The rapid development of the Rhoda Walker Field (51 new wells in 1977 and 31 wells in 1976) indicates the interest in the Delaware Mountain Group pays in the Delaware Basin. Hydraulic fracturing treatments are necessary to stimulate production to a commercial level. An efficient stimulation approach has been developed, with the aid of detailed computer design studies, to produce maximum productivity in a cost-effective manner.

Today's cutting edge diagnostic software for beam pumping surveillance, analysis, and optimization includes improved methodology based on time-tested techniques as well as practical new functionality. Specifically, this paper will reference dynamometer card pattern matching to aid the well analyst, lease operator, or other interested parties in understanding well operating conditions. This is technology available from the 1980's, but refined in the pattern matching algorithms used and the presentation of results to the user. Available new functionality includes diagnostic reporting that produces a collection of outputs or warnings which are the result of a statistical analysis of surface and downhole card information, calibration or predicted dynamometer card information, and trended data for each beam well addressed by the diagnostic software. The required data is gathered and the resulting calculations are performed each day by the diagnostic software. The purpose is to apply logic that an experienced well analyst would use to determine whether each well needs any corrective action. The diagnostic logic can be customized, allowing users to specify statistical limits for creating warnings. Those diagnostic warnings deemed unnecessary can be de-activated by the user. Major areas of interest for this paper include: 1) recognition of RPC load calibration problems, 2) gearbox torque and pumping unit counterbalance, 3) correct prime mover size, and 4) verification of pattern matching usability. The field test will include beam pumped wells located in conventional primary recovery areas and wells pumping under the influence of injected CO2 for secondary recovery. The data presented in this paper was randomly selected from wells in a 101 well system located in western United States. Average pumping depths ranged from 5400' to 6500'. All wells were equipped with RPCs (Rod Pumped Controllers), calibrated load cells (all with five years or less service), and some combination of magnetic proximity switches and inclinometers for position input. RPC and end device maintenance and software well configuration history should be consider as average.

A novel gelling agent for hydrochloric acid is evaluated through field tests. Increased formation conductivity and live acid penetration depth is reflected by sustained improvements in production after the treatments. The advantages of this new gelling agent are its stability in high concentrations of hydrochloric acid (28 percent) to 300 F. over a range of temperatures up Comparisons with ungelled acid and acid treatments using other gelling agents are presented. These case histories are in West Texas, New Mexico, North Dakota, Montana and other parts of the country.

It is extremely costly to do wireline gas-lift valve replacement in wells with subsea wellheads. All gas-lift valves for these installations should be designed for maximum run life and known injection-gas throughput performance for unloading and gas lifting the well. The API Recommended Practice method for gas-lift valve testing is not economically applicable. This paper describes a practical inexpensive rapid method for performance testing individual gas-lift valves in the field utilizing the injection-gas source for lifting the well.

Knowledge of oil-water relative permeability, polymer viscosity, and polymer retention is required to design a polymer flood. These properties are routinely determined in laboratory tests with reservoir rock and fluids. Lacking reservoir core material for laboratory measurements, Chain Oil Co. used a series of single well tests to define the required properties. Transient tests of buildup and falloff pressures were used to find the relative permeability end points, while a single well pumpin-pumpout test was conducted to determine polymer retention. Apparent reservoir dispersivity was also calculated. The field test results were used to design a J-Sand polymerflood. During polymer injection, pressure falloff tests were run to measure the in-situ viscosity at different polymer concentrations. Non-Newtonian type curves were used to analyze the transient data.

The "RUFF-COTE" * process, a resin-sand coating applied to the external surface of casing to provide an improved bond between the casing and cement, has now been widely used in oilfield completions for the past ten years. This process has been applied to well casing from 2-7/ 8 in. slim holes to 20- in. surface casing in ultra-deep wells. Additional application has been on intermediate casing strings as well as on offshore platform jacket legs. Successful field usage of this process in thousands of wells has demonstrated its effectiveness in providing a good bond between the cement and casing. One area, however, that had not been previously evaluated was how long the initial cement-to-casing bond is maintained after well completions operations such as perforating, fracturing or acidizing, and normal stresses applied during production. In order to properly evaluate the resin-sand coating, it was necessary to analyze wells that had been completed both with and without the resin-sand coating and had been producing for a number of years. Continental's Sacatosa Field in Maverick County, Texas, fitted all requirements for a good field test. The Sacatosa Field located in South Texas produces from the shallow San Miguel sand at a depth ranging from 1300 to 1700 feet. The wells were drilled with a light water-base mud and completed with either 4-l / 2 in. or 5-l/ 2 in. casing. Casing was run to TD and cemented to the surface. A well plot of Sacatosa Field showing the test area is presented in Fig. 1. The casing was perforated with a single-plane horizontal jet gun consisting of either three or eight shots within 24 to 48 hours after cementing. All wells were then hydraulically fractured with a sand-oil treatment.

In 1961, Beach, O"Brien and Goins, published the results of a study of squeeze-cementing perforations." The study was made over a four-year time span and involved actual wells located primarily in South Texas. The publication gives a comparison of the squeeze practice of that time of attaining pressures equal to overburden pressure and "putting away" relatively large volumes of cement, to the new concept of low-pressure "hesitation" or the "walking" squeeze. The former method made use of normal slurries and the latter of filtrate-loss-controlled slurries. The squeeze success ratio climbed from about 60% for the normal slurries to 85% for the filtrate-loss-controlled slurries. Perhaps the most spectacular success was a well in Yoakum County, Texas, where 230 feet of perforations were successfully squeezed with 100 sacks of cement in a single stage. This is believed to be the first publication showing filtrate-loss control as a key to successful cementing. This work reversed the industry's thinking on squeeze-cementing technique.

During the recent development of the fire-flood oil recovery processes, one of the first problems that had to be answered is how to initiate combustion. It was found that quite often certain crude oils were difficult to ignite even in the Iaboratory experiments, and the problems were magnified in field cases. Just why certain oils are more or less susceptible to combustion than other oils of oil bearing formations is not precisely known; but because of this, seireral ignition methods have been developeci and ignition equipment has been improved. Design temperature levels can be obtained and the heat generation capabilities of ignition equipment is sufficient to meet almost any resewoil- condition.

The fire-safe capability of a valve is becoming increasingly important when selecting valves, for hydrocarbon processing service. In spite of this,

Recent activity in the Avalon Shale play, an upper member of the Leonard series in southeastern New Mexico1, has opened up a new horizon for production from an unconventional formation. Key to the potential success of the Avalon Shale play will be the ability to adapt and refine horizontal completion methods and stimulation techniques. The effectiveness of hydraulic fracture stimulations is critical for optimal economic production of this natural gas and oil shale play. The initial stimulation methods used for the early wells in this play have revealed several challenges while hydraulically fracturing the Avalon Shale interval. Some of the issues are high treating pressure, near wellbore tortuosity, early fluid leak off, natural fractures, and a propensity for sand-outs that lead to shorter effective fractures and wellbore damage. This paper will present field case study demonstrating most of the previously mentioned problems and issues with hydraulically fracturing in the Avalon Shale and the steps that were taken to remedy them.

There are many different forms of artificial lift methods used in oil and gas wells in the United States. Eighty percent of the wells in the USA that are using a form artificial lift use a beam pump; to lift the fluids out of the well bore. Lifting the fluid out of the well bore lowers the hydrostatic pressure acting on the producing formation allowing greater in-flow and increased productivity. There are several reasons for the popularity of the beam pump; they are rugged, forgiving and easy to automate. Good diagnostics exist due to many companies developing dynograph systems. This focus of this paper is on the five basic components of any beam pump, why they are important and how they interact.

Conventional Sucker Rods were designed and thought for Beam Pumping applications as well as their make-up process (with circumferential displacement). This brought many failures in the connection which is supposed to be stronger than the rod body. A line of Hollow Sucker Rods (HSR) was developed with better material distribution and several advantages but basically providing more reliability due to the fact that they were thought from the development for PCP. They include a special connection with a SEC type of threads and torque shoulder which is made-up controlling torque with a regular pipe power tong. This paper shows the experience in a field located in south Argentina were HSR have been working for more than 5 years in 17 wells. Field results and failures are discussed as well as special issues to have in mind when producing with this alternative.

Over the last 50 years hydraulic lift has proven its worth to operators worldwide in varying lift conditions, both on and offshore. Since the development of hydraulic lift in the 1930's, the products and technology have rendered hydraulics a viable means of artificial lift in today's oilfield. Through understanding and foresight, the operators can optimize the production and minimize the operating expense through equipment flexibility and performance. By utilizing the flexibility of a hydraulic lift system, both the surface and subsurface equipment can adjust to changing well conditions through the life of the well without major equipment change-outs. Optimizing equipment performance through efficiency, treatment, and monitoring, the operator is able to keep a handle on lifting costs. The following will cover the flexibility and performance on a casing-free single well hydraulic lift system. Many of the topics covered also apply to other types of single zone completion installations such as parallel-free, gas vent, etc.

Continually rising costs for producing petroleum make it mandatory for the oil industry to search for more efficient, improved materials and simplified, longer-life equipment. "Flexirod", the newly marketed flexible pumping stand, possesses characteristics that drastically reduce corrosion fatigue and thereby frequency of well pulling, lower horsepower requirements, make handling easier and faster and create the potential for new concepts in pumping equipment. This paper describes in detail the construction and operation of a nylon-covered multi-wire strand that functions as a continuous sucker rod. It is sufficiently flexible and light in weight to be placed on a reel for easy, rapid, economical handling. Development has been underway for over six years and numerous lengths are in actual operation in wells varying from 1500 ft to 5000 ft in depth.

During 1969, Getty Oil Company, which has since become part of Texaco, Inc., initiated a massive field automation program in it's Kern River Oilfield in California. The result was the SCAN system, or Sampling, Control and Alarm Network, which can be credited with supplying most of the field data and operating information necessary for the successful transformation of that 70 year old oilfield from a daily oil production of 45,000 barrels to a maximum of over 100,000 barrels per day. The system is still in full operation and has since been expanded to service 4600 wells instead of the 2200 wells connected at its inception. SCAN as an operating system has been well reported in prior literature (See ref.) so only a brief functional description is given here. This paper limits its scope to a portion of the system rarely touched upon by system analysts, the field-end hardware components which supply well data to the SCAN computer center. Especial attention is given to the individual well flow sensors, often referred to as flow/no-flow switches. These devices are worthy of special examination because they supply a stream of data which is of surprising importance to both engineering and operating groups. Their selection and application problems are also pretty typical of those encountered with other items of data producing hardware.

Increased drilling and operating costs have resulted in a greater number of dually completed wells. Most operators prefer two parallel tubing strings over concentric installations, since the development of detachable two-string packers and split wellhead equipment for parallel strings. This paper discusses in detail the flow valve selection for gas lifting both zones of dual with a common injection gas source. The material is presented in a manner which permits an operator to choose the proper valve design for a dual without a previous thorough knowledge of gas lift principles. The design considerations using fluid operated, intermittent and continuous flow gas lift valves for dual installations are discussed. An efficient installation is based on the combination of producing characteristics of the two zones. Proposed valve installations are outlined for the following combinations: 1. Both zones continuous flow. 2. One zone continuous flow and the other zone intermittent flow. 3. Both zones intermittent flow. 4. Producing characteristics of either or both zones unknown.

The world's largest flue gas operation is being conducted in the Block 31 Field, Crane County, Texas. This multi-pay field was discovered by The Atlantic Refining Co., now Atlantic Richfield Co, in Nov. 1945. Early in the field's life, the industry's first miscible displacement program was started in the Devonian reservoir. The 54 MMCF/D flue gas plant started operations on March 8,1966. The miscible program had been conducted for approximately 17 yrs. Prior to construction of the flue gas plant, a conventional gasoline plant and injection facilities were in operation. By burning a portion of the absorber residue gas in a controlled atmosphere, the volume can be increased 9-11 times. Operation of this flue gas plant resulted in not having to purchase 30-40 MMCF/D of natural gas, permitting the sale of 20-30 MMCF/D of produced gas and assuring a good supply of displacement gas for the reservoir. The flue gas plant will extend the economic life of the injection program.

Primary cementing is simple, i.e., displace drilling mud with cement to form a hydraulic seal between the pipe and the borehole. All too often, efficient drilling mud removal is not achieved, the cement cannot form a hydraulic seal and the result is communication between zones. This paper provides a discussion on the use of a fluid caliper to improve the success rate of primary cementing. The fluid caliper is an extension of mud conditioning and, used in conjunction with centralizers and other proper cementing procedures, provides for a surer primary cement job. Procedures and case histories are included.

Sucker rod pumps are installed in approximately 90% of all oil wells in the U.S. Although they have been widely used for decades, there are many issues regarding the fluid dynamics of the pump that have not been fully investigated. A project was conducted at Sandia National Laboratories to develop an improved understanding of the fluid dynamics inside a sucker rod pump. A mathematical flow model was developed to predict pressures in any pump component or an entire pump under single-phase fluid and pumping conditions. Laboratory flow tests were conducted on instrumented individual pump components and on a complete pump to verify and refine the model. The mathematical model was then converted to a Visual Basic program to allow easy input of fluid, geometry and pump parameters and to generate output plots. Examples of issues affecting pump performance investigated with the model include the effects of viscosity, surface roughness, valve design details, plunger and valve pressure differentials, and pumping rate.

During the last ten years, the acoustical well sounder has really come into its own as a production tool. These instruments are used to determine the fluid level in wells by the echo method. In addition, the location of various subsurface equipment items can be determined. At the present time, there are two major manufacturers of acoustical well sounders. Both of these manufacturers use two small trunks to house their instruments. One trunk contains the wellhead attachment with the necessary interconnecting cables. The second trunk contains the amplifier-recorder.

Ideally when controlling a rod pumped well, is it important to have often and accurate fluid levels. However in the absence of the availability of these measurements, fluid levels must be calculated using fluid properties and pressure gradients. An important part of those calculations is being able to correctly approximate the fluid load. The fluid load is the difference between the upstroke fluid load and the downstoke fluid load. in this paper the accuracy and validity of a methodology for computing fluid load lines and therefore fluid level is verified through the application of the fluid load line calculation to a set of field data, for which a fluid level is available for each stroke analyzed.

The water-logging of low pressure gas wells is a serious problem in some areas, and tends to become more grievous as field pressures drop. The free travel plunger, an old idea in the petroleum industry may prove in some instances to be more economical than any other known method of meeting this problem. The paper explains the theory of the free travel plunger, presents a few case histories, and generally compares the economical and operational aspects of this method with the more popular siphon string and pumping methods.

Surfactants have performed well in a variety of applications with regard to stimulation. The role of surfactants, or surface active agents, in both acidizing and fracturing has been somewhat taken for granted; but these agents nonetheless play an extremely important and ever-increasing part in almost all successful stimulation treatments. Surfactants have been discussed thoroughly in the literature with respect to use in oil well treating fluids. Until recently, most surfactants used in stimulation have come from one of two families. The most commonly used are hydrocarbon-based, and the others consist of silicone-based materials. Numerous blends of these types are used to deal with a number of situations. In varying concentrations, the above-mentioned "conventional" surfactants have been used in a variety of applications which are as follows. 1. To lower the surface tension or interfacial tension of a fluid. 2. To provide non-emulsion characteristics to a fluid. 3. To provide emulsion-breaking characteristics to a fluid. 4. To provide emulsion-forming characteristics to a fluid. 5. To provide foaming characteristics to a fluid. 6. To suspend fines or particles in fluids. 7. To retard or extend the reaction time of various acids. 8. To allow more effective penetration by aqueous or acid systems. 9. To facilitate a desired wetting function on a particular surface (i.e., metal, rock, etc.). 10. To assist or prevent various types of material in adsorbing to particular surfaces under certain conditions or to allow low adsorption. 11. To provide protection from various harmful reactions (i.e., corrosion, precipitation, etc.).4 12. To allow interaction with other physical problems in the oil or gas reservoir such as fluid imbibitions, capillarity, saturation or permeability.5"6 13. To allow water block removal or more effective treatment load recovery. 14. To improve wetting and thereby hydration of polymers used in stimulation. There are probably other uses which could be mentioned, but those above are generally considered most essential. Correct use requires careful selection of a particular surfactant type. The criteria for surfactant selection for use in a treatment is given below to emphasize the importance of appropriate materials.

Foam cement's ultra-light density and high compressive strength characteristics have been employed in the Permian Basin to protect low-fracture gradient formations. In addition to standard casing jobs, squeeze cementing results have been greatly improved through use of fast setting, expansive foam cements to obtain an effective squeeze without breaking down weak formations. With this unique fluid, squeeze cementing jobs have had a significantly higher success ratio for controlling water zones and sealing corroded casing. In cases where standard lightweight cement slurry compositions have proven ineffective because pumping pressures exceed formation breakdown pressure, foam cement has been used to help prevent fracturing weak formations. Field results and job procedures will be emphasized to illustrate how foam cement is being used in the Permian Basin to improve squeeze cementing job results when low formation breakdown pressures are present.

For the past several years, foam has been used in many treatments as a fracturing fluid. Although many different types of reservoirs have been stimulated with foam, the primary zones of interest in Eastern Kentucky and Southern West Virginia have been the Berea Sandstone and the Devonian Shales. Due to the nature of these formations, i.e. low permeability, low bottom-hole pressure and water sensitivity, foam fracturing has been a successful technique. This paper presents the basic background theory of foam and presents several basic treatment designs which have been used successfully in the Devonian Shales and Berea Sandstone. Production histories for up to two years on a number of wells fractured with foam are compared to production histories of offset wells which were conventionally fractured with gelled water. In all the side-by-side comparisons, foam fracturing was found to give production results either as good as, or better than, conventional fracturing with gelled water.