Inverted emulsion (water in oil) muds have long been used for formation protection and improvement of hole stability, but slow penetration rates often offset advantages. Recently, relaxation of control of mud properties-notably fluid loss-has led to significant improvement in penetration rate. A comparison of weIls drilled in the Delaware Basin shows that significant savings in total well cost can be obtained through the use of new generation invert muds.

A magnetic bailer has been designed to capture and remove metallic compounds that gather in the wellbore and downhole operating equipment such as an ESP unit. The tool can be used as a standalone, as the part of the tubing, or can be set in the tubing as a joint that stands on Y-tool. The tool can be installed above or below the ESP unit. It can be wireline or coil tubing operated. It is, a cost effective and convenient physical way of cleaning the well. It can save significant well shut-in times that are otherwise unavoidable due to pump failure. Many producing formations produce metal compounds along with oil, gas and water. These metal compounds often are iron-associated compounds, heavy and usually settle in the wellbore. Often iron compounds combine with hydrogen sulfide (H2S) and sulfur dioxide (SO), usually present in natural gas, to form iron sulfide in the wellbore. Iron sulfide is a very hard material (SG 5.1 +). It is not malleable and has crystalline and abrasive structures. When iron sulfide enters an ESP unit, it damages the impellers, diffusers, and shaft, thereby reducing the pump run time and causing premature pump failure. Most of the time, it juggles in the fluid that is being pumped and falls back when the pump stops. It is not carried to the surface due to its high specific gravity, it instead sticks to the tubing walls above the pump, and most of the time in the first tubing joint, and with time completely plugs the tubing. Chemical treatment is usually not effective since the inhibitor is pumped out of the well. In this paper the physical properties of iron compounds in general and iron sulfide in particular, along with common contaminant compounds found in crude oil and natural gas and problems associated with iron compounds and associated scale are investigated. Second, the first indications of their presence and the unusual solids in the pump are addressed, and finally the tool design is discussed in detail.

Iron control studies over the last 30 years have dealt primarily with iron control in acidizing operations. In fracturing operations, iron control has received much less consideration. Certain hydrocarbon producing zones contain iron compounds in both the rock composition and formation water. Fluids used in fracturing operations may be incompatible with the formation water or rock itself, if iron is present in them. Special consideration should be given to the design of fracturing fluids and fracturing techniques so that iron problems will be minimized. This paper presents: (1) data and treating information on 3 formations (Clinton Sandstone in Ohio, Granite Wash in Oklahoma, Limy Sand in Texas) that contain iron in the formation rock and formation water and were treated with an iron control fracturing procedure. (2) the new iron control fracturing procedure that helps maintain iron in solution and helps provide compatibility of the fracturing fluids with the formation. (3) treating techniques to control iron problems and (4) field results from jobs that utilized the modified fracturing fluid and procedure. Sharp production decline curves have plagued operations in the formations listed. The Clinton Sandstone, Granite Wash, and Limy Sand formations have responded well to fracturing treatments; however, in many instances the production increases have not been sustained as long as desired. Iron, a constituent of the reservoir rock, may well be a primary factor in this problem. Utilization of iron control additives and treating techniques as applied to the formations encountered in Pennsylvania, Michigan, Illinois, Indiana, Kentucky, West Virginia, Tennessee, Alabama, Texas, and Oklahoma should be considered for improving cleanup operations, production stimulation and rate of production decline in the same or similar formations in other areas.

Sludging is an ever present problem in the Permian Basin. Recent studies have shown the influence of iron by-products on the sludging process. Questions have emerged concerning effects of CO2 introduction into the overall reaction. An operator concerned with this over-all process began a study to determine the influence of CO2 on the over-all system. The results of this study involving a San Andres CO2 pilot program are evaluated. Included are compatibility testing of produced oil, produced water and acid systems. Testing was conducted with and without iron injected into the system. A representative cross-section of the field lease crude and produced water was utilized. Considerations for future CO2 flood testing are discussed.

The precipitation of iron compounds following well treatment is a common problem in most areas of Texas and New Mexico. This insoluble gelatinous precipitate is both an effective plugging agent and an emulsion stabilizing agent. Either condition damages permeability and greatly restricts production of oil and gas. In order to effectively deal with the problem, the chemistry and physical characteristics of iron as an ion and its subsequent reactions must be understood. Sources of iron, well conditions, types of iron control agents and their properties will be discussed and evaluated.

Productivity, safety, and health are major concerns for companies attempting to maximize profit and provide safe, healthy work environments. Human performance declines when people receive less than optimal sleep. As performance declines, the risk for accidents and health problems increase. Long hours of work, especially for a week or longer generally lead to increased sleep debt, reduced performance and increased risk of accidents and health problems. Costs increase as performance declines and risks increase. These changes in human factors associated with sleep management can be especially troublesome for companies attempting Six-Sigma quality standards. A web-based tool, SLEEP Model, has been developed that allows people to input sleep time and duration, caffeine and alcohol use, and age to evaluate performance and various risk factors, including increased accident and health risks. The presentation will demo SLEEP Model and will illustrate the numeric value of wise sleep management.

A dynamometer pump card is a plot of the calculated pump loads and pump plunger positions during one complete stroke of the pumping unit. The plot is used to analyze pump performance. The pump card is normally calculated from measured surface polished rod load and position data. Different methods are used to display and plot so-called "Pump Cards". Sometimes the so-called pump card is actually a plot of sucker rod load and position, or maybe a sinker bar located above the pump. Several advantages exist for plotting the pump card as the load that the pump plunger applies to the sucker rod. First and foremost, the pump plunger card is easier to interpret and shows more mechanical and reservoir information. Visual estimates (high, medium and low) of the pump intake pressure are obvious from the pump card. Also, the zero load line on the pump plunger card indicates the quality and accuracy of the surface load and position measurements and computations. Examples are shown of the pump plunger card, interpretation of the pump plunger card and also plots of loads in nearby sucker rods and sinker bars that are sometime called pump cards. This paper recommends having the "Pump Card" represent the loads that the pump plunger applies to the sucker rod string and not represent loads in some nearby rod in the sucker rod string.

In response to customer needs, Smith Lift has developed a 1 3/4 in hydraulically driven diaphragm pump that allows the operator to insert and pull the pump without pulling the production tubing. The Hydraulic Diaphragm Insertable (HDI) pump is driven by a surface hydraulic power unit, which actuates a hydraulic cylinder down hole creating positive displacement pumping action, similar to a rod pump. The HDI pump can be installed with or without seating nipples in standard 2 3/8 in (or larger) production tubing. This paper will discuss the operation and deployment of the HDI pump along with initial results from preliminary testing including solid handling, electrical efficiency, pull and run economics, and low volume/deep pump performance.

Loving County, Texas has seen increased activity with current gas prices. Wells are drilled to depths of more than 18,000 feet. Reservoir pressures are as high as 16,000 psi with bottomhole temperatures up to 260_ F. Production has ranged 250 MCFD to 30 MMCFD. Multiple stage Frac jobs, usually 4 or 5 stages, is typically utilized. Each zone is perforated and stimulated using composite bridge plugs (CBP) to isolate each zone. After the all the zones of interest are fractured, high pressure coiled tubing is used to clean out bauxite and mill up the CBPs. This paper will explore how a unique process was used to successfully remove bauxite with 1.75" (OD) HP Coiled Tubing inside of 15,554" of 6.56" (ID) casing. Challenges included fluid selection, annular velocities and limited flow rates through the coiled tubing. The design and execution of this process will be discussed.

This paper will address how coiled tubing, combined with advanced acidizing technologies, can improve the ability to optimize treatment coverage in openhole completions. Two methods that have been very successful in the Permian and Anadarko Basins are foam and self-diverting acid systems. When acid is pumped into an openhole completion, it is difficult to determine precisely where the acid is going. It is vitally important to ensure that the entire interval is being treated adequately to optimize production. Coiled tubing and advanced acidizing technologies have shown tremendous promise with these stimulation techniques. This paper will also discuss the many techniques that have been attempted throughout the years with mixed results.

From September 1970 to May 1971, prototype jet pumps were installed in five wells in California, West Texas and New Mexico. These five wells were selected to give a wide variation in operating conditions and were used primarily for correlating actual field data with laboratory data and with computer calculated operating charts. During this nine-month period, the cavitation zone of the operating charts was defined and various materials were tested for the nozzle and for the throat of the pump. Three of the test wells used water and two used oil for the power fluid. Depths ranged from 1900 ft to 9500 ft and production ranged from 80 BFPD to 1000 BFPD. In May of 1971, after the jet pump was established as a viable deep well pump, it was formally announced and introduced at the International Petroleum Exposition in Tulsa. By November 1972, 18 months later, approximately 125 jet pumps were operating in the U.S. and abroad. In addition to these 125, another 50 had been installed and later removed-removed because of pumped-off conditions, insufficient surface horsepower, too much gas being produced through the pump or abandonment of the wells. All of these 50 pumps were installed in wells already pumping with hydraulic piston pumps, and as might be expected, most of these piston pumps were the ones experiencing the highest operating expense. But because the jet pump can be made to fit any "Free Pump" bottomhole assembly and because the surface power was already installed, these were convenient wells for operators wishing to try the jet pump. Many of the 125 operating jet pumps were also installed in wells already equipped with hydraulic piston pumps, and they have survived because they have reduced repair costs. Obviously, the jet pump is the simplest pump made for oil wells and its design allows it to tolerate poor quality power fluid, corrosive well fluids and free gas-conditions that lead to high repair costs for positive displacement pumps. Figure 1 shows the producing rates and setting depths of 100 jet pumps operating December 1, 1972. Approximately half of the dots on this chart represent wells in the Permian Basin and the cluster at 9300 ft are wells in Lea County, New Mexico. This chart illustrates the broad application of jet pumping-depths from 1550 ft to 14,750 ft and producing rates from 20 BPD to 1400 BPD. Two pumps not shown on the chart are set at 4500 ft and produce 2700 BPD and 3000 BPD. In Fig. 2 the principal parts-nozzle, throat and diffuser-of the pump are shown. Power fluid (water or oil) at high pressure is supplied to the nozzle which converts the pressure head to a high velocity jet. Pumping action begins when the fluid in the production inlet chamber is entrained by the jet stream emerging from the nozzle. In the throat, the produced fluid acquires high velocity from the power fluid and in the diffuser this velocity head is reconverted to a pressure head-pressure sufficient to move the fluid to the surface. The arrangement of one string of tubing set on a packer in the casing, as in Fig. 2, is called the casing free type system and is the most common type of system used. The parallel type of system shown in Fig. 3 can be used in wells with high gas/liquid ratios, to allow gas to vent through the casing instead of going through the pump.

This paper presents a method of directly calculating an optimum jet pump geometry for a set of specified conditions. It reviews jet pump theory to the extent necessary for explaining the sizing technique. The method uses a design performance curve which is a composite of the family of performance curves for the pump. An exact nozzle area is calculated and an area ratio selected, based on the design curve. This data is then used to select an off the shelf geometry from a manufacturer. The calculation sequence is presented along with an example set of calculations which follow that sequence.

Roller cone bits have long dominated the drilling in the Spraberry field of West Texas. Experience and/or drilling log information have indicated that the formation is typically drilled with an insert type roller cone bit. Conical type insert bits are usually chosen because of the durability of their cutting structure. Typical intervals are from the surface casing to 9000 ft. The formations are usually drilled with two to three insert bits. Conical type insert bits, IADC 527 and 537, are usually chosen because of the durability of their cutting structure in drilling interbedded shale and limestone. Development and applications of a new type of fixed cutter bit, which is able to drill very efficiently through interbedded formations, incorporates new cutter technology with enhanced drillability, durability, and reduced vibration. Trials show an increase in penetration rates compared to the best roller cone run in the field.

This paper will discuss how to choose a communications system for your Scada system, in depth discussion of different technologies and how to combine technologies myths and legends that surround communications systems, and how to tell the truth from the myth. What are the key critical success factors to installing a reliable Scada communication system?

Downhole gas separators are often the most inefficient part of a sucker rod pump system. This paper presents laboratory data on the performance of 5 different gas separator designs. Continuous flow and intermittent flow were studied. Field data is presented on one of the designs. The field data indicates that success or failure of the gas separator is dependent upon the fluids and wellbore pressures as well as the mechanical design of the gas separator. Successful and unsuccessful examples of gas separator performance in the field are shown along with field fluid data properties. Videos will be shown at the presentation of the continuous and intermittent flow of water and air through the transparent gas separators placed in transparent casing

It has been reported in the literature that the presence of soluble iron significantly increases the minimum inhibitor level for effective control of calcium carbonate and calcium sulfate scales. When confronted with developing a scale inhibitor for application in water containing 500 milligrams per liter soluble iron, the prospects of finding a scale inhibitor were daunting. Because the produced water was near saturation, compatibility of the scale inhibitor was of concern. Also, it was required that the scale inhibitor should be compatible with any corrosion inhibitor, biocide, coagulants, polyelectrolytes, scavengers, etc., which could be present in the system. Presented are the details of the laboratory investigation leading to the development of two scale inhibitors for calcium sulfate. Included are both the mechanical and chemical evaluations. Also, a case history successfully utilizing one of the inhibitors is discussed.

Many oil and gas producing reservoirs produce brine water, which is near or at saturation with respect to sodium chloride salt. During the process of producing these fluids, salt crystals form and grow to the point that a "salt block" is formed in the well and/or flowline. The mechanisms of this salt block formation vary, but most often it is due to one of two scenarios. (1) Temperature reduction of the fluids as they are transported from the reservoir to the surface. Such cooling decreases the capacity of the water to retain the salt in solution and thereby precipitation of the salt occurs. (2) In the case of gas production, the brine produced is striped of its water by the gas stream, concentrating the brine solution in the wellbore. This paper will describe laboratory testing, field application methods and case history results of the application of salt inhibiting treatments in several applications.

The cementing design process has been improved by utilizing up-to-date technology to predict actual down-hole conditions, allowing both the service company and the operator to manage fluid positions, critical circulating pressures and surface parameters while cementing under stringent conditions. This paper will explain how design data and Real Time Simulation can be utilized in making detailed predictions of many well parameters and make real-time adjustments during the operation to alter the outcome of the job. These tools can allow the operator and service provider to more accurately predict cement tops, change casing programs, control flow-back rates and pressures, monitor equivalent circulating density (ECD) on specific zones, or just prepare a better design for the next well in the field.

The Geared Centrifugal Pump (GCP) is a high volume artificial lift system consisting of a progressive cavity pump style rotating rod string driving a bottom intake ESP style multi-stage centrifugal pump via a downhole speed increasing transmission.

An operator was experiencing a fast decline in hydrocarbon production in one of their Clearfork Formation CO2 WAG flood patterns due to fracture communications between injectors and offset producers near Littlefield, Texas. In identified wells giving very poor sweep performance, injected Carbon Dioxide (CO2) freely communicated and broke through into offset producers. Following performing diagnostics to determine the extent and magnitude of the existing problem, designs and simulation analysis were developed on an identified well displaying a dominant fracture communication. A foamed Pozzolan slurry squeeze treatment was performed and monitored for purposes of drastically reducing if not completely eliminating the major injected flow entry in the well's open-hole interval and communicating via the reservoir to the offset producer. Elimination and or reduction in CO2 cycling through this eroded communicating fracture conduit has significantly benefited the sweep on hydrocarbon and improved the economics in this section of the WAG Unit.

More and more directional wells are being drilled to maximize hydrocarbon recovery and overcome environmental restriction. Today's state of art predictive software for rod pumping can be used to design and optimize rod pumping in deviated wells as well as vertical wells. Previously, traditional methods including wave equation techniques assume that the wellbore is vertical. Applying these methods to rod pumping in deviated wells will result in substantial errors and cause inappropriate design. The new technique considers a deviation survey for the 3-D borehole trajectory and rod/tubing drag in the predictive design method. The paper examines a real case for a severely deviated well by using the new software, showing best practices, sensitivity analysis and optimization.

Wells used for gas production can present many problems for ESP systems. Extended duration gas slugs can cause pumps to lose prime and cycle on and off. This paper deals with one lease holder's attempts to produce gas with an ESP system in place. New Dominion has wells with gas slugs lasting one to three minutes and longer. Working with a manufacturer, a solution was developed that (when properly sized) can balance the well and allow production of gas without constant system shutdowns. This paper examines two case histories involving inverted shrouds as long as 450". While producing as little as 900BWPD, output rose to 600MCFD of gas before leveling off at 400MCFD. This information will be beneficial to anyone wishing to use ESPs who is having problems with gas slugs in vertical or horizontal applications.

At the 50th Annual Southwestern Short Course in 2003, a paper was presented titled "New Design API Modified Sucker Rod Connection and Methods and Systems for Precise Sucker Rod Connection Makeup". This paper is an information update of continuing development and field applications of the four part api modified connection system in pcp and beam pumping wells. The paper also includes a study of in-plant single end coupling makeups on the three part standard api couplings employing the "precision coupling makeup system" where volumes of used inspected api number one class sucker rods of all sizes and grades were returned to field service. The study also contains an analysis of the mechanical and economical benefits of receiving the rods at the rig site with the couplings properly made up on one end and performing a single end makeup with the rod tongs at the workover rig, as opposed to the standard practice of the "floating coupling" or double end connection makeup.

The objective of this paper is to review applications of horizontal wells, discuss their successes and failures, and summarize the key parameters for economic success. Horizontal wells have been used in 1) thin payzones, 2) naturally fractured reservoirs, 3) formations with gas and/or water coning problems, 4) gas reservoirs and 5) EOR applications. Based upon field results, the paper summarizes the following key parameters for economic success: 1) fracture intensity and direction, 2) hydrocarbon payzone thickness, 3) well spacing, 4) areal anisotropy, 5) vertical permeability, 6) formation damage and post drilling clean-up, 7) necessity of multi-well prospect and, 8) geological control. This paper includes discussions on these parameters. Also, whenever possible, pertinent field histories are presented. Available field results indicate that the success rate of horizontal wells in reducing water coning is much higher than in reducing gas coning, especially in low permeability reservoirs.

The objective of this paper is to review applications of horizontal wells, discuss their successes and failures, and summarize the key parameters for economic success. Horizontal wells have been used in 1) thin payzones, 2) naturally fractured reservoirs, 3) formations with gas and/or water coning problems, 4) gas reservoirs and 5) EOR applications. Based upon field results, the paper summarizes the following key parameters for economic success: 1) fracture intensity and direction, 2) hydrocarbon payzone thickness, 3) well spacing, 4) areal anisotropy, 5) vertical permeability, 6) formation damage and post drilling clean-up, 7) necessity of multiwell prospect and, 8) geological control. This paper includes discussions on these parameters. Also, whenever possible, pertinent field histories are presented. Available field results indicate that the success rate of horizontal wells in reducing water coning is much higher than in reducing gas coning, especially in low permeability reservoirs.