Manuscript Title: Unlocking New/Missed Reservoir Zones at Shallow Depth Based on Integrating Post-Hydraulic Fracture Performance with Reservoir, Petrophysics, and Geology Data

2021 ◽  
Author(s):  
Michael Nashaat ◽  
Hassan Kolivand ◽  
Murat Zhiyenkulov ◽  
Yerlan Seilov ◽  
Kassem Ghorayeb ◽  
...  
Keyword(s):  
Hydraulic Fracture ◽  
Production Performance ◽  
Fracture Plane ◽  
Gas Field ◽  
Uncertainty Range ◽  
Main Challenge ◽  
Wide Range ◽  
Production Behavior ◽  
Fracture Performance ◽  
Productive Zone

Abstract Skhidno-Poltavske Field is a Ukrainian gas field producing mostly from commingled wells. These commingled wells have no information about the production split and the pressure data measured for each formation separately. This was one of the main challenges to study the field and understand the potential of each individual formation. Many wells were hydraulically fractured (HF) and showed a wide range of production and pressure performance after the stimulation. Six of these HF wells showed atypical pressure and production behavior after the HF compared to the rest of the wells. The main challenge in the reservoir simulation study was to understand whether these HFs reached isolated lateral segments of the same producing zones or accessed other reservoir zones by/due to vertical propagation of the hydraulic fracture plane. Understanding the pressure and production performance of these wells and comparing them to the other wells was the key to revealing their behavior. This was integrated with the petrophysical data to understand the potential formations and the uncertainty range of their properties. The geomodeling was the destination to translate these uncertainties into different realizations that were all dynamically tested to generate the most probable realization. The integration between different domains resulted in unlocking an overlooked productive zone that was out of consideration. This increased the reserves of this field and extended its life. One of the study recommendations was to test and develop this formation through perforating the existing wells or drilling new wells targeting the overlooked productive zone.

Hydraulic stimulation of natural fractures as revealed by induced microearthquakes, Carthage Cotton Valley gas field, east Texas

Geophysics ◽  
2003 ◽  
Vol 68 (2) ◽  
pp. 441-452 ◽  
Author(s):  
James T. Rutledge ◽  
W. Scott Phillips
Keyword(s):  
Hydraulic Fracture ◽  
Fracture Zone ◽  
Horizontal Stress ◽  
Focal Mechanisms ◽  
Fracture Plane ◽  
Natural Fractures ◽  
East Texas ◽  
Gas Field ◽  
Cotton Valley ◽  
Maximum Horizontal Stress

We produced a high‐resolution microseismic image of a hydraulic fracture stimulation in the Carthage Cotton Valley gas field of east Texas. We improved the precision of microseismic event locations four‐fold over initial locations by manually repicking the traveltimes in a spatial sequence, allowing us to visually correlate waveforms of adjacent sources. The new locations show vertical containment within individual, targeted sands, suggesting little or no hydraulic communication between the discrete perforation intervals simultaneously treated within an 80‐m section. Treatment (i.e., fracture‐zone) lengths inferred from event locations are about 200 m greater at the shallow perforation intervals than at the deeper intervals. The highest quality locations indicate fracture‐zone widths as narrow as 6 m. Similarity of adjacent‐source waveforms, along with systematic changes of phase amplitude ratios and polarities, indicate fairly uniform source mechanisms (fracture plane orientation and sense of slip) over the treatment length. Composite focal mechanisms indicate both left‐ and right‐lateral strike‐slip faulting along near‐vertical fractures that strike subparallel to maximum horizontal stress. The focal mechanisms and event locations are consistent with activation of the reservoir's prevalent natural fractures, fractures that are isolated within individual sands and trend subparallel to the expected hydraulic fracture orientation (maximum horizontal stress direction). Shear activation of these fractures indicates a stronger correlation of induced seismicity with low‐impedance flow paths than is normally found or assumed during injection stimulation.

Probabilistic Aggregation of Oil and Gas Field Resource Estimates and Project Portfolio Analysis

2009 ◽  
Vol 13 (01) ◽  
pp. 72-81 ◽  
Author(s):  
Jan F. van Elk ◽  
Ritu Gupta ◽  
David Wann
Keyword(s):  
Oil And Gas ◽  
Oil Industry ◽  
Field Studies ◽  
Critical Element ◽  
Gas Field ◽  
Uncertainty Range ◽  
Production Forecasting ◽  
True Value ◽  
Wide Range ◽  
Oil And Gas Field

Summary Probabilistic aggregation and dependency estimation are essential in portfolio methods, production forecasting, and resource estimation. The use of arithmetic addition understates the true value of the resource estimates within a portfolio of fields. Potentially, this could result in deferral of a project, or loss of lucrative business and commercial opportunities, such as project investment, facilitysizing decisions, or incremental gas-supply commitments. A statistically robust method for aggregation of resource estimates that appropriately uses expert opinion is presented in this paper. Using two integrated-project examples, this paper introduces new methods for (1) probabilistic aggregation of the resource estimates for multiple fields and (2) estimating a measure of dependency between the resource estimates of individual fields. The new analytical method for probabilistic aggregation is based on multivariate skew-normal (MSN) distributions, which can model a wide range of skewness through a shape parameter and are used heavily in financial and actuarial applications. In studies of the fields in which the multiple-realizations approach is used as a basis for the uncertainty framework, tornado diagrams are generated routinely to describe the dependence of the field resources on reservoir parameters. The improved method for evaluating measures of dependency between the resource estimates within a portfolio of fields uses these tornado diagrams as a basis. Incorporating the expertise and knowledge of geologists and petroleum engineers is a critical element of the method. These methods for probabilistic aggregation and estimating dependencies were developed within the context of the oil industry, but their use is not limited to the oil industry. They are general and can be used in other probabilistic-aggregation problems. Application of these techniques requires limited time and effort, compared to individual-field studies, and can have a profound impact on the uncertainty range of the total resources for the portfolio of fields.

scholarly journals Production behavior evaluation on multilayer commingled stress-sensitive carbonate gas reservoir

2020 ◽  
pp. 014459872096415
Author(s):  
Jianlin Guo ◽  
Fankun Meng ◽  
Ailin Jia ◽  
Shuo Dong ◽  
Haijun Yan ◽  
...  
Keyword(s):  
Early Stage ◽  
Sedimentary Environment ◽  
Production Performance ◽  
Total Production ◽  
Inversion Algorithm ◽  
Gas Reservoir ◽  
Hole Pressure ◽  
Bottom Hole Pressure ◽  
Bottom Hole ◽  
Production Behavior

Influenced by the complex sedimentary environment, a well always penetrates multiple layers with different properties, which leads to the difficulty of analyzing the production behavior for each layer. Therefore, in this paper, a semi-analytical model to evaluate the production performance of each layer in a stress-sensitive multilayer carbonated gas reservoir is proposed. The flow of fluids in layers composed of matrix, fractures, and vugs can be described by triple-porosity/single permeability model, and the other layers could be characterized by single porosity media. The stress-sensitive exponents for different layers are determined by laboratory experiments and curve fitting, which are considered in pseudo-pressure and pseudo-time factor. Laplace transformation, Duhamel convolution, Stehfest inversion algorithm are used to solve the proposed model. Through the comparison with the classical solution, and the matching with real bottom-hole pressure data, the accuracy of the presented model is verified. A synthetic case which has two layers, where the first one is tight and the second one is full of fractures and vugs, is utilized to study the effects of stress-sensitive exponents, skin factors, formation radius and permeability for these two layers on production performance. The results demonstrate that the initial well production is mainly derived from high permeable layer, which causes that with the rise of formation permeability and radius, and the decrease of stress-sensitive exponents and skin factors, in the early stage, the bottom-hole pressure and the second layer production rate will increase. While the first layer contributes a lot to the total production in the later period, the well bottom-hole pressure is more influenced by the variation of formation and well condition parameters at the later stage. Compared with the second layer, the scales of formation permeability and skin factor for first layer have significant impacts on production behaviors.

Gearbox (China) Ltd.: Will the Company's ERP System Support its Ambitious Growth Strategy?

2004 ◽  
Vol 19 (2) ◽  
pp. 140-148 ◽  
Author(s):  
Kai Reimers
Keyword(s):  
Operations Management ◽  
Emerging Market ◽  
Growth Strategy ◽  
Medium Size ◽  
Cultural Issues ◽  
Erp System ◽  
Organizational Behaviour ◽  
Main Challenge ◽  
Wide Range ◽  
Mechanical Devices

This case describes the experience of a wholly foreign-owned manufacturing company in Tianjin/China regarding the use of its ERP system in its main functional departments, purchasing, production planning, sales/distribution, and finance. The company is part of a group which is a global leader in the manufacturing and distribution of mechanical devices, called gearboxes, that are needed to drive a wide range of facilities such as escalators and baggage conveyor belts in airports. It has entered China in 1995 and the Tianjin manufacturing facility has soon become a hub for the Asian market. The main challenge confronting the management team is to support the breakneck growth rate of this young company. The company's ERP system plays a crucial role in this task. However, it seems that middle managers are frequently hitting an invisible wall when trying to expand the use of the ERP system in order to cope with ever-increasing workloads and coordination tasks. This case serves to illustrate cultural issues implicated in the use of an enterprise wide information system in a medium size company operating in an emerging market economy. In addition, issues of operations management, global management, and organizational behaviour are addressed.

Impact of the Cluster Spacing on Hydraulic Fracture Conductivity and Productivity of a Marcellus Shale Horizontal Well

2021 ◽  
Author(s):  
Mohamed El Sgher ◽  
Kashy Aminian ◽  
Ameri Samuel
Keyword(s):  
Hydraulic Fracture ◽  
Marcellus Shale ◽  
Technical Information ◽  
Gas Production ◽  
Production Performance ◽  
Valuable Insight ◽  
Fracture Conductivity ◽  
Fracture Properties ◽  
Gas Recovery ◽  
The Impact

Abstract The objective of this study was to investigate the impact of the hydraulic fracturing treatment design, including cluster spacing and fracturing fluid volume on the hydraulic fracture properties and consequently, the productivity of a horizontal Marcellus Shale well with multi-stage fractures. The availability of a significant amount of advanced technical information from the Marcellus Shale Energy and Environment Laboratory (MSEEL) provided an opportunity to perform an integrated analysis to gain valuable insight into optimizing fracturing treatment and the gas recovery from Marcellus shale. The available technical information from a horizontal well at MSEEL includes well logs, image logs (both vertical and lateral), diagnostic fracture injection test (DFIT), fracturing treatment data, microseismic recording during the fracturing treatment, production logging data, and production data. The analysis of core data, image logs, and DFIT provided the necessary data for accurate prediction of the hydraulic fracture properties and confirmed the presence and distribution of natural fractures (fissures) in the formation. Furthermore, the results of the microseismic interpretation were utilized to adjust the stress conditions in the adjacent layers. The predicted hydraulic fracture properties were then imported into a reservoir simulation model, developed based on the Marcellus Shale properties, to predict the production performance of the well. Marcellus Shale properties, including porosity, permeability, adsorption characteristics, were obtained from the measurements on the core plugs and the well log data. The Quanta Geo borehole image log from the lateral section of the well was utilized to estimate the fissure distribution s in the shale. The measured and published data were utilized to develop the geomechnical factors to account for the hydraulic fracture conductivity and the formation (matrix and fissure) permeability impairments caused by the reservoir pressure depletion during the production. Stress shadowing and the geomechanical factors were found to play major roles in production performance. Their inclusion in the reservoir model provided a close agreement with the actual production performance of the well. The impact of stress shadowing is significant for Marcellus shale because of the low in-situ stress contrast between the pay zone and the adjacent zones. Stress shadowing appears to have a significant impact on hydraulic fracture properties and as result on the production during the early stages. The geomechanical factors, caused by the net stress changes have a more significant impact on the production during later stages. The cumulative gas production was found to increase as the cluster spacing was decreased (larger number of clusters). At the same time, the stress shadowing caused by the closer cluster spacing resulted in a lower fracture conductivity which in turn diminished the increase in gas production. However, the total fracture volume has more of an impact than the fracture conductivity on gas recovery. The analysis provided valuable insight for optimizing the cluster spacing and the gas recovery from Marcellus shale.

An Empirical Analog Benchmarking Workflow to Improve Hydrocarbon Recovery

2021 ◽  
pp. 1-18
Author(s):  
Shaoqing Sun ◽  
David A. Pollitt
Keyword(s):  
Best Practices ◽  
Lessons Learned ◽  
Production Performance ◽  
Resource Potential ◽  
Systematic Analysis ◽  
Hydrocarbon Recovery ◽  
Field Development ◽  
Development Scenarios ◽  
Recovery Potential ◽  
Wide Range

Summary Benchmarking the recovery factor and production performance of a given reservoir against applicable analogs is a key step in field development optimization and a prerequisite in understanding the necessary actions required to improve hydrocarbon recovery. Existing benchmarking methods are principally structured to solve specific problems in individual situations and, consequently, are difficult to apply widely and consistently. This study presents an alternative empirical analog benchmarking workflow that is based upon systematic analysis of more than 1,600 reservoirs from around the world. This workflow is designed for effective, practical, and repeatable application of analog analysis to all reservoir types, development scenarios, and production challenges. It comprises five key steps: (1) definition of problems and objectives; (2) parameterization of the target reservoir; (3) quantification of resource potential; (4) assessment of production performance; and (5) identification of best practices and lessons learned. Problems of differing nature and for different objectives require different sets of analogs. This workflow advocates starting with a broad set of parameters to find a wide range of analogs for quantification of resource potential, followed by a narrowly defined set of parameters to find relevant analogs for assessment of production performance. During subsequent analysis of the chosen analogs, the focus is on isolating specific critical issues and identifying a smaller number of applicable analogs that more closely match the target reservoir with the aim to document both best practices and lessons learned. This workflow aims to inform decisions by identifying the best-in-class performers and examining in detail what differentiates them. It has been successfully applied to improve hydrocarbon recovery for carbonate, clastic, and basement reservoirs globally. The case studies provided herein demonstrate that this workflow has real-world utility in the identification of upside recovery potential and specific actions that can be taken to optimize production and recovery.

scholarly journals Co-eye: a multi-resolution ensemble classifier for symbolically approximated time series

2020 ◽  
Vol 109 (11) ◽  
pp. 2029-2061
Author(s):  
Zahraa S. Abdallah ◽  
Mohamed Medhat Gaber
Keyword(s):  
Time Series ◽  
Time Series Data ◽  
Ensemble Classifier ◽  
Series Data ◽  
New Classification ◽  
Symbolic Representations ◽  
Classification Technique ◽  
Field Of Vision ◽  
Main Challenge ◽  
Wide Range

Abstract Time series classification (TSC) is a challenging task that attracted many researchers in the last few years. One main challenge in TSC is the diversity of domains where time series data come from. Thus, there is no “one model that fits all” in TSC. Some algorithms are very accurate in classifying a specific type of time series when the whole series is considered, while some only target the existence/non-existence of specific patterns/shapelets. Yet other techniques focus on the frequency of occurrences of discriminating patterns/features. This paper presents a new classification technique that addresses the inherent diversity problem in TSC using a nature-inspired method. The technique is stimulated by how flies look at the world through “compound eyes” that are made up of thousands of lenses, called ommatidia. Each ommatidium is an eye with its own lens, and thousands of them together create a broad field of vision. The developed technique similarly uses different lenses and representations to look at the time series, and then combines them for broader visibility. These lenses have been created through hyper-parameterisation of symbolic representations (Piecewise Aggregate and Fourier approximations). The algorithm builds a random forest for each lens, then performs soft dynamic voting for classifying new instances using the most confident eyes, i.e., forests. We evaluate the new technique, coined Co-eye, using the recently released extended version of UCR archive, containing more than 100 datasets across a wide range of domains. The results show the benefits of bringing together different perspectives reflecting on the accuracy and robustness of Co-eye in comparison to other state-of-the-art techniques.

On the Use of Online Monitored Key Parameters From Pipe Lay Operations

2008 ◽  
Author(s):  
Ole David O̸kland ◽  
Egil Giertsen ◽  
Svein Sævik ◽  
Joakim Taby
Keyword(s):  
Time Domain ◽  
Online Monitoring ◽  
Time Domain Analysis ◽  
Current Profile ◽  
Gas Field ◽  
Wide Range ◽  
Back Calculation ◽  
Storegga Slide ◽  
New Generation ◽  
Norwegian Continental Shelf

For pipe lay operations parameters like heading and position of the lay vessel, lay-back and information about feeding of joints are usually collected and stored by the contractor. Many lay vessels are also equipped with a MRU unit for measurements of dynamic vessel motions, and in some cases the current profile is also monitored. This is especially the case for pipes with low bending stiffness and low ratio between weight and drag diameter (i.e. small pipe diameter) where current is important for the configuration of the pipe catenary. Together with the seabed these parameters constitutes the boundary conditions for a nonlinear time domain analysis of the lay operation. Such an analysis approach will have a wide range of application areas, from online monitoring to realistic back-calculation of a lay operation. During recent year’s work with the Ormen Lange field (see Figure 1) Marintek has developed a new generation of 3D pipeline analysis tools. Ormen Lange is the largest natural gas field on the Norwegian continental shelf. The field is situated 120 km northwest of Kristiansund. The seabed depths in the reservoir area vary between 800–1100m, and the terrain is very rough due to remnants from the Storegga slide. In the period 2006–2007 two 30" import lines, two MEG lines, and two umbilicals were installed at the Ormen Lange field. In the present paper monitored data collected during the installation of the 30" pipelines are used to back-calculate the lay operation. The agreement between observed and calculated lay parameters are reported and discussed.

Development of a new approach for hydraulic fracturing in tight sand with pre-existing natural fractures

2016 ◽  
Vol 56 (1) ◽  
pp. 225 ◽  
Author(s):  
Kunakorn Pokalai ◽  
David Kulikowski ◽  
Raymond L. Johnson ◽  
Manouchehr Haghighi ◽  
Dennis Cooke
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
High Stress ◽  
Gas Production ◽  
Natural Fracture ◽  
Rock Properties ◽  
Fracture Plane ◽  
Natural Fractures ◽  
Geomechanical Model ◽  
Well Design

Hydraulic fracturing in tight gas reservoirs has been performed in the Cooper Basin for decades in reservoirs containing high stress and pre-existing natural fractures, especially near faults. The hydraulic fracture is affected by factors such as tortuosity, high entry pressures, and the rock fabric including natural fractures. These factors cause fracture plane rotation and complexities, leading to fracture disconnection or reduced proppant placement during the treatment. In this paper, rock properties are estimated for a targeted formation using well logs to create a geomechanical model. Natural fracture and stress azimuths within the interval were interpreted from borehole image logs. The image log interpretations inferred that fissures are oriented 30–60° relative to the maximum horizontal stress. Next, diagnostic fracture injection test (DFIT) data was used with the poro-elastic stress equations to predict tectonic strains. Finally, the geomechanical model was history-matched with a planar 3D hydraulic fracturing simulator, and gave more insight into fracture propagation in an environment of pre-existing natural fractures. The natural fracture azimuths and calibrated geomechanical model are input into a framework to evaluate varying scenarios that might result based on a vertical or inclined well design. A well design is proposed based on the natural fracture orientation relative to the hydraulic fracture that minimises complexity to optimise proppant placement. In addition, further models and diagnostics are proposed to aid predicting the hydraulically induced fracture geometry, its impact on gas production, and optimising wellbore trajectory to positively interact with pre-existing natural fractures.

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