The long stroke hydraulic pumping unit, as we know it today, oftentimes may seem strange to the new operator, even though it has been operating successfully in parts of the oil field for the past fifteen years. Justifiably so, the hydraulic long stroke unit may at first seem unfamiliar to the new operator, since for years previous to the introduction of the long stroke hydraulic pumping unit the oil fields had know no other means of sucker rod pumping than the old familiar sight of a beam moving up and down. However, just as the rotary drilling rig has followed the cable tool rig, so has the hydraulic long stroke unit followed the beam pumping unit.

The rod and tubing pumps of today are far advanced over the oil well pumps of twenty and thirty years ago. Wells were shallow and that time consisted of common working barrels and the old bowspring cups. As well were drilled deeper; longer runs were required to lower lifting costs, metals were experimented with to assemble the forerunner of the present day precision rod and tubing pumps. The original metal pumps were built with plungers turned down in lathes to fit each individual barrel so that interchangeability was impossible. In recent years the American Petroleum Institute committees, in collaboration with manufacturers and oil producers, have established basic dimensions on all pumps which will allow any pump shop to stock API parts to repair all types of pumps.

This paper will deal with the four cycle spark ignition, carburetor engine designed to operate on the gaseous or liquid fuel or a combination of both as practically all so called high speed pumping engine are of this type. Actually, the correct classification of these engines should be "medium speed" as compared to engines being used in other industries operating as much higher speed.

The subject for today is the Care and Operation of Hydraulic Pumps.

All internal combustion engines are built to give long, trouble free service. An internal combustion engine, in order to operate, must have fuel, air, oil, and a coolant (usually water). The condition of these four items determines the useful life of an engine. Let's discuss each of these and attempt to point out desirable standards and how to combat below standard factors. Since the majority of engines used are gas engines, we will talk about natural gas as a fuel. Most gas used is a field gas and engine users don"t have much choice but to use it as it exists. In discussing fuel, we must also consider its effect on lubricating oil.

An internal combustion engine must have air, water, fuel, and oil fed to it in order to keep it operating. The condition of these four items determines the useful life of the engine. We will attempt to point out what the standards are and the best methods of combating the "below standard" factors where we have no choice but to use them as they exist in the field. It is not possible to describe and elaborate on fuel alone without considering its affect on the lubricating oil.

You men as users and myself representing a pipe manufacturer are both vitally interested in getting satisfactory service from our tubular goods. Engineering wise, there are three major factors which control this: 1) proper manufacture 2) Proper design, 3) Proper use.

Unitized Emulsion Treaters have been a reality for over 20 years. They have been employed in the Permian Basin for over 18 years. This type of surface equipment has become almost a necessity and is therefore considered standard equipment on most leases. The present day vessel is an efficient, pressure operated, automatic treating plant. Contrast this with the early day methods of treating oil in a pit with steam coils, or spreading the oil out in a thin layer and letting the sun warm and treat the oil. The present day practice of using Unitized Emulsion Treaters is an example of the oil industry's desire to conserve our natural resources.

When, where and how do you plan your career? No. 1, you decide what you really want! What do you want to accomplish during your life? Not what your parents wanted. Not what your spouse or children want. But, what do you want? Deciding what we want is difficult, getting it is even harder. To do this we need a life plan. We need to think of personal growth and values. We need to maintain health and fulfill spiritual needs. We need to develop our personal lives and to establish fruitful relationships. The problem is that we live in a world of change and risk. Change in our world is occuring faster than ever before in history. To move forward we must gamble. Somehow we must be flexible and adapt to this changing world but still steer a constant course toward our goal. We need to stack the odds in our favor, and we can. In the ultimate, you are the person who controls your life. You are the one who determines your forward progress.

Wolfcamp producers in Howard County, Texas have to be fracture stimulated to be economical. However, the low frac gradient and bottomhole reservoir pressures make formation closure slow and proppant retention in the created fracture during initial production difficult. This has led to many of the wells requiring wellbore cleanouts and in some cases multiple cleanouts. Various methods are available to overcome this problem. Methods of proppant flowback control vary from materials added to a proppant pack to provide physical stability, forced closure techniques, tail-in with curable resin coated proppants, etc. The most extensively used method in most areas of West Texas is the tail-in with curable resin coated proppant. Resin coated proppants consist of a substrate of sand or ceramic particle coated with multi-layers of phenolic and other specialty resins. These resins provide grain to grain bonding and additional particle strength. Presented are case histories of Wolfcamp producers fracture treated using 20/40 Mesh, White Sand and using a tail-in of curable resin coated sand comprising 15% of total proppant pumped. The case histories show that use of a resin coated proppant added an additional $25000 to $30000 to treatment costs, however, a single wellbore cleanout of sand costs $24000 to $27000. Making the cost of running a resin coated proppant tail-in

In all acidizing programs, a critical factor for success of the treatments is distribution of the acid between all productive zones. Since most producing wells are not homogeneous and contain layers of varying permeability, even distribution of the acid is a difficult task. This paper will present the results of approximately 55 high permeability wells from the Cantarell field in Mexico ranging from 1,000 to 6,000 md, which have been acidized using a novel acid diverter based on associative polymer technology (APT). This polymer inherently reduces the formation permeability to water with little or no effect on the permeability to hydrocarbon. Data from production logs from several of the treated wells will be presented which show excellent oil production distribution along the perforated intervals. In addition, production logs will also be shown for wells acidized with other diverters, such as foams and in-situ crosslinked acid, which showed poorer results.

As operators strive to increase production from existing reservoirs with depleted reservoir pressure, the use of under-balanced drilling and underbalanced horizontal drilling is becoming more widely used. One of the primary problems to overcome in drilling under-balanced is designing a circulating "fluid" that has an equivalent circulating density below the reservoir pressure. This paper discusses the mathematical equations used to design air drilled "under-balanced" wells. It will also show how these equations were used to design four separate wells. The presentation of actual field data will validate these equations and computer modeling used. (See Table 1) The four wells will include 1) 17,000 TVD well drilled into the Ellenberger formation with reservoir pressure at 1200 psig, 2) horizontal well drilled into the Petit formation at 5900 ft. TVD with reservoir pressure at 210 psig, 3) horizontal wells drilled into the upper Penn Formation at TVD 7800 ft. and reservoir pressure of 1000 psig., and 4) deviated wells drilled into the Ellenberger formation below 13,000 feet TVD and reservoir pressure of 600 psig. The mathematical equations used were developed by Dr. William C. Lyons of New Mexico Institute of Mining and Technology in Socorro, NM. Computer simulations for these wells were run by David Giffin on software developed by Boyum Guo and Dr. Lyons. Each of these wells was drilled using air drilling techniques. By measuring the pressure at both surface and bottom hole conditions, the validity of the mathematical models used has been established. Air or other compressed gas can be used to reduce equivalent circulating densities to accommodate almost any reservoir pressure.

This paper discusses the results of high volume submersible lift equipment (HVL) installed in a West Texas carbonate reservoir. Field-wide installation of HVL was made in a primary field in 1978 during the last stages of depletion. With a high capacity reservoir and a strong water drive, a significant increase in oil production was obtained. A reserve growth by HVL installation is documented with field results. Included is a historical overview of field installations with a post installation economic analysis and a summary of required facility revisions.

This paper presents basic data concerning the peripheral water flooding of three Haxbar sand reservoirs in the old Oscar field, Jefferson County, Oklahoma. The significance of reservoir data, its importance in interpretation of field conditions, operating procedures and resulting performance of the three reservoirs are discussed.

Fluid cleanup effects have hampered stimulation success in many tight, naturally fractured sandstone reservoirs. In some cases, cleanup problems affect not only short-term but long-term reservoir deliverability. The Wolfcamp intervals in Val Verde Basin, West Texas are tight, naturally fractured reservoirs and exhibit better responses to CO2 energized fluids than non-energized fluids. We will present data from a case study of several wells in the Wolfcamp intervals where 100% COz treatments have increased productivity in both initial and remedial applications. We will discuss how production was increased by 100% CO2 treatments in wells where non-energized and energized fluids were previously pumped. Then we will discuss treatments where 100% CO2 was effectively to propagate a fracture and transport proppant. An economic evaluation will be presented on the 100% CO2 remedial treatments in the Wolfcamp intervals. Finally operational concerns and the equipment set up for 100% CO1 and CO2 proppant treatments will be discussed.

This paper presents a field case history of a highly successful waterflood program in the Seven Rivers Sand (named Soma locally) at 1,000-1,700 ft. in Crockett County, Texas. The program has been completed and the project abandoned; consequently recover figures and performance are factual. They show that secondary oil recovery equaled almost three (3) times primary oil recovery.

The 600 acre Forest A. B. Gordon lease has produced 5,500,OOO bbl (9,167 B/A) of waterflood oil to March 1, 1966. This oil has been produced from the Yates formation and principally from, the Penn Bennett member. The primary recovery from this lease was 2,474,OOO bbl or 4,123 B/A, or a waterflood to primary ratio of 2.2 to 1. The A. B. Gordon waterflood is but one of many successful floods in the South Ward Field of southeastern Ward County, Texas, several of which have been reported on previously. It is the intent of this paper to review some of the information available at the start of waterflooding to see how reliable the various types of initial information would be in predicting waterflood response. Before going into these comparisons we will briefly look at the general character of the reservoir involved.

The ASR Hydro-Impact

Twenty-two sands in the Hewitt Field have been simultaneously flooded by the Exxon operated Hewitt Unit and a case history of the operations is detailed in this paper. A multiple sand waterflood project requires special optimization methods to improve oil recovery. Highlighted are the injection and production surveillance proTrams and optimization methods used at the Hewitt Unit. These include injection wellbore design, injection distribution, production stimulation, polymer augmented injection, and infill drilling. Successful application of these techniques has increased the ultimate recovery from this waterflood operation.

Water flooding is utilized extensively for oil recovery in the Permian Basin. Finding compatible and accessible make-up water can be problematic in some areas. In these situations, proper selection and application of scale inhibitors can enable the mixing of otherwise incompatible waters. This case study discusses the various methods used for product selection and application, including a testing methodology which can be used for direct measurement of scale inhibitor effectiveness and treatment optimization.

An analysis and economic evaluation of over 150 plunger installations in the San Juan Basin (SJB) has been made. The case study reviews performance and results of all installations, and clearly shows that plunger lift has significantly increased volumes and reserves. Best practices, screening criteria and design considerations are presented. Individual well results are presented in tabular form showing before and after rates. Economic analysis indicates plunger lift on these SJB wells is extremely attractive with average payout of installations in two months.

Virtually all west Texas wells possess, to varying degrees, conditions of internal and/or external casing corrosion. The majority of the corrosion problems begin when produced (or injected) fluids come in contact with the casing inner wall, or when formation fluids come in contact with the outer wall of the casing in areas not protected by adequate annular cement. Both internal and external casing corrosion problems can become more severe with time, and can, if not addressed, lead to premature demise of the well. In order to ascertain the severity of corrosion problems in any specific well, many wireline logging devices have been developed over the past several years. Basically mechanical/magnetic in makeup, quantitative interpretation from the classic tools depends largely upon assumption of unknowns that, in most cases, are very hard, if not impossible, to accurately identify. A new corrosion evaluation procedure developed by Schlumberger uses a uniquely different approach to the challenge of quantitative casing inspection. The technique uses full ultrasonic casing resonance information recorded with a modified cement evaluation tool. Using the CET* tool, all necessary casing inspection data can be recorded simultaneously with cement evaluation information. The waveforms recorded at each of the eight (8) radially spaced CET ultrasonic transducers can be analyzed to obtain the following information regarding the condition of the casing: - The specific internal geometry of the casing - An internal casing roughness profile. - A casing metal thickness profile. A derivation of the measurements obtained at each CET transducer will be presented followed by discussion of the currently available display presentations and casing imaging techniques. The specific utilities of the ultrasonic casing inspection technique will be highlighted by citing several examples from west Texas wells.

Casing inspection logs have proven to be an effective tool to help design and implement remedial operations during- waterflood redevelopment. A series of magnetic logging tools was run in a Tubb- Drinkard water flood located in SE New Mexico. The casing inspection logs qualitatively evaluated overall casing condition and indicated packer set points prior to conversion to water injection. In extreme cases, the logs discovered terminal casing damage requiring well abandonment. Many Permian Basin waterflood units have been infill drilled to reduce the pattern spacing. Older wells, some dating to the 30"s, are often converted to water injection to complete injection patterns. From the time a well is first completed, the casing wall thickness decreases. Corrosion, wear and physical damage combine to reduce the mechanical integrity of the casing, eventually destroying it. The casing inspection logging program has proven its value by substantially reducing workover costs and improving the success rate of injection well conversions.

When the drilling operation of an oil well is finished, an oil string of casing is left in the hole. In the early days, if the well would flow, it was allowed to flow through the casing. When it quit flowing, tubing was installed inside the casing. Oil was then pumped through the tubing with a working barrel and valves. The valves used leather cups with a ball check in the traveling and the standing valves. When this type pump needed repairs, it was necessary to pull both the rods and tubing to effect repairs on the pump. Then the rod pump came into use. This pumped was seated in the tubing and only the pump and rods were pulled for repairs to the pump.

Presentation of factors affecting casing pumps selection and application of casing pumps to high volume wells. Examples of successful applications are given.