The Anton Irish field was discovered in 1945, unitized in 1950 for a produced gas pressure maintenance project and converted to a waterflood in 1969. In 1997 CO 2 flooding began and currently accounts for about 85% of the unit production. Presently, the entire field produces around 6,500 BOPD; 36.5 MMCFPD of recycled CO 2 , and 69,200 BWPD. Over the years of flooding, various conformance problems have been identified and many attempts have been made to address these problems with limited to no success. In 2003 a new program was initiated to re-evaluate the problems and design better solutions. This paper will outline the diagnostic efforts that were undertaken, discuss the basic findings of that effort, review the resulting solutions that were designed to resolve these problems, and show the results of this work.
This paper discusses a data-base of information collected from 322 projects, all treated with the same Microbial Enhanced Oil Recovery Process An analysis of the data quantifies the effectiveness and economics of this particular process, and is a source of information useful for predicting treatment response in any given reservoir. Introduction During the past ten years, much attention has been focused on the evaluation of individual field applications of a variety of different Microbial Enhanced oil Recovery ("MEOR") processes. Little, if any, data has been published that reports the results of a single MEOR technology applied across a variety of reservoirs and production strategies. Consequently, oil producers have been resistant to accepting individual, commercial MEOR technologies because they perceive that MEOR has not been subjected to enough extensive, widespread field testing. This paper will present data illustrating the effectiveness of a single MEOR process that has been successfully applied and results quantified in a large number of commercial projects, representing more than 2,000 producing oil wells in the United States. Since these projects represent such a large number of oil reservoirs, comprising a wide variety of bottomhole conditions, formations, and drive types, it is now possible to provide much needed data to producers that can be used to predict how any given reservoir will respond to this MEOR process. A data-base, which is believed to be the first of its kind, has been created with data collected from the broad use of this MEOR system. The data has been organized to isolate ranges of individual reservoir characteristics like lithology, porosity, permeability, crude oil gravity, etc. so that they can be compared to the corresponding response in oil production observed after implementing MEOR. Information generated with the data-base can be used by producers as a tool to determine which of their reservoirs may be the best candidates for this process. It also provides oil producers with information they can use to make informed, economic decisions when considering the feasibility of utilizing this MEOR process once a candidate reservoir has been identified. Background Almost 3 million oil wells have been drilled nationwide within the United States and thus for more than 500 billion barrels ("bbls.") of oil have been discovered. primary and secondary recovery, using conventional technology, are expected to recover only 33% (~175 billion bbls.) of the 500 billion barrels of original oil in place ("OOIP"). P. 693
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractPolymer gels used for shutting off unwanted water in producing oil wells are certainly no stranger to the Arbuckle dolomite formation in Kansas, but in years past, they have delivered short-lived results and have been only marginally successful. In November 1997, that all changed after a unique design strategy utilizing proven polymer gel technology caused dramatic increases in oil production that resulted from shutting off a significant volume of water from a well located in the Bemis-Shutts field. Since that time, more than 200 wells have been treated for about 35 different operators with a greater than 95% success rate. Thousands of barrels of incremental oil at each treated well are being realized, and hundreds of thousands to millions of barrels less water are being produced from each treated well, than otherwise would have been produced without the treatment. These treatments are extending, by several years, the economic life of many Arbuckle wells, and are bringing shut-in wells back to life. This paper will report lessons learned from applying polymer gel water shut off technology to the Arbuckle formation, and present statistical data derived from a detailed database that has been maintained throughout the project. In addition to using the database as a tool to quantify results and further improve job performance, it is also being used to improve the predictability of response to treatment. Posttreatment oil and water production performance and treatment longevity will be compared to several variables like polymer gel treatment volume and injection pressure. The paper will also discuss how polymer injectivity and post-treatment well performance changes from place to place within the Arbuckle formation. Finally, treatment economics including job cost, payout time, revenue gain from increased oil and decreased water production, and return on investment will be presented.
This paper was prepared for presentation at the 1999 SPE Mid-Continent Operations Symposium held in Oklahoma City, Oklahoma, 28-31 March 1999.
This paper investigates the application of a proprietary surfactant-solvent package as an alternate chemical solution in Enhance Oil Recovery (EOR). This micro-emulsion system (MES) has many upsides to traditional solvent or surfactant-alone alternatives, as the package can be transported in-depth with less sacrificial adsorption yet maintain its interfacial tension reduction and oil swelling abilities to mobilize residual oil. While designing conformance jobs over the past several years, it has been observed that often times the injected fluids tend to travel through high permeability channels between a binary pair(s) of injector and producer. This short-circuit of injected fluids leaves residual oil in the channels and renders a large volume of the reservoir unswept. This paper examines the specific MES application where a high permeability channel is treated to mobilize the residual oil. The characteristic of the high permeability channel is based on production data and is comparatively relative to the total flood zone between a producer and an injector. Due to the small size of the channel the mobilized oil will be produced quickly resulting in attractive economics (due to smaller volume of treatment required). Due to quick response and attractive economics, there will be added incentive and field data to decide whether to expand the treatment on a field wide basis. Subsequently, the moving forward plan could be that once the treatment is validated, this process will be used in conjunction with conformance control along with Polymer as mobility control drive fluid for fieldwide expansion. Laboratory core flood experiment shows that a 1.0 PV slug of 1 gallons for thousand gallons (gpt) of the complex MES additives recovers about 9-12% OOIP (23-27% OIP). The experiment shows that an increase of oil cut from 1% to 12% occurs due to use of the complex MES. The laboratory experiment was performed with oil saturated Torrey Buff sandstone core. The results of this experiment were simulated using CMG's STARS simulation tool. The laboratory results were scaled up to test in two pilot configurations where the remaining oil in the channels was the primary target of the simulation exercise. The first pilot is a quarter 9-spot with one injector and three producers. The second pilot is a central injector in the up-dip of the structure with 5 producers. The simulation results show that the peak oil production due to the effect of the MES is very significant. The economic analysis indicates attractive returns over continued waterflood for both pilots.
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