The San Andres formation in the North Permian Basin in West Te.xas typically requires stimulation to be economically productive. Acid fracs are effective at increasing production but require frequent repetition due to steep declines. In the past, a comparatively small number of wells were sand-fraced and had limited success. The nature and degree of stresses in and bounding the productive zone typically result in frac treatments growing vertically into high mobility water zones. Techniques such as plugging back existing perforations and controlled fluid viscosity and pump rates combined with DataFR4Cs allowed the 35 wells covered in this paper to be fraced with controlled dimensions. This prevented the fracs from growing into adjacent water zones. The subject wells which were sand-faced since 1993 increased from an average production rate of 12.7 bopd to 35 bopd with an average 28.8% decline. The average water production increased from 25 to 50 bwpd which represents only a 2-fold increase in water compared to a 3-fold increase in oil production.

The use of rod guides in artificial lift applications has evolved to a level where accurate simulation of downhole conditions is necessary to evaluate various materials. K&M Energy Systems has designed and built a second generation plastic wear test machine that conducts tests in a heated fluid environment. A state-of-the-art data acquisition system collects all pertinent information. A standard procedure for establishing wear rates is proposed to enable end-users to compare wear characteristics of rod guide plastics in simulated downhole conditions.

LNS is simply natural gas condensed by refrigeration to a liquid -260 degrees F, a super cold or cryogenic liquid. As long as it is kept cold, it can be stored or transported like any other liquid. It is clear, colorless, odorless - in appearance not unlike club soda. Its density is about half that of gasoline and upon combustion it provides about half as much energy as gasoline. Godfrey L. Cabot, founder of the parent corporation of Distrigas, saw the advantages of liquefying natural gas for transportation as a liquid to areas not served by pipelines and he obtained a patent from the U.S. Patent Office in 1915. However, it was many years before Dr. Cabot's idea became commercially significant. The development of the LNG industry took two distinct paths: one in the United States as a peak having gas supply and the other in Europe and Japan as a baseload gas supply. Let's look at the history and see what these terms mean.

Issue management is a process everyone engages in everyday. You may not think of it as issue management but consider it problem solving or crisis management. Issue management, as discussed in this paper, is the process used to identify, analyze, evaluate, and act on regulations, legislation, public concerns, actions by others, and decisions that affect all aspects of your business. The process may be accomplished as "part of the job" or it may be a specific, deliberate action. Issue management is not limited to oil and gas operators. It is important for all oil and gas entities including service companies, independent contractors and processing facilities. Issue management is extremely important to business because internal and external actions affect the manner in which business conducts its activities, from day-to-day operations to long-range planning. Specific choices must also be made by each company as to whether it will take a proactive or reactive role in dealing with outside influences and challenges. Issue management, or the lack thereof, is an economic decision. It affects daily operations and profitability. How you choose to be involved in the issue management process will impact the effectiveness of your participation. Are you proactive or reactive? In general, most companies and their managers and employees react to arising issues that could affect how they operate. With respect to the oil and gas industry, proactive issue management has historically been left to major oil and gas companies with staffs dedicated to the process or independents that have chosen to be more involved. Many companies who are not directly involved in managing important issues affecting their business rely upon those in industry who are dedicated to preserving reasonable business practices and on the trade associations to represent them and their interests. Those who are uninformed or choose to not be part of the process react to the changes, often not realizing that they could have influenced the outcome.

A discussion of conventional beam pumping units. Factors you should consider before installing a pumping unit on your well. Advantages and disadvantages of air balanced units will be presented.

Every producer longs to get a well which produces by natural flow when he drills his well. The reasons are quite clear: the costs of installation, equipment and operation are considerably less than for any artificial lift method which could be installed. In spite of these obvious advantages, there are few references to be found that concern themselves with the flowing well. The paucity of material is probably due to two causes.

Fifty-six waterflood projects are grouped according to the producing water-oil ratios (WOR) in effect at the start of polymer treatment. A relationship between barrels of polymer oil, amount of polymer and water-oil ratio is developed over a range of WOR's from 1 to 50. Projects singled out for special study include conglomerate, sand, lime and fractured reservoirs. Hall Plots and input profile surveys are used to show injection side changes due to polymer treatment. Oil recovery/WOR curves and time/rate graphs illustrate production side responses. In all cases the polymer treatment was designed to improve volumetric sweep of the reservoir.

You are working on a problem that has been my problem for nearly 40 years

Drilling practices have changed considerably through the years. When rotary drilling first started, drill collars (as we know them today) were unheard of. Bits were not designed for heavy loads and only the weight of the drill pipe with a crossover sub (called a collar) between the drill pipe and bit, supplied the drilling weight. The search for more hydrocarbons required penetration of deeper and harder formations and brought about the development of improved rotary bits with the need for additional weight to make the bit drill. In an effort to put more weight on the bit, additional drill pipe weight was slacked off putting more drill pipe in compression. This resulted in an increased number of drill pipe failures. It was discovered that when drill pipe is run in compression for bit weight, it buckles and is subject to severe bending fatigue resulting in these failures. This is due to the stress reversals in the thin wall of the drill pipe created by rotating the pipe in compression while it is bent. Using this theory another person developed the idea of using heavy thick-walled pipe between the bit and drill pipe to furnish the necessary weight for the bit. These joints of heavy thick-walled pipe were called drill collars, named after the crossover sub that had been used in the same position in the string. Only a few collars were used initially, but the quantity increased rapidly with improved bit design and deeper drilling. Very few problems were encountered when only six to nine drill collars were used; but connection failures increased rapidly with the running of additional collars, because the drill collars buckled under the additional drill collar weight. Drill collars differ from drill pipe in that the highest points of stress are in the connection, due to the tube or body being much stiffer and stronger than the connection. The use of special bottomhole assemblies to centralize the collars and stiffen the connections was unheard of at this time. Initially, not much thought was given to deviation. It was believed that if the kelly were held straight up and down in starting the hole, it would continue straight. No one realized holes were being drilled crooked until the development of the Seminole Field in Oklahoma in about 1928 and 1929. People started to be suspicious when some wells required considerably more footage of casing to complete than others. Since the wells were assumed to be in the same producing horizon, the geologists were confused. It wasn"t until two offset drilling wells actually intersected one another, causing numerous fishing jobs, that people realized that crooked holes were possible. They began to be concerned about the cost of the additional tubing and casing to complete these crooked holes, and deviation from vertical became an important factor in the drilling industry. It was at this time that the acid bottle came into use as a means of measuring the hole inclination from vertical. A bottle of hydrofluoric acid was lowered into the well on a line and allowed to sit long enough for the acid to etch the inside of the bottle. This wasn"t very accurate, but the approximate deviation from vertical could be determined.

Water quality is becoming a larger issue for the producer, as water production increases. Poor water quality in injection water can create plugging and loss of injectivity. It also can result in a loss of revenue due to re-injection of hydrocarbons. This paper will discuss issues of water quality. It will also detail how to develop effective monitoring locations and how to interpret results of water quality tests to determine effective treatment. Examples of actual production data will be provided to illustrate how improving water quality will result in increased revenue to the producer.

The counterbalance problem is one of application, which is caused by the lack of knowledge on the part of the operating personnel as to the importance of proper counterbalance, and/or a program to assure proper application of this counterbalance. Further, the problem and need is present in each beam type sucker rod pumping system. The magnitude of these problems are realized when you consider that in excess of 80% of the world's pumping systems are of the beam type. Eventually, each person concerned with production of oil will be forced by necessity to solve in some manner his individual needs in relation to counterbalance.

In 1998, employees of Exxon (ExxonMobil after November 30, 1999) in partnership with Trout Unlimited, the Wildlife Habitat Council and the Boy Scouts of America, constructed a pond habitat project in western Wyoming. This voluntary environmental project augments efforts by the Wyoming Game and Fish Department to stabilize native Colorado River Cutthroat Trout populations and is comprised of a deep pond that provides trout overwintering and rearing habitat. The project demonstrates responsible corporate environmental performance and will be used to promote balanced environmental education and to foster cooperative relationships with state and federal regulatory agencies. This project reflects the pride and enthusiasm that ExxonMobil employees have for the communities and states where the company does business, and serves as an example of the progress that can be achieved when neighbors join together in a common effort to enhance environment values. The Sawmill Creek Trout Recovery Project received the Oil and Gas Reclamation and Wildlife Stewardship award from the Wyoming Game and Fish Department in September 1999. The project also received recognition in November 1999 from the Wildlife Habitat Council as a Certified Corporate Wildlife Habitat Site.

The purpose of this paper is to answer the ten most asked questions about plunger lift. 1. Do I Have Enough Pressure? 2. Do I Have Enough Gas Volume? 3. Will It Run Under A Packer? 4. Is My Sales Line Pressure Too High? 5. What Is My Operating And Maintenance Cost? 6. How Long Will It Be Effective? 7. Will It Work With Gas Lift? 8. Will It Work In Paraffin? 9. How Much Improvement Can Be Expected? 10. Will I Eventually Need A Pumping Unit? From these ten questions we can identify the areas of interest as Identifying a Candidate, Operating Cost and Economics and will answer the questions in those areas

This paper describes the automation system installed at the ARC0 Permian operated, Willard Unit CO2 flood. The automation includes a Supervisory Control and Data Acquisition (SCADA) system for pump off control, shutdowns and safety/environmental monitoring of over 300 rod pumped and flowing wells. The 24 hour monitoring system along with the data obtained, provides the benefit for identifying potential well problems and quick operator response. The paper also details the customization of the operator interface.

An extensive stimulation program is in progress in the San Andres Formation in the Willard Unit, Wasson Field, Texas. This paper presents some of the problems involved in the design and execution of the hydraulic fracturing operations. The case histories of two of these wells are presented.

This paper presents statistics for remedial stimulation work performed at the Willard Unit since 1986. It also discloses how stimulation candidates are chosen, what stimulation fluids are used at present, and how stimulation work is tracked. The Willard Unit is a San Andres carbon-dioxide flood located in the north-central portion of the Wasson field near Denver City, Texas. The Unit produced under primary from the mid 1930's until the start of water-flood operations in the mid 1960"s. Tertiary operations commenced in 1985 with the injection of carbon dioxide into approximately two thirds of the unit which is comprised of 340 producers and 260 injectors. The San Andres at the Willard Unit is a dolomite found at a depth of about 5100". Gross pay averages 150", porosity averages 8.5%, and permeability averages 1.5 md. The majority of wells are cased to 1 D and perforated with 15 to 20 holes. Producers have been sand fractured, and injectors have been either sand fractured or gelled-acid fractured.

Magnetic Flux density (MFD) technology is a safe and accurate means of locating and monitoring variations within the body wall of tubing and casing products. Older technology utilizing Gamma Radiation to identify these problems is very hazardous, typically produces limited results, and is physically limited to effectively evaluating only 6% to 12% of the total tube body. Improved MFD technology can offer a safe and effective method to evaluate 100% of the tube body for wall loss from corrosion, tool cuts, and sucker rod wear.

The complexity and cost of exploring for oil and gas has increased significantly in the past few years due to Intelligent Wells, Multilaterals and Heavy Oil field developments. New challenges for drilling, completing, producing, intervening in a well, environmental regulations, and wide swings in the price of oil have changed the role of technology in the oil fields. The industry is relying on technology to affect the costs of exploring for hydrocarbons in the following ways: - Reduce operating expenses (OPEX) by automating the processes used to explore and produce hydro - lncrease net present value (NPV) by providing systems that enhance the recovery of hydrocarbons f carbons, reducing the frequency of unplanned intervention, and improving information and knowledge management to decrease operating inefficiencies. From reservoirs. The new technologies improve production techniques to delay and/or reduce the production of water from downhole drilled and that will reduce the number of surface facilities required. The surface equipment requirements to handle increasingly larger quantities of hydrocarbons at these facilities should also decrease with the implementation of new technologies. - Reduce capital expenditures (CAPEX) by creating processes that will decrease the number of wells New processes for drilling, completion, production, artificial lift, and reservoir management have been created by advancements in technology in fields such as high temperature sensory, downhole navigation systems, composite materials, computer processing speed and power, software management, knowledge gathering and processing, communications and power management. Horizontal drilling and new fracture techniques have allowed operators to produce hydrocarbons profitably from areas that were uneconomical just a few years ago. Sensor technology in conjunction with data communications techniques provide on-demand access to the information necessary to optimize hydrocarbon production levels and achieve costs goals. Surface and downhole sensors are changing the way hydrocarbons are produced by optimizing production from downhole, supporting extend the life of artificial lift systems and providing information used to update reservoir and production models. A new technology that combines sensors with wireless telemetry provide the operators with new versatility and capability to place sensors in areas of the wellbore that were prohibitive due to technical difficulties and/or economic justification. The ability to communicate in and out of the wellbore using wireless systems can increase the reliability of the production system and decrease the amount of time required for the installation of the completion hardware in the wellbore. The elimination of cables, clamps, external pressure and temperature sensors, as well as splices on the cable that can fail inside the wellbore provides a significant advantage when attempting to place sensors in wellbores to monitor production or to optimize the pumps used in Artificial Lift applications.

Automation electronics manufacturers have been focusing a great deal of their development efforts on the plunger lift control application during recent years. The objective has been to automate this process

Real time analysis and visualization of the performance of a rod pumped well are achieved using multiple small and
compact wireless sensors that simultaneously transmit acquired data to a digital laptop manager that integrates the
measurements, displays performance graphs and provides advanced tools for analysis and troubleshooting of the
pumping system.
Battery powered wireless sensors for fluid level, pressure and dynamometer data acquisition are easily deployed and
quickly installed on the well. The laptop manager automatically recognizes and commissions the sensors. The user
sets up and controls the acquisition of data which may include multiple sensors that synchronously monitor variables
such as tubing and casing pressures, fluid level and polished rod acceleration/position and load as a function of time.
Elimination of cables and connectors improves the reliability of the hardware and data while speeding up the set-uptear-
down process. The user interface presents a smart instrument rather than a complex application.
Among the many innovations provided by these well performance analysis tools stand out the real time visualization
of the operation and fluid distribution in the down-hole pump, the simultaneous display of quantitative surface and
pump dynamometer graphs in conjunction with fluid level and wellbore pressures. Acquired data, wellbore
description and pumping system characteristics are saved as a historical data base creating a continuum of the well's
information and performance for direct comparison and detailed analysis.
The paper describes the hardware and user interface, the procedures for installation and acquisition and several
examples of field data and well performance analyses for a variety of rod pumping installations.

Development of the REDA PC progressing cavity electric submersible pumping system began in 1991. The primary driving force behind this product development was the problem of accelerated wear of sucker rods and production tubing in deviated and horizontal wells when using surface driven progressing cavity pump systems. Many producers were replacing sucker rod and production tubing strings multiple times per year. This was severely affecting the economic viability of the oil wells. Since May 1994, REDA PC units have been installed in over 60 oilwells. The main cause of pulling the pumping system has been pump life. The harsh downhole conditions reduce the pump"s, ability to produce fluid while the REDA PC drive system is normally unaffected. As a result, a customer requested that a system be designed that would allow the pump to be pulled and replaced while leaving the bottom drive system undisturbed. This paper will describe the tubing deployed REDA PC system and explain the wireline retrievable configuration, the in-well testing to date, and the future developments for the system.

The "Wolfberry" play is named after the two main productive formations, the low-permeability Wolfcamp and Spraberry, and is a very large part of the everyday business in the Permian Basin. Activity in the Wolfberry has recently increased, spurred by the current relatively strong oil prices. However, the economic foundation of these producing wells is their stimulation and the management of completion costs. All of these wells require multistage fracture treatments to achieve economic production and therefore significant effort has been given to continuous improvement in efficiently completing and fracturing Wolfberry wells. To illustrate the evolution of the optimization process, a retrospective of the changes implemented in fracturing Wolfberry wells over the past 10 years in several counties in the Permian Basin is presented. This paper addresses in particular, choices involved in optimizing stimulation stages (including perforation schemes), treatment fluids and proppants, to maximize net present value contribution of the hydraulic fracturing treatments.

One of the most common problems encountered in designing a stimulation treatment is a low working pressure rating of surface equipment. Quite often, tubular goods are capable of much higher working pressures than the wellhead equipment, and the primary limit of pressure and injection rate is above ground. Breakdown and "Ball Out" treatments are often restricted by low working pressure ratings when the maximum allowable pressure at the pump is less than the pressure required to inject fluid into new or fluid-damaged perforations. Even though high pressures may be required for only a few minutes, it is vital to successful completion of a well that each perforation or zone be opened. Pressure limitations can be especially critical since the fracture area developed and proppant transport are direct functions of injection rate. When the pressure limiting component of a well system is above ground it can usually be "upgraded" safely and reliably by one of these methods: 1. Isolating the wellhead from treating pressure 2. Substitution of a "Treating Tree" for the production Christmas tree 3. Special landing joints or "Top Out Joints" for working through blow out preventers or wellhead assemblies where conventional trees have not been installed. Each of these methods has its strong and weak points and warrants detailed examination.

Almost everyone connected with the oil and gas business will, at one time or another, be faced with rules and regulations governing oil and gas operations. The purpose of this paper is to present a generalized concept of some of the laws adopted by the various regulatory agencies in Texas and New Mexico. To completely encompass all rules and regulations in effect in the space and time allotted would be impossible. But, by supplementing the information contained in this paper with the reader's own knowledge and that available from other sources, one may gain a broader perspective of this particular phase of the oil and gas industry as well as a more complete understanding of the workings of the regulatory bodies.

Continuous coil tubing has become a viable alternative to the conventional workover method of injection well cleanout. With the increase in the wellhead price of oil, a greater emphasis is placed on the efficiency of in-place waterfloods. When an injection well within a flood becomes plugged, the method by which the well is monitored should indicate if there is a problem. Based on that indication and all available relevant data, a decision can be made as to the kind of problem which has developed and likely methods of correcting that problem. The use of coil tubing in many cleanout procedures is a cost- and time saving method. The circulation method is accomplished without the need of moving or disconnecting any part of the injection string. The wells do not have to be backflowed and stimulation jobs can be done with minimum exposure of the injection string to the corrosive effects of acid. A treatment technique can be designed to correct or counteract problems within the injection profile on a point-to-point basis.