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This paper documents the findings of the Deep Well Treatment and Injection (DWTI) field research project to demonstrate the use of hydraulic fracturing for non-exempt solids waste disposal. This test involved injection of a large quantity of simulated waste into a porous rock formation at a depth of 4500 feet. The inert material injected was designed to match appropriate properties of actual solid wastes. A total of 4 million pounds of sand and bentonite clay, plus 50,000 bbls of water, were pumped in four batch injection cycles spanning five days of operations. Fracture diagnostic tools used to measure the created fracture geometry included temperature and R/A tracer logs, hydraulic impedance, tiltmeters, and a new real-time passive seismic monitoring and analysis system. Seismic data was measured in two dedicated monitor wells offsetting the predicted fracture azimuth. Each well contained 75 geophones that provided 700' of vertical coverage. Over 2000 seismic events were obtained and analyzed for fracture height; 250 of these were analyzed further for three-dimensional fracture location. The fracture geometry was predicted in advance with a new computer model developed for this waste injection application. Results showed excellent agreement between the fracture height predicted and that measured by the seismic system, but that other diagnostic techniques were not sufficiently accurate. Good agreement between the maximum predicted fracture length and the length from the seismic system was also observed. Introduction The use of hydraulic fracturing for drill cuttings injection and other solid waste disposal has increased considerably in the last five years. Annulus injection of drill cuttings is frequently performed in the Gulf of Mexico, Alaska, the North Sea, and other parts of the world. Fracturing has also been used by Shell and ARCO to inject Naturally-Occurring Radioactive Material (NORM) in the Gulf of Mexico and by ARCO and BP at the Prudhoe Bay Unit in Alaska. With these applications of fracturing for exempt solids disposal in mind, ARCO has performed a field research program to demonstrate the safe use of hydraulic fracturing for disposal of non-exempt solid materials, such as contaminated soils and refinery sludge material. ThIs research program, called the Deep Well Treatment and Injection Program (DWTI), included fracture model development, assessment of waste transport due to groundwater flow, and the field demonstration project. This paper focuses on the hydraulic fracturing modeling, operations and diagnostics performed for this project. The goals of the field demonstration project were:To safely inject significant quantities of simulated solid waste material via hydraulic fracturing. P. 319^

A large unexplored tectonic basin with the potential for significant hydrocarbon accumulations was identified in north‐central Oregon using a variety of geophysical techniques. The basin, informally named after the local town of Heppner, is covered by several thousand feet of Miocene Columbia River Basalt Group (CRBG) but is readily identified by a gravity low against the Blue Mountains Uplift. The Paleocene/Eocene Herren Formation (Pigg, 1961), which outcrops on the Blue Mountains Uplift south of the Heppner Basin, offered good source and reservoir potential. Based on lateral extent, thickness and paleocurrent structures in the Herren Formation, the unit was expected to be present in the basin. Gravity modeling produced nonunique interpretations, thus magnetotelluric (MT) information was used to constrain the CRBG thickness. Static shifts in the MT data were removed using transient electromagnetic (TEM) data before MT data inversion. After extensive experimentation, adequate seismic data were obtained for structural mapping, but the seismic data were interpretable with confidence only after MT determinations of the CRBG thickness. As a result of the favorable geologic and geophysical information, the ARCO Hanna ♯1 well was drilled to 9100 ft (2800 m) near Heppner, Oregon in section 23, T2S, R27E in 1988. The thickness of the CRBG and Oligocene John Day Formation were accurately predicted by the geophysical interpretations. An unanticipated thickness of Eocene Clarno Formation was encountered and drilling ceased in this unit. No Herren Formation was penetrated during drilling. Geophysical well logs indicate the Clarno Formation has densities and resistivities sufficient to account for the gravity and electrical anomalies defining the prospect. Poor seismic quality was explained by the heterogeneous nature of the pre‐CRBG volcanic section encountered in the well.

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Production stimulation is commonly performed on reservoirs by hydraulically fracturing the formation. Fracture geometry is controlled by the regional stress field, strength and contrast in local rock stress and fracture fluid properties. Computer models predict the length and height of the fracture as a function of injection volume, pressure and rate, and, fluid and rock properties. Until recently, these computations were unable to be verified except for the fracture half length with pressure transient analysis and through log interpretation in close proximity to the well. Direct confirmation of fracture geometry has been shown possible with availability of downhole geophysical monitoring of the seismicity associated with the fracture production. This paper presents results of a test to directly measure the height, length, and azimuth of a fracture generated in the Prudhoe Bay Field, Alaska. Two triaxial geophone tools were deployed during August 1993 to monitor for microseismicity associated with a hydraulic fracture. One tool was deployed in an offsite monitoring well, and the second tool was deployed in the rathole of the fractured well. The objectives of the test were (1) to determine if seismicity existed and if it could be detected from within the fractured well and from the distant offsite monitoring well, (2) to evaluate techniques used to locate the fracture, and (3) provide guidance for the development of seismic recording systems used in fracture monitoring. Introduction Three techniques were used to monitor the hydraulic fracture. Each offered different operational advantages and disadvantages. This experiment attempted to evaluate each of these for future development. They were:offsite monitoring of the hydraulic fracture from a well that was 1450 feet away,monitoring from within the rathole of the fractured well,documenting the change in the vertical-to-horizontal earth noise ratio (H/Z) prior to, and following the hydraulic fracture in a deviated well for fracture height determination. Seismic monitoring of hydraulic fracturing has been successful in locating fracture paths in crystalline rock at the Hot Dry Rock Geothermal sites in New Mexico and Great Britain. It was hoped that these same techniques would work to monitor a hydraulic fracture in reservoir rock from an offsite monitoring well which was approximately 1450 feet away. Additionally, fracture height, length and orientation have been successfully monitored from the rathole of a water injection well in the North Sea. Finally, the Gas Research Institute has published a report and secured a patent outlining a unique method of determining fracture height known as H/Z. The primary goals of this test were to first determine if seismicity existed and if it occurred at rates high enough to be mapped in the Prudhoe Bay reservoir. Secondly, to evaluate and test the three techniques outlined above to determine if they would provide acceptable data for fracture monitoring. Finally, if adequate data was obtained, to map a hydraulic fracture using one or all of the above techniques. Background seismicity and perforation shot data were collected to determine the levels of seismic activity in the formation and document how well the formation propagated seismic energy. These data also allowed calibration of the seismic recording systems, and provided velocity information used in the location algorithms. It should be noted that the offsite DS 17-16 monitoring well had a lower zone fractured 10 days prior to the monitored fracture, and that proppant had been left over the open perforations to provide a "quiet environment for monitoring. The selection of well 17-16 permitted long baseline measurement of 10 day old fracture related seismicity. Any events located in the near wellbore area of well 17- 16 were mostly likely associated with the 10 day old fracture. Data were recorded in both the liner and the tubing of the monitoring well to determine if data could be obtained in the tubing of a completed well. This had obvious operational considerations, since a successful recording would obviate the need to pull tubing and set bridge plugs in future projects. The hydraulic fracture treatment was designed to simultaneously fracture two different zones, Sag river and Zone 4. In an attempt to get the best hydraulic fracture design possible, the fracture program consisted of three major steps. First, a high rate injection profile was performed to determine the distribution of flow between the two zones at rates above fracture pressure. Next, a comprehensive data frac was performed, and finally, the hydraulic fracture with proppant was completed. P. 387^