The Conventional beam pumping unit, a Class I lever system, was used almost exclusively in artificial lift applications from the 1700's until the late 1920"s. At that time, a "reversed" Conventional geometry design (Class III lever system), called an Air Balance unit because of its pneumatic counterbalance system, made its appearance. Later, in the mid 19503, a second, Class III lever system, or "reversed" geometry unit, was introduced and named the Mark II. Like the Air Balance unit, the Mark II had some performance features different from those of the traditional Conventional unit, but used similar rotating counterweights instead of the pneumatic arrangement of the Air Balance unit. The following paper will discuss some of the unique performance concepts of the Mark II design, and the background and rationale behind their development.

Inefficiencies in sucker rod pumping systems due to gas interference are major concerns for petroleum producing companies throughout the world. This paper describes an innovative cage design that is based on years of exposure to sucker rod pump inspection and repair from many varied field conditions and on compression and flow comparison testing. Observance of results obtained from working closely with the Alberta Research Council in Edmonton Alberta on numerous projects specifically related to conventional, thermal, vertical and horizontal sucker rod pumping was also influential. The creative cage design addresses the two features that are absolutely key to good standing cage performance. These two features are (I) high compression capability and (2) large flow capacity. The equipment used to perform the flow and compression testing allowed actual visual observation. The tests compared many different cage designs and demonstrated how those design differences affected cage performance.

The purpose of this paper is to discuss HNG Oil Company's drilling, completion, and producing operations in the Sawyer (Canyon) Field, Sutton County, Texas. The field is located south of Sonora, Texas as shown in Fig. 1. HNG has 134 productive wells, 60 percent of the field, on 58,000 acres with 220 offset proven locations yet to be drilled. The Canyon in this area is characterized by limited extent low permeability lenticular sands. The average well stabilizes at approximately 300 MCFPD and has an initial bottomhole pressure of about 1900 psi. Because of these characteristics and the initially low gas price (18c/MCF). The original economics were marginal. This necessitated a streamlining of operations to make the venture economical.

HNG Oil Company has completed over 20 deep gas wells in the past four years with remarkably few problems. The majority of the wells are located in the Delaware Basin of West Texas and range in deliverability from less than 1 MMCF/D to over 30 MMCF/D. Although each completion is different, the same basic steps were followed. Each was perforated in acid with a limited number of deep penetrating, burr-free perforations, and was originally stimulated with a moderate volume of 15% HCl using ball sealers to divert the acid. The mechanical hookup in each case consists of high quality, properly designed tubular goods and involved in these completions from the time the liner is cleaned out until it is flowing is four days for a single and five days for a dual. The key to the entire completion program is simplicity. The more operations involved in a completion and the more equipment placed in the well, the greater the chances for failure.

This paper is intended to have a twofold purpose. While the data cited refer to the specific problem of borehole instability as affected by the drilling fluid, it is also intended that the approach taken toward alleviation of the borehole instability problem through mud technology in this case is applicable to other drilling problems as well. Borehole instability serves as an example of a drilling problem to illustrate how drilling problems may be approached in an organized manner by way of the drilling mud. The varied drilling problems that are susceptible to alleviation in part through the drilling fluid, may be approached systematically by considering the drilling problem in terms of the fundamental characteristics of drilling fluids. These fundamental characteristics are stated in Fig. 1. More detail could be added to the criteria listed. Solids content could be listed in addition to weight, for example. Nevertheless, if a given drilling problem is considered carefully in terms of the criteria listed, it will be found that the analysis thus carried out will be accurate and reasonably thorough, insofar as the problem in question is subject to solution through the drilling fluid. Futhermore, in addition to serving as a guide for the application of mud technology, these same criteria point to areas in which improvements in presently existing technology may be sought. In the text to follow, the problem of borehole instability will be analyzed in terms of the weight, rheology, filtrate and other characteristics of the drilling fluid. Of the various rocks that are penetrated in the course of drilling a well, the rock most likely to be unstable is shale. Both sandstones and carbonate rocks may be unstable when subjected to tectonic stresses or when the hydrostatic mud pressure is lower than the pressure on the fluids in the rocks, particularly when the permeability is low. But the instability problem with shale is compounded by the extraordinary manner in which this rock is affected by wetting with water.

Fissile shale has strong potential to cause severe wellbore instabilities. It is highly laminated and can split easily into thin layers along its bedding planes. With the high concentrations of clay minerals, this type of rocks usually has high cation exchange capacity. Dispersion may not be strong, even in water, but the rock becomes highly broken mainly along bedding planes once it is in contact with fluids. Finding suitable drilling fluids to stabilize reactive fissile shale formations is an area of active research in M-I SWACO. A shale-stabilizing drilling fluid was designed for a highly-deviated lateral Morrow formation well in New Mexico. Morrow formation instability had caused serious drilling problems on a previous attempt to drill a lateral in this area and was the major obstacle to the exploration process. An oil-based fluid designed to stabilize the Morrow formation resulted in the successful drilling of an extended-reach lateral well.

The Horizontal Well Artificial Lift Consortium is now an official, funded project. The purpose is to develop an improved understanding of the issues for production horizontal oil and gas wells, especially where application of artificial lift is required.
The research is primarily conducted at the Univ. of Tulsa. There are currently 10 member companies with the number expected to grow.
This presentation will give an update of the status of the Consortium and the current research focus.

The oilfield adage that "you cannot hurt a good gas well or help a bad gas well" is not necessarily true. The new Horizontal-Spinner coupled with vast interpretation experience of temperature logs has revealed a number of completion problems that can be overcome. The gas source is not always where the perforations are placed and many perforations are not opened when treated. In deep gas wells the present formation logging tools do not properly identify the productive zones; and the present perforating and treating techniques do not create access to all the zones to be tested.

Field tests were performed to better understand the effectiveness of hot oiling to remove paraffin in downhole tubulars. In particular, the tests were designed to investigate the depth to which paraffin might be melted. The temperature decay following the end of the treatment, pump capacities, and heat loss assumptions were used to estimate the treated depths. The results indicated that annular hot oil treatments might be effective for paraffin wax that is very near the surface but the effective treating depth is very limited. In addition to the field testing, industry surveys of the perceived depth of effective treatment were collected. The results of the field tests compared with the industry survey suggest a dramatic problem of perception compared with reality. This disconnect may result in millions of dollars of expenditures that are ineffective or only partially effective. The field tests for a variety of tubular configurations indicated effective treating depths of less than 200 feet, compared with median perceived depth of 1,000 to 3,000 feet. The study also brought to light the seriousness of heat transfer losses from the hot oil burner to the wellhead before the process begins to start down the hole. In effect, the truck itself and injection line to the well act like giant
radiators that rob heat from the treating process. The results of the study suggest that alternatives to annular hot oiling need to be seriously evaluated if the artificial lift failure history indicates paraffin deeper than 200 to 300 feet. Furthermore, annular hot oiling during colder periods should be avoided altogether or otherwise very carefully designed and supervised.

The desirability of using a tubing anchor in a pumping well to increase effective pump stroke and to reduce wear on sucker rods, tubing and casing has been recognized for many years. It is well known that an unanchored tubing string "breathes" as a portion of the fluid load in the tubing is alternately transferred between the tubing and the sucker rods during the pumping cycle. The elimination of this movement of the tubing string by means of an effective anchor should provide obvious benefits to the operators of rod pumped wells. However, the use of tubing anchors in the past has, in general, given overall results that have been somewhat disappointing at best. In many cases there has been little or no increase in pump efficiency and rod and tubing wear have continued to reduce appreciably the operator's margin of profit.

The success ratio of squeeze cementing operations in the past has been poor. A lack of knowledge of downhole conditions and formation characteristics was partly to blame. Proper cementing materials for downhole conditions were not always available. Recent development of cementing materials and techniques has greatly improved the success ratio of squeeze cementing. New tools are available to provide a greater knowledge of downhole conditions to determine the existing problems in the well. New cementing materials have been developed so that a cement slurry can be tailor-made for each particular set of well conditions. Laboratory equipment is available now to stimulate downhole conditions in testing cementing materials in squeeze slurries. With the knowledge and materials available today a squeeze cementing job designed on the surface will, in most instances, perform down the hole.

An Operator/Pumper is typically expected to produce their assigned wells in a manner that results in a maximum allowable production rate at a minimum of cost. However, they must do so with the wellbore conditions, equipment, and operating environment they as assigned. This paper will present some tools and methods that the Operator/Pumper can utilize to help optimize a rod pump well.

The purpose of this paper is to discuss and emphasize the importance of the royalty owner to the oil industry and the direct effect which unfavorable owner relations has on your company's profit. This paper will be divided into six principle parts: (1) Introduction; (2) The importance of the royalty owner; (3) The landman's role in royalty owner relations; (4) The royalty owner's role as the company's constituent; (5) Ways of preventing adverse relations with royalty owners; (6) Summary.

This paper gives quantitative calculations of the effects of Carbon Dioxide and pressure on the solubilities of formation minerals in a West Texas brine. Increased pressure makes anhydrite and gypsum significantly more soluble. The solubilities of carbonate minerals are increased to a lesser extent. The presence of Carbon Dioxide causes large increases in the solubilities of carbonate minerals, thus exacerbating the scale problem. Carbon Dioxide will greatly reduce the pH of injected or connate water, but this undesirable effect is reduced by the buffering action of carbonate minerals. Because of this buffering action, common mineral scale inhibitors can be used in CO, floods. Increased dosage may be required because of the potential for more scale.

Gas and liquid are frequently transported simultaneously in the same pipe. Common occurrences include pipelines for gas and oilfields, piping in refineries and process plants, and steam injection and geothermal production systems. When two-phase flow (i.e. gas-oil-water) occurs in a pipeline, the phases separate geometrically in the pipe into various flow patterns. In general, the flow pattern that results depends upon several flow parameters, of which phase velocities and pipe inclination are the most important. When the flow pattern at the exit of a pipe consists of alternating slugs of gas and liquid (i.e. slug or intermittent flow). special operating procedures are frequently required. Processing such slugs can require first passing the gas-liquid mixture through a larger diameter conduit (i.e. slug catchers) to promote segregation or stratification of the phases. Only then can gas liquid separators be operated properly to minimize pressure fluctuations and assure an acceptable low volume fraction of liquid in the gas or gas in the liquid that leaves the separator. The cost of constructing and locating slug catchers can be extremely high, especially when dealing with large diameter pipelines terminating on offshore platforms. A method to eliminate long slugs of liquid economically is of great interest to companies operating the above types of facilities. It has been found that slug flow in a pipeline-riser pipe system can be eliminated or minimized by careful choking that results in little or no change in either flow rate or pressure level and elimination of pressure fluctuations. The careful choking can be accomplished automatically with a unique control system consisting of a combination of electronic and pneumatic devices. Such a system has been tested using kerosene and air on a 2-in. diameter pipeline-riser pipe test facility at Tulsa University). Slug-flow was eliminated automatically in every test conducted. The devices were also installed in a specially designed facility consisting of approximately 60,ft of 1-in. pipe configured with several rises and falls to simulate a hilly terrain pipeline. Slug flow was eliminated here also in every test conducted.

When designing a Production Facility, many engineers and production foremen are confronted with a multitude of codes, standards, best practices and even OSHA requirements. Often, the facility design is based on old outdated codes, standards, or practices. Lack of proper engineering design can lead to equipment failure, lost production, human injury or harm to the environment.
The safety of a facility is a direct function of how the facility is designed. The oil and gas industry has produced many codes and standards, which were developed primarily in response to incidents that had occurred. Understanding and learning how to apply the various codes and standards can greatly increase the operability and safety of facilities.
This paper reviews the key area of facility design that is critical to a safe facility. The paper explains how the different codes, standards and best practices can be used to develop safe and cost effective facilities.

The author developed a computerized technique for sucker rod system design that attains the pumping mode with the lifting efficiency being at a maximum. This optimum pumping mode gives the most economical combination of plunger size, stroke length and pumping speed. The proposed design procedure applies to conventional pumping units and assures minimum energy usage for the production of the required liquid rate to the surface. The method presented in this paper involves designing of the rod string for each pumping mode used in the process of selecting the optimum mode. This is an important new feature, compared to previous investigations that relied on published taper lengths. The determination of pumping parameters (plunger stroke length, pumping loads, etc.) is affected by the physical characteristics of the rod string. However, string design requires the knowledge of the pumping mode: plunger size, stroke length, pumping speed. Therefore, the selection of an optimum pumping mode is an iterative process, for which a detailed solution is given in the paper.

Throughout the world the most common method used to artificially produce wells is through the means of sucker rod lift. Low producing efficiencies caused by incomplete pump fillage is the most common operational problem experienced by these the sucker rod lifted wells. Incomplete pump fillage is the result of having a pump capacity that exceeds the production rate of the well or having poor gas separation at the pump intake and a portion of the pump capacity being lost to gas interference. More efficient operations and lower cost will result, if these wells are operated with a pump filled with liquid. To operate with a full pump requires the elimination of any gas interference in the pump and requires controlling pump run time so the pump displacement will match the inflow of liquid from the reservoir into the wellbore. Periodically the operator must monitor the wells operations to insure that the pump has no mechanical problems and efficient operations are maintained as all the available liquid is produced from the wellbore.

Sucker rod breaks have been extensively studied and documented in the oil industry. Polished rod failures, on the other hand, have not received as much attention. As a general rule, operators seem to be more tolerant of polished rod failures. But polished rods fail for reasons that can be controlled. The purpose of this paper is to identify these reasons and to discuss ways to minimize polished rod breaks. Almost without exception, the polished rod is the strongest component of the rod string. It has the largest cross-sectional area and its material strength is at least equal to that of the sucker rods. Yet in many cases, polished rods fail with regularity while the sucker rods do not. Surface pumping equipment can induce destructive stresses in polished rods. By analyzing polished rod failures, which usually occur at the bottom of the polished rod clamp, useful conclusions can be reached about these stresses and what can be done to control them.

Hydraulic pumping systems for oil wells have been in existence since 1932. High-pressure power fluid (produced oil or water) is supplied to a
subsurface engine-pump assembly. The power fluid exhausted from the engine is returned to the surface along with produced fluids from the well. The earlier hydraulic systems employed one or more highpressure pumps on the surface to furnish power fluid to one or more wells. Large tanks were used to settle out water and solids from power oil.

Availability of CT as well known OCTG and the need to have new options on artificial lift prompted a CT consulting firm to investigate the use of CT to convey well fluids to the surface. While numerous test proved that CT as "hollow sucker rods" can replace conventional sucker rods and production tubing, the lack of appropriated coil tubing units to deploy and retrieve CT economically delays the application of this innovative option. The paper will discuss new CTU designs and economics related to the use of CT versus solid sucker rods, and the latest developments in artificial lift with coiled tubing. This paper will describe laboratory testing, field application methods and case history results of the application of salt inhibiting treatments in several applications.

Availability of CT as well known OCTG and the need to have new options on artificial lift prompted a CT consulting firm to investigate the use of CT to convey well fluids to the surface in oil and gas wells.The first idea consisted of a stationary CT attached to a modified rod pump to convey fluids to surface by the use of hydraulic pulses. This first approach triggers a second idea consisting in the reciprocation of CT as hollow sucker rod in rod pumping wells. Numerous tests for diverse applications are being performed with results to be covered in this paper.Because of the consequences of these innovations, another idea was tested, this time to reciprocate a subsurface pump capable of using the full cycle of the pumping unit with either conventional rods or CT. Latest field test results are part of this paper.

Recent innovations and repeated successful applications using the multiple patented PAL PLUNGER casing plungers suggested extending the applications to stripper gas wells that produce from multiple production zones and/or from wells with casing having obstructions that restrict proper placement of down hole landing stops. The new HYBRID CASING PLUNGER, successfully installed and retrieved using a standard swab rig, removes well bore fluids from multiple production zones. The standard PAL PLUNGER was coupled with a unique down hole compression packer and fluid isolation assembly to permit well bore fluids to be lifted by gas flow to above the packer and subsequently removed from the well bore on the next plunger cycle. Bottom hole pressure data obtained shows the hydrostatic gradient to be that of the "dry" gas section of the well bore above the standing fluid level. Production data shows an increase in fluid removal and daily production rates.

This discussion is primarily concerned with the operating control of the bottom hole pump of the hydraulic pumping system. Design and engineering calculations are purposely omitted, as well as any discussion concerning operation and maintenance of the surface power pump. In short, the purpose of this discussion is to suggest procedures for operating hydraulic bottom hole pumps and to show that with hydraulic pumping, the operator has an exceptionally fine tool for defining well problems.

In 1949, the first commercial hydraulic fracturing treatment was performed, thus initiating one of the most outstanding well stimulation procedures that the petroleum industry has ever known. During the past 16 years, much advancement have been made in the concepts of hydraulic fracturing theory. The purpose of this paper is not to clarify the concepts of hydraulic fracturing theory, but to present a sound design method of effectively employing the concepts. Discussion of theory will be confined to only that necessary to justify the method of design. The design procedure presented in this paper is limited to vertical fractures and presents a method of optimizing fracture treatment sizes.