Source: http://www.freepatentsonline.com/y2014/0222405.html
Timestamp: 2020-02-28 19:31:11
Document Index: 501728366

Matched Legal Cases: ['Application No. 60', 'Application No. 61', 'Application No. 61', 'Application No. 2009', 'Application No. 2011', 'Application No, 2008', 'Application No 2010']

SYSTEM AND METHOD FOR PERFORMING DOWNHOLE STIMULATION OPERATIONS - Schlumberger Technology Corporation
United States Patent Application 20140222405
A system and method for performing stimulation operations at a wellsite having a subterranean formation with of a reservoir therein is provided. The method involves generating a plurality of quality indicators from a plurality of logs, and combining the plurality of quality indicators to form a composite quality indicator. The plurality of stress blocks may then be merged using diversion criterion. The composite quality indicator may be combined with the merged stress blocks to form a combined stress and composite quality indicator, the combined stress and composite quality indicator comprising a plurality of blocks with boundaries therebetween. The method may further comprise defining stages along the combined stress and composite quality indicator based on the diverter-assisted stage classifications; and selectively positioning perforations in select stages based on the diverter-assisted stage classifications thereon.
Lecerf, Bruno (Houston, TX, US)
Usoltsev, Dmitriy (San Antonio, TX, US)
Pope, Timothy L. (Cheyenne, WY, US)
Pena, Alejandro (Katy, TX, US)
Itibrout, Tarik (Richmond, TX, US)
Enkababian, Philippe (Richmond, TX, US)
14/101028
Download PDF 20140222405 PDF help
20040019471 Loading method and program January, 2004 Bush et al.
20090228246 Methods and systems of engineering analysis using a hybrid approach with FEM and adaptive SPH September, 2009 Lacome
20100076737 INFERRING SYSTEM-LEVEL PROPERTIES March, 2010 Boddy et al.
1. A method for staging a stimulation operation for a wellsite having a reservoir positioned in a subterranean formation, comprising: generating a plurality of quality indicators from a plurality of logs; combining the plurality of quality indicators to form a composite quality indicator; merging a plurality of stress blocks using diversion criterion; combining the composite quality indicator with the merged stress blocks to form a combined stress block and composite quality indicator, the combined stress block and composite quality indicator comprising a plurality of blocks with boundaries therebetween; defining stages along the combined stress and composite quality indicator based on diverter-assisted stage classifications; and selectively positioning perforations in select stages based on the diverter-assisted stage classifications thereon.
5. The method of claim 1, wherein the diverter-assisted stage classifications comprise one of good, had and combinations thereof.
6. The method of claim 1, further comprising selectively adjusting the stage boundaries.
7. The method of claim 6, wherein the selectively adjusting comprises selectively eliminating the plurality of blocks that are less than a minimum diverter-assisted stage length.
8. The method of claim 6, wherein the selectively adjusting comprises splitting the plurality of blocks having a length greater than a minimum diverter assisted stage length.
9. The method of claim 6, wherein the selectively adjusting comprises selectively shifting boundaries based on the diverter assisted classifications.
10. The method of claim 1, wherein the merging further comprises: creating a plurality of stress blocks; computing fracture initiation pressure using one or more of well properties, near-wellbore properties and the plurality of stress logs; and merging fracture initiation blocks using the diversion criterion
11. The method of claim 10, wherein the merged stress blocks are the merged fracture initiation blocks.
12. The method of claim 1, wherein the selectively positioning the perforations further comprises selecting positioning the perforations to impart a direction to the fracturing sequence.
13. The method of claim 1, wherein the selectively positioning the perforations further comprises selectively positioning the perforations to fracture stress shadowed regions of the formation.
14. A method for staging a stimulation operation for a wellsite having a reservoir positioned in a subterranean formation, comprising: obtaining a log of at least a portion of a wellbore of the wellsite; defining boundaries at intervals along the log based on stimulation data; identifying pay zones along, the wellbore based on the boundaries; specifying fracture units along the identified pay zones; defining stages along the specified fracture units; designing perforation locations based on the defined stages; and designing a diversion treatment.
15. The method of claim 14, wherein the obtaining comprises measuring at least one parameter along the portions of the wellbore.
16. The method of claim 14, wherein the reservoir is a tight gas sand reservoir.
17. The method of claim 14, wherein the lost is one of a resistivity log, a permeability log, a porosity log and combinations thereof.
18. The method of claim 14, wherein the log comprises a composite log formed from a plurality of logs.
This application is a continuation-in-part of, and claims the benefit of priority to, U.S. Patent Application Pub. No. 2012/0185225, filed on Dec. 28, 2011, and entitled SYSTEM AND METHOD FOR PERFORMING DOWNHOLE STIMULATION OPERATIONS, which claims priority to U.S. Pat. No. 8,412,500, issued on Apr. 2, 2013, and entitled SIMULATIONS FOR HYDRAULIC FRACTURING TREATMENTS AND METHODS OF FRACTURING NATURALLY FRACTURED FORMATION, which claims priority to U.S. Provisional Application No. 60/887,008, filed on Jan. 29, 2007, and entitled METHOD FOR HYDRAULIC FRACTURING TREATMENT IN NATURALLY FRACTURED FORMATION: this application also claims benefit of priority to U.S. Provisional Application No. 61/464,134, filed on Feb. 28, 2011, and U.S. Provisional Application No. 61/460,372, filed on Dec. 30, 2010, entitled INTEGRATED RESERVOIR CENTRIC COMPLETION AND STIMULATION DESIGN METHODS; the entire contents of each are hereby incorporated by reference herein in their entirety.
Oilfield operations may be performed to locate and gather valuable downhole fluids, such as hydrocarbons. Oilfield operations may include, for example., surveying, drilling, downhole evaluation, completion, production, stimulation, and oilfield analysis. Surveying may involve seismic surveying using, for example, a seismic truck to send and receive downhole signals. Drilling may involve advancing, a downhole tool into the earth to form a wellbore. Downhole evaluation may involve deploying a downhole tool into the wellbore to take downhole measurements and/or to retrieve downhole samples. Completion may involve cementing and casing a wellbore in preparation for production. Production may involve deploying production casing into the wellbore for transporting fluids from a reservoir to the surface. Stimulation may involve, for example, perforating, fracturing, injecting, and/or other stimulation operations, to facilitate production of fluids from the reservoir.
Oilfield analysis may involve, for example, evaluating information about the wellsite and the various operations, and/or performing well planning operations. Such information may be, for example, petrophysical information gathered and/or analyzed by a petrophysicist; geological information gathered and/or analyzed by a geologist; or geophysical information gathered and/or analyzed by a geophysicist. The petrophysical, geological and geophysical information may be analyzed separately with dataflow therebetween being, disconnected. A human operator may manually move and analyze the data using multiple software and tools. Well planning may be used to design oilfield operations based on information gathered about the wellsite.
FIG. 5.1 is a schematic diagram and FIG. 5.2 is a flow chart illustrating a method of staging a stimulation operation in a tight gas sandstone formation.
FIG. 8 is a schematic diagram depicting a composite quality indicator termed from a completion and a reservoir quality indicator.
FIG. 15.1 is a schematic diagram and FIG. 15.2 is a flow chart illustrating a method of staging a stimulation operation in a tight gas sandstone formation with a diverter.
FIGS. 16-19 are diagrams illustrating a method of staging a stimulation operation for a shale reservoir in a vertical well.
FIG. 20 is a diagram showing a continuum of stresses along the lateral (reported as fracture initiation pressure Pim) used for the determination of preferred locations of mechanical isolation devices based on the initiation pressure differential that can be overcome with the diverter.
FIG. 21 is a wellbore and its corresponding stress log, where perforations are located at local minima and local maxima of the stress log.
FIG. 22 is a stimulated wellbore and its corresponding stress log, where induced fractures have propagated in the zones of lower stress and where changes in stress of the rock have generated stress relief fractures.
FIG. 23 is a stimulated wellbore and its corresponding stress log, where induced fractures have been diverted from and perforations in high stress regions have been stimulated to thrill complex fractures.
The present disclosure relates to design, implementation and feedback of stimulation operations performed at is wellsite. The stimulation operations may be performed using a reservoir centric, integrated approach. These stimulation operations may involve integrated stimulation design based on multi-disciplinary information (e.g., used by a petrophysicist, geologist, geomechanicist, geophysicist and reservoir engineer), multi-well applications, and/or multi-stage oilfield operations (e.g., completion, stimulation, and production). Some applications may be tailored to unconventional wellsite applications (e.g., tight gas, shale, carbonate, coal, etc.), complex wellsite applications multi-well), and various fracture models (e.g., conventional planar bi-wing fracture models for sandstone reservoirs or complex network fracture models for naturally fractured low permeability reservoirs), and the like. As used herein unconventional reservoirs relate to reservoirs, such as tight gas, sand, shale, carbonate, coal, and the like, where the formation is not uniform or is intersected by natural fractures (all other reservoirs are considered conventional).
The stimulation operations may also be performed using optimization, tailoring for specific types of reservoirs (e.g., tight gas, shale, carbonate, coal, etc.), integrating, evaluations criteria (e.g., reservoir and completion criteria), and integrating data from multiple sources. The stimulation operations may be performed manually using conventional techniques to separately analyze dataflow with separate analysis being disconnected and/or involving a human operator to manually move data and integrate data using multiple software and toots. These stimulation operations may also be integrated, for example, streamlined by maximizing multi-disciplinary data in an automated or semi-automated manner.
FIGS. 1.1-1.4 depict various oilfield operations that may be performed at a wellsite, and FIGS. 2.1-2.4 depict various information that may be collected at the wellsite. FIGS. 1.1-1.4 depict simplified, schematic views of a representative oilfield or wellsite 100 having subsurface formation 102 containing, for example, reservoir 104 therein and depicting various oilfield operations being performed on the website 100. FIG. 1.1 depicts a survey operation being performed by a survey tool, such as seismic truck 106.1, to measure properties of the subsurface formation. The survey operation may be a seismic survey operation for producing sound vibrations. In FIG. 1.1, one such sound vibration 112 generated by a source 110 reflects off a plurality of horizons 114 in an earth formation 116. The sound vibration(s) 112 may be received in by sensors, such as geophone-receivers 118, situated on the earth's surface, and the geophones 118 produce electrical output signals, referred to as data received 120 in FIG. 1.1.
In response to the received sound vibration(s) 112 representative of different parameters (such as amplitude and/or frequency) of the sound vibration(s) 112, the geophones 118 ma produce electrical output signals containing data concerning the subsurface formation. The data received 120 may be provided as input data to is computer 122.1 of the seismic truck 106.1, and responsive to the input data, the computer 122.1 may generate a seismic and microseismic data output 124. The seismic data output 124 may be stored, transmitted or further processed as desired, for example by data reduction.
FIG. 1.2 depicts a drilling operation being performed by a drilling tool 106.2 suspended by a rig 128 and advanced into the subsurface formations 102 to form a wellbore 136 or other channel. A mud pit 130 may be used to draw drilling mud into the drilling tools via flow line 132 for circulating drilling mud through the drilling tools, up the wellbore 136 and back to the surface. The drilling mud may be filtered and returned to the mud pit. A circulating system may be used for storing, controlling or filtering the flowing drilling muds. In this illustration, the drilling tools are advanced into the subsurface formations to reach reservoir 104. Each well may target one or more reservoirs. The drilling tools may be adapted for measuring downhole properties using, logging while drilling tools. The logging while drilling tool may also be adapted for taking a core sample 133 as shown, or removed so that a core sample may be taken using another tool.
Sensors (S), such as gauges, may be positioned about the oilfield to collect data relating to various operations as described previously. As shown, the sensor (S) may be positioned in one or more locations in the drilling tools and/or at the rig to measure drilling parameters, such as weight on bit, torque on bit, pressures temperatures, flow rates, compositions, rotary speed and/or other parameters of the operation. Sensors (S) may also be positioned in one or more locations in the circulating system.
The surface unit may be provided with a transceiver 137 to allow communications between the surface unit and various portions of the current oilfield or other locations. The surface unit 134 may also be provided with or functionally connected to one or more controllers for actuating mechanisms at the wellsite 100. The surface unit 134 may they send command signals to the oilfield in response to data received. The surface unit 134 may receive commands via the transceiver or may itself execute commands to the controller. A processor may be provided to analyze the data (locally or remotely), make the decisions and/or actuate the controller. In this manner, operations may be selectively adjusted based on the data collected. Portions of the operation, such as controlling drilling, weight on bit, pump rates or other parameters, may be optimized based on the information. These adjustments may be made automatically based on computer protocol, and/or manually by an operator. In some cases, well plans may be adjusted to select optimum operating conditions, or to avoid problems.
FIG. 1.3 depicts a wireline operation being performed by a wireline tool 106.3 suspended by the rig 128 and into the wellbore 136 of FIG. 1.2. The wireline tool 106.3 may be adapted kw deployment into a wellbore 136 for generating well logs, performing downhole tests and/or collecting samples. The wireline tool 106.3 may be used to provide another method and apparatus for performing a seismic survey operation. The wireline tool 106.3 of FIG. 1.3 may, for example, have an explosive, radioactive, electrical, or acoustic, energy source 144 that sends and/or receives electrical signals to the surrounding subsurface formations 102 and fluids therein.
While only simplified wellsite configurations are shown, it will be appreciated that the oilfield or wellsite 100 may cover a portion of land, sea and/or water locations that hosts one or more wellsites. Production may also include injection wells (not shown) for added recovery or for storage of hydrocarbons, carbon dioxide, or water, for example. One or more gathering facilities may be operatively connected to one or more of the wellsites, for selectively collecting downhole fluids from the wellsite(s).
FIGS. 2.1-2.4 are graphical depictions of examples of data collected by the tools of FIGS. 1.1-1.4, respectively. FIG. 2.1 depicts a seismic trace 202 of the subsurface formation of FIG, 1.1 taken by seismic truck 106.1. The seismic trace may be used to provide data, such as a two-way response over a period of time. FIG. 2.2 depicts a core sample 133 taken by the drilling tools 106.2. The core sample may be used to provide data, such as a graph of the density, porosity, permeability or other physical property of the core sample over the length of the core. Tests for density and viscosity may be performed on the fluids in the core at varying, pressures and temperatures. FIG. 2.3 depicts a well log 204 of the subsurface formation of FIG. 1.3 taken by the wireline tool 106.3. The wireline log may provide a resistivity or other measurement of the formation at various depts. FIG. 2.4 depicts a production decline curve or graph 206 of fluid flowing through the subsurface formation of FIG. 1.4 measured at the surface facilities 142. The production decline curve may provide the production rate Q as a function of time t.
FIG. 3.1 depicts stimulation operations performed at wellsites 300.1 and 300.2. The wellsite 300.1 includes as rig 308.1 having a vertical wellbore 336.1 extending into a formation 302.1. Wellsite 300.2 includes rig 308.2 having wellbore 336.2 and rig 308.3 having wellbore 336.3 extending therebelow into a subterranean formation 302.2. While the wellsites 300.1 and 300.2 are shown having specific configurations of rigs with wellbores, it will be appreciated that one or more rigs with one or more wellbores may be positioned at one or more wellsites,
Wellbore 336.1 extends from rig 308.1, through unconventional reservoirs 304.1-304.3. Wellbores 336.2 and 336.3 extend from rigs 308.2 and 308.3, respectfully to unconventional reservoir 304.4 As shown, unconventional reservoirs 304,1-304.3 are tight gas sand reservoirs and unconventional reservoir 304.4 is a shale reservoir. One or more unconventional reservoirs such as tight gas, shale, carbonate, coal, heavy oil, etc.) and/or conventional reservoirs may be present in a given formation.
Reservoir 304.4 of formation 302.2 has been perforated and packers 307 have been positioned to isolate the wellbore 336,2 about the perforations 338.3-338.5. As shown in the horizontal wellbore 336.2, packers 307 have been positioned at stages St1 and St2 of the wellbore. As also depicted, wellbore 304.3 may be an offset (or pilot) well extended through the formation 302.2 to reach reservoir 304.4. One or more wellbores may be placed, at one or more wellsites. Multiple wellbores may be placed as desired.
Fractures may be extended into the various reservoirs 304.1-304.4 for facilitating production of fluids therefrom. Examples of fractures that may be formed are schematically shown in FIGS. 3.2 and 3.4 about a wellbore 304. As shown in FIG. 3.2, natural fractures 340 extend in layers about the wellbore 304. Perforations (or perforation clusters) 342 may be formed about the wellbore 304, and fluids 344 and/or fluids mixed with proppant 346 may be injected through the perforations 342. As shown in FIG. 3.3, hydraulic fracturing may be performed by injecting through the perforations 342, creating fractures along a maximum stress plane σlmax and opening and extending the natural fractures.
A stimulation tool 350 may be provided as part of the surface unit 334 or other portions of the wellsite for performing stimulation operations. For example, information generated during one or more of the stimulation operations may be used in well planning for one or more wells, one or more wellsites and/or one or more reservoirs. The stimulation tool 350 may be operatively linked to one of more rigs and/or wellsites, and used to receive data, process data, send control signals, etc., as will be described, further herein. The stimulation tool 350 may include a reservoir characterization unit 363 for generating a mechanical earth model (MEM), a stimulation planning unit 365 for generating stimulation plans, an optimizer 367 for optimizing the stimulation plans, a real time unit 369 for optimizing in real time the optimized stimulation plan, a control unit 368 for selectively adjusting the stimulation operation based on the real time optimized stimulation plan, an updater 370 for updating the reservoir characterization model based on the real time optimized stimulation plan and post evaluation data, and a calibrator 372 for calibrating the optimized stimulation plan as will be described further herein. The stimulation planning unit 365 may include a staging design tool 381 for performing staging design, a stimulation design tool 383 for performing stimulation design, a production prediction tool 385 for prediction production and a well planning tool 387 for generating, well plans.
FIG. 4.1 is a schematic flow diagram 400 depicting a stimulation operation, such as those shown in FIG. 3.1. The flow diagram 400 is an iterative process that uses integrated information and analysis to design, implement and update a stimulation operation. The method involves pretreatment evaluation 445, a stimulation planning 447, real time treatment optimization 451, and design/model update 453. Part or all of the flow diagram 400 may be iterated to adjust stimulation operations and/or design additional stimulation operations in existing or additional wells.
The pre-stimulation evaluation 445 involves reservoir characterization 460 and generating a three-dimensional mechanical earth model (MEM) 462. The reservoir characterization 460 may be generated b integrating information, such as the information gathered in FIGS. 1.1-1.4, to perform modeling using united combinations of information from historically independent technical regimes or disciplines (e.g., petrophysicist, geologist, geomechanic and geophysicist, and previous fracture treatment results). Such reservoir characterization 460 may be generated using integrated static modeling techniques to generate the MEM 462 as described, for example, in US Patent Application Nos. 2009/0187391 and 2011/0660572. By way of example, software, such as PETREL™, VISAGE™, TECHLOG™, and GEOFRAME™ commercially available from SCHLUMBERGER™, may be used to perform the pre-treatment evaluation 445.
Conventional geomechanical modeling may be used to generate the MEM 462. Examples of MEM techniques are provided in US Patent Application No. 2009/0187391. The MEM 462 may be generated by information gathered using, for example, the oilfield operations of FIGS. 1.1-1.4, 2.1-2.4 and 3. For example, the 3D MEM may take into account various reservoir data collected beforehand, including the seismic data collected during early exploration of the formation and logging data collected from the drilling of one or more exploration wells before production (see, e.g., FIGS. 1.1-1.4). The MEM 462 may be used to provide, for example, geomechanical information for various oilfield operations, such as casing point selection, optimizing thy number of casing strings, drilling stable wellbores, designing completions, performing fracture stimulation, etc.
The generated MEM 462 may be used as an input in performing stimulation planning 447. The 3D MEM may be constructed to identify potential drilling wellsites. In one embodiment, when the formation is substantially uniform and is substantially free of major natural fractures and/or high-stress barriers, it can be assumed that a given volume of fracturing fluid pumped at a given rate over a given period of time will generate a substantially identical fracture network in the formation. Core samples, such as those shown in FIGS. 1.2 and 2.2 may provide information useful in analyzing fracture properties of the formation. For regions of the reservoir manifesting similar properties, multiple wells tar branches) can be placed at a substantially equal distance from one another and the entire formation will be sufficiently stimulated.
The stimulation planning 447 may involve well planning 465, staging design 466, stimulation design, 468 and production prediction 470. In particular, the MEM 462 may be an input to the well planning 465 and/or the staging design 466 and stimulation design 468. Some embodiments may include semi automated methods to identify, for example, well spacing and orientation, multistage perforation design and hydraulic fracture design. To address a wide variation of characteristics in hydrocarbon reservoirs, some embodiments may involve dedicated methods per target reservoir environments, such as, but not limited to, tight gas formations, sandstone reservoirs, naturally fractured shale reservoirs, or other unconventional reservoirs.
The stimulation planning 447 may involve a semi-automated method used to identify potential drilling wellsites by partitioning underground formations into multiple set of discrete intervals, characterizing each interval based on information such as the formation's geophysical properties and its proximity to natural fractures, then regrouping multiple intervals into one or multiple drilling wellsites, with each wellsite receiving a well or a branch of a well. The spacing and orientation of the multiple wells may be determined and used in optimizing production of the reservoir. Characteristics of each well may be analyzed for stage planning and stimulation planning, in some cases, a completion advisor may be provided, for example, for analyzing vertical or near vertical wells in tight-gas sandstone reservoir following a recursive refinement workflow.
Well planning 465 may be performed to design oilfield operations in advance of performing such oilfield operations at the wellsite. The well planning 465 may be used to define, for example, equipment and operating parameters for performing the oilfield operations. Some such operating parameters may include, for example, perforating locations, operating pressures, stimulation fluids, and other parameters used in stimulation. Information gathered from various sources, such as historical data, known data, and oilfield measurements (e.g., those taken in FIGS. 1.1-1.4), may be used in designing a web plan. In some cases, modeling may be used to analyze data used in forming a well plan. The web plan generated in the stimulation planning may receive inputs from the staging design 466, stimulation design 468, and production prediction 470 so that information relating to and/or affecting stimulation is evaluated in the well plan.
The well planning 405 and/or MEM 402 may also be used as inputs into the staging design 466. Reservoir and other data may be used in the staging design 466 to define certain operational parameters for stimulation. For example, staging design 466 may involve defining boundaries in a wellbore for performing stimulation operations as described further herein. Examples of staging design are described in US Patent Application No. 2011/0247824. Staging design may be an input for performing stimulation design 468.
Stimulation design defines various stimulation parameters (e.g., perforation placement) for performing stimulation operations. The stimulation design 468 may be used, for example, for fracture modeling. Examples of fracture modeling are described in US Patent Application No, 2008/0183451, 2006/0015310 and PCT Publication No. WO2011/077227. Stimulation design may involve using various models to define a stimulation plan and/or a stimulation portion of is well plan.
Stimulation design may integrate 3D reservoir models (formation models), which can be a result of seismic interpretation, drilling geo-steering interpretation, geological or geomechanical earth model, as a starting point (zone model) for completion design. For some stimulation designs, a fracture modeling algorithm may be used to read a 3D MEM and run forward modeling to predict fracture growth. This process may be used so that spatial heterogeneity of a complex reservoir may be taken into account in stimulation operations. Additionally, some methods may incorporate spatial X-Y-Z sets of data to derive an indicator, and then use the indicator to place and/or perform a wellbore operation, and in sonic instance, multiple stages of wellbore operations as will be described further herein.
Stimulation design may use 3D reservoir models for providing information about natural fractures in the model. The natural fracture information may be used, for example, to address certain situations, such as cases where a hydraulically induced fracture grows and encounters a natural fracture (see. FIGS. 3.2-3.4), in such cases, the fracture can continue growing into the same direction and divert along the natural fracture plane or stop, depending on the incident angle and other reservoir geomechanical properties. This data may provide insights into, for example, the reservoir dimensions and structures, pay zone location and boundaries, maximum and minimum stress levels at various locations of the formation, and the existence and distribution of natural fractures in the formation. As a result of this simulation, nonplanar (i.e. networked) fractures or discrete network fractures may be formed. Some workflows may integrate these predicted fracture models in a single 3D canvas where microseismic events are overlaid (see, e.g., FIG. 3.4). This information may be used in fracture design and/or calibrations.
Microseismic mapping may also be used in stimulation design to understand complex fracture growth. The occurrence of complex fracture growth may be present in unconventional reservoirs, such as shale reservoirs. The nature and degree of fracture complexity may be analyzed to select an optimal stimulation design and completion strategy. Fracture modeling may be used to predict the fracture geometry that can be calibrated and the design optimized based an real time. Microseismic mapping and evaluation. Fracture growth may be interpreted based on existing hydraulic fracture models. Some complex hydraulic fracture propagation modeling and/or interpretation may also be performed for unconventional reservoirs (e.g., tight gas sand and shale) as will be described further herein. Reservoir properties, and initial modeling assumptions may be corrected and fracture design optimized based on microseismic evaluation.
Examples of complex fracture modeling are provided in SPE paper 140185, the entire contents of which is hereby incorporated by reference. This complex fracture modeling illustrates the application of two complex fracture modeling techniques in conjunction with microseismic mapping to characterize fracture complexity and evaluate completion performance. The first complex fracture modeling technique is an analytical model for estimating fracture complexity and distances between orthogonal fractures. The second technique uses a gridded numerical model that allows complex geologic descriptions and evaluation of complex fracture propagation. These examples illustrate how embodiments may be utilized to evaluate bow fracture complexity is impacted by changes in fracture treatment design in each geologic environment. To quantify the impact of changes in fracture design using complex fracture models despite inherent uncertainties in the MEM and “real” fracture growth, microseismic mapping and complex fracture modeling may be integrated for interpretation of the microseismic measurements while also calibrating the complex stimulation model. Such examples show that the degree of fracture complexity can vary depending on geologic conditions.
Referring back to FIG. 4.1, various optional features may be included in the stimulation planning 447. For example, a multi-well planning advisor may be used to determine if it is necessary to construct multiple wells in a formation. If multiple wells are to be formed, the multi-well planning advisor may provide the spacing and orientation of the multiple wells, as well as the best locations within each for perforating and treating the formation. As used herein, the term “multiple wells” may refer to multiple wells each being independently drilled front the surface of the earth to the subterranean formation; the term “multiple wells” may also refer to multiple branches kicked off front to single well that is drilled from the surface of the earth (see, e.g., FIG. 3.1). The orientation of the wells and branches can be vertical, horizontal, or anywhere in between.
Embodiments may also include real tune treatment optimization (or post job workflows) 451 for analyzing the stimulation operation and updating the stimulation plan during actual stimulation operations. The real time treatment optimization 451 may be performed during implementation of the stimulation plan at the wellsite (e.g., performing fracturing, injecting or otherwise stimulating the reservoir at the wellsite). The real time treatment optimization may involve calibration tests 449, executing 448 the stimulation plan generated in stimulation planning 447, and real time oilfield stimulation 455.
Real time interpretation 463 may be performed on or off site based on the data collected. Real time stimulation design 465 and production prediction 467 may be performed similar to the stimulation design 468 and production prediction 470, but based on additional information generated during the actual oilfield stimulation 455 performed at the wellsite. Optimization 471 may be provided to iterate over the real time stimulation design 465 and production prediction 467 as the oilfield stimulation progresses. Real time stimulation 455 may involve, for example, real time fracturing. Examples of real time fracturing are described in US Patent Application No 2010/0307755, the entire contents of which are hereby incorporated by reference.
Real time control 469 may be provided to adjust the stimulation operation at the wellsite as information is gathered and an understanding of the operating conditions is gained. The real time control 469 provides a feedback loop for executing 448 the oilfield stimulation 455. Real time control 469 may be executed, for example, using the surface unit 334 and/or downhole tools 306.1-306.4 to alter operating conditions, such as perforation locations, injection pressures, etc. While the features of the oilfield stimulation 455 are described as operating in real time, one or more of the features of the real time treatment optimization 45 1 may be performed in real time or as desired.
The information generated during the real time treatment optimization 451 may be used to update the process and feedback to the reservoir characterization 445. The design model update 453 includes post treatment evaluation 475 and update model 477. The post treatment evaluation involves analyzing the results of the real time treatment optimization 451 and adjusting, as necessary, inputs and plans for use in other wellsites or wellbore applications.
The post treatment evaluation 475 may be used as an input to update the model 477. Optionally, data collected from subsequent drilling and/or production can be fed back to the reservoir characterization 445 (e.g., the 3D earth model and/or stimulation planning 447 (e.g., well planning, module 465). Information may be updated to remove errors in the initial modeling and simulation, to correct deficiencies in the initial modeling, and/or to substantiate the simulation. For example, spacing or orientation of the wells may be adjusted to account the newly developed data. Once the model is updated 477, the process may be repeated as desired. One or more wellsites, wellbores, stimulation operations or variations may be performed using the method 400.
An example stimulation design and downstream workflow useful for unconventional reservoirs involving tight gas sandstone (see, e.g., reservoirs 304.1-304.3 of FIG. 3.1) are provided. For tight gas sandstone reservoir workflow, is conventional stimulation (i.e. hydraulic fracturing) design method may be used, such as a single or multi-layer planar fracture model.
FIGS. 5.1 and 5.2 depict examples of staging involving a tight gas sand reservoir. A multi-stage completion advisor may be provided for reservoir planning for tight gas sandstone reservoirs where a plurality of thin layers of hydrocarbon rich zones (e.g., reservoirs 304.1-304.3 of FIG. 3.1) may be scattered or dispersed over a large portion of the formation adjacent the wellbore (e.g., 336.1). A model may be used to develop a near wellbore zone model, where key characteristics, such as reservoir (pay) zone and geomechanical (stress) zone, may be captured.
FIG. 5.1 shows a log 500 of a portion of a wellbore the wellbore 336.1 of FIG. 3.1). The log may be a graph of measurements, such as resistivity, permeability, porosity, or other reservoir parameters logged along the wellbore. In some cases, as shown in FIG. 6, multiple logs 600.1, 600.2 and 600.3 may be combined into a combined log 601 for use in the method 501. The combined log 601 may be based on a weighted linear combination of multiple logs, and corresponding input cutoffs may be weighted accordingly.
The log 500 (or 601) may correlate to a method 501 involving analyzing the log 500 to define (569) boundaries 508 at intervals along the log 500 based on the data provided. The boundaries 568 may be used to identify (571) pay zones 570 along the wellbore. A fracture unit 572 may be specified (573) along the wellbore. Staging design may be performed (575) to define stages 574 along the wellbore. Finally, perforations 576 may be designed (577) along locations in the stages 574.
A semi-automated method may be used to identify partitioning of a treatment interval into multiple sets of discrete intervals (multi-stages) and to compute a configuration of perforation placements, based on these inputs. Reservoir (petrophysical) information and completion (geomechanical) information may be factored into the model, simultaneously. Zone boundaries ma be determined based on input logs. Stress logs may be used to define the zones. One can choose any other input log or a combination of logs which represents the reservoir formation.
For each identified pay zones, a simple fracture height growth estimation computation based on a net pressure or a bottom hole treating pressure may be performed, and the over lapping pays combined to form a fracture unit (FracUnit). Stimulation stages may be defined based on one or more of the following conditions: minimum net height, maximum gross height and minimum distance between stages.
Perforation locations, shot density and number of shots, may be defined based on a quality of pay zone if the stress variations within a stage are insignificant. If the stress variations are high, a limited entry method may be conducted to determine distribution of shots among fracture units. A user can optionally choose to use a limited entry method (e.g., stage desired. Within each FracUnit, a location of perforation may be determined by a selected KH (permeability multiplied by perforation length).
A completion advisor for a horizontal well penetrating formations of shale reservoirs is illustrated in FIGS. 7 through 12. The completions advisor may generate a multi-stage stimulation design, comprising a contiguous set of staging intervals and a consecutive set of stages. Additional inputs, such as fault zones of any other interval information may also be included in the stimulation design to avoid placing stages.
FIGS. 7-9 depict the creation of a composite quality indicator for a shale reservoir. The reservoir quality and completion quality along the lateral segment of borehole may be evaluated. A reservoir quality indicator may include, for example, various requirements or specifications, such as total organic carbon (TOC) greater than or equal to about 3%, gas in place (GIP) greater than about 100 scf/ft3, Kerogen greater than high, shale porosity greater than about 4%, and relative permeability to as (Kgas) greater than about 100 nD. A completions quality indicator may include, for example, various requirements or specifications, such as stress that is ‘-low’, resistivity that is greater than about 15 Ohm-m, clay that is less than 40%, Young's modulus (YM) is greater than about 2×106 psi ( ), Poisson's ratio (PR) is less than about 0.2, neutron porosity is less than about 35% and density porosity is greater than about 8%.
Other quality indicators, such as a completions quality indicator, may be formed in a similar manner using applicable logs (e.g., Young's modulus, Poisson's ratio, etc. for a completions log). Quality indicators, such as reservoir quality 802 and completion quality 801 may be combined (1346) to form a composite quality indicator 803 as shown in FIG. 8.
FIGS. 9-11 depict stage definition for the shale reservoir. A composite Quality indicator 901 (which may be the composite quality indicator 803 of FIG. 8) is combined (1348) with as stress log 903 segmented into stress blocks by a stress gradient differences. The result is a combined stress & composite quality indicator 904 separated into GB, GG, BB and BG classifications at intervals. Stages may be defined along the quality indicator 904 by using the stress gradient log 903 to determine boundaries. A preliminary set of stage boundaries 907 are determined at the locations where the stress gradient difference is greater than a certain value (e.g., a default may be 0.15 psi/ft). This process may generate a set of homogeneous stress blocks along the combined stress and quality indicator.
As shown in FIG. 10, to large block 1010 may be split (1354) into multiple blocks 1012 to form stages A and B where an interval is greater than a maximum stage length. After the split, a refined composite quality indicator 1017 may be formed, and then split into a non-BB composite quality indicator 1019 with stages A and B. In some cases as shown in FIG. 10, grouping large ‘BB blocks with non-BB’ blocks, such as ‘GG’ blocks, within a same stage, may be avoided.
As shown in FIG. 11, the process in FIG. 10 may be applied for generating a quality indicator 1017 and splitting into blocks 1012 shown as stages and B. BB blocks may be identified in a quality indicator 1117, and split into a shifted quality indicator 1119 having three stages A, B and C. As shown by FIGS. 1 0 and 11, various numbers of stages may be generated as desired.
If a formation is not uniform or is intersected by major natural fractures and/or high-stress barriers, additional well planning may be needed. In one embodiment, the underground formation may be divided into multiple sets of discrete volumes and each volume may be characterized based on information such as the formation's geophysical properties and its proximity to natural fractures. For each factor, an indicator such as “G” (Good), “B” (Bad), or “N” (Neutral) can be assigned to the volume. Multiple factors can then be synthesized together to form a composite indicator, such as “GG”, “GB”, “GN”, and so on. A volume with multiple “B”s indicates a location may be less likely to be penetrated by fracture stimulations. A volume with one or more “G”s may indicate a location that is more likely to be treatable by fracture stimulations. Multiple volumes can be grouped into one or more drilling wet kites, with each wellsite representing a potential location for receiving it well or a branch. The spacing and orientation of multiple wells can be optimized to provide an entire formation with sufficient stimulation. The process may be repeated as desired.
While FIGS. 5.1-6 and FIGS. 7-12 each depict specific techniques for staging, various portions of the staging may optionally be combined. Depending on the wellsite, variations in staging design may be applied.
FIG. 13 is a flow diagram illustrating a method (1300) of performing a diversion-assisted stimulation operation. The method involves identifying (1340) a reservoir quality indicator and a completion quality indicator along a lateral segment of a borehole, integrating (1342) a plurality of logs into a single quality indicator, separating (1344) the quality indicator into good and had classifications; combining (1346) the reservoir quality indicator and the completions quality indicator to form a composite quality index; combining (1.348) a composite quality index with stress blocks to form a combined stress block and quality block separated into GG, GB, BG and BB classifications; defining (1350) stages and boundaries of the quality index using a stress gradient log; eliminating (1352) small stress stages where an interval is less than a minimum stage length; splitting (1354) large stages to form a plurality of stages where the interval is greater than a maximum stage length, selectively shifting (1356) BB intervals and selectively positioning (1358) perforations based on the diverter assisted stage classifications.
FIG. 14 is a flow diagram illustrating a method (1400) of performing a stimulation operation. The method involves obtaining (1460) petrophysical, geological and geophysical data about the wellsite, performing (1462) reservoir characterization using a reservoir characterization model to generate a mechanical earth model based on integrated petrophysical, geological and geophysical data (see, e.g., pre-stimulation planning 445). The method further involves generating (1466) a stimulation plan based on the generated mechanical earth model. The generating (1466) may involve, for example, well planning 465, staging design, 466, stimulation design 468, production prediction 470 and optimization 472 in the stimulation planning 447 of FIG. 4. The stimulation plan is then optimized (1464) by repeating (1462) in a continuous feedback loop until an optimized stimulation plan is generated.
The method may also involve performing (1468) a calibration of the optimized stimulation plan (e.g., 449 of FIG. 4). The method may also involve executing (1470) the stimulation plan, measuring (1472) real time data during execution of the stimulation plan, performing real time stimulation design and production prediction (1474) based on the teal time data, optimizing in real time (1475) the optimized stimulation plan by repeating the real time stimulation design and production prediction until a real time optimized stimulation plan is generated, and controlling (1476) the stimulation operation based on the real time optimized stimulation plan. The method may also in evaluaitin (1478) the stimulation plan after completing the stimulation plan and updating (1480) the reservoir characterization model (see, e.g., design/model updating 453 of FIG. 4). The steps may be performed in various orders and repeated as desired.
One specific type of well operation is a diversion treatment. Hydraulic and acid fracturing of horizontal wells as well as multi-layered formations may require using diverting techniques in order to enable fracturing redirection between different zones. Examples of suitable diverting techniques may include the application of hall sealers, slurried benzoic acid flakes and/or removable /degradable particulates, as described in U.S. Patent Application Pub. No. 2012/0285692, the disclosure of which is incorporated by reference herein in its entirety. As well, other treatments may employ of diverting techniques.
Disclosed herein are diverter-assisted-staging algorithms for a well penetrating a subterranean formation. Separate algorithms may be used for vertical and horizontal wells. The diverter-assisted staging algorithm may include various semi-automated processes to identify the optimum multi-stage perforation and staging design for treatments using a diverter. As used herein, the term “diverter” refers to a material placed within a subterranean formation to partially or entirely plug a feature of the subterranean formation, such as, for example, a perforation or fracture of the formation. The term “diverter” should not be defined to include “bridge plugs” or any similar device, which are employed to isolate a specific section of a wellbore.
The staging algorithms utilize a variety of reservoir data that may be obtained both from the subterranean formation an /or the 3D geological model. The algorithms may also utilize petrophysical properties such as, for example, open hole and cased hole logs, borehole images, core data and 3D reservoir models to determine reservoir quality. Geomechanical properties such as, for example, in-situ rock stresses, modulus of elasticity, leak-off coefficient, Poisson's ratio of the wellbore may be used to determine fracture initiation, propagation, and containment within the target zones (completion quality).
For vertical wells, once the boundaries, reservoir (pay) zones, FracUnits are defined and the staging design is completed, the diverter's ability at overcoming stress variations may be incorporated into a perforation design to promote the distribution of the fracturing fluids, such as limited entry method, which is achieved by choosing perforation diameter and number of perforations such that the anticipated injection rate produces sufficient velocity though each perforation to create a pressure differential between the hydraulic fracture and the wellbore.
An example stimulation design and downstream workflow useful for unconventional reservoirs involving tight gas sandstone. (see, e.g., reservoirs 304.1-304.3 of FIG. 3.1) are provided. For tight gas sandstone reservoir workflow, a conventional stimulation (i.e. hydraulic fracturing) design method may be used, such as a single or multi-layer planar fracture model.
A diverter-assisted completion advisor for a vertical well penetrating formations of shale reservoirs is illustrated in FIG. 15.1 and FIG. 15.2. FIGS. 15.1 and 15.2 depict examples of staging involving a tight gas sand reservoir with a diverter. A multi-stage completion advisor may be provided for reservoir planning for tight gas sandstone reservoirs where a plurality of thin layers of hydrocarbon rich zones (e.g., reservoirs 304.1-304.3 of FIG. 3.1) may be scattered or dispersed over a large portion of the formation adjacent the wellbore (e.g., 336.1). A model may be used to develop a near wellbore zone model, where key characteristics, such as reservoir (pay) zone and geomechanical (stress) zone, may be captured.
FIG. 15.1 shows a log 1500 of a portion of a wellbore (e.g., the wellbore 336.1 of FIG. 3.1). The log may be a graph of measurements, such as resistivity, permeability, porosity, or other reservoir parameters logged along the wellbore. In some cases, as shown in FIG. 6, multiple logs 600.1, 600.2 and 600.3 may be combined into a combined log 601 for use in the method 1501 (as illustrated in FIG. 15.2). The combined log 601 may be based on a weighted linear combination of multiple logs, and corresponding input cutoffs may be weighted accordingly.
The log 1500 (or 601) may correlate to a method 1501 involving analyzing the log 1500 to define (1569) boundaries 1568 at intervals along the log 1500 based on the data provided. The boundaries 1568 may be used to identify 1571) pay zones 1570 along the wellbore. A fracture unit 1572 may be specified (1573) along the wellbore. Staging design may be performed (1575) to define stages 1574 along the wellbore. Perforations 1576 may be designed (1577f along locations in the stages 1574. Finally, as diversion treatment may be designed (1579) along one or more of the locations in stages 1574. The diversion design should include a quantity of diverter such as, for example, the quantity or amount of diverter to plug a number of perforations in order to generate an additional pressure differential between the hydraulic fracture(s) and the wellbore required to divert fluid to other perforations. The diverter may be selected based upon information known to persons skilled in the art, with rules such as being able to plug the downhole features the induced fracture.
For horizontal wells, reservoir quality indicators and completion quality indicators are classified and combined in composite quality blocks, as discussed in further detail below. Generally, stress information may be used to generate stress blocks. Here stress may mean the computed fracture initiation or breakdown pressure derived from the in-situ stresses and wellbore properties. If the stress difference between blocks is lower than a threshold value defined by the pressure which is generated by the diverter, then the stress blocks are merged. The merged stress blocks and the composite quality index are combined to design stages and perforation clusters. Finally, the diverter enables adding a final step of selectively positioning, the perforations.
A diverter-assisted-completion advisor for a horizontal well penetrating formations of shale reservoirs is illustrated in FIG. 16. The diverter-assisted-completions advisor may generate a multi-stage stimulation design, comprising a contiguous set of staging intervals and a consecutive set of stages. Additional inputs, such as fault zones or any other interval information may also be included in the stimulation design to avoid placing stages.
FIG. 16 depicts a stage definition for the shale reservoir. First, a stress log is being segmented in stress blocks by a stress gradient difference of values (e.g., about 0.15 psi/ft) (1601)1. The stress differences between the stress blocks and pressure generated by the diverter are then compared (1602). The stress blocks are then “merged” or “combined” (1603) if the stress difference between two (2) blocks is less than the pressure which can be generated with the diverter. A composite quality indicator 1604 (which ma be the composite quality indicator 803 of FIG. 8) is combined with a stress log segmented into merged stress blocks by stress gradient differences lower than the pressure generated by the diverter (1604). The result is a combined stress and composite quality indicator separated into GB, GG, BB and BG classifications at intervals (1605). Stages may be defined along the stress and composite quality indicator 1605 by using the stress gradient log 903 to determine boundaries. A preliminary set of stage boundaries 907 are determined at the locations where the stress gradient difference is greater than the difference which can be overcome by a diverter. This process may generate a set of homogeneous merged-stress blocks along the combined stress and quality indicator.
Stress blocks may be adjusted to a desired site of blocks. For example, small stress blocks may be eliminated where an interval is less than a minimum stage length by merging it with an adjacent block to form a refined composite quality indicator 1606. One of two neighboring blocks which has a smaller stress gradient difference may be used as a merging target. In another example, large stress blocks may be split where an interval is more than a maximum stage length to form another refined composite quality indicator 1607.
FIG. 17 is a flow diagram illustrating a method (1700) of performing a diversion-assisted stimulation operation. The method involves identifying (1740) a reservoir quality indicator and a completion quality indicator along a lateral segment of a borehole, integrating (1742) a plurality of logs into a single quality indicator, separating (1744) the reservoir quality indicator into good and had classifications and combining (1746) the reservoir quality indicator and the completion quality indicator to form a composite quality index. Independently of the identifying (1740), integrating (1742), separating (1744) and combining (1746) steps, the method further involves creating (1748) stress blocks along a lateral segment of a borehole and merging (1750) the stress blocks using the diversion criterion discussed above in 1603. The method then further involves combining (1752) a composite quality index (1746) with the merged stress blocks (1750) to form a combined stress block, and quality block separated into at least one of the following diverter-assisted classifications: GG, GB, BG and BB, defining (1754) stages using the combined composite quality index and merged stress blocks (1752), eliminating (1756) small stages where an interval is less than a minimum diverter assisted stage length, splitting (1758) large stages to form a plurality of stages where an interval is greater than a minimum diverter assisted stage length, selectively adjusting (1760) the stage boundaries to form uniform quality blocks and selectively positioning (1762) perforations based on the diverter assisted classifications. The minimum stage length is often a balance between time efficiency (e.g., cost of treatment) which decreases as the stage gets longer and the quality of stimulation decreases. In some fields, the stage length may be from about 200 to about 500 ft in horizontal completion.
FIG. 18 is a flow diagram illustrating a method (1800) of performing a diversion-assisted stimulation operation. The method involves identifying (1840) a reservoir quality indicator and a completion quality indicator along a lateral segment of a borehole, integrating (1842) a plurality of logs into a single quality indicator, separating (1844) the reservoir quality indicator into good and bad classifications and combining (1846) the reservoir duality indicator and the completion quality indicator to form a composite quality index. Independently of the identifying (1840), integrating (1842), separating (1844) and combining (1846) steps, the method further involves creating (1848) stress blocks along a lateral segment of a borehole, computing (1850) the fracture initiation pressure using one or more of the wellbore properties, near-wellbore properties and stress log, and merging (1852) the fracture initiation blocks using the diversion criterion discussed above in 1603. The method then further involves combining (1854) a composite quality index (1846) with the merged fracture initiation blocks (1852) to form a combined fracture initiation block and quality block separated into GG, GB, BG and BB classifications, defining (1856) stages using the combined composite quality index and merged fracture initiation blocks (1854), eliminating (1858) small stages where an interval is less than a minimum diverter assisted stage length, splitting (1860) large stages to form a plurality of stages where an interval is greater than a minimum diverter assisted length, selectively adjusting (1862) the stage boundaries to form uniform quality blocks and selectively positioning (1864) perforations based on the diverter assisted classifications.
FIG. 19 is a flow diagram illustrating a method (1900) of performing a diversion-assisted stimulation operation. The method involves identifying (1940) a reservoir quality indicator and a completion quality indicator along a lateral segment of a borehole, integrating (1942) a plurality of logs into a single quality indicator, separating (1944) the reservoir quality indicator into good and had classifications and combining (1946) the reservoir quality indicator and the completion quality indicator to form a composite quality index. Independently of the identifying (1940), integrating (1942), separating (1944) and combining (1946) steps, the method further involves creating (1948) stress blocks along as lateral segment of a borehole and merging (1950) the stress blocks using the diversion criterion discussed above in 1603. The method then further involves combining (1952) a composite quality index (1946) with the merged stress blocks (1950) to form a combined stress block and quality block separated into GG, GB, BG and BB classifications, defining (1954) stages using the combined composite quality index and merged stress block (1952), eliminating (1956) small stages where an interval is less than a minimum diverter assisted stage length, splitting (1958) large stages to form a plurality of stages where an interval is greater than a minimum diverter assisted length, selectively adjusting (1960) the stage boundaries to form uniform quality blocks and selectively positioning (1962) perforations based on the diverter assisted classifications. The method may also include as an optional step selectively positioning (1964) perforations to a direct sequence (e.g., from toe to heel) or to fracture stress shadowed regions. Mechanical isolation techniques, such as, for example, bridge plugs may be used to separate stress blocks selected as described above. Furthermore, selective positioning of the mechanical isolations could also be based on the sequential selection of stress block lengths in a suitable direction along a completion. For example, the direction may be a toe-to-heel arrangement as depicted in FIG. 20, which illustrates a continuum of stresses along the lateral (reported as fracture initiation pressure (Pim). FIG. 20 also shows a sequential determination of the suitable locations of the mechanical isolation 2002 devices based on the fracture initiation pressure differential 2000 (ΔPim) that can be overcome with the diverter. The sequential technique can be performed manually, semi-automatically or automatically, but can also be performed front any arbitrary point along the completion. In FIG. 20: Starting from the section to be fractured at the toe 2004 (right hand side of FIG. 20), and moving toward the heel 2006 (Following the arrow to the left side of FIG. 20), the Pim log variations are compared with ΔPim. ΔPin is the criterion described earlier (1605). Any variation of amplitude exceeding ΔPim is to be isolated using a mechanical isolation device 2002 such as a bridge plug, which isolates a section of the wellbore independently front the stress variations of the formation. The advantage of such an approach is to use bridge plugs only where required by the stress variations.
Perforations can be located to impart a preferred direction to the sequence of clusters to be fractured (see FIG. 20). For example, if the stress variations are distributed such that lower stress regions are at the toe of the stage, then one may begin by perforating the low stress zones toward the toe of the stage, and then place the ‘high stress perforations toward the heel of the stage. Using this method, the toe dusters will be fractured first and plugged by the diverter. After the diverter is placed, in the perforations, the heel clusters may then be fractured. One potential advantage of such a toe-to-heel scheme is if the amount of diverter pumped downhole is in excess for the number of fractures, then the excess diverter remains in the wellbore and downstream of the new dusters to be fractured. Therefore, the location of that “diverter in excess” may not inadvertently plug the new fractures which are being created in the high stress zones. This may happen if the job design overestimated the number of perforations which have been fractured prior to injecting a diverter Such overestimation can occur when the design overestimated the amount of perforations which have been fractured by as factor of 50%, and the actual pre-diversion treatment left half of the perforations unstimulated. Therefore, if 10 kg of diverter is used to plug effectively the actual fracture, but the design called for 20 kg of diverter, then there is a 10 kg, diverter excess that will be pumped in the wellbore. This excess amount of diverter should not accidentally plug the perforations to divert to, so it is desirable that the perforations to divert to are above the perforations to plug (i.e., toward the heel with respect to the old perforations). If the risk of inadvertently plugging perforations to divert to is perceived high, then one may decide not to use the diverter when the stress distribution is such that the low stress regions are located toward the heel of the stage.
Alternatively, as shown in FIG. 21, the perforation location 2104 may also be selected ardor located so that the perforations 2104 in low stress areas of the stress logs 2102 once stimulated and after diversion are perforations to be fractured in regions under the stress shadow of the perforations fractured initially. The differences in low stress and high stress are a function of the original stress anisotropy, rock geomechanical property and net pressure developed during the development of the induced fracture. A typical value for a difference in fracture gradient between the low and high stress regions is 0.2 psi/ft. Stress shadows are characterized by the situation when hydraulic fractures are placed in dose proximity, the subsequent fractures may be affected by the stress field from the previous fractures. The effects include higher net pressures, smaller fracture widths and changes in the associated complexity of the stimulation. The level of microseismicity is also altered by stress shadow effects. Additional details regarding stress shadowing are described in SPE 147363, the disclosure of which is incorporated by reference herein in its entirety.
In a reservoir with medium level of horizontal stress anisotropy, such as, for example, a first stage may initially open the low stress clusters creating bi-wing or low complexity fracture 2202 due to stress anisotropy. In brittle formations, the propagation of the bi-wing fractures 2202 can also cause parallel stress relief fractures 7106 Such bi-wing fractures 2202 are presented in FIG. 22, where perforations 2204 connected to the low stress zones are being fractured.
The induced fractures induce an altered stress field in the surrounding formation. The stress perpendicular to the fractures may change by a larger degree than the stress parallel to the fracture, thereby reducing the stress contrast. Stress anisotropy can be reduced or even reversed to facilitate openings of planes of weakness within the rock.
Pumping the diverter obstructs the fractures. A second part of pumping after diversion will initiate fracturing in the higher stress clusters in areas of the rock that would be altered by the stress shadow of the 1st stage. Those stress-altered regions have a lower, or inverted stress anisotropy and therefore the dilation of the existing natural fracture or shear failure of planes of weakness. Therefore these fractures would likely be more complex (i.e., for a complex fracture network 2302) giving a better connection with hydrocarbon remaining in the formation. See FIG. 23. Method to determine the spacing between fractures for generating stress-altered complex fracturing is described SPE130043 and U.S. Pat. No. 8,439,116 B2, each of which is incorporated by reference herein in its entirety.
An individual using the diverter-assisted completion advisor may decide to compare the results of the simulation with a diverter and without the diverter. Because the diverter enables merging stress blocks, the diverter assisted algorithm tends to show that the length of each section isolated with bridge plugs is in general longer than without diverter. The engineer may also chose a higher value of max stage length based on the simulation results,
Previous Patent: COMPUTER-IMPLEMENTED PSUEDO-BROWSING
Next Patent: METHOD AND SYSTEM FOR PATIENT-SPECIFIC MODELING OF BLOOD FLOW