Operators have stimulated and produced from the Yates and Queen formations in Ward and Winkler counties for 38 years. The field was discovered in 1968 and has been explored, developed, bought and sold for several cycles. Each operator developed the field to different degrees. The paper will is a part one of what has been done in the past and what is being done currently. Technology used will be included. This encompasses new or improved additives and engineering modeling tools used today by the service company to optimize production. Part two will come when we can make judgment changes to an already good design and have ample time to collect production data to see if production can be impacted for an improved return on investment.

This paper describes the use of electrical submersible pumping systems (ESP"s) with portable variable frequency drives (VFD"s) to perform step-rate testing on multi lateral horizontal producing oil wells in the 4 - Corners area of New Mexico, Colorado, Utah, and Arizona. A major Operator drilled and completed several of these multi lateral wells in the area. High volume ESP's were installed due to the success of the multi lateral concept and resultant high producing rates. Down hole sensors were installed to monitor drawdowns and changes in reservoir pressure and temperature as the step-rate tests were performed. Surface measurements of fluid producing rates, well head pressures, and VFD parameters were also made, and were communicated to the Operator via SCADA systems and cellular phone links. The units were initially started at low frequencies on the VFD"s, and the rates and pressures monitored until stable. Then the VFD was sped up, with new rates and pressures measured. The process was repeated in several steps until the well either pumped off or became gas locked. This paper presents the results of these operations and illustrates with schematics, system drawings, and production decline rates how the wells performed and how the well testing program was successful.

Continuous increase in worldwide brown-field activity and overall depletion of current gas fields has renewed focus on maximizing gas production from existing wells. In most gas wells, water and/or condensate is produced along with gas. As gas wells mature, decreasing formation pressure and gas velocities gradually impair the well resulting in production declines due to the inability to lift these fluids. Current operational strategies use plunger lift, ESP, additional compressors, or intermittent production techniques to build reservoir pressure and produce fluids from these wells. An alternative method used to deliquify loaded wells is through the application of chemical additives commonly referred to as "foamers". This paper will present some case histories of successful usage of foamers: both water soluble and condensate foamers.

Infrared imaging (IR) can be a useful tool in the oil and gas industry. At ChevronTexaco, IR is used as a proactive maintenance tool in our oil and gas producing facilities and plants. IR was first introduced in the 1980's as a tool to inspect electrical systems for loose or bad connections on overhead distribution systems and overheating equipment, mainly motors and transformers. In the past we have primarily used IR for electrical inspections, but have also found that it is useful in finding anomalies on mechanical equipment as well, such as belt alignment and tension on rod pumping units or overheating bearings on a transfer pump to name a few. In the last two years we have found that IR can help tremendously in finding tank and vessel level and interface problems. It is also useful as an aid in identifying and scheduling tank maintenance, such as tank cleanouts and chemical treatment procedures and dosages. In this paper we will discuss these different applications of IR technology at ChevronTexaco.

In most fields today, operators are asked to do more with less. The common theme is; keep production up and expenses down. This paper describes the results experienced in several fields in Texas that are using an integrated software tool for production field automation. The combination of the right personnel and the right software has provided an environment where production costs are reduced and total production is increased. Efficiently monitoring well and facility operations, analyzing well performance, and accurately predicting problems has resulted in significantly decreased failure rates and increased production per well. Choosing the right software involves several decisions: 1. Building versus buying the system; 2. A single integrated system versus multiple systems; 3. UNIX or Windows-based system; 4. Built-in analysis or a separate analytical program; 5. Simply automating existing procedures or providing analysis that improves operations. Choosing the right personnel structure involves determining the needs of the system and coupling that with the available people. Fields that have put an emphasis on well analysis have shown great strides in well failure reduction which by itself increases field production. Proper automation allows producers to concentrate on operations efficiency, eliminating much of the need for solving problems on an emergency basis.

The purpose of this paper is to provide an engineering tool to the Oil and Gas Industry that will plot and monitor downhole failures by type of failure (Tubing Leaks, Rod Parts and Pump Repairs), by depth of failure and by date of failure. Utilizing Microsoft Excel Software to build this engineering tool provides to the user spreadsheet software that is utilized throughout the Oil and Gas Industry, easily electronically transported and does not require excessive technical support. Use of this engineering tool will provide you the opportunity to visually analysis the following: 1.

Polyethylene lined (polylined) tubing has been in service throughout West Texas several years. This paper reviews the experiences of one field where use of polylined tubing began in 2000 in one well and was then extended to other wells in efforts to mitigate high tubing failures. The data contained here in reviews the pre and post tubing failure rates of the about 40 wells, and reviews the salvages of tubing in a few select wells discussing their reduction in lost tubing value per day. The improvement in well failures and the reduction in lost value are very significant offsetting the added material costs and handling problems associated with polylined tubing. But, the paper will also provided notes addressing some of those handling caveat gained from field experiences.

Traditionally Pump Off Controllers (POC"s) have been used to monitor wells for fluid pound. However, signals generated by properly maintained quantitative POC systems can be utilized for a variety of monitoring and production optimization activities. Typically the POC's used in quantitative analysis consist of a load measurement sensor, a position sensor and a control box to collect data. In addition, in centralized systems, a communications device (i.e. radio transmitter) is used to communicate to a modem equipped computer workstation. This paper will discuss how data captured by POC systems can be utilized more extensively to manage field operations. Traditionally POC data, such as dynagraph cards, have been used to analyze for pump tillage, gas interference, and general artificial lift (A/L) performance by importing POC data into artificial lift analysis programs. However, properly calibrated POC's are being used to monitor fluid levels, minimize the occurrence of stuffing box leaks or flowline breaks due to excessive pressure, and monitoring paraffin buildup. In addition to load and position, data such as flowline pressures, vessel level in facilities, upstream and downstream pressures and rates on injection lines can be captured via the POC system. Submersible pump monitoring including amperage, flow rate and flowline pressures are also being monitored. The subject POC system was installed in 1989 to monitor 600 wellbores producing from the Clearfork formation. The initial concept was to control pump off to reduce failure frequency and operating costs. The system was designed to use polished rod load cells and inclinometer position sensors. Hardware and software upgrades continue to be implemented as needed. However, the concept of using the system solely for pump off control has evolved to utilizing the system as a Production Optimization Center (P.O.C.) that serves as a hub for production operations processes.

Optimization of production from a reservoir produced by artificial lift can take weeks or months. The process typically involves gathering and amalgamation of operating data, then manual analysis of the data in software packages to find optimization opportunity.
To streamline and enhance this process, each artificially lifted well in the reservoir was equipped with an intelligent data processing device programmed with a real time model of the well. The processors were linked to a central access point where the operation of field could be remotely viewed in real time.
Each well's processor was provided with a target bottom hole flowing pressure or target flow rate to enable the optimum production of the reservoir. The real time system automatically compared the desired target drawdown values with the capability of the pumping system installed in each well, and automatically suggested the optimum operating frequency and well head pressure to achieve the target. Where the lift system was not capable of producing to the target bottom hole pressure, a larger pump was automatically recommended. As production conditions change the system automatically adapted its recommended operating points to compensate and maintain target production.
This paper discusses three case studies where real time optimization and diagnosis lead to improved production from the reservoir.

Recent studies have shown that in many instances large fluid volumes can be lifted by sucker rods with great effectiveness, from shallow to medium depth wells. Wherever this is feasible, significant reduction in cost of elevating a barrel of fluid may be realized by the operator. The advent of longer stroke units with improved geometry, larger speed reducers and bottom-hole pumps, as well as the new high strength sucker rods, have combined to make high volume rod pumping a practical and economical achievement. In the past, applications of this type have generally been considered only for bottomhole centrifugal pumps. This paper reviews some actual field studies and emphasizes the practicality of high volume production with sucker rods.

The fatigue life of a reinforced plastic sucker rod is controlled by minimum stress, the stress range, and the operating temperature. The diagram, Figure 1, is part of API Specification 11C. For any minimum stress found on line 0-1, a peak allowable stress is found directly above on line A-P. If a well is operating at 100 percent of this allowable range with an operating temperature of 160F, it should cycle 7,500,000 times before expected first failure. Column B and Column D allow the stress range to be modified for different life expectancies and different operating temperatures. Figure 2 is the stress range diagram for Fiberflex fiberglass sucker rods. Two different parts of the rod must be considered when estimating fatigue life: the rod body and the end connector system.

Using spectral gamma ray imaging to identify issues of fracture stimulation placement has been well documented and enhanced by providing methods to interpret inside or near wellbore phenomena as well as fracturing phenomena occurring within 25 inches of the wellbore. Recent studies by Robinson and Voneiff have confirmed that in most vertical or near vertical wells, fracture heights determined by tracers are equivalent to or within ten percent of fracture heights predicted by 3D models or post-fracture treatment performance testing. " Furthermore, it has been determined that when tracers are proportioned properly throughout proppant slurries and carried as an integral part of non-washing, non-crushing, non-abrasion loss carriers, the counts as determined by spectral gamma ray imaging are directly related to fracture width.* This has successfully been corroborated by correlations made using long-spaced or dipole sonic logging and refined by an algorithm developed to quantify fracture width at the wellbore. Most recently a case study has shown that tracers may be used to confirm that fracture closure may not occur as quickly as is often calculated or assumed.

Many production engineers are beginning to use three-dimensional (3-D) fracture propagation models to design and analyze hydraulic fracture treatments. To use a 3-D model, one must define the layers that comprise the reservoir and develop detailed datasets that accurately describe the layers. The data that are critical for designing and analyzing hydraulic fracture treatments are in-situ stress, formation permeability, formation porosity, reservoir pressure, and Young's modulus. Many times, these parameters can be determined from logs and/or correlated to lithology. Once the datasets are obtained, one can use a three-dimensional fracture propagation model to estimate values of created or propped fracture length, width, and height. To understand and improve the fracture design process, the engineer must confirm the estimates of fracture dimensions that are predicted by a fracture propagation model. To verify the model, one must analyze field data to be sure the field data are consistent with the model results. For example, the net pressure predicted by the 3-D fracture propagation model should closely match the net pressures observed in the field. When net pressure is adequately matched, we usually find that the overall created fracture dimensions predicted by a 3-D fracture propagation model are reasonable. To determine estimates of propped fracture length, one must also analyze post-fracture production and pressure transient data. Because of fracture fluid cleanup problems, we often find that values of propped fracture length generated by analyzing field production data are much shorter than the created fracture length predicted by the fracture propagation model ." Detailed engineering studies are often required to reconcile the differences. To directly measure values of fracture width, one must perform a fracture treatment in open-hole, then use a downhole imaging tool to "see" the fracture. Such an approach is not usually practical. In this paper, we will describe a method to qualitatively estimate the propped width profile at the borehole that uses radioactive tracers. Confirming the propped width profile generated by a model with field data can be very beneficial and informative. We have found that the use of zero wash radioactive tracers can help us learn both (1) where the fracture fluid is going and (2) where the proppant resides in the fracture near the wellbore. Assuming the level of radioactivity is proportional to volume, then the level of radioactivity will also be proportional to the propped fracture width. As such, one can obtain qualitative estimates of propped fracture width at the wellbore using a radioactive tracer where the strength of the radioactive signal is proportional to fracture volume near the wellbore. The objectives of this paper are to discuss what factors control the fracture width profile and how to obtain data to compute fracture width. We also explain how one can use radioactive tracers to develop data that can be analyzed to determine qualitative estimates of propped fracture width. Finally, we provide several examples to illustrate how one can estimate values of propped fracture width, and how those values can be used to calibrate a 3-Dimensional fracture propagation model. The information described in this paper can be used by a production engineer to obtain a better understanding of a specific hydraulic fracture treatment. As our understanding of hydraulic fracturing improves, we should be able to design the optimal fracture treatment with more certainty. When we design and pump the optimal fracture treatment, we maximize the economic return on developing oil and gas properties.

Variable Frequency Drive (VFD) technology has been employed in a wide variety of applications in many industries in recent years. Application of VFD to the rod pumping system has allowed pumping speed to be adjusted in real time by the POC, eliminated sheave changes as well conditions change, reduced power consumption, and allowed continuous pumping of wells producing formation solids. This paper will review the installation, operation, benefits and economics of installations on new and existing wells at several locations in West Texas operated by BP America

Absolute permeability is a property of the rock only, while effective perm is a property of the rock and the fluids present in the rock. In the most general sense, permeability used in the petroleum industry is a constant in Darcy's flow equation that equates flow rate, pressure gradient, and fluid properties. Even though a formation has a permeability regardless if it is flowing or not, by this definition a direct measurement of permeability requires a dynamic process not a static process. Historically, well logs have been used to estimate permeability via correlations related to a commonly logged property: porosity. Perm-porosity correlations are generated from core and transformed to well log porosity. These correlations are generally semilog in nature in the general form of y = axb. Other correlations attempt to estimate effective perm by incorporating irreducible water saturation estimated from resistivity logs and Archie's equation. Most well logging environments are static conditions, where invasion of mud filtrate into the permeable formations has ceased at the time the well is logged. This paper reviews traditional and new methods of quantitatively inferring permeability from well logs and addresses the feasibility of a true permeability log.

This paper describes how motor speed can be used to deduce items of practical interest. With respect to equipment loading, gearbox torque can be deduced from motor speed and the relationship between speed and motor torque. Unit balance can be sensed and counterbalance can be adjusted to minimize loading and to conserve power. An unexpected result is that reasonably precise dynamometer cards can be inferred from motor speed and unit geometry, even without use of a dynamometer.

An open-hole completed lateral CO, WAG injection well in the San Andres formation had not performed as desired in developing a sweep of upper structure pay and indications were that an injection profile problem existed. It was ascertained that all injection fluids were entering into a known 30-40 ft. interval approximately 230 ft from the toe of this 1,337-ft horizontal lateral rendering the remaining lateral section ineffective. Tracer surveys and interference pressure tests showed most injection fluids were being lost out of the productive interval and not giving the desired response to offset producers. A conformance design utilizing a dehydrated crystallized copolymer was implemented to control the loss of injection fluids into the unwanted zone. With confirmation of a positive treatment response, a coil tubing stimulation utilizing 135_F heated acid was performed to improve injectivity into the desired intervals within the remaining lateral section.

Carnegie Production Company operates wells in the Appalachian Basin throughout the states of Pennsylvania and West Virginia. A typical well is completed with 4.5" OD casing in multiple zones with multiple sets of perforations between 3000" to 6000". Liquid loading is a common problem in these wells due to insufficient flow rates to remove liquids. Liquid loading decreases production and occasionally will completely shut-off production. Frequent swabbing, rod pumps, siphon strings, tubing plungers are some methods used to remove these fluids. One cost effective method gaining increased use is a modified 4.5" nominal OD casing plunger utilizing a pressurized dome. This modified casing plunger eliminates the need for tubing, siphon strings, rods and downhole pumps. The modified casing plunger can remove liquids from a completion, be a solution to the liquid-loading dilemma, increase production, and extend the life of wells with very little investment. The modified casing plungers are designed primarily for wells that cannot operate, nor support the cost, of traditional pumping systems or frequent swabbing. The casing plungers are becoming an economic alternative to swabbing these lower volume, low pressure wells, particularly if these wells produce 1 to 10 barrels of liquid per day. A description of the modified casing plunger, a liquid unloading sequence, and field results from Carnegie are summarized in this paper.

It has been estimated that almost half a million oil wells today use V-best drives to transmit power from a prime mover to the pumping unit. Of all the desirable characteristic of the V-belt drive as a power transmission medium- such characteristics as resilience, dependability, adaptability, compactness, ease of speed change, and cleanliness- perhaps the major characteristic responsible for this widespread use of V-belt drives is the fact that inherently they need very little care. In those rare instances where difficulties arise in the operation of the V-belt drive, those difficulties can generally be traced to lack of understanding of the fundamentals of such drives- or to ignoring them.

The Austin chalk formation in Van field, Van Zandt County, Texas, USA, was identified as a candidate for infill drilling and recompletion. For the program to be economically successful, total well costs would have to be significantly reduced without compromising production performance. To achieve total systems cost reduction, a team of management, engineering and field personnel from both the operator and supplier was formed. The team's charter was to create a workover program that reduced the total operating cost by 25% without a detrimental effect on production. To identify and prioritize potential opportunities, the team employed a Structured Process Improvement exercise. Smaller task groups were formed, based on individual member expertise, to evaluate the feasibility and impact of each new technique. After a review of individual group recommendations, a revised workover process was implemented by the operator. Total systems cost reduction of 37% and replacement of 500,000 BOE reserves were realized in the first 90 of 150 planned wells.

For years engineers have known the value of elevated temperature cooling of internal combustion engines. As far back as 1916, Muir, Rushmore, Harrison, and others applied cooling systems to automobile engines which they called "controlled temperature," "steam cooling," and "evaporative cooling." While tests included operating at various controlled pressures to raise or lower the boiling point of the coolant, the control utilizing the natural law of boiling was found to be the most suitable.

Presents applications, design consideration, and economics of variable speed drives. Horsepower and torque requirements are shown for these applications.

The casing and tubing are subjected to have become increasingly more severe. Therefore, the manufacturer and user have had to find ways to perform non-destructive tests to measure the performance properties of these tubes. Wells are not only being drilled deeper but more areas of high pressure are being encountered. Secondary recovery projects quite often increase the working pressure under which the tubes operate. The stimulating processes for oil and gas wells, such as fracturing and acidizing, have brought about new demands on tubular goods.

The Petroleum Technology Transfer Council (PTTC) is a national organization established in 1993 to provide technology transfer to independent oil and gas operators. The organization is a funded partnership between DOE, state agencies and industry, which is headquartered in Houston with 10 regional offices serving all producing states. The PTTC Texas- Permian Basin was established in 1999 to assist the PTTC Texas RLO; the Bureau of Economic Geology. This paper will discuss the methodologies PTTC has utilized for transferring technology. The primary vehicles include workshops developed to address specific industry needs, case studies that represent proven technologies and industry's method of two-way beneficial sharing, and personal contacts via phone, fax, email, or websites. The PI

This paper summarizes the case history of the implementation of VeriTrax, a fully integrated chemical delivery and data management system. This is a computerized system that automates the processes involved in the provision of production chemicals, allowing for increased accuracy of chemical usage and tank levels for operators, and increased efficacy of chemical delivery and billing through a fully integrated SAP-based system. The Operator and Clariant Oil Services worked together to create VeriTrax, which optimized performance by eliminating manual input into both the Operator's and Clariant Oil Services" SAP systems. Complete details are given in the paper on the three components of VeriTrax: a global positioning system (GPS), a computer interface and a smart meter. When a delivery is made using VeriTrax, the GPS immediately identifies the well based on the location and the smart meter records the amount of product dispensed and sends this information into SAP.