Surface Facilities For Inert Gas Generation And Compression East Binger Unit, Caddo County, Oklahoma

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Hamaker, R.J., Member SPE-AIME, Production Operators, Inc. Production Operators, Inc. This paper was presented at the 1979 Production Operations Symposium of the Society of Petroleum Engineers of AIME, held in Oklahoma City, Oklahoma, February 25–27, 1979. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words. Write: 6200 N. Central Expy., Dallas, Texas 75206. Abstract With the increase in enhanced recovery projects, it is helpful for all operators to have the benefit of the experience obtained to date in order that future projects may proceed as smoothly as possible. It is the intent of this paper to review some of the history and design criteria employed in this miscible recovery project. Further, the experience obtained during the first year of operation along with associated problems are reviewed. Future field performance and its relation to the existing facility performance and its relation to the existing facility is included to cover the full scope of projects of similar nature. Introduction The Marchand Sands formation in Caddo County, OK, were established as a significant producing zone in the first half of 1975. Based on preliminary reservoir analysis and history of the nearby Norge Field, it became evident that some type of pressure maintenance program was required and detailed reservoir studies were authorized to establish the best method of production. Primary production, waterflood, natural gas injection, and inert gas injection were the production techniques investigated over the next 12 to 18 months. The reservoir oil has an API gravity of approximately 42 SSU at 60 degrees F having an intermediate hydrocarbon content (C2 – C6) of 30%. The producing formation is tightly packed sandstone with an average permeability of less than 1.0 md. These hydrocarbon and geological considerations are similar to Arco's Block 31 in Crane County, TX. Research of this project along with the laboratory test on the efficiency of the recovery techniques previously mentioned indicated that a miscible gas drive would be the most effective recovery mechanism. Natural gas was eliminated as a reinjection media based on its current value and, therefore, a substitute inert gas was selected. Flue gas, nitrogen, and CO2 were investigated with flue gas offering the most attractive economic alternate after consideration of all applicable operating and investment parameters. Concurrent with the evaluation as to the method of production, unitization formulas were developed, discussed, and finally agreed upon with approval of the unit by the majority of the operators in Jan. 1977. The Oklahoma Corp. Commission approved the unit in July and flue gas injection began in September of that year (Fig. 1). DESIGN CRITERIA In March 1977, an order was given to proceed with design and construction of a facility to deliver 30 MMscf/D (24 MMscf/D on a long-term contract and 6 MMscf/D on a 3-year contract) at a plant discharge pressure of 4500 psig. Many factors plant discharge pressure of 4500 psig. Many factors were to be considered in the design of this facility with two basic requirements establishing the general plant configuration:earliest possible injection date to allow increased production without further pressure decline in the reservoir, andflexibility in capacity to provide for possible changes in flow requirements. To meet the early onstream date, the contractor elected to move to the plant site two existing 3-MMscf/D modules that had been in operation at another location. Necessary revisions were made to these modules, and they were installed and placed in operation by Sept. 1977, 6 months after approval to proceed (Fig. 2). proceed (Fig. 2).The principle of plant design for this project is to take the exhaust gas generated by the gas engine driver of the injection compressor, catalytically treat this exhaust gas to remove O2 and NOx, dehydrate the gas, and perform the injection compression. (See Fig 3.) By use of this technique approximately 7.5 to 8:0 MMscf/D of dry inert exhaust gas can be delivered at injection pressures for every 1 MMscf/D of fuel consumed. It is helpful also to note that 500 hp will generate about 1 MMscf/D of dry exhaust gas (15,000 hp giving 30 MMscf/D).

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Steam injection in heavy oil recovery often reaches the economical limit. Factors such as steam-oil ratio, generation costs, formation injectivity, reservoir pressure and heat losses are critical for the viability of these projects. This works presents a workflow to develop a scheme of surface facilities for different field conditions, that allows the capture, storage and usage of flue gas generated by steam generators and use it in a steam-flue gas injection process, which is going to mitigate the CO2 emissions, increase oil production and improve the results of steam injection alone in terms of energy efficiency. The proposed workflow has 4 phases: 1) material balance to estimate the composition of flue gas generated based in generator parameters as gas feed, energy capacity and air excess; 2) numerical simulation of the involved processes as combustion, compression and heat exchange to study thermodynamic properties of the flue gas generated; 3) integrity analysis for equipment selection; and 4) determination of the most adequate scheme for flue gas managing according to field requirements. Different case studies for surface facilities development are presented. High initial flue gas temperatures (400°F) and corrosion rates mainly by the presence of CO2 and O2 were identified as critical operation parameters. Since above 140°F corrosion rate gets higher compromising the integrity of the equipment, optimal relation between the gas feed used and an excess of air (15%) might allow a full combustion process decreasing the CO and hydrocarbons fraction in flue gas stream. Cooler units are required after the gas is compressed since the temperature raises, H2O separation has to be done after the first cooling process in order to mitigate the possible formation of carbonic acid on the stream; facilities dimensions are related to the capacity of steam generators and availability of flue gas volumes. The development of an adequate scheme of surface facilities requires an analysis of the conditions described before. Considering that each field has its own characteristics, the current workflow allows to develop optimal facilities for different projects using numerical simulation of multiple processes. The methodology presented allows to determine the adequate facilities for different field conditions, in order to implement a steam flue gas enhanced oil recovery project that increases production and mitigates environmental impacts.
The East Binger Field located in Caddo County, Oklahoma had an expected primary recovery of only 10.7%. After extensive reservoir, laboratory, and model studies, a plan of unitization was approved and an inert gas miscible displacement project was initiated in 1977. Unanticipated operational problems, such as leaks in casings, tubing and packers, plugging of low permeability sand, and other problems were analyzed and solved. Oil and gas production to date is consistent with the predictive models. An anticipated problem of inert gas breakthrough has been handled to date by planned interim methods. In 1984, as a result of engineering and economic studies of several viable alternatives, a decision was made by the East Binger Unit (EBU) to switch to a nitrogen management concept. Under construction, with a late 1986 startup date, is a nitrogen management facility which will replace the existing inert gas supply system as well as replace the interim method of handling produced gas. The facility which is integrated to reduce capital, energy and other operating costs, will provide cryogenically-produced nitrogen from both nitrogen rejection and air separation, 985 Btu/SCF [3.48 × 104 MJ/m3] residue gas, pipeline quality natural gas liquids and 18,000 MSCFD (thousand standard cubic feet per day) [5.1 × 105 m3/D] of 5,000 psig [3.45 mPa] nitrogen. With nitrogen management, higher hydrocarbon recoveries and lower lifting costs are expected.
This paper summarizes the design, selection, installation and operational aspects of hydrocarbon miscible flood field facilities. Field facilities discussed include solvent and gas, fresh and produced water injection pipelines, double block and bleed system, and injection wellhead. The piping design for high pressure injection system is described to explain the economics of selection of high grade pipe. In a cyclic miscible injection system, hydrate formation is the main operational problem. This paper presents the rationale for selection of the unique design of double block and bleed system. The simplicity of this design has reduced operating costs. The techniques involved in switching the cycles from solvent injection to water and vice versa are described. Field facilities pressure testing has always been an outstanding question, especially for miscible injection lines. Water, gas and methanol as test media are evaluated.
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