A 30 day waterflooding test in which seawater was injected into two production zones (A and B) of an oil producing limestone reservoir is analyzed. During testing the flow rates were varied to maintain constant tubing head pressure. Injection rates were recorded for three levels of constant tubing head pressures (THP): initial (THP = 990 psig), intermediate (THP = 1240 psig), and final (THP = 1490 psig).
The purpose of the analysis was to detect the possible occurrence of a fracture. A radial fluid possible occurrence of a fracture. A radial fluid flow technique was utilized to analyze the pressure-injection behavior. The analyses disclosed a pressure-injection behavior. The analyses disclosed a change in the formation's ability to transmit fluids. Rock mechanics analyses were utilized to quantify the changes in in situ stress due to water flooding effects (i.e. pore pressure buildup and temperature decrease). The later analysis disclosed that the bottomhole fluid pressures exceeded the modified minimum in situ stresses at the intermediate and final pressure levels.
Both, the increase in fluid transmissibility and the bottomhole fluid pressure rise above the modified minimum in situ stress indicated the occurrence of fracture. A possible fracture geometry was obtained by means of 2-D and 3-D hydraulic fracturing simulators.
The problem discussed herein refers to a 30-day filtered seawater injection into two perforated zones of an oil bearing limestone perforated zones of an oil bearing limestone reservoir. Seawater temperature (110 deg. F) was approximately 51 deg. F lower than the reservoir temperature (161 deg. F). The two reservoir zones defined as A and B are divided according to a vertical permeability and porosity stratification, as shown in Figure 1. The injection test was conducted at three levels of constant pressure. The initial tubing head pressure (THP) of 990 psig was increased to an intermediate pressure step of 1240 psig and, finally, to a pressure of 1490 psig. Plots of the recorded injection rates and psig. Plots of the recorded injection rates and THP versus time, are displayed in Figure 2. Pumping was continuous except for some minor Pumping was continuous except for some minor interruptions.
Spinner surveys at each perforated zone indicated an injection split after 24 hours of pumping at 66% and 34% into Zones A and B, respectively. At the end of the test, after approximately 730 hours, the injection split changed to 14% into Zone A and 26% into Zone, B. These calculated indexes are compared with expected injectivity index values in Table 1. The obtained injectivities for Zones A and B were smaller and greater respectively than expected. These differences were attributed to possible preferential stimulation of Tone B.
The objective of the following sections is to detect suspected fracture occurrence and determine fracture behavior based on reservoir engineering and rock mechanics principles.
During waterflooding the fluid was injected at a constant tubing head pressure while flow rates were recorded with respect to time. The tubing head pressure (THP) and flow rate history are shown in Figure 2.
During the initial constant (THP) value a radial flow analysis will provide a quantitative estimate of the average formation transmissibility. For the later stages, when the pressure was increased, the average estimated kh/mu pressure was increased, the average estimated kh/mu value should remain unchanged. However. an increase to an "apparent" transmissibility could be attributed to a fracture and/or fracture growth. Pursuant to fracturing the formation will pass through several phases of behavior, namely, pass through several phases of behavior, namely, wellbore storage dominated flow, fracture linear flow, formation linear flow, and pseudo radial flow. Since, our main goal is to establish change in fluid transmissibility, these other flow regimes are not considered.