San Andres producers in several areas of Gaines County, Texas are limited on stimulation injection rates due to the proximity of potential water producing intervals. The San Andres is a dirty dolomite formation with a bottomhole temperature of approximately 135_F. Usage of acid to stimulate the formation is desirable, but given the low injection rate restrictions, diversion and penetration of the acid into the formation are difficult to accomplish. Prior treatments using rock salt for diversion resulted in most of the salt falling into the rat-hole. Recently, success has been achieved utilizing a viscoelastic acid diversion system and a chemically retarded acid system pumped in alternate stages. Injection rates have been held to 3 BPM or less, with pressure increases from diversion being observed. Initial production responses have been from 2 to 7 times more oil and 2 to 5 times the water.

The CO2 foam fracturing fluid provides a gas drive to assist removal of the treating (load) fluids after the proppant has been placed in the formation, establishes permeability to gas within the formation volume that has been saturated by load fluids, and minimizes the actual water volume that is required to place a given volume of proppant in the formation. Due to the high density of the liquid CO2 mixture, the CO2 foam can be utilized on deep, high pressure formations without experiencing prohibitive wellhead treating pressures. The CO2 also reacts with the water in the foam to form carbonic acid, so that the overall pH of the system is reduced (thus reducing the damaging effect of the fluids), and it lowers the surface tension of the load fluids so that they can be recovered more rapidly and efficiently. Field experience in the Ark-La-Tex area has demonstrated that the CO2 foam system can be used successfully in low permeability oil and/or gas sands and carbonates, at depths ranging from 2900' to 14,000 ', reservoir temperatures of 120_F to 370_F, and reservoir pressures of 1000 psi to 13,200 psig. Treatment histories and pressure transient tests have demonstrated that many of these formations are sensitive to some fluids utilized in conventional gelled water fracture treatments. A comparison of CO2 foam with several other stimulation methods demonstrates its overall success. In many instances the production results obtained with CO2 foam fluid are superior to more conventional systems that have been used in the past.

The subject matter of this paper will describe Binary foam fluids, their advantages and how they have been applied to increase production in various tight gas sands in Southeast New Mexico. The paper will include a discussion of the formations stimulated, production results, and typical treatments for tight gas sands. Furthermore, the paper will include comments on Binary foam design utilizing three dimensional fracture simulators and considerations for workover candidate selection.

Fracturing designs are generally based on information from 2D simulators, 3D simulators, field experience, or previous designs. Once a fracturing job is designed and a fracturing schedule is established, the job is usually pumped according to design without any changes. Because of such inefficient planning and procedures, millions of dollars are wasted each year on fracturing jobs that fail to provide the expected results. Preplanning and real-time analysis are key factors for successful hydraulic fracturing and increased hydrocarbon production. The following seven-step process can be followed to incorporate real-time analysis and improve fracturing procedures: 1. Gather information about the initial wells to be stimulated. 2. Design a fracturing procedure based on information and well parameters. 3. Perform a step-rate test and pump-in test to evaluate both the formation and near-wellbore regions. 4. Fracture the first well as it was predesigned. 5. Analyze pressure response during the fracturing procedure and perform pressure matching to obtain fracture parameters such as propped length, propped height, and conductivity. 6. Use the information collected in Step 5 to modify the original design. 7. Continue real-time analysis on each well. Implementing this seven-step process should enable producers to achieve the best possible fracture design.

Corrosion of injection equipment is a common problem in CO2 miscible injection operations. The two basic mechanisms by which this corrosion occurs are from internal corrosion caused by holidays in the injection tubing coating as well as from external corrosion caused by CO2 invading the tubingcasing annulus through minute seepages in the downhole injection equipment. Unfortunately, these problems are both common and costly. In one West Texas CO2 injection project, Unocal Corporation, using state-of-the-art connection and testing procedures has developed a method of installing downhole CO2 injection equipment which virtually eliminates this tubing-casing communication. In addition, the internal plastic coating of the tubulars remains intact and holiday-free during field handling procedures. The system involves the use of a helium connection test combined with meticulous attention to detail in the field handling and connection of the tubulars. The following is a discussion of the development and implementation of these procedures.

TEXACO U.S.A. has successfully installed an automation system which provides distributed remote control and monitoring of the entire array of producing operations at the Wharton and Robertson Waterflood Units in Gaines County, Texas. A preliminary economic analysis of the project indicates that the benefits attained have exceeded expectations. Microprocessor based Remote Terminal Units (RTU's) are used to detect and report alarm conditions and operating data to a Master Terminal Unit (MTU) located in a field office on the Wharton Unit. RTU's have been eveloped to provide the following functions: 1.) Control beam pumped wells. 2.) Monitor variable speed driven electric submersible
pumped wells. 3.) Monitor and control individual injection wells. 4.) Perform automatic well testing and monitor the operation
of the production satellites. 5.) Monitor the operations at the tank batteries. 6.) Monitor and control the water injection plants.

A liner is probably the most critical string of pipe set in a well. One of the most common problems encountered in liner cementing is the migration of gas in the annulus during the cementing operation. This can lead to a leaky liner top and a subsequent remedial squeeze job. By using proper cementing techniques and materials, including mud removal procedures, gas migration can be minimized and the need to squeeze liner tops can be reduced. Recently, several liners were set in wells in Lea County, New Mexico, in which different drilling conditions and problems were encountered (Table I). This paper presents case histories of these wells and the cementing techniques and systems used to combat these problems.

Sand, Iron Sulfide, Frac Sand, and other particulates produced with the fluid often cause sucker rod pumping problems that shorten sucker rod pump runs to unacceptable times, or actually prevent successful use of sucker rod pumping. Common sense methods of successfully dealing with these particulate problems will be covered as will developments in sucker rod pumps for successful particulate production.

When dealing with cementing operations with problematic formation issues, achieving satisfactory top of cement (TOC) is essential. A central Texas operator encountered zonal isolation challenges that resulted in inadequate TOCs. One of those challenges was achieving a density both above the pore pressure and below the fracture gradient. In some wells, this density window was as narrow as 0.02 to 0.04 psi/ft. Karsts and tectonic-fractured formations exist in this field, which often result in uncovered zones and TOCs at unacceptable levels. Formations such as these, with heavy erosion and cave-related brecciation, can have huge voids at volumes that are nearly impossible to measure. To meet regulatory requirements and achieve successful zonal isolation, competent cement sheaths are necessary. Initially, expensive cement-squeeze applications evolved as the zonal isolation effort was initiated in these trouble wells. However, it was decided to use a conformance product to allow the cement column to exist at a high enough level to be deemed a successful solution without the aid of the squeeze application. This
paper presents a case history of several central Texas wells in which satisfactory TOC was difficult to achieve. The challenge was to get cement high enough to meet regulatory requirements, without having to perform a squeeze job. The wells discussed exist in an environment with washed out formations occurring in a narrow window of design density. The design criteria involved overcoming these washed out regions that consume cement volume. The service company provided a solution of using a conformance product to achieve adequate TOC without the aid of a squeeze application. This paper compares several wells before and after using this water super-absorbent polymer procedure, demonstrating an improved percentage of adequate TOCs and significant cost savings to the operator.

Sucker rod connection failures seem to be a problem to some operators, while others do not seem to have the same problems. The connection should be the strongest link in the sucker rod string while the rod body should see more failures. There are three main classifications for the connection failures. These are: manufacturing discontinuities or defects, mechanical damage (including handling and make-up procedures), and loss of displacement (LOD). This paper will: discuss the API industry connection, discuss the three failure classification areas, and provide many
example pictures of the failure causes Additionally, recommendations will be provided on how to prevent future connection failures.

Sucker rod coupling friction values are used by rod design software to calculate rod loads for bare steel tubing on steel couplings. The friction values for sucker rod couplings on HDPE lined tubing are not yet known or defined. Therefore, rod load calculations in HDPE lined tubing are problematic. Tests were performed to compare the coupling friction in HDPE lined tubing compared to bare steel tubing at various temperatures and side loads. The objective was to find the drag ratio of rod couplings on HDPE lined tubing to that of bare steel tubing at various temperatures. The data was used to develop an equation to calculate the drag in HDPE lined tubing compared to that of bare steel tubing as a function of temperature. Although not quantitatively analyzed in this study, a side load capacity difference between HDPE lined and bare tubing was also observed

After consideration of all component parts in a sucker rod pumping installation, it is believed that the sucker rod string most directly affects the action and performance of the entire system. Sucker rod behavior, in transferring the forces and loads that are involved, determines the action of the subsurface pump. The load imposed on the surface equipment are attributed directly to the inherent characteristics of the sucker rods. The allowable stresses , range of loads imposed and speed of operation, which a sucker rod string can withstand without excessively frequent breakage, limit the economic depth and capacity of an installation.

It is important to know the cause of sucker rod failures so that the cause can be eliminated or guarded against. This paper presents numerous illustrations of the most common forms of sucker rod failures and explains the cause of these failures. Corrosion is the greatest cause of sucker rod failure and the bulk of the illustrations are of sucker rods that have been damaged by corrosion. A brief description of the basic corrosion process is included.

The most common type of sucker rod failures (pin failures) can be reduced by application of load range effects. This paper introduces a simple graph which can be used as a guide to limit peak loads based on load range for increased sucker rod service life.

There are very few papers that present the actual fatigue data for various grades of sucker rods from a variety of manufactures. This paper will provide information on the testing being conducted by one sucker rod manufacturer and the performance of high strength API D grade rods versus non-API extra high strength rods for air fatigue in rotary bending tests. Additionally, information will be provided on the relevance of these results and on the next phases of fatigue testing that is being planned.

This paper discusses the history of rod guides, early attempts in their development, types of guides presently available, a study of the proper use of guides, and a recommended procedure for placement of guides.

This presentation will provide a review of published information where sucker rod lift has been used to produce highly deviated and horizontal wells. Additionally, some useful recommended practices from equipment suppliers will be included on design, selection, and changes to consider for rod lift equipment when used to produce horizontal versus vertical wells.

Most sucker rod pin and coupling failures are considered to be related to loose couplings. Correct pin prestress offers the best way to prevent loose couplings and the "circumferential displacement" method offers the best way to achieve correct pin pre-stress.

This paper discusses the many types of balls and seats that the industry has to offer for varied well conditions, and also explains the proper use of plungers, barrels, tubes, cages, and other accessories. Pump parts destroyed by corrosion and abrasion are displayed, as well as sample pumps constructed to resist such attack.

Presentation will cover care and handling best practices for a sucker rod pump from the pump shop to the well bore and introduce a new tool for safely lifting a sucker rod pump from horizontal to vertical at the well head. For years, long and heavy insert pumps have been lifted into the vertical position to be run into the well by various means, some causing damage to the pump and contributing to failures. In most cases this process places undo stress on the rig crew, as they have to support the entire weight of the pump while it is lifted and it places them under a suspended load. These safety concerns can be reduced with the use of this tool and recommended procedures.

One of the principal causes of subsurface failures is corrosion. Corrosivity of well fluids is primarily related to hydrogen sulfide and/or carbon dioxide gases in the produced water. Optimum utilization of corrosive-resistant materials for component parts of sucker rod pumps has been the more economical practice in Exxon's operation as compared with the use of corrosion inhibitors and less expensive metals. Past performance of pump part metals was studied to provide guidelines in upgrading the pump part metallurgy. Using a computerized data bank, over 8,000 pump runs were analyzed from 26 major folds within the West Texas and Oklahoma areas, most of which contained hydrogen sulfide in the produced fluid. General guidelines for pump part metals selection were established. The study indicated that average pump part service of at least I2 months should be expected with proper metallurgy selection.

Sucker Rod pumping as it is used in today's oil field, evolved from the waterwell wooden sucker. Early history includes rope used for lifting water in irrigation systems. Increasing rod string performance lift through manufacturing quality control, proper string design, correct handling and control of environment.

For more than ten years the Petroleum Industry has used and benefited from a Reliability Information and Failure Tracking System for electrical submersible pumping (ESP-RIFTS). More recently another RIFTS system for progressing cavity pumping (PCP-RIFTS) has proven to be beneficial to participating members. At the 2010 Sucker Rod Pumping Workshop, discussion started about developing a RIFTS project for sucker rod pumping. This is now about to become a reality. The RIFTS systems collect and store information on pumping systems and system failures. This information is tracked to discover different types of failures and failure mechanisms. Companies that are members of the RIFTS Joint Industry Project (JIP) can search this information to determine which system components work best in differing conditions. They can determine which metallurgies or system suppliers are more effective in specific situations. They can benchmark their equipment and processes vs. others.
Participation in the JIP's created for the development of ESP-RIFTS and PCP-RIFTS has been limited to Operating Companies. However, for the Sucker Rod Pumping

Reduction of preventable problems inherent in beam pumping systems can be achieved by continuous monitoring of system loads with electronic equipment and software systems developed by Delta-X Corporation. Electronic monitoring equipment was developed for permanent installation on electric prime mover driven beam pumping units. This equipment provides instantaneous polish rod load versus stroke position data. The equipment's self-monitoring mode allows the pumpoff controller (DXI-30) to interpret polish rod load versus displacement and make a logic decision to shut the well down for a predetermined time when a pumped-off condition is detected. Rod parts and other major downhole problems are also detected and result in setting of an alarm and shutting down the unit until visually inspected and manually restarted. Interfacing capacity is designed into the system to allow plotting load versus position data with a dynamometer or the storing of such data, for later retrieval, in an electronic memory card. These data may be later recalled, using a computer program, to recreate a dynamometer card shape, calculate gearbox torque, and/or a downhole pump card. Introduction of the new DXI-40 microprocessor controller with a communication system allows remote access to all load data. System control can also be effected from a remote location.

QRod is the most widely used program for the design and prediction of the performance of Sucker Rod Beam Pumping Installations. A damped wave equation solution is used to accurately predict the surface dynamometer loads, gearbox torque and pump capacity, with a minimum amount of input. New design tools have been added to include: 1) Slippage Calculator from pump clearances ties the pump efficiency to the predicted pump displacement. 2) Sinker Bar length calculator determines the sinker bar length as pump diameter or pump depth chances. 3) Results can be shown in any system of units. 4) Dynamometer measured surface DYN files can be imported and plotted on top of the predicted dynamometer card. QRod's objective is to help the beam pumping system designer implement state of the art design technology without getting buried with details. Changing a parameter such as tubing anchor, stroke length, stroke rate, or pump diameter is immediately seen in the dynamically updated plots.