Amount Of Proppant Research Articles

Analysis of the Difference between Hydraulic Fracturing and Flow Channel Fracturing

As time goes by, there will be a decline in formation productivity, as reflected in the decline in the rate of oil production from production wells. The decline in the rate of production was caused by many things such as a decrease in reservoir pressure, also formation damage. Where damage to the formation will result in a decrease in rock permeability. The decrease in rock permeability is caused by the blockage of rock pores due to the invasion of solids and drill mud filtrate, cementing, fluid fluids or previous stimulation. Besides the small rate of oil production can also be caused by the low natural permeability of rocks. With the decreasing productivity of the formation, it is necessary to make efforts to increase the productivity of the formation again, where one of them is by the method of hydraulic fracture stimulation. In this analysis, we will discuss the difference between conventional stimulation methods and flow channel fracturing. Flow channel fracturing is a fracturing process by making a network around proppant granules to form proppant pillar, so that a path is formed for the fluid to flow more easily. What distinguishes between conventional hydraulic fracturing with flow channel fracturing is the resulting fracture form, fracturing fluid injection pattern, and the amount of proppant used.

Probability-Statistical Models to Forecast Hydraulic Fracturing Efficiency

The article discusses the criteria for choosing fracture parameters by length, height and amount of proppant to be injected. The criteria, chosen on the basis of for probabilistic and statistical analysis are to ensure adequate application of multiand single-stage hydraulic fracturing technique. The statistical indicators analysis of the multistage hydraulic fracturing application on the AS12-3 horizon made it possible to clarify the ranges of main hydraulic fractures parameters in terms of their length, volume, number of fractures and the weight of the injected proppant.

Fine calculation method for fracture morphology based on microseismic events and its application

AbstractMicroseismic monitoring is an effective method to interpret the morphological parameters of artificial fractures (length, height, and orientation), which is the key to the design of hydraulic fracturing. It is difficult to recognize effective fracture shape after fracturing by using microseismic monitoring data only, which results in a very confusing interpretation of fracture morphology that is quite different from reality. Therefore, in this study, we propose an innovative classification method based on the principal component analysis theory combined with fracturing operation parameters (proppant amount and volume) and derived theoretical formulas for calculating the correction coefficients (volume, length, and height) to optimize and describe fracture patterns finely. By applying 36 wells in Qie‐6 block of the Qinghai Oilfield, the microseismic monitoring events were identified, and the fracture morphology and effective stimulated reservoir volume (ESRV) were corrected. This method is a reliable technology for the interpretation of fracture morphology for field hydraulic fracturing construction.

Unlocking well productivity drivers in Eagle Ford and Utica unconventional resources through data analytics

North America's unconventional resources are viewed as statistical plays because of the wide variability in the performance of hydraulically fractured wells. Attempts to unlock the primary drivers of productivity yield different interpretations because of the over-parameterized stimulation processes, diverse geoscience concepts and non-unique solutions of associated reservoir flow modeling. An opportunity to derive insights on the yet-to-be fully understood flow mechanisms lies in the interrogation of acquired stimulation and production data. In search of causation relationships, a data analytics approach was used to profile and associate well productivity with multiple hydraulic fracturing stimulation parameters for Eagle Ford and Utica horizontal wells in areas with similar geological settings. Data for the study was retrieved from public-accessible databases managed by the Rail Road Commission of Texas, Department of Natural Resources of Ohio and Chemical Disclosure Registry of FracFocus. Results from the approach show multiple apparent causal relationships between production and stimulation parameters with the latter evolving in tandem. As a result, a priori knowledge was incorporated in decoupling dependencies for sole contributions of parameters. Among the most critical trends, the amount of proppant and fracturing fluid volume correlated with productivity. The average proppant concentration, used to decouple this association, correlated poorly with cumulative hydrocarbon production. Better performing wells in which the amount of proppant was high coincidentally had been stimulated with large amounts of fracturing fluid; thus, motivating the latter to be interpreted as a primary driver for Eagle Ford and Utica production enhancement. It was speculated that the induced hydraulic fracture length is effective; thus, use of large amounts of high quality proppant to create conductive fractures might be yielding limited value. Additional results provided insights on interdependences between injected proppant, lateral length, fracturing stages, perforation clusters and fracturing fluid volume. The identification of stimulation parameters that correlated with well productivity provided ground for speculating that unconventional resources are not statistical as portrayed and repeatable well performance can be realized if stimulation operations are systematically constrained. Further reflection on the results backed postulations on attributes of reservoir flow physics such as matrix permeability, fracture conductivity and effective fracture length. In conclusion, data analytics shed light on dominant productivity drivers in the subject unconventional resources and provided ground for hypotheses that will improve knowledge-driven simulation models.

A Unified Approach To Optimize Fracture Design of a Horizontal Well Intercepted by Primary- and Secondary-Fracture Networks

Summary The classical optimization design dependent on a single-fracture (SF) assumption is widely applied in performance optimization for hydraulically fractured wells. The objective of this paper is to extend the optimal design to a complex fracture network to achieve the maximum productivity index (PI). In this work, we established a pseudosteady-state (PSS) productivity model of a fractured horizontal well, which has the flexibility of accounting for the complexity of fracture-network dimensions. A semianalytical solution was then presented in the generalized matrix format through coupling reservoir- and fracture-flowing systems. Subsequently, several published studies on the PSS productivity calculation of a SF were used to verify this model, and a 3D transient numerical simulation of an orthogonal fracture network was used to perform further verification. We show that results from our solutions agree very well with those benchmarked results. On the basis of the model, we provide a detailed analysis on the productivity enhancement of the fracture-network/optimization work flow using unified fracture design (UFD). The results show the following: The PI is determined by fracture conductivity and complexity (network size, spacing, and configuration), and it is a function of fracture complexity and conductivity when the influence of proppant volume is not considered. Under the constraint of a given amount of proppant known as UFD, the maximum PI would be achieved when the best balance between network complexity and conductivity was obtained. It is more advantageous to minimize fracture complexity by creating relatively simple-geometry fractures with smaller network size and larger fracture spacing in the condition of small and intermediate proppant numbers. It should be the design goal to generate a complex network by creating relatively complex-geometry fractures with larger network size and smaller fracture spacing in the condition of a large proppant number. Increasing fracture complexity could reduce the optimal requirement of fracture conductivity. The proposed approach can provide guidance for a network-hydraulic-fracturing design for an optimal completion.

Stimulation for geothermal wells in the Netherlands

Abstract Hydraulic fracturing is a long-established method of stimulating a well to improve the inflow or outflow potential. Hydraulic fracturing is the most successful stimulation method used by the oil and gas industry, and is also used for water injection and production wells around the world, even for drinking-water wells. Hydraulic fracturing creates a crack in the earth that is then filled with a highly conductive material (proppant). This fracture has a large inflow area compared to an unstimulated wellbore and provides a high-permeability path for the fluid to flow in or out of the reservoir. Hydraulic fracturing has a long history of being used in hot dry rock (HDR) geothermal applications since the 1980s (Murphy & Fehler, 1986). In those often very tight reservoirs, the aim is to create fracture networks that generate the reservoir flow capacity. In high-permeability formations, fracturing can potentially double the productivity of a well. In low-permeability formations, well performance can be increased by a factor of 5–10 in most cases. In this paper, we focus on two different scenarios of geothermal stimulation. The first is for permeable, porous formations where the heat exchange happens through the perfect contact between the fluid and the porous reservoir. Stimulation may then be necessary to create a small fracture if the pressure drop near the well is too large due to insufficient reservoir permeability. The other scenario is a formation at great depth, where the formation permeability is so extremely small that very long propped fractures would be needed to obtain sufficient flow or even where the porous system does not provide sufficient heat exchange but the heat exchange has to be facilitated by an artificial or stimulated fracture network: a so-called Enhanced Geothermal System. For porous, permeable formations we will present examples of fracture treatments that can increase the flow rate so that the economics of the project is improved. In some formations, stimulation is then a contingency in case of poorer than expected reservoir quality. A worst-case well with a large skin value of 20 can perform with stimulation like a base-case unstimulated well. In other formations, stimulation will be integral to well design in order to optimise the project performance. For those cases the Coefficient of Performance can be improved from 7 to 25 with the aid of stimulation. In Ultra-Deep Geothermal (UDG) recovery, the targets are reservoirs below 4000 m, because industrial heat demand requires a minimum temperature of 120°C up to 250°C. For an economic business case, the rate over a period of 15 to 25 years should be from 150 to 450 m3 h−1, depending on the boundary conditions. Shallower reservoirs in the Netherlands often show very high permeability, but at great depth the target layers could have very low permeability (Veldkamp et al., 2018). Several stimulation methods can be used, of which hydraulic fracture stimulation with water (proppantless) is the primary candidate. Other stimulation methods are propped fracturing in sandstone, acid fracturing in carbonates and thermal stimulation. For a geological play that is attractive for UDG in the Netherlands, the most likely stimulation method is with water fracturing, because propped fracturing would require a huge amount of proppant that is very costly. Based on analogues and conceptual designs, the expected flow rate is estimated under selected boundary conditions.

Next Generation Reservoir Engineering

We present a fundamental physics based understanding of the chemical, mechanical, thermal and hydrological processes and their interactions that operate over long-time scales to form and characterise the porosity/fracture networks in conventional and unconventional oil and gas reservoirs. We apply that understanding to engineer that structure for the purpose of energy extraction and resource discovery. The interdisciplinary approach links geoscience, engineering and computational science disciplines with the result of providing a step change in exploration and exploitation technologies with significant reduction in onshore gas development costs without compromising OHSE or environmental protection and assurance. In this presentation, we will show the first results that allow incorporation of important processes in Unconventional Plays. Surprisingly, diagenetic processes such as the smectite-illite transition are found to create natural fractures under tectonic load that form the permeable reservoirs in Shale Gas/Oil Reservoirs. Results indicate that the fractures triggered by natural fluid release reaction on geological time scales are supported by a critical fluid pressure that must not be crossed to avoid sudden loss of the reservoir. Upon crossing this threshold reservoir damage can be substantial. No amount of proppant or other engineering interaction can rescue the reservoir on a human time-scale. Our novel framework allows to link the long-time scale geological processes with the design of an injection-extraction protocol to maintain critical fluid pressure. We are also able to incorporate micro-structural changes and fluid-solid interaction at grain scale. The latter has only been benchmarked for conventional carbonate plays, but the Multiscale results are encouraging for the entire spectrum of conventional and unconventional traps/source rocks. Our theoretical framework and the forward simulator is specifically designed to interface with geophysical inversion techniques for multi-scale geophysical data. Completing this data-assimilation step in the future will define Next Generation Reservoir Engineering.

Modeling of quantifying proppants for stimulation reservoir volume fracturing in a shale hydrocarbon reservoir

Massive hydraulic fracturing (MHF) technology is widely used to increase the stimulation reservoir volumes in the development of shale hydrocarbon reservoirs by pumping large amounts of fracturing fluids and proppants at a high injection rate. However, fresh water dissipation and the flowback fluid pollution created by this technology brings serious environmental problems. Moreover, the post-production of MHF is uncertain and some fractured wells keep a low production level all the time. It is therefore necessary to find an economical treatment size to satisfy the actual geology position of shale reservoirs, such as mountainous and water shortage regions. The amount of proppant for MHF are a key parameter of treatment size, which also effect the volume of fracturing fluids and injection rate directly. A proppant quantifying model for MHF in a shale hydrocarbon reservoir was developed. In this model, the complex fracture network was characterized as the enhanced permeability area (EPA), and then a correlation was built between the amount of proppants and the EPA based on the Warren–Root model. When the EPA parameters were optimized by a reservoir simulator according to the post-production and net present value, the optimum volume of proppants for a specific shale well can be obtained easily. The new model has been applied at the first horizontal well in Jianghan shale oil field and three horizontal and eighteen vertical wells in Western Sichuan shale gas field successfully. Compared with the results of the early empirical design method used in Western Sichuan, this approach shows a better post-production.

Transient pressure analysis of horizontal well with nonorthogonal transverse fractures and drainage volume characterization using Fast Marching Method

Horizontal well drilling and multistage hydraulic fracturing are essential to economic recovery of unconventional tight/shale reservoirs. Multiple transverse fractures are ideally supposed to be perpendicular to the minimum stress direction, but nonorthogonal transverse fractures might be seen in practice, which might bring a better connection between wellbore and fractures. However, for the same fracture half-length, the stimulated reservoir area might be less. Thus, the well performance with these nonorthogonal transverse fractures is full of uncertainty. Little research work is currently conducted on the nonorthogonal transverse fracture scenario.Our transient pressure analysis of horizontal well performance with nonorthogonal transverse hydraulic fractures utilizes the concept of rate-normalized pressure and transient productivity index. The novel Fast Marching Method (FMM) is adopted to characterize the drainage volume evolution for multi-stage horizontal wells and validate the proposed methodology. Sensitivity studies contrast transient pressure behavior and productivity index for azimuth angles from 15 to 90°, e.g. from nearly longitudinal to truly transverse fracture angles. Additionally, transient pressure behavior and long-term reservoir performance of horizontal well for different scenarios are investigated, such as reservoir anisotropy and different proppant allocation strategies under the constraints of given horizontal well spacing and total proppant amount.Contrast to what we are usually expecting, results show that for the same fracture spacing, and the same total proppant amount, the well with nonorthogonal transverse fractures will have a higher productivity index than that for truly transverse fractures. Different from productivity index, the long-term reservoir performance, however, turns out to play a different game, given specific horizontal well spacing and the same total proppant amount. Reservoir performance for horizontal well with nonorthogonal transverse fractures can be significantly improved by optimally allocating the proppant and designing hydraulic fracture placement strategies through this research.

PERFORMANCE OF THE VARIABLE CONDUCTIVITY DAMAGED FRACTURE AND FRACTURE OPTIMIZATION

The article presents the results of the variable or non-uniform conductivity (width, permeability or both profiles) in the fracture. This allows predict performance of damaged fracture, and so on. Usage the average conductivity of fractures to represent an equivalent constant value has shown that it works well for high conductivity, reduces conduction (i.e ellipsoidal or wedge-shaped fractures) with maximum conductivity in the wellbore. For inverted wedge cracks (conductivity in the well is less than an average) the fracture efficiency will be significantly reduced, and the average conductivity will greatly overestimate the effective value. Moreover, for low-conductivity fractures in the well the equivalent conductivity is weighed more relative to the value of the well than the average. Also the article presents the optimal conductivity of fractures (and fracture sizes) for a given amount of proppant to maximize productivity.

Bed load proppant transport during slickwater hydraulic fracturing: Insights from comparisons between published laboratory data and correlations for sediment and pipeline slurry transport

Bed load transport is the movement of particles along the top of a bed through rolling, saltation, and suspension created by turbulent lift above the bed surface. Based on experimental work, early investigators suggested that bed load transport may be an important mechanism during field scale hydraulic fracturing. However, later studies suggested that bed load transport is much more important in the laboratory than at field scale because the rate of bed load transport does not scale with fracture height. In recent years, there has been a resurgence of interest in the idea that bed load transport is significant at the field scale. Patankar et al. (2002) and Wang et al. (2003) presented new laboratory scale experiments on bed load proppant transport and proposed correlations to match the data. The correlations have subsequently been applied directly in field scale hydraulic fracturing simulators and have been used to design completion strategies and select proppants. This paper reviews correlations for sediment and slurry transport and provides a reanalysis of the laboratory results from Patankar et al. (2002). The analysis finds that the experiments can be well-described using classical correlations for sediment and slurry flow. The correlations are applied without adjusting any free parameters to fit the data. The analysis suggests that the total amount of proppant that can be transported in bed load transport in laboratory experiments is roughly similar to the amount transported at field scale. Because much greater volumes of proppant are injected at the field scale, the implication is that bed load transport is negligible in the great majority of field scale hydraulic fracturing treatments.

Modeling of hydraulic fracturing and designing of online pumping schedules to achieve uniform proppant concentration in conventional oil reservoirs

We present a novel control framework for the closed-loop operation of a hydraulic fracturing process. Initially, we focus on the development of a first-principle model of a hydraulic fracturing process. Second, a novel numerical scheme is developed to efficiently solve the coupled partial differential equations defined over a time-dependent spatial domain. Third, a reduced-order model is constructed, which is used to design a Kalman filter to accurately estimate unmeasurable states. Lastly, model predictive control theory is applied for the design of a feedback control system to achieve uniform proppant concentration across the fracture at the end of pumping by explicitly taking into account the desired fracture geometry, total amount of proppant injected, actuator limitations, and safety considerations. We demonstrate that the proposed control scheme is able to generate a spatial concentration profile which is uniform and close to the target concentration compared to that of the benchmark, Nolte's pumping schedule.

Development of a Powerful Data-Analysis Tool Using Nonparametric Smoothing Models To Identify Drillsites in Tight Shale Reservoirs With High Economic Potential

Summary The oil-and-gas industry is entering an era of “big data” because of the huge number of wells drilled with the rapid development of unconventional oil-and-gas reservoirs during the past decade. The massive amount of data generated presents a great opportunity for the industry to use data-analysis tools to help make informed decisions. The main challenge is the lack of the application of effective and efficient data-analysis tools to analyze and extract useful information for the decision-making process from the enormous amount of data available. In developing tight shale reservoirs, it is critical to have an optimal drilling strategy, thereby minimizing the risk of drilling in areas that would result in low-yield wells. The objective of this study is to develop an effective data-analysis tool capable of dealing with big and complicated data sets to identify hot zones in tight shale reservoirs with the potential to yield highly productive wells. The proposed tool is developed on the basis of nonparametric smoothing models, which are superior to the traditional multiple-linear-regression (MLR) models in both the predictive power and the ability to deal with nonlinear, higher-order variable interactions. This data-analysis tool is capable of handling one response variable and multiple predictor variables. To validate our tool, we used two real data sets—one with 249 tight oil horizontal wells from the Middle Bakken and the other with 2,064 shale gas horizontal wells from the Marcellus Shale. Results from the two case studies revealed that our tool not only can achieve much better predictive power than the traditional MLR models on identifying hot zones in the tight shale reservoirs but also can provide guidance on developing the optimal drilling and completion strategies (e.g., well length and depth, amount of proppant and water injected). By comparing results from the two data sets, we found that our tool can achieve model performance with the big data set (2,064 Marcellus wells) with only four predictor variables that is similar to that with the small data set (249 Bakken wells) with six predictor variables. This implies that, for big data sets, even with a limited number of available predictor variables, our tool can still be very effective in identifying hot zones that would yield highly productive wells. The data sets that we have access to in this study contain very limited completion, geological, and petrophysical information. Results from this study clearly demonstrated that the data-analysis tool is certainly powerful and flexible enough to take advantage of any additional engineering and geology data to allow the operators to gain insights on the impact of these factors on well performance.

Residual opening of hydraulic fractures created using the channel fracturing technique

The channel fracturing technique aims for discontinuous placement of proppant particles along the length of a hydraulic fracture in a way that a network of open channels or voids can be created between the proppant-filled regions of the fracture. In this paper, a simple theoretical model is developed to identify the optimal proppant volume fraction that maximises the effective conductivity of the partially-filled fracture while reducing the amount of proppant used.The fracture geometry is idealised as two-dimensional and a regular arrangement of proppant columns is considered. The residual opening profile of the fracture is determined as a function of the proppant column width and spacing, the mechanical properties of the rock and the proppant pack as well the magnitude of the compressive in-situ stress acting normal to the fracture plane. The effective fracture conductivity is then determined as a function of its residual opening profile. Some optimal estimates are provided for the conductivity enhancement and reduction in proppant use which can be useful for the application of the channel fracturing technique.

Optimization of Spacing and Penetration Ratio for Infinite-Conductivity Fractures in Unconventional Reservoirs: A Section-Based Approach

Summary In this paper, we consider the development plan of shale gas or tight oil with multiple multistage fractured laterals in a large square drainage area that we call a “section” (usually 640 acres in the US). We propose a convenient section-based optimization of the fracture array with two integer variables, the number of columns (horizontal laterals) and rows (fractures created in a lateral), to provide some general statements regarding spacing of wells and fractures. The approach is dependent on a reliable and efficient productivity-index (PI) calculation for the boundary-dominated state (BDS). The dimensionless PI is obtained by solving a time-independent eigenvalue problem by use of the finite-element method (FEM) combined with the Richardson extrapolation. The results of the case study demonstrate two decisive factors: the dimensionless total fracture length, related to the total amount of proppant and fracturing fluid available for the section, and the feasible range of actual fracture half-lengths, related to current fracturing-technology limitations. Under the constraint of dimensionless total fracture length, increasing the number of columns (horizontal laterals) increases the total PI but with only diminishing returns, whereas the optimal fracture-penetration ratio decreases somewhat, but is still near unity. When adding the technological constraint of a limited range of fracture half-lengths that can be routinely and reliably created, only a few choices remain admissible, and the optimal decision can be easily made. These general statements for the ideal homogeneous and isotropic formation can serve as a reference in the more-detailed optimization works. In other words, we offer a first-pass method for decision making in early stages when detailed inputs are not yet available. The information derived from the section-based optimization method and the efficient and reliable algorithm for PI calculation should help the design of multistage fracturing in shale-gas or ultralow-permeability oil formations.

Production Response in the Denver-Julesburg Basin

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 180217, “The Impact of Petrophysical and Completion Parameters on Production in the Denver-Julesberg Basin,” by Fred Miller, Carrizo Oil and Gas; Jon Payne, Eureka Geological Consulting; and Howard Melcher, Jim Reagan, and Leen Weijers, Liberty Oilfield Services, prepared for the 2016 SPE Low Permeability Symposium, Denver, 5–6 May. The paper has not been peer reviewed. The authors used a high-quality digital-log data set to characterize reservoir quality accurately in the Niobrara and Codell Formations in the Denver-Julesberg (DJ) Basin. A petrophysical work flow was developed, and detailed mapping of the reservoir attributes was completed. The log-derived parameters, along with an aeromagnetic and vitrinite-reflectance data set, provided excellent insight into which geologic parameters could be tied best to well-production response. Introduction In 2013, the authors began to evaluate production response in an area where nearly 50 Niobrara wells were completed by a single operator with a similar completion design for all wells. There was a wide variation in production results after 180 days of production, ranging from 4 to 16 BOE/lateral ft. The amount of proppant pumped per lateral foot changed very little and ranged between 800 and approximately 1,000 lbm/ft. The dramatic change in production response in light of the absence of major completion changes led to the early conclusion that geology is of great importance in the the Niobrara and Codell. In the early days of DJ production, horizontal-well-development operators did not generally make radical changes to completion designs, making it harder to evaluate the effect of these changes. Only since 2014 has a significant change from previous approaches been seen, with a new focus on a reduction in cost per BOE. Starting in 2009, stage count for mostly short (approximately 4,300-ft) laterals varied between 10 and 20 stages, with average stage intensity of 300 ft/stage. One of the first horizontal wells in the basin started with five stages, after which stage count quickly jumped to 16 to 20 stages in a short lateral. In recent years, stage count has increased significantly, partly because of longer extended-reach laterals and partly because of higher stage intensity. Stage intensity has dropped below 200 ft/stage, with some operators now experimenting with 125 ft/stage. Fluid and proppant volumes on a per-lateral-foot basis have not changed as dramatically in the DJ Basin as they have in other major US shale plays. Rate and rate per lateral foot show a similar lack of change over the first few years of DJ horizontal-well development; average rates are relatively low, most likely driven by the early-stage limitations of sliding-sleeve completions. Only recently have higher-rate jobs been seen. In response to the initial lack of DJ completion changes and the associated apparent lack of effect on production (resulting from production impact being hidden by larger geological changes), the authors developed a petrophysical work flow in an attempt to capture some of these geological parameters and assign them to every horizontal well. This led to calculation of the hydrocarbon pore volume (HPV), a proxy for bulk rock quality, for each of the wells. The conclusion was reached that any statistical model built only on completion parameters will be insufficient and will have to rely on a combination of completion and petrophysical/geological parameters.

Optimal Design of Hydraulic Fracturing for Deep Volcanic Reservoir in Zhungeer Basin

Deep volcanic reservoir in Xinjiang Zhungeer basin is buried over 4000m, the elastic modulus of reservoir rocks is high, hence it is difficult to initiate hydraulic fracture during fracturing operation; fracturing fluid filtration is serious and hard to be controlled due to the massive natural fractures in reservoir. Because of the serious heterogeneity along both horizontal and vertical direction, the optimum targets of design fracturing for different well layers are not the same. 4 out of 12 fracturing wells have not achieved the target amount of proppant. Ultimately, fracturing success rate is low and the production increase after fracturing shows a big difference among different wells. In order to improve the success rate and efficiency of deep volcanic reservoir fracturing, based on the analysis of the difficulties in previous fracturing operation, combined with the geological characteristics of reservoir, we optimized the key engineering parameters of deep volcanic rock fracturing, including perforation parameters, filtration parameters, fracture parameters and operation parameters. Results of fracturing design optimization bear an important guiding significance for improving the fracturing success rate and efficiency of deep volcanic reservoir in Zhungeer basin, Xinjiang province.

Stochastic optimization of hydraulic fracture and horizontal well parameters in shale gas reservoirs

Multistage hydraulic fracturing is one of the most important techniques in the successful exploitation and development of shale gas reservoirs. Most unconventional reservoirs rely on multistage hydraulic fracturing for commercial success. This success is accomplished by drilling horizontal well of appropriate length and creating transverse hydraulic fractures in stages across the well. Shale-gas reservoir's contact with the horizontal well bore is improved by using optimal well length, optimal fracture conductivity, optimum fracture length and optimum number of fracture stages. Because multistage fracturing of long horizontal wells increase the cost of field development, the economics of field development can be improved by using global optimization algorithms to estimate the optimum values of these operational parameters. In shale gas reservoirs, hydraulic fracture parameters such as fracture half-length, amount of proppant and fracture spacing should be optimized to maximize the net present value (NPV).In this work, differential evolution (DE) is implemented on a more realistic LGR-based shale gas reservoir simulation model. The objective is to maximize the net present value by optimizing hydraulic fracturing parameters and horizontal well length. Results obtained indicate that significant increase in NPV can be realized by using the optimization algorithm to estimate the operational parameters of hydraulic fracturing process in shale gas reservoirs.

A probabilistic and statistical approach as a means of predicting the efficiency of hydraulic fracturing

The study considers mathematical data on the efficiency of using a single-stage and multistage types of hydraulic fracturing for petroleum field development. The research is based on the geological and physical characteristics of the deposits in the latitudinal segment of the Ob River area, which has helped justify the method of choosing the HF technique. The probabilistic and statistical analysis of the commercial efficiency statistics has determined the quantitative criteria for selecting the crack parameters such as length, height and the amount of proppant injected, which can facilitate making estimates for the use of a single-stage and multistage types of hydraulic fracturing. The productive horizon AC-12-3 has a complex geological and physical structure and low reservoir properties, which greatly complicates its development but facilitates active formation of its hard-to-recover deposits.The study has revealed that the technology used to enhance oil recovery from the horizon BC-8-1 on the basis of a single-stage hydraulic fracturing can be effective for quite a limited time not exceeding 3-4 years. Meanwhile, the use of the multistage HF technology on the horizon AC-12-3 showed its higher efficiency compared to the single-stage HF technology.The results of the probabilistic and statistical analysis of the commercial application of the multistage hydraulic fracturing technology have proved that it is necessary to take into account the geological and physical peculiarities of a horizon in order to choose an appropriate technology of petroleum recovery.

Comprehensive Optimization Methodology for Stimulation Design of Low-Permeability Unconventional Gas Reservoirs

SummaryOver the past decade, multiple-fracture horizontal wells (MFHWs) have proved successful in recovering oil and particularly gas from very-low-permeability reservoirs. For MFHW planning and design, it is important to be able to make decisions on several variables, such as number of wells, number of fractures per well, amount and type of proppant per fracture, fracture dimensions (length, width, and height), and possibly others. Standard practice for making such decisions is mostly empirical. However, empiricism may not be as successful for new cases that are significantly different from old ones. In such cases, what-if analysis is used by combining intuition with numerical simulators to assess the outcomes of possible decisions. Even though this approach may produce feasible results, it is unlikely that it leads to optimal decisions because of the complexity of the problem. Therefore, a systematic methodology is needed for MFHW planning and design that produces optimal solutions efficiently and effectively.In this work, we develop such a methodology that optimizes net present value (NPV). The methodology poses the design problem as nested optimization in which the outer-optimization shell involves decisions on the number of wells, number of fractures per well, and amount of proppant, whereas the inner optimization maximizes the productivity index (PI) by selecting optimal fracture dimensions. The proposed methodology integrates in a systematic way a fracture-design module, a production-estimation module, and an economics module. Because the methodology is automated and numerically efficient, one can use it effectively for field development.A case study is used to illustrate the applicability of the proposed methodology, and suggestions are made for further improvements.