Design optimum frac jobs using virtual intelligence techniques

Unconventional completions in North America have seen a paradigm shift in volumes of proppant pumped since 2014. There is a clear noticeable trend in both oil prices and proppant volumes – thanks to low product and service costs that accompanied the oil price crash in early 2015. As the industry continues to recover, operators are reevaluating completion designs to understand if these proppant volumes are beyond what is optimal. This paper analyzes trends in completion sizes and types across all major unconventional oil and gas plays in the US since 2011 and tracks their impact on well productivity. Completion and production data since 2011 from more than 70,000 horizontal wells in seven major basins (Gulf Coast, Permian, Appalachian, Anadarko, Haynesville, Williston and Denver Julesburg basins) and 11 major oil/gas producing formations were analyzed to examine developments in proppant and fluid volumes. Average concentration of proppant per gallon of fluid pumped was used to understand transitional trends in fracturing fluid types with time. Production performance indicators such as First month, Best 3 or Best 12 months of oil and gas production were mapped against completion volumes to evaluate if there are added economic advantages to pumping larger designs. In general, all major basins have seen progressive improvements in average well performance since 2011, with the Permian Basin showing the highest improvement, increasing from an average first-six-months oil production of 25,000 bbl in 2011 to 75,000 bbl in 2017. The Gulf Coast basin, where the Eagle Ford formation is located, has seen a 6-fold increase in proppant volumes pumped per foot of lateral since 2011 while the Permian and Appalachian basins hit peak proppant volumes in 2015 and 2016 respectively. In Permian and Eagleford wells, higher proppant volumes in general have resulted in better production up to a certain concentration. In Williston and Denver basins, most operators are moving away from gelled fluids, and reduced average proppant concentration per fluid volume pumped shows inclination toward hybrid or slickwater designs. While some of these observations are tied to reservoir quality, proppant volumes have begun to peak as operators have either reached an optimal point or are in the process of reducing volumes. Demand for proppant is expected to nearly double by 2020. As oil prices continue to recover, well AFEs continue to increase, despite multiple efforts to improve capital efficiency. The need for enhanced fracture conductivity and extended half-lengths on EURs are been discussed by combining actual observed production data and sensitivities using calibrated production models. The industry is moving toward large-volume slickwater fracturing operations using smaller proppants, but he operating landscape is expected to see a correction when such designs become less economical.

Hydraulic fracturing technology is usually required to allow tight gas to escape from the low-permeability reservoir and flow through the wellbore to the surface. So far, there are no numerical tools in the petroleum industry which can optimize the whole process from geological modeling, hydraulic fracturing until production simulation with the same 3D model with consideration of the thermo-hydro-mechanical coupling. In addition, optimization design should be considered from the perspective of production, especially for multiple hydraulic fractures. Thus, the simulation of the production phase with created fractures in one model is very important for the optimization design. In this dissertation, a workflow and a numerical tool chain were developed for design and optimization of multistage hydraulic fracturing in horizontal well with regard to a maximum productivity of the tight gas wellbore. Frac-Simulator was developed to match the fracturing operation history automatically and optimize the hydraulic fracturing with consideration of thermal effect and gel-breaking. The temperature change will affect the fracture propagation process directly through the thermal stress as well as expansion or shrinkage. The temperature can also influence the fluid properties (gel breaking) as well. In order to maximize the productivity of the above mentioned tight gas wellbore, Frac-Produ Simulator was developed for the simulation of the gas production. The change of stress tensor ij and the fracture conductivity F CD during gas production are also taken into account. After the verification of the developed Simulators, a full 3D reservoir model is generated based on a real tight gas field in the North German Basin. After the history matching of the stimulation phase, the same 3D reservoir model is generated, including formations and the created fractures with their own fracture geometries and proppant concentration. The bottomhole pressure development derived from the measured treating pressure was used as input data for the stress sensitive reservoir simulation. Through analysis of simulation results, a new calculation formula of F CD was proposed, which takes the proppant position and concentration into account and can predict the gas production rate of each fracture more accurately. However, not only F CD but also proppant distribution and hydraulic connection of stimulated fractures to the well, geological structure and the interaction between fractures are determinant for the gas production volume of each fracture. Hence, the relationship between gas production rates from each fracture in the later production is different from that at the beginning. For the sensitivity analysis numerical simulations were carried out with different design parameters, including proppant type, viscosity of the injection fluid and injection time. The results show that the influences of proppant type on fracture geometry and fracture conductivity is much larger than that of the viscosity of the injection fluid, while the influences of the injection time are the smallest. For the optimal fracture treatment design different numerical simulations with varied fracture number/spacing and treatment schedule were performed. The results show that the injection rate is not the higher the better. If it is too high, the fracture width will become wider and the proppant will settle down easier to the bottom, which leads to insufficient hydraulic connection between fracture and wellbore. The fracture spacing should also not be too small, otherwise the influence area/drainage radius is not enough. Thus, there is no unique criterion to determine the optimal number and spacing of the fractures, it should be analyzed firstly in detail to the actual situation and decided then from case to case.

Background: The ongoing shortage of natural gas in the country necessitates enhanced efficiency in gas field development. Alongside domestic gas consumption, the demand for higher production volumes, particularly from low-permeability reservoirs, further emphasizes the relevance of this study. Aim: To optimize the production in fields with low-permeability reservoirs through proppant hydraulic fracturing (HF) to increase the permeability of formations and improve well productivity. Materials and methods: The study’s object is the gas condensate field X, located in the Moyynkum trough of the Shu-Sarysu depression in the Zhambyl region. During the study, a comprehensive analysis was conducted on the efficiency of refracturing operations, with a specific focus on proppant tonnage. As a result, a methodology for optimizing the parameters of refracturing was proposed. This methodology involves adjusting the volume of injected proppant to alter the geometry of fractures and enhance well productivity. Furthermore, a novel approach to adapting hydraulic fracturing techniques for conditions with a high risk of fluid accumulation in the wellbore has been developed. Unlike conventional solutions, this approach introduces a comprehensive production stabilization strategy that incorporates mechanized fluid removal methods, such as coiled tubing, foam-inhibiting check valves, and plunger elevators. Results: It was determined that maintaining the initial injection volume during repeated HF operations does not significantly enhance the gas flow rate. An analysis of the post-fracturing data confirmed the effectiveness of the applied strategy, as evidenced by changes in the gas-condensate factor and the stabilization of flow rates. Additionally, soluble fibers were utilized for the first time in some wells during the HF process. The analysis indicated that their application yielded positive outcomes, including improved fracture conductivity and increased well productivity, suggesting that this technology holds promise for future implementation. Conclusion: The findings of the study indicate that it yields higher gas production gains compared to refracturing. This highlights the significance of precise timing and careful selection of proppant volume to optimize the effectiveness of refracturing. In the X field, HF continues to be a crucial intervention for enhancing the productivity of new wells. It is advisable to conduct pre- and post-operation pressure recovery curve analyses to monitor impacts and refine the technology used. Considering the reservoir characteristics and potential pressure interferences, the operation’s design and the proppant volume must be meticulously planned to achieve the best possible outcomes.

SummaryPerforming hydraulic fractures on gas storage wells to improve their deliverability is a common practice in the eastern part of the U.S. Most fields used for storage in this region are old, and the reservoir characteristic data necessary for most reservoir studies and hydraulic fracture design and evaluation are scarce. This paper introduces a new method by which parameters that influence the response of gas storage wells to hydraulic fracturing may be identified in the absence of sufficient reservoir data. Control and manipulation of these parameters, once identified correctly, could enhance the outcome of frac jobs in gas storage fields. We conducted the study on a gas storage field in the Clinton formation of northeastern Ohio. We found that well-performance indicators before a hydraulic fracture play an important role in how good the well will respond to a new frac job. We also identified several other important factors.The identification of controlling parameters serves as a foundation for improved frac job design in the fields where adequate engineering data are not available. Another application of this type of study could be the enhancement of selection criteria among the candidate wells for hydraulic fracturing. To achieve the objective of this study, we designed, trained, and applied an artificial neural network. The paper will discuss the results of the incorporation of this new technology in hydraulic fracture design and evaluation.

The understanding of proppant flow through fractures is critical in evaluating the hydraulic fracturing performance. As a continuation of our experimental efforts devoted to understanding how proppant flows in rough vertical fractures, in this paper, we examine the effect of injection parameters on the proppant transport in rough vertical fractures. The effects of polymer concentration, injection rate, proppant concentration, and type of proppant were investigated in detail. Experimental results show that a sufficiently high polymer concentration is needed to enable effective proppant flow in rough fractures. In general, the relative coverage of proppants increased dramatically as the polymer concentration increased, implying that the higher viscosity of fracturing fluid could enhance the slurry's ability to place more proppant vertically into the fracture and help to maintain a better conductivity after fracturing treatment. A sufficiently high injection rate of the slurry is also needed to enable effective proppant flow in rough fractures. At certain low injection rate, the proppants carried by a low polymer solution might not exhibit a tree-like settling pattern, diminishing the effect of roughness effect on the proppant transport. This means that even in rough fractures, the tree-like settling pattern of the proppants did not necessarily occur for sure; the injection rate should be properly selected to enable such phenomenon. With other condition being kept constant, a higher proppant loading led to a higher final relative coverage of the proppants in the rough fractures. But if the injection rate used for delivering the proppants is not sufficiently high, we may encounter injectivity issues; in our lab experiments, this caused the choking of the pump. The heavier proppant (ceramic proppants) in the rough fracture models tended to suppress the tree-like settling pattern that was experienced by the lighter proppant (silica sands). This is attributed to the larger density of the ceramic proppants, leading to a larger settling velocity. In order to maximize the spreading of a given proppant over a rough fracture model, we should determine the proper values of all the essential injection parameters (including polymer solution, injection rate, proppant concentration) by striking a good balance among them. The conclusions obtained in this study shed light on how to optimize slurry injection parameters to achieve an optimal proppant-filling ratio during hydraulic fracturing.

_ Since approximately 2012, large multistage completions in horizontal wells have significantly boosted oil production in the Bakken Formation. As of the time of writing, more than 18,000 stimulated wells have been completed in Bakken using various completion designs. Operators have experimented with well spacing, as well as the size and intensity of stimulation jobs by injecting increasingly large volumes of fluid and proppant to maximize oil production while minimizing costs. However, wells that received larger treatments did not always perform as expected. Furthermore, the aggregated impact of various interrelated completion design parameters and reservoir characteristics was not fully understood, leaving room for improvement in completion optimization evaluations. Publicly accessible completion and production data, meticulously collected by the North Dakota Industrial Commission (NDIC), combined with advancements in data science, have created an excellent opportunity to optimize drilling and completion strategies using statistical data analysis and predictive modeling. Observations and experiences from thousands of producing Bakken wells can now be analyzed and interpreted using data mining techniques. This article presents examples of data science applications in completion optimization calculations in Bakken production. Completion Design Optimization Using Predictive Modeling The initial optimization study analyzed drilling and completion results from more than 12,000 oil-producing wells across the Bakken in North Dakota using 2020 data (URTeC 3723843). Simple interpretations of the relationship between production performance and completion parameters, based on bivariate (two-dimensional) scatterplots, proved challenging due to the nonlinear nature of these dependencies. Data-mining techniques capable of accommodating nonlinear relationships and complex, incomplete information were applied to identify optimal completion practices. The dataset used in this analysis included eight publicly available completion design parameters: 1. Perforated interval 2. Injected fluid volume 3. Proppant amount 4. Stage count 5. Injection rate 6. Injection pressure 7. Proppant type 8. Completion type These parameters were used to predict well performance, measured by cumulative 6-month oil production. Predictive modeling was performed using the gradient boosting (GB) data-mining tool, in which multiple decision trees described the variability of the multidimensional dataset. The initial predictive modeling conducted for the entire Bakken play demonstrated acceptable performance for the training model (evaluated by R²), but the test model—using 20% of all data—showed weaker performance. This phenomenon, known as overfitting, occurred when a single statistical model struggled to accurately predict well production performance across various Bakken locations which are characterized by heterogeneous geology and reservoir properties.

There have been various observations about the merits of increasing the proppant volume during hydraulic fracturing of source rocks. A general recommendation has been that larger proppant volumes can help in maintaining fracture flow capacity. In this study, we present data on actual cases related to more than 104 wells producing from the Bakken formation. Two parameters of interest were used as measures of well productivity. First was the average initial flow rate of the well, represented by the cumulative production during the first three months, and then was the production decline represented by the cumulative volume of oil produced in 180 days. Both of these parameters were tested as a function of corresponding sand/liquid ratios for similar completion practices and in the same reservoir. In all cases, we observed an an optimum value for the proppant liquid ratio related to the best case scenarios. Beyond that optimal ratio, the well performance show a deterioration. We attribute this to an overall reduction in fracture conductivity caused by packing of fractures, potential proppant plugging and slurry dehydration under excessive proppants placement.

The Marcellus Shale play has attracted much attention in recent years. Our full understanding of the complexities of the flow mechanism in matrix, sorption process and flow behavior in complex fracture system (natural and hydraulic) still has a long way to go in this prolific and hydrocarbon rich formation. In this paper, we present and discuss a novel approach to modeling and history matching of hydrocarbon production from a Marcellus shale asset in southwestern Pennsylvania using advanced data mining & pattern recognition technologies. In this new approach instead of imposing our understanding of the flow mechanism, the impact of multi-stage hydraulic fractures, and the production process on the reservoir model, we allow the production history, well log, and hydraulic fracturing data to force their will on our model and determine its behavior. The uniqueness of this technique is that it incorporates the so-called "hard data" directly into the reservoir model, such that the model can be used to optimize the hydraulic fracture process. The "hard data" refers to field measurements during the hydraulic fracturing process such as fluid and proppant type and amount, injection pressure and rate as well as proppant concentration. The study focuses on part of Marcellus shale including 135 wells with multiple pads, different landing targets, well length and reservoir properties. The full-field history matching process was completed successfully. Artificial Intelligence (AI)-based model proved its capability in capturing the production behavior with acceptable accuracy for individual wells and for the entire field.

Summary Mud rock “shales” by their very nature can be problematic to fracture stimulate given the wide variation in geology, rock properties and reservoir characteristics. Quite often, a positive production response from a well may be incorrectly credited to the completion and frac design when in reality the production was dominated by favorable reservoir characteristics. Conversely a poor production response from a well may be blamed on the completion and frac design when in fact poor reservoir quality is the controlling factor. The subject of this paper is a revisit of the physics behind production increases from hydraulic fracturing and results from detailed evaluations performed by experienced engineers with reservoir knowledge for the purpose of evaluating completion effectiveness and frac efficiency for shale and other low permeability formations. The findings presented show that in many cases pumping large volume sand frac designs result in an inefficient hydraulic fracture. This inefficiency is due to minimal production contribution from a relatively large portion of the hydraulically exposed fracture face and/or frac length. These findings are supported by current hydraulic fracturing theory and understanding. The evaluation methods utilized in these evaluations are not new, however they currently are underutilized by the industry for completion and frac analysis.

Mud rock “shales” by their very nature can be problematic to fracture stimulate given the wide variation in geology, rock properties and reservoir characteristics. Quite often, a positive production response from a well may be incorrectly credited to the completion and frac design when in reality the production was dominated by favorable reservoir characteristics. Conversely a poor production response from a well may be blamed on the completion and frac design when in fact poor reservoir quality is the controlling factor. The subject of this paper is a revisit of the physics behind production increases from hydraulic fracturing and results from detailed evaluations performed by experienced engineers with reservoir knowledge for the purpose of evaluating completion effectiveness and frac efficiency for shale and other low permeability formations. The findings presented show that in many cases pumping large volume sand frac designs result in an inefficient hydraulic fracture. This inefficiency is due to minimal production contribution from a relatively large portion of the hydraulically exposed fracture face and/or frac length. These findings are supported by current hydraulic fracturing theory and understanding. The evaluation methods utilized in these evaluations are not new, however they currently are under-utilized by the industry for completion and frac analysis.

It is an established fact that the Canyon Sand Formation in the Val Verde Basin must be fracture stimulated to exploit the reservoir's potential. However, in the past, the degree of stimulation required has been a judgement call at best. Due to recent results from an industry consortium dealing with conductivity, it became obvious that many past stimulation designs were inadequate. Changes in fracturing fluids, as well as proppant selection, concentration, and placement, have led to an improved design. Past treatments were insufficient in fracture half-length and conductivity. These treatments have now been modified to double the fracture half-length, and to increase the conductivity six-fold. These design changes are necessary to overcome fluid damage and long-term conductivity deterioration. Computer simulated fracturing programs have been used to develop improved designs. When implemented in the field, these designs have proven to increase profitability through post-frac production results. Although previously reported laboratory work has addressed the topic of in-situ fracture conductivity, these findings were not substantiated with actual production results. Therefore, a case study of twenty four wells located in Sutton County, Texas was performed to determine the actual effect of fracturing fluid type on well performance. A comparison of post-frac well production indicates that different fracturing fluids can dramatically effect a well's producibility. This case study supports the consortium's findings, that different fracturing fluid types create varying levels of permeability impairment.

The application of MHFHW (multistage hydraulic fracturing horizontal well) enormously contributes to the dramatic increasing production of low permeability reservoir. Geomechanics is the key factor for fractured well by influencing SRV (stimulated reservoir volume) and post-stimulation production. Stress variation and distribution characteristics along with real-time fracturing are simulated based on 4D (four-dimension) geomechanics research, providing the effective technical support for the designing and optimization of hydraulic fracturing scheme to get larger SRV and higher post-stimulation production. 1D (one-dimension) geomechanics model is firstly built using data from drilling, mud log, well log, mini fracture and well testing, and then verified by comparing with drilling events and laboratory test of core samples. Furthermore, Project team combines 1D geomechanics model with additional data including 3D structural model, fault distribution and seismic data to achieve the regional 3D (three-dimension) geomechanics model. 3D Geomechanics model only represents the original stress field that before hydraulic fracturing, which will be changed by pumping massive fracturing fluids into reservoir. 3D geomechanics model study is integrated with the data from real-time fracturing and micro- seismic monitoring to generate 4D geomechanics model, enabling the characterization of variation of geomechanics model with real-time fracturing. 4D Geomechanical research result clearly characterizes the stress model variation and reduces the uncertainties in reservoir stimulation operation. The model helps to optimize pressure pumping rate, volume of proppant and fracturing fluids, eventually maximizes the increase of fracture flow conductivity and post-stimulation production., This case study discusses the multi-stages fracturing treatment scheme optimization of horizontal well H84001 based on the 4D Geomechanical research of this low permeability reservoir. H84001 production has improved 184.2% compared with the offset well without fracturing treatment optimization. This project established the mathematical relationships between reservoir deformation and strain, upgrading geomechanical study methods from static to dynamic. The research finding provides technical guidance to develop low permeability reservoir in an economical and efficiency stimulation scheme.

The impacts of the fluid type and stress shadow on proppant transport during hydraulic fracturing in a Marcellus shale horizontal well with multiple hydraulic fracture stages were investigated. The available data from a Marcellus Shale horizontal well were utilized to determine the hydraulic fracture properties and to develop a reservoir model. The reliability of the model was confirmed by the close agreement between the predicted production by the model and the well production data. The impact of fluid type and stage spacing on proppant transport during hydraulic fracturing and gas production from Marcellus shale horizontal well were then investigated by employing the reservoir models. Slickwater, compared to crosslinked gels and high viscosity friction reducers (HVFRs), is more efficient in horizontal Marcellus shale wells that are fractured in multiple stages. The application of the HVFRs and crosslinked gels resulted in fracture height growth out of the pay zone. While the use of slickwater directed all stimulation energy towards the pay zone and resulted in improved hydraulic fracture properties in the Marcellus shale and lead to high gas recovery. INTRODUCTION The advancements in horizontal drilling and hydraulic fracturing technologies have made shale production a reality for the past decade. With the technical and economical limitations posed by hydraulic fracturing operations in unconventional reservoirs, it is imperative to create an optimized fracturing design to achieve economic production. A number of treatment design considerations including the type of fluid, proppant type and size, and the additives must be evaluated to achieve successful well stimulation results. In general, proppant transport is dependent on proppant size, density, and type; fluid rheology; temperature changes; pumping rate, among others. The fracturing fluid should be compatible with the formation and promote the increase in the stimulated volume. In order to transport the proppants deep into the fracture, the fluid should be capable of keeping the proppants suspended. With an inherent viscosity, fluid should be able to develop the necessary fracture width to accept proppants. Also, it should have low friction pressure loss and sufficient stability to retain its viscosity throughout the treatment and finally, it should be easy to remove after the treatment. The type of fluid used therefore has pronounced impact on the transport of proppants and the properties of the created hydraulic fracture and consequently the hydrocarbon production. Proppant selection is a contributing factor in the dimensions of a propagating fracture. The most prevalent hydraulic fracturing treatment fluids in shale formations is slickwater with no significant amount of thickening agent. The application of this low viscosity fluid system contradicts conventional fracturing theory. However, slickwater is the preferable fracturing fluid in shale because of its cost-effectiveness and low potential for damaging the shale. In addition, slickwater has the potential to prevent high fracture height growth leading to better fracture containment within the pay zone.

Horizontal well drilling and hydraulic fracturing have become the enabling technologies for unconventional reservoir development. From tight gas, to oil and gas-producing shales and coal bed methane, all these resources rely on hydraulic fracturing for its commercial viability. The primary goal of the completion in these ultra-low permeability formations is to provide a conductive path to contact as much rock as possible, through the use of multistage hydraulic fractures along a horizontal lateral. Reservoir contact is optimized by defining the extent of the lateral length, the number of stages to be placed in the lateral, the fracture placement technique and job size. Fracture conductivity is determined by the proppant type and size, fracturing fluid system as well as the placement technique.While most parameters are considered in great detail in the completion design, the fracture conductivity receives lesser attention. On one side many feel that in extremely low permeability formations hydraulic fractures act as ‘infinitely conductive features’, even with minimal conductivity. On another side many factors that affect the effective conductivity acting in the hydraulic fracture are poorly understood or overlooked. This can lead to a disappointing outcome with wells producing below the reservoir potential.This paper presents a technique to assess the realistic fracture conductivity at downhole conditions, describe the relationship between conductivity and productivity and its economic implications in proppant selection. The effects of transverse fractures, low areal proppant concentration and flow dynamics, are also considered among other variables.Fracture modeling and actual field results will be presented to illustrate the optimization process. The case histories included in the paper show the successful implementation of this method in shale gas and liquids rich formations.

Geophysical well logs, petrographic thin section core analyses, and production- and pressure-decline curve analyses were used to pressure-decline curve analyses were used to characterize the geology and to estimate the reserves, recovery, and well life of the East Canton oilfield, northeastern Ohio. Clean sand sections of the Clinton were found to contain an average of 95 percent quartz and less than 4 percent clay. These sections correlated with the 80-percent-sand line determined by gamma ray logs and with core permeabilities averaging more than 0.1 permeabilities averaging more than 0.1 millidarcy. Production was found to be more closely related to thickness of 80 percent sand than any other reservoir characteristic. Economic life and output of the wells studied are predicted to be approximately 10 years and about 30,000 to 40,000 barrels per well. A primary recovery factor of 9 to 12 percent is indicated. Primary reserves of the 60,000-acre field are a minimum of 51 million barrels. Approximately 500 additional wells will have to be drilled to complete development of the field. With such a low primary oil-recovery factor, much oil will remain for secondary recovery possibilities. Introduction The East Canton oilfield is one of the largest in the Appalachian Basin (Fig. 1) and contains important primary and secondary oil reserves. The reservoir has low porosity and permeability, and hydraulic fracturing is permeability, and hydraulic fracturing is needed to stimulate wells to economic production. More than 60,000 acres of proved production. More than 60,000 acres of proved production are available with more than 1,000 production are available with more than 1,000 wells, and there are infill locations for at least 500 more. Over 14 million barrels of oil have been extracted from the field, and current production is 10,000 to 11,000 barrels per day. The Bureau of Mines undertook these per day. The Bureau of Mines undertook these studies to obtain information for possible secondary recovery considerations in this field. Reservoir and production characteristics of this field have never been clearly understood, however, and such information is essential to productivity predictions and maximum recovery. productivity predictions and maximum recovery. Geological and reservoir studies were made in an effort to obtain this information. Techniques and methods utilized included pressure buildup tests, PVT bottom-hole sample test, production decline and pressure decline production decline and pressure decline analyses, and correlation of geophysical well log data with oil production data from over 100 wells.