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.

Each year production is lost due to water influx from naturally occurring or induced channels or fractures. A special sealant process has been developed to help control subsurface water movement. The process consists of two individual states separated by a water spacer. Multiple treatments may be applied to control more severe downhole conditions. The first stage consists of about 200 gal/ft of a solids-free, non-Newtonian fluid with a viscosity of approximately 200 cp for matrix penetration. As much as ten pounds of solids per gallon may be added to this fluid for channels or fractures. This stage forms a very stiff gel when it contacts synthetic or formation brine. In fresh water zones where little salt is present, a preflush of concentrated brine is injected ahead of the first stage. The second stage consists of 10 to 30 sks/ft of low water-loss, accelerated cement slurry. This cement slurry is used to complete the special sealant process by forming a permanent, high-strength plug. To fit specific well conditions, solids may be added to the cement slurry. Successful sealant treatments have been performed in West Texas and New Mexico to correct subsurface water movement in producing wells. Most applications have been in naturally occurring or induced channels or fractures creating undesirable water flow. Sealant treatments up to 8,000 gal of first-stage fluid followed with 600 sacks of cement have been used.

Automating of oil production leases may be approached stepwise if proper planning is done initially. This paper summarizes the various automated processes in lease production, showing the limits and planning required to automate at each stage is set out.

Nitrogen alone has demonstrated success as a fracturing fluid in reservoirs normally found sensitive to liquid systems. It has proven useful in shales of the Ohio Valley and West Virginia areas, and in similar lithology of the Fort Worth Basin located in North Central Texas. The fracturing efficiency of nitrogen, as related to leakoff and flow capacity testing with no propping agent, has been investigated to analyze the effectiveness of nitrogen stimulation. Also, field data are presented which demonstrate successful results of the nitrogen technique in both oil and gas reservoirs. From the laboratory studies and field results, several conclusions were drawn concerning nitrogen stimulation. Of primary interest is that most of the width reduction in an unpropped fracture will occur in the early stage of production which indicates a sharp decline of the well flow rate after a relatively short period.

The effect of the physical properties of various cementing mixtures on bond log interpretations is presented. The nature of the pipe cement contact required for minimum acoustic transmission and effects of instrument calibration are also discussed.

The initial goal of a

A 12,500' hydraulic jet pumped well, located in Andrews County, Texas, was converted to a rod pumping system in order to reduce lifting costs and maximize profit. A rod pumping simulation program (wave equation) was used to quantify possible ranges of equipment loading, rod loading, plunger over-travel, and ultimately, production in the stock tank. The sucker rod pumping system design includes the use of fiberglass rods, a downhole separator located above a permanent packer and a tapered tubing string. The design criteria, installation procedure and actual system performance are presented.

The Snyder Field is located in southeast Howard County, approximately 15 miles southeast of (the City of Big Spring, Texas. The field was discovered in May, 1926, with the completion of the Magnolia Petroleum (Choate and Henshaw) No. 1, M. H. O"Daniel Well. The field covers 6000 productive acres and production is obtained from approximately 400 wells. The Snyder Field is south of the Iatan-East Howard Field and is separated from that field by an arbitrary dividing line utilized by the Texas Railroad Commission in distinguishing between the fields. The portion of the Snyder Field reviewed in this paper

The Northeast Jones area of Oklahoma was discovered in 1945. Production peaked in 1948 and the area was almost depleted by 1950. Primary recovery was an economic failure and the field was almost abandoned without a trial of secondary recovery. There were several reasons for the pessimism regarding water flooding, but the most predominant was the old "rule of thumb" that secondary recovery would be the same as primary recovery. The Northeast Jones Cleveland sand unit was formed in 1952, however, with the promotion of an outside group of operators. The water flood proved to be very successful and lucrative, recovering over twice as much waterflood oil as primary oil. Peripheral injection was employed which eliminated the need to drill new wells and, in retrospect, made the project much more successful than would a pattern water flood. The geometry of the water flood, the uniformity of the formation, and the high oil saturation are believed to be the major contributing factors to the high oil saturation are believed to be the major contributing factors to the high waterflood recovery and efficiency. Only 3.1 bbl of effective water injection were required for each barrel of oil recovered.

Currently available production packers are categorized according to function and design. A packer classification method is outlined with the equipment available from several manufacturers included as examples. Simplified cross-sectional drawings, photographic examples, major design features, and several common applications are included for each general type packer. An abbreviated packer designation method is also presented.

One of the first steps in determining how to manage a waste stream from a pipeline operation is to identify which regulatory agency has jurisdiction over the management of that waste stream. In the State of Texas, two state agencies and a federal agency have regulatory authority over different aspects of waste management. A lack of familiarity with current regulations may result in some confusion for pipeline operators. This was demonstrated in the last year.* It appears that many pipeline operators whose hazardous waste management activities are subject to RRC jurisdiction are actually registered through the Texas Natural Resources Conservation Commission (TNRCC). P The following discussion is intended to clarify jurisdictional issues with respect to waste management for pipeline operations in Texas and alleviate any potential confusion within the regulated community. This discussion does not address other issues, like pipeline safety regulation (RRC) or air emissions (TNRCC), where the jurisdictional boundaries are different than for waste. Jurisdictional authority for all regulated activities should be fully evaluated for each facility.

An 87-well lease in a major West Texas oil field has been converted to automatic operations except for custody transfer. The system automatically controls the production from the wells and the periodic well testing scheduled for the lease. All wells on the lease are pumped with standard, electrically powered, beam units. Periodic well testing, formerly done manually, is now performed automatically by means of electrically operated time controllers which divert on a pre-determined schedule production from the well to be tested through well test units. Lease production is gathered at a central storage battery equipped with automatic tank switching and safety controls. The pumper's work on the lease includes daily visits to the battery with the pipeline gauge to test manually the oil and to make the pipeline runs and checks of wells and equipment for routine maintenance.

Pressure coring offers a method for obtaining In Situ reservoir Saturations. However due to the requirement of pressure balance during coring it has henceforth been limited to use in reservoirs with pressure gradients greater than 0.25 psi per foot. This paper will describe techniques used to obtain the first known successful pressure cores taken using a foam mud system; thereby extending the useful range of pressure coring to under-pressured reservoirs. Stable foam is a compressable Non-Newtonian fluid that requires special design considerations when used in conjunction with pressure coring. Careful well design is necessary to insure Bottom hole pressure during drilling and coring operations does not fall below reservoir pressure. This can easily occur if foam degradation and nonlinear pressure gradients are not considered. A complete technique for using foam to pressure core, including well design, field implementation, and core handling is presented in this paper. This technique includes a well bore design, a pressure analysis method, a method of selecting optimal foam design, a description of logistics, an empirical calibration test, and a description of pressure coring operations and core handling.