This paper reports the results of several field tests of the ability of bacteria, indigenous to oil reservoirs, to reduce and eliminate hydrogen sulfide (H2S) from the production stream. The effort was a logical progression from laboratory studies reported previously, to field testing under controlled conditions. The field testing ranged from production tanks to individual well treatments to large groups of wells. The treatment consists of providing small quantities of essential nutrients to denitrifying bacteria, which utilize the volatile fatty acids present in many oil reservoirs as a carbon source. These denitrifying bacteria in the reservoir compete in the microecosystem for the volatile fatty acids also required by the sulfate reducing bacteria. This process is called Biocompetitive Exclusion. The field tests show the ability of the biocompetitive exclusion process to be a viable field treatment for the reduction and elimination of iron sulfide and hydrogen sulfide problems in producing oil wells. Different treatment practices, quantities, frequencies, and candidate selection were examined as part of this testing program. An attempt was made to quantify production increases resulting from the treatment. Recommendations are made to increase the effectiveness of the application of this process in a field environment. Treatment of wells with the Biocompetitive Exclusion Process was both a technical and an economic success. Introduction The classical interpretation of microbial enhanced oil recovery (MEOR) is to introduce a microorganism along with a food source to effect a positive change in the recovery mechanism of an oil reservoir. A common treatment is to clean up paraffin problems in producing wells. More sophisticated processes take advantage of the microbe's ability to produce surfactants, acids, alcohols, and polymers to improve oil recovery. In the biocompetitive exclusion process, bacteria already existing in the reservoir are stimulated to effect favorable changes in the production stream. Sperl and Sperl have shown that nutrients can be introduced into reservoir systems to stimulate indigenous microorganisms. This commonly occurs when reservoirs are flooded with water containing significant sulfates. This sulfate influx stimulates the indigenous sulfate reducing bacteria (SRB) population which metabolize the sulfate into hydrogen sulfide gas. The hydrogen sulfide then reacts with metallic compounds such as iron to form iron sulfide, apparent in many producing systems as a black scale soluble in hydrochloric acid. Iron sulfide scale often plugs flow paths in the reservoir, perforations, pump intakes, and tubulars, causing restricted production. In a similar manner, the introduction of nitrate salts as a nutrient to the denitrifying bacteria (DNB) population causes them to flourish and metabolize the sulfides out of the system, producing byproducts commonly used as agents for improved oil recovery. Hitzman and Sperl have recently discovered that volatile fatty acids (VFA), such as acetate, butyrate, formate, lactate and propionate, play a key role in the microecology of petroleum reservoirs. This is an important step in understanding reservoir microecology and effecting positive change using the biological system. Volatile fatty acids have been found in many petroleum reservoirs. They act as a carbon source for microbial action. They are generally metabolized by sulfate reducing bacteria, such as Desulfovibrio desulfitricans, generating H2S gas as a by-product. P. 125^
This paper summarizes the steam injection operations of the Naval Petroleum Reserve No. 3 (NPR-3), Teapot Dome field, Wyoming, a federally owned oilfield, located about 35 miles north of Casper, Wyoming. More than 24 million barrels of oil has been produced since initiation of production in 1922; more than 15 million barrels has been produced since full production began in 1976. The Shannon sandstone is the shallowest (350 to 500 ft) and most productive of nine producing zones and accounts for 55% of current production. The Shannon, composed of the Upper and Lower Shannon sandstones, was deposited as an offshore bar where bar margin, inter bar and bioturbated shelf sandstones are the reservoir. The reservoir is faulted and extensively fractured, with the two sandstone intervals separated by shaly non-productive siltstones Maximum gross sand thickness is 100 ft with an average porosity of 18% and 63 mD air permeability. Since only 5% of the Shannon's 144 million barrels of original oil-in-place was estimated to be recoverable by primary means, a study of recovery technologies was conducted in 1980 resulting in implementation of a polymer-improved waterflood pilot and an in situ combustion pilot in 1981. The polymer pilot was unsuccessful, while the in situ combustion pilot was considered a technical success although marginally economic. Favorable response to steam preheating in the in situ combustion pilot led to the development of a steamdrive pilot in October 1985. Favorable response in the steamflood pilot led to recent rapid expansion. Currently 150 acres are being flooded using five 50MMBtu/hr steam generators. The history of the steamflood has been reviewed in an effort to document successful application of steamflooding in a shallow, very heterogeneous, low-permeability, light oil (320 API gravity) reservoir which defies conventional screening criteria. Introduction The intent of this paper is to demonstrate how the productive life of many shallow, light oil reservoirs may be extended by the application of thermal enhanced oil recovery (TEOR) methods. In view of the growing dependence in the United States on foreign, sometimes unreliable, oil supply, it is our opinion that documented case histories of unusual or marginal EOR projects may be of paramount importance to U.S. oil producers in coming decades. This paper documents the use of steam to produce light oil (32 API gravity) from a shallow, very heterogeneous, low-permeability reservoir which defies conventional TEOR screening criteria. Field geology, project history, pattern design, spacing, completions, operational problems, performance, and economics are detailed. The overall objective of the Shannon steamflood is to extend the economic life of Naval Petroleum Reserve No. 3 (NPR-3), thus allowing for future development of other producing formations. During fiscal year 1986 (FY86), total oil production from NPR-3 was 3,152 barrels of oil per day (BOPD) (501 m3/d). Total EOR production for FY86 was 87 BOPD (13.8 m3/d) or 2.8% of total oil production. P. 93
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractOftentimes the management decisions that are required for pumping wells can be significantly improved by having an additional piece of information. If the fluid level in a producing well can be known in real time, many other pieces of information can then be calculated and/or inferred. With this additional information, better decisions can be made to improve the efficiency of the producing operation.Fluid level machines, dynamometers, power analyzers, and pump-off controllers have all been very successful in increasing the operation of the rod-pumped well, and to a lesser degree, the progressive cavity and electric submersible wells. A recently patented fluid level controller technology enables the electrically pumped well to be optimized with real time fluid level data.The fluid level controller can be used to measure and control the fluid level in a producing well without a packer to within a foot. It can penetrate foamy columns to read previously unavailable fluid levels below the foam. The level at which the pump turns on and off can be preset, and even automatically optimized. The producing bottom hole pressure can be calculated and used to improve the production and operating economics of many different types of artificial lift systems. It can also be used as a reservoir management tool. Its potential applications include:preventing gas-locking, optimizing oil production from rate sensitive producers, conducting pressure transient tests, and evaluating the effects of injection well changes real time in an array of surrounding producing wells.Field data has already revealed some interesting phenomena associated with downhole production observations that may lead to a better understanding of near-wellbore production mechanics. Changes in fluid level as gas rises through the annular column have been detected. Slug flow can be observed in what was thought to be steady state producers.
This paper summarizes the literature research on water shutoff treatment technologies, distills the critical elements for designing a treatment in a naturally fractured Tensleep producer, presents the treatment design process, and shares the field operations experiences and treatment results. The subject well is located in the Teapot Dome Field in the Naval Petroleum Reserve No. 3, Natrona County, Wyoming. The project was funded by the U.S. Department of Energy and the Rocky Mountain Oilfield Testing Center. The literature and interview research illuminated the aspects of the treatment that are scientifically sound, as well as the areas that are in need of additional research. The most important factor in treating wells for excessive water production is the characterization of the water production mechanism. This paper outlines some simple graphical techniques used to identify water flowing through a natural fracture system from an underlying aquifer. Selection of treatment technology, treatment volume, concentration schedule, and quality control issues are discussed. Critical logistics and operational matters are also covered. An unusual approach to the treatment was taken by stimulating the well with a propellant stimulation treatment prior to the water shut-off treatment. This technique is designed to improve the communication with the natural fractures in the near-wellbore area, and allow the treatment to be pumped at lower pressures with less polymer dehydration problems and more effective treatment placement. It is hoped that the improved placement will extend the life of the treatment. The job procedure, cost estimate, schedule, and project economics are presented, and compared to the actual job execution. The treatment had some unexpected pressure behavior during the placement. Ideas are proposed to explain the behavior, and suggestions are made to gather additional data during future treatments to verify the theories and better understand treatment design. The treatment was performed on October 13, 2000 and three months of production data are used to judge its success. Pre-treatment production rate was 14.1 barrels of oil per day (BOPD) (2.24 m3/d) and 7,817 barrels of water per day (BWPD) (1243 m3/d). Post treatment rates after two weeks were 18 BOPD (2.9 m3/d) and 1,880 BWPD (299 m3/d). After three months, production seems to be stabilizing around 12 BOPD (1.9 m3/d) and 3,150 BWPD (496 m3/d). Problems were experienced with ESP pump sizing following the treatment. Literature Definition of State-of-the-Art To determine the best way to shut off water in a naturally fractured producing well, the experience documented in the literature was researched. Some of the authors were also contacted directly to clarify certain issues. The Most Critical Issue: Problem Identification. One theme runs though most of the papers and conversations on which this paper is based. The most critical design issue is to determine the source of the water and the production mechanism. Numerous technologies are available for water shut-off, but the nature of the water production must be known in order to design an effective treatment. The most common cause of water shut-off treatment failure is the misdiagnosis of the problem. Keng Sen Chan1 (1995) gave details on using plots to classify problem water types. Elphick and Seright2 (1997) also published some excellent guides to using plots to help diagnose water problems. Treatment Design. Once the water production mechanism is understood, the water shut-off treatment strategy can be formulated. This involves selection of an appropriate technology, design of an effective treatment, formulation of a treatment procedure, and an effective quality control program.
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