US20240110472A1

US20240110472A1 - Optimal drilling and fracturing sequences for placing numerous horizontal wells in tight reservoirs

Info

Publication number: US20240110472A1
Application number: US17/959,871
Authority: US
Inventors: Kaiming Xia; Yanhui HAN
Original assignee: Saudi Arabian Oil Co
Current assignee: Saudi Arabian Oil Co
Priority date: 2022-10-04
Filing date: 2022-10-04
Publication date: 2024-04-04

Abstract

Systems and methods include a technique for drilling and fracturing wells. Geomechanical properties and in-situ stresses for the field are estimated using collected data and results from mini-fracking tests. A 3D geomechanics model for the field is generated based on 3D property model and natural fracture network. First 3D hydraulic fracturing modeling for a single well is conducted to obtain an optimum pump schedule for a target fracture length and well spacing for placing numerous horizontal wells in the field. Then 3D hydraulic fracturing modeling for the multiple wells is conducted based on a drilling-fracturing sequence configured to generate symmetric fractures and to determine an optimum pump schedule for middle wells, considering tensile stress superposition. The drilling-fracturing sequence includes initially skipping fracturing of a drilled well adjacent to a fractured well. The group of wells are drilled and fractured using the sequence.

Description

TECHNICAL FIELD

The present disclosure applies to techniques for drilling wells, such as oil and gas wells.

BACKGROUND

During the past few decades, technology developments in horizontal drilling and multistage hydraulic fracturing have played an important role in shale gas recovery, e.g., deep and tight gas recovery. Drilling multiple horizontal wells from a pad has increasingly become a common approach in unconventional resource development. Drilling multiple horizontal wells can reduce drilling costs, shorten drilling times, and reduce negative impacts on land and the environment. The combination of horizontal drilling and hydraulic fracturing can significantly increase the production of reservoirs.

SUMMARY

The present disclosure describes techniques that can be used for horizontal drilling and multistage hydraulic fracturing. In some implementations, a computer-implemented method includes the following. Geomechanical properties for a well in a group of wells in a field are estimated using collected data and results from mini-fracking tests on previous wells. The estimates include in-situ stresses and maximum horizontal stress direction for the field. A prediction is determined for a discrete natural fracture network for the field, including predicting fracture geometries, orientations, and distributions for the group of wells. A three-dimensional (3D) geomechanics model is generated for the field based on 3D grid properties of the field and the discrete natural fracture network. 3D hydraulic fracturing modeling for fracturing a single well in the field is conducted to obtain an optimum pump schedule for a target fracture length and well spacing for placing numerous horizontal wells in the field. 3D hydraulic fracturing modeling for the group of wells is conducted based on a drilling-fracturing sequence configured to generate symmetric fractures and to determine an optimum pump schedule for middle wells in the group of wells considering tensile stress superposition, where the drilling-fracturing sequence includes initially skipping fracturing of a drilled well adjacent to a fractured well. The group of wells are drilled and fractured using the drilling-fracturing sequence.
The previously described implementation is implementable using a computer-implemented method; a non-transitory, computer-readable medium storing computer-readable instructions to perform the computer-implemented method; and a computer-implemented system including a computer memory interoperably coupled with a hardware processor configured to perform the computer-implemented method, the instructions stored on the non-transitory, computer-readable medium.
The subject matter described in this specification can be implemented in particular implementations, so as to realize one or more of the following advantages. Drilling and fracturing sequences can be integrated together for generating symmetric fractures in the field scale. New drilling and fracturing sequences can be used for multiple horizontal wells drilled from pads in the field scale. The corresponding drilling and fracturing strategies can alleviate stress shadow and generate symmetric fractures with respect to each wellbore in the field scale. The integrated techniques can be used to manage and plan drilling sequences and fracturing sequences in shale/tight gas reservoirs which need fracturing. Injection fluid volume can be reduced using existing tensile stress bulbs around the fracture tips of the neighboring wells and avoid stress shadow, resulting in cost reductions in the field scale. The tensile stress bulb can be fully used to optimize drilling and fracturing sequences, resulting in the generation of symmetric fractures and a reduction of injection fluid volume. A new geomechanics workflow can be used to determine a target fracture length, an optimal well spacing and its corresponding pump schedule (injection fluid volume). Both single well hydraulic fracturing model and multiple wells hydraulic fracturing model are used to obtain the different pump schedules. The multiple wells hydraulic fracturing model is used to determine the pump schedule for the middle wells of the fracturing sequences, which requires less injection fluid volume due to using tensile stress superposition.
The details of one or more implementations of the subject matter of this specification are set forth in the Detailed Description, the accompanying drawings, and the claims. Other features, aspects, and advantages of the subject matter will become apparent from the Detailed Description, the claims, and the accompanying drawings.

DESCRIPTION OF DRAWINGS

FIG. 1A is a diagram showing an example of a sequential fracturing order for a single well, according to some implementations of the present disclosure.

FIG. 1B is a diagram showing an example of a skipping fracturing order for a single well, according to some implementations of the present disclosure.

FIG. 2 is a diagram showing an example of a zipper-fracturing sequence for stimulating two neighboring horizontal wells, according to some implementations of the present disclosure.

FIG. 3 is a diagram showing an example of a modified zipper-fracturing sequence for stimulating two horizontal wells, according to some implementations of the present disclosure.

FIGS. 4 and 5 show examples of plots that include induced stresses due to fracture opening, in which both compressive stress and tensile stress can be generated, according to some implementations of the present disclosure.

FIG. 6 . is a diagram showing an example of a horizontal stress and tensile stress bulb 602 around fracture tip induced by fracture opening, according to some implementations of the present disclosure.

FIG. 7 is a drawing showing an example of a sequence including an asymmetric fracture geometry due to tensile stress bulb superposition, according to some implementations of the present disclosure.

FIG. 8 is a drawing showing an example of a fracturing sequence for multistage stimulation of multiple horizontal wells, according to some implementations of the present disclosure.

FIG. 9 is a diagram showing an example of a new strategy of optimized drilling and fracturing sequences, according to some implementations of the present disclosure.

FIG. 10 is a flow diagram showing an example of a workflow for determining pump schedules and fracturing sequences for stimulating multiple horizontal wells, according to some implementations of the present disclosure.

FIG. 11 is a flowchart of an example of a method for determining the pump schedule of the optimal drilling and fracturing sequences for placing numerous horizontal wells in tight reservoirs, according to some implementations of the present disclosure.

FIG. 12 is a block diagram illustrating an example computer system used to provide computational functionalities associated with described algorithms, methods, functions, processes, flows, and procedures as described in the present disclosure, according to some implementations of the present disclosure.

Like reference numbers and designations in the various drawings indicate like elements.

DETAILED DESCRIPTION

The following detailed description describes techniques for horizontal drilling and multistage hydraulic fracturing. Various modifications, alterations, and permutations of the disclosed implementations can be made and will be readily apparent to those of ordinary skill in the art, and the general principles defined may be applied to other implementations and applications, without departing from the scope of the disclosure. In some instances, details unnecessary to obtain an understanding of the described subject matter may be omitted so as to not obscure one or more described implementations with unnecessary detail and inasmuch as such details are within the skill of one of ordinary skill in the art. The present disclosure is not intended to be limited to the described or illustrated implementations, but to be accorded the widest scope consistent with the described principles and features.
The present disclosure includes techniques that can be used to optimize drilling sequences of horizontal wells and their hydraulic fracturing sequences. For example, optimization can refer to achieving drilling and fracking results that indicate or result in a performance greater than a predefined threshold. Integrating these two factors into a better sequence, timing, and location of drilling and fracturing events can help to maximize production rates and reduce operation costs.
Techniques of the present disclosure can be used to establish several numerical models to verify the existence of using the tensile stress bulb around the fracture tips after hydraulic fracturing. The feasibility of using the induced tensile stress bulbs can be studied to optimize hydraulic fracture propagation in terms of cost, which can alleviate stress shadow issues. Based on this, drilling sequence and fracturing when considered and sequenced together in a field operation sequence can generate symmetric fractures. Symmetric fractures are strongly desired since most reservoir production models are built for symmetric fractures with respect to the wellbore. In order to facilitate drilling and fracturing strategies of the present disclosure, a workflow is provided to determine the well spacing and the corresponding optimal pump schedules for the field scale. As indicated in the FIGS. 10 and 11 , two optimal pump schedules for the new drilling-fracturing sequence are needed and determined through hydraulic fracturing modeling. One is determined through hydraulic fracturing modeling of the single well, which will be used as the pump schedule for the side wells in the new drilling-fracturing sequences. The second one is determined through hydraulic fracturing modeling of multiple well, which will be used as the pump schedule for the middle wells in the new drilling-fracturing sequences.
The present disclosure describes integrated drilling and fracturing sequences for placing numerous horizontal wells in the field scale. The techniques can include optimizing multiple horizontal wells' placement connecting the same pad and their corresponding drilling and fracturing sequences.
Techniques of the present disclosure can be based on building numerical models to show the tensile stress bulbs existing around the fracture tips and the potential impact on reducing hydraulic fracture propagating resistance. Through integrating drilling and fracturing factors as a whole, drilling and fracturing sequences can be optimized together while focusing on reducing drilling times and improving fracturing results. Such techniques can lead to the development of integrated and optimal drilling and fracturing sequences, which can lead to the generation of symmetric fractures instead of asymmetric fractures on the field scale. This can improve production and reservoir field management. This can occur not only by avoiding stress shadow but also by fully using the existing tensile stress bulb around the fracture tips to reduce fracture propagation resistance propagating from the neighboring wells. Using the tensile stress superposition can maximize fracture length and reduce injection fluid volume, which can lead to cost reductions. A workflow was developed to facilitate this drilling and fracturing strategy, which can consider the impact of natural fractures (if available) on the optimizing well spacing and pump schedule.
An objective of the techniques of the present disclosure is to provide integrated drilling and fracturing sequences for drilling multiple horizontal wells from pads in the oil and gas industry in which hydraulic fracturing treatment is used to boost the production. The drilling and fracturing sequences can be based on solid mechanics and computer simulations. Drilling multiple horizontal wells from pads along the minimum horizontal stress direction has increasingly become a common approach in unconventional resource development, which can alleviate the negative impact on the environment. At the same time, it is advantageous to optimize drilling and fracturing sequences and their locations. Integrating these factors into better sequences, timings, and locations of the fracturing events can help to maximize production rates and reduce development costs on the field scale.
Conventional techniques have taught over time that hydraulic fracturing modeling shows that fracturing in skipping order or alternating order produces relatively even and longer fracture lengths than fracturing sequentially for a single well (see FIGS. 1 and 2 ). Fracturing sequentially exhibits relatively high fracture interference. Therefore, in the discussion that follows, each well is assumed to be fractured in skipping order if not specifically described otherwise. In the present disclosure, at least one drilling and fracturing sequence is provided for multiple horizontal wells, which can outperform the other fracturing sequences in terms of fracture geometry and injection fluid volume reduction. An important advantage of the techniques is the generation of symmetric fractures with respect to the wellbore, which is good for production prediction and reservoir management. Techniques of the present disclosure can also be used to address complex issues and determine optimal fracturing sequences for drilling and fracturing multiple horizontal wells drilled from pads in the field.
In conventional systems, new hydraulic fracturing designs have been focused on increasing fracture geometry by alleviating the stress shadow during hydraulic fracture treatment and maximizing the fracture length as long as possible. Fracturing using sequential order represents the conventional method (as shown in FIG. 1A), exhibiting stress shadow if the fracturing interval is not large enough. To solve this problem, a “Texas-two method” was developed for fracturing a single well (see FIG. 1B), providing advantages over previous methods. Zipper fracturing was developed for simultaneous fracturing of two parallel horizontal wells from toe to heel (see FIG. 2 ). In this technique, fractures that are created from each perforation cluster can propagate toward each other.
FIG. 1A is a diagram showing an example of a sequential fracturing order 100 for a single well, according to some implementations of the present disclosure. FIG. 1B is a diagram showing an example of a skipping fracturing order 150 for a single well, according to some implementations of the present disclosure. The fracturing orders are presented from heel 102 to toe 104.
FIG. 2 is a diagram showing an example of a zipper-fracturing sequence 200 for stimulating two neighboring horizontal wells, according to some implementations of the present disclosure. FIG. 3 is a diagram showing an example of a modified zipper-fracturing sequence 300 for stimulating two horizontal wells, according to some implementations of the present disclosure.
A modified zipper fracturing technique can combine the alternating fracturing and zipper-fracturing together to create fractures in a staggered pattern, as shown in FIG. 3 . This technique places a fracture between every two consecutive fractures that are fractured in a neighboring well. A modified zipper-fracturing design can potentially increase the stress interference between the fractures and exhibit a stress shadow issue for incoming fractures propagated from the neighboring wells, which might not create an effective stimulated rock volume (SRV) for hydrocarbon production as might be expected. This condition can exist when the fracture intervals from a neighboring well are not large enough.
Hydraulic fracturing in skipping order produces relatively even and longer fracture lengths for a single well. Fracturing sequentially can exhibit a relatively high fracture interference. Therefore, in the following description, each well is assumed to be fractured in skipping order.

Factors Considered for Determining Fracturing Sequences

Stress shadow has been well recognized as an issue that can inhibit the propagation of incoming fractures generated from the neighboring wells. Besides the stress shadow, it is also known that tensile stresses can be induced by fracture opening. The induced tensile stresses can be used to reduce fracture propagation resistance. To explain and study these phenomena, several numerical models can be generated.
FIGS. 4 and 5 show examples of plots 400 and 500 that include induced stresses due to fracture opening, in which both compressive stress and tensile stress can be generated, according to some implementations of the present disclosure. The fractured areas are in a compression state and the intensity is dependent on the fracture spacing and rock properties. Based on the stresses, it can be seen that the formation will be in compression between fractures. The areas surrounding the fracture tips can be in tension state due to fracture opening, which can form the tensile stress bulbs. The increased compression stress between the fractures can pose an issue for incoming fractures propagating from the neighboring wells, which is not good for modified zipper-fracturing method. For in-line fracturing of two neighboring wells (e.g., the zipper-fracturing method) the stress shadow issue can be avoided. The stress interference due to the existing tensile stress bulbs (see FIG. 4 ) can be used. The tensile stress bulbs can be fully used to overcome or reduce fracture propagating resistance for fracturing the neighboring wells if this advantage can be understood and utilized (see FIG. 6 ). As indicated in FIG. 6 , the areas between the two fracture tips will develop tensile stress bulbs due to tensile stress superposition. The tensile stress bulbs will attract fractures propagating relatively easily and faster toward the tensile stress bulb zone, where fracture propagating resistances are relatively lower than other areas. The existing tensile stress bulb can be good or bad depending on the fracturing sequences of the multiple horizontal wells.
The fracturing sequences of multiple wells can make a big difference in terms of operation costs and fracture geometry for production. Generally, in-line fracturing and off-line fracturing methods can be selected. The selection of which fracturing method should be used for a particular region will depend on subsurface conditions and well completion operation. Key concerns of which fracturing method to select can include the magnitude of minimum horizontal stress, rock properties, and the discrete natural fracture network. In the geologic situation with relatively larger minimum horizontal stresses and/or fracture closure pressure, it can be difficult to create longer fractures. In-line fracturing may be a realistic choice. In the case with a relatively low minimum horizontal stress or fracture closure pressure, it will be easier to create longer fractures with the same energy than that of a high minimum horizontal stressed area.
FIG. 4 is a diagram 400 showing an example of a horizontal stress and tensile stress bulb 402 around fracture tip induced by fracture opening, according to some implementations of the present disclosure. Stress contours 404 (e.g., measured in Pascals (Pa)) are indicated by shading.
FIG. 5 is a diagram 500 showing an example of horizontal stress and tensile stress bulb 502 around fracture tip induced by fracture opening, according to some implementations of the present disclosure. Stress contours 504 (e.g., measured in Pa) are indicated by shading.
FIG. 6 . is a diagram 600 showing an example of a horizontal stress and tensile stress bulb 602 around fracture tip induced by fracture opening, according to some implementations of the present disclosure. Regarding differences in FIGS. 4-6 , FIG. 4 is for a single fracture, and FIG. 5 is an example of three fractures propagating from one well. FIG. 6 is an example of two neighboring wells, each well having three fractures. FIG. 6 shows the stress superposition exhibited in the middle areas. This indicates the existence of tensile stress superposition, which can be good for reducing fracture propagation resistance. Also, this condition promotes faster propagation of fractures toward each other.
FIG. 7 is a drawing showing an example of a sequence 700 including an asymmetric fracture geometry due to tensile stress bulb superposition 712, according to some implementations of the present disclosure. Due to fracture interference and the stress shadow effect, fracturing multiple horizontal wells sequentially is likely to generate an asymmetric fracture geometry with respect to the well trajectory unless the well spacing is too large. This is true for both in-line fracturing methods and off-line fracturing methods. FIG. 7 is used to illustrate and explain the reasons why asymmetric fractures are generated. In FIG. 7 , it is assumed a first Well # 1 701 is fractured first, followed by fracturing a second Well # 2 702. Three potential instances are shown by FIG. 7 . In a first instant 706, once Well #1 701 is fractured, tensile stress bulbs 704 are generated around the fracture tips of Well # 1 701. It is known that hydraulic fractures in rock are generally generated due to tensile failure when the induced tensile stress exceeds the minimum horizontal stress plus the tensile strength (see FIG. 4 ). A tensile stress bulb is induced in the areas surrounding the previously generated fracture tips of Well # 1 701. The induced tensile stress bulb will exist as long the fractures are not fully closed, which superimposes 706 the stress induced by subsequent fractures initiated from the neighboring Well # 2 702. This tensile stress superposition will attract the hydraulic fractures from Well # 2 702, propagating towards Well # 1 701 relatively more easily and faster (see Well #2 702 in FIG. 7 ). For in-line fracturing, the subsequent fractures should tend to propagate faster and longer towards the existing tensile stress bulb areas where the neighboring well is already fractured (see instant # 2 708). This leads to asymmetric fracture geometries originated from Well # 2, which might not be good for well production. As indicated in FIG. 7 , the fracture propagating length L₂ 718 of Well # 2 702 is larger than the fracture propagating length L₁ 716 of Well # 1 701 (L₂>L₁). The fracture lengths on both sides of the well are not equal. An adverse effect of in-line fracturing is the new propagating fracture (from Well #2) connects to the previously generated fractures from neighboring Well # 1, which is indicated as instant # 3 710. Also, it can prevent the newly generated fractures from Well # 2 from propagating long enough in the opposite direction (downward in FIG. 7 ). After fractures communicate 714, the stress bulbs between the two wells can shrink or disappear accordingly. The fractures originated from both Well # 1 and Well # 2 can continue to propagate if fluid injection is continuing. Overall asymmetric fractures are likely to be generated for the two neighboring wells.
FIG. 8 is a drawing showing an example of a fracturing sequence 800 for multistage stimulation of multiple horizontal wells 802, according to some implementations of the present disclosure. FIG. 8 represents a conventional sequences 804 and 806 to drill wells and then fracture the wells. The sequences can lead to asymmetric fractures, in which it is difficult to control fracture geometries relative to the well trajectory. Based on this reason, it is not suggested to fracture multiple horizontal wells using the well sequential fracturing sequence marked in FIG. 8 , although skipping order and two-round fracking procedures can be used for individual wells.

New Drilling and Fracturing Sequences for Multiple Horizontal Wells

For hydraulic fracturing of a horizontal well, symmetric fractures are strongly desired. The existence of symmetric fractures can make it relatively easy to control and predict the production of a stimulated well. Most production models are developed based on the symmetric fractures with respect to the wellbore. For this purpose, the present disclosure describes drilling and fracturing sequences for stimulating multiple horizontal wells in the field. The horizontal wells drilled from pads can all be assumed to be at the minimum horizontal stress direction. Unlike conventional practice, the techniques of the present disclosure can optimize the drilling sequences and fracturing sequences together as a whole, which can shorten the waiting time between well operations. This can lead to the achievement goal of using tensile stress bulbs to reduce injection fluid volume 808, generate symmetric fractures 810, and optimize well spacings.
FIG. 9 is a diagram showing an example of a new strategy of optimized drilling and fracturing sequences 900, according to some implementations of the present disclosure. For example, FIG. 9 shows an example of drilling and fracturing sequences that can be used in multiple horizontal wells. The new strategy of optimized drilling and fracturing sequences 900 can be used to generate symmetric fractures with respect to each wellbore. Three wells 902 are drilled from Pad_1 904. Then, two wells 902 are subsequently drilled from each of Pad_2 906 and Pad N 908. Drilling sequence 910 and fracturing sequence 912 are followed, with the order of the wells 902 being different in each sequence 910, 912. This drilling schedule can reduce drilling trajectory lengths of the wells as compared, for example, to drilling four wells from one pad. In this regard, the optimized drilling and fracturing sequences 900 can save drilling time and reduce overall development costs. In FIG. 9 , injection volume 914 and fracture geometry 916 are also listed, and all fractures are symmetric. The optimized drilling and fracturing sequences 900 are applicable in situations in which only one drilling rig exists in a drilling block and in which two wells are drilled on the same side of the drilling pad. In this situation, three wells can first be drilled from the first pad, followed by two wells each in the second and third pads as described with reference to FIG. 9 . The wells can be fractured according to a skipping order. Each well can be fractured using two rounds. The first round can be used to fracture the well with large fracture stage spacing. After the first-round fracturing is complete, the second round can start. This sequence can reduce stress shadow.
In particular, Well #3 can be drilled second and subsequently fractured after it is drilled. As indicated in FIG. 9 , Well #1 and Well # 3 have a relatively large distance between them, and the tensile stress bulbs around each fracture tip are difficult to cause asymmetric fracture for well # 3. The fracture geometries for well # 3 will be approximately symmetric with respect to its well trajectory. Then proceed to drill well #2 and fracture it thirdly. Similar stress conditions on both sides of well # 2, the fractures will likely propagate with equal growth rates on both sides of well # 2. Therefore, symmetric fractures can be generated for well # 2, and also tensile stress bulb can be used to reduce injection fluid volume for the middle well as marked in FIG. 9 . In summary, after each well is drilled, fracturing can be pursued subsequently before drilling the next well. No need to wait for all the wells being drilled. Drilling a well and fracturing a well should be taken alternatively. After the two wells from Pad_1 are drilled and fractured following the drilling and fracturing sequences, then the next drilling pad can be drilled (see FIG. 9 ). The same pattern of drilling and fracturing sequences in the field can be followed, which can lead to symmetric fractures for each wellbore. This alternative fracturing sequence will be executed following a similar pattern in the whole field scale. In other words, after every alternating well is drilled and fractured, the well between the fractured wells is to be drilled and fractured subsequently.
In practice, symmetric fracture geometries are strongly desired, as these geometries can deliver the uniform drainage radius for production in the field. The strategies can also be good for well placement and well planning and management in the field.

Workflow for Determining Fluid Injection Volume and Well Spacing

In order to use the sequences described in the present disclosure to generate symmetric fractures for stimulating multiple horizontal wells drilled from the pad, a first step can be to determine target well spacing and a corresponding pump schedule. The initial pump schedule can be determined using hydraulic fracturing modeling of a single well. The initial pump schedule can be planned to use a total injection fluid volume of V. The initial pump schedule can also be defined to generate the fracture length equal to the target well spacing. The corresponding fracture length can be used to determine a well spacing S for multiple horizontal wells drilled from a pad. The natural fracture network (if possibly obtained based on data availability) can be incorporated into the hydraulic fracturing modeling so as to be configured to handle naturally-fractured reservoirs such as clastic gas reservoirs.
FIG. 10 is a flow diagram showing an example of a workflow 1000 for determining pump schedules for stimulating multiple horizontal wells, according to some implementations of the present disclosure. The workflow 1000 can be used for fracturing sequences described in the present disclosure for stimulating multiple horizontal wells in the field, for example. In the workflow 1000, if a constant well spacing is used as determined from hydraulic fracturing modeling of a single well for a field, then the injection fluid volume for fracturing the middle well can be reduced using the existing tensile stress bulbs. For example, as shown in FIG. 9 , the injection fluid volume (1−α)V for the middle Well # 2 and Well # 4 can be less than that of the two side wells of Well # 1 and Well # 3. Variable α, which is less than 1, represents a reduction of injection fluid volume and ranges from 0.1 to 0.30.
At 1002, data collection is performed, including collecting drilling reports, well surveys, formation tops, and well logs. At 1004, a mini-fracking test is performed to determine breakdown pressure. At 1006, geomechanical properties, including in-situ stresses, are determined. At 1008, image log processing occurs for natural fracture orientations and fracture intensity, and for maximum horizontal stress orientation. At 1010, the breakdown pressure is estimated. At 1012, three-dimensional (3D) property modeling occurs. At 1014, natural fracture prediction occurs, including predicting fracture geometry, orientation, and distribution. At 1016, an initial pump schedule is designed based at least on the breakdown pressure and the fluid efficiency. At 1018, a 3D geomechanics model is built based on 3D grid properties and a discrete natural fracture network. At 1020, 3D hydraulic fracturing modeling of single well is conducted to obtain the optimal pump schedule for a target fracture length and well spacing for the field. At 1022, 3D hydraulic fracturing modeling is conducted for stimulating multiple horizontal wells and to generate symmetric fractures, and to determine the optimum fluid injection volume or pump schedule for the middle wells considering tensile stress superposition.
In the workflow, if a constant well spacing is used that is determined from hydraulic fracturing modeling of a single well for a field, the injection fluid volume for fracturing the middle well can be reduced to some extent. For example, as shown in FIG. 9 , the injection fluid volume (1−α)V for the middle wells # 2 and #4 will be less than that of the two side wells # 1 and 3. The corresponding middle well is named based on the fracturing sequences. The variable α can be determined through hydraulic fracturing modeling for a particular field. The reduction of injection fluid volume is due to the tensile stress superposition effect. The hydraulic fracturing cost reduction can be achieved through two approaches: (1) if the pump schedule is determined and kept as constant, the well spacing can be increased by a certain percentage like 10%, 20%, etc., which should be obtained through hydraulic fracturing modeling; (2) or the injection volume can be reduced for the middle well leaving the well spacing as constant, which is determined from hydraulic fracturing modeling of a single well. Either one can be taken for the purpose of cost reduction.
As evidenced in the above hydraulic fracturing simulations for multistage stimulation of multiple wells, the tensile stress superposition exists in certain regions and can be used to generate additional fracture growth, which should be accounted for optimizing injection fluid volume. If the fracture length is designed based on the hydraulic fracturing simulation of a single well, the actual well spacing for multiple wells should be larger than the fracture length determined by the single well simulation. Not only can this avoid fracture communication issues, but also it can effectively apply the same amount of fluid to generate a relatively longer fracture.
FIG. 11 is a flowchart of an example of a method 1100 for determining a pump schedule for optimal drilling and fracturing sequences for placing numerous horizontal wells in tight reservoirs, according to some implementations of the present disclosure. For clarity of presentation, the description that follows generally describes method 1100 in the context of the other figures in this description. However, it will be understood that method 1100 can be performed, for example, by any suitable system, environment, software, and hardware, or a combination of systems, environments, software, and hardware, as appropriate. In some implementations, various steps of method 1100 can be run in parallel, in combination, in loops, or in any order.
At 1102, geomechanical properties for a well in a group of wells in a field are estimated using collected data and results from mini-fracking tests on previous wells. The estimates include in-situ stresses and maximum horizontal stress direction for the field. In some implementations, method 1100 further includes collecting data for the well, including collecting drilling reports, well surveys, formation tops, and wells logs. From 1102, method 1100 proceeds to 1104.
At 1104, a prediction is determined for a discrete natural fracture network for the field, including predicting fracture geometries, orientations, and distributions for the group of wells. In some implementations, method 1100 further includes performing image log processing for natural fracture orientations, fracture intensity, and for maximum horizontal stress orientation for the field. From 1104, method 1100 proceeds to 1106.
At 1106, a three-dimensional (3D) geomechanics model is generated for the field based on 3D grid properties of the field and the discrete natural fracture network. From 1106, method 1100 proceeds to 1108.
At 1108, 3D hydraulic fracturing modeling for fracturing a single well in the field is conducted to obtain an optimum pump schedule for a target fracture length and well spacing for placing numerous horizontal wells in the field. The 3D hydraulic fracturing modeling can determine an injection volume or the optimal pump schedule for the side wells indicated in FIG. 9 . From 1108, method 1100 proceeds to 1110.
At 1110, 3D hydraulic fracturing modeling for the multiple wells is conducted based on a drilling-fracturing sequence configured to generate symmetric fractures and to determine an optimum pump schedule for the middle wells considering tensile stress superposition, where the drilling-fracturing sequence includes initially skipping fracturing of a drilled well adjacent to a fractured well. For example, the 3D hydraulic fracturing modeling can determine the injection fluid volume or optimal pump schedule for the middle wells that is to be used for keeping the well spacing for the wells in the group of wells obtained at 1108. From 1110, method 1100 proceeds to 1112.
At 1112, the group of wells are drilled and fractured using the drilling-fracturing sequence. For example, the sequence can follow the order described with reference to FIG. 9 . A fracturing order for the group of wells can be different from a well numbering for the group of wells. An injection fluid volume for a middle well drilled last in a pad is reduced by a variable α, where the variable α is a percentage reduction of the injection fluid volume for a first well from a pad. The injection fluid volume for a last well in the pad can be given by (1−α)V, where α is a value in a range of 0.1 to 0.3, and where V is a volume of injection fluid for the first well in the pad. After 1112, method 1100 can stop.
In some implementations, in addition to (or in combination with) any previously-described features, techniques of the present disclosure can include the following. Outputs of the techniques of the present disclosure can be performed before, during, or in combination with wellbore operations, such as to provide inputs to change the settings or parameters of equipment used for drilling. Examples of wellbore operations include forming/drilling a wellbore, hydraulic fracturing, and producing through the wellbore, to name a few. The wellbore operations can be triggered or controlled, for example, by outputs of the methods of the present disclosure. In some implementations, customized user interfaces can present intermediate or final results of the above described processes to a user. Information can be presented in one or more textual, tabular, or graphical formats, such as through a dashboard. The information can be presented at one or more on-site locations (such as at an oil well or other facility), on the Internet (such as on a webpage), on a mobile application (or “app”), or at a central processing facility. The presented information can include suggestions, such as suggested changes in parameters or processing inputs that the user can select to implement improvements in a drilling and well completion environment. For example, the suggestions can include parameters that, when selected by the user, can cause a change to, or an improvement in, drilling parameters (including drill bit speed and direction) or overall production of a gas or oil well. The suggestions, when implemented by the user, can improve the speed and accuracy of calculations, streamline processes, improve models, and solve problems related to efficiency, performance, safety, reliability, costs, downtime, and the need for human interaction. In some implementations, the suggestions can be implemented in real-time, such as to provide an immediate or near-immediate change in operations or in a model. The term real-time can correspond, for example, to events that occur within a specified period of time, such as within one minute or within one second. Events can include readings or measurements captured by downhole equipment such as sensors, pumps, bottom hole assemblies, or other equipment. The readings or measurements can be analyzed at the surface, such as by using applications that can include modeling applications and machine learning. The analysis can be used to generate changes to settings of downhole equipment, such as drilling equipment. In some implementations, values of parameters or other variables that are determined can be used automatically (such as through using rules) to implement changes in oil or gas well exploration, drilling, or testing. For example, outputs of the present disclosure can be used as inputs to other equipment and/or systems at a facility. This can be especially useful for systems or various pieces of equipment that are located several meters or several miles apart, or are located in different countries or other jurisdictions.
FIG. 12 is a block diagram of an example computer system 1200 used to provide computational functionalities associated with described algorithms, methods, functions, processes, flows, and procedures described in the present disclosure, according to some implementations of the present disclosure. The illustrated computer 1202 is intended to encompass any computing device such as a server, a desktop computer, a laptop/notebook computer, a wireless data port, a smart phone, a personal data assistant (PDA), a tablet computing device, or one or more processors within these devices, including physical instances, virtual instances, or both. The computer 1202 can include input devices such as keypads, keyboards, and touch screens that can accept user information. Also, the computer 1202 can include output devices that can convey information associated with the operation of the computer 1202. The information can include digital data, visual data, audio information, or a combination of information. The information can be presented in a graphical user interface (UI) (or GUI).
The computer 1202 can serve in a role as a client, a network component, a server, a database, a persistency, or components of a computer system for performing the subject matter described in the present disclosure. The illustrated computer 1202 is communicably coupled with a network 1230. In some implementations, one or more components of the computer 1202 can be configured to operate within different environments, including cloud-computing-based environments, local environments, global environments, and combinations of environments.
At a top level, the computer 1202 is an electronic computing device operable to receive, transmit, process, store, and manage data and information associated with the described subject matter. According to some implementations, the computer 1202 can also include, or be communicably coupled with, an application server, an email server, a web server, a caching server, a streaming data server, or a combination of servers.
The computer 1202 can receive requests over network 1230 from a client application (for example, executing on another computer 1202). The computer 1202 can respond to the received requests by processing the received requests using software applications. Requests can also be sent to the computer 1202 from internal users (for example, from a command console), external (or third) parties, automated applications, entities, individuals, systems, and computers.
Each of the components of the computer 1202 can communicate using a system bus 1203. In some implementations, any or all of the components of the computer 1202, including hardware or software components, can interface with each other or the interface 1204 (or a combination of both) over the system bus 1203. Interfaces can use an application programming interface (API) 1212, a service layer 1213, or a combination of the API 1212 and service layer 1213. The API 1212 can include specifications for routines, data structures, and object classes. The API 1212 can be either computer-language independent or dependent. The API 1212 can refer to a complete interface, a single function, or a set of APIs.
The service layer 1213 can provide software services to the computer 1202 and other components (whether illustrated or not) that are communicably coupled to the computer 1202. The functionality of the computer 1202 can be accessible for all service consumers using this service layer. Software services, such as those provided by the service layer 1213, can provide reusable, defined functionalities through a defined interface. For example, the interface can be software written in JAVA, C++, or a language providing data in extensible markup language (XML) format. While illustrated as an integrated component of the computer 1202, in alternative implementations, the API 1212 or the service layer 1213 can be stand-alone components in relation to other components of the computer 1202 and other components communicably coupled to the computer 1202. Moreover, any or all parts of the API 1212 or the service layer 1213 can be implemented as child or sub-modules of another software module, enterprise application, or hardware module without departing from the scope of the present disclosure.
The computer 1202 includes an interface 1204. Although illustrated as a single interface 1204 in FIG. 12 , two or more interfaces 1204 can be used according to particular needs, desires, or particular implementations of the computer 1202 and the described functionality. The interface 1204 can be used by the computer 1202 for communicating with other systems that are connected to the network 1230 (whether illustrated or not) in a distributed environment. Generally, the interface 1204 can include, or be implemented using, logic encoded in software or hardware (or a combination of software and hardware) operable to communicate with the network 1230. More specifically, the interface 1204 can include software supporting one or more communication protocols associated with communications. As such, the network 1230 or the interface's hardware can be operable to communicate physical signals within and outside of the illustrated computer 1202.
The computer 1202 includes a processor 1205. Although illustrated as a single processor 1205 in FIG. 12 , two or more processors 1205 can be used according to particular needs, desires, or particular implementations of the computer 1202 and the described functionality. Generally, the processor 1205 can execute instructions and can manipulate data to perform the operations of the computer 1202, including operations using algorithms, methods, functions, processes, flows, and procedures as described in the present disclosure.
The computer 1202 also includes a database 1206 that can hold data for the computer 1202 and other components connected to the network 1230 (whether illustrated or not). For example, database 1206 can be an in-memory, conventional, or a database storing data consistent with the present disclosure. In some implementations, database 1206 can be a combination of two or more different database types (for example, hybrid in-memory and conventional databases) according to particular needs, desires, or particular implementations of the computer 1202 and the described functionality. Although illustrated as a single database 1206 in FIG. 12 , two or more databases (of the same, different, or combination of types) can be used according to particular needs, desires, or particular implementations of the computer 1202 and the described functionality. While database 1206 is illustrated as an internal component of the computer 1202, in alternative implementations, database 1206 can be external to the computer 1202.
The computer 1202 also includes a memory 1207 that can hold data for the computer 1202 or a combination of components connected to the network 1230 (whether illustrated or not). Memory 1207 can store any data consistent with the present disclosure. In some implementations, memory 1207 can be a combination of two or more different types of memory (for example, a combination of semiconductor and magnetic storage) according to particular needs, desires, or particular implementations of the computer 1202 and the described functionality. Although illustrated as a single memory 1207 in FIG. 12 , two or more memories 1207 (of the same, different, or combination of types) can be used according to particular needs, desires, or particular implementations of the computer 1202 and the described functionality. While memory 1207 is illustrated as an internal component of the computer 1202, in alternative implementations, memory 1207 can be external to the computer 1202.
The application 1208 can be an algorithmic software engine providing functionality according to particular needs, desires, or particular implementations of the computer 1202 and the described functionality. For example, application 1208 can serve as one or more components, modules, or applications. Further, although illustrated as a single application 1208, the application 1208 can be implemented as multiple applications 1208 on the computer 1202. In addition, although illustrated as internal to the computer 1202, in alternative implementations, the application 1208 can be external to the computer 1202.
The computer 1202 can also include a power supply 1214. The power supply 1214 can include a rechargeable or non-rechargeable battery that can be configured to be either user- or non-user-replaceable. In some implementations, the power supply 1214 can include power-conversion and management circuits, including recharging, standby, and power management functionalities. In some implementations, the power supply 1214 can include a power plug to allow the computer 1202 to be plugged into a wall socket or a power source to, for example, power the computer 1202 or recharge a rechargeable battery.
There can be any number of computers 1202 associated with, or external to, a computer system containing computer 1202, with each computer 1202 communicating over network 1230. Further, the terms “client,” “user,” and other appropriate terminology can be used interchangeably, as appropriate, without departing from the scope of the present disclosure. Moreover, the present disclosure contemplates that many users can use one computer 1202 and one user can use multiple computers 1202.
Described implementations of the subject matter can include one or more features, alone or in combination.
For example, in a first implementation, a computer-implemented method includes the following. Geomechanical properties for a well in a group of wells in a field are estimated using collected data and results from mini-fracking tests on previous wells. The estimates include in-situ stresses and maximum horizontal stress direction for the field. A prediction is determined for a discrete natural fracture network for the field, including predicting fracture geometries, orientations, and distributions for the group of wells. A three-dimensional (3D) geomechanics model is generated for the field based on 3D grid properties of the field and the discrete natural fracture network. 3D hydraulic fracturing modeling for fracturing a single well in the field is conducted to obtain an optimum pump schedule for a target fracture length and well spacing for placing numerous horizontal wells in the field. 3D hydraulic fracturing modeling for the group of wells is conducted based on a drilling-fracturing sequence configured to generate symmetric fractures and to determine an optimum pump schedule for middle wells in the group of wells considering tensile stress superposition, where the drilling-fracturing sequence includes initially skipping fracturing of a drilled well adjacent to a fractured well. The group of wells are drilled and fractured using the drilling-fracturing sequence.
The foregoing and other described implementations can each, optionally, include one or more of the following features:
A first feature, combinable with any of the following features, where the method further includes collecting data for the well, including collecting drilling reports, well surveys, formation tops, and wells logs.
A second feature, combinable with any of the previous or following features, where the method further includes performing image log processing for natural fracture orientations, fracture intensity, and for maximum horizontal stress orientation for the field.
A third feature, combinable with any of the previous or following features, where the 3D hydraulic fracturing modeling considers an injection volume for the single well.
A fourth feature, combinable with any of the previous or following features, where a fracturing order for the group of wells is different from a well numbering for the group of wells.
A fifth feature, combinable with any of the previous or following features, where an injection fluid volume for a middle well drilled last in a pad is reduced by a variable α.
A sixth feature, combinable with any of the previous or following features, where the variable α is a percentage reduction of the injection fluid volume for a first well from a pad.
A seventh feature, combinable with any of the previous or following features, where the injection fluid volume for a last well in the pad is given by (1−α)V, where a is a value in a range of 0.1 to 0.3, and where V is a volume of injection fluid for the first well in the pad.
In a second implementation, a computer-implemented system includes one or more processors and a non-transitory computer-readable storage medium coupled to the one or more processors and storing programming instructions for execution by the one or more processors. The programming instructions instruct the one or more processors to perform operations including the following. Geomechanical properties for a well in a group of wells in a field are estimated using collected data and results from mini-fracking tests on previous wells. The estimates include in-situ stresses and maximum horizontal stress direction for the field. A prediction is determined for a discrete natural fracture network for the field, including predicting fracture geometries, orientations, and distributions for the group of wells. A three-dimensional (3D) geomechanics model is generated for the field based on 3D grid properties of the field and the discrete natural fracture network. 3D hydraulic fracturing modeling for fracturing a single well in the field is conducted to obtain an optimum pump schedule for a target fracture length and well spacing for placing numerous horizontal wells in the field. 3D hydraulic fracturing modeling for the group of wells is conducted based on a drilling-fracturing sequence configured to generate symmetric fractures and to determine an optimum pump schedule for middle wells in the group of wells considering tensile stress superposition, where the drilling-fracturing sequence includes initially skipping fracturing of a drilled well adjacent to a fractured well. The group of wells are drilled and fractured using the drilling-fracturing sequence.
The foregoing and other described implementations can each, optionally, include one or more of the following features:
A first feature, combinable with any of the following features, where the operations further include collecting data for the well, including collecting drilling reports, well surveys, formation tops, and wells logs.
A second feature, combinable with any of the previous or following features, where the operations further include performing image log processing for natural fracture orientations, fracture intensity, and for maximum horizontal stress orientation for the field.
A third feature, combinable with any of the previous or following features, where the 3D hydraulic fracturing modeling considers an injection volume for the single well.
A fourth feature, combinable with any of the previous or following features, where a fracturing order for the group of wells is different from a well numbering for the group of wells.
A fifth feature, combinable with any of the previous or following features, where an injection fluid volume for a middle well drilled last in a pad is reduced by a variable α.
A sixth feature, combinable with any of the previous or following features, where the variable α is a percentage reduction of the injection fluid volume for a first well from a pad.
Implementations of the subject matter and the functional operations described in this specification can be implemented in digital electronic circuitry, in tangibly embodied computer software or firmware, in computer hardware, including the structures disclosed in this specification and their structural equivalents, or in combinations of one or more of them. Software implementations of the described subject matter can be implemented as one or more computer programs. Each computer program can include one or more modules of computer program instructions encoded on a tangible, non-transitory, computer-readable computer-storage medium for execution by, or to control the operation of, data processing apparatus. Alternatively, or additionally, the program instructions can be encoded in/on an artificially generated propagated signal. For example, the signal can be a machine-generated electrical, optical, or electromagnetic signal that is generated to encode information for transmission to a suitable receiver apparatus for execution by a data processing apparatus. The computer-storage medium can be a machine-readable storage device, a machine-readable storage substrate, a random or serial access memory device, or a combination of computer-storage mediums.
The terms “data processing apparatus,” “computer,” and “electronic computer device” (or equivalent as understood by one of ordinary skill in the art) refer to data processing hardware. For example, a data processing apparatus can encompass all kinds of apparatuses, devices, and machines for processing data, including by way of example, a programmable processor, a computer, or multiple processors or computers. The apparatus can also include special purpose logic circuitry including, for example, a central processing unit (CPU), a field-programmable gate array (FPGA), or an application-specific integrated circuit (ASIC). In some implementations, the data processing apparatus or special purpose logic circuitry (or a combination of the data processing apparatus or special purpose logic circuitry) can be hardware- or software-based (or a combination of both hardware- and software-based). The apparatus can optionally include code that creates an execution environment for computer programs, for example, code that constitutes processor firmware, a protocol stack, a database management system, an operating system, or a combination of execution environments. The present disclosure contemplates the use of data processing apparatuses with or without conventional operating systems, such as LINUX, UNIX, WINDOWS, MAC OS, ANDROID, or TO S.
A computer program, which can also be referred to or described as a program, software, a software application, a module, a software module, a script, or code, can be written in any form of programming language. Programming languages can include, for example, compiled languages, interpreted languages, declarative languages, or procedural languages. Programs can be deployed in any form, including as stand-alone programs, modules, components, subroutines, or units for use in a computing environment. A computer program can, but need not, correspond to a file in a file system. A program can be stored in a portion of a file that holds other programs or data, for example, one or more scripts stored in a markup language document, in a single file dedicated to the program in question, or in multiple coordinated files storing one or more modules, sub-programs, or portions of code. A computer program can be deployed for execution on one computer or on multiple computers that are located, for example, at one site or distributed across multiple sites that are interconnected by a communication network. While portions of the programs illustrated in the various figures may be shown as individual modules that implement the various features and functionality through various objects, methods, or processes, the programs can instead include a number of sub-modules, third-party services, components, and libraries. Conversely, the features and functionality of various components can be combined into single components as appropriate. Thresholds used to make computational determinations can be statically, dynamically, or both statically and dynamically determined.
The methods, processes, or logic flows described in this specification can be performed by one or more programmable computers executing one or more computer programs to perform functions by operating on input data and generating output. The methods, processes, or logic flows can also be performed by, and apparatus can also be implemented as, special purpose logic circuitry, for example, a CPU, an FPGA, or an ASIC.
Computers suitable for the execution of a computer program can be based on one or more of general and special purpose microprocessors and other kinds of CPUs. The elements of a computer are a CPU for performing or executing instructions and one or more memory devices for storing instructions and data. Generally, a CPU can receive instructions and data from (and write data to) a memory.
Graphics processing units (GPUs) can also be used in combination with CPUs. The GPUs can provide specialized processing that occurs in parallel to processing performed by CPUs. The specialized processing can include artificial intelligence (AI) applications and processing, for example. GPUs can be used in GPU clusters or in multi-GPU computing.
A computer can include, or be operatively coupled to, one or more mass storage devices for storing data. In some implementations, a computer can receive data from, and transfer data to, the mass storage devices including, for example, magnetic, magneto-optical disks, or optical disks. Moreover, a computer can be embedded in another device, for example, a mobile telephone, a personal digital assistant (PDA), a mobile audio or video player, a game console, a global positioning system (GPS) receiver, or a portable storage device such as a universal serial bus (USB) flash drive.
Computer-readable media (transitory or non-transitory, as appropriate) suitable for storing computer program instructions and data can include all forms of permanent/non-permanent and volatile/non-volatile memory, media, and memory devices. Computer-readable media can include, for example, semiconductor memory devices such as random access memory (RAM), read-only memory (ROM), phase change memory (PRAM), static random access memory (SRAM), dynamic random access memory (DRAM), erasable programmable read-only memory (EPROM), electrically erasable programmable read-only memory (EEPROM), and flash memory devices. Computer-readable media can also include, for example, magnetic devices such as tape, cartridges, cassettes, and internal/removable disks. Computer-readable media can also include magneto-optical disks and optical memory devices and technologies including, for example, digital video disc (DVD), CD-ROM, DVD+/-R, DVD-RAM, DVD-ROM, HD-DVD, and BLU-RAY.
The memory can store various objects or data, including caches, classes, frameworks, applications, modules, backup data, jobs, web pages, web page templates, data structures, database tables, repositories, and dynamic information. Types of objects and data stored in memory can include parameters, variables, algorithms, instructions, rules, constraints, and references. Additionally, the memory can include logs, policies, security or access data, and reporting files. The processor and the memory can be supplemented by, or incorporated into, special purpose logic circuitry.
Implementations of the subject matter described in the present disclosure can be implemented on a computer having a display device for providing interaction with a user, including displaying information to (and receiving input from) the user. Types of display devices can include, for example, a cathode ray tube (CRT), a liquid crystal display (LCD), a light-emitting diode (LED), and a plasma monitor. Display devices can include a keyboard and pointing devices including, for example, a mouse, a trackball, or a trackpad. User input can also be provided to the computer through the use of a touchscreen, such as a tablet computer surface with pressure sensitivity or a multi-touch screen using capacitive or electric sensing. Other kinds of devices can be used to provide for interaction with a user, including to receive user feedback including, for example, sensory feedback including visual feedback, auditory feedback, or tactile feedback. Input from the user can be received in the form of acoustic, speech, or tactile input. In addition, a computer can interact with a user by sending documents to, and receiving documents from, a device that the user uses. For example, the computer can send web pages to a web browser on a user's client device in response to requests received from the web browser.
The term “graphical user interface,” or “GUI,” can be used in the singular or the plural to describe one or more graphical user interfaces and each of the displays of a particular graphical user interface. Therefore, a GUI can represent any graphical user interface, including, but not limited to, a web browser, a touch-screen, or a command line interface (CLI) that processes information and efficiently presents the information results to the user. In general, a GUI can include a plurality of user interface (UI) elements, some or all associated with a web browser, such as interactive fields, pull-down lists, and buttons. These and other UI elements can be related to or represent the functions of the web browser.
Implementations of the subject matter described in this specification can be implemented in a computing system that includes a back-end component, for example, as a data server, or that includes a middleware component, for example, an application server. Moreover, the computing system can include a front-end component, for example, a client computer having one or both of a graphical user interface or a Web browser through which a user can interact with the computer. The components of the system can be interconnected by any form or medium of wireline or wireless digital data communication (or a combination of data communication) in a communication network. Examples of communication networks include a local area network (LAN), a radio access network (RAN), a metropolitan area network (MAN), a wide area network (WAN), Worldwide Interoperability for Microwave Access (WIMAX), a wireless local area network (WLAN) (for example, using 802.11 a/b/g/n or 802.20 or a combination of protocols), all or a portion of the Internet, or any other communication system or systems at one or more locations (or a combination of communication networks). The network can communicate with, for example, Internet Protocol (IP) packets, frame relay frames, asynchronous transfer mode (ATM) cells, voice, video, data, or a combination of communication types between network addresses.
The computing system can include clients and servers. A client and server can generally be remote from each other and can typically interact through a communication network. The relationship of client and server can arise by virtue of computer programs running on the respective computers and having a client-server relationship.
Cluster file systems can be any file system type accessible from multiple servers for read and update. Locking or consistency tracking may not be necessary since the locking of exchange file system can be done at the application layer. Furthermore, Unicode data files can be different from non-Unicode data files.
While this specification contains many specific implementation details, these should not be construed as limitations on the scope of what may be claimed, but rather as descriptions of features that may be specific to particular implementations. Certain features that are described in this specification in the context of separate implementations can also be implemented, in combination, in a single implementation. Conversely, various features that are described in the context of a single implementation can also be implemented in multiple implementations, separately, or in any suitable sub-combination. Moreover, although previously described features may be described as acting in certain combinations and even initially claimed as such, one or more features from a claimed combination can, in some cases, be excised from the combination, and the claimed combination may be directed to a sub-combination or variation of a sub-combination.
Particular implementations of the subject matter have been described. Other implementations, alterations, and permutations of the described implementations are within the scope of the following claims as will be apparent to those skilled in the art. While operations are depicted in the drawings or claims in a particular order, this should not be understood as requiring that such operations be performed in the particular order shown or in sequential order, or that all illustrated operations be performed (some operations may be considered optional), to achieve desirable results. In certain circumstances, multitasking or parallel processing (or a combination of multitasking and parallel processing) may be advantageous and performed as deemed appropriate.
Moreover, the separation or integration of various system modules and components in the previously described implementations should not be understood as requiring such separation or integration in all implementations. It should be understood that the described program components and systems can generally be integrated together in a single software product or packaged into multiple software products.
Accordingly, the previously described example implementations do not define or constrain the present disclosure. Other changes, substitutions, and alterations are also possible without departing from the spirit and scope of the present disclosure.
Furthermore, any claimed implementation is considered to be applicable to at least a computer-implemented method; a non-transitory, computer-readable medium storing computer-readable instructions to perform the computer-implemented method; and a computer system including a computer memory interoperably coupled with a hardware processor configured to perform the computer-implemented method or the instructions stored on the non-transitory, computer-readable medium.

Claims

What is claimed is:

1. A computer-implemented method, comprising:

estimating, using collected data and results from mini-fracking tests on previous wells, geomechanical properties for a well in a group of wells in a field, including in-situ stresses and maximum horizontal stress direction for the field;

determining a prediction for a discrete natural fracture network for the field, including predicting fracture geometries, orientations, and distributions for the group of wells;

generating a three-dimensional (3D) geomechanics model for the field based on 3D grid properties of the field and the discrete natural fracture network;

conducting 3D hydraulic fracturing modeling for fracturing a single well in the field to obtain an optimum pump schedule for a target fracture length and well spacing for placing numerous horizontal wells in the field;

conducting 3D hydraulic fracturing modeling for the group of wells based on a drilling-fracturing sequence configured to generate symmetric fractures and to determine an optimum pump schedule for middle wells in the group of wells considering tensile stress superposition, wherein the drilling-fracturing sequence includes initially skipping fracturing of a drilled well adjacent to a fractured well; and

drilling and fracturing the group of wells using the drilling-fracturing sequence.

2. The computer-implemented method of claim 1, further comprising:

collecting data for the well, including collecting drilling reports, well surveys, formation tops, and wells logs.

3. The computer-implemented method of claim 1, further comprising:

performing image log processing for natural fracture orientations, fracture intensity, and for maximum horizontal stress orientation for the field.

4. The computer-implemented method of claim 1, wherein the 3D hydraulic fracturing modeling considers an injection volume for the single well.

5. The computer-implemented method of claim 1, wherein a fracturing order for the group of wells is different from a well numbering for the group of wells.

6. The computer-implemented method of claim 1, wherein an injection fluid volume for a middle well drilled last in a pad is reduced by a variable α.

7. The computer-implemented method of claim 6, wherein the variable α is a percentage reduction of the injection fluid volume for a first well from a pad.

8. The computer-implemented method of claim 7, wherein the injection fluid volume for a last well in the pad is given by (1−α)V, wherein α is a value in a range of 0.1 to 0.3, and wherein V is a volume of injection fluid for the first well in the pad.

9. A computer-implemented system, comprising:

one or more processors; and

a non-transitory computer-readable storage medium coupled to the one or more processors and storing programming instructions for execution by the one or more processors, the programming instructions instructing the one or more processors to perform operations comprising:

10. The computer-implemented system of claim 9, the operations further comprising:

11. The computer-implemented system of claim 9, the operations further comprising:

12. The computer-implemented system of claim 9, wherein the 3D hydraulic fracturing modeling considers an injection volume for the single well.

13. The computer-implemented system of claim 9, wherein a fracturing order for the group of wells is different from a well numbering for the group of wells.

14. The computer-implemented system of claim 9, wherein an injection fluid volume for a middle well drilled last in a pad is reduced by a variable α.

15. The computer-implemented system of claim 14, wherein the variable α is a percentage reduction of the injection fluid volume for a first well from a pad.