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.

With the advent of the super deep well the particular properties of gases become more critical. Both heavy hydrocarbon gases and the relatively lighter hydrogen sulfide and carbon dioxide follow the general gas laws, but the apparent problem from the floor of the drilling rig is quite different. The reservoirs in super deep wells contain gases under greater than critical pressure and temperatures that are liberated to the mud stream as a "liquid". This poses some very critical problems in the early detection and later control of high pressure gas reservoirs. The great depth of the new super deep wells enforces a time lag on all actions that can be very confusing and further masks the problem of critical pressure of gas. An understanding of these phenomena can help alleviate the difficulties experienced in drilling into very deep, high-pressure gas reservoirs.

This paper presents a basic method for designing and analyzing continuous and intermittent flow gas lift installations by combining mathematical and graphical design techniques. By expressing the graphical presentations of well performance in the form a pressure-depth diagram, one standard procedure can be employed to design continuous and intermittent flow gas lift installations using any basic type of gas lift valve. This approach to gas lift design presents a complete graphical picture of the pressure conditions that are encountered in the wellbore during the "kick-off" and producing phases of gas lift thus providing the designer with a better understanding of gas lift operation.

This paper deals with the problems of gas lift design for a dually completed well. Gas lift flow valves are described. The limitations of small tubing and restricted annular areas are noted. Problems of flow valves design for small tubing are emphasized. Methods for gas lifting only one zone of a separate injection gas source for each zone to be lifted, as compared with common gas source for both zones, are discussed. Application of concentric and parallel type dual gas lift installations are outlined. The advantages of retrievable gas lift equipment are mentioned.

This paper presents a history of intermittent gas lift production practices in multiple completed wells in the TXL Field in Ector County, Texas, and the South Andrews Field in Andrews County, Texas. These two fields contain most of Shell Oil Company's gas lift installations in the Permian Basin. Attention is given to individual installation designs in an attempt to evaluate their merit or demerit for particular well conditions. The purpose of this paper is to show the approach to multiple gas lift operation in these two areas progressively over an approximate ten-year span with particular emphasis given to improvements based on experience with an evaluation of prior installations.

The proper design of a gas lift installation is not always readily apparent from well data. Previews mechanics of continuous flow and intermittent flow and factors affecting design.

Advanced exploration into, and production

Gas migration or "gas cut cement 'I has been an industry problem for many years. This paper discusses the testing of six different cement slurry additives and a saturated saltwater slurry, all designed to prevent gas migration. The slurries were tested for their effectiveness at preventing gas migration at low pressures, such as is experienced offshore in shallow gas sands. Test equipment of a new design was fabricated. The slurries were exposed to gas pressure at the bottom of a 17 foot cement column in 1-1/2" pipe and the volume of invading gas measured. The hardened columns were then cut into sections to observe the channels created by the gas. The study showed that none of the products were able to completely stop the gas migration. Some products did appear to perform better than others but none were completely effective. The testing showed several of the slurry's properties to be associated with the formation of gas channels. In many of the tests, unexpected and as of yet unexplained gaps enveloped in the cement columns as the cement hardened. Based on these results, additional testing is being conducted.

A discussion of the selection of gas regulators and controls with special emphasis on design, material of construction, and sizing. Sizing equations, with example problems are presented. A glossary of control industry terminology is included.

Natural gas presently supplies approximately one-third of the energy used in the United States. The current critical shortage of natural gas presents a challenging problem to the pipeline industry, the consumer and the producer. Only through cooperation by all three parties and the Federal Government will it be possible to continue to supply even the current percentage of the energy used in the United States through natural gas.

Gas turbines are being utilized as the prime movers for Gulf's Goldsmith (5600-ft.) Field Water Injection Station. The Goldsmith (5600-ft.) Field is located in Ector County, Texas. This paper will endeavor to describe the installation, operation, and economics of using gas turbines as prime movers. This paper will cover a period of almost 5 years, from initial installation in April 1961 to January 1966.

Higher gas prices have presented new opportunities in gas fields. An imperative issue throughout these fields is liquid loading. This paper discusses and presents results from a low rate, low cost deliquification project. Inexpensive pumping units with a small motor and pump are installed to keep water off the formation, enabling the production of gas. This is a long term solution allowing the well to produce to its economic limit in an efficient, low maintenance system.

There are several concepts now available in the industry to pump water downward below a packer in a gas well and allow the gas to flow freely up the casing of a gas well. This reduces the flowing gradient and allows gas flow to occur at a lower flowing bottom hole pressure. Also it eliminates any water disposal problems. This can now be done with ESP systems, PCP systems and also beam lift systems. In order for these systems to perform, a zone below the gas producing zone must be available where the water can be injected below a packer. According to Enviro-Tech Tools, State Regulatory Commissions are classifying this method as a Class II injection well, and as such they require underground injection control permits. This paper centers on discussion of some systems using modified beam lift systems to inject water in a gas well to enhance gas production. Systems are reviewed and some field experience is discussed.