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.

The science of business management has progressed as rapidly in recent years as the science of engineering. However, much of this knowledge has been utilized by only the larger businesses with professionally trained managers. The manager of a small business has frequently come from another profession, such as engineering, and was not exposed to management training during his formal education; and since going into business for himself, he has had neither the time nor the financial resources to m-educate himself in the field of business management. Fortunately, many of these managers by experience, observation, or perhaps native intelligence have acquired and put to use much of this new knowledge. Because this knowledge is essential to survive in competition with larger and better-financed competitors, the more successful small companies have acquired the knowledge through some source. The purpose of this paper is to present some of these new management practices and show how they apply to a small business. Since many of the readers are from the consumer side of the oil industry, I shall also point out some recognition symbols of a well-managed company. This will assist the buyer of goods and services in identifying the well-managed companies to use, because good management results in fair prices, good service, and a quality product.

Flowmeters available to the petroleum industry fit into a wide range of operating principles and are diverse in the physical phenomena employed. Flow measurement may be made from (1) velocity, (2) mass transfer rate, (3) volumetric transfer, or (4) interference. Our industry pumps fluids that range from (1) clean, homogenous newtonian to (2) heterogenous non-newtonian slurries. Application of flowmeter type to fluid type requires more than casual attention. This paper presents a summary of flowmeter types currently available and gives advantages and disadvantages of each. Included in this technology survey are (1) flowmeter types, (2) operating principle, (3) range of accuracy, and (4) proper application of each. The conclusion is reached that flowmeter choice is not as straightforward as users may have been led to believe, however, an informed user can select a meter that will give the best available service.

An experimental paraffin control technique has been developed and tested in several West Texas Chevron operated leases producing from the Spraberry formation. The results were encouraging. The methods described below provide a structured framework for testing and analyzing paraffin control and for applying the procedures developed.

A recurring problem in foam fracturing is sand suspension; i.e., the suspension of high sand concentrations in the liquid phase of a foam frac system. A process has been developed which enables the liquid phase to be pumped directly from the blender to the high-pressure pumps without recirculating to suspend high sand concentrations. This process for foam frac is improved by using a unique gel-gel breaker system for the liquid portion used in generating the foam. The advantage of this system is that more sand may be carried in the liquid portion, which means that more sand can be delivered downhole, which in turn delivers more sand to the fracture. resulting in more of the created fracture being propped. The liquid portion of the fluid is divided into two portions. The main liquid portion which carries the sand is modified by hydrating a cellulose-type polymer in water to form a viscous gel. The viscosity of this gel is such that high sand concentrations can be carried without recirculation. The other smaller portion carries a foaming agent and a gel breaker. When the two liquids are combined, the viscosity of the gel breaks immediately. Nitrogen gas is then added downstream to generate the foam as shown in Fig. 1.

Pressure buildup analysis has been used for many years to evaluate the performance of wells and estimate the properties of reservoirs. Usually, the application of pressure transient theory to the evaluation of well tests requires that accurate bottomhole pressure measurements be made. In the case of a well producing by beam pumping, the direct measurement of bottomhole pressures is impossible, since the presence of the pump in the tubing physically precludes the use of wireline pressure gages and permanent downhole pressure installations are usually not economically attractive. For this reason, indirect bottomhole pressure measurements are usually made by measuring the annulus pressure at the surface along with the fluid level in the annulus. From these measurements and the fluid densities, the bottomhole pressure may be estimated with an accuracy depending on the accuracy of the estimated fluid properties and the measurement accuracy. This procedure has been criticized, since the pressures being analyzed are not directly measured and the accuracy of the data and estimated fluid properties limits the analysis precision. This report documents an improved evaluation method for wells producing on beam pumps. Instead of indirectly calculating the bottomhole pressure, the wellbore is modeled and the analysis is performed directly on the measured data. Since both casing pressure and fluid level are measured, the number of data points is essentially doubled over standard well testing and the accuracy of the analysis can be judged by comparison with the actual measured data. In addition, since the casing pressure appears to be mainly affected by wellbore effects, the evaluation accuracy is improved even more than would be expected from statistical considerations alone.

Cement squeezes have been used for many years for various operations such as casing leak repairs, sealing of thief zones, and zonal isolation. While they have been successful in many of these operations, they often require more than one attempt before success is achieved, or they are not successful at all. This paper presents the development of a system based on a combination of a porosity-fill sealant with particulates. The particulates provide leakoff control, which leads to shallow matrix penetration of the sealant. The main advantage of this system over cement is that the gel remaining in the wellbore can be washed out of the hole, and does not need to be drilled out as is the case with cement. While this system has previously been reported, this paper presents improvements in the fluid-loss system as well as additional information on case histories.