In 1973, a decision was reached to make a comprehensive joint geological and engineering study of the North McElroy Unit. It was hoped that the combined efforts would result in a more practical study to assist in the current waterflood operations. The objectives of this study were to (1) determine the different lithologies within the unitized interval and their associated physical properties; (2) establish reliable correlations and construct meaningful structure maps; (3) define the most efficient completion and production techniques; and (4) incorporate a more efficient water-injection program.

A procedure to optimize drilling programs is presented from a practical standpoint. The concept of a control well based on offset well data, using a cost per foot approach is discussed. Once the control-well and proposed-well data have been determined, a systematic analysis of the drilling variables is carried out. This analysis is concerned with the drilling hydraulics, mud properties, bit type, bit weight, and rotary speed. The final product is a well program which includes a summary of the proposed hydraulics, mud system, bit selection and operating conditions. In a final analysis, proposed drilling costs are compared with costs for the control well, and the proposed cost savings is determined.

Agnew" has proposed that temperature be utilized as a method for obtaining knowledge of the portion of a reservoir which has actually been stimulated. This particular method of evaluating frac and acid treatments has been utilized for several years. Additional evidence for the use of radioactive materials with temperature has recently led to the utilization of techniques involving the use of RA materials in conjunction with temperature, which lends a more quantitative perspective to treatment design and interpretation. This is particularly true when the combined techniques are used in conjunction with selective staging of fracturing and acidizing treatments.

In secondary or tertiary recovery projects fluids are injected into the rock formations to sweep residual hydrocarbons to producing wells. To optimize this operation the fluids must be injected at specified rates into the desired depth intervals. Therefore, injection profiles are run to determine the injection rates as a function of depth. Although temperature and noise logs can provide some qualitative data, spinner surveys or radioactive (abbreviated r/a) tracer logs are run if quantitative results are desired. At the present time by far the most popular method in use is the downhole radioactive tracer ejection method. The objective of this paper is to review the basic principles underlying this technique.

Qualitative interpretation of drill stem test (DST) pressure-time charts often is more of an art than a science. However, logical and efficient interpretation can be easily accomplished by understanding the basic factors involved in producing a chart. No two DST charts are exactly the same, and thus the guidelines given in this paper are designed to be general in nature. With knowledge of the basic DST shapes and forms in mind, even complicated charts can be broken into components and satisfactorily interpreted. A DST is a temporary completion of an interval within a well to help determine as much useful reservoir information as possible about the interval. The fluids recovered from a DST help describe the fluid type available from the reservoir and how well it may flow. The pressure-time chart is a valuable record of the test events and serves to validate the test results. At the wellsite, a properly interpreted DST chart also can give an indication of important reservoir parameters, such as productivity, permeability, pressure, and wellbore damage. In addition, determination of reservoir characteristics such as depletion, supercharge, permeability anomalies, and multiple zones often is possible when the chart interpretation is coupled with information such as reservoir geology. Finally, the quantitative pressure-time DST data can be analyzed using standard industry pressure transient analysis methods. These can yield valid numerical approximations of important reservoir parameters, and further support the chart interpretation. Quantitative analysis will not be covered in this paper.

This paper presents a methodology for evaluating waterflood performance on a pattem-bypattern
basis to identify wells that may benefit from some type of intervention or remediation. We
developed this approach to have a rapid screening method to analyze the commonly available data from
a waterflood and maximize the amount of useful information that can be determined from these data.
We calculate permeability and the variation in skin factor at the injector with time. We also calculate
average reservoir pressure, saturation and net voidage within each pattern as a function of time.
Diagnostic plots and maps show regions of high and low reservoir pressure, areas of poor sweep efficiency and the locations and types of various conformance problems. We have implemented the technique described here in a spreadsheet program on a PC. We also use a mapping software package to visualize and present the results of the analysis. We show how to calculate skin factor at injection wells and average reservoir pressure as a function of time on a pattemby- pattern basis. We also describe several diagnostic plots and maps to visualize and evaluate the waterflood performance. The data required for this analysis consists primarily of data that is gathered during the normal course of water-flood operations. We use the following data in our analysis. 1. Historical monthly production volumes of oil, water and gas. 2. Historical monthly water injection volumes and pressures for each injection well. 3. Average reservoir pressure and water saturation at the beginning of the analysis (either at the start of primary production or at the beginning of the waterflood). 4. Net pay and porosity distribution, preferably on a pattern-by-pattern basis. 5. The x-y location of each well and, preferably, information on how each well is completed including tubulars, perforations and stimulation.

The Kelly Snyder field is located in Scurry County, Texas, as shown on Fig. 1. This field is one of the major oil reservoirs in the United States. After discovery in 1948, the field was produced by solution gas drive until 1954 when a recommendation by the Scurry Area Canyon Reef Operators" Committee was implemented. The recommendation was to install a centerline water injection program to restore and maintain reservoir pressure above the bubble point. In March 1953 the SACROC Unit was formed and the proposed injection program was started in September 1954. Although this water injection program worked quite well, SACROC owners continued to look for ways to further improve recovery from the reservoir. In 1968, after careful study of several possible miscible displacement processes, a SACROC reservoir engineering committee recommended a miscible carbon dioxide injection program for the Unit to increase the ultimate recovery from the reservoir. The next three years were required to prepare for the carbon dioxide injection. The field was divided into 202 inverted nine-spot pattern areas and three phase areas which would be processed with CO2 on a separate time schedule consistent with the CO2 supply, as shown in Fig. 2. To commence injection it was necessary to install compression facilities and a CO, pipeline to transport 200,000 MCF/D of CO2 from several extraction plants in the Val Verde Basin area of southwest Texas and to prepare the Phase I area for injection by installing a field injection system, exposing the entire reef in the producers, and preparing the pattern injectors for injection. With the work completed, CO,injection began in January 1972. Downhole injection surveys were run frequently during the early life of the project, and poor profile coverage was discovered in many of the injectors. The problem became very critical when CO, breakthrough occurred during June 1972, more than a year before the CO2 removal facilities were complete, requiring curtailment of production. It became evident that correction of these poor profiles was necessary to avoid cycling the expensive CO2 and to avoid further production curtailments due to CO2 breakthrough. Since several methods are available for improving injection well profiles, the Unit Operator tested and evaluated several different methods. Open-hole packers were installed in several wells, but frequent failures occurred due to packer movement or CO, permeation of the packer rubber. Several types of polymer profile improvement jobs were performed with little success. The only control method which has proven to be consistently effective for controlling downhole injection profiles is the installation of a liner across the reef, followed by the installation of downhole flow control equipment.

Fluid slippage is defined as the fluid that leaks past a metal plunger during the upstroke of a down-hole, rod-drawn, positive displacement pump. American Petroleum Specification 11AX covers this type of pump which is used in approximately 90% of artificially lifted wells. This paper will present the first part of the results of a continuing research project covering the theoretical analysis and laboratory testing of pump slippage. The goal of this project is to present a mathematical model which will accurately represent the actual down-hole slippage for this class of pump. The current results should be useful to operators for selection of clearances between metal plungers and barrels. In the review of literature many of the clearances and differential pressures were lower than what is normally experienced in light oil operations. Tested clearances that were reported in the literature were 0.007" or lower. This investigation will evaluate some new ground looking at larger clearances and higher differential pressures.

The author will review the current status of a complete new approach is well servicing that includes: 1) A remotely operated robotic-automatic well services rig wherein there is no operating personnel within 100 feet of the wellbore. 2) An integrated system for making up tubing as well as the two element rod connection to absolute computer precision. 3) An integrated system for over the well electronic inspection systems of tubing and rods.

In the past few years there have been a number of software programs developed to process open hole wireline log data on personal computers. The majority require a thorough knowledge of program documentation to obtain the maximum benefit. When this is combined with the overall reluctance among many users to read documentation, the end result is a less than optimum utilization of processing power. The Microsoft Windows* operating environment for IBM compatible computers was created with the user's needs in the forefront by utilizing the concept of a "visual interface". Programs run under this environment can be executed with a minimum of keystrokes by using a mouse and pull down menus. All options are generally displayed to the user, and a minimum of program knowledge is required to execute an application in this system. To date, though, little use has been made of the Microsoft Windows operating environment in the log analysis software arena. To take advantage of the speed and ease of use, a popular minicomputer-based field log analysis program has been modified to function in the Windows environment. The Quick Log Analysis (QLA)" program is designed to accept the full range of wireline inputs available on the market. The Windows shell allows the user to run the program with a minimum of effort and a minimum of documentation. In addition, the Windows environment allows the user to integrate log graphics, cross-plots, reports, and text into a single document. The end result is a user-friendly log analysis program with powerful capabilities.

In these times of low oil prices and increasing operating costs, we at Shell NorthStar in Baker, MT, have been searching for ways to reduce costs and at the same time reduce failures. We have been successful in failure reduction caused by corrosion. But now, we needed a way of reducing rod loads to reduce rod failures and still pump the necessary amounts of fluid to maintain production. Our pump depths range from 8200" in the Little Beaver field to 9100" in the Pine unit; average production is 40 BOPD and 250 BWPD. Gas interference had not been a problem until we started drilling horizontal wells. This problem was addressed with the use of a ring valve assembly. After discussions with Rod Johnson (Rig Management Team leader), Doug Kaufman (Dresser Oil ToolsTM District manger), the RCFA team and several people in Altura field in West Texas, we came up with several ideas. We could run a shorter plunger, run a loose fit plunger (.007 clearance instead of .003) or take a closer look at a "vortex" standing valve we learned of at a recent school.

Sucker Rods, the prime purpose of which is to impart the reciprocating motion and power of the end of the walking beam to the sub-surface pump, are such a simple piece of apparatus that it might seem nothing much could be done to improve them. However, much has been and is being done to make their proper care and use better understood, to obtain a more accurate understanding of the actual loads imposed upon them, and to improve the joint design, the rod materials and the manufacturing techniques. It is the purpose of this paper to review what has been done and what is now being done along these lines with a belief that an understanding of these problems will lead to a better use and consequently, a more economic life of this vital link in the oil well pumping mechanism.

The techniques involved in the completion of a well, with regard to cementing operations, vary with areas and with regard to cementing operations, vary with areas and operators. Certain procedures are, however, looked upon as being most suitable for particular applications and often certain cementing slurry components have been found to give better performance in one of the two major cementing operations: primary cementing and squeeze cementing. A resume of proper cementing techniques is presented which will include flow characteristics of cementing slurries, effect of turbulent flow velocities on mud removal, effectiveness of chemical washes and the use of cementing plugs. The application of relatively new cementing practices using various low fluid loss slurries will be discussed from the standpoint of both primary and squeeze cementing and a resume given on results obtained while using these techniques.

During the past 4 years, successful field applications for casing plungers have been extended through recently patented innovations in design. This paper will review and summarize the technical progress in casing plungers. A variety of field applications will be reviewed and a summary of results will be presented. Actual economics of successful applications will be presented. Criteria for well selection, based on the comparison of best and worst case results, will be detailed. Probable expectations will be demonstrated through charts of actual well results.

New, patented technology developments on forming spiral flow in surface flowlines and pipelines as well as downhole to extend critical flow have been tested in a variety of programs by the Department of Energy (D.O.E.), with associations with the Stripper Well Consortium, Universities, and the Rocky Mountain Oilfield Testing Center. This presentation will provide a summary of this testing from 2002 through 2006. This will cover artificial lift applications to extend flowing wells, lower critical flow requirements to unload wells and production operations on mitigating paraffin and line freezing, as well as stagnant fluids removal. Finally, future testing of the various devices will be presented.

The Olmos Sand formation in South Texas presents many completion problems which vary considerably depending on geographic location. Almost always, massive stimulation is required to bring the sand to economic levels of production. Factors which must be considered to develop the best completion methods include mineralogy, lithology, temperature and frac gradients, permeability and porosity data, and the nature of the produced fluids. The paper also discusses the relative merits of different stimulation techniques used by the operators in the area and describes some effective methods of perforating, breaking down and fracturing the Olmos Sand.

With improved oil prices the Delaware formation of S.E. New Mexico has become a hot bed of activity since early 1990. The paper presents background information such as lithology, formation rock characteristics, X-Ray Diffraction and SEM analysis. Completion practices and perforation programs are reviewed for nine different fields along with analysis of different stimulation practices. The paper also reviews stimulation fluids, volumes, injection rates, types of proppant used and fracture geometries to provide an optimum completion program.

The emphasis of this paper is on what has been accomplished and how it has been accomplished. It is a matter of public record that from the time carbon dioxide was first injected at the tail end of a waterflood operation eleven years ago until now the production from Twofreds Field has increased from less than 180 bopd, to over 920 bopd, with the associated recovery of over 2.5 MMbbls of tertiary oil. The story that hasn't been told is exactly how this has been accomplished; what equipment is involved in the handling, processing, transportation, injection, and gathering of CO2 and the problems encountered throughout the system in dealing with this corrosive and compressible material. With introductory remarks as to the general nature of carbon dioxide, its unusual properties and how they relate to oilfield equipment and handling, this paper addresses equipment design, operation and maintenance from the source through the processing plant, through compressors and down the line, through injection facilities into the reservoir and finally to the recycling stage.

Paraffin related problems in the oilfield continue to hamper efficient production operations. Over the years, many thermal, chemical and microbial techniques have been developed for paraffin removal and inhibition. But it is very difficult to decide which treatment process will be the most efficient in a given environment. Only an experienced person with a vast knowledge of previous treatment operations can give a suitable decision. This project aims at making a comparative study of these techniques with an objective of creating a decision tree to diagnose and suggest the best remedial measure for such problems.

During recent sucker rod pumping problem solving schools it has become apparent that few engineers and operators know about the non-dimensional pumping parameters developed by the Sucker Rod Pumping Research Inc. and provided to the industry in API RP 11L for rod string designs. This paper will discuss the background and physical meaning of the two main parameters Fo/SKr and No/No", show the nomograph of their inter-relationship, and provide recommended limits which are typically not provided in modern rod string computer programs. These limits may assist in reducing sucker rod system failures. Additionally, the relationship of these design parameters to the dynamic motion of the sucker rod pumping system and the formation of undertravel or overtravel dynamometer cards will be provided.

The use of fluid loss additives in cementing is by no means a new idea. The industry utilized bentonite early on in cementing compositions to help control water loss to permeable formations. One of the first organic fluid loss additives was carboxymethyl hydroxyethyl cellulose. Polymer-type It was used when introduced in primary cementing. Shortly thereafter the use of fluid loss additives was extended to squeeze cementing.2 From that time, about 1961 to the middle 197Os, fluid loss additive compositions were changed to be able to handle varying downhole and surface conditions. In the mid-1970s a new concept, fluid loss additives for high-water-containing cement, was introduced. Up to this time, fluid loss additives (organic) were seldom placed in the high-water-containing lead slurries but mainly in the tail-in slurries being placed across pay zones. From the mid-1970s to the present, continued improvement in fluid loss additives has been made as well as advances in dynamic testing of fluid loss additives.3 There is still room for improvement in the area of fluid loss additives themselves because they need to be able to perform under all types of conditions. What fluid loss additives need to be able to handle is any combination of permeability, temperature, pressure, differential pressure, and slurry composition, yet still give any degree of fluid loss control predictably and economically. Obviously, this is quite an assignment and that is why each service company has several different fluid loss additives. It also stands to reason that fluid loss additives are expensive since they are polymers. It is, in fact, not uncommon for fluid loss additives to cost as much per sack of cement as'the cement itself. Thus, fluid loss additives should be used with common sense, and hopefully, the following discussion will tie together several aspects of fluid loss control into one comprehensive package and give insights into when to use fluid loss additives, how much to use, and what type to use. Most of the information in this paper is not new, but it has not been covered in one place and especially with a bias towards the Permian Basin.

The Willard Unit is located in the Wasson (San Andres) Field in Yoakum County, Texas. The reservoir is a layered dolomite with an average porosity of 8.5% and average permeability of 1.5 md. Secondary recovery by waterflooding has been in progress since 1965. Although secondary operations have been quite successful in the Willard Unit, a substantial amount of oil will be unrecoverable by waterflooding. A CO2 miscible displacement project was conducted in the unit to investigate the applicability of this process for full-scale improved oil recovery. The project consisted of two separate-held tests to study the various operational and reservoir aspects of the CO2 miscible process. The first of these consisted of eight adjacent CO2 injection wells on regular waterflood spacing. Since this was the first effort to conduct a CO2 miscible flood in this unit, this test was called Phase I. Water and CO2 were injected alternately in Phase I from November, 1972, to February, 197.5. This area was planned to provide insight into the extent of reservoir sweep problems that might occur in a regular-size pattern CO2 flood. It would also provide an opportunity to investigate control measures if these problems arose. Additionally, information would be obtained on injection performance and operational procedures that could be used in planning a unit-wideflood. The second test was located and operated separately from Phase I and was called the Pilot. It consisted of four wells: an injector, logging observation well, pressure observation and sampling well, and pressure core well, all on close spacing. The Pilot was designed to allow a more detailed investigation of the reservoir flow behavior of CO2 and water and to determine the reduction in waterflood residual oil levels due to CO2 injection. Phase I injection performance was good. The reservoir pressure was maintained above the minimum required for miscible displacement. Cumulative CO2 injection was 3.8 BCF of CO2, or 4.4% of the hydrocarbon pore volume. Some of the injected CO2 was produced as a result of excessive CO2 injection pressures, but this volume has totaled only 3% of the cumulative injection. There was no evidence of severe gravity segregation or area1 sweep problems. A complete analysis of the Pilot area has not been finalized. This project verified the concept of stratified flow in the reservoir and no significant gravity overriding of the CO2 was observed, The pressure core project was very successful and the Pilot results suggest that additional oil displacement occurred as a result of the CO2 injection.

Cement spacer fluids have traditionally been supplied by the cementing service companies. Specific performance properties and design criteria of most spacer systems have not been well defined. A cement spacer's basic function is to prevent non-compatible fluids from intermixing. It must perform with a wide range of additives under varying conditions while remaining compatible with both the drilling fluid and cement slurry. Spacer systems have traditionally been shrouded in secrecy and considered user unfriendly. This system has been successfully used in multiple wells drilled with both aqueous and non-aqueous based fluids at temperatures up to 350_ F (177_ C). Information is provided to help demystify spacers and provide operators with simple tools to adapt the spacer system to various drilling fluids and cement slurry formulations. Information is provided on performance properties as well as how to design a spacer system for specific applications.

A simple low cost dynamometer has been developed to obtain qualitative dynamometer cards for rod-pumping wells. The dynamometer installs on the polished rod in a matter of seconds and transmits data to a portable computer via wireless communications. The dynamometer measures rod stretch through each stroke of the pumping cycle. A sensor attached to the polished rod detects the bottom of each stroke to obtain position. The data is sent to the portable computer using wireless technology therefore eliminating troublesome cables. The wireless design allows technicians to perform dynamometer surveys in ther vehicle up to 300 feet from the well. The qualitative dynamometer can determine pump off conditions, down hole pump condition and rod string problems. Quanitative data can be obtained by using software available from Theta Enterprises. The dynamometer is low cost alternative to high cost, complicated quanitative systems.

A changing pattern in the methods of management by the oil producer makes it necessary that the contractor assume new responsibilities in the services he offers. This service must include planning management and well site supervision. The contractor seeks from the producer a basic change in his concept of management responsibilities in connection with well service and workovers. It is apparent that production rig operating cost has increased at a faster rate than rig productivity. This trend, for a healthy operation, must be stopped. To accomplish this, either the producer or the contractor must increase rig productivity. It is the opinion of the author that the contractor is best equipped, best trained and most experienced in the operation of production rigs. The responsibility to accomplish this rests squarely on his shoulders and the contractor's existence depends entirely upon his acceptance of this role of assuming responsibility of well site supervision to increase well site productivity. Providing more and better training for his field supervisors is the approach the contractor has elected to take. The Association of Oil well Servicing Contractors, trade association of well servicing contractors, conducted the first of a continuing series of well site supervisor courses at the University of Oklahoma in October, 1967. The main purpose of such courses is to provide contractors" supervisors with the knowledge necessary to perform workover and well completion work, which are normally the responsibility of the operators" well completion foreman. This paper sets out this and other plans and procedures by which the contractor hopes to change the producers" concept of well service and workover management responsibility.