Improvements in understanding short-range permeability variability in coal seam gas reservoirs

2016 ◽  
Vol 56 (2) ◽  
pp. 555
Author(s):  
Stephen Tyson ◽  
Suzanne Hurter ◽  
Fengde Zhou ◽  
Morteza Jami
Keyword(s):  
Short Range ◽  
Simulation Models ◽  
Holistic Approach ◽  
Predictive Modelling ◽  
Gas Production ◽  
Production Performance ◽  
Improve Measurement ◽  
Production Wells ◽  
Production History ◽  
The Impact

After several years of production history on at least some of the more than 7,000 CSG production wells in the Surat and Bowen basins, reservoir engineers continue to note that understanding detailed permeability spatial variation near the well bore and its impact on actual production performance remains poor. There is a growing realisation that permeability of coals has an even higher variability than was initially expected, and that this variability occurs across a shorter range than that of the typical inter-well spacing (~750 m). As a result, flow between wells, pressure depletion, water and gas production rates and ultimate recovery is difficult to predict. Forecasting short-range continuity of different categories of absolute permeabilities through modelling is the key challenge. Other physical or geophysical parameters may change similarly with the same range. Generation models tend to over-estimate the lateral continuity of coals and associated carbonaceous shales resulting in a poor match between the model predictions and the observed production data. This may be due to incomplete information on the short-range variability of porosity and permeability and the appropriate up-scaled values for these parameters used in the reservoir simulation models. This extended abstract discusses controls on permeability, both the geological influences and the impact of drilling and completion on permeability. Taking a holistic approach to the problem of understanding permeability variability, the relative impact of these controls is estimated and discussed. With the benefit of rudimentary ranking of these controls, techniques have been developed to improve measurement and modelling of permeability variability. These approaches can help improve the predictive modelling capability of reservoir performance.

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.

A New Estimation of Water-Drive Reservoir Production Performance Prediction Based on Radial Fluid Flow

2011 ◽  
Vol 361-363 ◽  
pp. 364-369
Author(s):  
Xiao Juan Liu ◽  
Rui Huang ◽  
Rui He Wang
Keyword(s):  
Numerical Approach ◽  
Production Performance ◽  
Calculation Error ◽  
Fine Grid ◽  
Reservoir Evaluation ◽  
Vertical Heterogeneity ◽  
Production History ◽  
Calculation Results ◽  
History Of ◽  
The Impact

Due to deposition sequence, reservoir can be approximately considered as formation vertically consisting of many small layers with different physical properties. Meanwhile, the property distribution of these small layers, e.g. heterogeneity of the formation, has a great impact on reservoir development and its production performance. No matter how fine grid to be used, it is always difficult for traditional numerical simulation to couple the impact of vertical heterogeneity of the formation, that will inevitably result in significant calculation error. Therefore in order to overcome this defect and deliver better calculation results which are consistent along with real production performance, this paper derives a math model combined both analysis approach and numerical approach, which has a better description for vertical heterogeneity of formation by overlapping small layers and could deliver better calculation results by fine-gridding strata profile. The model could be applied to either predict further field production performance or conduct history match based on production history of field. This method has applied in actual production analysis and reservoir evaluation, and good results have been achieved.

scholarly journals NUMERICAL MODELLING AND SIMULATION OF CO2 –ENHANCED COAL-BED METHANE RECOVERY (CO2-ECBMR): THE EFFECT OF COAL SWELLING ON GAS PRODUCTION PERFORMANCE

2015 ◽  
Vol 7 (2) ◽  
pp. 102
Author(s):  
Ferian Anggara ◽  
Kyuro Sasaki ◽  
Yuichi Sugai
Keyword(s):  
Gas Production ◽  
Production Performance ◽  
Coal Bed ◽  
Methane Recovery ◽  
Coal Matrix ◽  
Ch4 Production ◽  
Coal Swelling ◽  
Production Ratio ◽  
Permeability Changes ◽  
Production Wells

This presents study investigate the effect of swelling on gas production performances at coal reservoirs during CO2-ECBMR processes. The stressdependent permeability-models to express effect of coal matrix shrinkage/swelling using Palmer and Mansoori (P&M) and Shi and Durucan (S&D) models were constructed based on present experimental results for typical coal reservoirs with the distance of 400 to 800 m between injection and production wells. By applying the P&M and S&D models, the numerical simulation results showed that CH4 production rate was decreasing and peak production time was delayed due to effect of stress and permeability changes caused by coal matrix swelling. The total CH4 production ratio of swelling effect/no-swelling was simulated as 0.18 to 0.95 for permeability 1 to 100 mD, respectively. It has been cleared that swelling affects gas production at permeability 1 to 15 mD, however, it can be negligible at permeability over 15 mD.

Encouraging Preliminary Results of Steam Flood Pilot Project in Unconsolidated Reservoir with Strong Water Drive, Sultanate of Oman

2021 ◽  
Author(s):  
A. A. Qassabi
Keyword(s):  
Simulation Models ◽  
Pilot Project ◽  
Steam Injection ◽  
Production Performance ◽  
Surveillance Program ◽  
Sultanate Of Oman ◽  
Productivity Improvement ◽  
Cyclic Steam Stimulation ◽  
Production History ◽  
Steam Flood

Observed performance of the specially designed steam flood pilot project (implemented and currently operating in the unconsolidated, strong water drive and relatively deep of Mesozoic Sand reservoir in IXYZM Field, Sultanate of Oman) indicates encouraging results of thermal EOR. This reservoir has been produced under primary cold production with horizontal wells but production history and simulation models indicate that ultimate recovery, even with dense well spacing, will be limited to less than 15% of OOIP. Cyclic steam stimulation has been applied in several wells prior to steam flood pilot implementation to confirm steam injectivity and productivity improvement. Reservoir simulation and analytical analysis led to the design of a two-pattern pilot using 2 vertical injectors and 3 horizontal producers. Steam injection started in late 2018 and a complete surveillance program is undergoing to monitor all key parameters related to injection and production performance.

scholarly journals High-resolution pressure transducer design and associated circuitry to build a network-ready smart sensor for distributed measurement in oil and gas production wells

2022 ◽  
Author(s):  
Edval J. P. Santos ◽  
Leonardo B. M. Silva
Keyword(s):  
High Resolution ◽  
Data Acquisition ◽  
Pressure Transducer ◽  
Oil And Gas ◽  
Gas Production ◽  
Smart Sensor ◽  
Oil And Gas Production ◽  
Production Wells ◽  
Distributed Measurement ◽  
The Impact

AbstractMiniaturized single-mode thickness-shear pressure transducer combined with high-temperature SOI, silicon on insulator, integrated circuit technology is proposed as network-ready high-pressure high-resolution smart sensor for distributed data acquisition in oil and gas production wells. The transducer miniaturization is investigated with a full 3D computer model previously developed by the authors to assess the impact of intrinsic losses and various geometrical features on transducer performance. Over the last decades there has been a trend toward size reduction of high-resolution pressure transducer. The implemented model provides insight into the evolution of high-resolution pressure transducers from Hewlett-Packard™  to Quartzdyne™  and beyond. Distributed measurement in production oil wells in extreme harsh environment, such as found in the pre-salt layer, is an unsolved problem. The industry move toward electrified wells offers an opportunity for application of smart sensor technology and power line communications to achieve distributed high-resolution data acquisition.

scholarly journals The Effect of Regular and Long Cyclic Steam Stimulation Method on Oil Production Performance of RUA Field in Central Sumatera

2020 ◽  
Vol 43 (1) ◽  
pp. 7-15
Author(s):  
Intan Permatasari ◽  
Tomi Erfando ◽  
Muhammad Yogi Satria ◽  
Hardiyanto Hardiyanto ◽  
Tengku Mohammad Sofyan Astsauri
Keyword(s):  
Heavy Oil ◽  
Oil Production ◽  
High Viscosity ◽  
Production Performance ◽  
Reservoir Temperature ◽  
Cyclic Steam Stimulation ◽  
Production Wells ◽  
Production History ◽  
Stimulation Method ◽  
Cyclic Stimulation

RUA field is classified into heavy oil reservoir type due to the high viscosity value and low API degree . This causes the RUA field can not be produced conventionally. the solution of this problem is to apply steam or thermal injection into reservoir which could reduce the viscosity of the heavy oil (Bera Babadagli, 2015). One of the best EOR methods that has been proven to overcome this issue is using CSS method (Suranto et al., 2020). During the production period, the CSS process can affect the viscosity of the oil by increasing the temperature of the oil in the reservoir. In one production well, cyclic work are applied periodically, its called repeated cyclic (J. J. Sheng, 2013). This is because time of reservoir temperature stays above the baseline temperature reservoir shortly. Even though the cyclic already done repeatedly, there is still a decrease of oil production, different peak reservoir temperatures, and found the possibility of pump damage after the cycle job which led to the need for analysis on these issues. The analysis was performed by looking at the historical production data, historical reservoir temperature data, and production pump work data in the RUA field. After a production history data that reprsentative analyzed, it was found that teh production after cyclic there is increasing, and there is also a decline from the previous cyclic production. Based on the results of the production analysis, it was found that 53.24% of the production wells in the RUA field were already in the ramp down stage and 46.75% were already in the ramp-up stage. Meanwhile, the average HET for regular cyclic jobs is 3-4 months and 5-6 months for long cyclic jobs. And from the pump work data, only 3 wells were damaged. This suggests that cyclic stimulation is completely safe to be performed in this field.

scholarly journals Effect of Perforation Interval Design on Gas Production from the Validated Hydrate-Bearing Deposits with Layered Heterogeneity by Depressurization

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-20
Author(s):  
Yingli Xia ◽  
Tianfu Xu ◽  
Yilong Yuan ◽  
Xin Xin
Keyword(s):  
Energy Demand ◽  
Production Efficiency ◽  
Gas Production ◽  
Production Performance ◽  
Gas Release ◽  
Methane Recovery ◽  
Hydrate Dissociation ◽  
Gas Recovery ◽  
Hydrate Reservoir ◽  
Production Wells

Natural gas hydrate is considered as one of the best potential alternative resource to address the world’s energy demand. The available geological data at the Mallik site of Canada indicates the vertical heterogeneities of hydrate reservoir petrophysical properties. According to the logging data and sample analysis results at the Mallik 2L-38 well, a 2D model of geologically descriptive hydrate-bearing sediments was established to investigate the multiphase flow behaviors in hydrate reservoir induced by gas recovery and the effects of perforation interval on gas production performance. Firstly, the constructed model with vertical heterogeneous structures of permeability, porosity, and hydrate saturation was validated by matching the measured data in the Mallik 2007 test. The excessive residual methane in the hydrate reservoir observed in simulated results indicates insufficient gas production efficiency. For more effective methane recovery from a hydrate reservoir, the effect of perforation interval on long-term gas production performance was investigated based on the validated reservoir model. The simulation results suggest that both the location and length of the perforation interval have significant impact on hydrate dissociation behavior, while the gas production performance is mainly affected by the length of the perforation interval. To be specific, an excellent gas release performance is found in situations where the perforation interval is set at the interface between a hydrate reservoir and an underlying water-saturated zone. By increasing the perforation interval lengths of 5 m, 8 m, and 10 m, the gas release volumes from hydrate dissociation and gas production volumes from production wells are increased by 34%, 52%, and 57% and 37%, 58%, and 62%, respectively.

Key Factors in Shale Gas Modeling and Simulation

2014 ◽  
Vol 59 (4) ◽  
pp. 987-1004 ◽  
Author(s):  
Łukasz Klimkowski ◽  
Stanisław Nagy
Keyword(s):  
Shale Gas ◽  
Gas Production ◽  
Production Performance ◽  
Hydraulic Fractures ◽  
Well Performance ◽  
Key Factors ◽  
Gas Well ◽  
Well Production ◽  
Multi Stage ◽  
The Impact

Abstract Multi-stage hydraulic fracturing is the method for unlocking shale gas resources and maximizing horizontal well performance. Modeling the effects of stimulation and fluid flow in a medium with extremely low permeability is significantly different from modeling conventional deposits. Due to the complexity of the subject, a significant number of parameters can affect the production performance. For a better understanding of the specifics of unconventional resources it is necessary to determine the effect of various parameters on the gas production process and identification of parameters of major importance. As a result, it may help in designing more effective way to provide gas resources from shale rocks. Within the framework of this study a sensitivity analysis of the numerical model of shale gas reservoir, built based on the latest solutions used in industrial reservoir simulators, was performed. The impact of different reservoir and hydraulic fractures parameters on a horizontal shale gas well production performance was assessed and key factors were determined.

scholarly journals Simulation Study to Evaluate the Impact of Fracture Parameters on Shale Gas Productivity

2020 ◽  
Vol 39 (2) ◽  
pp. 432-442
Author(s):  
Abdul Majeed Shar ◽  
Waheed Ali Abro ◽  
Aftab Ahmed Mahesar ◽  
Kun Sang Lee
Keyword(s):  
Shale Gas ◽  
Gas Production ◽  
Simulation Software ◽  
Production Performance ◽  
Gas Reservoirs ◽  
Gas Reservoir ◽  
Shale Gas Reservoir ◽  
Fracture Parameters ◽  
Shale Gas Reservoirs ◽  
The Impact

The production from shale gas reservoirs has significantly increased due to technological advancements. The shale gas reservoirs are very heterogeneous and the heterogeneity has a significant effect on the quality and productivity of reservoirs. Hence, it is essential to study the behavior of such reservoirs for accurate modelling and performance prediction. To evaluate the impact of fracture parameters on shale gas reservoir productivity using CMG (Computer Modelling Group) stars simulation software was the main objective of this study. In this paper, a comprehensive analysis considering an example shale gas reservoir was conducted for production performance analysis considering uniform and non-uniform fractures configurations. Several simulations were performed by considering the multi-stage hydraulically fractured reservoir. The sensitivities conducted includes the different cases of moderate and severe heterogeneity along with variable fractures half-length, effect of changing fracture spacing, variable fracture conductivities. The simulation results showed that by increasing conductivity of fracture increases the gas production rate significantly. Moreover, cases of reservoir permeability heterogeneity were analyzed which show the significant effect on gas rate and on cumulative gas production. The results of this study can be used to improve the effectiveness in designing and developing of shale gas reservoirs and also to improve the accuracy of analyzing heterogeneous shale gas reservoir performance.

scholarly journals Reservoir modeling of New Albany Shale

2010 ◽  
Author(s):  
◽  
Amirmasoud Kalantari-Dahaghi ◽  
Keyword(s):  
Gas Production ◽  
Natural Fracture ◽  
Reservoir Modeling ◽  
Production Data ◽  
Reservoir Model ◽  
Top Down ◽  
New Albany Shale ◽  
Production History ◽  
The Impact ◽  
Western Kentucky

The intent of this study is to reassess the potential of New Albany Shale formation using a novel and integrated workflow, which incorporates field production data and well logs using a series of traditional reservoir engineering analyses complemented by artificial intelligence & data mining techniques. The model developed using this technology is a full filed model and its objective is to predict future reservoir/well performance in order to recommend field development strategies.;The impact of different reservoir characteristics such as matrix porosity, matrix permeability, initial reservoir pressure and pay thickness as well as the length and the orientation of horizontal wells on gas production in New Albany Shale have been presented.;The study was conducted using publicly available numerical model, specifically developed to simulate gas production from naturally fractured reservoirs.;The study focuses on several New Albany Shale (NAS) wells in Western Kentucky. Production from these wells is analyzed and history matched. During the history matching process, natural fracture length, density and orientations as well as fracture bedding of the New Albany Shale are modeled.;Sensitivity analysis is performed to identify the impact of reservoir characteristics and natural fracture aperture, density and length on gas production, using information found in the literature and outcrops and by performing sensitivity analysis on key reservoir and fracture parameters.;Then, the history-matched results of 87 NAS wells have been used to develop a full field reservoir model using an integrated workflow, named Top-Down, Intelligent Reservoir Modeling. In this integrated workflow unlike traditional reservoir simulation and modeling, we do not start from building a geo-cellular model. Top-Down intelligent reservoir modeling starts by analyzing the production data using traditional reservoir engineering techniques such as Decline Curve Analysis, Type Curve Matching, Single-well History Matching, Volumetric Reserve Estimation and Recovery Factor. These analyses are performed on individual wells in a multi-well New Albany Shale gas reservoir in Western Kentucky that has a reasonable production history. Data driven techniques are used to develop single-well predictive models from the production history and the well logs (and any other available geologic and petrophysical data).;Upon completion of the abovementioned analyses a large database is generated. This database includes a large number of spatio-temporal snap shots of reservoir behavior. Artificial intelligence and data mining techniques are used to fuse all these information into a cohesive reservoir model. The reservoir model is calibrated (history matched) using the production history of the most recent set of wells that have been drilled in the field. The calibrated reservoir model is utilized for predictive purposes to identify the most effective field development strategies including locations of infill wells, remaining reserves, and under-performer wells. Capabilities of this new technique, ease of use and much shorter development and analysis time are advantages of Top-Down modeling as compared to the traditional simulation and modeling.;In addition, 31 recently drilled well in Christian county Western Kentucky-Halley's Mills quadrangle have been used to perform Top-down modeling. Zone manager feature of Geographix software is used. The available production data are going to be the attributes in this feature. The contours are generated and the results have been compared with the result of Top-down modeling (Fuzzy pattern recognition). Structural map, isopach map and the other geological map has been generated using Geographix.;Additionally, in order to indentify the effect of horizontal lateral length on well productivity from New Albany Shale, fracture network has been regenerated in order to represent the distribution of natural fracture in that formation.

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