The Horizontal Well Artificial Lift Consortium is now an official, funded project. The purpose is to develop an improved understanding of the issues for production horizontal oil and gas wells, especially where application of artificial lift is required.
The research is primarily conducted at the Univ. of Tulsa. There are currently 10 member companies with the number expected to grow.
This presentation will give an update of the status of the Consortium and the current research focus.

The oilfield adage that "you cannot hurt a good gas well or help a bad gas well" is not necessarily true. The new Horizontal-Spinner coupled with vast interpretation experience of temperature logs has revealed a number of completion problems that can be overcome. The gas source is not always where the perforations are placed and many perforations are not opened when treated. In deep gas wells the present formation logging tools do not properly identify the productive zones; and the present perforating and treating techniques do not create access to all the zones to be tested.

Field tests were performed to better understand the effectiveness of hot oiling to remove paraffin in downhole tubulars. In particular, the tests were designed to investigate the depth to which paraffin might be melted. The temperature decay following the end of the treatment, pump capacities, and heat loss assumptions were used to estimate the treated depths. The results indicated that annular hot oil treatments might be effective for paraffin wax that is very near the surface but the effective treating depth is very limited. In addition to the field testing, industry surveys of the perceived depth of effective treatment were collected. The results of the field tests compared with the industry survey suggest a dramatic problem of perception compared with reality. This disconnect may result in millions of dollars of expenditures that are ineffective or only partially effective. The field tests for a variety of tubular configurations indicated effective treating depths of less than 200 feet, compared with median perceived depth of 1,000 to 3,000 feet. The study also brought to light the seriousness of heat transfer losses from the hot oil burner to the wellhead before the process begins to start down the hole. In effect, the truck itself and injection line to the well act like giant
radiators that rob heat from the treating process. The results of the study suggest that alternatives to annular hot oiling need to be seriously evaluated if the artificial lift failure history indicates paraffin deeper than 200 to 300 feet. Furthermore, annular hot oiling during colder periods should be avoided altogether or otherwise very carefully designed and supervised.

The desirability of using a tubing anchor in a pumping well to increase effective pump stroke and to reduce wear on sucker rods, tubing and casing has been recognized for many years. It is well known that an unanchored tubing string "breathes" as a portion of the fluid load in the tubing is alternately transferred between the tubing and the sucker rods during the pumping cycle. The elimination of this movement of the tubing string by means of an effective anchor should provide obvious benefits to the operators of rod pumped wells. However, the use of tubing anchors in the past has, in general, given overall results that have been somewhat disappointing at best. In many cases there has been little or no increase in pump efficiency and rod and tubing wear have continued to reduce appreciably the operator's margin of profit.

The success ratio of squeeze cementing operations in the past has been poor. A lack of knowledge of downhole conditions and formation characteristics was partly to blame. Proper cementing materials for downhole conditions were not always available. Recent development of cementing materials and techniques has greatly improved the success ratio of squeeze cementing. New tools are available to provide a greater knowledge of downhole conditions to determine the existing problems in the well. New cementing materials have been developed so that a cement slurry can be tailor-made for each particular set of well conditions. Laboratory equipment is available now to stimulate downhole conditions in testing cementing materials in squeeze slurries. With the knowledge and materials available today a squeeze cementing job designed on the surface will, in most instances, perform down the hole.

An Operator/Pumper is typically expected to produce their assigned wells in a manner that results in a maximum allowable production rate at a minimum of cost. However, they must do so with the wellbore conditions, equipment, and operating environment they as assigned. This paper will present some tools and methods that the Operator/Pumper can utilize to help optimize a rod pump well.

The purpose of this paper is to discuss and emphasize the importance of the royalty owner to the oil industry and the direct effect which unfavorable owner relations has on your company's profit. This paper will be divided into six principle parts: (1) Introduction; (2) The importance of the royalty owner; (3) The landman's role in royalty owner relations; (4) The royalty owner's role as the company's constituent; (5) Ways of preventing adverse relations with royalty owners; (6) Summary.

This paper gives quantitative calculations of the effects of Carbon Dioxide and pressure on the solubilities of formation minerals in a West Texas brine. Increased pressure makes anhydrite and gypsum significantly more soluble. The solubilities of carbonate minerals are increased to a lesser extent. The presence of Carbon Dioxide causes large increases in the solubilities of carbonate minerals, thus exacerbating the scale problem. Carbon Dioxide will greatly reduce the pH of injected or connate water, but this undesirable effect is reduced by the buffering action of carbonate minerals. Because of this buffering action, common mineral scale inhibitors can be used in CO, floods. Increased dosage may be required because of the potential for more scale.

Gas and liquid are frequently transported simultaneously in the same pipe. Common occurrences include pipelines for gas and oilfields, piping in refineries and process plants, and steam injection and geothermal production systems. When two-phase flow (i.e. gas-oil-water) occurs in a pipeline, the phases separate geometrically in the pipe into various flow patterns. In general, the flow pattern that results depends upon several flow parameters, of which phase velocities and pipe inclination are the most important. When the flow pattern at the exit of a pipe consists of alternating slugs of gas and liquid (i.e. slug or intermittent flow). special operating procedures are frequently required. Processing such slugs can require first passing the gas-liquid mixture through a larger diameter conduit (i.e. slug catchers) to promote segregation or stratification of the phases. Only then can gas liquid separators be operated properly to minimize pressure fluctuations and assure an acceptable low volume fraction of liquid in the gas or gas in the liquid that leaves the separator. The cost of constructing and locating slug catchers can be extremely high, especially when dealing with large diameter pipelines terminating on offshore platforms. A method to eliminate long slugs of liquid economically is of great interest to companies operating the above types of facilities. It has been found that slug flow in a pipeline-riser pipe system can be eliminated or minimized by careful choking that results in little or no change in either flow rate or pressure level and elimination of pressure fluctuations. The careful choking can be accomplished automatically with a unique control system consisting of a combination of electronic and pneumatic devices. Such a system has been tested using kerosene and air on a 2-in. diameter pipeline-riser pipe test facility at Tulsa University). Slug-flow was eliminated automatically in every test conducted. The devices were also installed in a specially designed facility consisting of approximately 60,ft of 1-in. pipe configured with several rises and falls to simulate a hilly terrain pipeline. Slug flow was eliminated here also in every test conducted.

When designing a Production Facility, many engineers and production foremen are confronted with a multitude of codes, standards, best practices and even OSHA requirements. Often, the facility design is based on old outdated codes, standards, or practices. Lack of proper engineering design can lead to equipment failure, lost production, human injury or harm to the environment.
The safety of a facility is a direct function of how the facility is designed. The oil and gas industry has produced many codes and standards, which were developed primarily in response to incidents that had occurred. Understanding and learning how to apply the various codes and standards can greatly increase the operability and safety of facilities.
This paper reviews the key area of facility design that is critical to a safe facility. The paper explains how the different codes, standards and best practices can be used to develop safe and cost effective facilities.

The author developed a computerized technique for sucker rod system design that attains the pumping mode with the lifting efficiency being at a maximum. This optimum pumping mode gives the most economical combination of plunger size, stroke length and pumping speed. The proposed design procedure applies to conventional pumping units and assures minimum energy usage for the production of the required liquid rate to the surface. The method presented in this paper involves designing of the rod string for each pumping mode used in the process of selecting the optimum mode. This is an important new feature, compared to previous investigations that relied on published taper lengths. The determination of pumping parameters (plunger stroke length, pumping loads, etc.) is affected by the physical characteristics of the rod string. However, string design requires the knowledge of the pumping mode: plunger size, stroke length, pumping speed. Therefore, the selection of an optimum pumping mode is an iterative process, for which a detailed solution is given in the paper.

Throughout the world the most common method used to artificially produce wells is through the means of sucker rod lift. Low producing efficiencies caused by incomplete pump fillage is the most common operational problem experienced by these the sucker rod lifted wells. Incomplete pump fillage is the result of having a pump capacity that exceeds the production rate of the well or having poor gas separation at the pump intake and a portion of the pump capacity being lost to gas interference. More efficient operations and lower cost will result, if these wells are operated with a pump filled with liquid. To operate with a full pump requires the elimination of any gas interference in the pump and requires controlling pump run time so the pump displacement will match the inflow of liquid from the reservoir into the wellbore. Periodically the operator must monitor the wells operations to insure that the pump has no mechanical problems and efficient operations are maintained as all the available liquid is produced from the wellbore.

Sucker rod breaks have been extensively studied and documented in the oil industry. Polished rod failures, on the other hand, have not received as much attention. As a general rule, operators seem to be more tolerant of polished rod failures. But polished rods fail for reasons that can be controlled. The purpose of this paper is to identify these reasons and to discuss ways to minimize polished rod breaks. Almost without exception, the polished rod is the strongest component of the rod string. It has the largest cross-sectional area and its material strength is at least equal to that of the sucker rods. Yet in many cases, polished rods fail with regularity while the sucker rods do not. Surface pumping equipment can induce destructive stresses in polished rods. By analyzing polished rod failures, which usually occur at the bottom of the polished rod clamp, useful conclusions can be reached about these stresses and what can be done to control them.

Hydraulic pumping systems for oil wells have been in existence since 1932. High-pressure power fluid (produced oil or water) is supplied to a
subsurface engine-pump assembly. The power fluid exhausted from the engine is returned to the surface along with produced fluids from the well. The earlier hydraulic systems employed one or more highpressure pumps on the surface to furnish power fluid to one or more wells. Large tanks were used to settle out water and solids from power oil.

Availability of CT as well known OCTG and the need to have new options on artificial lift prompted a CT consulting firm to investigate the use of CT to convey well fluids to the surface. While numerous test proved that CT as "hollow sucker rods" can replace conventional sucker rods and production tubing, the lack of appropriated coil tubing units to deploy and retrieve CT economically delays the application of this innovative option. The paper will discuss new CTU designs and economics related to the use of CT versus solid sucker rods, and the latest developments in artificial lift with coiled tubing. This paper will describe laboratory testing, field application methods and case history results of the application of salt inhibiting treatments in several applications.

Availability of CT as well known OCTG and the need to have new options on artificial lift prompted a CT consulting firm to investigate the use of CT to convey well fluids to the surface in oil and gas wells.The first idea consisted of a stationary CT attached to a modified rod pump to convey fluids to surface by the use of hydraulic pulses. This first approach triggers a second idea consisting in the reciprocation of CT as hollow sucker rod in rod pumping wells. Numerous tests for diverse applications are being performed with results to be covered in this paper.Because of the consequences of these innovations, another idea was tested, this time to reciprocate a subsurface pump capable of using the full cycle of the pumping unit with either conventional rods or CT. Latest field test results are part of this paper.

Recent innovations and repeated successful applications using the multiple patented PAL PLUNGER casing plungers suggested extending the applications to stripper gas wells that produce from multiple production zones and/or from wells with casing having obstructions that restrict proper placement of down hole landing stops. The new HYBRID CASING PLUNGER, successfully installed and retrieved using a standard swab rig, removes well bore fluids from multiple production zones. The standard PAL PLUNGER was coupled with a unique down hole compression packer and fluid isolation assembly to permit well bore fluids to be lifted by gas flow to above the packer and subsequently removed from the well bore on the next plunger cycle. Bottom hole pressure data obtained shows the hydrostatic gradient to be that of the "dry" gas section of the well bore above the standing fluid level. Production data shows an increase in fluid removal and daily production rates.

This discussion is primarily concerned with the operating control of the bottom hole pump of the hydraulic pumping system. Design and engineering calculations are purposely omitted, as well as any discussion concerning operation and maintenance of the surface power pump. In short, the purpose of this discussion is to suggest procedures for operating hydraulic bottom hole pumps and to show that with hydraulic pumping, the operator has an exceptionally fine tool for defining well problems.

In 1949, the first commercial hydraulic fracturing treatment was performed, thus initiating one of the most outstanding well stimulation procedures that the petroleum industry has ever known. During the past 16 years, much advancement have been made in the concepts of hydraulic fracturing theory. The purpose of this paper is not to clarify the concepts of hydraulic fracturing theory, but to present a sound design method of effectively employing the concepts. Discussion of theory will be confined to only that necessary to justify the method of design. The design procedure presented in this paper is limited to vertical fractures and presents a method of optimizing fracture treatment sizes.

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.