TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper shows a comparison of dual-array microseismic maps with single-well maps for horizontal wells in the Barnett shale. Results from two test cases showing gel and water fracturing maps are given and compared with initial production. Dual-array mapping provides for a much larger areal coverage and increased accuracy when accurate bottomhole locations and velocity structure are available, but do have trade-offs that need to be considered.

Surface Tilt Mapping (STM) has been successfully applied to stimulation treatments, disposal projects and in numerous steam floods to provide information on fluid movements in the reservoir.This proven technology has now been applied to a waterflood in the San Andres formation at a depth of 5600 feet to analyze preferential flow.Since typical water injection rates in the San Andres range from 100 to 300 BWPD, a novel flowback method was developed to maximize the STM response when testing injection wells under normal operating conditions.An analysis technique that allows the removal of earth tides was also applied to further enhance the quality of the data.The STM results showed conclusive preferential flow direction in the seven wells tested.In most wells, multiple tests were performed with good agreement on the flow trend. Background The Reeves Unit (location shown in Figure 1) was originally discovered in 1957.In 1965 a unitization and peripheral waterflood was initiated and by 1997 the Unit had been drilled to 20 acre spacing and converted to a line drive pattern.Table I contains the formation and production data for the Unit.As shown in Figure 2, the line drive waterflood pattern was established on a northeast/southwest alignment of the injectors. In waterflood operations it is common to have preferential flow trends that can either create considerable economic problems, due to early breakthrough and high water handling costs, or be used to increase recovery by optimum alignment of the flood pattern.Mapping the movement of injected fluids as they travel in the reservoir is a challenge that Operators have tried to overcome using numerous techniques.In the Reeves Unit, in Yoakum County, Texas, fluid movement in the reservoir was determined by employing STM in conjunction with a novel flowback method that induced a detectable movement in relatively low rate water injectors. Tiltmeter Fracture Mapping The principle of tiltmeter fracture mapping is simply to infer fracture geometry by measuring the fracture-induced rock deformation[1]. The induced deformation field radiates in all directions and can be measured either downhole with wireline-conveyed tiltmeter arrays or with a surface array of tiltmeters. Surface tiltmeters measure the fracture direction, dip and depth to fracture center, whereas downhole tiltmeters measure the dimensions of the hydraulic fracture. Figure 3 shows a schematic diagram of the induced deformation field from a vertical fracture (during injection) as seen both downhole and at the surface. The deformation field of a purely vertical fracture measured by surface tiltmeters is a trough that runs along the fracture direction with "bulges" on either side.The symmetry of the "bulges" on both sides of the trough indicates fracture dip.The deformation of a purely horizontal fracture is a radial bulge with the highest deflection centered roughly at the wellhead, and no associated troughs[2]. Procedure/Objective Initially, the procedure was to install the Tiltmeters into an active area of the Reeves Unit waterflood (Figure 4) and monitor the deflections within the waterflood for a baseline.Then the injection wells were shut-in to produce a change in the system and attempts were made to measure this "relaxation" in order to establish the preferential flow trends.Unfortunately, the surface deformation from shutting in the wells was not sufficient to establish conclusive flow trends.The next step was to re-establish injection and record the response.This resulted in better data, but the signal magnitude was still not sufficient in all wells.To increase the magnitude of the deformation it was decided to rig up the injection wells for flowback.The piping and tank was configured to allow the wells to immediately be diverted from injection to production.Due to the reservoir pressure, it was possible to flow back the wells at rates 5 to 10 times the average daily injection rate for periods of up to 2 hours.This resulted in rapid deformations that could be detected by STM.The analysis of this data on many wells was straightforward but for other wells it was difficult to analyze the magnitude of the deformation due to the influence of earth tides.