Many engineers, when faced with the necessity of designing a fracture treatment for a well, will either look to the experience of other operators in the field or will rely on a service company for the design. Although these courses of action have merit, they do not always result in the most effective treatment for a particular situation. It is essential therefore, that the engineer have a knowledge of basic design methods and an understanding of fundamental fracturing concepts if he is to intelligently recommend a fracture treatment for a well. This paper presents a brief summary of fracturing concepts and a method for determining the size of the treatment. It provides a sound engineering basis for designing a fracture treatment, especially in areas where there is little or no prior fracturing experience to act as a guide. With this design procedure the engineer can determine the amount of frac fluid and the quantity of sand to be injected. The discussion in this paper is limited to the conventional, sand packed treatment where the induced fracture is in a vertical plane. It is generally believed that in most cases the induced fracture will be vertical below a depth of about 3,000 feet.

Over the last decade the use of the pressure derivative as a diagnostic tool in pressure transient analysis has grown immensely. The modern well test analyst turns to the derivative log-log plot almost exclusively to formulate a first opinion on well test behavior. The pressure derivative essentially allows the analyst a magnified view of the distinctive pressure behavior associated with various wellbore and reservoir phenomena. This paper utilizes both real and simulated pressure transient data to illustrate common derivative responses due to selected wellbore and near-wellbore effects, reservoir types, and boundary conditions. Definitions of common well test analysis terminology are included. The information presented should allow individuals who are involved in well testing, but not necessarily confident in test analysis, to qualitatively comment on test results.

A typical submergible electric pumping unit is composed of seven basic components: electric motor, multi-stage centrifugal pump, protector, power cable, motor flat cable, switchboard and an auto transformer, single three phase or a bank of three single phase transformers. All of the above equipment is manufactured in numerous sizes and types to fit the well specifications, such as casing size, desired producing volume, total lift, electrical power supply and environment. In addition to these basic components, various auxiliary items are used. Some are required, while others are optional. The most common required items to complete an installation are: Cable clamps, cable reel, reel supports, shock absorber, shipping boxes, tubing support and, in many cases, a swage nipple. Other optional items not required for an installation, but recommended where applicable are: Flat cable guards, check valve, bleeder valve, centralizers, motor jackets and downhole pressure sentries. In some instances, usually in remote areas, engine generator sets are used instead of purchased utility power. Such generator sets may power multi-well installations or individual wells. In the latter case, transformers can usually be eliminated by supplying an alternator which is wound to supply the proper input voltage (required surface voltage).

It is becoming increasingly important for technical personnel in the petroleum industry to have a background in filtration and separation techniques. One of the principal reasons for this need is demonstrated by the number of enhanced oil recovery (EOR) projects currently in operation. Anytime contaminated fluids are introduced into a subsurface formation there is a risk of damage. In the case of water and gas flooding operations where large volumes of fluid are injected, levels of contamination become acute problems. As an example of a systematic approach to filtration problems, this communication describes the component selection and field operation of a pilot system for the removal of solid and liquid contaminants from waterflood injection water.

Packers are run in oil and gas wells primarily to confine fluids. Usually the objective is to confine high-pressure or corrosive fluids and/or, in the case of multiple completions, to confine the fluid to specific tubing strings. Many side benefits are obtained because of the confinement; such as, protection of the casing from high-pressure or corrosive fluids, separation of zones in the well bore, directing the flow of treating fluid, and also as a safety feature. Various questions always arise; e.g., how much weight to set on the packer, how much do you pull, how much psi will it hold, how much do you pull to release the packer? There are a number of computer programs that have been written to analyze and predict tubing and packer loading forces and tubing movement. The computer certainly has its place, especially in the deeper wells where the conditions become more extreme and critical and the calculations become more complex. However, most applications can be quickly and accurately analyzed by applying a few basic calculations to determine the net result of the various operating conditions. Quite often it is possible to rely on an experience factor to design a hookup; but for more extreme conditions, the present and future well conditions should be anticipated and a hookup designed that would be compatible with these operations. This discussion will concern itself with calculations involving the hydraulics and various other forces as they affect packers. An attempt will be made to focus the emphasis on calculations that can be readily made at the wellsite without sacrificing accuracy. It would be oversimplifying the subject to say that all packer application problems are pressure and area calculations; but many of the calculations simply involve pressure and area. A little further in this discussion we will touch on tubing movement calculations involving piston (axial), helical buckling (corkscrewing), ballooning (radial) and temperature (axial). In a total analysis, many complex theories are utilized but that is not the purpose of this paper.

Mainly due to its long history, sucker rod pumping is a very popular means of artificial lift. Nearly two thirds of the worlds producing oil wells are on this lift. This paper reviews concerns that producers are faced with today when using inadequately designed sucker rod pumping designs, and suggest basic methods to assist with those concerns. In general, sucker rod pumping applications can be very effective when properly designed.

Where shall we drill? Is there oil in this zone? What is the best place to perforate? Where can we find water for this flood? From where is this water coming? How much oil is there in this zone? Where is the best place to inject? Did we pass up some good reserves? Why is the gas to oil ratio increasing? The answers to these common questions result in decisions which both cost and make money. Proper use of electric logs can help solve these problems many times. For this reason production personnel should be familiar with the principles of log interpretation.

The energy provided by salt water in an oil reservoir is one of the best known oil recovery mechanisms. Salt water should be considered a tremendous asset to oil production, rather than a liability, and it should be intelligently handled. Progressive companies recognize the value of salt water, as well as its dangers. Provision for its handling is made in the budget along with other development and operating costs. The most satisfactory method of disposing of large volumes of salt water in inland areas is by subsurface well disposal. A properly installed system does not "just happen"; it must be designed in detail and have adequate supervision, preferably by experienced personnel, during installation. Because of the corrosive nature of oil field waters, consideration should be given to the economy of corrosion resistant materials. The disposal well is the "heart" of a salt water disposal system and must be well protected, as it should be the last well in an oil pool to be plugged. The cooperative system to serve an entire pool provides for the most efficient handling of salt water disposal.

The handling, installation, and after-operations are all very important factors to ensure successful submergible pumping operations. This paper recommends the basic practices to follow for each of these subjects. It is felt that if these practices are followed, it will result in successful submergible operations for the user. The bottom line is that the producing company must be the major contributor who enforces good working practices that are pertinent to their operations and result in economical results. The following list itemizes the responsibilities and precautions related to the handling, installation, and operations of a submergible pump. Details of these general practices will be covered in the context of this paper under each individual category.

Packers used in oil wells date back to the earliest oil fields. The first packers were homemade and were generally a wooden plug-rag packer made by wrapping rags around a pipe, or steel wool or lead packed in the bottom of the hole with tools. Most of this early work was in open hole. Modern completions where casing is set through, cemented, perforated and acidized increased packer usage, giving rise to packer service firms that furnish tools and service to perform a treating job on a rental basis. These service tools are patented and are not sold. Approximately 5% of workover and completion money is spent on rental packers. This increased use of service packers started just after -World War II and resulted in the development of the modern service packer and retrievable bridge plug.

The results of a pilot inhibition program carried out on eight wells on the MCA Unit, Maljamar, New Mexico, form the basis for a batch treatment program that has been translated to over 400 producing wells in the Hobbs area. The recommended treatment program will be discussed with respect to selection of inhibitor, batch treatment methodology, frequency of treatment, and inhibitor dosage. Results showing the effectiveness of this program with regard to corrosion mitigation, increased production, and improvement of the quality of the produced oil and water will be presented.

The Beam Gas Compressor

A number of different methods of controlling beam pumping units are in use today and the important features of each are considered. Most of these controllers use the polish rod load (measured directly or by inference from the motor load) to determine the performance of the rods and pump downhole in the well. Whenever a variation in the rod load is seen indicating that the pump is not full of liquid, the controller shuts down the pump - usually for a fixed period of time. A new method which slows the pump motor by use of a variable frequency drive, allowing continuous operation, has been tested in West Texas. The advantages of this 11pumpdown18 method and preliminary results of the test program will be presented.

New results have appeared for downhole pump slippage predictions from fairly recent test data. Additional testing is in progress. A pump with large plunger/barrel clearances will slip more fluid. A pump with smaller clearances will slip or leak less but a tighter fit will tend to increase rod buckling at the pump to a greater degree. Considerations for pump leakage and example calculations are presented using the older and the new pump slippage relationships. Also the effect of pump clearances on possible buckling are studied. Further additional possible causes of rod buckling are presented and discussed and compared. The results will help the reader to decide on how to size pump clearances to provide leakage for lubrication in the pump without losing too much pump efficiency. Several ideas on the source of rod buckling are presented and compared, and the reader should be left with some review of older ideas and some newer concepts on how to combat rod buckling in the operation of a beam pump system.

Training techniques used in Continental Oil Company's Well Pumping Short Courses will be discussed. The API recommended practice (RP 11L) for calculation well loads, peak torque, polished rod horsepower, etc., will be presented in "building block" form. An understanding of instantaneous net torque calculations using torque factors will be secured. Typical rod pumping problem areas and possible solutions by utilizing standing valve and traveling valve tests vs. pre-calculated loads, shapes of dynamometer cards, orders of dynamometer cards and overtravel and undertravel dynamometer cards will also be presented. Three hours of course time are required for this presentation.

With the advent of Shale gas, fractured horizontal gas wells are the preferred method of well construction. Figure 1 illustrates production from Shale Gas. The well construction of horizontal wells can take on many forms. Figure 2 shows that horizontal wells can be drilled up from the kick off point, approximately horizontally from the kick off point and downward from the kick off point. The wells can be more complex than shown in Figure 2 and of different depths than illustrated. However for horizontal wells, when using pumps, the pumps cannot be set below the perforations as they sometimes can be for gas separation in near vertical wells, so this advantage is lost. This is one reason that many horizontal gas wells are dewatering using gas lift. However there are advantages to using beam pumps that still can be considered.

Variable speed drives have changed the way beam pumping units keep wells pumped down, prevent failures, and extend the life of the machine. VSDs, although slow to be accepted are now a typical portion of the control mechanism found in pumping units. In this paper, we will review the history of VSDs in the oilfield, provide an overview of where they are now an take a glimpse into the near future of developments. We will also cover issues that VSDs bring into the field with power quality concerns such as additional harmonics and what new technologies are available now and in the near future to combat these power quality issues.

The phenomenon of sulfide stress cracking (SSC) can result in catastrophic failures of pressurized equipment and piping, resulting in extensive damage, injuries and possible fatalities. Sulfide stress cracking was first identified as a serious problem in the oil industry in the late 1950's with the development of deeper sour reservoirs. The high strength materials required for these wells began to fail as a result of brittle fracture that was later identified as SSC. Research began on this phenomenon, and a task group was formed, which later became associated with NACE. In 1975, the T-1B committee of NACE published the first edition of MR-0175, "Metals for Sulfide Stress Cracking and Stress Corrosion Cracking Resistance in Sour Oilfield Environments". This presentation will discuss SSC, identify the requirements for SSC to occur and give designers and operators practical options for the prevention of SSC in equipment operating in an aqueous H2S environment.

In this paper, the behavior and analysis of rod pumped wells are studied. In particular, the theory and practice of determining motor mechanical and electrical loading are investigated. The results from these measurements can be used to acquire further information regarding the system, including mechanical and electrical system efficiencies. The methodologies discussed in this paper are used to design rod pumping systems with correctly sized motors as well as analyze specific cases from the field.

This paper will cover NBIC Code requirements of proper materials, welding procedures, and documentation in the repair and / or modification of ASME Code pressure vessels.

For West Texas and Eastern New Mexico producing areas, analog pump off controllers are widely employed by numerous operators to optimize fluid recovery and reduce equipment failures for beam pumped producing wells. With the development of supervisory pump off control (SPOC) systems, pump off control technology can provide engineering and operations personnel with a more complete well surveillance package that includes diagnostic capabilities. In addition, SPOC system hardware configurations are deployed so that individual well site controllers send alarm signals, digitized dynamometer cards, and other pertinent operating data to a host computer when a lift equipment failure or anomalous operating condition occurs. Besides providing for an immediate response to an upset well condition, the stored data allows for more accurate determination for the problem source. Effective lift design modifications can then be accurately developed. Amoco Production Company (Amoco) had implemented analog pump off controllers, to work in conjunction with a proprietary lease automation system, for the vast majority of beam pumped producing wells. With the availability of SPOC systems on a commercial scale, pilot testing was initiated to determine whether this enhanced technology could provide sufficient benefits to allow for pump off controller retrofit. In addition, experiences of other operators were reviewed to augment what developed to be favorable pilot test applications. Based upon this cumulative information, SPOC systems were implemented for non-automated producing properties and as upgrades for some key producing properties. Following implementation of SPOC systems for 671 wells that were previously equipped with analog pump off controllers, a post installations appraisal was completed to identify average economic benefits. Documented lift equipment failure reductions and fluid production increases were found to provide significant incentive to justify continued SPOC system proliferation.

For West Texas and Eastern New Mexico producing areas, analog pump off controllers are widely employed by numerous operators to optimize fluid recovery and reduce equipment failures for beam pumped producing wells. With the development of supervisory pump off control (SPOC) systems, pump off control technology can provide engineering and operations personnel with a more complete well surveillance package that includes diagnostic capabilities. In addition, SPOC system hardware configurations are deployed so that individual well site controllers send alarm signals, digitized dynamometer cards, and other pertinent operating data to a host computer when a lift equipment failure or anomalous operating condition occurs. Besides providing for an immediate response to an upset well condition, the stored data allows for more accurate determination for the problem source. Effective lift design modifications can then be accurately developed. Amoco Production Company (Amoco) had implemented analog pump off controllers, to work in conjunction with a proprietary lease automation system, for the vast majority of beam pumped producing wells. With the availability of SPOC systems on a commercial scale, pilot testing was initiated to determine whether this enhanced technology could provide sufficient benefits to allow for pump off controller retrofit. In addition, experiences of other operators were reviewed to augment what developed to be favorable pilot test applications. Based upon this cumulative information, SPOC systems were implemented for non-automated producing properties and as upgrades for some key producing properties. Following implementation of SPOC systems for 671 wells that were previously equipped with analog pump off controllers, a post installations appraisal was completed to identify average economic benefits. Documented lift equipment failure reductions and fluid production increases were found to provide significant incentive to justify continued SPOC system proliferation.

This paper presents the practical and the theoretical benefits of running a sucker rod - beam lift system as slowly as possible. The slowest speed possible is defined as the speed required to pump all the liquid the reservoir will flow into the well on a continuous basis. Operational changes to create any desired speed are shown and several field examples are used to illustrate the point. The potential savings using these methods are a greatly expanded run time, the system does the minimum amount of work and requires the minimum amount of power, the reservoir is allowed to produce at maximum rates with a minimum of down time for repairs to the rods, tubing, and pump.

As today's artificial lift equipment becomes more sophisticated and provides greater rates of return it is more important than ever to strive for 100% reliability. Since the equipment is often deployed in harsh electrical environments it is important to take effective measures to protect this equipment from damaging electrical surges. This paper will explore various methods that have been used to protect artificial lift equipment in the harsh electrical environments where they are often deployed. It will focus on practical applications, and solutions that are simple to install and have proven effective over multiple years of deployment. The paper will include a case study which demonstrates the economic benefits of using sustainable electrical protection systems to maintain production and protect artificial lift equipment from damaging electrical disturbances. The material will be presented in a very straight forward manner and should be of interest to all.

The optimization software and automation principles discussed in this paper have been implemented in fields with as few as 20 wells to fields with well over 3,000 wells. These installations have been made in primary recovery fields to tertiary recovery fields undergoing water, C02, or steam flooding. These systems have been installed in new fields with no automation in place and in mature fields, which have been automated for over a decade. Over the history of all these installations, we have documented the benefits and rationale for implementation of these types of systems. The paper describes the cash flow enhancement benefits of implementing a comprehensive production automation optimization System.