Carbonate formations have been treated with acid for many years to increase fracture length and conductivity and, thereby, stimulate production. Fracture acidizing of carbonate formations, however, requires consideration of several parameters. One important parameter is the distance acid will penetrate the fracture before completely reacting. This distance is referred to as the acid penetration distance. Other parameters include dynamic fracture geometry and fracture conductivity. Although these three parameters are largely controlled by-formation properties, they can be strongly influenced by the treating fluids used and the techniques employed to place these fluids. Acid penetration distances have been increased to various extents with chemically retarded acids, gelled acids, emulsified acids and acid systems composed of hydrochloric, acetic and/or formic acids. A new chemical retarder has been developed which can be used with emulsified and non-emulsified acids to help increase acid penetration into fractured limestone formations. The unique chemical retarder is chemically and physically adsorbed on the formation where it slows the reaction rate of acid. Besides retarding the acid-limestone reaction effectively, adsorption also appears strong enough to withstand turbulent flow. Although a retarder may greatly increase penetration distance, other parameters, such as fracture conductivity, also have to be considered if the retarder is to be used. For example, during a retarded acid treatment inadequate fracture conductivity may result if fracture cooling causes over retardation of the acid near the wellbore. Placement techniques are in use, however, that could resolve this problem. During treatment, a less retarded acid can be injected before the retarded acid for better conductivity near the wellbore, and the density of preflush can be balanced with the density of partially spent acid for better acid distribution along the fracture face. This paper will discuss the laboratory evaluation of the new retarder's effect on acid penetration distances and reaction times with non-emulsified and emulsified 15% HCl, 20% HCl, 28% HCl and a 7-1/2% HCl-10% formic acid mixture. Also to be discussed, are acid placement techniques used recently in twenty one Mexican wells with the new retarder. Results of these techniques thus far are also listed.

The oil industry customarily has utilized various clay control additives to prevent formation damage caused by the hydration (swelling) or migration of clays. These additives include inorganic metal cations, (e.g. Zr+4, Al+3, Ti+4, et al.) synthetic polyacrylate polymer types, quaternary ammonium salts, and petroleum heavy ends. Clay stabilization using metal cations is accomplished by ion exchange with cations in the clay mineral lattice. These types of clay control agents are limited in application due to their general incompatibility with most polymers used to viscosify completion fluids. This incompatibility is particularly apparent in crosslinked stimulation fluid systems because the metal cations interfere with the crosslinking mechanism of the fluid. Quaternary ammonium salts are also used as clay control agents. They function in approximately the same manner as the metal cations. Synthetic polyacrylate polymers have been used as clay control agents in completion techniques. The polyacrylate function is two-fold. First, the polymer's cationic character under mildly acidic conditions exchanges with lower charged cations located on the clay mineral lattice. Secondly, because this polymer is a long chain molecule (due to molecular weight), it lines the pore wall which insulates the clays involved in the pore channels. Clay damage control through physical isolation of formation clays has been achieved by using petroleum heavy ends, and other similar materials. This method of clay stabilization has shown a degree of effectiveness. A major problem in using this method is due to economics. A number of clay stabilizers have been reported to fuse migrating clays. These systems are used primarily in sand consolidation, hydraulic fracturing and acidizing applications.

Hydrochloric-Hydrofluoric acid mixtures for sandstone acidizing have been the topic of many investigations with respect to optimum hydrofluoric (HF) concentrations necessary for effective treatment. The hydrochloric acid (HCl) concentration needed is only at a concentration necessary to inhibit the formation of calcium fluoride (CaF2), and to provide a conversion media when utilizing ammonium bifluoride for HF production. All indications show that HCl-HF acids in concentration ranges between 3% HCl-0.6% HFto 6% HCl-1.2% HF are in many instances more effective acidizing systems with regard to eliminating the initial damaging effect caused when more conventional HCl-HF treatments are used. These conventional systems tend to chemically and physically dislodge or remove more than they can effectively "clean up", and depend on additional amounts of following acid volume to "eventually" remove these dispersed formation particles, or force them within smaller spaces in the formation. This fives the indication on conventional HCl-HF acids causeing initial "damage", which is followed by restoration of lost permeability, with some improvement, but seldom in proportion to the volumes and concentrations used. Lower concentration HCl-HF acid systems tend to initiate slower and less damaging reactions, thereby "cleaning up" after themselves and offering improved permeability without the initial probable sloughing threat and subsequent "damage" of the higher concentration conventional HCl-HF combinations. Thus an innovation of utilizing weaker HCl systems with intensification via the use of weak HF concentrations has provided an effective means to successfully acidize or acid-frac low permeability sandstone reservoirs.

Based on the drift-flux model, a new mathematical formulation was developed to predict natural separation efficiency. The new model presented in this work considers the effect of the slip velocity in the radial direction, variable neglected in previous simplified models. In addition, a correlation for this effect was obtained by fitting the model to experimental data. Good agreement of this simplified model with the experimental data for not only lower but also for higher gas and liquid flow rates has shown the important effect that the slip velocity in the radial direction has in the prediction of natural separation.

Use of 4-1/2 OD tubular in the completion of deep gas wells makes possible perforating a well with a large, non-expendable type fun while maintaining a pressure differential into the wellbore and treating the well at rates up to 50 BPM. Increases in a well's deliverability as a result of these techniques make the new design economically attractive. These completion methods can be performed on the well without the need to kill it either during or after completion of the well.

Historically, tight gas formations such as the Strawn limestone in Crockett County, Texas and the Devonian in Andrews and Midland Counties, Texas have been treated with pad and acid treatments consisting of gelled water, gelled acid and
crosslinked hydrochloric acid. A new emulsion polymer has been developed which significantly increases the efficiency of these treatments. The new emulsion polymer exhibits a polymer size approximately 15 times smaller than that previously known to the industry. The polymer also utilizes a highly specific external activator to initiate and promote hydration. This process allows the microsized polymer to effectively disperse prior to hydration, thereby dramatically reducing the potential to form un-hydrated masses ("lumps" or "fisheyes"). Both macro and microscopic "lumps" can be particularly detrimental to the formation matrix. This paper will document the increased well production of the &awn formation in Crockett County, Texas and the
Devonian formation in Andrews and Midland Counties, Texas as a result of the polymer's use, outline the treatment, and describe the chemistry of the new emulsion polymer and its operational efficiency and versatility.

One of the primary concerns in completion practices for the Canyon Sand in Sterling, Schleicher, Sutton, and Crockett counties has been to balance possible formation damage with completion costs. The low productivity, and until very recently, the low gas prices for this area has made the use of "exotic" fracturing treatments very difficult to justify. The fluids were normally a gelled water or gelled weak acid system, often used with CO2. In those instances where the treatments are performed via tubing, low injection rates often contributed to screenouts. The recent advent of cross linked water based fluids and more effective clay stabilizers has reduced both the screenout problems and formation damage. Within the last 8-12 months, a complexed weak acid system has been developed which has demonstrated a combination of most of the advantages of the other systems with very few disadvantages. The ability to transport sand out to the drainage boundary is the ideal stimulation practice for almost any "tight" sand. This idealized treatment, though, is often not economically justifiable due to the inefficient nature of the fracture fluid, especially the earlier fluids used in this area. In this paper, we will investigate the theoretical and practical aspects of pumping a complexed weak acid system. This system possesses a large number of the desired characteristics for use in the Canyon Sand -- high viscosity, low friction loss, low pH compatibility with C02, compatibility with clay stabilizers and fluorocarbon surfactants, low fluid loss, and excellent sand transport properties.

A new friction reducer was tested in various fluids to measure its performance in both a small scale flow loop and a field scale system. The polymer was mixed into fresh water and a 1% KCl brine, then pumped through 1_ inch coiled tubing and straight pipe. Drag reduction as high as 69% was achieved in the coiled tubing, and as high as 84% in straight pipe. The study also included 7% KCl, 10 ppg NaCl and 11.4 ppg CaCl2. A small scale flow loop, consisting of _ inch diameter coiled tubing and straight pipe was used. There was good correlation between the fresh water friction pressures measured in the small scale flow loop and full scale system for straight pipe. The measurements using the _ inch coiled tubing over estimated the amount of friction anticipated in the larger coiled tubing. The heavier brines generally required greater polymer loadings.

Fiberglass reinforced pipe (FRP) was originally developed and marketed in the oil field as a highly corrosion-resistant alternative to steel in relatively small-diameter, low-pressure gathering and flow lines. As the acceptance of FRP grew, so did the demand for larger diameters, and higher operating pressures. This acceptance of FRP in the oil field as an almost commodity item inevitably led to widespread stocks of fiberglass at both the distributor and the end-user level, until now probably 70% of the pipe sold is installed without the specific knowledge of the manufacturer.Aside from the educational aspects which are necessary with all new materials, the major reason for this kind of attention was the need to insure that the crews were trained in the proper installation of the adhesive bonded joint. It can be proven that a properly made adhesive joint, under the right conditions, is as strong as the pipe itself and, in fact, these requirements are written just that way in some standards and specifications. Unfortunately, this is more easily specified than it is attained. Most thermosetting adhesives are sensitive to both humidity and temperature conditions. Adhesives, by definition, rely on intimate surface contact in order to perform efficiently, hence the need for nearly perfectly clean and dry bonding surfaces. As anyone who has tried to lay adhesive joint pipe in a West Texas dust storm or a Louisiana "Sun Shower" can tell you, these conditions are not always easily attainable. In addition to all this, because adhesives undergo a chemical reaction, temperature plays a critical role in the working time in the container and in the curing time of the joint. Recognizing these limitations, FRP manufacturers have spent a great deal of time and money working to minimize these difficulties and increase the overall reliability of the joint. For example, nearly all FRP is supplied with end protectors to keep the bonding surfaces clean and dry. Many suppliers offer heat assist methods for curing the joints in cold weather. Installation instructions are supplied with each adhesive kit. At least two of the major manufacturers are offering adhesive joints with a built-in mechanical assist to hold the joint straight and immobile while the adhesive cures - all of this in an effort to improve the reliability and acceptance of FRP throughout the industry.

In an everyday review of well and reservoir performance there is a wealth of interpretive tools such as the one given in SPE Monograph No. 1 on build-up interpretation and in many articles in the SPE journals. Too often, however, the meager data available for analysis causes concern as to the reliability of the conclusions. A typical problem involves the declining production rate of older wells, where the engineer is faced with the problem of determining what remedial steps, if any, can be justified. Several possible problems come to mind. 1. The pump may not be operating efficiently. 2. Scale deposits may be forming in the well, causing skin damage. 3. The reservoir pressure may be lower than expected. 4. The formation may be tighter than expected. This paper describes a new practical service for acoustically determining build-up curves for pumping wells. Included in the service is a rapid standardized analysis that provides the client with measures of pump efficiency, estimates of skin damage, formation permeability and reservoir pressure. Figure 23 shows a summary of the reservoir data obtained in this analysis.

In the recent National Petroleum Council (NPC) report to the Secretary of the Interior on the U.S. Energy Outlook", it is noted that naturally- occurring geothermal steam and hot-water reservoirs in California and Nevada, while potentially contributing up to only two percent of the total U.S. electrical generating capacity by the year 1985, could supply over one-third of the projected electrical power requirements for those two states (16,000 MW out of a total estimated requirement of 52,000 MW). The NPC projection, while close to a recent estimate by Dr. Carel Otte*** of a potential 20,000 MW of neglect any significant contribution from other western states. However, other estimates of the U.S. geothermal potential are considerably greater than those given above. A very recent state-by-state geothermal resource evaluation gives a total U. S. geothermal potential several hundred times greater than the NPC projection. However, this quite realistic evaluation is based on one additional premise not considered in the NPC projection: that a method can be developed for economically recovering the thermal energy contained in the much more numerous reservoirs of hot rock that are nearly impermeable to circulating ground water. One such method is the subject of this paper.

Successful acid stimulation requires a method to distribute the acid between multiple hydrocarbon zones. Since almost all producing wells are inhomogeneous, containing sections of varying permeability, this can be a huge problem. In addition, the water saturation of the various zones plays an important role. Since acid is an aqueous fluid, it will tend to predominantly enter the zones with the highest water saturation. These water zones are also often the highest permeability zones, so acid stimulation will often result in large increases in water production. There can be many negative aspects to increased water production, such as increased lifting and disposal costs, increased corrosion, etc. This paper describes the use of a new low viscosity system which can inherently reduces formation permeability to water with little effect on hydrocarbon permeability, and also diverts acid from high permeability zones to lower permeability zones. This new system has been used in offshore Mexico in the Chuc, Caan and Pol fields among others over the past year. During this time, over 30 wells have been treated with the new system. Most standard acid treatments in this field result in increased hydrocarbon and water production. The new system has resulted in increased hydrocarbon production with no increase in water production, and in some cases a decrease in water production. Details from several of these jobs will be presented showing the diversion and production results.

Acid Polymer gels having pH less than one have been crosslinked for retarding the chemical and physical activity of hydrochloric acid on calcareous formations. Hydrochloric acid concentrations from & percent to 28 percent have been successfully crosslinked. This new and unique stimulation fluid offers high viscosity with adequate shear stability, perfect support for proppants and clay stabilization. Additionally, the fluid provides effective fluid loss control and retardation of acid reaction enabling live acid to penetrate deeper into the formation for better formation conductivity and practically a residue free break for rapid clean-up of the well after the job. Results of lab and field tests show this new Acid Crosslinked System to be effective stimulation fluid for acidizing and acid fracturing in calcareous and sandstone formations having low formation permeability.

Lifting problems in producing wells can drastically cut the oil operator's profit on initial investment. Well conditions that cause severe lifting problems are: 1. High sand content in the producing fluid which will often damage or freeze the bottom hole pump. 2. Paraffin or gyp accumulation on the tubing I.D. and sucker rods, resulting in eventual plugging. 3. The oil produced is of low gravity and cannot be efficiently pumped in cold weather. Wells with the above conditions are presently being pumped with optimum efficiency through use of a new method of artificial lift. The method applies the principle of sonic energy to oil well production. The equipment used will vibrate the tubing string in such a manner that valves in the tubing collars will lift the fluid to the surface.

Corrosion surveying of pipelines can now be performed by an instrumented pig which travels through the line with the fluid normally transmitted. A continuous log of the entire line shows the areas where corrosion pitting has occurred.

This paper will discuss the properties and applications of a new water-base fracturing fluid. In particular, it will discuss its leak-off characteristics, its rheological behavior, and its proppant-transport capability. Additionally, it will give examples of its use in the field, including production information. Beginning in the late 1960"s, intensive research was done in the area of improved stimulation fluids. This led to the development of a variety of crosslinked fracturing fluids based on both organic and synthetic polymers. These fluids featured extreme viscosities, perfect or near perfect proppant transport, and good pumpability without excessive friction drop. In nearly all cases, high polymer loadings were required for optimum performance. In the case of the natural polymers, the higher loadings resulted in excessive residue and consequent sand-pack damage. The synthetic polymers left no damaging residue; however, they were prohibitively expensive. The subject gel was designed to overcome the limitations of the early crosslinked gels. It features a moderate polymer loading which, when complexed with an organometallic chelate, furnishes high but not excessive viscosity combined with perfect proppant transport. It features good leak-off control and is residue-free when broken. The base polymer of this system is carboxymethylcellulose which is hydrated prior to pumping. The complexing agent is added continuously after sand is dispersed in the base gel. Since the concentration of organometallic chelate is low, an air-drive proportioner ha's been designed and built with suitable control and monitoring features. This device is also described in the paper.

The use of a fluid containing an abrasive for perforating casing and cleaning open hole has been an established technique for many years. Generally, the jetting tool is installed on tubing along with a collar locator, tubing hold-down, centralizer, and in some instances an anchor swivel. The tool is then lowered to the desired perforating or jetting depth to be cleaned. Perforating or jetting operations are initiated by pumping the abrasive fluid into the tubing conductor, then to the jet body, and out the jet nozzles at relatively high differential pressure on to the surface or surfaces to be cut or penetrated. Conversion of the pressure into kinetic energy imparts high velocity to the abrasive particles, which upon impact with the formation face or casing wall will erode the material in an organized pattern. A prime deterrent to effective hydraulic perforating an openhole section in an old well is the extended stand-off distance at which the perforating or jetting operation must be performed. This condition is particularly aggravated and critical in "shot" holes and openhole sections which have been previously acidized or fractured and have since become scaled or plugged. The purpose of this paper is to present a self-decentralizing hydraulic perforating tool which produces unbalanced forces and which, when coupled with a flexible fluid conductor, will provide a novel combination resulting in near zero stand-off hydraulic perforating conditions for improved effectiveness in perforating or penetrating a formation face in open hole. A sketch and general operating procedure plus some equations involved in development and several pertinent to its effectiveness for penetrating rock or scale are set forth. In general, this discussion is presented along operational lines and is substantiated by test target results, pictures, and after treatment responses. These results present concrete evidence, confirmed by representatives of various oil companies in West Texas and Southeast New Mexico that the successful development of the tool for perforating or penetrating formations in open hole or "shot" hole is an accomplished fact, and that this process can be relied on to penetrate rock or scale.

"Conventional acidizing has ignored relative permeability effects by attempting to inject aqueous fluids into zones filled with crude." Since most oil wells in the Permian Basin today are on water flood or produce large quantities of water, relative permeability is an issue. Therefore in zones where the water saturation is high due to depletion of the higher permeability zones and/or natural fractures, acid tends to enter these zones instead of the oil zones where the acid is needed and wanted. This in turn leads to higher water cuts instead of increased oil cuts. A new non-particulate, non-gaseous material has been developed to effectively divert acid away from highly water saturated zones. This new material's diversion capabilities are dictated by the relative permeability of the formation as with foam, but it offers a simplicity and accuracy to the treatment that foam and other diverting agent can not. This paper discusses a case history that utilized this material for acid diversion in a water flood.

A new technology now exists to expand solid stainless steel tubulars for downhole remedial pre frac applications. Very different from other expandable technologies, mainly due to the setting process and the capacity of the tools to expand until they're in contact with the casing, this technology has now been used successfully in several countries as a precision intervention to resolve a variety of downhole problems. This paper will: provide an introduction to inflatable packer expandable steel technology, what it is and how it works; discuss some of the issues identified and resolved during the development of the technology; provide case histories using examples of pre frac jobs DV tools and sliding sleeve repair jobs from operations in US, and Western Canada; summarize the features, benefits, and limitations of the technology; present the solutions available today in the US.

Delivery of recovered hydrocarbons from oil fields to refinery, storage and consumption points is related to significant oil products loss. Losses occure all the way from oil production up to receiving them by consumers. The losses are due to outfow, evaporation, weather factors, equipment imperfections, etc. However, according to the case studies, approximately 75% of liquid oil products losses are due to evaporations. Hydrocarbons evaporation is concerned with not only material losses, but also causes environment polluction by toxic hydrocarbons. Therfore, duel losses reduction is an important economic and an environmental problem. Recently, a new tchnology was developed to prevent VOC emissions from tank batteries. The pontoon structures made of oil-resistant rubber-textile or synthetic material are used to prevent VOC emissions. Maintenance and dump of pressure in a pontoon space is carried out by means of the compressor and gas collector. The device was tested in FSU oil fields.

The sucker rod connection poses several problems to rig crews as well as the oil companies. The first issue the crews have to deal with is the face that there are two elements to a rod connection: The lower and the upper rod interfaces. Making up both elements to precise circumferential displacements at the same time is almost impossible.
This paper will deal with these issues and will illustrate a new tool that solves the makeup problems and at the same time, gives the crews a method to remove or replace a coupling. The tool can be instructed to make up either both or only one element of the connection to the precise desired CD. The two CD's are measured independently.

A new treating method has been designed for use in wells in which injectivity has been decreased by deposition of polymer residue incurred in polyacrylamide polymer and copolymer treatments. This treatment consists of one or two stages: an oxidizer stage followed by an acid stage, or a combined acid-oxidizer stage. This treatment is effective against polyacrylamide polymer and copolymer deposits near the wellbore that will not respond to conventional treatments. It is known that polymer injection can gradually lead to a decrease in injectivity. solid polymer, This injectivity decrease can be due to incompletely dissolved improperly inverted emulsion polymer, and/or deposition and adsorption on the rock face. These blockages can contain inorganic as well an organic components. An acidizing treatment is necessary for the inorganics while an oxidizer treatment is necessary to treat the organic constituent. The new treatment method consists of a strong oxidizer that is acid compatible. The pH of the oxidizer stage can be adjusted to suit the need of a given well. The pH adjustment can also control the release rate of the oxidizer. These solutions are mildly corrosive to steel. The oxidizer and acid can be split into two stages if the mixture proves to be too corrosive, or if a stronger acid is desired. These treatments have been effective without the acid stage in polymer injection wells. Laboratory data and preliminary well treatment results are presented to show the effectiveness of the oxidizer alone and with acid.

The productivity of oil and gas wells can he improved through the use of efficiently designed acid fracturing treatments. The approach to acid fracturing treatment design presented in this paper enables a comparison of the production increases for various types of acid systems. In this study, four hydrochloric acid systems (plain, foamed, gelled anti crosslinked) were used to design acid fracturing treatments. An acid fracturing stimulation design comparison for three reservoirs is presented.

A new promising enhanced oil recovery technology has developed. The technology involves in-situ generation of carbon dioxide to recover trapped residual oil from reservoirs. This technology has two at least unique features that set it apart from existing technologies. First, CO2 is injected as part of a dense liquid phase (not simply compressed CO2). Because the injected fluid is a dense liquid at ambient conditions, there is no need for the expensive compression costs that are associated with convention CO2 injection processes. The gravity head associated with the fluid column allows CO2 to be injected in a more cost-effective manner. This proprietary technology allows CO2 to be released in-situ after injection into the reservoir. A second unique feature of this new technology is that a proprietary surfactant formulation forms foam when the CO2 is generated in situ. The slim tube and core experimental results demonstrated advantages of the new technology. The technology also was tested in Russian and Chinese oil fields.

The formation of troublesome organic deposits during oil and gas production is a significant cause of decreased production and increased lifting costs. Traditional methods of mechanical and solvent-based removal are time consuming, expensive, and can create additional problems of re-deposition and dehydration facilities upsets. A novel process has been developed to remove organic deposits from hydrocarbon producing wells and equipment by generating an exothermic reaction that melts and disperses paraffin wax and asphaltenic
deposits. The reaction product is a powerful paraffin dispersant that prevents redeposition after the temperature returns to normal. The process is non-aqueous, which does not cause troublesome emulsions or potentially dangerous gas production.