The Shafter Lake San Andres Unit was formed on July 1, 1967, and water injection was initiated in August, 1968. Prior to the start of water injection, an extensive stimulation program was undertaken to increase current production from the unit wells and to prepare them for flood response. Since the initiation of the stimulation program in September, 1967, a total of 40 hydraulic fracturing treatments have been performed on 38 wells using lease oil, refined oil, and salt water as fracturing fluids. Of the 40 fracturing treatments that were conducted, lease oil was used on five treatments, refined oil was used on 13 treatments, and salt water was used on 22 treatments. The investigation described in this paper was undertaken to determine the relative effectiveness of oil-base and water-base fracturing fluids used in the 40 fracturing treatments and to evaluate the overall results of the entire fracturing program. To accomplish the above objectives, it was necessary to evaluate the design criteria and treatment procedures employed in the fracturing treatments and to describe the prefractured quality of the wells that were fractured. A detailed investigation of each fracturing treatment and two computer programs, one for designing hydraulic fracture treatments and one for determining well reconditioning economics, were used in attaining the objectives.

Hydraulic fracturing, the most widely used well stimulation technique, is a prime example of a process developed by industrial research. This process, which was commercialized in 1949, has grown from a small, simple well treatment to a highly sophisticated well stimulation technique. The total wells fractured in the United States and Canada exceed 450,000 with approximately 2,200 treatments currently being conducted each month. Through proper engineering and application of the process, the recoverable oil reserves have been increased an estimated seven billion barrels.

Hydraulic fracturing of wells in naturally fractured reservoirs can differ dramatically from fracturing wells in conventional isotropic reservoirs. Fluid leakoff is the primary difference. In conventional reservoirs, fluid leakoff is controlled by reservoir matrix and fracture fluid parameters. The fluid leakoff rate in naturally fractured reservoirs is typically excessive and completely dominated by the natural fractures. Historically, attempts to fracture-stimulate wells in naturally fractured reservoirs have been unsuccessful due to high ieakoff rates and gel damage. The typical approach is to attempt to control the leakoff with larger pad volumes and solid fluid loss additives. This approach is not universally effective and can do more harm than good. This paper presents several field examples of a fracture stimulation program performed on the naturally fractured Devonian carbonate of West Texas. Qualitative pressure decline analysis and net treating pressure interpretation techniques were utilized to evaluate the existence of natural fractures in the Devonian Formation. Quantitative techniques were utilized to assess the importance of the natural fractures to the fracturing process. This paper demonstrates that bottomhole pressure monitoring of fracture stimulations has benefits over conducting minifrac treatments in naturally fractured reservoirs. Finally, the results of this evaluation were used to redesign fracture treatments to ensure maximum productivity and minimize costs.

Fracture azimuth, directional permeability trends, overpressured water zones, poor cement quality, depleted production intervals... all major concerns when hydraulically fracturing in mature waterfloods. Mature watertloods, such as those found in the Permian Basin of West Texas, present reservoir and production considerations not normally associated with primary recovery. After 30 or more years of waterflooding, pressure characteristics, fracture tendencies, and reservoir fluid properties can be altered. Fracture orientation, vertical and area1 sweep efficiency, altered stress conditions, poor cement and casing quality, and large perforation intervals all affect hydraulic fracturing in mature waterfloods. This paper will address current hydraulic fracturing terminology, design considerations of all hydraulic fracture treatments, and discuss those issues unique to secondary recovery.

Hydraulic lift performance of the Getty Oil Company McKnight Lease in the Headlee (Ellenburger) Field, Ector County, Texas is the topic of this discussion. Original artificial lift was by gas lift followed by fixed casing hydraulic pumps. Excessive operating costs due to the lack of gas availability resulted in a search for other means of artificial lift. The selection of hydraulic pumps resulted in reduced operating costs. Further evaluation of well capabilities led to the installation of additional surface HP and increased production. Also to be discussed is a unique method of power oil treating for salt and iron sulfide removal.

Phase I for the hydraulic pumping method of artificial lift was the initial development of the first commercially successful hydraulic pumping installation in 1932. Phase II followed with the introduction of the "free pump" in 1948. Phase III covers the relatively recent development of the unitized, skid-mounted Power Fluid Conditioning Unit which was conceived in 1969 and placed on the market in 1970. The acceptance of the concept of using a PFCU for taking well fluid and making it suitable for power fluid had resulted primarily from overcoming the disadvantages of the established central system concept - specifically, the high cost of treating and storing power oil combined with cost of long, high-pressure power oil lines. The "Unidraulic" Hydraulic Pumping System eliminates these disadvantages by moving the power fluid system back to the well site. The Power Fluid Conditioning Unit removes solids from the produced well fluid with a cyclone separator. The cyclone converts the pressure energy of the fluid into centrifugal force to increase the settling velocity of the suspended solids. These solids are carried by the force to the discharge point at the bottom of the cone. The liquid phase, being lighter, moves upward in the cone as a spiraling vortex to the liquid discharge connection at the top of the cyclone. Solids-free power fluid, either water or oil, from the reservoir provides suction to the multiplex pump which returns the power fluid at the required pressure to the wellhead to again operate the subsurface production unit to start the lift cycle all over again. Lease treating facilities are needed to process and treat only that volume of oil, water or gas that is actually produced from the well; the same as for a sucker rod pumping well. Therefore, well testing procedure is performed exactly as a sucker rod pumping well.

During the past eighteen years the hydraulic long stroke pumping unit has made an ever increasing entrance into the crude oil production picture. In 1939, two hydraulic long stroke units made their appearance in the oil fields. In the early days of the hydraulic unit, as is true with other new types of equipment, there was a great deal to be learned by the manufacturer's as well as the operators. Often the operator of the early hydraulic long stroke unit felt fortunate if he had a four or five day trouble free period. Nevertheless, the deep wells with high volumes presented problems to the producers which they realized had to be solved.

This presentation concerns the theory, design, and application of hydraulic pumping for deep single and multiple slim hole completions. More specifically, the operational problems that are inherent with this type of system will be discussed, along with the practical solutions that have been field tested and have proven successful.

The hydraulic method of artificial lift has traditionally offered creative solutions to operators faced with a wide array of producing problems. A long history of equipment and application development has brought today's hydraulic pumping systems to a status of unique adaptability to varied application requirements with reliable operating performance. This update on the capabilities of the hydraulic system will review system hardware and describe installation and operating characteristics which account for the versatility of this lift method. Examples of application flexibility are discussed, including installations for horizontal completions, hydraulic lift powered from the water flood injection plant, wireline set hydraulic pumps in existing wells and well testing.

This paper discusses new hydraulic equipment which reduces maintenance, increases simplicity at lower costs and improves operation. Presentation includes demonstration of a hydraulic unit installed on a "dummy" well-head, and placed in operation. The complete circuit is visible through use of clear plastic materials.

Hydraulic pumping systems have been around for a while now, but in the past they have underperformed against mechanical beam pumps. With improvements in drive and control technology, hydraulic pumping systems are now able to outperform beam units. They have achieve higher speeds without putting added stress on the rod string by optimizing the velocity profile of the actuator. Because the prime mover and actuator are mechanical linked on a beam pump, the velocity profile of the actuator is a sinusoidal; however, the prime mover and actuator on a hydraulic system are not physically connected, so the profile is able to be optimized. Additionally, their speeds and strokes can be easily adjusted with he push of a button, their footprint is much smaller, and there are no safety concerns because there are no external moving parts.

A recently developed hydraulically operated (HO) stage cementer has proven beneficial in cementing both vertical and horizontal wells. Although the tool was developed primarily to aid in cementing highly deviated and horizontal wells, its application in any situation calling for a stage cementer can be beneficial. 1. In operations where a free-fall opening pluq (bomb shaped) is normally used, the waiting time for free fall to the plug seat is eliminated, saving rig time and allowinq for continuous circulation of the hole. These cementers can be opened immediately, which is beneficial in those applications in which first stage cement is brought above the cementer. 2. If a displacement plug (pump down style) is normally used, the need is eliminated for excess cement in the casing to ensure that the first stage is not over-displaced, saving drill out time after cement is set. In this configuration, a positive check of float equipment for secure holding can be made. The cementer is designed to monitor annulus pressure and internal pressure. When internal pressure reaches a predetermined level above annulus pressure at the tool, the cementer opens and circulation begins for the second stage. The cementer is closed by a conventional closing plug. This paper presents discussion of HO stage cementer operation, options available with the cementers, job design , and results of actual job conduct using these methods.

With the trend toward more stringent clean air legislation moving at a rapid pace the industry may soon be faced with the problem of totoal vapor recovery. This presentation will review the types of equipment which have been developed to meet these requirements.

Hydrophobia, apart from the disease connotation, means fear of water. A Seldom mentioned fact of metallurgy is that there are "Hydrophobic" metals and alloys whose very nature is to resist wetting by water. As a corollary, these same surfaces aggressively wet with oil and will maintain themselves oil wet in an oil/water flow stream by attracting oil out of the flow stream while repelling water. Since mineral scale deposition comes from the water component and not the oil, there will be a tendency for it to aggregate in the flow stream and be swept out in the flow stream. Thus the system environment, being the oil/water mixture in the flow stream can be utilized to assist in solving scaling problems, particular at pressure drops and other scaling nodes. Examples will be presented wherein high energy ion deposited thin films of hydrophobic metals and alloys have been shown to resist scale formation while providing dry metal lubricity in a variety of actual installations. In many cases, the formation of scale on a moving rod operating through an elastomeric seal will cause the seal to fail, resulting in the discharge of fugitive emissions to the environment. It has been demonstrated conclusively in many field applications involving stuffing box rubbers and lease motor valve stems that scale can either be prevented entirely or have its adhesion reduced to the point where an elastomeric seal will rub it off. The cost of such films is quite low and the economic benefits to the users in terms of increased service life alone make their use cost effective even without regard to the far more valuable consideration of reducing the incidence of and clean up costs associated with releasing fugitive emissions.

Most folks in the oilfield are true experts in their field. They are, for the most part, good thinkers with original ideas that when properly conveyed bring value to both the inventor as well as the industry. Our industry needs new ideas. The majority of innovative ideas come when a person doing his/her job realizes there is a better way to accomplish a task. However, a good idea is nothing more than a dream until it is born. This paper deals with the capturing and documenting of ideas and what to do with them. Topics covered are: What is patent protection? How does one know if the idea is unique or novel or is patentable? How does one protect his/her idea? Who owns the idea? What are the general costs involved? When does one cross the infringement line?What web sites are available to help develop and protect one's ideas?

The extreme under-balanced (EUB) perforating technique has proven effective in deep, low porosity and low-to-medium permeability formations. The state-of-the-art scientific software for perforating performance modeling (PPM) can be effectively used in predicting the perforation performance in a wide variety of scenarios and to compare actual post-job details to make decisions according to economic benefits for various perforating techniques. As with any software modelling, a good grasp of the reservoir rock properties and fluid properties are essential as input parameters. The success of the EUB perforating performance and the capability of the PPM to successfully predict the well deliverability has increased confidence in effective candidate selection. Predictions from the PPM are within +/- 10% of the measured post-job results observed. The paper presents various cases that show how effectively and economically these deep sandstone formations can be completed to maximize the return on investment (ROI) and the rate of return (ROR).

By compiling foreman's costs in a West Texas field, a method was determined for identifying problem wells and keeping a close liaison between field personnel and engineers in the office. Plots of marginal water and oil production as a function of both oil price and pulling costs were generated and used by field personnel and engineering for identifying unprofitable wells.

The first hydraulic fracture treatments in the Sprabeny Trend consisted of 1500 gallons of refined oil carrying l/4 lb per gallon of sand. Since then, the average size of hydraulic fracture treatments has increased significantly to 180,000 gal of fluid and 432,000 lb of sand. The indication from a detailed characterization of the reservoir suggests that in certain cases an increase to over 900,000 lb of sand may be justified to maximize rate of return on investment. This should be combined with limited interval perforating and forced closure to ensure successful execution. Justification for these recommendations will be provided with an integration of the reservoir characterization and 3-D hydraulic fracture simulators.

Wells are produced via rod/pump with generally an oil to water ratio of less than 1:4 being experienced. Under these conditions, it is generally accepted that a "water wet

In drilling applications the two most common drive mechanisms are rotary and the positive displacement motor (PDM), each of these having been employed for over a century. The theory behind PDM's is to increase the amount of mechanical power at the bit using the drilling fluid to generate power. This has proven to be a very efficient means of drilling.There is another drive mechanism that is commonly disregarded, the turbodrill. Turbodrills operate on the same principle as PDM"s, by using the drilling fluid to generate power to drive the bit. Having been used in the oil and gas industry since the 1950's the turbodrill is still relatively obscure and many applications where it could be used are simply overlooked. This paper provides the history of turbines, guidelines for identifying applications where turbines can be beneficial in the drilling operation, and recent case histories in the Rocky Mountains.

Ignition systems for initiating in situ combustion are reviewed with emphasis on electrical ignition and gas flame ignition. Related surface and down-hole equipment are discussed in detail, as well as the mechanical completion features of ignition wells. Typical ignition operations are discussed and techniques for detecting ignition are presented.

A pipeline efficiency value of 90% is routinely used as a "rule of thumb" to estimate the production costs associated with gas-gathering systems. The 90% efficiency is appropriate for the development of new gas fields. However, conditions in mature or developing gas fields can dramatically reduce pipeline efficiency and gas-gathering system capacity. These conditions are often overlooked until a significant reduction in daily production has occurred. In order to understand the problem, field conditions that reduce the pipeline efficiency of a gas-gathering system are reviewed with respect to changes in gas production. A field study was performed to identify and correct conditions that reduce gas-gathering system efficiency. The impact of field conditions on line efficiency is examined through computer simulation. Finally, the field study is reviewed in order to show how an increase in line efficiency impacts production and reserves.

The example is from a subsea infrastructure that was experiencing flow assurance challenges due to both hydrate and paraffin formation. The condensate had a paraffin content of 14.5 wt%. Paraffin control chemicals were being deployed with limited success. This paper gives a detailed description of the flow assurance root cause failure analysis in a Gulf of Mexico production system that was experiencing severe hydrate and paraffin failure. Details are given on the experimental work performed to develop new products, as well as results of the field applications. The paper summarizes the implementation and ongoing monitoring of this program in the field and provides lessons learned. Details on the cost savings created in reduced operations and chemical overhead for the operator are given, along with the value savings due to no lost production since blow downs were no longer required.

The Tertiary Oil Recovery Project (TORP) at the University of Kansas has been in existence since 1974. The Project is state supported and was established to conduct research on enhanced recovery processes which are applicable in Kansas and the Mid-Continent area. TORP has been investigating gelled polymer technology, which was developed to improve sweep efficiency in waterflooding and other displacement processes. The technology has been tested in several field pilot projects in the State. A number of these have been conducted as cooperative ventures between independent operators and the University. In this paper, the technology and its application in several fields are described. The manner in which the cooperative efforts have been undertaken are discussed.

Currently downhole cards can be computed from surface cards by solving the one dimensional damped wave equation with finite differences and an iteration on the damping factor or dual iteration on the damping factors. The one dimensional damped wave equation only takes into consideration friction of a viscous nature and ignores any type of mechanical friction. However, when dealing with a deviated or horizontal well, the mechanical friction in between the rods, couplings and tubing is no longer negligible. In this paper, the modified Everitt-Jennings code is further extended to incorporate mechanical friction and accommodate deviated wells