scholarly journals Optimization of Fracture Spacing and Well Spacing in Utica Shale Play Using Fast Analytical Flow-Cell Model (FCM) Calibrated with Numerical Reservoir Simulator

Energies ◽  
2020 ◽  
Vol 13 (24) ◽  
pp. 6736
Author(s):  
Ruud Weijermars
Keyword(s):  
Cell Model ◽  
Flow Cell ◽  
Production Performance ◽  
Design Parameters ◽  
Gas Wells ◽  
Production Rates ◽  
Fracture Spacing ◽  
Well Spacing ◽  
Wet Gas ◽  
Reservoir Simulator

Recently, a flow-cell model (FCM) was specifically developed to quickly generate physics-based forecasts of production rates and estimated ultimate resources (EURs) for infill wells, as the basis for the estimation of proven undeveloped reserves. Such reserves estimations provide operators with key collateral for further field development with reserves-based loans. FCM has been verified in previous studies to accurately forecast production rates and EURs for both black oil and dry gas wells. This study aims to expand the application range of FCM to predict the production performance and EURs of wells planned in undeveloped acreage of the wet gas window. Forecasts of the well rates and EURs with FCM are compared with the performance predictions generated with an integrated reservoir simulator for multi-fractured wells, using detailed field data from the Utica Field Experiment. Results of FCM, with adjustment factors to account for wet gas compressibility effects, match closely with the numerical performance forecasts. The advantage of FCM is that it can run on a fast spreadsheet template. Once calibrated for wet gas wells by a numerical reservoir simulator accounting for compositional flow, FCM can forecast the performance of future wells when completion design parameters, such as fracture spacing and well spacing, are changed.

scholarly journals Predicting the Performance of Undeveloped Multi-Fractured Marcellus Gas Wells Using an Analytical Flow-Cell Model (FCM)

Energies ◽  
2021 ◽  
Vol 14 (6) ◽  
pp. 1734
Author(s):  
David Waters ◽  
Ruud Weijermars
Keyword(s):  
Cell Model ◽  
Marcellus Shale ◽  
Flow Cell ◽  
Production Performance ◽  
Design Parameters ◽  
Fracture Treatment ◽  
Gas Wells ◽  
Future Production ◽  
Historic Data ◽  
Treatment Design

The objective of the present study is to predict how changes in the fracture treatment design parameters will affect the production performance of new gas wells in a target zone of the Marcellus shale. A recently developed analytical flow-cell model can estimate future production for new wells with different completion designs. The flow-cell model predictions were benchmarked using historic data of 11 wells and 6 different completion designs. First, a type well was generated and used with the flow-cell model to predict the performance of the later infill wells—with variable completion designs—based off the performance of earlier wells. The flow-cell model takes into account known hyperbolic forecast parameters (qi, Di, and b-factor) and fracture parameters (height, half-length, and spacing) of a type well. Next, the flow-cell model generates the hyperbolic decline parameters for an offset well based on the selected changes in the fracture treatment design parameters. Using a numerical simulator, the flow-cell model was verified as an accurate modeling technique for forecasting the production performance of horizontal, multi-fractured, gas wells.

scholarly journals Pre-Drilling Production Forecasting of Parent and Child Wells Using a 2-Segment Decline Curve Analysis (DCA) Method Based on an Analytical Flow-Cell Model Scaled by a Single Type Well

Energies ◽  
2020 ◽  
Vol 13 (6) ◽  
pp. 1525
Author(s):  
Ruud Weijermars ◽  
Kiran Nandlal
Keyword(s):  
Cell Model ◽  
Flow Cell ◽  
Curve Analysis ◽  
Treatment Quality ◽  
Well Performance ◽  
Reservoir Simulations ◽  
Decline Curve Analysis ◽  
Production Forecasting ◽  
Well Spacing ◽  
Decline Curve

This paper advances a practical tool for production forecasting, using a 2-segment Decline Curve Analysis (DCA) method, based on an analytical flow-cell model for multi-stage fractured shale wells. The flow-cell model uses a type well and can forecast the production rate and estimated ultimate recovery (EUR) of newly planned wells, accounting for changes in completion design (fracture spacing, height, half-length), total well length, and well spacing. The basic equations for the flow-cell model have been derived in two earlier papers, the first one dedicated to well forecasts with fracture down-spacing, the second one to well performance forecasts when inter-well spacing changes (and for wells drilled at different times, to account for parent-child well interaction). The present paper provides a practical workflow, introduces correction parameters to account for acreage quality and fracture treatment quality. Further adjustments to the flow-cell model based 2-segment DCA method are made after history matching field data and numerical reservoir simulations, which indicate that terminal decline is not exponential (b = 0) but hyperbolic (with 0 < b< 1). The timing for the onset of boundary dominated flow was also better constrained, using inputs from a reservoir simulator. The new 2-segment DCA method is applied to real field data from the Eagle Ford Formation. Among the major insights of our analyses are: (1) fracture down-spacing does not increase the long-term EUR, and (2) fracture down-spacing of real wells does not result in the rate increases predicted by either the flow-cell model based 2-segment DCA (or its matching reservoir simulations) with the assumed perfect fractures in the down-spaced well models. Our conclusion is that real wells with down-spaced fracture clusters, involving up to 5000 perforations, are unlikely to develop successful hydraulic fractures from each cluster. The fracture treatment quality factor (TQF) or failure rate (1-TQF) can be estimated by comparing the actual well performance with the well forecast based on the ideal well model (albeit flow-cell model or reservoir model, both history-matched on the type curve).

scholarly journals Numerical Study on the Influence of Well Layout on Electricity Generation Performance of Enhanced Geothermal Systems

Processes ◽  
2021 ◽  
Vol 9 (8) ◽  
pp. 1474
Author(s):  
Yuchao Zeng ◽  
Fangdi Sun ◽  
Haizhen Zhai
Keyword(s):  
Energy Efficiency ◽  
Electric Power ◽  
Electricity Generation ◽  
Horizontal Well ◽  
Production Performance ◽  
Electricity Production ◽  
Fracture Permeability ◽  
Fracture Spacing ◽  
Vertical Well ◽  
Well Spacing

The energy efficiency of the enhanced geothermal system (EGS) measures the economic value of the heat production and electricity generation, and it is a key indicator of system production performance. Presently there is no systematic study on the influence of well layout on the system energy efficiency. In this work we numerically analyzed the main factors affecting the energy efficiency of EGS using the TOUGH2-EOS1 codes at Gonghe Basin geothermal field, Qinghai province. The results show that for the reservoirs of the same size, the electric power of the three horizontal well system is higher than that of the five vertical well system, and the electric power of the five vertical well system is higher than that of the three vertical well system. The energy efficiency of the three horizontal well system is higher than that of the five vertical well system and the three vertical well system. The reservoir impedance of the three horizontal well system is lower than that of the three vertical well system, and the reservoir impedance of the three vertical well system is lower than that of the five vertical system. The sensitivity analysis shows that well spacing has an obvious impact on the electricity production performance; decreasing well spacing will reduce the electric power, reduce the energy efficiency and only have very slight influence on the reservoir impedance. Fracture spacing has an obvious impact on the electricity production performance; increasing fracture spacing will reduce the electric power and reduce the energy efficiency. Fracture permeability has an obvious impact on the electricity production performance; increasing fracture permeability will improve the energy efficiency and reduce the reservoir impedance.

Optimization of Well Spacing for Tight Sandstone Gas Reservoirs - Case Study of Eastern Sulige Gas Field

2012 ◽  
Vol 616-618 ◽  
pp. 762-766
Author(s):  
Rui Lan Luo ◽  
Ji Wu Fan ◽  
Hong Mei Liao ◽  
Wen Xu
Keyword(s):  
Early Stage ◽  
Production Performance ◽  
Test Time ◽  
Production Data ◽  
Tight Gas ◽  
Gas Wells ◽  
Tight Sandstone ◽  
Gas Field ◽  
Gas Well ◽  
Well Spacing

Influenced by special geologic condition and stimulation, the production performance of tight fractured gas well is obviously different from that of conventional gas well. During deliverability testing, the hydraulic fractured gas well can never reach steady state with limited test time. It is difficult to calculate reserve and drainage area accurately at early development stage. Take eastern Sulige gas field for example, by correctly recognizing the percolation characteristics and production performance of hydraulically-fractured tight gas wells, and combined with core analysis, 116 hydraulically fractured tight gas wells in eastern Sulige gas field have been analyzed. A prediction chart of recoverable reserve for estern Sulige gas field is established. With this chart, the ultimately recoverable reserves, drainage sizes, drainage lengths and drainage widths of 116 hydraulically-fractured tight gas wells in eastern Sulige gas field are predicted based on early stage of production data, and finally a reasonable well spacing for this field is suggested. Only utilizing routine production data without employing additional resources, this method is a good predictive guide to launch a development plan of tight gas field.

Unified Assessment of Unconventional Resource Plays – Implications for Global Exploration and Development

2021 ◽  
Author(s):  
Tarun Grover ◽  
Jamie Stuart Andrews ◽  
Irfan Ahmed ◽  
Ibnu Hafidz Arief
Keyword(s):  
Commodity Prices ◽  
Design Parameters ◽  
First Year ◽  
Well Productivity ◽  
Well Spacing ◽  
Cumulative Production ◽  
Unconventional Resource ◽  
Log Normal ◽  
The Impact ◽  
Sweet Spots

Abstract Unconventional resource plays, herein referred to as source rock plays, have been able to significantly increase the supply of hydrocarbons to the world. However, majority of the companies developing these resource plays have struggled to generate consistent positive cash flows, even during periods of stable commodity prices and after successfully reducing the development costs. The fundamental reasons for poor financial performance can be attributed to various reasons, such as; rush to lease acreage and drill wells to hold acreage, delayed mapping of sweet spots, slow acknowledgement of high geological variability, spending significant capital in trial and errors to narrow down optimal combinations of well spacing and stimulation designs. The objective of this paper is to present a systematic integrated multidisciplinary analysis of several unconventional plays worldwide which, if used consistently, can lead to significantly improved economics. We present an analysis of several unconventional plays in the US and Argentina with fluid systems ranging from dry gas to black oil. We utilize the publicly available datasets of well stimulation and production data along with laboratory measured core data to evaluate the sweet spots, the measure of well productivity, and the variability in well productivity. We investigate the design parameters which show the strongest correlation to well productivity. This step allows us to normalize the well productivity in such a way that the underlying well productivity variability due to geology is extracted. We can thus identify the number of wells which should be drilled to establish geology driven productivity variability. Finally, we investigate the impact of well spacing on well productivity. The data indicates that, for any well, first year cumulative production is a robust measure of ultimate well productivity. The injected slurry volume shows the best correlation to the well productivity and "completion normalized" well productivity can be defined as first year cumulative production per barrel of injected slurry volume. However, if well spacing is smaller than the created hydraulic fracture network, the potential gain of well productivity is negated leading to poor economics. Normalized well productivity is log-normally distributed in any play due to log-normal distribution of permeability and the sweet spots will generally be defined by most permeable portions of the play. Normalized well productivity is shown to be independent of areal scale of any play. We show that in every play analyzed, typically 20-50 wells (with successful stimulation and production) are sufficient to extract the log-normal productivity distribution depending on play size and target intervals. We demonstrate that once the log-normal behavior is anticipated, creation of production profiles with p10-p50-p90 values is quite straightforward. The way the data analysis is presented can be easily replicated and utilized by any operator worldwide which can be useful in evaluation of unconventional resource play opportunities.

A Proxy Flow Modelling Workflow to Estimate Gridded Dynamic Properties and Well Production Rates by Deep Learning Algorithms

2021 ◽  
Author(s):  
Soumi Chaki ◽  
Yevgeniy Zagayevskiy ◽  
Terry Wong
Keyword(s):  
Neural Network ◽  
Deep Learning ◽  
Dynamic Properties ◽  
Reservoir Management ◽  
Flow Modeling ◽  
Static Properties ◽  
Production Rates ◽  
Reservoir Properties ◽  
Well Production ◽  
Reservoir Simulator

Abstract This paper proposes a deep learning-based framework for proxy flow modeling to predict gridded dynamic petroleum reservoir properties (like pressure and saturation) and production rates for wells in a single framework. It approximates the solution of a full physics-based numerical reservoir simulator, but runs much more rapidly, allowing users to generate results for a much wider range of scenarios in a given time than could be done with a full physics simulator. The proxy can be used for reservoir management tasks like history matching, uncertainty quantification, and field development optimization. A deep-learning based methodology for accurate proxy-flow modeling is presented which combines U-Net (a variant of convolutional neural network) to predict gridded dynamic properties and deep neural network (DNN) models to forecast well production rates. First, gridded dynamic properties, such as reservoir pressure and phase saturations, are predicted from static properties like reservoir rock porosity and absolute permeability using a U-Net. Then, the static properties and the dynamic properties predicted by the U-Net are input to a DNN to predict production rates at the well perforations. The inclusion of U-net predicted pressure and saturations improves the quality of the well rate predictions. The proposed methodology is presented with the synthetic Brugge reservoir discretized into grid blocks. The U-Net input consists of three properties: dynamic gridded reservoir properties (such as pressure or fluid saturation) at the current state, static gridded porosity, and static gridded permeability. The U-Net has only one output property, the target gridded property (such as pressure or saturation) at the next time step. Training and testing datasets are generated by running 13 full physics flow simulations and dividing them in a 12:1 ratio. Nine U-Net models are calibrated to predict pressures/saturations, one for each of the nine grid layers present in the Brugge model. These outputs are then concatenated to obtain the complete pressure/saturation model for all nine layers. The constructed U-Net models match the distributions of generated pressures/saturations of the numerical reservoir simulator with a correlation coefficient value of approximately 0.99 and above 95% accuracy. The DNN models approximate well production rates accurately from U-Net predicted pressures and saturations along with static properties like transmissibility and horizontal permeability. For each well and each well perforation, the production rate is predicted with the DNN model. The use of the constructed proxy flow model generates reservoir predictions within a few minutes compared to the hours or days typically taken by a full physics flow simulator. The direct connection that is established between the gridded static and dynamic properties of the reservoir and well production rates using U-Net and DNN models has not been presented previously. Using only a small number of runs for its training, the workflow matches the numerical reservoir simulator results with reduced computational effort. This helps reservoir engineers make informed decisions more quickly, resulting in more efficient reservoir management.

scholarly journals A Review on the Application of Multiphase Twin Screw Pump as a Downhole Wet Gas Compressor to Improve Gas Wells Recovery Factor

2021 ◽  
Vol 15 ◽  
pp. 223-232
Author(s):  
Sharul Sham Dol ◽  
Niraj Baxi ◽  
Mior Azman Meor Said
Keyword(s):  
Volume Fraction ◽  
Energy Industry ◽  
Gas Wells ◽  
Screw Pump ◽  
Research Activities ◽  
Wet Gas ◽  
Gas Compression ◽  
Twin Screw ◽  
Gas Volume Fraction ◽  
Gas Volume

By introducing a multiphase twin screw pump as an artificial lifting device inside the well tubing (downhole) for wet gas compression application; i.e. gas volume fraction (GVF) higher than 95%, the unproductive or commercially unattractive gas wells can be revived and made commercially productive once again. Above strategy provides energy industry with an invaluable option to significantly reduce greenhouse gas emissions by reviving gas production from already existing infrastructure thereby reducing new exploratory and development efforts. At the same time above strategy enables energy industry to meet society’s demand for affordable energy throughout the critical energy transition from predominantly fossil fuels based resources to hybrid energy system of renewables and gas. This paper summarizes the research activities related to the applications involving multiphase twin screw pump for gas volume fraction (GVF) higher than 95% and outlines the opportunity that this new frontier of multiphase fluid research provides. By developing an understanding and quantifying the factors that influence volumetric efficiency of the multiphase twin screw pump, the novel concept of productivity improvement by a downhole wet gas compression using above technology can be made practicable and commercially more attractive than other production improvement strategies available today. Review and evaluation of the results of mathematical and experimental models for multiphase twin screw pump for applications with GVF of more than 95% has provided valuable insights in to multiphase physics in the gap leakage domains of pump and this increases confidence that novel theoretical concept of downhole wet gas compression using multiphase twin screw pump that is described in this paper, is practically achievable through further research and improvements.

Artificial Lift Optimization for Shallow Carbonate Magwa and Ostracod Formations with Massive Propped Fractures

2021 ◽  
Author(s):  
Nasser AlAskari ◽  
Muhamad Zaki ◽  
Ahmed AlJanahi ◽  
Hamed AlGhadhban ◽  
Eyad Ali ◽  
...  
Keyword(s):  
Production Performance ◽  
Shallow Depth ◽  
Production Rates ◽  
Field Development ◽  
Artificial Lift ◽  
Geological Conditions ◽  
Fracture Fluid ◽  
Reservoir Potential ◽  
Gas Lift

Abstract Objectives/Scope: The Magwa and Ostracod formations are tight and highly fractured carbonate reservoirs. At shallow depth (1600-1800 ft) and low stresses, wide, long and conductive propped fracture has proven to be the most effective stimulation technique for production enhancement. However, optimizing flow of the medium viscosity oil (17-27 API gravity) was a challenge both at initial phase (fracture fluid recovery and proppant flowback risks) and long-term (depletion, increasing water cut, emulsion tendency). Methods, Procedures, Process: Historically, due to shallow depth, low reservoir pressure and low GOR, the optimum artificial lift method for the wells completed in the Magwa and Ostracod reservoirs was always sucker-rod pumps (SRP) with more than 300 wells completed to date. In 2019 a pilot re-development project was initiated to unlock reservoir potential and enhance productivity by introducing a massive high-volume propped fracturing stimulation that increased production rates by several folds. Consequently, initial production rates and drawdown had to be modelled to ensure proppant pack stability. Long-term artificial lift (AL) design was optimized using developed workflow based on reservoir modelling, available post-fracturing well testing data and production history match. Results, Observations, Conclusions: Initial production results, in 16 vertical and slanted wells, were encouraging with an average 90 days production 4 to 8 times higher than of existing wells. However, the initial high gas volume and pressure is not favourable for SRP. In order to manage this, flexible AL approach was taken. Gas lift was preferred in the beginning and once the production falls below pre-defined PI and GOR, a conversion to SRP was done. Gas lift proved advantageous in handling solids such as residual proppant and in making sure that the well is free of solids before installing the pump. Continuous gas lift regime adjustments were taken to maximize drawdown. Periodical FBHP surveys were performed to calibrate the single well model for nodal analysis. However, there limitations were present in terms of maximizing the drawdown on one side and the high potential of forming GL induced emulsion on the other side. Horizontal wells with multi-stage fracturing are common field development method for such tight formations. However, in geological conditions of shallow and low temperature environment it represented a significant challenge to achieve fast and sufficient fracture fluid recovery by volume from multiple fractures without deteriorating the proppant pack stability. This paper outlines local solutions and a tailored workflow that were taken to optimize the production performance and give the brown field a second chance. Novel/Additive Information: Overcoming the different production challenges through AL is one of the keys to unlock the reservoir potential for full field re-development. The Magwa and Ostracod formations are unique for stimulation applications for shallow depth and range of reservoirs and fracture related uncertainties. An agile and flexible approach to AL allowed achieving the full technical potential of the wells and converted the project to a field development phase. The lessons learnt and resulting workflow demonstrate significant value in growing AL projects in tight and shallow formations globally.

Numerical Simulation Study on the Key Influencing Factors of Water-Invasion Performance for the Gas Wells with Bottom-Water

2014 ◽  
Vol 884-885 ◽  
pp. 104-107
Author(s):  
Zhi Jun Li ◽  
Ji Qiang Li ◽  
Wen De Yan
Keyword(s):  
Numerical Simulation ◽  
Influencing Factors ◽  
Bottom Water ◽  
Simulation Method ◽  
Gas Production ◽  
Production Performance ◽  
Gas Wells ◽  
Two Phase ◽  
Gas Well ◽  
Water Gas

For the water-sweeping gas reservoir, especially when the water-body is active, water invasion can play positive roles in maintaining formation pressure and keeping the gas well production. But when the water-cone break through and towards the well bottom, suffers from the influencing of gas-water two phase flows, permeability of gas phase decrease sharply and will have a serious impact on the production performance of the gas well. Moreover, the time when the water-cone breakthrough will directly affect the final recovery of the gas wells, therefore, the numerical simulation method is used to conduct the research on the key influencing factors of water-invasion performance for the gas wells with bottom-water, which is the basis of the mechanical model for the typical gas wells with bottom-water. It indicate that as followings: (1) the key influencing factors of water-invasion performance for the gas wells with bottom-water are those, such as the open degree of the gas beds, well gas production and the amount of Kv/Kh value; and (2) the barrier will be in charge of great significance on the water-controlling for the bottom water gas wells, and its radius is the key factor to affect water-invasion performance for the bottom water gas wells where the barriers exist nearby.

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