During recent years, multiple completions have become more commonplace. This is to be expected due to the obvious economic advantages derived from producing two or more allowable while having to drill but one hole. Problems encountered in producing multiple completions, as in single completions, are usually minimal, until artificial lift is required. With the installation of lift equipment, production from zones beneath a packer can be adversely affected if the pump intake pressure is below the bubble point of the produced fluid and the gas production is not adequately vented. The use of vent strings in these cases can result in maintaining producing rates at or near normal, and thereby increase income and shorten producing life over what would be anticipated if the well were produced unvented. This paper presents some limited data on producing from beneath a packer with the gas production vented and unvented. Venting through one-inch tubing strings is compared with annular venting. A method, with a trial and error solution, of predicting unvented production is also presented.

Significant advances have recently been made in laboratory attempts to measure realistic fracture conductivity values for proppants at reservoir conditions. This paper will give a brief overview of recent work throughout the industry related to conductivity testing, and efforts being made to simulate the environment of fracturing proppants during a well's producing life. Also presented will be data showing that test results can be significantly different when using wet gas as the flowing medium following a short period of flowing brine water. Listed below are the nine most important test parameters that need to be incorporated into the test procedure: -Reservoir Temperature -Extended test times -Core wafers -Gel residue within the proppant pack -Gel filter cakes from dynamic fluid loss tests -Shear preconditioning of fluids in fluid loss tests -Frac fluid clean-up -Wet nitrogen gas as flowing medium (to model gas wells) -Multiple closure stress values. Previous authors have modeled some of these variables, but this paper will present data where all parameters listed above are included. These test results will allow an operator to more accurately model a fracturing treatment with a design simulator and thus predict the post-frac production using a reservoir simulator.

Electrical submersible pumping is perhaps the most inflexible of any artificial lift method because any given ESP pump can only be used in a specific, quite restricted range of pumping rates. If used outside its recommended liquid rate range, the hydraulic efficiency of the pump rapidly deteriorates; efficiencies can go down to almost zero for pumping rates lying well outside of the lower or upper limits. In addition to the loss of energy and the consequent decrease in profitability the ESP system, when operated under such conditions, soon develops mechanical problems that can lead to a complete system failure. An improper installation design or inaccurate information on the well's inflow capability always results in a mismatch between the design rate and the actual pumping rate. The usual result of these troubles is a workover job and the running of a newly-designed ESP system of the proper lifting capacity. Since the capacity of the ESP system, without using an expensive VSD (variable speed drive) unit, cannot be easily changed, wellhead chokes are often used to restrict the pumping rate and to force the ESP pump to operate within the recommended liquid rate range. This solution, of course, is very detrimental to the economy of the production system because the pressure drop across the choke causes high hydraulic losses and a considerable waste of energy. The paper investigates the negative effects of surface production chokes on the energy efficiency of ESP systems using NODAL analysis tools. The proper way of conducting a NODAL analysis for this purpose is detailed along with the description of power flow in the ESP system. The calculation of energy losses in system components is detailed and the relative importance of the individual losses is shown. The elimination of the problems associated with the use of surface chokes is investigated and the proper parameters of the necessary VSD unit are found.

The scope of this paper includes a brief introduction about On-Off tool, design and construction, their applications, operational procedures, and general load carrying capabilities. The paper discusses some advantages gained by installing an On-Off tool such as, the ability to repair or replace the rod string without unseating the pump, the ability to break the sucker rod string just above the pump eliminating stripping job and the ability to run oversized tubing pumps.

The concept of using chemical additives to reduce drag or friction of fluids flowing in turbulence has been a well-known phenomenon for many years. It has been the subject of several papers both in and outside the petroleum industry. There are many stimulation treatments now being performed which would be virtually impossible were it not for friction-reducing chemicals present in the stimulation fluids. Even small-volume acid washes done through small-diameter tubing or coiled tubing units utilize friction-reducing chemicals. Friction reducers, used in small quantities, can provide reduced surface treating pressures, higher injection rates, and lower hydraulic horsepower requirements. Historically, powdered-type friction reducers have been used in the petroleum industry for most aqueous fracturing treatments. The common polymers used to reduce friction on a large scale are guar gum, derivatives of cellulose, and synthetic polymers such as polyethylene oxides and polyacrylamides. Synthetic polymers generally provide higher friction reduction at lower concentrations than do the natural polymers and cellulose materials. Advances in polymerization techniques have made possible the development of polymers in liquid form. Now, synthetic friction-reducing polymers, similar to those previously used as solids, can be obtained in liquid form making handling and mixing less difficult. Liquids do not have a tendency to lump when added to aqueous fluids as do dry powders. When lumps form, they are not easily dispersed and can reduce the material available for lowering friction pressure. Also, the addition of liquid systems to treating fluids can be uniformly controlled. Using proper guidelines, it is possible to select a polymer system which provides good friction reduction, is stable in concentrated acid solutions for extended periods of time, and is compatible with most acid additives. This paper compares the properties of a liquid acid friction-reducing agent with several commonly used powdered materials. Some guidelines for selecting an acid friction reducer and laboratory testing of friction reducers are discussed. Successful field results using a liquid friction reducer in acid are also described.

This paper discusses the use of AutoCAD, a popular PC CAD (Computer Aided Design/Drafting) application package, for calculation and analysis of water flood injection profile data. By heavily utilizing the customizing capability of the AutoCAD program, calculational accuracy and repeatability are enhanced. Additionally, the well log analyst is able to more readily verify and validate assumptions during the interactive data analysis phase. The theory and application of profile analysis will be discussed: included are example calculations. Additionally, AutoCAD customizing techniques and programming examples will be discussed. Finally, the automated use of AutoCAD to facilitate multiple well presentations (historical and intra field) will be presented.

This paper discusses the use of AutoCAD, a popular PC CAD (Computer Aided Design/Drafting) application package, for calculation and analysis of water flood injection profile data. By heavily utilizing the customizing capability of the AutoCAD .program, calculational accuracy and repeatability are enhanced. Additionally, the well log analyst is able to more readily verify and validate assumptions during the interactive data analysis phase. The theory and application of profile analysis will be discussed: included are example calculations. Additionally, AutoCAD customizing techniques and programming examples will be discussed. Finally, the automated use of AutoCAD to facilitate multiple well presentations (historical and intra field) will be presented.

This paper presents the practice of using downstream chokes in unloading injection pressure operated (IPO) gas-lift valves. The practice helps to assure effective unloading and may provide protection against erosion damage during the unloading process. It has several other benefits that are discussed in the paper. A gas-lift valve/choke model has been developed. It provides accurate predictions of the gas passage through the choked valve during the unloading process. And, it can help to analyze existing gas-lift performance, where the objective is to determine which valve(s) are open and how much gas is being injected through them. This model is described in the paper.

Coatings of various materials are used to improve corrosion, abrasion and scaling resistance of ESP components. This paper will briefly discuss some of the coatings with a focus on Teflon and it's potential to increase run time. A specific application will be discussed in detail. A completely coated pump was run between uncoated pumps in a New Mexico well that produces significant solids. The well was pulled after a 224-day run and all pumps torn down and examined. This paper will review the findings of the tear down and implications for future Teflon coating applications and tests.

Due to encountered influxes of water while attempting to gain consolidation around wellbores and/or their tubulars, cement can have difficulty in achieving the needed sealing and preventative state necessary for zonal isolation. High influxes of water present across these areas needing remediation can deteriorate the cement at any state from its being placed through the time it takes it to form and develop enough strength to resist this environment. Presented are trials, developed techniques and results based on incorporating crystallized co-polymer super absorbent materials mixed with cement and also as a pre-flush system in conjunction with cementing operations to address a variety of influx problems around wellbores. Data includes laboratory analysis and performance evaluations generated while testing and performing these cement operational solutions. Diagnostics used to arrive at a best fit solution are also detailed and discussed.

As fluids are produced from a reservoir, zones of higher permeability and correspondingly higher flow rates create channels for the preferential movement of fluids.

By coupling the communications power of the internet with the latest in reservoir simulation technology, it is now feasible to direct oil and gas field development in near real-time, using a continuously updated computer model that matches and reflects the actual rates and pressure data observed in the field. While quarterly or monthly updates are probably sufficient in most cases, operators have the option of updating the model weekly or even daily in order to meet the needs of each situation. This ground breaking approach can remove much of the risk from evaluating well completions, optimizing the location of offset and infill wells, predicting reservoir pressures, flow rates, reservoir drainage patterns, identifying the most effective completion methods, well spacing patterns and many other field management decisions. This paper illustrates how this kind of dynamic reservoir simulation can be implemented, even for small, remote production locations, and it cites examples of where this has already been tried, the results that were obtained and describes the experience of those who have actually implemented this approach. The capability now exists for operators, regardless of size or location, to model every new development well (prior to drilling), identify the most cost-efficient reservoir drainage plan and adjust that plan in an ongoing manner based on actual field/well behavior.

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.