyon formations of the Delaware Mountain group.

SONAN (sonic-analysis) logging resulted primarily from the research and development of a practical logging sound by McKinley et. al. of Esso Production Research Company (EPRC). McKinley primarily confined his research to the use of this system for documenting fluid flow behind cemented casing but also described the potential of this system as a flow meter. Following the publication of his findings in 1973, several service companies, including Dresser Atlas, began field testing equipment varying slightly from the EPRC designs. The variations were the result of efforts to speed up the recording of the log and to improve the ease of operations of the system and its reliability. In the time since, additional applications of this system have been noted, including its use to (1) find zones of lost circulation in drilling wells, (2) locate leak points in casing and tubing, (3) locate the source of fluid entry in uncased well bores, and (4) use this system in calculating perforation productivity profiles. McKinley also demonstrated that the data recorded could be quantitatively evaluated to determine rate of flow as well as the source. Because of the present method of data recording and the potential quantitative nature of the data, Dresser Atlas found that the processing of the field-recorded data is best performed with the aid of digital computers. Automated processing of the sound log data has been found to speed the interpretation, improve the accuracy of the interpretation and provide customers with a permanent record of our analysis for their well files. The equipment, principle of operation, several examples of the applications previously mentioned, and our processing of the data are discussed in the following pages.

A "smart" predictive computer program called RODSTAR has been developed that combines expert rod pumping knowledge with state-of- the-art wave equation and pumping unit modeling algorithms. With this computer program one can get optimized system designs in minutes by asking the program to calculate the strokes per minute, plunger size, and rod string design for a desired production rate. RODSTAR also helps the user select the pumping unit size and warns him about bad designs, pump or rods that are too big for the tubing, or pumping speed that is too high. The program's capability to automatically design steel or fiberglass rod strings ensures minimum rod loading and lowest rod string cost. In addition to the expert features of its design algorithms, the program calculates rod stresses at the top and bottom of each rod section to help avoid rod compression, and recommends prime mover size for NEMA D, gas engines, or ultra high slip motors. It also calculates prime mover energy consumption, monthly electricity bill, overall system efficiency, and the effect of prime mover speed variation and unit inertia on net gearbox torque. It can simulate full pump, fluid pound, or gas interference, and any pumping unit geometry including non-beam pumping units.

Selection of lubricants depends on many factors of design, service and operating conditions. Examples, including the selection of lubricants for pumping unit gear reducers, are given.

The increase in small diameter casing completions has increased the use of small size tubing. Gas lift would be the most suited method of artificial lift in many installations where it has not been used due to the unavailability of accurate flowing pressure gradient traverses for small conduits. Initial evaluation of gas lifting through small tubing using calculated pressure gradients based on the extrapolation of a widely accepted two-phase energy loss correlation eliminated the feasibility of gas lift. The calculated pressure gradients were much higher than actually exist. Experimental data has be gathered recently for single- and two- phase flow through small conduits. This data has been correlated into usable flowing pressure gradient traverses for small tubing and pressure loss due to friction curves for gas flow through small configurations. Two-phase flowing pressure traverses for 1- and 1-1/4-inch nominal tubing are presented for the design of continuous flow gas lift installations and prediction of maximum producing rates from wells with small tubing. Curves for gas flow are offered for calculation of the friction portion of the pressure loss is small tubing and annuli.

Major assets of producing companies include reservoirs that are subject to secondary recovery operations. These secondary projects can be improved upon through the proper application of technical knowledge and experience. During the past 10 years, large investments have been made in initiating new water-floods and gas injection projects. Improved recovery programs have been undertaken in existing secondary operations which include infill drilling, converting new or existing wells to injection service, and well workovers designed to control or improve injection profiles. With all this activity there is a definite need to monitor well and field performance to maximize both profit and recoverable hydrocarbon reserves. Today, high pressure waterflooding is relatively common. Typically, injection may exceed reservoir voidage over a prolonged period of time and even after fillup of the free gas space. Under such conditions, it is advantageous that everything possible be done to maximize oil production. Isometric diagrams and calculations can be used to pin-point candidates for large volume lift, selective well completions, and additional infill or development drilling since increased withdrawals a.re often indicated to prevent reservoir pressure from increasing unnecessarily. The use of geological isometric cross-sections in studying and monitoring secondary-recovery programs has wide application. The isometric crosssection provides a means of incorporating inherent geological parameters that materially affect all injection projects. Of primary importance is the geological interpretation presented on the isometric cross-section showing the continuity of the various layers which directly affects vertical and horizontal sweep efficiency in a secondary-recovery project. Since the unit displacement efficiency is fixed by the injection fluid selected, improvements in existing secondary-recovery projects require a better understanding and application of geological interpretive knowledge to develop practical means of improving the area1 and vertical sweep efficiency of each pattern or tract. During primary production operations, only limited geological information is required after development drilling operations are concluded. For example, isometric cross-sections could help in primary well completions. It is only during secondary recovery operations that a more detailed and reliable geological description of the reservoir is required for monitoring the progress of the flood throughout the reservoir. The need for geological definition may become quite apparent when secondary flood performance differs substantially from predictions and forecasts. Another basic use of geological data is in properly modeling the effects of stratification. This procedure is necessary in order to match reservoir performance history in reservoir simulation studies and make reliable predictions of future performance. Exotic or tertiary recovery programs will have to be selected by operators who have the necessary technology, including a better understanding of the inherent heterogeneous nature of reservoir rocks.

The use of high strength proppants in wells that are deeper than 15,000' is not new to the oil industry. Utilization of these expensive proppants; however, in shallow (+8400'), hard formation wells is new to the industry, especially in the West Texas area. Four wells in the Calvin (Dean) Field of Glasscock County, Texas are currently undergoing a comparison test. Two wells were fractured using 20/40 mesh sand while the other two wells were fractured using 20/40 mesh sintered bauxite. The justification to use bauxite in individual treatments, the preliminary results, and current well performances are discussed in this paper.