Geo-Engineered Completion Optimization: An Integrated, Multi-Disciplinary Approach to Improve Stimulation Efficiency in Unconventional Shale Reservoirs

2015 ◽  
Author(s):  
David R. Spain ◽  
Ivan Gil ◽  
Herb Sebastian ◽  
Phil S. Smith ◽  
Jeff Wampler ◽  
...  
Keyword(s):  
Large Scale ◽  
Horizontal Well ◽  
State Of The Art ◽  
Economic Benefits ◽  
Production Performance ◽  
No Production ◽  
Natural Fractures ◽  
Well Performance ◽  
Shale Reservoirs

Abstract Large, high density fracture networks are necessary to deliver commercial production rates from sub-microdarcy permeability organic-rich shale reservoirs. Operators have increased lateral length and fracture stages as the primary means to improve well performance and, more recently, are tailoring completion techniques to local experience and reservoir-specific learning. In particular, closer fracture stage spacing or increased number of stages per well have driven improvements in well performance. Large scale adoption occurs when the change in performance is clearly linked to the reservoir-specific completion design. Horizontal well fracturing efficiency in unconventional reservoirs is notoriously poor. Numerous authors report that 40 to 60 per cent of frac stages or individual perforation clusters have been shown (albeit with highly uncertain surveillance methods) to contribute little or no production. The fracture initiation and propagation process is very complex in shale; it is affected by in-situ stress, geomechanical heterogeneity, presence of natural fractures, and completion parameters. Close cluster spacing can provide enhanced well production; however, if the spacing is too close, stress shadowing among these clusters can actually induce higher stresses, creating fracture competition. This paper presents an approach to the integration of these parameters through both state-of-the-art geological characterization and unconventional 3D hydraulic fracture modeling. We couple stochastic discrete fracture network (DFN) models of in-situ natural fractures with a state-of-the art 3D unconventional fracture simulator. The modeled fracture geometry and associated conductivity is exported into a dynamic reservoir flow model, for production performance prediction. Calibrated toolkits and workflows, underpinned by integrated surveillance including distributed temperature and acoustic fiber optic sensing (DTS/DAS), are used to optimize horizontal well completions. A case study is presented which demonstrates the technical merits and economic benefits of using this multidisciplinary approach to completion optimization.

scholarly journals Extrinsic Camera Calibration with Line-Laser Projection

Sensors ◽  
2021 ◽  
Vol 21 (4) ◽  
pp. 1091
Author(s):  
Izaak Van Crombrugge ◽  
Rudi Penne ◽  
Steve Vanlanduit
Keyword(s):  
Camera Calibration ◽  
Real World ◽  
Large Scale ◽  
State Of The Art ◽  
Bundle Adjustment ◽  
Field Of View ◽  
Extrinsic Calibration ◽  
Practical Procedure ◽  
Partial Overlap

Knowledge of precise camera poses is vital for multi-camera setups. Camera intrinsics can be obtained for each camera separately in lab conditions. For fixed multi-camera setups, the extrinsic calibration can only be done in situ. Usually, some markers are used, like checkerboards, requiring some level of overlap between cameras. In this work, we propose a method for cases with little or no overlap. Laser lines are projected on a plane (e.g., floor or wall) using a laser line projector. The pose of the plane and cameras is then optimized using bundle adjustment to match the lines seen by the cameras. To find the extrinsic calibration, only a partial overlap between the laser lines and the field of view of the cameras is needed. Real-world experiments were conducted both with and without overlapping fields of view, resulting in rotation errors below 0.5°. We show that the accuracy is comparable to other state-of-the-art methods while offering a more practical procedure. The method can also be used in large-scale applications and can be fully automated.

scholarly journals Production Rate Analysis of Fractured Horizontal Well considering Multitransport Mechanisms in Shale Gas Reservoir

Geofluids ◽  
2018 ◽  
Vol 2018 ◽  
pp. 1-17 ◽  
Author(s):  
Qi-guo Liu ◽  
Wei-hong Wang ◽  
Hua Liu ◽  
Guangdong Zhang ◽  
Long-xin Li ◽  
...  
Keyword(s):  
Production Rate ◽  
Shale Gas ◽  
Horizontal Well ◽  
Production Performance ◽  
Natural Fractures ◽  
Gas Reservoir ◽  
Isothermal Adsorption ◽  
Well Production ◽  
Shale Gas Reservoir ◽  
Fractured Horizontal Well

Shale gas reservoir has been aggressively exploited around the world, which has complex pore structure with multiple transport mechanisms according to the reservoir characteristics. In this paper, a new comprehensive mathematical model is established to analyze the production performance of multiple fractured horizontal well (MFHW) in box-shaped shale gas reservoir considering multiscaled flow mechanisms (ad/desorption and Fick diffusion). In the model, the adsorbed gas is assumed not directly diffused into the natural macrofractures but into the macropores of matrix first and then flows into the natural fractures. The ad/desorption phenomenon of shale gas on the matrix particles is described by a combination of the Langmuir’s isothermal adsorption equation, continuity equation, gas state equation, and the motion equation in matrix system. On the basis of the Green’s function theory, the point source solution is derived under the assumption that gas flow from macropores into natural fractures follows transient interporosity and absorbed gas diffused into macropores from nanopores follows unsteady-state diffusion. The production rate expression of a MFHW producing at constant bottomhole pressure is obtained by using Duhamel’s principle. Moreover, the curves of well production rate and cumulative production vs. time are plotted by Stehfest numerical inversion algorithm and also the effects of influential factors on well production performance are analyzed. The results derived in this paper have significance to the guidance of shale gas reservoir development.

Comparison of Fractured-Horizontal-Well Performance in Tight Sand and Shale Reservoirs

2011 ◽  
Vol 14 (02) ◽  
pp. 248-259 ◽  
Author(s):  
E.. Ozkan ◽  
M Brown ◽  
R.. Raghavan ◽  
H.. Kazemi
Keyword(s):  
Hydraulic Fracture ◽  
Horizontal Well ◽  
Flow Model ◽  
Horizontal Wells ◽  
Natural Fracture ◽  
Well Performance ◽  
Fracture Conductivity ◽  
Fractured Horizontal Well ◽  
Shale Reservoirs ◽  
Fractured Horizontal Wells

Summary This paper presents a discussion of fractured-horizontal-well performance in millidarcy permeability (conventional) and micro- to nanodarcy permeability (unconventional) reservoirs. It provides interpretations of the reasons to fracture horizontal wells in both types of formations. The objective of the paper is to highlight the special productivity features of unconventional shale reservoirs. By using a trilinear-flow model, it is shown that the drainage volume of a multiple-fractured horizontal well in a shale reservoir is limited to the inner reservoir between the fractures. Unlike conventional reservoirs, high reservoir permeability and high hydraulic-fracture conductivity may not warrant favorable productivity in shale reservoirs. An efficient way to improve the productivity of ultratight shale formations is to increase the density of natural fractures. High natural-fracture conductivities may not necessarily contribute to productivity either. Decreasing hydraulic-fracture spacing increases the productivity of the well, but the incremental production gain for each additional hydraulic fracture decreases. The trilinear-flow model presented in this work and the information derived from it should help the design and performance prediction of multiple-fractured horizontal wells in shale reservoirs.

scholarly journals Numerical Simulation Investigation on Well Performance Integrated Stress Sensitivity and Sand Production

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-11
Author(s):  
Chong Cao ◽  
Linsong Cheng ◽  
Xiangyang Zhang ◽  
Junjie Shi
Keyword(s):  
Numerical Model ◽  
Horizontal Well ◽  
Plastic Region ◽  
Quantitative Description ◽  
Outer Zone ◽  
Stress Sensitivity ◽  
Production Performance ◽  
Oil Well ◽  
Well Performance ◽  
Sand Production

For unconsolidated sanding wells, the interaction between sanding and pressure-dependent permeability as oil is produced from the bottom of the well puts higher challenges on the evaluation and prediction of well performance. Therefore, it is essential to assess the oil well performance considering the synthetic effect of stress-sensitive and produced sand particles. In this paper, a new stress-sensitive factor is proposed to describe the relationship between stress and permeability in the numerical model. Also, based on the rectangular plastic region by the sand migration near the perforation, a quantitative expression of the sanding area for numerical model calculation was established. Combined with a quantitative description of these two key parameters, a sand-producing horizontal well model is established to evaluate production performance. In this model, the area of sand production near the wellbore is considered as the inner area with increased permeability while the outer zone remains the original reservoir. Besides, the model was verified by the production data from the sand-producing horizontal well in the oilfield. Furthermore, sensitivity parameters (such as stress sensitivity, the size of sanding zone, well location, and reservoir boundaries) are used to make the analysis of well productivity, which provides a theoretical basis for petroleum engineers to adjust the development plan for horizontal wells in the weakly consolidated sandstone reservoir.

scholarly journals Effects of Diffusion, Adsorption, and Hysteresis on Huff-n-Puff Performance in Ultratight Reservoirs with Different Fluid Types and Injection Gases

Energies ◽  
2021 ◽  
Vol 14 (21) ◽  
pp. 7379
Author(s):  
Khaled Enab ◽  
Hamid Emami-Meybodi
Keyword(s):  
Oil Recovery ◽  
Large Scale ◽  
Volatile Oil ◽  
Production Performance ◽  
Compositional Model ◽  
Reservoir Fluid ◽  
Wide Range ◽  
Black Oil ◽  
Shale Reservoirs ◽  
The Impact

Cyclic solvent injection, known as solvent huff-n-puff, is one of the promising techniques for enhancing oil recovery from shale reservoirs. This study investigates the huff-n-puff performance in ultratight shale reservoirs by conducting large-scale numerical simulations for a wide range of reservoir fluid types (retrograde condensate, volatile oil, and black oil) and different injection gases (CO2, C2H6, and C3H8). A dual-porosity compositional model is utilized to comprehensively evaluate the impact of multicomponent diffusion, adsorption, and hysteresis on the production performance of each reservoir fluid and the retention capacity of the injection gases. The results show that the huff-n-puff process improves oil recovery by 4–6% when injected with 10% PV of gas. Huff-n-puff efficiency increases with decreasing gas-oil ratio (GOR). C2H6 provides the highest recovery for the black oil and volatile oil systems, and CO2 provides the highest recovery for retrograde condensate fluid type. Diffusion and adsorption are essential mechanisms to be considered when modeling gas injection in shale reservoirs. However, the relative permeability hysteresis effect is not significant. Diffusion impact increases with GOR, while adsorption impact decreases with increasing GOR. Oil density reduction caused by diffusion is observed more during the soaking period considering that the diffusion of the injected gas caused a low prediction error, while adsorption for the injected gas showed a noticeable error.

scholarly journals PRODUCTIVITY PREDICTION OF FRACTURED HORIZONTAL WELLS WITH LOW PERMEABILITY FLOW CHARACTERISTICS

2019 ◽  
Vol 27 (2) ◽  
pp. 82-92
Author(s):  
Wen Jing ◽  
Luo Wei ◽  
Yin Qingguo ◽  
Wang Hongying ◽  
He Yongming ◽  
...  
Keyword(s):  
Large Scale ◽  
Horizontal Well ◽  
Superposition Principle ◽  
Economic Benefits ◽  
Low Permeability ◽  
Fractured Horizontal Well ◽  
Proposed Model ◽  
Seepage Model ◽  
Productivity Prediction ◽  
Low Permeability Reservoirs

Horizontal well and large-scale fracturing are revolutionary technologies in petroleum industry. The technologies bring obvious economic benefits to exploiting unconventional oil and gas reservoirs with low permeability, ultra-low permeability and shale gas. With the increasingly extensive application of these technologies, other correlated technologies have also gained great development. However, low-permeability reservoirs exhibit complicated features and horizontal well fractures have complex shape. The existing methods for the productivity prediction of fractured horizontal well in low-permeability reservoirs rarely consider the influencing factors in a comprehensive manner. In this paper, a horizontal well seepage model of casing fracturing completion was established according to the superposition principle of low-permeability reservoir and the relationship between potential and pressure, by which model the seepage characteristics of low-permeability reservoirs could be fully described. Based on the established new seepage model, a new targeted model with coupling seepage and wellbore flow was established for the productivity prediction of low-permeability fractured horizontal well. Finally, the new targeted model was verified through field experiment. The experimental results confirmed the reliability of productivity prediction by the proposed model. Sensitivity analysis was then performed on the parameters in the proposed model.

Using geomechanical modeling to quantify the impact of natural fractures on well performance and microseismicity: Application to the Wolfcamp, Permian Basin, Reagan County, Texas

2016 ◽  
Vol 4 (2) ◽  
pp. SE1-SE15 ◽  
Author(s):  
Ahmed Ouenes ◽  
Nicholas M. Umholtz ◽  
Yamina E. Aimene
Keyword(s):  
Empirical Relationship ◽  
Production Performance ◽  
Fault System ◽  
Fracture Density ◽  
Natural Fractures ◽  
Well Performance ◽  
Optimal Position ◽  
Complex Fault ◽  
Quantitative Impact ◽  
The Impact

We have evaluated workflows to quantify the mechanical impact of natural fractures (NFs) on the production performance of hydraulically stimulated stages in shale wells. Variations in fracture orientation and density can enhance or degrade the transport and effectiveness of fracturing fluids. Specifically, we studied the effect of a complex fault splay system on a horizontal Wolfcamp B reservoir well. A general workflow that combines geophysics, geology, and geomechanics (3G) was evaluated and applied to the well. The benefits of the 3G workflow are threefold. First, the quantitative impact of the NFs on the regional stress is provided through the differential horizontal stress variation, which impacts fracturing complexity. Then, the reservoir strain map, validated with microseismic data, gives insights into the stimulated drainage pathways. Finally, the ability of the [Formula: see text] integral to predict poor hydraulic fracturing stages as a function of fracture density along the wellbore or as a function of the energy required to propagate a fracture. Building on the validated 3G workflow, a well placement workflow that takes into account the quantitative impact of NFs on well performance was developed on the sample Wolfcamp well. By comparing the [Formula: see text] integral of the same completion stage in simulations with and without NFs, stages with similar [Formula: see text] integral values in both simulations were identified as those not being affected by the NF network. This allows the workflow to provide the optimal position of a well in the presence of NFs associated with a complex fault system that may produce undesirable water. The result is a validated 3G workflow that provides a geomechanical explanation for an empirical relationship showing that high oil production is achieved within a “Goldilocks” range of natural fracturing.

scholarly journals Evaluation of Reservoir Quality and Forecasted Production Variability along a Multi-Fractured Horizontal Well. Part 2: Selected Stage Forecasting

Energies ◽  
2021 ◽  
Vol 14 (19) ◽  
pp. 6007 ◽  
Author(s):  
Christopher R. Clarkson ◽  
Zhenzihao Zhang ◽  
Farshad Tabasinejad ◽  
Daniela Becerra ◽  
Amin Ghanizadeh
Keyword(s):  
History Matching ◽  
Horizontal Well ◽  
Production Performance ◽  
Reservoir Quality ◽  
Well Performance ◽  
Fracture Geometry ◽  
Fractured Horizontal Well ◽  
Production Variability ◽  
Montney Formation ◽  
Low Permeability Reservoirs

The current practice for multi-fractured horizontal well development in low-permeability reservoirs is to complete the full length of the well with evenly spaced fracture stages. Given methods to evaluate along-well variability in reservoir quality and to predict stage-by-stage performance, it may be possible to reduce the number of stages completed in a well without a significant sacrifice in well performance. Provision and demonstration of these methods is the goal of the current two-part study. In Part 1 of this study, reservoir and completion quality were evaluated along the length of a horizontal well in the Montney Formation in western Canada. In the current (Part 2) study, the along-well reservoir property estimates are first used to forecast per-stage production variability, and then used to evaluate production performance of the well when fewer stages are completed in higher quality reservoir. A rigorous and fast semi-analytical model was used for forecasting, with constraints on fracture geometry obtained from numerical model history matching of the studied Montney well flowback data. It is concluded that a significant reduction in the number of stages from 50 (what was implemented) to less than 40 could have yielded most of the oil production obtained over the forecast period.

scholarly journals An Analytical Framework for Stress Shadow Analysis During Hydraulic Fracturing – Applied to the Bakken Formation, Saskatchewan, Canada

2021 ◽  
Author(s):  
Mostafa Gorjian ◽  
Sepidehalsadat Hendi ◽  
Christopher D. Hawkes
Keyword(s):  
Hydraulic Fracturing ◽  
Large Scale ◽  
Shear Failure ◽  
Microseismic Monitoring ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Bakken Formation ◽  
Stress Shadow

Abstract. This paper presents selected results of a broader research project pertaining to the hydraulic fracturing of oil reservoirs hosted in the siltstones and fine grained sandstones of the Bakken Formation in southeast Saskatchewan, Canada. The Bakken Formation contains significant volumes of hydrocarbon, but large-scale hydraulic fracturing is required to achieve economic production rates. The performance of hydraulic fractures is strongly dependent on fracture attributes such as length and width, which in turn are dependent on in-situ stresses. This paper reviews methods for estimating changes to the in-situ stress field (stress shadow) resulting from mechanical effects (fracture opening), poro-elastic effects, and thermo-elastic effects associated with fluid injection for hydraulic fracturing. The application of this method is illustrated for a multi-stage hydraulic fracturing operation, to predict principal horizontal stress magnitudes and orientations at each stage. A methodology is also presented for using stress shadow models to assess the potential for inducing shear failure on natural fractures. The results obtained in this work suggest that thermo and poro-elastic stresses are negligible for hydraulic fracturing in the Bakken Formation of southeast Saskatchewan, hence a mechanical stress shadow formulation is used for analyzing multistage hydraulic fracture treatments. This formulation (and a simplified version of the formulation) predicts an increase in instantaneous shut-in pressure (ISIP) that is consistent with field observations (i.e., ISIP increasing from roughly 21.6 MPa to values slightly greater than 26 MPa) for a 30-stage fracture treatment. The size of predicted zones of shear failure on natural fractures are comparable with the event clouds observed in microseismic monitoring when assumed values of 115°/65° are used for natural fracture strike/dip; however, more data on natural fracture attributes and more microseismic monitoring data for the area are required before rigorous assessment of the model is possible.

Multistage Horizontal Well Hydraulic Fracturing Stimulation Using Coiled Tubing to Produce Marginal Reserves from Brownfield: Case Histories and Lessons Learned

2015 ◽  
Author(s):  
Amro Hassan ◽  
Ahmed Abd ElMeguid ◽  
Arshad Waheed ◽  
Mohamed Salah ◽  
Essam Abd ElKarim
Keyword(s):  
Hydraulic Fracturing ◽  
Horizontal Well ◽  
Economic Benefits ◽  
Lessons Learned ◽  
Western Desert ◽  
Low Permeability ◽  
Successful Implementation ◽  
Well Performance ◽  
Artificial Lift ◽  
Low Permeability Reservoirs

Abstract The Baharyia formation is a common reservoir in the Western Desert of Egypt. It is characterized as a heterogeneous reservoir with low sand quality. It is comprised of fine-grained sandstone, thin, laminated, sand-poor parasequences with shale interbeds. The heterogeneity and low permeability of the Upper Baharyia reservoirs are the primary challenges to maintaining economic well productivity. The interest in developing low permeability reservoirs stems from favorable economics attributed to advancements in horizontal well drilling and hydraulic fracturing technology, offering methods to increase production by increasing the contact area of the producing interval. Subsequently, it became apparent that wellbore contact alone was not always sufficient for providing production increases expected, thus requiring multistage hydraulic fracturing (MSHF) stimulation treatments to achieve production targets. Primary well production analysis revealed that the cumulative production from the horizontal well discussed was enhanced from 37 to 70% of recoverable reserve and the recovery factor was doubled. From a production analogy standpoint, these resulted in reduced drilling of three vertical wells and had direct economic benefits by reducing the installed artificial lift strings, related expensive artificial lift equipment repairs, and the number of necessary workovers. This paper takes a multidisciplinary approach to help understand productivity enhancement of low permeability reservoirs in the Western Desert of Egypt, through a detailed analysis of well performance and successful implementation of MSHF in horizontal wells to maximize drainage volume around the well. It is intended to serve as guidelines to help operators facing similar challenges.

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