A case study was conducted on San Andres Formation wells to evaluate the benefit of focused efforts to optimize hydraulic fracturing treatments for improved well productivity. The application of conventional fluids and techniques had provided lower than expected post-treatment productivity and a rapid decline rate, suggesting that fracture conductivity was less than optimum. Several recently introduced hydraulic fracturing technologies were combined to develop an integrated treatment design and application package to improve well production. Included among these were real-time fracture treatment analysis, advanced mini-frac analysis, the use of state-of-the-art fracturing fluid and breaker chemistries, and the application of resin-coated sands and forced-closure techniques. Average incremental production was significantly increased through application of the new technologies. The effectiveness of the modifications in design, chemistry, and application is clearly demonstrated by the production improvements.

In the present state of the oil and gas economy, operators have been searching for ways to increase production and cash flow with no gamble and with an AFE expenditure that gives their money back and a good return on their investment the first year.Operators are finding that one sure way to increase production and cash flow on producing wells is to relieve the RESTRICTING BACK PRESSURE on the producing formation on wells which respond to this technique. This restricting back pressure is caused by a combination of several things; a direct result of the sales line pressure; the pressure required to operate the separator; the line friction from the separator back to the well head. These flow lines vary in length and the longer the flow line and the terrain they follow, the more back pressure you will find at the well head. The final results of this back pressure translates all the way down to the face of the formation and restricts its ability to give up oil and gas. Pressure requirements to operate an individual lease may vary, but the negative effect of production is the same - IT IS RESTRICTED.

The increasing recognition of Plunger-Lift as a viable method for producing many wells, has brought a number of changes to the technology involved. The importance of proper plunger-lift performance criteria (as reported in an earlier SPE paper) has been recognized and steps taken to incorporate this information into modern day control systems. This paper discusses the usage of plunger velocity in establishing operating cycles for gas wells and for oil wells. When used in conjunction with state of the art electronic microprocessors, the results are increased Production, extended economic limits, less downtime, and many others. This has been proven to be the case in both conventional and slim-hole wells. Primary areas of discussion are: 1. Relativity of plunger velocity insofar as efficiency is concerned. 2. Standard approach historically taken to achieve maximum production. 3. New software design that automates cycle changes while increasing production and reducing both man hours and down time. 4. Test results and case histories.

Removal of emulsified oil from waste water is receiving renewed attention in light of best practical control technology and treatment level requirements. This paper presents a discussion of the induced-gas flotation process as a method for cleaning waste waters by removing suspended contaminants using, froth floration. The origin of the process is briefly reviewed and a comparison is made to dissolved-air flotation showing that the two processes have both similarities and differences. A method of inducing and dispersing gas bubbles into water with individual cell mechanisms is discussed. Consideration is given to both the hydraulic and chemical characteristics of the stream. The complete flotation machine incorporating multiple cells in series is assessed from the mechanical design standpoint. The operation of induced-gas flotation equipment is explained. Consideration is given to the interrelationship of various design and operational aspects of this process. Both the importance and the limitation of chemical treatment additives are pointed out. A bench test method for selecting chemical treatment is discussed with a critical review of its ability to predict scale-up unit performance and the chemical formulation and volume requirements. Review of past oilfield experience with induced gas flotation machinery, shows that this is a viable method for cleaning produced water of suspended oil and solid particles.

Separation of oil and water has been important in crude oil production historically. Some oils and produced brines do not mix with enough stability to seriously complicate handling. Water in oil emulsions are more common than the oil in water type, often called "reverse emulsions" or "O/W"S". We will see, however, that there are problems in clarifying produced water, or more specifically removing trace amounts of suspended oil and solids from this water. This discussion will bear upon resolving the more stable dispersions of oil in water that are encountered in oilfield production practice. Therefore, it will concern clarification of that water by several methods including the induced gas flotation process (IGF).

The most valuable assets held by any company are the men and women who do the work. The job of properly defending these assets equals, or transcends, all other responsibilities of supervisory personnel. Responsible industrial organizations recognize the economics involved in protecting employees and are seeking individuals with ability to promote safety.

Statistics demonstrate that there is big money in oilfield theft, approximately half a billion dollars yearly. Yet, most operators would be hard pressed to itemize their actual assets or verify ownership of stolen or lost equipment. This paper discusses the lack of internal control prevalent throughout the petroleum industry and identifies, through initiation of company policy and procedures, methods to both minimize oilfield theft and maximize cost-effective loss prevention accountability.

Waterflooding concepts in carbonate reservoirs of West Texas and New Mexico have changed drastically in recent years. The original flood designs for many waterfloods called for peripheral water injection with minimal interior injection. The use of generalized geologic correlations or averages of rock properties in the design and execution of these projects led to delayed and inefficient flood response. Review of these drive projects, particularly with a more precise geologic definition, led to the conclusion that closer-spaced, more regular flood patterns would be necessary to enhance ultimate oil recovery.

Infill drilling in conjunction with waterflooding is being used to accelerate production and improve recovery efficiency. Many authors have discussed the reasons for infill drilling and the factors which affect the success of an infill drilling project.I,2,3,4,5,6 Reservoirs are heterogeneous rather than homogeneous. Van Everdingen1 related this to spacing and infill drilling. He noted that the East Texas field has been developed on a five-acre spacing. Recovery in this field with close spacing will be about 87% whereas other fields usually average 30%. He studied a number of fields, both carbonates and sandstones, and noted that recovery efficiencies improved as acre-spacings decreased. Barber et al2 discussed the carbonates in West Texas. They reported that the reservoirs were found to be more discontinuous than originally thought as more wells were drilled. In the Fullerton Clearfork Unit infill wells were drilled and some producers were converted to injectors. The infill wells produced higher rates with lower water cuts than the offset wells. This was interpreted as additional pay being opened up with some of the pay not having been flooded. Thus, infill drilling increased reservoir continuity which they defined as the percentage of pay that is continuous from one well to the next. Driscoll3 reported on the factors affecting increased recovery after an infill drilling project. The one which ties in with our study is minimizing lateral discontinuities. Often a producing section will contain many pay zones which are vertically separated. In addition, these zones are often not continuous in a lateral direction. Closer spacing increases the percent of continuous pay.The discontinuities are particularly evident in carbonates. This is also evidenced by the waterflood pattern used with a reservoir. Ghauri et al note that in the West Texas Denver Unit initially a peripheral injection was used. However, because of the discontinuous zones, much of the reservoir was not being flooded. According to Stiles5 there are three requirements for a pay zone to be successfully waterflooded: a) Continuous and homogeneous between injector and producer b) Injection supported c) Effectively completed in offset producer. Obviously, discontinuous zones will have some difficulty meeting the first and third requirements. George and Stiles reported on the Robertson, Fullerton and Means fields They noted that these fields have many porosity stringers over several hundred feet of thickness. Some of these stringers are continuous over several thousand feet while others extend only a few feet. Rarely does one stringer cover the entire field. In addition, thicker formations such as these are more apt to have several permeable layers.

This paper presents oil-water inflow performance relationships (IPR) for water drive reservoirs above the bubble point. A wide range of rock and fluid properties, relative permeability curves and initial water saturations has been considered. The effect of a skin region around the wellbore is also included in the analysis. The general theory and application of pressure-production relationships have been discussed.

This paper presents oil-water inflow performance relationships (IPR) for water drive reservoirs above the bubble point. A wide range of rock and fluid properties, relative permeability curves and initial water saturations has been considered. The effect of a skin region around the wellbore is also included in the analysis. The general theory and application of pressure-production relationships have been discussed.

Over 40 years ago, the late President Hoover set forth a creed which is perhaps even more applicable today than when he said: "It is only through the elimination of waste and the increase in our national efficiency that we can hope to lower the cost of living, on the one hand, and raise our standards of living, on the other. The elimination of waste is a total asset. It has no liabilities."" This is the creed by which we in the oil industry are trying to live when we attack the problem of corrosion losses or waste in oil and gas producing equipment. A cynic might say that we in the chemical industry are merely trying to increase our sales and profits while you in the producing industry are merely trying to reduce your lifting costs thereby increasing your profits. Such a statement would be true, of course, and what better way is there to "increase our national efficiency?"

The Injecta-Box

The Iatan East Howard Field is located in eastern Howard County, Texas. Production is commingled from the San Andres, San Angelo and Clearfork zones. Pressure support in the field is provided by waterflood. Injectivity into these zones was poor due to the buildup of iron sulfide and biomass. Several methods were used to cleanup this buildup. The first method used was to cleanout the wellbores with 15% acid and 14% sodium hypochlorite (bleach), utilizing a coiled tubing unit. The second method was to pump bleach and acid into the injection system, which would in turn be pumped down the wells. The third method was to cleanout both the surface and downhole lines with 3000 parts per million (ppm) chlorine dioxide (CL02) and 15% NEFE acid. The relative benefits and costs of these three methods is discussed. This work was performed when ARC0 Oil and Gas (ARCO) operated the properties. In the fourth quarter of 1992, Anadarko purchased APCO's interest in the properties. It is not the objective of this paper to discuss the chemistries and chemical reactions involved with these methods. Those can be found in numerous places in the literature. The objective is to communicate the procedures involved, the costs, and the benefits.

An innovative patented casing plunger offers production increases in Panhandle reservoirs. Several years ago, casing plungers were introduced to Panhandle oil & gas reservoirs. While several applications responded well, others were limited by wellbore conditions and reservoir fluids. Those problems have been addressed in a recently patented casing plunger, providing substantial increases in daily production and recoverable reserves. Design details, working models and producion data will be presented to encourage broader applications of casing plungers as reserves and bottom-hole pressures continue to decline. Current applications have been successful in all weights of 4-1/2" casing tapered strings common in Upper Anadarko Basin. Wellbore fluids of all combinations of oil, gas, condensate and water have been produced with the new casing plunger. Applications for 5-1/2" casing are also presented. Reasonable installation costs and recoverable tangible assets can be expected.

During the de-watering phase of typical Black Warrior Basin coalbed methane wells, an artificial lift method is needed to produce large volumes of water yet. have the ability to handle a moderate amount of produced solids such as coal fines and frac sand. In response to this scenario, the Coleman Pump Company developed a free style jet pump with a design specific to the problems encountered during coalbed dewatering operations. The unique design of flow passages in the pump allows retrieval of a very small portion of the pump while still providing a greater than normal flow capacity. In addition. the pump does not utilize any downhole moving parts which proves advantageous in a high solids environment to reduce workover expense. Meridian Oil applied the above technology to a test well in the Black Warr Coal Project. In this well, the pump was placed in the conventional or Basin threaded production tubing using a coiled tubing conveyed, concentric string, installation technique. This allowed the coiled tubing to be utilized as a power fluid path while water and gas were separated downhole and produced to surface independently through the dual annular spaces created by the concentric design. This design also provided for easy placement and retrieval of the throat and nozzle portion of the pump by using surface pump pressure. This design package provided a significant increase in water rate which resulted in an accelerated gas production rate and an overall increase in profitability for the well.

To gain a better understanding of the significance of insert rock bits in today's drilling, it is important to review the evolutionary process of the entire rock bit development. Modern-day rock bit technology began in 1909 with the introduction of the first rotary cone rock bit. Prior to this time, the use of the rotary drilling process had been limited to soft formations because harder formations were difficult or impossible to drill using the scraping action of the drag bit. The rotary cone bit, then, enabled the industry to drill much harder formations than previously possible. However, the early designs utilized cones which did not mesh. Consequently, the bit "balled" up" readily when drilling soft shale formations. In 1925, this problem was solved with the introduction of a two-cone bit with intermeshing teeth. As the teeth of one cone passed through the grooves of the opposite cone, accumulated formation was pushed from the grooves of the opposing cone; thus, it was called "self-cleaning." The new cutting structure enabled the drilling industry, for the first time, to make hole through both soft and hard formations with a single bit, markedly reducing overall time on each well. Until 1932, the basic bearing of rolling cutter bits remained the journal-type. Many attempts were made to effectively lubricate the bearing and extend bit life. However, none were effective, and bearing life remained extremely short until the introduction of anti-friction (roller) bearings in 1932.

National-Oilwell is the Distributor for a newly patented line of Insertable Progressing Cavity Pumps. This new technology allows the producer to install and remove both the rotor and stator with the sucker rod string. The tubing string contains a down-hole seating assembly attached to the bottom, which stays in place until the tubing is removed from the well. The improved efficiencies and state of the art elastomer materials are all combined to significantly reduce the lifting costs for today's producer. These pumps have the ability to move many different fluids including: oil, water, high viscosity fluids, and fluids containing solids such as sand, coal, or formation fines.

The Downhole Dynamometer Database is a compilation of test data collected with a set of five downhole tools built by Albert Engineering under contract to Sandia National Laboratories. The downhole dynamometer tools are memory tools deployed in the sucker rod string with sensors to measure pressure, temperature, load, and acceleration. The acceleration data is processed to yield position, so that a load vs. position dynagraph can be generated using data collected downhole. With five tools in the hole at one time, all measured data and computed dynagraphs from five different positions in the rod string are available. The purpose of the Database is to provide industry with a complete and high quality measurement of downhole sucker rod pumping dynamics. To facilitate use of the database, Sandia has developed a Microsoft Windows-based interface that functions as a visualizer and browser to the more than 40 Mbytes of data, The interface also includes a data export feature to allow users to extract data from the database for use in their own programs. Following a brief description of the downhole dynamometer tools, data collection program, and database content, this paper will illustrate a few of the interesting and unique insights gained from the downhole data.

Despite preventive measures taken during the manufacture of oil field tubular goods some defective lengths are produced. Other lengths become defective as the result of damage occurring during shipment or handling, or because of service conditions to which they are subjected. Failure to detect and properly dispose of these defective lengths before failure occurs has and can become costly and dangerous.

Illustrates the installation of a free type tandem dual zone hydraulic pump. Presents operation and design of special equipment required.

A Reda pump is essentially a multistage centrifugal pump, the shaft of which is directly connected through a protector section to a submergible electric motor. The entire assembly, as a unit, is of such outside diameter that it can be installed in wells completed with standard size casing. In operating position, the unit is suspended on tubing, submerged in the well fluid, with a cable from the surface supplying electricity to the motor. The installation may be for any depth since the unit is designed to function under any submergence pressures encountered.

When it becomes necessary to put an oil well on the pump, the operator is usually faced with an investment of several thousand dollars in some means of artificial lift. By far the most successful and most generally accepted type of artificial lift is the beam type pumping unit. Many years of research and testing have gone into the design of the modern pumping unit. Advancements in metallurgy and the most up-to-date machine tools go into its manufacture. All these improvements in design and technique of manufacture are of little value in the equipment is not installed properly on the well or operated correctly. For the operator to get the most from his investment in a pumping unit, he should operate the unit as the manufacturer intended it to be used and within its nameplate rating.

In today's times of material shortages and spiraling material costs, it has become increasingly important to emphasize proper installation techniques and a comprehensive maintenance program to assure long equipment life with minimum maintenance. Of prime consideration will be a scheduled maintenance program to prevent untimely and expensive downtime, and to prevent expensive major maintenance.

The purpose of this paper is to show how the design and operation of pilot-controlled gas-lift valves have overcome many of the inherent problems of multiple completions. Within the production tubing string, multiple completed wells are no different than single completions. From a gas-lift standpoint, the main difference is that several wells producing from a common casing, have a common casing annulus gas supply. This fact eliminates the use of pressure in the annulus as the sole means for actuating the gas-lift valves.