This paper presents three years of field experience showing dramatically improved rod string performance, resulting in lower intervention costs.
There are three key factors in achieving this improved performance. First and foremost is the rigorous application of best practices for rod handling, connection cleaning, preparation and lubrication. Second is the use of a fully automated rod tong which delivers accurate CD control on every connection in the string. She third factor is a secondary measurement of true torque for each connection, giving further assurance that proper pin tension is achieved.
This experience has demonstrated that API 11BR does contain the proper recommended practices for successful rod makeup. Suggestions are presented for future topics which could be considered for further enhancement of API 11BR.

During the past 10 years, methods have been developed to adequately and economically protect lease surface vessels fabricated from mild steel and subject to corrosion. In general, these methods have fallen into 2 categories

The South Cowdeu (San Audres) Unit was selected as the site for one of three mid-term projects to be conducted under the DOE Class II Oil Program for Shallow Shelf Carbonate Reservoirs. The $21 million project was designed to demonstrate the technical and economic viability of an innovative carbon dioxide (CO2 flood project development approach. The new approach employed cost-effective advanced reservoir characterization technology as an integral part of a focused development plan utilizing horizontal injection wells, where appropriate, and centralization of production/injection facilities to optimize CO2 project economics. This paper will review actual implementation and field performance in the first eighteen months of the project, focusing on key issues of timing, stimulation, injection profile monitoring, reservoir pressure reduction, and conformance control A comparison will be presented of initial simulation model results with current predictions.

Fluid loss into the formation matrix can be a serious problem during overbalanced workover operations, Invasion by the completion fluid can cause near-wellbore damage and can also cause problems associated with poor wellbore cleanout and loss of hydrocarbon reserves. In addition, fluid loss can increase costs associated with rig time and treatments devoted to restore the initial condition of the formation. Traditional techniques to minimize fluid loss use solids or viscous pills, although it has been amply documented that these systems can damage the formation if not properly removed after the treatment. This paper presents the laboratory development and validation of a novel solids-free fluid-loss (SFFL) system used during overbalanced workover operations. This system relies on an ionic polymer that decreases matrix permeability to aqueous fluids, limiting leakoff into treated zones. This polymer immediately adsorbs to the surface of the rock,
eliminating the need to shut the well in. In addition, this system does not require the use of breakers, which eliminates negative impact on post-stimulation well productivity. Laboratory test data show the capability of the material to control fluid leakoff and achieve high levels of regained permeability to hydrocarbons. To date, about 110 jobs have been performed with this novel SFFL system. The paper discusses field results from the application of this system during overbalanced workover operations and other applications where maintenance
of a hydrostatic column is necessary for well control. This system has been proposed for solving partial and total loss to full circulation in overbalanced operations such as: (1) lost-circulation events occurring during cementing, fracturing, and drilling, (2) well intervention cleanouts by coiled tubing (CT) and hydraulic workover (HWO), (3) gravel packing, (4) replacement of artificial lift equipment (i.e., electrical submersible pumps), and (5) overbalanced tubing-conveyed perforating (OTCP), among others.

To investigate the causes of fluid migration behind the casing after primary cementing, pressure and temperature measurements were made in the annulus of seven wells during cementing operations. Sensors were attached to the outside of the casing as it was run into each well; in this way data were obtained from several depths. A logging cable, also clamped to the casing, was used to bring data from the sensors to the surface. In some of the wells these annular measurements were continued during subsequent completion or workover operations. The pressure data could be used to determine conditions that either prevented or allowed fluid entry into the wellbore. Generally, pressure in the cement column began to decrease shortly after the cement was pumped. The success of the cementing operation depended on the cement attaining sufficient strength to exclude pore fluids from the cement before the pressure somewhere in the cement column declined to pore pressure at that depth. Pressure in the cement generally appeared to decline to the pore pressure in adjacent formations after the cement had set. In one well, however, pressure in the cement opposite a "tight streak" steadily declined to far less than a water hydrostatic gradient as the cement set.

Production of natural gasoline and other liquefied petroleum gases from casing head or oil well separator gas and gas distillate is the primary function of a natural gasoline plant. In this role, it demonstrates just another step taken by our industry toward achieving maximum utilization and deriving maximum benefit from one of our country's important resources, natural gas.

In the beginning of this project the primary goal was to compare IPC and Bare tubing and discern which was more effective in lowering tubing failures and which was more economical. In this project, a sample of 62 wells was examined from the Sprabeny area as well as an additional 152 wells from the Preston Spraberry Unit "Best Practices" program. All wells were evaluated from January of 1996 to July of 2002. The question in concern was if IPC should be part of the optimizing process. During the research for the answer to this question it became evident that more conclusions could be drawn from the information gathered than was originally expected. Not only was the IPC question to be answered but the effects of other optimization techniques were seen as well. In this report, one will see the final decision on the effectiveness of IPC as well as the parameters needed for it to be effective. One will also see the benefits of Sinkerbars and Pump off Controllers (POC).

Numerous articles have been published on field application of dynamometers. However, dynamometers are not widely used. Use of dynamometers has been limited by the difficulty of interpreting dynamometer cards. This paper deals with recognizing rod-pumping problems through field analysis of qualitative dynamometer cards.

Scale and paraffin problems cost the oil industry billions of dollars in prevention, maintenance and repair each year. A new and innovative approach to well management, using a physical fluid treatment device, will be presented showing how it reduces well interventions and, correspondingly, improves production efficiency. Over 45 wells in West Texas were treated for scale and paraffin using a unique physical fluid treatment device over a period of 24 months. Specific case histories will be highlighted identifying prior operating issues and comparing favorable use incorporating the physical fluid device. The device, operating at 120 khz, is conveniently attached at the surface of the well and causes the scale to nucleate in the produced fluid rather than on the walls of the well tubulars. Paraffin is attracted to the scale and other inorganics and also remains in the produced fluid. Paraffin and scale are carried away with the produced fluids.

Newly drilled water injection wells in the Shell operated Jordan University Unit in the Jordan(San Andres) Field of West Texas exhibited thin intervals of high permeability (and poor profiles) soon after injectivity began (Fig. 1). The wells had been selectively acidized (straddle packers were used to isolate each perforation while acidizing) with surface pressures of not more than 500 psi. Since fiberglass casing was cemented across the entire injection interval, the use of cement to squeeze off selected perforations (prior to reacidizing perforations not taking water) was not feasible because of its high density and hard set. A plugging material with a low viscosity and a specific gravity approaching that of fresh water was needed in order to plug the rock matrix near the wellbore. A crosslinked polymer was used because its specific gravity and viscosity approach that of fresh water, and it is a non-particulate. Therefore, the polymer could be used without hydraulically fracturing the rock or "plating out" on the wellbore face. The use of polymers in injection well profile control has been well-documented in previous publications. A different method of application of a crosslinked, stiff gel polymer (American Cyanamid Company AM-9 Chemical Grout) was successfully used to alter injection profiles in the three San Andres dolomite water injection wells. Proven fluid design techniques were successfully used to premix a gel solution and a catalyst solution at the surface ("on the fly") for a downhole (3800 ft) setting time of approximately 20 min. at 90" F. The resulting solution had low viscosity pumping characteristics, yet rapidly increased in viscosity at the desired setting time. Consequently, the solution pumping characteristics were also similar to fresh water. In addition, an under displacement gel placement technique was utilized to assure that uncontaminated polymer was gelled in the pore network (within a radius of 6 to 8 ft) and back into the wellbore. The under displacement technique and reacidizing of old tight perforations were the keys to injection well profile change in the Jordan University Unit. Production history data from wells surrounding the three injectors reflect an increase of approximately 550 BOPD over an 18-month period. The increase in oil production is a direct result of injection well profile improvement. See Table 1 for an economic analysis of the cost of the three worked-over injection wells and of the production results associated with the 16 surrounding producing wells.

One of the more extensive uses of directional drilling anywhere in the world has been in the development of the East Wilmington Oil Field in Long Beach, California. The average well achieves a deviation from vertical in excess of 50' and wells with a build-up in the 70 to 80 range are not uncommon before they are dropped off to 50 or less when penetrating the completion interval. Over 780 wells have been drilled in this field to date, requiring the highest degree of control and accuracy in order to avoid intersection of other wells and to obtain proper bottom hole spacing. The Measurement-While-Drilling (MWD) directional system has been tested on several wells and proven to provide the required accuracy along with many advantages over past methods used in the field development. Accurate transmission by MWD of bottom hole measurements to the surface is provided by mud pressure pulses generated in the drill pipe downhole and detected by a pressure transducer mounted on the standpipe. Surface equipment includes the means for detecting, recording and processing these pressure pulses, to translate the information from the pressure pulses to rig floor displays useable by the drilling crew.

The McKinley afterflow method has been successfully used to interpret drill-stem tests (D.S.T.) and short-time production tests where conventional analysis methods cannot be employed, or are difficult to apply." Although the afterflow method has other applications, this study will be limited to pressure buildup behavior. Throughout this paper the McKinley afterflow buildup method will be referred to as simply the afterflow method. The Horner method is the most commonly used technique for interpreting short-time test data, so the following examples will be compared to this method.2 Effective permeability, wellbore damage or stimulation, radius of investigation, and expected production rate are the reservoir parameters obtainable by the afterflow method. Exact numerical values are not obtained by this or any curve-matching procedure, but the order of magnitude of the answers is sufficiently close to help make decisions that are normally made from a short-time test. Six examples have been selected to illustrate the application of the afterflow method. These examples are typical of many tests analyzed from producing areas around the world. They hav,e been selected because of the large amount of followup data made available by Henry Engineering and other industry companies. Reference 1 describes the analytical treatment of the afterflow method. Utilization of the afterflow method to D.S.T. and short-time production tests has previously been described by Milner and Warren in S.P.E. number 4123. Our contribution through this study is to present verification, by actual field results, of the afterflow method to certain types of problems.

With existing demands for oil and gas at continued higher prices, there has become a greater interest in previously uneconomical reservoirs. The Cisco and Canyon formations in Sterling County, Texas fall into this category. In particular, the Conger (Penn) area has enjoyed rapid and continuous development since 1977. Hydraulic fracturing has been required to stimulate for commercial production. Stimulation practices have been reviewed and a more efficient approach developed to provide maximum productivity at an optimum cost.

The rapid development of the Rhoda Walker Field (51 new wells in 1977 and 31 wells in 1976) indicates the interest in the Delaware Mountain Group pays in the Delaware Basin. Hydraulic fracturing treatments are necessary to stimulate production to a commercial level. An efficient stimulation approach has been developed, with the aid of detailed computer design studies, to produce maximum productivity in a cost-effective manner.

Today's cutting edge diagnostic software for beam pumping surveillance, analysis, and optimization includes improved methodology based on time-tested techniques as well as practical new functionality. Specifically, this paper will reference dynamometer card pattern matching to aid the well analyst, lease operator, or other interested parties in understanding well operating conditions. This is technology available from the 1980's, but refined in the pattern matching algorithms used and the presentation of results to the user. Available new functionality includes diagnostic reporting that produces a collection of outputs or warnings which are the result of a statistical analysis of surface and downhole card information, calibration or predicted dynamometer card information, and trended data for each beam well addressed by the diagnostic software. The required data is gathered and the resulting calculations are performed each day by the diagnostic software. The purpose is to apply logic that an experienced well analyst would use to determine whether each well needs any corrective action. The diagnostic logic can be customized, allowing users to specify statistical limits for creating warnings. Those diagnostic warnings deemed unnecessary can be de-activated by the user. Major areas of interest for this paper include: 1) recognition of RPC load calibration problems, 2) gearbox torque and pumping unit counterbalance, 3) correct prime mover size, and 4) verification of pattern matching usability. The field test will include beam pumped wells located in conventional primary recovery areas and wells pumping under the influence of injected CO2 for secondary recovery. The data presented in this paper was randomly selected from wells in a 101 well system located in western United States. Average pumping depths ranged from 5400' to 6500'. All wells were equipped with RPCs (Rod Pumped Controllers), calibrated load cells (all with five years or less service), and some combination of magnetic proximity switches and inclinometers for position input. RPC and end device maintenance and software well configuration history should be consider as average.

A novel gelling agent for hydrochloric acid is evaluated through field tests. Increased formation conductivity and live acid penetration depth is reflected by sustained improvements in production after the treatments. The advantages of this new gelling agent are its stability in high concentrations of hydrochloric acid (28 percent) to 300 F. over a range of temperatures up Comparisons with ungelled acid and acid treatments using other gelling agents are presented. These case histories are in West Texas, New Mexico, North Dakota, Montana and other parts of the country.

It is extremely costly to do wireline gas-lift valve replacement in wells with subsea wellheads. All gas-lift valves for these installations should be designed for maximum run life and known injection-gas throughput performance for unloading and gas lifting the well. The API Recommended Practice method for gas-lift valve testing is not economically applicable. This paper describes a practical inexpensive rapid method for performance testing individual gas-lift valves in the field utilizing the injection-gas source for lifting the well.

Knowledge of oil-water relative permeability, polymer viscosity, and polymer retention is required to design a polymer flood. These properties are routinely determined in laboratory tests with reservoir rock and fluids. Lacking reservoir core material for laboratory measurements, Chain Oil Co. used a series of single well tests to define the required properties. Transient tests of buildup and falloff pressures were used to find the relative permeability end points, while a single well pumpin-pumpout test was conducted to determine polymer retention. Apparent reservoir dispersivity was also calculated. The field test results were used to design a J-Sand polymerflood. During polymer injection, pressure falloff tests were run to measure the in-situ viscosity at different polymer concentrations. Non-Newtonian type curves were used to analyze the transient data.

The "RUFF-COTE" * process, a resin-sand coating applied to the external surface of casing to provide an improved bond between the casing and cement, has now been widely used in oilfield completions for the past ten years. This process has been applied to well casing from 2-7/ 8 in. slim holes to 20- in. surface casing in ultra-deep wells. Additional application has been on intermediate casing strings as well as on offshore platform jacket legs. Successful field usage of this process in thousands of wells has demonstrated its effectiveness in providing a good bond between the cement and casing. One area, however, that had not been previously evaluated was how long the initial cement-to-casing bond is maintained after well completions operations such as perforating, fracturing or acidizing, and normal stresses applied during production. In order to properly evaluate the resin-sand coating, it was necessary to analyze wells that had been completed both with and without the resin-sand coating and had been producing for a number of years. Continental's Sacatosa Field in Maverick County, Texas, fitted all requirements for a good field test. The Sacatosa Field located in South Texas produces from the shallow San Miguel sand at a depth ranging from 1300 to 1700 feet. The wells were drilled with a light water-base mud and completed with either 4-l / 2 in. or 5-l/ 2 in. casing. Casing was run to TD and cemented to the surface. A well plot of Sacatosa Field showing the test area is presented in Fig. 1. The casing was perforated with a single-plane horizontal jet gun consisting of either three or eight shots within 24 to 48 hours after cementing. All wells were then hydraulically fractured with a sand-oil treatment.

In 1961, Beach, O"Brien and Goins, published the results of a study of squeeze-cementing perforations." The study was made over a four-year time span and involved actual wells located primarily in South Texas. The publication gives a comparison of the squeeze practice of that time of attaining pressures equal to overburden pressure and "putting away" relatively large volumes of cement, to the new concept of low-pressure "hesitation" or the "walking" squeeze. The former method made use of normal slurries and the latter of filtrate-loss-controlled slurries. The squeeze success ratio climbed from about 60% for the normal slurries to 85% for the filtrate-loss-controlled slurries. Perhaps the most spectacular success was a well in Yoakum County, Texas, where 230 feet of perforations were successfully squeezed with 100 sacks of cement in a single stage. This is believed to be the first publication showing filtrate-loss control as a key to successful cementing. This work reversed the industry's thinking on squeeze-cementing technique.

During the recent development of the fire-flood oil recovery processes, one of the first problems that had to be answered is how to initiate combustion. It was found that quite often certain crude oils were difficult to ignite even in the Iaboratory experiments, and the problems were magnified in field cases. Just why certain oils are more or less susceptible to combustion than other oils of oil bearing formations is not precisely known; but because of this, seireral ignition methods have been developeci and ignition equipment has been improved. Design temperature levels can be obtained and the heat generation capabilities of ignition equipment is sufficient to meet almost any resewoil- condition.

The fire-safe capability of a valve is becoming increasingly important when selecting valves, for hydrocarbon processing service. In spite of this,

Recent activity in the Avalon Shale play, an upper member of the Leonard series in southeastern New Mexico1, has opened up a new horizon for production from an unconventional formation. Key to the potential success of the Avalon Shale play will be the ability to adapt and refine horizontal completion methods and stimulation techniques. The effectiveness of hydraulic fracture stimulations is critical for optimal economic production of this natural gas and oil shale play. The initial stimulation methods used for the early wells in this play have revealed several challenges while hydraulically fracturing the Avalon Shale interval. Some of the issues are high treating pressure, near wellbore tortuosity, early fluid leak off, natural fractures, and a propensity for sand-outs that lead to shorter effective fractures and wellbore damage. This paper will present field case study demonstrating most of the previously mentioned problems and issues with hydraulically fracturing in the Avalon Shale and the steps that were taken to remedy them.

There are many different forms of artificial lift methods used in oil and gas wells in the United States. Eighty percent of the wells in the USA that are using a form artificial lift use a beam pump; to lift the fluids out of the well bore. Lifting the fluid out of the well bore lowers the hydrostatic pressure acting on the producing formation allowing greater in-flow and increased productivity. There are several reasons for the popularity of the beam pump; they are rugged, forgiving and easy to automate. Good diagnostics exist due to many companies developing dynograph systems. This focus of this paper is on the five basic components of any beam pump, why they are important and how they interact.

Conventional Sucker Rods were designed and thought for Beam Pumping applications as well as their make-up process (with circumferential displacement). This brought many failures in the connection which is supposed to be stronger than the rod body. A line of Hollow Sucker Rods (HSR) was developed with better material distribution and several advantages but basically providing more reliability due to the fact that they were thought from the development for PCP. They include a special connection with a SEC type of threads and torque shoulder which is made-up controlling torque with a regular pipe power tong. This paper shows the experience in a field located in south Argentina were HSR have been working for more than 5 years in 17 wells. Field results and failures are discussed as well as special issues to have in mind when producing with this alternative.