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.

The crude oil produced by ConocoPhillips in its South Guymon Unit is very paraffinic and has caused paraffin problems in formation, pumps, tubing, casing, flowlines and separators for years. Costs of production had been increasing because of lost production, plugged pumps, workover problems and stripping jobs. Many different types of treatments including cutting, solvent/chemical treatments, hot oil and hot water/chemical had been tried but all had been unable to reduce the problems or reduce costs. A unique application in this field has been found to cost effectively remove paraffin with cold water and chemical. This paper will discuss the application method, how it was tested and benefits resulting from its use.

Many oil-producing areas suffer from troublesome paraffin deposition in production and transportation operations. The use of paraffin inhibitors, which are sometimes referred to as wax crystal modifiers or pour point depressants, have been effective at reducing plugging caused by paraffin deposition. To be effective these materials must be applied at a point before the paraffin falls out of solution and they must be present on a continuous basis. This presentation describes a technique for squeezing inhibitor into the reservoir rock matrix to get a slow consistent return of inhibitor provide an extended treatment for controlling deposition

In Coalbed Methane (CBM) production wells using Electric Submersible Pumps (ESP), it is common to control fluid levels to the required setting by the use of Variable Speed Drives. However this can cause high harmonics and, as a result, in the Powder River Basin in Wyoming, power companies have become increasingly reluctant to allow the use of variable speed drives and an alternative method of well control had to be found. A totally new approach to controlling ESPs, and thus the well fluid levels, was conceived. The Weatherford Well Management System0 (WMS) is a self-contained alternative to variable speed drives, which eliminates harmonics problems. It consists of a motor starter, a motor protection system and a microprocessor which controls a surface actuated choke in the flow line. During production operations, fluid levels can be controlled by automatically adjusting the choke. This paper describes the conception, development and field testing of the Weatherford WMS as a viable alternative to variable speed drives for downhole pump control. This system, which can be made compatible with any communication system, though designed for ESP applications in CBM production, is also applicable to other artificial lif t systems and oilfield applications.

Diversified efforts are continually being made to reduce artificial lift operating costs and/or increase oil production. The intent of these efforts is to put more profit in producing operations and prolong the economic life of present oil properties. Also, a greater ultimate recovery means more efficient use of our natural resources. Fluid Packed Pump has become a part of an artificial lift revolution with the development of the Unidraulic-a unitized, one-well hydraulic pumping system which can economically compete across the board with rod pumping equipment particularly in the larger sizes and in addition can offer several operating advantages. Let's face it, large volume lift is on the increase due to expanded secondary recovery operations, higher allowables and the desire to produce wells at their maximum capability rather than at a lesser volume due to inadequate lift equipment. The Unidraulic concept was discussed briefly in a paper which was presented at the 1971 Southwestern Petroleum Short Course. 1 It began taking shape in April, 1969, following the approval of development money, engineering time, and a testing program. The first unit was actually installed on a 5100-ft well in South Texas on January 20, 1970. There are now in excess of 50 Unidraulic installations throughout the Mid-Continent, West Texas, California and Hocky Mountain areas. The heart of the Unidraulic hydraulic pumping system is the power fluid conditioning unit which has been designed and assembled to provide a solid-free fluid which can be used to transmit horsepower hydraulically. Other required items of equipment are those normally associated with a central-battery installation-the surface wellhead control, the subsurface production unit and the associated accessory items.

Lack of submergence and gas interference are the principal causes of poor pump efficiency; both create fluid pound. Fluid pound contributes greatly to rod parts, bearing and gear failure in pumping units, V-belt failure and prime mover damage. The greatest loss is in production when gas interference is present. Subsurface gas separators of many designs are being used; these separators are essential. The more gas that is separated from the oil and permitted to escape up the casing before it can reach the pump intake, the better. Some of the gas that remains in solution until it reaches the pump intake will break out of solution as it passes through the dip tube and standing valve. Intermittent pumping will greatly reduce equipment damage where fluid pounds are created by lack of submergence. One can intermittently pump a well with gas interference and reduce damage to equipment, but often at a sacrifice in production. Much of the gas breaks out in the formation and enters the casing through the perforations as free gas. Free gas escapes up the casing at about six inches per second in oil, and this gas should not present a pumping problem unless the well is over-pumped or excessive back pressure is held on the casing. Some gas remains in solution until it enters the pump. Some gas remains in solution even through the pump. This gas breaks out when it reaches its bubble point and quite often flows off. This is called "heading up". Gas-locking occurs when the traveling valve remains closed throughout the stroke. The "Charger" valve supports the fluid load above the traveling valve until near the bottom of the downstroke, then charges the upper chamber with fluid. A fluid pound cannot exist unless the fluid load is supported by the traveling valve on the downstroke. A fluid pound on the upstroke cannot exist if the traveling valve supports the entire fluid load. With a "Charger" valve, the seal opens at the beginning of the upstroke because the pump is filled with liquid. The seal closes and supports the fluid load at the beginning of the downstroke. The upper chamber approaches zero psi quickly after the plunger starts its downward movement. The fluid and gases in the lower chamber simply pass through the traveling valve as it moves down. The fluid load is supported by the seal and the buoyant effect is eliminated permitting the rods to fall more freely, thus increasing the weight of the rods on the downstroke. In every test we have to date, the range of load in rods has been reduced because of this increased weight on the downstroke. The peak polished rod loads have remained about the same or have been reduced, except in one test where there was an increase, which will be discussed later.

With over 600,000 rod-pumped wells in North America alone, failure of this common artificial lift system substantially raises lifting costs. Among the leading causes of failure in sucker rod-pumped wells are rod parts and tubing wear. Typically, an operator has little reliable data with regard to tubing deviation and the root cause of rod-on-tubing wear and tubing or sucker rod failure. In many cases, a minority of wells constitute the majority of repeat failures and workover cost in a field. Obtaining tubing geometry, wall thickness and rod condition, correlated by depth, during the well workover is critical to determine the failure root cause. A system is presented that uses high resolution data and internet-based imaging of key producing well conditions to (i) enable efficient analysis and (ii) apply preventive measures before the workover is completed and the well returned to service. An application is launched from Internet Explorer that allows dynamic 3-D viewing of individual wells or entire producing fields. Tubing and rod geometry and condition by depth in the producing well, is downloaded to the client machine from a web server in compressed XML and then imaged in an interactive graphic format. Correlation of deviation, wear and failures is rapidly displayed in a 3-D image of a specific well or a field view. Cross-wellbore queries allow mapping of common well conditions. The net result is lowered failure frequency, lower lifting costs and increased annual production.

Optimum production of gas wells requires static and flowing pressure surveys to detect excessive liquid loading. Wireline pressure surveys have been customary in spite of their cost and potential safety risks. Developments in digital acoustic fluid level technology have resulted in being able to undertake not only static bottom hole pressure calculations from fluid level measurements but to extend this technology to flowing pressure gradient surveys in gas wells. The new procedure involves monitoring fluid level and pressure in the tubing during a short term test sequence. The procedure is inexpensive and non-intrusive. Tests clearly show the redistribution of flowing gas and liquid and allow the construction of the corresponding tubing pressure traverse and the determination of the flowing gas/liquid ratio, liquid fallback volume and flowing BHP. Examples of tests performed in operating gas wells that are flowing above or below critical flow rates are presented and discussed in detail.