The low-permeability (1 to 100 mu d) sand members of the Rotliegendes and the Carboniferous formations are a major source of gas reserves in West Germany. To establish commercial production from the limited number of deep (+13,100 ft [ +4000 m]) Rotliegendes and Carboniferous wells drilled to date, stimulation of the wells with massive hydraulic fracturing (MHF) treatments is necessary. A great deal of effort was directed not only at the design and performance of these MHF stimulation jobs, but also at the interpretation of buildup data obtained from the treatments and at the integration of the results into a model for future production forecasts.
This paper reviews the available hand-applied methods used to analyze the postfracture behavior of wells stimulated with the MHF technique. These methods analyze buildup data collected during the past 5 years from three wells, each producing from more than one horizon. The results of these analyses include the length and conductivity of the fracture created during the MHF treatment.
Recent estimates of gas reserves in West Germany amount to about 10.6 × 1012 scf [300 × 10 std m3]. Similar reserves are anticipated from future discoveries, which will probably occur in the Rotliegendes and Upper Carboniferous formations and are expected to be deep, low-permeability reservoirs. We estimate that at least one-third of the predicted discoveries can be produced economically if MHF stimulation treatments are applied.
For an economic evaluation of the high cost of the development of deep, low-permeability gas reservoirs, it is necessary to predict the long-term flow behavior of MHF wells. This prediction requires realistic estimates of the length and the conductivity of the fracture system created in an MHF treatment, estimates of the formation permeability, and estimates of other reservoir parameters. permeability, and estimates of other reservoir parameters. This study updates Brinkmann et al.'s 1980 work, which reviewed the "hand-applied" methods that were available and used them to analyze the early data for three MHF wells and to obtain estimates for the fracture parameters. Since then, more data and methods have parameters. Since then, more data and methods have become available for the analysis. Data comparisons give some indication of the long-term behavior of the fracture properties. The new methods are suited for the analysis properties. The new methods are suited for the analysis of fractures intercepting multilayer reservoirs and result in improved estimates for the properties of the multihorizon/ multifracture system typically encountered in the Rotliegendes and Upper Carboniferous wells.
The locations of the gas fields and the analyzed wells in northern West Germany are shown in Fig. 1. Each well produces from more than one horizon. The horizons were produces from more than one horizon. The horizons were separated by thick shale layers and were individually fracture stimulated. The well log for Goidenstedt Well Z7, shown in Fig. 2, is typical for all the wells. The available pressure/production performance results for the wells are shown in Fig. 3.
The purpose of MHF is to expose a large surface area of the low-permeability formation to flow inside wellbore. This is achieved technically by generating fractures that extend far into the formation and by filling them with proppants to keep the fractures open and to ensure a high proppants to keep the fractures open and to ensure a high conductivity. A low-permeability formation is characterized as having an in-situ permeability of 1 to 100 mu d.
At depths of +13,100 ft [+4000 m], a two-wing vertical fracture is created and is assumed to be symmetrical around the wellbore. Fig. 4 illustrates the influence of a two-wing vertical fracture by showing a three-dimensional representation of the pressure distribution in one quadrant of the drainage area of the MHF gas well Hamwiede Well Z2 (lower interval). Table 1 lists the reservoir parameters.
After 1 year of production, the cumulative production amounted to about 636 ⨯ 10 scf [18 ⨯ 10 std m3 ] corresponding to 3% of the gas initially in place within the drainage area.
Fig. 4 shows the influence of the fracture on the flow behavior in the reservoir. The flow is no longer radial to the wellbore; instead, it is almost linear in the region nearest the fracture. Radial flow is primarily away from the fracture. Therefore, conventional radial flow theory, as described in Refs. 2 through 4, is inadequate for analyzing low-permeability MHF gas wells.
To make realistic predictions for the rates and reserves of MHF wells and to evaluate the long-term effectiveness of the stimulation, a theory explicitly accounting for the fracture system created in the MHF treatment was used.