Summary A field test was performed at the Coleville field to evaluate the ability of indigenous bacteria to remove sulfides from reservoir brine. Ammonium nitrate and sodium phosphate were injected continuously at two injectors for nearly 50 days. Sulfide levels at the two injectors declined by 42 to 100% and by as much as 50 to 60% at two adjacent producers. Concentrations of indigenous sulfide oxidizing, nitrate-reducing bacteria increased at injectors and producers while concentrations of sulfate-reducing bacteria remained unchanged or decreased slightly. Stimulation of indigenous beneficial bacteria has potential application as a cost-effective, low toxicity means to remove and control sulfides in reservoir brines. Introduction Produced water from oil reservoirs frequently contains soluble sulfide (H2 S, HS– and S2–) as a consequence of the activities of sulfate-reducing bacteria (SRB). The presence of sulfides in produced brine creates serious problems for the petroleum industry due to their toxicity, odor, corrosiveness, formation of insoluble metal sulfides, and lowering of the sales quality of produced gas. Removal and control of sulfide in reservoir brines typically involves the injection of chemicals such as sulfide scavengers and biocides, whereas, protection from the corrosive nature of sulfides is often accomplished using corrosion inhibitors. Some of the problems with the use of these chemicals include their lack of selectivity, stability, and compatibility. Additionally, many of these chemicals are expensive, toxic, and hazardous. An alternative method to remediate sulfide in reservoir brines is through selective manipulation of the indigenous bacteria. Jenneman et al.1 and Jack et al.2 demonstrated that indigenous bacteria in a sulfide-laden environment (e.g., sewage and oil field reservoir brines) could be manipulated by changing the dominant electron acceptor from sulfate to nitrate such that nitrate-reducing bacteria (NRB) oxidize the sulfide present and out-compete the SRB for common electron donors, e.g., organic acids. This approach was subsequently shown to be applicable to other produced brines from oil and gas fields3,4 as well as gas storage fields.5 During a microbially enhanced oil recovery field test, McInerney et al.6 added ammonium nitrate to injected brine at the Southeast Vasser Vertz Sand Unit in Payne County, OK and reported a 40-60% reduction in sulfide at three adjacent producers that was attributed to the activity of indigenous NRB. Sublette et al.,7 at the Salt Creek field in Wyoming, demonstrated that the non-indigenous NRB, Thiobacillus denitrificans strain F, when added to produced brine successfully removed sulfides using oxygen as an oxidant. Jack and Westlake8 reported that although the introduction of 100 ppm nitrate to an oil field brine resulted in significant changes in biofilm populations and a reduction in iron sulfide concentrations, the nitrate addition also resulted in an increase in SRB counts and a six-fold increase in corrosion rates. More recently, Hitzman and Dennis9 as well as Giangiacomo and Dennis10 successfully demonstrated that the application of a patented combination of nitrate, nitrite and molybdate 11 could be used to reduce sulfide concentrations and control SRB in a process referred to as biocompetitive exclusion. This process is designed to stimulate indigenous NRB to out-compete SRB for a common electron donor, i.e., fatty acids. Reservoir Description. The Coleville field (CV) is located near Kindersley in Saskatchewan, Canada. The field was discovered in 1951 and has been on water injection since 1958. The wells produce from the Bakken sandstone at a depth of 823 m and a bottom hole temperature of 29°C. The permeability of the formation averages between 0.49 and ?m 2 with streaks up to 3.0 ?m2. The oil is heavy, asphaltic crude with an API gravity of 13. Currently, produced water is reinjected at a rate of 4770 m3/d with less than 5% of this being make-up water from the Belly River formation. The injected brine contains total dissolved solids of less than 7500 mg/L and a pH of 7.5 at reservoir pressure. Chloride, bicarbonate and sulfate are the principal anions with sodium, calcium and magnesium the major cations. Fatty acids such as formate, acetate and propionate are below detectable levels >10 mg/L). Throughout the field, sulfide concentrations in the produced brine range from a few mg/L to greater than 200 mg/L. Souring is believed to have occurred through the activity of SRB at the time water injection was initiated. The presence of sulfides, SRB, and chlorides in the brine has contributed to a corrosive environment, which has lead to the need to apply corrosion inhibitors at the producers and a biocide at the water plant. Due to the high cost and hazardous nature of these chemicals, manipulation of indigenous bacteria through nitrate injection was evaluated as a means of removing sulfide and controlling SRB. Biological Sulfide Oxidation. During laboratory tests, the addition of 5 mM KNO3 and 100 ?M NaH 2PO4 to CV reservoir brine resulted in the complete oxidation of over 100-mg/L sulfide within 15 hours.12 This oxidation was later found to be due to the presence of a unique group of sulfide-oxidizing NRB indigenous to the CV brine.13 These NRB oxidize sulfide without the apparent requirement for organic compounds according to the equation: 5HS−+2NO3−+7H+→5S0+N2+6H2O.12 Therefore a prominent feature of this reaction involves the oxidation of sulfide to elemental sulfur via the activity of indigenous, sulfide-oxidizing NRB.
Summary This paper describes the analysis of the long-term oil production performance of 37 near-well polymer treatments on 26 producing wells in western Kansas to determine incremental oil recovery resulting from the treatments. Estimated incremental oil recovery from the 37 treatments was 76,500 STB of oil from 39,600 Ibm of polymer injected, or 1.93 STB/lbm of polymer injected. The polymer treatment types giving the best oil recovery performance were solutions of anionic polyacrylamide (ungelled) and cationic polyacrylamide gelled in situ with the chromium reduction/oxidation process. Both gave incremental oil recoveries of 2.6 STB oil/Ibm of polymer injected and had average treatment lifetimes exceeding 1 year. Introduction Polymer treatments of injection and production wells have been used extensively for fluid diversion and to increase oil recovery. Injection of high-molecular-weight polymers increases the viscosity of the injected water and reduces the permeability of the porous medium to water. In producing-well treatments, the injected aqueous polymer solution preferentially flows into zones that exhibit high permeability to water and subsequently restricts the flow of water when the well is put back on production. Polymer injection has two effects: the water production rate decreases substantially and the pressure drawdown into the wellbore often increases greatly, resulting in an increased oil production rate. During the 1970's, Phillips Petroleum Co. conducted 37 polymer treatments on 26 producing wells in western Kansas. All but one of the treatments were on wells completed in the Arbuckle dolomite formation. The formation has been characterized as a highly fractured, vuggy dolomite with varying amounts of chert and with reservoir characteristics varying from field to field throughout the Central Kansas Uplift. Permeability ranges from 50 to 5,000 md; porosity ranges from 1% to 20%, with an average of 15%. The oil zone is estimated to be 5 to 50 ft thick; the total Arbuckle zone is up to 300 ft. Oil viscosity ranges from 3 to 13 cp. The reservoir drive mechanism is primarily bottomwater drive, and the wells are completed at the top of the formation to delay the onset of water production. Water production comes primarily from coning. Because of the natural fracture network, vertical permeability is high and there are few vertical barriers to restrict water coning.
Summary Microbial enhanced-oil-recovery (MEOR) nutrients were injected in an injection well at North Burbank unit (NBU) in Oklahoma to plug off high-permeability layers through the growth of indigenous microorganisms and to divert injection fluid to lower-permeability, higher-oil-saturation zones. Several different types of treatments were performed using both sequential and co-injection of nutrients. Pressure falloff/injection tests and vertical injection profiles were conducted before and after nutrient injection. The results of pressure injection tests following co-injection of nutrients and an incubation period indicated a 33% drop in the effective permeability to the injection fluid and a negative skin factor, while injection profile surveys showed a 33% reduction in the zone taking water. Swabbed samples from the injector following shut in revealed abundant bacterial concentrations and products as well as oil and inorganic solids. Although significant in-depth permeability reduction was observed following nutrient co-injection tests, the unstable behavior of the plug suggested that insufficient biomass was being formed to effectively seal off the higher-permeability zones. Introduction The NBU located in Osage County, OK has been the target of numerous enhanced-oil-recovery (EOR) efforts over the past 25 years. It is estimated of the 671 MMbbl of original oil in place (OOIP), over 300 MMbbl of oil remain. In 1980, a freshwater polymer flood was initiated in a 1,440 acre section of NBU, and this project accounted for an additional 2.5 MM STB of oil over that attributable to waterflooding alone. However, declining oil prices and the costs associated with procuring fresh water have made the further expansion of freshwater polymer flooding in NBU only marginally attractive. For these reasons, Phillips Petroleum Co. began to look to MEOR as an alternative method to chemical EOR for increasing oil production at NBU. MEOR has several potential advantages over chemical EOR. Microbial processes can use inexpensive feedstocks (e.g., molasses) and convert them to products, such as solvents, surfactants, acids, polymers, and gases, that have potential for increasing oil recovery. Microbial processes can be applied in situ so that products are produced in the reservoir, avoiding some of the problems of product retention by the reservoir rock. Also, MEOR processes are environmentally friendly because they use only biodegradable chemicals and nonpathogenic microorganisms.
A freshwater polymer-flood project was implemented in a 1,440-acre area of the North Burbank Unit (NBU) in 1980 with sequential injection of 4.2 million Ibm of polyacrylamide and 4.0 million Ibm of a 2.9% aluminum citrate crosslinking solution. Response to polymer flooding has been very pronounced, with ultimate incremental oil recovery projected to exceed 2.5 MMSTB of oil and total project oil expected to be 4.5 MMSTB. A crosslinked polymer-flood process for use in brine was developed that displays equally favorable performance characteristics as the freshwater polymer-flooding system.
The Maureen field, a light oil reservoir in the North Sea which has achieved waterflood oil recovery close to 53 percent of the OOIP is nearing the end of its producing life under waterflooding operations. This field was evaluated as to the feasibility of improved oil recovery through high pressure air injection as an inexpensive substitute for other unavailable or costly gases. Six accelerating rate calorimeter (ARC) tests and five combustion tube tests were conducted to determine the oxidation characteristics of Maureen crude oil while injecting air in the presence of reservoir rock and brine. These tests showed that Maureen oil will reliably autoignite, generate flue gas (85 % N2 and 15 % CO2) and propagate a stable combustion front. In addition with air enrichment, a first contact miscible displacement process can be maintained. High pressure air injection was then modeled as a miscible process using the history matched Maureen waterflood model: the results showed incremental oil recovery due to air injection would range from 17.8 to 26.3 MM STB (4.5 to 6.6% OOIP) depending on the relative location of the air injection wells (flank or crestal). Introduction The Maureen field in the UK sector of the North Sea has achieved water flood oil recovery close to 53 % of the original oil-in-place (OOIP), but is nearing the end of its productive life under water- flooding operations. The water flood has achieved a volumetric sweep efficiency in the range of 90 percent and most of the reservoir hydrocarbon pore volume has been reduced to the residual oil saturation to water of 23 percent, but if abandoned in its present state, Maureen will leave 175 MM STB in place as unrecoverable oil. The next phase of economic oil recovery will require a displacement fluid that is near first-contact miscible, can be recycled, and is available offshore for less than $1.5 US/reservoir bbl. One way to achieve these objectives is through high pressure air injection. High pressure air injection can reduce the residual oil saturation through formation of a miscible gas bank which will displace the remaining oil to the producing wells. This was confirmed by phase behavior modeling of Maureen oil and combustion product gases. Scoping model runs show that high pressure enriched air injection (30 percent oxygen) in a waterflooded reservoir can generate a first-contact miscible fluid in-situ for less than $1.5 US/reservoir bbl. Laboratory combustion tube tests with Maureen oil and core material show that oxygen will oxidize about 3 to 5 saturation units of the oil to create carbon dioxide, generate heat for the steam, and upgrade the oil by 2 to 4 API units. The miscible gas mixture is expected to consist of 34% steam, 16% CO2 and 50% N2. As the extracted oil and steam cool, the foamy oil and water will form a temporary emulsion until carbon dioxide separates from the liquid phases. This temporary emulsion prevents oxygen bypassing the oxidation front and improves sweep efficiency by decreasing the mobility ratio to less than 0.5. Based on Permian Basin experience of enhanced oil recovery from waterflooded reservoirs in west Texas, a carbon dioxide rich gas mixture would be the ideal fluid for increasing oil recovery from the Maureen reservoir. A carbon dioxide gas mixture will recover an additional 8 to 15 percent of the original oil-in-place in the contacted reservoir volume over that achievable by water-flooding. As the reservoir temperature increases due to depth of burial or due to combustion, less carbon dioxide is required in the gas mixture to effectively extract most of the medium to light gravity oil. For temperatures over 200 C, water (in the steam phase) and carbon dioxide can be injected to create a first-contact miscible gas mixture. Experience learned from Amoco's West Hackberry project and Koch's Medicine Pole Hills project shows that it requires about two-thirds of a pore volume of injected air to sweep the reservoir. Laboratory tests show the Maureen oil will autoignite at reservoir temperature, therefore only a single well huff-and-puff test will be required to prove the Maureen oil will oxidize at field conditions. P. 655^
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