Embodiments of this application relate to methods and apparatus to model fractures in subterranean formations and to treat the formations using information from the models.
In tight gas formations, hydraulic fracturing treatments are often carried out in multiple stages when there are many gas bearing formation layers (payzones) over a large depth interval in a well. The minimum horizontal in-situ stress has a strong effect on hydraulic fracture height, and the hydraulic fracture height is an important factor to consider in designing the treatments. It is time consuming to manually design staged hydraulic fracturing treatments in tight gas formations when the number of payzones is large (over 100). The design of fracturing treatments depends on many factors, such as petrophysical and geomechanical properties of the formation. Algorithms are available for staging design based on petrophysical properties, but the in-situ stresses have not been considered in such algorithms. The minimum horizontal in-situ stress has a strong effect on hydraulic fracture height (
Embodiments of the invention relate to a method for treating a subterranean formation comprising measuring mechanical properties of a formation comprising Young's modulus, Poisson's ratio, and in-situ stress; determining formation fracture height based on the mechanical properties; estimating number and location of hydraulic fractures based on the determining; identifying hydraulic fracturing treatment stages based on the estimating; and performing hydraulic fracturing treatments in the stages. Embodiments of the invention also relate to a method for treating a subterranean formation comprising measuring mechanical properties of a formation comprising Young's modulus, Poisson's ratio, and in-situ stress; determining a target zone based on the mechanical properties; estimating number and location of hydraulic fractures based on the determining; identifying hydraulic fracturing treatment stages based on the estimating; and performing hydraulic fracturing treatments in the stages.
At the outset, it should be noted that in the development of any such actual embodiment, numerous implementation—specific decisions must be made to achieve the developer's specific goals, such as compliance with system related and business related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time consuming but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure. In addition, the composition used/disclosed herein can also comprise some components other than those cited. In the summary of the invention and this detailed description, each numerical value should be read once as modified by the term “about” (unless already expressly so modified), and then read again as not so modified unless otherwise indicated in context. Also, in the summary of the invention and this detailed description, it should be understood that a concentration range listed or described as being useful, suitable, or the like, is intended that any and every concentration within the range, including the end points, is to be considered as having been stated. For example, “a range of from 1 to 10” is to be read as indicating each and every possible number along the continuum between about 1 and about 10. Thus, even if specific data points within the range, or even no data points within the range, are explicitly identified or refer to only a few specific, it is to be understood that inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that inventors possessed knowledge of the entire range and all points within the range. The statements made herein merely provide information related to the present disclosure and may not constitute prior art, and may describe some embodiments illustrating the invention.
Embodiments of this invention include a method for automatically designing multi-stage hydraulic fracturing treatments in multi-payzone formations based on the minimum horizontal in-situ stress. A method was developed to select the number and locations of hydraulic fractures required to stimulate all payzones, and at the same time, with no or minimal overlapping of fractures. The hydraulic fractures are then grouped together based on available pumping capacity for each treatment stage to determine the number of stages required to treat the entire well.
The method is applicable for vertical or slightly deviated wells in tight gas formations. For such formations, long fractures are required to achieve a production increase. The tight gas formations often consist of shale and sandstone sequences, and the gas production is mainly from the sandstone layers. The applicability of the method depends on stress contrasts to limit fracture heights to practical magnitude. When there is no stress contrast large enough to limit fracture height growth, other rules are required for the treatment stage design.
As briefly discussed above and illustrated by
Embodiments of this invention relate to methods to automatically design staged hydraulic fracturing treatments based on fracture height and in-situ stress. A method was developed to select the number and locations of hydraulic fractures required to stimulate all payzones, with no or minimal overlapping of fractures. The hydraulic fractures are then grouped together based on available pumping capacity for each treatment stage to determine the number of stages required to treat the entire well. The detailed step-by-step method, which takes into account the effect of in-situ stress and fracture height in staging design, is described below.
1. Formation Zones
It is assumed that the zones of petrophysical properties, mechanical properties, and in-situ stresses are generated from well logs. Each zone has a single value of any property, and a zone is the smallest unit in the staging design algorithm. For example, zones based on petrophysical properties (gas payzones) and based on stresses are shown under the headings of Gas and Stress in
2. Bottomhole Treating Pressure
The bottomhole treating pressure (BHTP) can be determined or estimated from previous treatments in offset wells in the same or similar formations. If a BHTP at a particular depth (TVD) is known, the BHTP as a function of depth can be obtained by using a pressure gradient. One estimate of the pressure gradient is the averaged value of the stress gradients of all CPs. Multiple BHTPs at multiple depths can also be specified, in which case the BHTP as a function of depth is provided by a table of BHTP versus depth. In
3. Fracture Initiation Intervals
A fracture initiation interval is required in each simulation using a software program such as the program FRACHITE™ which is commercially available from Schlumberger Technology Corporation of Sugar Land, Tex. to determine fracture height. We need to determine the locations where the fractures initiate along the TVD of the entire formation. Generally, a fracture initiation interval is a CP, for example, the intervals are shown by double arrows and numbered with I1, I2, I3, I8, and I9, one for each CP in
4. Software
The software program FRACHITE™ is used to calculate a fracture height H for each fracture initiation interval based on formation mechanical properties, stresses, and BHTP. The BHTP at the depth of each initiation interval for the FRACHITE™ calculation is interpolated from the BHTP versus depth function. The results from the FRACHITE™ calculations are the fracture heights from all the initiation intervals, each height is associated with one initiation interval, as shown by H1-H9 from I1-I9 under the heading “Heights” in
5. Fractures
Because the heights determined in Step 4 may overlap, a number of CPs may be treated or stimulated by one fracture. We need to determine the minimum number of fractures that are needed to treat all the CPs, with no or minimal overlapping. This step is the procedure to determine fractures based on the heights obtained from Step 4 by the following rules:
Similarly, for the example in
In summary, the following table shows the relation between fracture, height, and payzones for all CPs for the example in
The Fracture units may need to be re-numbered sequentially from bottom up after this step is completed.
6. Stages
The next step is to determine how many fractures (Fracture units) are grouped into one treatment stage. Starting from the well bottom, determine the number of Fracture units that can be treated in one stage based on the available pump rate Q (bbl) and pump rate per unit height q (bbl/ft) required for fracturing in a particular formation. Both the available pump rate Q and the pump rate per unit height q are specified by the user. The pump rate for each Fracture unit is the product of the pump rate per unit height q times the fracture height or the payzone height. When the sum of the required pump rates from a number of Fracture units reaches the available pump rate, these Fracture units are grouped into one stage.
If using fracture height to determine pump rate, we need to consider overlapping heights. When Fracture units have overlap heights, only one of the overlap parts is used in the flow rate calculation. For the example in
The stage determination can also be based on other criteria, such as based on maximum gross height, minimum distance between the stages, and minimum net height.
When there is more than one fracture in a stage, limited entry perforating may be needed when the stress differences between the fractures are large. For each stage, if the stress difference between the Fracture units is larger than a user specified value, use the limited entry design algorithm to determine the number of perforation holes for each fracture. The limited entry design algorithm is based on the stresses of Fracture units. The stress of a Fracture unit is the stress of its initiation interval. In the example of
The method has been implemented in a hydraulic fracturing treatment design software package.
The particular embodiments disclosed above are illustrative only, as the invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details herein shown, other than as described in the claims below. It is therefore evident that the particular embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the invention. Accordingly, the protection sought herein is as set forth in the claims below.
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