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.

The developoment of a new cage for bottomhole sucker rod pumps was initiated by Oxy Petrolem to solve prematrue failures of existing cages in their water flood fields. Oxy approached Quinn's with the purpose of designing a cage in the Wasson/Clearforks area.After reviewing the wells, Quinn's designed a new cage that is a one piece cage, can handle an alternate pattern ball, have better flow characteristics with less pressure drop than any existing cages, and handle deep, corrosive well conditions.Quinn's utilized their finite element anaylysis software to design this new cage. The QP2 cages were built, ran and tested. Quinn's also successfully developed interim cages that achieved longer run lives while develping the QP2 cage.This paper will expand on the design process that was undertaken to fulfill Oxy's request for a better cage and also verify the design criteria.

The bottomhole sucker rod pump, is the workhorse of artificial lift around the world. If the bottomhole sucker rod pump becomes fouled, the oil company is losing revenue. Prior to calling the service rig, this paper will provide a series of pracatical procedures to tyr BEFORE the service company is called. The goal is to restore pump function and return production to normal, while keeping lifting cost down.

On many occasions lost circulation is associated with stuck pipe and once circulation is regained the pine may become free. With a good mud system sometimes it is not advisable to contaminate the mud with other fluids; however, with Nitrogen the mud may be circulated through a degasser or across the shale shaker to break the gas out leaving uncontaminated mud. Nitrogen technical manuals will show pressure gradients of commingled nitrogen and liquid densities up to 11 lbs/gal. All gas laws are incorporated into their design. At low concentration of nitrogen and high pressure the charts show near linear conditions. An equation for field use by engineers will show the pressure gradient and amount of nitrogen required to lower the hydrostatic pressure of any weight fluid.

This paper addresses one method of dealing with produced gas containing carbon dioxide (CO2) and hydrogen sulfide (H2S) in C02 secondary recovery projects in the Permian Basin of west Texas and southeast New Mexico. Reinjection of produced gas is becoming more common as Permian Basin C02 floods mature. Reinjection can be very cost effective, environmentally prudent, and technically beneficial. Reinjection reduces or eliminates sulfur emissions, reduces capital costs by eliminating sweetening facilities, and often reduces the cost of injection C02 purchases. However, reinjection of H2Scontaining ("sour") gas creates some regulatory concerns not present with CO2 or sweet gas. The Railroad Commission of Texas (RRC) has several rules in place designed to ensure public safety. Some of these regulations require expensive solutions if the regulatory issues are not planned in the initial stages of project design. This paper will review the regulations that will affect gas reinjection projects in the Permian Basin, and outline steps to efficiently address the regulatory concerns.

Optimization of effective fracture area is among the principal tenets of fracturing design engineering. It is well understood that effective fracture area is a first order driver for well productivity, and that optimization of effective fracture area is often critical to economic exploitation of reservoir assets. Extensive testing in a large-scale slot apparatus was conducted to evaluate the relative effects of various component and treatment parameters on the proppant transport capability of various slurry compositions. The acquired data were utilized to determine the minimum horizontal slurry velocities necessary for proppant transport using the respective slurry compositions. An

Although fluid viscosity reduction is commonly used to gauge polymer degradation and viscosity reduction does indicate that polymer degradation has occurred, it is misleading to conclude that reduced viscosity equates to improved fracture conductivity or retained formation permeability. Polymer fragments which result from the normal breaking of gelled, cross-linked fracturing fluids no longer contribute significantly to fluid viscosity but do contribute to proppant pack and/or formation permeability damage. Laboratory evaluations and procedures to characterize the efficiency of gel breakers, based upon the size distribution of the generated polymeric fragments, have been presented in previous studies. Results of core flow evaluations are presented in this study, and demonstrate the relationship of typical molecular weight distributions produced by degraded typical cross-linked fracturing fluids to permeability and production reduction within the rock matrix. Several ranges of core permeability were evaluated. Data yield a quantitative profile of the extent of formation permeability damage that can be expected based upon polymer fragment distributions and the original rock permeability. Detailed analysis of the data are provided.

This paper presents a method of estimating the reliability and expected operating time for injection units. An analysis of failure observations is presented and the means by which statistical methods can be employed to obtain reliability estimates. Expected operating times incorporating repair periods are developed and an example presented to illustrate the application of these techniques.

Effective waterflooding requires that injected water be condifed to and moved through the zones of permeability containing the remaining oil in place after primary production. The injection waters available for waterflooding are becoming more and more limited; therefore, this supply must be more efficiently utilized through confinement to the zones containing the secondary oil-in-place. Problems which are most common to water injection wells are those effecting confinement of injection water; i.e., channeling up or down out of zone, channeling through existing water stringers, or excessively high permeability zones, and simply going out bottom. Several different materials and methods are being used in efforts to control these water injection problems

The economics of secondary recovery is certainly important to today's domestic oil industry. There is, however, another important consideration which must be taken, in view of present shortages of proven reserves-ultimate recovery of secondary oil. In other words, can more of these known reserves now in place in reservoirs already drilled and under waterflood be produced economically? Obviously, no oil will be banked to a producer if no water is injected into the section containing the moveable oil saturation which remains after primary production is accomplished. There are three common problems encountered in waterflooding which make it difficult even impossible-to inject water into and through all of the reservoir containing the residual moveable oil: 1. Little or no response to injection due to lack of confinement to the section of interest 2. Premature water breakthrough due to zones of high water saturation or extreme variations of permeability within the section of interest 3. Water breakthrough due to fingering of injection fluid caused by over-injection and/or directional permeability within the section of interest. This paper will consider only problems 2 and 3. Problem 1 was discussed by the author in a previous short course (1971). Water breakthrough occurs rapidly in zones of high water saturation since injection always seeks the path of least resistance. High water saturations offer less resistance to the flood water because the relative permeability to water is greater. Water breakthrough occurs rapidly in thin zones of high permeability for two reasons: 1. Most of the primary oil comes from the higher permeability, leaving high water saturation. 2. The extremely high permeability zones offer less resistance to the injection water anyway. Water breakthrough comes soon when over-injection causes water to finger through to producers. Over-injection occurs when an optimum rate is calculated for a total section to be flooded and only a small zone accepts the injected fluid-again the path of least resistance. Directional permeability simply offers the shortest distance between two points-in this case, between the injection and producing wells. The paths of injection flow after breakthrough become even easier since they exhibit higher relative permeability to water.

This presentation discusses the results of experimental and field case studies of a remedial treatment technique designed to eliminate fracture proppant production. This process uses a low-viscosity consolidating agent, which is placed into the propped fractures via coiled tubing or conventional tubing coupled with a pressure-pulsing tool. The treatment fluids are designed to provide consolidation for previously placed proppant near the wellbore without damaging the permeability of the proppant pack. The consolidation treatment transforms the loosely packed proppant in the fractures and the formation sand close to the wellbore into a cohesive, consolidated, yet highly permeable pack. Laboratory gas flow testing indicates that the proppant pack in a fracture model under closure stress required low-strength bonds between proppant grains to withstand high production flow rates. Field case histories are presented to discuss treatment procedures, precautions, and recommendations for implementing the treatment process. One major advantage of this new remedial treatment technique is the ability to place the treatment fluid into the propped fractures, regardless of the number of perforation intervals and their lengths, without mechanical isolation between the intervals. The fluid placement efficiency of this process makes remediation economically feasible, especially in wells with marginally economic reserves.

Remote production management systems involve several basic configuration components. These components can be thought of as building blocks comprising a system. For the purpose of our discussion we will represent or conceptualize major components and their respective detailed facilities by means of block diagrams.

Modern stimulation treatments involve recording of a variety of data including surface rates, wellhead pressures, liquid additive rates and other parameters related to the fluids and proppants being applied as shown in Fig. 1 8, 2. In recent years, computers have been used not only to track and evaluate such treatments but also to model bottom-hole conditions in an attempt to simulate fracture geometry in real time during the treatment. Much of this work has centered around three dimensional models such as noted by Meyer1j2 and Cleary3. The capabilities exists that we can now read data directly into one or more of these new models via remote telecommunications real-time, offering a great savings in time and manpower. The proper utilization of fracture simulation software requires personnel capable of running and interpreting these highly specialized programs. Making such personnel available on location can be costly and is not always possible. Remote telecommunication of real-time data can serve a useful purpose in this regard. Telecommunication of data offers a major benefit to operators by providing the ability to monitor treatments remotely and observe the analysis as it is being performed real-time. Personnel at the remote site may also analyze the data in real-time and provide guidance over the phone.