Balancing injection-withdrawal ratio on a pattern basis is essential in optimizing tertiary recovery projects, where high lease expenses tend to marginalize even the best of candidates. Advances in reservoir modeling techniques provide increasingly reliable predictions of long term field-wide production response; however, a gap frequently exists in supplying routine or short term individual well forecasts. This paper describes a simple allocation technique utilizing a modified version of Darcy's equation for linear flow within the setting of a field-wide pattern network. Generated factors allocate actual injection to offset production, calculating idealized production volumes on a gross reservoir barrel basis for comparison to actual production to influence uniform injection-withdrawal. In other words, a check and balance system to assist in guiding operations. Developed over the past several years for use in the SACROC Unit in West Texas, tailoring is possible for other secondary/tertiary recovery projects given field specific conditions.

Operating electric submersible pumps in a CO2 flood is challenging and requires applying new engineering and operational resources to be successful. Extremely high GLR"s, radically changing bottom hole pressures and changing fluid densities require more than just conventional methods for operating and troubleshooting ESP"s. An integrated control system was used to troubleshoot well conditions that consist of high concentrations of CO2. Accurate bottom hole pressure, temperature and vibration information was collected and used to determine actual well conditions and make decisions based on real data.This application decreases the "guess work" previously used in determining bottom hole conditions and increases the effectiveness of decision making to correct problems. This paper is a continuation of work efforts that were started and discussed in last year's SWPSC.

By arranging the geometry of the beam type oilfield pumping unit as a non-symmetrical front-mounted lever system, it is possible, in most cases to fit more closely the counterbalance torque pattern to the well load torque pattern, with significant reductions in peaks. This system results in a relatively uniform loading of both prime mover and gear reducer; the loading in turn allows the operator to handle many applications with smaller equipment and reduced first cost.

The technology associated with the use of carbon dioxide as a component of oilfield stimulation fluids has evolved dramatically since its introduction in the early 1960's. Technology improvements in the mechanical, chemical, and applications areas will be discussed herein. This paper will be introduced with a brief review of the chemical and physical properties of carbon dioxide which are the basis for the utilization of CO2, in the stimulation industry. The introduction will be followed by a discussion of mechanical advances in CO, pumping equipment, pressure maintenance devices, heaters, fluid viscosity measurement, flow monitoring instrumentation and safety equipment. Next, chemical developments such as CO,-compatible acid, water and alcohol gellants, dispersants, vapor phase stabilizers and crosslinkers will be traced. Finally, stimulation applications of CO2 will be described. These applications have multiplied from acid and hydraulic fracturing fluids energized by CO2 as a minor commingled component for rapid removal of mud, silts, fines, water blocks and emulsions, through miscible hydrocarbon treatments, to dispersions, "foams" and crosslinked alcoholic fracturing fluids where CO2 is the major component.

MWD services have been commercially available for over ten years. The most entrenched application is that of directional services, where conventional methods such as wireline steering have all but been obsoleted. The only real advances in this application have been those influenced by software changes and data rate improvements. For example, faster tool face update rates while steering are now possible. A relatively recent sensor is one that provides weight on bit and torque in real time. The currently intended applications are estimation of bit wear and bearing failure. A drilling model is used to estimate shear strengths of the rock, although the model currently appears to be limited to shales only. The resulting Mechanical Efficiency Log is used for a variety of interpretations. An augmentation of the RLL service is now available whereby the recorded log may be retrieved on a wireline by stabbing with a "wet" connector upon demand. In the interests of brevity, neither this nor the MEL service will be discussed here. The other recent sensors/services are the EWRR and CN0SM, both described more fully below.

From the earliest days of West Texas drilling, produced brines have been readily available. Drillers quickly realized, even in the early days, the advantages to be gained from drilling with clear brine. Today, good quality brine is conveniently available to most parts of the Permian Basin at a delivered cost of 25 cents to 50 cents per barrel. The advantages of using clear brine as a drilling fluid have been adequately documented. The more obvious advantages are: (1) improved penetration rate with a solids-free fluid as compared to a typical drilling mud; (2) clear fluid with a density of up to 10.0 ppg is available when needed for pressure balance; (3) the natural tendency of brine to "pickle" or inhibit the swelling of shaley formations, thus protecting production zones and hole condition in general; and (4) all these at a relatively low unit cost compared to conventionally formulated drilling fluids.

In recent years the development of refractory materials has proceeded at a much faster rate than the ability of industry to utilize them effectively. This paper will discuss in detail some of the more interesting of these compounds, their potential for the petroleum industry and a process by which they may be uniformly applied to the surface of any object. Radio frequency sputtering is the name of the process and it is the intent of this paper to give sufficient detail as to the basic description and parameters of this process to enable the reader to implement it with a reasonable degree of effort. Results are cited that pertain to field problems.

Use of liquefied gases as fracture fluids has been a commercially available service for more than a year and both results and experience have helped dictate new developments and define candidate reservoirs. Designed originally for gas well stimulation, the new service uses a fluid made up of liquefied CO2, LPG and methyl alcohol. The liquefied gases are mixed in such a proportion that they remain a liquid and behave as a liquid as long as they are under adequate pressure and below the critical temperature of the mixture. When they are heated above their critical temperature in the reservoir and pressure released, the liquid reverts to a gas. This results in extremely rapid clean-up and minimizes problems of water sensitivity and liquid retention damage. In practice, the liquefied gases are mixed in varying proportions depending on reservoir temperature. For each well, the proportion is designed to provide a mixture that will have a critical temperature about 15% below the reservoir temperature. Since the mixture is not an effective frac fluid in itself, a gelling agent in methyl alcohol is added as a third component to provide the desired properties of viscosity, low leak-off or fluid loss control, low friction pressures, and good prop-carrying ability. In a stimulation treatment, the liquefied gases are mixed in proper proportion on location and pumped to the wellhead. The gelled alcohol and prop are mixed using a special pressurized blender and pumped to the wellhead where they mix with the liquefied gas mixture to produce a uniform prop-laden frac fluid. Not only is it necessary to design the liquefied gas mixture to have the proper critical temperature for each well, but it is also necessary to design the methyl alcohol gel to provide the desired frac fluid properties to the final fluid for each well. Properties of the final fluid are determined from conventional fracture design calculations. (Although addition of the gelled alcohol to the liquefied gases increases the critical temperature of the mixture, laboratory data indicate that this increase is more than offset by designing the liquefied gas mixture to have a critical temperature 15% below reservoir temperature. In low-temperature wells, design is based on vapor pressure of the liquefied gas mixture as compared to reservoir pressure.)

This paper discusses the latest equipment and software developments in wellsite drilling monitor systems. Included is a discussion of data collection and analysis by on-site computer. Specific emphasis on data analysis for drilling optimization and pressure detection in hard rocks is presented. New analytical tools, such as mud temperature and conductivity logging, are discussed, An economic analysis of data collection units gives the operator a basis for judging the merits of available services.

A sound velocity sensor is described as a means for detecting interfaces between different hydrocarbons in products and crude oil pipelines. Temperature and pressure influences are described as systematic error sources that are amenable to automatic compensation by a microprocessor. The utility of the sonic technique is assessed for detecting difficult interfaces between hydrocarbons of similar API gravities and for those interfaces where substantially different gravities prevail. A new development involving a combination sonic interface detector and sonic flowmeter is also discussed.

This paper discusses the development and use of polyelectrolyte's as broad spectrum coagulant aids and/or coagulants in the clarification of oil field waters.

Many papers have emphasized the problems of obtaining efficient mud displacement by cement, causing channels, annular gas flow and other problems. Mud displacement in liner cementing is more difficult than in full-string cementing because of several factors. Some suggestions for obtaining better results in liner cementing through, the use of newly-developed rotation equipment are presented in this paper. Tools designed for these types of jobs are shown and recommended procedures given.

Since the first foam fracturing treatment in approximately November of 1974, great strides have been made in both the technology of foam per se and the equipment to handle same. Countless numbers of papers, presentations and patents have been presented. A sampling of these is listed in the bibliography of this paper. The early foam fracturing treatments were conducted using water, foamer, and nitrogen injection trucks. The treatments were small and sand concentrations quite normally did not exceed two to three pounds per gallon downhole. It was always a very frightening experience for a company man, who had not been on a foam frac, to attend his first treatment. A company man who was used to visual read-out of both flow rate and pressure of all materials going down hole was in for quite a surprise on the early foam fracturing treatments. Nitrogen rate, which in many cases is produced by anywhere from 5 to 50 trucks, was measured by counting pump strokes on the units. A nitrogen treater would stand in the frac van and indicate to the company man what the rate was at all times. One could monitor with flowmeters, clean and dirty fluid rate of the base fluid to be pumped. But unless one was very trusting, one never really knew what was being pumped downhole. Without the benefit of both low-pressure and in-line high-pressure densiometers, one really never knew that the sand concentration was and because of the complexity of the density of the foam fluid there was very little in the way of checking same. In spite of all the aforementioned problems, many successful foam fracturing treatments, in fact hundreds, were conducted in just this manner. This says a great deal for the diligence of nitrogen treaters and fracturing operators. Quite thankfully, today foam fracturing is not such a black art. We in today's industry have quite functional in-line flowmeters for measuring the exact rate of nitrogen as it is pumped downhole. Most foam fracturing treatments should be conducted utilizing both in-line low-pressure densiometers for measurement of sand concentration in the concentrate as well as high-pressure in-line densiometers for measuring the final concentration of sand in the foam. Both of these measuring techniques, in addition to much improved sand handling capabilities from the service companies, utilizing either specialized valving in their pumps or sand concentrators, allow sand concentrations up to and including 8 pounds per gallon. Foam fracturing treatments have been conducted approaching two million pounds of sand with pump times well over 10 hours. Foam fracturing pump rates have varied anywhere from 5 barrels per minute up to 150 barrels per minute. Foam fracturing has indeed become another very useful tool for oil companies in the enhancement of production of oil and gas. Recently, a new development in this area has been the utilization of the emulsion foam/CO2 technique which has given new emphasis to energized gaseous foam fracturing.

The recirculation electric submersible pump system was introduced to industry in 1995. Subsequently, the system's utility has been demonstrated in numerous installations; the vast majority of which have occurred in the Permian Basin area of west Texas / southeast New Mexico. The system can be used to: (1) minimize gas interference with the pump (2) maximize well drawdown (3) increase fluid flow past the motor in low volume wells, and (4) eliminate shrouds. The primary goals of most all existing installations have been either to avoid gas interference with the pump and or to minimize producing fluid levels. This paper provides a basic description of the recirculation system. Sample output from a new recirculation pump sizing applet is presented. The benefits of the technology to Permian Basin operators are demonstrated through several case histories. These examples include applications of the technology in both 5.5-in. and 7-in. casing wells.

The routines of your daily work can be efficient only as they place demands on your lifting equipment that are in balance with its mechanical and metallurgical design. You of the petroleum industry who are engaged in artificial lifting do specify equipment. If your demands exceed its abilities, unfortunately you are then involved in an expensive servicing job and replacement of equipment. We should be able to mutually agree that you, in lifting, can do your job more easily and better if you understand the nature of your equipment

The difficulties in recognizing pay versus non-pay zones in the Permian Bell Canyon and Cherry Canyon sands in Reeves and Culberson counties are the result of: 1.) the presence of residual oil, 2.) the very fine grain size (Mz = 0.05 to O.10mm), 3.) the high Rw values (Rw = 0.15 to 0.25 ohm-m) and 4.) the presence of authigenic chlorite and mixed-layered illite-smectite clays. The fine grain size and the authigenic clays result in high irreducible water saturations. These high irreducible water saturations together with the presence of residual oil in both pay and non-pay sands and high Rw values result in low resistivity contrast between pay and non-pay sands. In order to overcome these difficulties, a series of crossplots and core analysis were used to determine pay from non-pay zones in two wells. Using net pay cut-offs of Vcl < 15% (dispersed clay), effective porosity (0e > 15% for 1.0 md) and Archie water saturation (Swa) < 60%, three "behind pipe" pay zones were identified in the two wells. These three zones have a combined hydrocarbon pore-meter thickness of 1.5 (5.0 pore-feet which calculates into 1.55 million barrels of oil in place assuming 40-acre drainage."

Power to operate the unit is generally taken from the lines of public utility companies who furnish 3-phase, 60 cycle power at carious standard voltages. Where utility power is not available, an engine generator unit is used at the well. The motor, which is a squirrel cage, induction type, turns the pump at approximately 3450 R.P.M. Maximum motor horsepower ratings are controlled by casing size.

The downhole tubing caliper survey, as part of a preventative maintenance program, is an effective tool for reducing the number of future or repeat tubing failures that occur on rod-pumped wells. Preliminary field results of an investigation in the North McElroy Unit, Crane and Upton Counties, Texas indicate that downhole tubing caliper surveys may be the most economical and effective field method of eliminating worn or severely corroded tubing in a well and insuring against troublesome repeat tubing failures. Generally, common practice is to replace only the failed joint and any visually defective tubing until a certain frequency of failures occur, although hydrostatic testing is sometimes utilized as a means of detecting thin-walled joints. This presentation compares common field practices to the downhole tubing caliper survey, from the standpoints of both economics and relative repeat failure frequency. The caliper survey's potential as a monitor of corrosion, wear, and downhole mechanical problems is also discussed.

This paper describes a new tool and method for removing solids; such as sand, scale, and iron sulfide; from production fluids before the fluid's entry and passage thru a downhole pump. A downhole pump's life and efficiency may be significantly increased. Erosive wear and sticking of pump parts is greatly reduced. This new device, the "Sandtrap" Downhole Dasandar, is run on the production string below any type of downhole pump. Centrifugal action within the device separates solids prevalent in well fluids and collects the separated solids in extended intervals of mud anchor joints or the rathole. It is most applicable in wells that produce small volumes of solids continuously or large volumes (slugs) intermittently.

With more and more emphasis on reducing expenses for beam units, most operators are examining all areas to try to cut costs. One of the biggest costs in beam unit operations is the associated electrical charges. Examining the pumping units to determine and adjust to the optimum counterbalance will reduce the electrical bill. Several fields have been checked with a PC software program, which allows the operator to determine how far out of balance the units are and what it will take to properly balance them. Properly balanced pumping units will result in savings both in kilowatt hours demand and also in consumption, reducing the electrical costs. Examples from several fields are discussed, including the actual power costs and the reduction in expenses that occurred.

There are several ways that power consumers with large distribution systems can reduce their electrical cost. In this paper we will discuss two methods. The first method will be the application of capacitors and the second is the selection of the proper rate.

The downhole cushioning device can reduce fluid pound effects on sucker rod strings. The tool studied in this paper is compact and simple. It is placed in the rod string above the pump to absorb shock waves. This should help prolong equipment life and reduce operating expenses. The cushioning device uses a piston and sleeve that fill with well fluid. Fluid enters the chamber creating a buffer to absorb and dampen shocks. Field data available at present indicate the device to be effective. Case histories show a reduction in rod failures after installation in problem wells.

The need to effect water production through the use of relative permeability modifiers is becoming an everyday reality in the oil and gas industry today. Rising exploration and development costs, along with ever-increasing water management costs, require that cost-effective methods of reducing unwanted water production be developed and implemented. To address this issue, a new relative permeability modifier system has been developed. It is designed to be placed into the matrix of sandstone or carbonate formations. The relative permeability modifier selectively reduces the permeability to water, without detrimentally affecting oil or gas permeability. This new water management treatment approach provides simplicity in job application, is viable over a wide range of reservoir types, lithologies, and permeabilities, and can be employed in a broad range of job types, including matrix injection and hydraulic fracturing treatments.

The pump card has three load reference lines 1) Zero Load line, 2) Fluid Load, Fo, from Fluid Level, calculated using the pump intake pressure determined from an acoustic

Refracturing can be used to increase production in poorly fractured wells. A different application of this technology is to refracture wells with strong initial fractures. In this paper, we provide evidence of increased production due to refracturing two tight gas wells having deeply penetrating initial fractures. Surface tiltmeter measurements show refracture orientations at oblique angles to the azimuth of the initial fractures.