Summary A study of subsurface water-injection operations in the Willisten geologicbasin demonstrated the practicality of incorporating risk management proceduresinto the regulation of underground injection control (UIC) programs. Arealistic model of a computerized data base was developed to assess the maximumquantifiable risk that water from injection wells would reach an undergroundsource of drinking water (USDW). In the Williston basin, the upper-boundprobability of injection water escaping the wellbore and reaching a USDW isseven chances in 1 million well-years where surface casings cover thedrinking-water aquifers. Where surface casings do not cover the USDW'S, theprobability is six chances in 1,000 well-years. probability is six chances in1,000 well-years. Introduction In the continental U.S., the oil and gas industry operates 170,000saltwater-disposal and EOR injection wells that inject 60 million BWPD intosubsurface formations. By assessing the potential risk of USDW con tamination, operators and regulators can identify those areas where additionalcorrosion-protection measures and increased surveillance of injectionoperations can be most effective in reducing the likelihood of injection waterreaching a USDW. An API study of oil- and gas-industry subsurface waterinjection in the U.S. developed a methodology to quantify an upper limit forthe risk of water from waterinjection wells reaching a USDW. The methoddetermined the probability of simultaneous failures of an injection well'stubing, production casing, and surface casing going undetected, permittinginjection water to escape into the borehole and possible to reach a USDW. The API study also showed that the individual well and field data needed to assessrisk are available, but that the information often is kept by a number ofdifferent operators, regulatory agencies, and commercial computer data bases. The study recommended that a model of a UTC data base be implemented in ageologic basin to evaluate the practicality of collecting and usingrisk-assessment guidelines in managing underground injection programs. As aresult, a study was conducted to test the feasibility of constructing a modeldata base for the Williston basin and to use the risk approach to rank areasbased on their risk of contaminating a USDW. Recommendations on databasecontent solicited from selected regulatory agencies and operators were used todefine the basic engineering, geologic, and injection data, along with thedatabase queries and reports necessary to administer UIC programs andoperations effectively. As a result of this effort, a realistic model wasdeveloped of a data base containing the necessary elements for evaluating therisk of USDW contamination in underground injection operations in the Willistonbasin. Overview of Risk Approach The risk approach to managing underground injection operations in apractical method of prioritizing and/or redirecting personnel and prioritizingand/or redirecting personnel and funds toward activities that are most likelyto contaminate a USDW. Risk-assessment guidelines do not give scientificcertainty, but they can be useful in setting priorities, in designing corrosionprotection systems, and in formulating protection systems, and in formulatingregulations. Risk assessments can help distinguish realistic potential USDWcontamination threats from trivial ones. They also can give regulators theinformation they need to decide what degree of monitoring and testing is neededfor a given area. To be effective, the data elements used in defining risk mustbe an integral part of a basic UIC data base. Such a data base conwellidentifiers, well-completion data, mechanical-integrity test results, injectionvolumes and pressures, and the base and top of the deepest USDW. The dataelements needed to maximize the risk-based decision process include tubing andcasing failure process include tubing and casing failure history, well-workoverresults, and reservoir definition (including identification of corrosive zonesand saltwater aquifers). UIC Regulations A major driving force leading to increased emphasis on the protection of USDW's has been the regulations promulgated by the U.S. Environmental Protection Agency (EPA) under the Safe Drinking Water Act of 1974. That actgave the EPA or an EPA approved state agency the authority to regulatesubsurface fluid injection to protect USDW's. The EPA's UIC program addressesfive classes of injection wells. Class II wells, which the oil industry isprimarily concerned with, include those used for disposal of fluids brought tothe surface and in connection with oil and natural gas production, injection offluids for EOR, and storage of liquid hydrocarbons. JPT P. 737
The offshore pilot test of a submerged production system (SPS) encompassedthe entire spectreum of SPS equipment, which was designed for use in waterdepths to 2,000 ft. Results show that deepwater installation techniques arepracticable, deepwater maintenance machinery is competent to repair anoperating system, with some modifications, the SPS is suitable for commercialapplication. Introduction The purpose of the submerged production system (SPS) is to provide a meansof producing offshore fields in water depths beyond the practical capability ofbottom-founded, surface-penetrating structures. The SPS is an integrated suiteof equipment designed to satisfy the life-cycle requirements for producing asubsea field from developmental drilling through field abandonment. Thisintegrated suite of equipment spans from the completion interval of the wellsto the transfer of produced fluid into a common-carrier pipeline or shuttletanker. The prototype version of the SPS used for the pilot test included atleast one representative piece of every type of oceanfloor equipment requiredfor a commercial application. The subject of this paper is a discussion of SPScapabilities from both functional and maintenance viewpoints followed by adescription of the offshore pilot test performed to validate the SPS concept.The pilot test description covers the prototype SPS equipment, test objectives, conduct of prototype SPS equipment, test objectives, conduct of the test, and, finally, conclusions that were made following an evaluation of testresults. SPS Functional Capabilities The SPS is a full-capability production system. Fig. 1 depicts the system'smost general equipment configuration. The template unit shown on the seaflooris the major component of the system. The fluids produced by the wells andgathered by the template produced by the wells and gathered by the templateunit are routed via pipelines and an articulated production riser to a surfaceprocessing facility for production riser to a surface processing facility forstorage and disposal. The drillship shown in Fig. 1 is used both for installingthe template and for drilling the development wells. Among the designrequirements that apply to all SPS equipment are that they be simply, highlyreliable, and have a long life expectancy. One of the most salientcharacteristics of the SPS is that it eliminates the need to expose personnelto the ocean-floor environment during personnel to the ocean-floor environmentduring installation, operation, maintenance, and (at field abandonment)recovery of the subsea equipment. Surface-controlled, electrohydraulic, supervisory control equipment is used to control and monitor the ocean-floorequipment remotely. On command from the surface, hydraulic power is switched tooperate valve actuators and diverter actuators in the manifold. Allflow-control valves - such as downhole safety valves, master valves, wingvalves, and pipeline block valves - are fail-safe closed and pipeline blockvalves - are fail-safe closed and require the presence of hydraulic pressure toremain open. The monitoring capability provides sufficient information to (1)determine the performance of a well, (2) generate appropriate workoverprograms, and (3) troubleshoot an equipment malfunction in preparation formaintenance. An automatic, fail-safe preparation for maintenance. An automatic, fail-safe safety system monitors the manifold and the control equipment. If anoperating parameter exceeds its preset limit, a preplanned course of action ispreset limit, a preplanned course of action is initiated automatically toreturn the equipment to a safe operating condition, usually to shut in all orpart of the wells. JPT P. 899
The offshore pilot test of Exxon’s Submerged Production System (SPS) has reached a successful conclusion. This pilot test encompassed the entire spectrum of SPS equipment, spanning from the well completion intervals to, but not including, common surface processing and storage facilities. Since the SPS is designed to meet all the life cycle needs of a subsea field, one of the objectives of the pilot test was to evaluate both the techniques and the equipment used to install, operate, and maintain a prototype version of the SPS. The equipment under test was designed for use in water depths up to 2000 ft, but with minor modifications it is capable of operating in significantly greater depths. Evaluation of pilot test results has shown that the deep water installation techniques are practicable and that the deep water maintenance machinery is competent to repair any failures likely to occur in an operating system. One of the most significant problems in conducting the pilot test was achieving adequate quality control during equipment manufacture. The test results have demonstrated that, with relatively minor modifications, the SPS is suitable for commercial application.
Training for computer center operators, design engineers, and maintenance personnel; equipment testing to locate design deficiencies; acceptance personnel; equipment testing to locate design deficiencies; acceptance testing to insure equipment quality and to minimize installation time; and programmed preventive maintenance--these are programs that have been programmed preventive maintenance--these are programs that have been instituted by one major company to assure equipment reliability and data integrity in its computer production control system. Introduction In four of its five operating divisions, Exxon Company, U.S.A. (a Division of Exxon Corporation) has instituted a Computer Production Control (CPC) program, using identical computer centers and program, using identical computer centers and program systems to monitor and control oil and gas program systems to monitor and control oil and gas producing operations. The company presently uses producing operations. The company presently uses CPC to operate 26 fields with a total of 4,100 wells. The daily production of these fields is 315,000 bbl of oil and 1 Bcf of gas. CPC is being installed in eight additional fields, which will bring total CPC-operated production in 34 fields to about 375,000 B/D. production in 34 fields to about 375,000 B/D. The objectives of the CPC program are to increase the effectiveness of producing operations and to use manpower more efficiently. The system is designed to continuously monitor and feed back operating data to field personnel and to perform control functions, generate reports for regulatory purposes, and enter oil and gas volumes directly into the accounting system. The CPC system is a multicomponent operation, with equipment ranging in complexity from a two-position switch to a real-time process control computer. Maximum benefits can be derived from such a system only if (1) personnel responsible for the design, implementation, operation, and repair of the individual components are adequately trained; (2) measurement accuracy and reliability are verified before equipment is selected; (3) equipment is factory and field tested before it is accepted; and (4) programmed preventive maintenance is begun as soon programmed preventive maintenance is begun as soon as the system is implemented. Basic CPC Features In each division office there is a central process-control computer (Fig. 1), which is process-control computer (Fig. 1), which is programmed to monitor and direct field operations. programmed to monitor and direct field operations. The computer has a core memory of 48K and disc storage of more than 7,500K. The peripheral equipment in the computer center includes a high-speed line printer, two type-writers, and a card reader. A computer interface unit connects the computer with a communication network that links the computer with the CPC fields. Field equipment includes end devices located at the wells, metering sites, and central facilities (Fig. 2). These end devices generate volume information, measure tank levels, indicate alarms and status, and perform control functions. The field cabling connects perform control functions. The field cabling connects the end devices to the remote terminal unit, where volume information is accumulated, status/alarms are monitored, and analog (A/D) measurements are made. Upon request, this information is coded and transmitted from the remote terminal unit to the computer. The remote terminal unit also receives and decodes control and set-point (D/A) messages from the computer and transmits them to the appropriate end devices for execution. Phase shift modulation techniques are employed for transmission between the remote terminal unit and the computer interface unit. Data are transmitted at rates of 100 and 600 bits/sec. Communication between the computer center and field operating personnel is maintained through a man-machine input-output (I/O) system. JPT P. 31
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