Hydraulic fractures productivity performance in tight gas sands—a numerical simulation approach

2011 ◽  
Vol 51 (1) ◽  
pp. 519
Author(s):  
Jakov Ostojic ◽  
Reza Rezaee ◽  
Hassan Bahrami
Keyword(s):  
Hydraulic Fracture ◽  
Effective Field ◽  
Gas Production ◽  
Simulation Software ◽  
Hydraulic Fractures ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Gas Recovery ◽  
Single Well ◽  
The Impact

The increasing global demand for energy along with the reduction in conventional gas reserves has lead to the increasing demand and exploration of unconventional gas sources. Hydraulically-fractured tight gas reservoirs are one of the most common unconventional sources being produced today and look to be a regular source of gas in the future. Hydraulic fracture orientation and spacing are important factors in effective field drainage and gas recovery. This paper presents a 3D single well hydraulically fractured tight gas model created using commercial simulation software, which will be used to simulate gas production and synthetically generate welltest data. The hydraulic fractures will be simulated with varying sizes and different numbers of fractures intersecting the wellbore. The focus of the simulation runs will be on the effect of hydraulic fracture size and spacing on well productivity performance. The results obtained from the welltest simulations will be plotted and used to understand the impact on reservoir response under the different hydraulic fracturing scenarios. The outputs of the models can also be used to relate welltest response to the efficiency of hydraulic fractures and, therefore, productivity 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.

scholarly journals Analysis of hydraulic fracture behavior and well pattern optimization in anisotropic coal reservoirs

2020 ◽  
pp. 014459872096083
Author(s):  
Yulong Liu ◽  
Dazhen Tang ◽  
Hao Xu ◽  
Wei Hou ◽  
Xia Yan
Keyword(s):  
Hydraulic Fracture ◽  
Coalbed Methane ◽  
Fracture Network ◽  
Simulation Software ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Well Pattern ◽  
Well Pattern Optimization ◽  
The Impact

Macrolithotypes control the pore-fracture distribution heterogeneity in coal, which impacts stimulation via hydrofracturing and coalbed methane (CBM) production in the reservoir. Here, the hydraulic fracture was evaluated using the microseismic signal behavior for each macrolithotype with microfracture imaging technology, and the impact of the macrolithotype on hydraulic fracture initiation and propagation was investigated systematically. The result showed that the propagation types of hydraulic fractures are controlled by the macrolithotype. Due to the well-developed natural fracture network, the fracture in the bright coal is more likely to form the “complex fracture network”, and the “simple” case often happens in the dull coal. The hydraulic fracture differences are likely to impact the permeability pathways and the well productivity appears to vary when developing different coal macrolithtypes. Thus, considering the difference of hydraulic fracture and permeability, the CBM productivity characteristics controlled by coal petrology were simulated by numerical simulation software, and the rationality of well pattern optimization factors for each coal macrolithotype was demonstrated. The results showed the square well pattern is more suitable for dull coal and semi-dull coal with undeveloped natural fractures, while diamond and rectangular well pattern is more suitable for semi-bright coal and bright coal with more developed natural fractures and more complex fracturing fracture network; the optimum wells spacing of bright coal and semi-bright coal is 300 m and 250 m, while that of semi-dull coal and dull coal is just 200 m.

scholarly journals Gas-Water Flow Behavior in Water-Bearing Tight Gas Reservoirs

Geofluids ◽  
2017 ◽  
Vol 2017 ◽  
pp. 1-16 ◽  
Author(s):  
Renyi Cao ◽  
Liyou Ye ◽  
Qihong Lei ◽  
Xinhua Chen ◽  
Y. Zee Ma ◽  
...  
Keyword(s):  
Water Saturation ◽  
Flow Behavior ◽  
Stress Sensitivity ◽  
Gas Production ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Threshold Pressure Gradient ◽  
Tight Gas Reservoirs ◽  
Gas Recovery ◽  
Mobile Water

Some tight sandstone gas reservoirs contain mobile water, and the mobile water generally has a significant impact on the gas flowing in tight pores. The flow behavior of gas and water in tight pores is different than in conventional formations, yet there is a lack of adequate models to predict the gas production and describe the gas-water flow behaviors in water-bearing tight gas reservoirs. Based on the experimental results, this paper presents mathematical models to describe flow behaviors of gas and water in tight gas formations; the threshold pressure gradient, stress sensitivity, and relative permeability are all considered in our models. A numerical simulator using these models has been developed to improve the flow simulation accuracy for water-bearing tight gas reservoirs. The results show that the effect of stress sensitivity becomes larger as water saturation increases, leading to a fast decline of gas production; in addition, the nonlinear flow of gas phase is aggravated with the increase of water saturation and the decrease of permeability. The gas recovery decreases when the threshold pressure gradient (TPG) and stress sensitivity are taken into account. Therefore, a reasonable drawdown pressure should be set to minimize the damage of nonlinear factors to gas recovery.

scholarly journals History Matching and Forecast of Shale Gas Production Considering Hydraulic Fracture Closure

Energies ◽  
2019 ◽  
Vol 12 (9) ◽  
pp. 1634 ◽  
Author(s):  
Juhyun Kim ◽  
Youngjin Seo ◽  
Jihoon Wang ◽  
Youngsoo Lee
Keyword(s):  
Shale Gas ◽  
Hydraulic Fracture ◽  
History Matching ◽  
Gas Flow ◽  
Fluid Pressure ◽  
Gas Production ◽  
Hydraulic Fractures ◽  
Gas Reservoirs ◽  
Shale Gas Reservoirs ◽  
Fracture Closure

Most shale gas reservoirs have extremely low permeability. Predicting their fluid transport characteristics is extremely difficult due to complex flow mechanisms between hydraulic fractures and the adjacent rock matrix. Recently, studies adopting the dynamic modeling approach have been proposed to investigate the shape of the flow regime between induced and natural fractures. In this study, a production history matching was performed on a shale gas reservoir in Canada’s Horn River basin. Hypocenters and densities of the microseismic signals were used to identify the hydraulic fracture distributions and the stimulated reservoir volume. In addition, the fracture width decreased because of fluid pressure reduction during production, which was integrated with the dynamic permeability change of the hydraulic fractures. We also incorporated the geometric change of hydraulic fractures to the 3D reservoir simulation model and established a new shale gas modeling procedure. Results demonstrate that the accuracy of the predictions for shale gas flow improved. We believe that this technique will enrich the community’s understanding of fluid flows in shale gas reservoirs.

MASSIVE HYDRAULIC FRACTURE STIMULATION OF EARLY PERMIAN GAS RESERVOIRS, BIG LAKE FIELD, COOPER BASIN

1984 ◽  
Vol 24 (1) ◽  
pp. 180
Author(s):  
D. J. Stanley ◽  
G. Halliday
Keyword(s):  
Hydraulic Fracture ◽  
Joint Venture ◽  
Oil And Gas ◽  
Gas Production ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Potential Resource ◽  
Primary Porosity ◽  
Initial Results ◽  
Cooper Basin

In 1981, South Australian Oil and Gas Corporation Pty Ltd commenced a project to apply Massive Hydraulic Fracture (MHF) technology to the tight gas reservoirs of the Tirrawarra and Patchawarra Formations of the Big Lake Field. Four wells had defined the potential at depths of 8500-10 000 ft (2500-3000 m) in the early 1970s but early attempts to stimulate gas production were unsuccessful.The Tirrawarra Sandstone, as a massive unit of 120-200 ft (35-60 m) thickness, was a prime candidate. The Patchawarra sandstones, ranging up to 40 ft (12 m) thick and interbedded with shales and coals, presented a more difficult problem.Petrologic analysis disclosed quartz sandstones in which the pore system consists mainly of large irregularly shaped dissolution pores. Diagenesis has destroyed primary porosity and precipitated authigenic illite, illite-smectite, kaolinite and siderite. The gas contains 32 per cent CO2 and is very dry. Temperatures are close to 400°F (200°C). The formations are overpressured.The project has drilled two wells, Big Lake 26 and 27, and applied two MHF treatments in Big Lake 26. One further MHF remains to be done in Big Lake 27. Each MHF treatment has been tailored to the particular petrologic, reservoir, stratigraphic, pressure and temperature conditions of that zone. The tailoring of MHF design has been further refined by running a 'mini-frac' with 10 000 gal (45 000 L) of fluid. MHF designs have involved up to 620 000 lb (280 000 kg) of sand, 60 000 lb (27 000 kg) of sintered bauxite and 300 000 gal (1350 kL) of gel. Having management on-site to react to aberrations and vary the design has been important in operations.One Tlrrawarra Sandstone MHF has been unsuccessful (as predicted) and the other, on initial results, appears highly successful. The Patchawarra Formation MHF speared off into a coal but appears moderately successful. Long-term flow tests will provide definitive results.Encouraged by these initial results, the Joint Venture Partners have drilled two further wells in the Big Lake Field which await MHF treatment. The gas-in-place is estimated at about 1.5 trillion cubic feet (42.5 billion cubic metres). Three other tight gas prospects of similar size, Burley, McLeod and Kirby, have been identified. The size of this potential resource provides a strong incentive to attempt to make MHF treatments economically viable in the Cooper Basin.

The effect of hydraulic-fracture parameters on the welltest response of multi-fractured tight-gas reservoirs

2013 ◽  
Vol 53 (1) ◽  
pp. 375
Author(s):  
Chaolang Qiu ◽  
Mofazzal Hossain ◽  
Hassan Bahrami ◽  
Yangfan Lu
Keyword(s):  
Hydraulic Fracture ◽  
Transient Flow ◽  
Hydraulic Fractures ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Pressure Derivative ◽  
Unconventional Gas ◽  
Tight Gas Reservoirs ◽  
Fracture Parameters ◽  
Unconventional Gas Reservoirs

With the reduction of conventional reserves, the demand and exploration of unconventional sources becomes increasingly important in the energy supply system. Low permeability, low porosity, and the complexities of rock formation in unconventional gas reservoirs make it difficult to extract commercially viable gas resources. Hydraulic fracture is the most common technique used for commercial production of hydrocarbon resources from unconventional tight-gas reservoirs. Due to the existence of an extremely long transient-flow period in tight-gas reservoirs, the interpretation of welltest data based on conventional welltest analysis is quite challenging, and could potentially lead to misleading results. This peer-reviewed paper presents a new approach based on a log-log reciprocal rate derivative plot. Emphases are given on the identification of factors affecting the welltest response in multiple hydraulic-fractured wells in unconventional gas reservoirs based on numerical simulation. The objective is to investigate the sensitivity of various reservoir and hydraulic-fracture parameters, such as multiple hydraulic-fracture size, fracture number and fracture orientation on welltest response, and the effect of the pressure derivative curve on the slopes of welltest diagnostic plots, as well as on well productivity performance. The results can be used to understand the welltest response for different hydraulic-fracturing scenarios for the efficiency and characteristics of hydraulic fractures.

scholarly journals Shallow Formation Hydrofracture Mapping Experiment

1978 ◽  
Vol 100 (1) ◽  
pp. 24-27
Author(s):  
L. J. Keck ◽  
C. L. Schuster
Keyword(s):  
Diagnostic Techniques ◽  
Small Scale ◽  
Hydraulic Fractures ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Model Calculations ◽  
Gas Recovery ◽  
Electrical Potentials ◽  
Fracture Fluid ◽  
Production Company

Geophysical diagnostic techniques are being developed to characterize the massive hydraulic fractures that are being utilized for the enhanced gas recovery from the Western tight gas reservoirs. Sandia Laboratories is developing a system based on the measurement of surface electrical potentials. Model calculations indicate that the electrical potentials produced by direct electrical excitation of the fracture well and the fracture fluid can be used to determine the direction and asymmetry of a massive fracture. A small scale, shallow formation hydrofracture experiment was conducted by the AMOCO Production Company in an attempt to better correlate theoretical and experimental data.

scholarly journals Analysis on the effect of different fracture geometries on the productivity of tight gas reservoirs

2020 ◽  
Vol 16 (2) ◽  
pp. 201-211
Author(s):  
Temoor Muther ◽  
Adnan Aftab Nizamani ◽  
Abdul Razak Ismail
Keyword(s):  
Hydraulic Fracture ◽  
Constant Width ◽  
Hydraulic Fractures ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Fracture Geometry ◽  
Tight Gas Reservoirs ◽  
Constant Height ◽  
Tight Gas Reservoir ◽  
Half Length

Tight gas reservoirs are unconventional reservoir assets which have been the focus of major research in the petroleum industry owing to the global decline in conventional reservoirs. They are widely unlocked by creating hydraulic fractures in the formation to increase the flow capacity and productivity. The objective of this paper is to analyze different fracture geometries and their effect on tight gas production. The reservoir simulation model of the tight gas reservoir has been built with single porosity approach. A single vertical well with a single stage fracture has been used in the model to predict the behavior of fracture geometry. The major parameters of fracture geometry studied are fracture half-length, fracture width, and fracture height. Four sensitivities are run over different fracture geometry that is constant height and constant width, constant height and changing width, changing height and constant width, and changing height and changing width, while increasing the fracture half-length from 100 ft to 500 ft in each case. Sensitivity analysis exhibited that keeping the hydraulic fracture at constant height and constant width while increasing the fracture half-length resulted in enhanced tight gas productivity i.e. 11.63%, 14.14%, 16.06%, 17.48%, and 18.89% at hydraulic fracture half-lengths of 100 ft, 200 ft, 300 ft, 400 ft, and 500 ft, respectively, compared to other types of fracture geometry.

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.

Modeling Fracture-Fluid Cleanup in Tight-Gas Wells

SPE Journal ◽  
2010 ◽  
Vol 15 (03) ◽  
pp. 783-793 ◽  
Author(s):  
John Yilin* Wang ◽  
Stephen A. Holditch ◽  
Duane A. McVay
Keyword(s):  
Reservoir Simulation ◽  
Gas Production ◽  
Base Case ◽  
Tight Gas ◽  
Gas Wells ◽  
Gas Reservoirs ◽  
Data Set ◽  
Gas Recovery ◽  
Modeling Fracture ◽  
Fracture Fluid

Summary On occasion, a hydraulically fractured tight-gas well does not perform up to its potential because of slow or incomplete fracture- fluid cleanup. A number of papers have been written to address individual factors related to fracture-fluid cleanup, but many questions as to which factors mostly affect gas production from such wells remain unanswered. Numerical reservoir simulation is one of the best methods to study the fracture-fluid-cleanup problem. Continuing from our previous publication (Wang et al. 2008) on the effect of gel damage on fracture cleanup, we used reservoir simulation to analyze systematically the factors that affect fracture- fluid cleanup and gas recovery from tight-gas wells. We first developed a comprehensive data set for typical tight gas reservoirs and then ran single-phase-flow cases for each reservoir and fracture scenario to establish the idealized base-case gas recovery. We then systematically evaluated the following factors: multiphase gas and water flow, proppant crushing, polymer filter cake, and, finally, yield stress of concentrated gel in the fracture. The gel in the fracture is concentrated because of fluid leakoff during the fracture treatment. We evaluated these factors additively in the order listed. We found that the most important factor that reduces fracture-fluid cleanup and gas recovery is the gel strength of the fluid that remains in the fracture at the end of the treatment. This paper illustrates the complexity of the fracture-fluid- cleanup problem and points out the need to use reservoir simulation and to include all the pertinent factors to model fracture-fluid cleanup rigorously. The procedures presented can provide a useful, systematic guide to engineers in conducting a numerical simulation study of fracture-fluid cleanup.

Sign in / Sign up

Export Citation Format

Share Document