Crosslinked gels are adequately stable at high fluid temperatures and have thus established their usefulness for fracturing high-temperature formations. However, in certain treatment situations, they may develop high friction pressure in tubular goods which can limit their injection rate. Furthermore, the rheological properties exhibit a time-shear history dependency that is quite difficult to predict. Two-stage gel systems have been very successful in providing a means to develop desired viscosity at downhole conditions without causing high tubular friction pressures. However, several currently available systems do not have the stability required for large volume treatments at temperatures above 250_F (120C). A fracturing fluid has been developed that solves many disadvantages and limitations of both crosslinked and two-stage gel systems. This is made possible by the use of a new delayed hydrating gelling agent. The fluid has the desired two-stage viscosity qualities and can be formulated to provide the desired viscosity throughout a treatment. In addition, the rheological properties of the new fluid system are highly predictable. This fracturing fluid system has been successfully tested in the field. Fluid design and treatment results will be presented.

The A & B zones of the Trading Bay Oil Field, Cook Inlet, Alaska are a series of heterogeneous, largely unconsolidated sandstones. These sands contain several million barrels of reserves. Although numerous attempts had been made to produce these zones since 1967, less than 1% of the oil-in-place had been produced by January, 1980. Wells which were completed in the A & B intervals typically tested at non-commercial producing rates or declined to uneconomic rates within a year. Re-perforating, acidizing and various flushes with oil, all proved unsuccessful. Extensive analysis and studies of reservoir fluids, core material and production characteristics resulted in isolating the cause of the producing problems as a formation fines movement problem. Use of various clay stabilizing chemicals met with no success. Conventional formation fracturing to stimulate production appeared to be out of the question because of the problems of proppant imbedment in the soft, dirty sandstones. However, a concept to fully pack created hydraulic fractures with high concentrations of proppant and modifications of conventional fracturing procedures to achieve it, appeared promising, was pursued, and found to be successful. This paper describes a fracturing technique including procedures and materials for poorly consolidated sandstones. The stimulation technique has resulted in successful completions in the A & B zones and made possible economic recovery of a significant and heretofore essentially non-producible resource. It is expected that the technique may be applicable in many other areas where economical drainage of oil deposits from poorly consolidated sandstones is presently not possible.

The tremendous energy of a nuclear explosive and the very small size of a nuclear device warrant consideration of utilizing the energy released to stimulate production from relatively non-productive petroleum and natural-gas reservoirs, and from oil-shale and tar-sands deposits. Significant quantities of petroleum and gas are present in many thick, deeply buried reservoirs that have natural low productivity because of low permeability of the formation or high viscosity of the oil. Productivity from such formations cannot be adequately stimulated by conventional techniques of well completion. Also, vast deposits of oil shale lie too deep for economic mining. If these deposits could be adequately fractured the kerogen present might be converted to shale oil through in situ retorting. Studies of the feasibility of using nuclear explosives to produce fluid hydrocarbons from petroleum, natural-gas, tar-sands, and oil shale deposits have resulted in the following conclusions: 1) low-productivity natural gas reservoirs off the best immediate possibility for nuclear stimulation; 2) some petroleum reservoirs may be stimulated similarly; 3) nuclear fracturing of oil shale may permit in situ retorting; 4) conclusions concerning nuclear stimulation of production from deep tar-sands deposits in the United States cannot be drawn because of inadequate knowledge of their occurrence; 5) an actual experiment is needed to determine technical and economic feasibility; 6) radioactive contamination of hydrocarbon fluids is a problem that can be solved by various means, and nuclear stimulation can be conducted safely and within existing regulations; and 7) a test may be proposed and conducted relatively soon on a natural-gas reservoir of low productivity.

This paper documents 8 years of performance of an improved artificial lift system installed in a secondary recovery project. This improved artificial lift system matches a Fiberglass-Sinkerbar rodstring design to a specific pumping unit installed with a Pump-off Controller. Fiberglass-Sinkerbar rodstring designs have been given little or no consideration concerning reduced downhole rod and tubing failures or power consumption costs. The success of this improved artificial system has led to the following improvements in field performance: 1.Increased lift capacity from 20 cmpd (126 bfpd) to 100 cmpd (629 bfpd) 2.Runtimes between failure in excess of 1450 days (4.2 years) 3.Reduced power costs from .070 to .061cents/barrel 4.Lower operating expenses due to reduced power consumption, reduced maintenance costs and less downtown. Utilization of this improved artificial lift system will increase lift capacity, reduce downhole failures, increase runtimes and reduce power consumption and related expenses

Tubing leaks due to rod wear and corrosion are common in the oil field and can add significantly to the operating cost of any well. The preferred field applicable approaches to finding production tubing weak spots and leaks vary with different companies and range from pouring paint from a bucket, hydrostatic testing, and electronic inspection of the tubing as it is tripped. We have taken field data from numerous jobs and explored how each of these testing methods can be improved or enhanced to increase information reliability and to reduce the frequency and cost of well failures. Caveat: It is not the purpose of this paper to review or judge the attributes of the various techniques and apparatus used in electronic tubing inspection services as the equipment varies in how it works and how it is built. This paper addresses how the on-lease technology is applied over the well and how the results can change based on field applications and interpretations.

This study was performed at Mobil Salt Creek Field Unit in Kent County, TX and consisted of mechanical seal failures for Bingham split case centrifugal injection pumps. For individuals who are unfamiliar with the operation or function of mechanical seals, a reference is included in the study (see Appendix A - Fundamentals of Mechanical Seals). Due to the injection of C02, in addition to water, into the Mobil Salt Creek reservoir for increased oil production, the associated composition of the reservoir water changed greatly. The total suspended solids (TSS), total dissolved solids (TDS), pH, and entrained gases in the produced water changed dramatically from the former water flood or water driven reservoir. Consequently, when there were any changes in pressure or increases in temperature, solids, scaling, or "salting" was occurring. This increase in temperature or pressure drop can be quite common when dealing with the mechanical seal system. The mechanical seal system consists of three (3) items. Those items are water composition, seal material selection/design, and seal flush system. This brought to light the complexity of the mechanical seal issue.

This paper describes the methods used by Southwestern Public Service Company (SPS) to optimize the use of approximately 90,000,000M ZF of natural gas and 2,000,000 tons of coal each year. The fuel that is purchased by SPS cams from five different suppliers and is covered by thirteen contracts, each contract containing one or rare take-or-pay constraints. Optimization is applied at tm levels: 1. Take-or-pay provisions of all contracts are met on monthly, annual or other basis as specified in the contracts. 2. Minute-by-minutes use of gas and coal is adjusted to provide the lowest instantaneous overall cost of generating the power demanded by SPS customers at that instant. The optimization methods used at both levels are described. Presented are the advantages and disadvantages of the techniques that are used. An assessment is made of the overall success of the optimization system.

We have seen many changes throughout the years in the manner in which oil companies have been organized and managed. There have been the hard, tough, rough-and-tumble days of the wildcatter and the gusher, and there has been what we like to think of as the days of "enlightened" management of Wall Street and the operating management at the well head. Changes have occurred in which additional layers of supervision have been added and subtracted, offices made large and small, and people hired or "retired"

It would seem that before we can get into formulas and actual power calculations, it would be worth while to review a definition of electricity and study some of the instruments used to determine the quantities that are needed in power calculations.

Many of the calculations made use of in the various branches of the petroleum industry involve the pressure, temperature, and volume relationships of gases. The mathematical equations which express these relationships have been known as the gas laws.

The theory of the measurement of the flow of a liquid through an orifice is based on the two fundamental laws of hydraulics. Gas flow involves some further modifications which will be mentioned after the simpler case of liquid flow has been developed.

Many complicated explanations have been written of corrosion; yet, it is simply a transformation of energy. The corrosion process itself is quiet and unheralded, without any noticeable display of heat, light, or sound. A major portion of this cost and destruction can be stopped by applying known methods of corrosion control.

Liquid level control is critical in the separation of gas, oil and water from the well stream. This is accomplished with the use of vessels designed to hold fluid long enough for this separation to take place. This is typically accomplished with the use of four different styles of controllers; mechanical, pneumatic, electronic and floatless. This paper will discuss the types of controllers, how they function, application for each and the different valves they operate.

Liquid level control is critical in the separation of gas, oil and water from the well stream. This is accomplished with the use of vessels designed to hold fluid long enough for this separation to take place. The liquid level controller dictates how long these fluids will remain in the vessel. This is typically accomplished with the use of three different styles of controllers; mechanical, pneumatic, and floatless. This paper will discuss the different types of controllers, how the function, applications for each and the different valves they operate.

Basic theory and application of magnetic particle inspection will be presented along with the operation and techniques of electromagnetic induction inspection for field inspection of oil country tubular goods.

Crude oil as typically produced from petroleum bearing formations consists not only of oil or liquid hydrocarbons but associated with it will be hydrocarbon gas, salt water, and possibly some solids. The amount of produced water may vary from small natural occurring amounts to large amounts where water has been injected in secondary recovery operations. In some of the newer tertiary recovery systems carbon dioxide is injected into the formations to stimulate production, and therefore, some of it is returned with the oil production. It too must be processed with the crude oil stream. There are several items of production equipment that are used in various combinations to make what is termed the "production facility" or "production battery." The term "tank battery" is normally associated with the group of oil production tanks that are connected in parallel to receive the oil and/or water production from the producing wells. The term "production battery" or "production facility" is used to include not only the tank battery but the other pieces of equipment associated with it to process, treat, and separate the liquid and gas streams. First, this paper will discuss individually the various pieces of equipment that are used in oil production processing. Interconnection and system design using the various pieces of equipment will then be illustrated.

Recent increases in the demand and price for natural gas have stimulated requirements for gas compressors of all sizes. This paper develops the basic fundamentals of gas compressor sizing. The scope of this discussion is limited to slow speed (300-1000 RPM), horizontal, double acting, reciprocating compressors. Since exact specifications vary between different manufacturers, it is advisable to consult the manufacturer concerning his product's performance. The data and tables shown are intended to be as universally applicable as possible. A field gas compressor normally consists of the gas compressor itself, a prime mover, and other components all coordinated to meet a specific condition or range of conditions. The emphasis here will be given to sizing the compressor, and its flexibility and coordination with other components of the package.

A well analysis program is an area where any oil company can make money immediately. It appears that most well analyses are performed by large oil companies that have large computer facilities. However, in order to use these facilities, a great deal of effort is required on the part of the engineer or technician. Quite often, the engineer could make a few calculations with a small calculator and have the answer to the problem. This requires that the engineer understand the basic principles of the pump, rod string, and pumping unit operation. Equipment to obtain the necessary data was hard to use and required considerable time. Usually, the pumping system had severe problems before the time and effort would be spent to analyze it. Now, equipment is available that will allow the engineer or technician to obtain the data easily and make an analysis in a few minutes. Of primary importance is a thorough understanding of the operation of a modern oil well pump. Figure 1 is a schematic drawing of such a pump

Building on recent innovations and repeated successful applications using the multiple patented PAL PLUNGER casing plungers n multiple zone stripper gas wells in the Oklahoma Panhandle, the technology was successfully tested in 7 vertical wells drilled in the Barnett Shale in Coke County, Texas. Prior to the installation of casing plungers, the primary method of fluid removal employed large pump units powered with gas fired motors. The issues addressed and the solutions devised, along with the results will be presented for information and discussion.

The profitability of rod pumping operations is a direct function of the energy requirements of pumping. For maximum profits the efficiency of the pumping system must be maximized, this can only be achieved by finding the optimum pumping mode for the required liquid production rate. These principles are used in the paper by presenting a case study on improving rod pumping operations. The project reported was conducted in a mature onshore field with 70-plus rod pumped wells. An extensive measurement program involving more than 50% of the wells was set up and pumping parameters were measured with a portable computerized system. The detailed evaluation of measurement data facilitated the detection of general and specific problems in the design and operation of the pumping installations. With the aim of improving the field-wide profitability of pumping operations, an optimization of each well's pumping parameters was made. Calculation results showed that a field-wide power saving of about 17% can be anticipated if all wells operate at their most economic pumping modes.

Limited field-testing of gas separators used with progressing cavity pumps have shown improved gas separation with the pump set in the producing interval. This paper is presented to illustrate these changes and their associated improvement and to exchange information with other operators. While these modifications are not fully understood or tested with a significant number of installations the improvement observed warrants discussion.

Severe production penalties often result from gas interference in the operation of pumping wells. Test results of the application of field constructed bottom hole gas separator systems have proved and re-emphasized the merit of these installations. Increased pump efficiency and increased production can be obtained through the proper use of equipment that has often been referred to as inadequate and obsolete.

In the past decade, gas control in producing oil well reservoirs with gas caps has become one of the major problems facing the oil and gas producer. This problem has gained in significance insofar as the oil producer is concerned, since Regulatory Bodies have increased their activity in curbing unnecessary wasting of reservoir energy. Evidence of this fact is shown by the downward trend in permissible gas-oil ratios for many fields in the state of Texas. The Railroad Commission of Texas, normally requires a general gas-oil survey one each year on all producing oil wells in the field. The result of these surveys are studied, and the gas limit for each well is set; therefore, the penalized allowable is that amount of oil that can be produced with the daily gas limit. As an example, we will consider a well in a reservoir that has a limiting gas-oil ratios of 2,000 to 1. We will assume that this well has allowable of 60 barrels of oil per day; therefore the daily gas limit for well will be 60 times 2,000 for 120,000 cubic feet per day. If the well has a allowable gas-oil ratio of 6,000 to 1, the penalized allowable will be 120,000 divided by 6000, or 20 barrels of oil per day.

Gas Frac is a fracturing treatment using a new and absolutely water free fluid system. The fluid is liquefied petroleum gas and liquid carbon dioxide mixed in such a ratio that they remain a liquid and behave as other liquids a long as they are under adequate pressure and below their critical temperature. After the fluid is heated to this temperature in the reservoir and pressure released, the liquid reverts to a gas. This results in extremely rapid clean-up and no residual fluids are left in the formation. Gas Frac was developed especially for gas well stimulation. Results to date have proved this technique to be very successful. This paper discusses the techniques, materials and equipment used. An analysis of results of fracture treatments is presented.

Pumping free gas reduces pump-liquid efficiencies and alters loading on the pumping system. The rod pumping design procedure outlined in API RP IIL assumes complete pump liquid fillage and determines loads based on test data gathered from an electrical analog computer model. The Shell method is based on a mathematical solution, and the resulting loads are calculated assuming incomplete pump fillage (gas interference). Design charts similar to those used in API RP IIL for rod pumped systems are shown based on 75% liquid and 25% gas fillage of the pump. These design charts are compared to API rod design charts. In general, incomplete pump fillage alters peak loading conditions: however, loads are not significantly different in most cases from API loads. Surface pump dynamometer cards for 75% fillage are compared with100% fillage cards. The shape of the 100 and 75% pump fillage dynamometer cards are somewhat different, especially in the first half of the downstroke. The effects of pumping gas on pump efficiency are shown and explained. The optimum pump volumes and depth plus the important parameters affecting gas separation are outlined.