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.

Paraffin formation has been a problem for many oil producers. Current technology for alleviating the problem of paraffin build up consists of: (1) mechanical removal, (2) removal with hot oil or other solvents, and (3) treating the wellbore with a paraffin dispersant or inhibitor. This paper will discuss the application of a new form of paraffin inhibitor and a novel technique for introducing the paraffin inhibitor into the producing formation. The study was conducted in the Dean Formation, Ackerly Dean Unit (ADU), Dawson County, Texas.

Oil Operators in Southeast New Mexico have been very successful in producing wells dual completed in both the Blinebry and Paddock formations. One area of contention, however, has been the mineral saturation in the commingled brine and the incompatibility of the various minerals in the two produced brines. Liquid scale inhibitors, applied conventionally during the fracture stimulation of each zone have not been successful in preventing formation of calcium carbonate and calcium sulfate scales after the wells have been placed on production. This paper details several successful applications of a novel, solid scale inhibitor that is applied with the proppant during the fracturing process. The application of this inhibitor has provided the Operator with maximum production and minimal remedial workover expense through long-term inhibition of calcium scales.

The purpose of a gas separator is to separate free gas from produced fluid before the fluid enters the intake of an electric submersible pump (ESP). If free gas is allowed to enter the ESP, it tends to cause the ESP to cycle, resulting in additional pump and motor wear and eventual contamination of the motor oil with wellbore fluids. Two types of gas separators are commonly available, the reverse flow separator and the rotary separator. This paper summarizes a recent field test in which the performance of the rotary gas separator was compared to that of a reverse flow separator under similar conditions in the same well. This field test was done on a low volume well under waterflood. An ESP was run in this well because a beam lift would interfere with the landowner's irrigation equipment. The original ESP, which was run with a standard reverse flow separator, could not pump the fluid level down because excessive gas caused the unit to cycle on and off. Three cases were studied. The first two cases consisted of running two identical 400 BPD ESPs, each one for a period of several months. The first ESP was equipped with a standard reverse flow separator and the second was equipped with a rotary gas separator. In the third case, a 280 BPD ESP equipped with a rotary gas separator was studied. It was necessary to run this ESP because the originally sized 400 BPD ESP became oversized once the effect of gas cycling was removed due to the rotary gas separator.

Commercial Measurement While Drilling systems have now been available for over ten years. A broad range of capabilities have been developed, albeit at significant cost. Development has primarily been driven by technology availability. The market for MWD services has been primarily limited by capability, supply and cost. MWD technology has now matured to the point where it is possible to offer significantly more capability than may be required in a given situation. Current MWD applications can be categorized as directional drilling, drilling efficiency, non-reservoir formation evaluation, and reservoir evaluation. The basic data requirements of these applications are sometimes complementary, however the cost of providing a system to cover all applications is prohibitive for the majority of wells. MWD is a technological development impacting several other wellsite services. The most significant of these are Drilling Equipment, Mudlogging and Wireline Logging. MWD cannot fully supplant any of these services, and must coexist alongside them all. Thus, any projection of the future role of MWD must look at the current and future interaction between all these services. Analyzing the inherent capabilities and limitations of each service provides an insight into their intrinsic benefits and value. Projecting likely future developments, it is concluded that MWD services will evolve to offer a broad range of applications solutions. These will focus on the inherent unique capability of MWD systems to provide downhole information as the well is being drilled. This should result in MWD services becoming an economically viable option for a wide range of wells.

This paper illustrates the wide use of PD meters and the growth of their use, particularly in Lease Automatic Custody operations. Furthermore, it discusses many of the basic principles of efficient meter operation, namely installation, proving meter accuracy, maintenance requirements and sampling. Various factors which influence accurate measurement are discussed, as well as different types of meter proving devices.

Evaluation of artificial lift requirements and selection of appropriate lift equipment for an oilwell must take into account the well inflow performance under anticipated producing bottom hole conditions. Controlled well test at these conditions will generate the necessary inflow performance data for this purpose. This paper describes a portable Production Test Unit and related well equipment which permits multi-rate production testing for the purpose of developing IPR data. Description of the Hydraulic Jet Pumping System used and examples of test procedures are included.