Dynamometer testing of sucker rod lifted wells is performed routinely in a safe and efficient manner throughout the world.

Dire predictions regarding the availability of petroleum and continuation of our present civilization, are indicated by the title of a recent presentation "The Peak of World Oil Production and the Road to the Olduvai Gorge," which predicts the crash of civilization in 2030." There are other more conservative predictions for just a peak in petroleum production in 2005. In a previous paper at this conference I projected the peak in oil production to 2040.

Field data on pumping well buildup curves illustrate long fluid column stabilization, U-tubing of liquid from tubing into the annulus, gas coning, high-pressure gas stringers, and high-pressure liquid stringers. Examples are given of truncation and of fitting two curves to the afterflow to get a better approximation of main pay and stringer properties, and of estimating unflooded stringer pressure from afterflow changes.

The American Gear Manufacturers' Association introduced its first recommendation for sizing oilfield pumping unit gear reducers in the year 1935. This recommendation eventually became AGMA Standard 422.02 and was incorporated in API Standard 11E. Since 1935 the only major change in API Standard 11E has been the addition of ductile iron as a gear material. AGMA's new standard, AGMA 422.XX, covers recommended gear ratings based on tooth strength as well as pitting resistance. The present standards, AGMA 422.02 and API llE, do not include specific recommendations for tooth strength. AGMA 422.XX also includes recommendations for sizing surface hardened gears in addition to thru hardened gears covered in the present standards. A detailed comparison between the new and old ratings, as well as the physical size of some typical oilfield pumping unit reducers, is illustrated and discussed.

Oil and gas drilling and production activities are currently regulated by many governmental entities. Such massive regulation inevitably leads to industry discussions concerning whether or not certain specific regulations are needed. This paper broadly outlines the impact of the Texas Clean Air Act of 1967 on petroleum drilling and production activities. The reasonableness and necessity of this act are reviewed with respect to the various petroleum-production activities.

This paper discusses the mechanics of air drilling, modifications such as mist or foam drilling, unique equipment requirements, and downhole problems that have been encountered. Special attention is given to describing techniques developed to prevent or control downhole problems.

In 2000 TEMA Oil & Gas ("TEMA") purchased the Simpson-Mann field in Val Verde and Crockett counties. The Simpson-Mann field's completion horizon is the Canyon Sand. From their prior Canyon Sand experience, TEMA's asset management team was convinced that better completions could be made. While the initial post acquisition completions were equivalent to the field's historical completions, TEMA was disappointed in the quality of their new wells. Additionally, TEMA did not think they were improving their understanding of the field's critical characteristics consequently they decided to change. Starting in 2003, TEMA changed their techniques; and expectations in order to enhance their understanding of the Simpson-Mann field. While not confirmed the current theory dictates a radical departure from historical stimulation techniques.We theorize through fracturing data, chemical marking, and early core analysis why we believe the natural fracture system is biased away from vertical.

The last American Frontier, Alaska, is for the most part a harsh and demanding wilderness - a land of extremes. There are places where winter temperatures reach a painfully cold -85_F and summer highs reaching a sweltering 95_F. For most of the year Alaska's North Slope (area between Brooks Range and Arctic Ocean) remains an icy desert, receiving less than six inches of moisture annually. Despite these extremes, Alaska's North Slope has an abundant amount of wildlife. The summer months bring the Caribou back to their traditional camping grounds. Today there is still room for the Caribou to graze peacefully in a largely unspoiled environment. It is in this Arctic wilderness that Atlantic Richfield Company and Exxon first discovered Prudhoe Bay Field in 1968.

About two trillion barrels of oil will remain in the existing reservoirs without implementing enhanced oil recovery. Chemical recovery offers the most obvious and attractive method to recover this oil. Alkaline-Surfactant-Polymer (ASP) is the most promising chemical EOR process due to the synergism of alkaline, surfactant and polymer flooding. In this presentation, we will discuss the following: 1)Mechanisms of individual polymer, surfactant and alkaline processes, 2) ASP synergistic mechanism, 3)Laboratory evaluation procedures, 4) Status of ASP application, 5) A field case of commercial ASP application, 6) Problems with the ASP field application.

A new technology called the Hydro-Balanced Stuffing Box System used successfully to prevent pollution caused by polished rod pumps, was designed for use in Artificial Lift Systems using a positive displacement plunger pump. The development was discussed in a paper presented at the 2000 Southwestern Petroleum Short Course and this paper will discuss the field testing and further developments in the technology. A leak in the high pressure packing of a pump has the potential of causing environmental pollution, safety hazards, loss of energy and costly clean-up. The technology described transfers the pressure of the product being pumped to a sacrificial barrier fluid of known characteristics. When the seals wear sufficiently to leak, only the environmentally friendly fluid leaks to the atmosphere. The presentation will include slides and drawings of the Hydro-Balanced Packing System.

In order to combat falling productivity and increased water production in the West Flowers and Guest (Canyon Sand) fields, a new approach to stimulation technique and fluid had to be initiated. It was suspected that many pre-1975 frac jobs probably were lost into unproductive zones resulting in very little stimulation of the actual pay section. To combat this situation, the frac fluid was changed to a very high viscosity cross-linked CM C-based polymer gel. The base fluid was 2% KC1 water treated with de-emulsifiers. A detailed computerized study was conducted to determine a near optimum treatment design. Fluid volumes were selected based on frac lengths which provided the most economically feasible productivity increase ratios (J/Jo) and proppant concentrations were analyzed so as to afford the optimum permeability contrasts. Sand concentrations were increased, and 10-20 mesh sand was used. The perforations are acidized and broken down. This is followed by a base temperature survey. A 2,000-gal dummy stage (slick water) is pumped to determine the zone taking fluid. If channeling is observed, a stage of a calculated amount of benzoic acid flakes is run to divert thef2uid into the pay section. A 2,000-gal dummy stage is next pumped. Based on the results of a temperature and radioactive survey, the fraction of the pay section taking fluid is determined. A proportional amount of frac is pumped followed by a calculated amount of block. This is followed by a shut-in period of 20 minutes to let the fracture heal and the surface pressure till about 500 psi. The above steps are repeated until all or most of the zone is fractured.

More effective use of computing tools for production surveillance by operations and engineering personnel is critical to increases in profitability. Exxon's ALWORKS (Artificial Lift Workstation) is a software package that provides easy access to electronically stored data and provides that data to various surveillance, analysis and design applications with minimal user effort. The software has been field tested and significant increases in productivity by operations personnel have been observed, which will lead to increases in profitability.

American Petroleum Institute (API) Specification 11B covers requirements for standardization of components, materials, dimensional requirements, and testing/inspection for sucker rod components.
This paper will review the recent revision of this specification and highlight the changes made to the specification

As early as 1895, Herman Frasch recognized a need for acid additives in acid stimulation treatments. His observations and subsequent patent spelled out the need for an acid corrosion inhibitor. During the span of years from the early 1930s to the mid 196Os, much advancement was made in the field of developing additives for hydrochloric acid stimulation. Surfactants, corrosion inhibitors, buffering agents, and reaction time retarders as we know them today, had their beginnings. The one notable factor about these advances is the fact that all were truely additives for the acid. That is, the materials were added to the acid in small quantities to alter the properties of the treating fluid. Seldom were the additives used at concentrations exceeding 1%. In the mid 196Os, alcoholic acid treating solutions were introduced. This launched an era of more basic changes in the whole nature of the acidizing fluids. This was no longer an additive because a significant portion of the treating fluid might now be termed as a solvent. Later in the decade came the use of chemically stabilized dispersions of aromatic solvents in an acid external emulsion. Then in 1971, the use of mutual solvents was introduced. Each of these advancements offered new possibilities and improved the treatment results by helping the acid past physical barriers so it could perform the job it was intended to do. During the same decade, much work was directed to enhanced oil recovery through micellar flooding. From this technology came the concept of the micellar acidizing solvent. The following sections will compare the properties and use of the popular and widely used solvent systems to the newest - a micellar acidizing solvent.

This paper presents the development of a new system for water and gas shutoff operations. This system combines a conformance sealant (based on an organically crosslinked polymer) with non-cement particulates. The particulates provide leak off control which leads to shallow matrix penetration of the sealant. This filtrate from the leak off is thermally activated. After exposure to the bottomhole temperature of the well, it forms a three-dimensional gel structure which effectively seals off the targeted interval. The limited and controlled leak off into the matrix during the squeeze results in a controlled depth of invasion. Selective perforation of the oil zones re-establishes the desired hydrocarbon production from the targeted interval. The system can be easily washed out of the wellbore, as compared to cement which must be drilled out. This system can be considered as an alternative to standard cement squeeze operations, casing leak repairs, sealing of thief zones, etc.

As hydraulic fracturing treatments continue to increase in fluid volume and in expense, emphasis is now being placed on more efficient treatment techniques. The traditional method of batch mixing a fracturing fluid has several disadvantages. Once the chemicals are added to the mixing water, they must be pumped within a specific length of time in order to retain their effectiveness. A delay due to well, weather or equipment problems can cause the premixed chemicals to degrade. Chemicals used to mix fracturing fluids constitute a substantial part of the treatment cost. Finally, any fluid left from the treatment usually cannot be reused unless it is transported to another location within a certain time limit. A continuous-mixing technique has been recently developed to more efficiently mix fracturing fluids. The technique eliminates pretreatment mixing of the fracturing fluid by proportionally combining the fracturing fluid chemicals with the mixing water in the blender tub at the time of the job. Sand is then added to the fluid, and the resulting fracturing slurry is pumped to the high pressure pumps for injection into the wellbore. In this paper, field and laboratory studies are cited in the attempt to describe the continuous-mix methodology. A cost comparison of continuous mixing and of traditional batch mixing based on job analysis is also presented.

A discussion of the evolution in design, development and application of subsurface locking mandrels is presented. Several major types will be discussed with respect to their merits and limitations. A case history shows the use of the mandrel from completion to gas lift operations.

An approach to automation of oil field production including a computer oriented system entailing consideration for remote terminals, communication facilities, communications between the actual process, (in this case the oil wells themselves), and the central logic. The system also provides for communications between the oil field operators and the central logic.

Nowhere in the oil field are experience and "rule of thumb" employed more frequently than in estimating chemical treatment volumes to be used to stimulate production. The majority of chemical treatments performed are attempts to improve fluid flow by removing restrictions around the wellbore. Usually, if the production rate has declined more rapidly than expected, it is an indication that a restriction exists or is forming. Darcy's equation for fluid flow through concentric cylinders empirically describes "skin damage". These theoretical curves relate productivity damage ratio to the extent and degree of damage. Combined with plots of treating radius vs. porosity, treatments can be evaluated. Also, general conclusions are possible from the shape of Darcy's theoretical curves. From these evaluations, a basis is available to estimate treatment volumes.

Software and a manifolding system for automating closed-chamber drillstem tests have been developed. This paper describes the software, the manifolding and, briefly, the data acquisition system that provides the interface between them. In addition, it presents improved correlations for determining the maximum influx rates of gasfree and gas-saturated water. The typical test procedure is outlined in the paper and an actual example of a closed-chamber test illustrates the paper.

Lining and coating of oilfield tubular goods have long been common solutions to downhole tubular corrosion problems in oil and gas operations. Thermoplastic linings and spray-coated resins have been replaced in numerous applications recently with filament-wound composite materials. Notably, the introduction of Fiberglass-Epoxy Resin liners in downhole and surface steel tubular goods has provided opportunities for continuous operation in corrosive environments under higher temperatures and greater volumes of corrosive substances. Increased capabilities of fiberglass-lined tubulars in deep corrosive gas wells, for example have given operators greater flexibility by providing less-expensive options to costly alloy steel production tubing. These were previously perceived to be the only choice. New products have emerged that will tolerate temperatures in excess of 300" F and high concentrations of H2S and C02 amongst other corrosive gases and liquids. In addition, operators of disposal facilities are saving capital expense by disposing waste gas through FG-lined tubing into depleted sands and carbonate reservoirs in lieu of constructing elaborate treatment plants to remove corrosive waste products. This paper will examine the long-term economic benefits of FG-lined tubular goods vis-a-vis various alternatives- typically less expensive methods such as Internal Plastic Coating (IPC) and tubulars lined with cement products as well as with Polyvinylchloride (PVC) and Polyethylene products. Additionally, comparative examples are presented where corrosive gases are being produced through alloy steel in high-temperature applications at production facilities. Finally, case histories of both high-temperature gas production and large volumes of low-pH waste products are being disposed are presented.

This paper shows how an existing water holding tanK designed to separate oil and water is economically modified to increase fluid retention time. A case history from a waterflood in Andrews County, Texas where this design is used is discussed. The results of this study show increased retention time reduced oil carryover and suspended solids in the injection water.

A variety of sour gas sweetening processes have been commercially available for a number of years, and reports of new processes appear regularly. Many of these processes present severe problems in economics and operating consistency for selectively removing hydrogen sulfide from sour gas, especially in the presence of high concentrations of carbon dioxide. This presentation describes a new one-step process which selectively removes H2S, even in the presence of CO2, and converts it directly to elemental sulfur. Only one vessel is used and this operates unattended or with minimum manpower. No recirculating pump, regenerating vessels, or reboilers are required. And perhaps most important, the spent slurry produced has been declared non-hazardous by most regulatory agencies. Field operations have shown this one-step process to be safe and reliable. Experience has shown that existing available process equipment can often be adapted to use the process. Guidelines for equipment design are given and field applications for this type of process are suggested. Specific field installations are cited to illustrate the safe and simple operation of this new system which requires comparatively low capital investment.

This paper explains the development and the applications of a simple, accurate, and efficient computer program for decline curve analysis of both oil and gas wells. By utilizing root extraction technique in numerical methods, the decline exponent n of a given oil/gas property with production rate - time data can be computed directly and the initial decline rate Di can then be determined. With the values of n and D., the governing decline equation *or the property can be formulated and used to predict its future performance. The computer program uses very little computer memory space and it runs very fast. Three examples are included to show the accuracy and speed of the program.

Presents latest equipment and methods used in analysis of electrical systems and methods of obtaining more efficient and profitable electrical system operation.