Hydraulic fracturing treatment in deep and tight gas reservoirs may be very challenging. The landing depth of the horizontal section of the well can reach up to a true vertical depth 4,900 meters in sandstone formation in some locations. Therefore, the vertical stress and horizontal stresses may be approximately 40% higher than shale gas/oil reservoirs in other regions. Also, the rock is very tight with very high compressive strength in such deep sandstone locations. Directly applying hydraulic fracturing tools and procedures used for shale oil/gas reservoirs at depth less than 3000 m in vertical depth may not be effective and frequently fail to breakdown surrounding rock to create fractures for a deep and tight reservoir.
Thus, alternative methods of selecting a hydraulic fracturing process in deep and tight gas reservoirs may be desired.
According to one embodiment, a method of selecting a hydraulic fracturing process includes simulating, using one or more processors, a cased hole hydraulic fracturing process for a well within a field, wherein the simulating accounts for an interaction between hydraulic fractures and natural fracture network surrounding the well. The method further includes receiving a determination of whether the hydraulic fractures interact with the natural fracture network according to an interaction criteria, receiving a selection of the cased hole/perforation hydraulic fracturing process in response to the hydraulic fractures not interacting with the natural fracture network according to the interaction criteria, and receiving a selection of an open hole hydraulic fracturing process in response to the hydraulic fractures interacting with the natural fracture network according to the interaction criteria.
According to another embodiment, a system for selecting a well completion process includes one or more processors and one or more memory modules including non-transitory computer-readable medium storing instructions. When executed by the one or more processors, the instructions cause the one or more processors to simulate a cased hole hydraulic fracturing process for a well within a field by accounting for an interaction between hydraulic fractures and a natural fracture network surrounding the well. The instructions further cause the one or more processors to receive a determination of whether the hydraulic fractures interact with the natural fracture network according to an interaction criteria, receive a selection of the cased hole/perforation hydraulic fracturing process in response to the hydraulic fractures not interacting with the natural fracture network according to the interaction criteria, and receive a selection of an open hole hydraulic fracturing process in response to the hydraulic fractures interacting with the natural fracture network according to the interaction criteria.
It is to be understood that both the foregoing general description and the following detailed description present embodiments that are intended to provide an overview or framework for understanding the nature and character of the claims. The accompanying drawings are included to provide a further understanding of the disclosure, and are incorporated into and constitute a part of this specification. The drawings illustrate various embodiments and together with the description serve to explain the principles and operation.
Embodiments of the present disclosure are directed to systems and methods for selecting a well hydraulic fracturing method for horizontal wells. More particularly, embodiments provide a robust workflow which can effectively identify the right stimulation method for stimulating deep and tight gas reservoirs.
Hydraulic fracturing is a technology for facilitating economic recovery of natural gas/oil from tight formations. Hydraulic fracturing treatments are designed to stimulate production from tight reservoirs with low permeability. This often involves pumping large amounts of fluid and proppants according to the pumping schedule and thus creating long propped fractures, which have high permeability flow channels towards the wellbore and a large drainage area towards the low permeability tight formation. However, the hydraulic fracturing treatments only succeed when they are designed based on the specific character of target formations to optimize development of a complex network of hydraulic fractures and natural fractures. For some gas reservoir located at very deep and tight formation more than 4,900 meters in vertical depth, the conventional cased-hole/perforated hydraulic fracturing process fails frequently due to the downhole pressure quickly reaching the limiting pressure of wellhead safety requirement. In other words, the formation breakdown has been a challenging issue, which leads to foregoing of the hydraulic fracturing treatment. Additionally, some portions may be fractured successfully while other parts may fail. For this kind of subsurface geologic setting with high rock breakdown pressure requirement, methods for selecting the right stimulation method are desired.
Cased hole hydraulic fracturing process initiates major hydraulic fractures from perforations and propagate along the maximum horizontal stress direction. For this method, the pump schedule should be well designed to guarantee that the downhole pressure around the perforation clusters is higher than the required breakdown pressure. At the same time, the surface treating pressure should be below the wellhead safety requirement. Otherwise, the hydraulic fractures cannot be initiated and treatment will fail. Currently, hydraulic fracturing simulators cannot accurately predict the required breakdown pressure due to the simplification of computer model implementation, which does not account for the 3D complex configuration of perforated wellbore (include perforation cluster and perforation phase angle). Also a large element sizes have to be used for reducing the simulation time to a practical level. Valuable time and resources may be wasted when the well completion method fails.
To prevent such hydraulic fracturing failure, an open hole hydraulic fracturing process might be a better choice.
For the open hole hydraulic fracturing process, fluid injection is aimed at initiating fracture through the weakest locations of open hole formation. However, the hydraulic pressure is relatively uniform within the isolated interval, which might not able to initiate hydraulic fractures as does the cased hole hydraulic fracturing method. Due to the large open hole interface, the injected fluid still might be able to seep into the rock formation quickly enough as planned by the pump schedule. For a reservoir with many discrete natural fractures, this method can lead to discrete natural shearing slip and significantly stimulate rock volume for successful production. Thus, the open hole hydraulic fracturing process may be an efficient method for reservoirs with many discrete natural fractures.
Generally, methods of the present disclosure comprise borehole image analysis, logging data processing, calculation of mechanical properties based on log data, poroelastic parameters and implications to fluid flow in the formation, estimation of in-situ stresses and breakdown pressure, natural fracture prediction and fracture property estimation, modeling hydraulic fracturing accounting for the interaction between hydraulic fractures and discrete natural fractures. Each of these components is weighed in the decision making process for selecting the right stimulation method for the subsurface geologic setting. Thus, hydraulic fracturing designs can be refined and modified at the field or well level to optimize the fracture network and maximize oil/gas production.
Various embodiments for selecting the appropriate hydraulic fracturing process (also referred to as a well completion process) to stimulate deep and tight reservoirs for efficient oil and gas production are described in detail herein.
Referring now to
The simulation model outputs an interaction between the fractures created by the simulated cased hole hydraulic fracturing process and a predicted natural fracture network. Generally, hydraulic fractures propagate along the maximum principal stress direction. In the subsurface geologic setting with well-developed natural fractures, the interaction between hydraulic fracture and natural fracture can be very complex. Several phenomena may occur during the hydraulic fracture propagating towards the natural fracture which may include: 1) hydraulic fracture arrested by natural fracture; 2) hydraulic fracture crossing natural fracture; 3) hydraulic fracture propagating along natural fractures; and 4) hydraulic fractures branching into natural fracture after crossing. Which phenomenon will happen is dependent on the natural fracture interface property, in-situ stresses, intersection angle, fluid properties, and natural fracture orientation with respect to in-situ stresses.
When fractures caused by the hydraulic fracturing process interact with the natural fracture network, they change direction from an initial direction when leaving the well to a direction of the natural fracture. Hydraulic fractures that strongly interact with natural fractures are likely to lead to a complex fracture network, which is ultimately good for production.
At block 104, it is determined whether or not the fractures output by the simulation model interact with a predicted natural fracture network in accordance with an interaction criteria. The interaction criteria is not limited by this disclosure. In one example, the simulation model outputs a display that illustrates the simulated fractures and predicted natural fracture network (see
As another example, the decision at block 104 may be made deterministically by a computer. As a non-limiting example, the interaction criteria may be a threshold percentage of hydraulic fractures that change direction by more than a predetermined angle toward a direction of the natural fracture network. Embodiments are not limited by the threshold percentage. For example, without limitation, the threshold percentage may be 20%, 30%, 40%, 50%, 60%, 70%, or even 80%. Embodiments are also not limited by the predetermined angle. As non-limiting examples, the predetermined angle may be 20 degrees, 30 degrees, 40 degrees, 50 degrees, 60 degrees, 70 degrees, or 90 degrees.
The threshold percentage and/or the predetermined angle may be set by a user in a graphical user interface. As a non-limiting example, the user may set the predetermined angle at 40 degrees, and the threshold percentage at 50%. Thus, the interaction criteria is satisfied when 50% or more of the simulated fractures change direction at an angle of greater than or equal to 40 degrees in a direction parallel to the natural fracture network.
It should be understood that other interaction criterion may be used.
Referring again to
If the interaction criteria is not satisfied (i.e., the fractures do not interact with the natural fracture network in accordance with the interaction criteria), the process moves to block 108 where the cased hole hydraulic fracturing process is selected. In some embodiments, the user selects the cased hole hydraulic fracturing process after viewing the output of the simulation on an electronic display. In other embodiments, a computer automatically selects the cased hole/perforation hydraulic fracturing process and initiates scheduling to physically stimulate the well by the cased hole hydraulic fracturing process. In either case, the well is then stimulated by any known or yet-to-be-developed cased hole hydraulic fracturing process.
At block 201, data from various sources is collected to be provided as inputs to the various models in downstream steps. Embodiments are not limited by the type of data that is collected. For example, actual, historical data may be taken in the form of drilling report, well surveys, formation tops, (e.g., sandstone, shale, carbonate), well logs (e.g., sonic logs), sensor readings, geological data, and the like.
At block 202, the breakdown pressure for open hole and cased hole/perforation hydraulic fracturing are estimated. Rock breakdown or fracture initiation may be important for a successful hydraulic fracturing process. Accurately estimating the breakdown pressure of formation may be important, which controls the selection of the correct wellhead, casing size and their burst pressure limits and initial pump schedule design. The breakdown pressure may be measured through a leak-off test. Further, the breakdown pressure may also be calculated based on elastic theory. The breakdown pressure should be estimated as accurate as possible to select the correct casing, treatment tubing, wellhead, and the like. Otherwise, the hydraulic fracturing pump schedule may not be injected as planned.
At block 203 geomechanic properties (e.g., dynamic and static Poisson's ratio, Young's modulus, shear modulus, bulk modulus, frictional angle, cohesion, tensile strength, unconfined compressive strength, bulk, Young, and shear modulus), the poroelastic property Biot's constant, and in-situ stresses of the reservoir of vertical direction σV and maximum horizontal stress σHmax, and σHmin are determined based on the data that is collected at block 201.
At block 204, image logs are processed to determine the natural fracture classification (e.g., bedding, stylolite, conductive and partially conductive fractures, resisting and partial resistive fractures, and induced fractures), natural fracture orientations, dip angle, fracture intensity, maximum horizontal stress orientation, and the like. The image logs may be determined in block 201 and may be compiled by providing one or more cameras or other sensors into one or more wells of the field. Any known or yet-to-be-developed method of image log processing to characterize the natural fractures may be utilized.
The output from block 204 is used to predict the natural fracture network in three-dimensional space at block 207. Based on the image log processing results, fracture data along the well trajectory may be obtained, which include fracture locations, fracture types, dip angles, dip azimuths, and the like. The fracture data is provided to a fracture modeling simulator and initial data analysis is performed first. Then, fracture data is upscaled into 3D grid. The upscaling is the process of assigning values to the cells in the 3D grid that is penetrated by the wells. Upscaling allows the well information to be used as input for the property modeling of block 206 as well.
Next, the 3D grid is populated using geostatistical methods based on the updated fracture intensity logs. For fracture modeling, the fracture intensity derived from fracture counts on image logs is limited only to the near borehole region. The fracture intensity laterally away from the wellbore may be highly uncertain. A fracture driver in the entire grid can provide additional information about the lateral/spatial extent of fractures. Generally, it works as a guide for the 3D distribution of intensity. Four types of fracture drivers can be used for fracture modeling, which are geological related information (porosity, facies, etc.), seismic (acoustic impedance), geomechanical aspect (fault related), and stress-related. Then, a fracture network model can be created using either deterministic approach or stochastic approaches. The fracture network model will be inserted into the hydraulic fracturing model later in the process. It should be understood that other methods for predicting the natural fractures may be utilized, and that embodiments are not limited by the process described above.
The cased hole hydraulic fracturing breakdown pressure is estimated at block 205 based on the geomechanical properties, the poroelastic property, and in-situ stresses determined at block 203. Any method of estimating the breakdown pressure may be used. An example method of estimating the breakdown pressure is applicable to deviated, cased hole and clustered perforation hydraulic fracturing treatment. In the model, the far field in-situ stresses are projected to the perforation coordinate system through a series intermediate coordinate system transformations. And then the projected far field in-situ stresses are superposition with the other induced stresses. The model also accounts for the effect of casing-cement intermediate layers' mechanical properties as well as the perforation quality.
At block 206, a 3D property modeling is conducted. The property modeling is the process of filling cells of the 3D grid with discrete or continuous properties. For hydraulic fracturing modeling purpose, the parameters within the 3D grid will be generated, which may include the parameters mentioned above with respect to block 203. Any known or yet-to-be-developed three-dimensional modeling technique may be utilized in generating the three-dimensional property model. As a non-limiting example, the three-dimensional model may include a three-dimensional array of cells that include values for the above-referenced properties.
A limiting pressure and an initial pump schedule is determined at block 208 from the open hole breakdown pressure and the estimated cased hole breakdown pressure and wellhead limit. The pump schedule includes attributes such as fluid injection rate, type of fluid, duration of the fluid injection, proppant type and concentration in terms of pound per gallon (ppg), and the like. The limiting pressure is the maximum pressure for casing or wellhead safety, which should be below the limiting pressure of wellhead safety. The initial pump schedule can be roughly evaluated based on the Bernoulli's equation and is optimized in blocks 209-213.
At block 209, a three-dimensional geomechanics model is generated that combines the three-dimensional model derived at block 206 with the predicted natural fracture network derived at block 207. Thus, the cells (i.e., grids) of the three-dimensional model are augmented with information regarding the natural fractures to form the three-dimensional geomechanics model.
Additionally, at block 210, the natural fracture properties of the predicted natural fracture network are estimated using empirical laws built in the fracture prediction simulator. The natural fracture properties may include natural fracture porosity, permeability, and fracture aperture.
The next step is to perform a three-dimensional simulation of a cased hole hydraulic fracturing process of a well using the initial pump schedule developed at block 208 and three-dimensional geomechanics model built at block 209. The three-dimensional simulation outputs at least a surface treating pressure (fluid pressure at the surface near wellhead), downhole pressure (fluid pressure around the perforation clusters), fracture geometry, proppant coverage, and an interaction between the simulated hydraulic fractures and the natural fracture network at provided by the three-dimensional geomechanics model derived at block 209.
The hydraulic fracturing simulator can be developed using either finite element method or boundary element method. The interaction between hydraulic fractures and natural fractures network may be dependent on the several factors. Generally, hydraulic fractures propagate along the maximum principal stress direction. In the subsurface geologic setting with well-developed natural fractures, the interaction between hydraulic fractures and natural fractures can be very complex.
Several phenomena may occur during the hydraulic fracture propagating towards the natural fracture, which may include: 1) hydraulic fracture arrested by natural fracture; 2) hydraulic fracture crossing natural fracture; 3) hydraulic fracture propagating along natural fractures; and 4) hydraulic fractures branching into natural fracture after crossing. Which phenomenon will happen is dependent on the natural fracture interface properties (frictional coefficient and cohesion), in-situ stresses, intersection angle, fluid properties, and natural fracture orientation with respect to in-situ stresses. Either of the above 3-4 scenarios may be considered an interaction between hydraulic fractures and natural fractures.
After the three-dimensional simulation is performed, at block 212 it is determined whether or not the surface treating pressure exceeds the wellhead safety limit of the well that is being simulated. If so, the process moves to block 213 where the pump schedule is adjusted and then back to block 211 for an updated three-dimensional hydraulic fracturing simulation. Blocks 211, 212, and 213 are repeated until the surface treating pressure does not exceed the wellhead safety limit of the well.
When the surface treating pressure does not exceed the wellhead safety limit at block 212, the process moves to block 214 wherein it is determined whether or not the generated hydraulic fractures interact with a natural fracture network in accordance with an interaction criteria. For example, the interaction criteria may be similar to those described at block 104 of
In the example of
Referring now to
As described above, the interaction criteria may be heuristically applied by a viewer of the output. A viewer may look at the output of
The interaction criteria may be deterministic. As a non-limiting example and as stated above, the interaction criteria may be a threshold percentage of hydraulic fractures that change direction more than a predetermined angle. The predetermined angle may be any angle, and may be measured as illustrated by angle α shown in
Referring once again to
After the pump schedule is optimized, the cased hole hydraulic fracturing process (i.e., a cased hole well completion method) is selected at block 220. The optimized cased hole hydraulic fracturing process may then be applied to physically hydraulically fracture the reservoir.
When there is strong interaction between the hydraulic fractures and the natural fracture network (i.e., an interaction criteria is satisfied) at block 214, an open hole hydraulic fracturing process may be more efficient and thus the process moves to the open hole simulation process 215. Thus, if strong interactions between hydraulic fractures and natural fractures can be observed, the possibility of stimulating the well through fluid injection over an open hole for each fracking stage is evaluated.
The open hole simulation process 215 receives as input the three-dimensional geomechanics model built at block 209 and the estimated natural fracture properties determined at block 210. At block 216, a fluid-rock coupling reservoir simulation is conducted using the same pump schedule over each isolated zone of the open hole well. The advantage of using fluid-rock coupling is capable of capturing the interaction between fluid flow and solid deformation within a porous rock, which is an extension of elasticity and porous medium flow (diffusion equation). The fluid-rock coupling simulation allows deformation, effective stress changes and pore pressure change to be obtained simultaneously, which are used to evaluate the natural fractures shearing slip or not. This can be achieved through finite element modeling of poroelasticity. The reservoir is defined by poroelastic material.
At block 217, evaluations of stresses and pore pressure changes, Coulomb stress change, and the impact of Coulomb stress change on the natural fracture network shearing slip are conducted. For fluid injection of hydraulic fracturing, the impact on natural fracture shearing slip can be activated during two phases. In phase 1, the hydraulic fracture openings driven by fluid injection immediately generate additional stresses at the natural fracture network. After phase 1, the pore pressure increases due to undrained response at the natural fracture network gradually develops. The fluid pressure change permeating in the formation is governed by the diffusion equation, which is dependent on the following rock properties: hydraulic diffusivity, formation permeability, fluid viscosity and storage coefficient—a function of the compressibility of both the fluid and porous rock, and distance between injection point and individual natural fracture. For either of these two phases, natural fracture shearing slip is likely to happen if the induced shear stress is high enough to exceed the breaking strength. For a production zone full of natural fractures, it is desirable to stimulate those natural fractures as much as possible. To achieve this, fluid injection over the open hole stage after stage might be a better way. The impact of this stimulation method on stimulated rock volume can be estimated through Coulomb strength theory and Coulomb stress change.
Natural fractures need stresses and pore pressure changes to trigger shearing slip, which can be activated if the shear stresses acting on the fracture surfaces overcome the resistance to slip of the adjacent rock blocks. Pore pressure change due to fluid injection can be the main reason. The shear resistance is due to friction, which is proportional to the difference between the normal stress acting on the fault, and fluid pressure in the fault. The fault is in stable state as long as the magnitude of shear stress is lower than the shear resistance or frictional strength. The critical condition is called by the Coulomb strength criterion, which reflects two fundamental factors: friction and effective stress by:
τ=μ(σn−p).
The presence of effective stress in the Coulomb criterion shows that the fluid pressure counterbalances the effect of the normal compression stress σn. The Coulomb criterion indicates that fault slip can be triggered by either decrease of the normal stress or an increase of the pore pressure, and or an increase of the shear stress. Coulomb stress change (ΔCSC) can also be used to evaluate a natural fracture becoming stable or unstable due to change of pore pressure and stress, which is given by:
ΔCSC=ΔT−μ(Δσn−Δp),
where Δτ is the shear stress change on a fracture in the fracture direction (positive in the direction of fracture slip), Δσn represents the compressive stress change that clamps or unclamps the fracture (positive if the fracture is in compression), Δp is the pore pressure change in the fracture that unclamps the fracture, and μ is the frictional coefficient of fracture surface. Based on the definition of ΔCSC, a positive change of ΔCSC promotes shearing slip and a negative change inhibits fracture shearing slip. Therefore the focal point of evaluating natural fracture shearing slip is on predicting stress and pore pressure change.
The main objective of injecting fluid through an isolated open hole is targeted at maximizing the SRV through shearing the natural fractures, and thereafter increase the permeability of the production zone. However, including all the natural fractures in the modeling is very challenging and computationally very expensive. As mentioned above the shearing slip possibility of complex natural fracture networks may be evaluated through calculating the Coulomb stress change, which uses the normal stress and pore pressure changes with respect to the natural fractures orientations induced by fluid injection of pump schedule. After finite element modeling of poroelasticity and projecting the stresses onto the fracture direction, the Coulomb stress change is calculated using the above equation and the natural fracture shearing slip is evaluated. Based on the affected areas of fracture shearing slip, the SRV can be approximately calculated. Thus, it is checked at block 217 whether natural fractures can be activated.
The main objective of this stimulation method is to drive numerous natural fractures to shear slip and therefore increase the formation permeability for good production.
Finally, at block 220 the right well hydraulic fracturing process is selected. This selection workflow is aimed at selecting the right well completion method, which can alleviate the breakdown issue for deep and tight oil/gas reservoirs and make the well stimulation more likely to be completed so that a better production can be achieved. A comparison between the two methods can be achieved through reservoir production simulations.
Embodiments of the present disclosure may be implemented by a computing device, and may be embodied as computer-readable instructions stored on a non-transitory memory device.
As also illustrated in
The processor 630 may include any processing component configured to receive and execute computer readable code instructions (such as from the data storage component 636 and/or memory component 640). The input/output hardware 632 may include a graphics display device, keyboard, mouse, printer, camera, microphone, speaker, touch-screen, and/or other device for receiving, sending, and/or presenting data. The network interface hardware 634 may include any wired or wireless networking hardware, such as a modem, LAN port, wireless fidelity (Wi-Fi) card, WiMax card, mobile communications hardware, and/or other hardware for communicating with other networks and/or devices, such as to receive the data 638A from various sources, for example.
It should be understood that the data storage component 636 may reside local to and/or remote from the computing device 600, and may be configured to store one or more pieces of data for access by the computing device 600 and/or other components. As illustrated in
Included in the memory component 640 may be the operating logic 642, the modeling logic 643, and the simulation logic 644. The operating logic 642 may include an operating system and/or other software for managing components of the computing device 600. The operating logic 642 may also include computer readable program code for displaying the graphical user interface used by the user to input parameters and review results of the simulations. Similarly, the modeling logic 643 may reside in the memory component 640 and may be configured to facilitate generation models of reservoirs of interest. The simulation logic 644 may be configured to run the simulations described herein to generate the displays of the interactions between hydraulic fractures and natural fracture networks.
The components illustrated in
It should now be understood that embodiments of the present disclosure are directed to systems and methods for selecting a hydraulic fracturing process for reservoirs, such as, without limitation, deep and tight gas reservoirs. More particularly, embodiments are directed to workflows for selecting the efficient and reliable well stimulation method for gas reservoirs in deep and tight formations. The workflows include, but are not limited to, borehole image analysis, logging data processing, calculation of mechanical properties based on log data, estimation of in-situ stresses and breakdown pressure, natural fracture prediction and fracture property estimation, modeling hydraulic fracturing accounting for the interaction between hydraulic fractures and discrete natural fractures. Further, the workflows include finite element modeling of fluid injection over open hole of each fracking stage, Coulomb stress change and impact on natural fracture shearing slip, and estimation of stimulated rock volume, which represents a new way to evaluate the fluid injection over the isolated open hole stimulation method. Embodiments may be weighed in selecting either cased hole hydraulic fracturing or open hole perforation hydraulic fracturing process
Having described the subject matter of the present disclosure in detail and by reference to specific embodiments thereof, it is noted that the various details disclosed herein should not be taken to imply that these details relate to elements that are essential components of the various embodiments described herein, even in cases where a particular element is illustrated in each of the drawings that accompany the present description. Further, it will be apparent that modifications and variations are possible without departing from the scope of the present disclosure, including, but not limited to, embodiments defined in the appended claims. More specifically, although some aspects of the present disclosure are identified herein as preferred or particularly advantageous, it is contemplated that the present disclosure is not necessarily limited to these aspects.