Damage Tolerance of Well-Completion and Stimulation Techniques in Coalbed Methane Reservoirs

2005 ◽  
Vol 127 (3) ◽  
pp. 248-256 ◽  
Author(s):  
Hossein Jahediesfanjani ◽  
Faruk Civan
Keyword(s):  
Coalbed Methane ◽  
Damage Tolerance ◽  
Horizontal Wells ◽  
Gas Production ◽  
Productivity Index ◽  
Dual Porosity ◽  
Formation Damage ◽  
Hydraulic Fractures ◽  
Well Completion ◽  
Reservoir Conditions

Coalbed methane (CBM) reservoirs are characterized as naturally fractured, dual porosity, low permeability, and water saturated gas reservoirs. Initially, the gas, water, and coal are at thermodynamic equilibrium under prevailing reservoir conditions. Dewatering is essential to promote gas production. This can be accomplished by suitable completion and stimulation techniques. This paper investigates the efficiency and performance of the openhole cavity, hydraulic fractures, frack and packs, and horizontal wells as potential completion methods which may reduce formation damage and increase the productivity in coalbed methane reservoirs. Considering the dual porosity nature of CBM reservoirs, numerical simulations have been carried out to determine the formation damage tolerance of each completion and stimulation approach. A new comparison parameter, named as the normalized productivity index Jnp(t) is defined as the ratio of the productivity index of a stimulated well to that of a nondamaged vertical well as a function of time. Typical scenarios have been considered to evaluate the CBM properties, including reservoir heterogeneity, anisotropy, and formation damage, for their effects on Jnp(t) over the production time. The results for each stimulation technique show that the value of Jnp(t) declines over the time of production with a rate which depends upon the applied technique and the prevailing reservoir conditions. The results also show that horizontal wells have the best performance if drilled orthogonal to the butt cleats. Long horizontal fractures improve reservoir productivity more than short vertical ones. Open-hole cavity completions outperform vertical fractures if the fracture conductivity is reduced by any damage process. When vertical permeability is much lower than horizontal permeability, production of vertical wells will improve while productivity of horizontal wells will decrease. Finally, pressure distribution of the reservoir under each scenario is strongly dependent upon the reservoir characteristics, including the hydraulic diffusivity of methane, and the porosity and permeability distributions in the reservoir.

Selection of Coal-Bed Methane Well Completion Method Based on Grey System Theory

2013 ◽  
Vol 295-298 ◽  
pp. 3171-3174
Author(s):  
Gang Yang ◽  
Zhi Ming Wang ◽  
Ru Jie Peng ◽  
Tian Chen ◽  
Zhong Xin Ren
Keyword(s):  
Coalbed Methane ◽  
Evaluation Method ◽  
Net Present Value ◽  
Gas Production ◽  
Grey System Theory ◽  
Coal Bed ◽  
Internal Rate Of Return ◽  
Grey System ◽  
Well Completion ◽  
Selection Of

Aim at the diversity of coalbed methane well completion methods, grey system is used to select completion method. Firstly, implement production prediction and economic evaluation. Then evaluate five indexes: cumulative gas production, net present value, dynamic payback period, internal rate of return and risk factor. The most appropriate completion method can be got. When apply this evaluation method to Sihe mining of Qinshui basin, results show that pinnate horizontal well is the most suitable completion method, followed by fractured vertical well.

Simultaneous Multifracture Treatments: Fully Coupled Fluid Flow and Fracture Mechanics for Horizontal Wells

SPE Journal ◽  
2014 ◽  
Vol 20 (02) ◽  
pp. 337-346 ◽  
Author(s):  
Kan Wu ◽  
Jon E. Olson
Keyword(s):  
Fluid Flow ◽  
Fracture Propagation ◽  
Horizontal Wells ◽  
Gas Production ◽  
Propagation Model ◽  
Displacement Discontinuity ◽  
Hydraulic Fractures ◽  
Multiple Fractures ◽  
Frictional Pressure Drop ◽  
Horizontal Wellbore

Summary Successfully creating multiple hydraulic fractures in horizontal wells is critical for unconventional gas production economically. Optimizing the stimulation of these wells will require models that can account for the simultaneous propagation of multiple, potentially nonplanar, fractures. In this paper, a novel fracture-propagation model (FPM) is described that can simulate multiple-hydraulic-fracture propagation from a horizontal wellbore. The model couples fracture deformation with fluid flow in the fractures and the horizontal wellbore. The displacement discontinuity method (DDM) is used to represent the mechanics of the fractures and their opening, including interaction effects between closely spaced fractures. Fluid flow in the fractures is determined by the lubrication theory. Frictional pressure drop in the wellbore and perforation zones is taken into account by applying Kirchoff's first and second laws. The fluid-flow rates and pressure compatibility are maintained between the wellbore and the multiple fractures with Newton's numerical method. The model generates physically realistic multiple-fracture geometries and nonplanar-fracture trajectories that are consistent with physical-laboratory results and inferences drawn from microseismic diagnostic interpretations. One can use the simulation results of the FPM for sensitivity analysis of in-situ and fracture treatment parameters for shale-gas stimulation design. They provide a physics-based complex fracture network that one can import into reservoir-simulation models for production analysis. Furthermore, the results from the model can highlight conditions under which restricted width occurs that could lead to proppant screenout.

scholarly journals Modeling Simultaneous Multiple Fracturing Using the Combined Finite-Discrete Element Method

Geofluids ◽  
2018 ◽  
Vol 2018 ◽  
pp. 1-20 ◽  
Author(s):  
Quansheng Liu ◽  
Lei Sun ◽  
Pingli Liu ◽  
Lei Chen
Keyword(s):  
Hydraulic Fracturing ◽  
Solid Phase ◽  
Horizontal Wells ◽  
In Situ Stress ◽  
Gas Production ◽  
Hydraulic Fractures ◽  
Multiple Fractures ◽  
Fracture Geometry ◽  
Stress Shadow ◽  
Oil Gas

Simultaneous multiple fracturing is a key technology to facilitate the production of shale oil/gas. When multiple hydraulic fractures propagate simultaneously, there is an interaction effect among these propagating hydraulic fractures, known as the stress-shadow effect, which has a significant impact on the fracture geometry. Understanding and controlling the propagation of simultaneous multiple hydraulic fractures and the interaction effects between multiple fractures are critical to optimizing oil/gas production. In this paper, the FDEM simulator and a fluid simulator are linked, named FDEM-Fluid, to handle hydromechanical-fracture coupling problems and investigate the simultaneous multiple hydraulic fracturing mechanism. The fractures propagation and the deformation of solid phase are solved by FDEM; meanwhile the fluid flow in the fractures is modeled using the principle of parallel-plate flow model. Several tests are carried out to validate the application of FDEM-Fluid in hydraulic fracturing simulation. Then, this FDEM-Fluid is used to investigate simultaneous multiple fractures treatment. Fractures repel each other when multiple fractures propagate from a single horizontal well, while the nearby fractures in different horizontal wells attract each other when multiple fractures propagate from multiple parallel horizontal wells. The in situ stress also has a significant impact on the fracture geometry.

Reservoir protection and well completion technology for multi-branch horizontal wells in coalbed methane

2021 ◽  
Vol 14 (9) ◽  
Author(s):  
Xiaofeng Ran ◽  
Bo Zhang ◽  
Wei Wei ◽  
Haifa Yu ◽  
Wenjun Liang ◽  
...  
Keyword(s):  
Coalbed Methane ◽  
Horizontal Wells ◽  
Well Completion ◽  
Reservoir Protection

Application of Real-Time Geomechanical Modeling to Prevent Wellbore Instability While Drilling Horizontal Wells with Extended Reservoir Contact

2021 ◽  
Author(s):  
Ernesto Gomez Samuel Gomez ◽  
Raider Rivas ◽  
Ebikebena Ombe ◽  
Sajjad Ahmed
Keyword(s):  
Real Time ◽  
Planning Process ◽  
Horizontal Wells ◽  
Gas Production ◽  
Wellbore Stability ◽  
Productivity Index ◽  
Rock Properties ◽  
Wellbore Instability ◽  
Hydrocarbon Reservoir ◽  
Cap Rock

Abstract Background Drilling deviated and horizontal high-pressure, high-temperature (HPHT) wells is associated with unique drilling challenges, especially when formation heterogeneity, variation in formation thickness as well as formation structural complexities are encountered while drilling. One of the major challenges encountered is the difficulty of landing horizontal lateral within the thin reservoir layers. Geomechanical modeling has proven to be a vital tool in optimizing casing setting depths and significantly increasing the possible lateral length within hydrocarbon bearing reservoirs. This approach ultimately enhanced the production output of the wells. In a particular field, the horizontal wells are constructed by first drilling 8 3/8" hole section to land about 5 to 10’ into the impervious cap rock just above the target reservoir. The 7" casing is then run and cemented in place, after which the horizontal hole section, usually a 5 7/8" lateral, is drilled by geosteered within the target reservoir to access its best porosity and permeability. Due to the uncertainty of the cap rock thickness, setting the 7" liner at this depth was necessary to avoid drilling too deep into the cap rock and penetrating the target reservoir. This approach has its disadvantages, especially while drilling the 5-7/8" lateral. Numerous drilling challenges were encountered while drilling the horizontal lateral across the hard cap rock. like severe wellbore instability, low ROP and severe drillstring vibration. To mitigate the challenges mentioned above, geomechanical modelling was introduced into the well planning process to optimize the 8 3/8" hole landing depth within the cap rock, thereby reducing the hard caprock interval to be drilled in the next section. Firstly, actual formation properties and in-situ rock stress data were obtained from logs taken in previously drilled wells in the field. This information was then fed into in the geomechanical models to produce near accurate rock properties and stresses values. Data from the formation fracture strength database was also used to calibrate the resulting horizontal stresses and formation breakdown pressure. In addition to this, the formation pore pressure variability was established with the measured formation pressure data. The porosity development information was also used to determine the best landing depths to isolate and case-off the nonreservoir formations. Combined with in-depth well placement studies to determine the optimal well trajectory and wellbore landing strategy, geomechanical modelling enabled the deepening of the 8 3/8" landing depth without penetrating the hydrocarbon reservoir. The geomechanical models were also updated with actual well data in real time and allowed for the optimization of mud weight on the fly. This strategy minimized near wellbore damage across the reservoir section and ultimately improved the wells productivity index. Deepening of the 8 3/8" landing depth and minimizing the footage drilled across the hard and unstable caprock positively impacted the overall well delivery process from well planning and drilling operations up to production. The following achievements were realized in recent wells where geomechanical modelling was applied: The initiative helped in drilling more stable, in-gauge holes across the reservoir sections, which were less prone to wellbore stability problems during drilling and logging operations.Downhole drilling tools were less exposed to harsh drilling conditions and delivered higher performance along with longer drilling runs.Better hole quality facilitated the running of multistage fracture completions which, in turn, contributed to increase the overall gas production, fulfilling the objectives of the reservoir development team.The net-to-gross ratio of the pay zone was increased, thereby improving the efficiency of the multistage fracture stages, and allowing the reservoir to be produced more efficiently.

CoalBed Methane Pad Wells Completion and Artificial Lift Optimizations: Case Study From Australia Surat Basin DS Gas Field

2021 ◽  
Author(s):  
Li Ming ◽  
Xia Zhaohui ◽  
Liu Lingli ◽  
Cui Zehong ◽  
Duan LiJiang ◽  
...  
Keyword(s):  
Coalbed Methane ◽  
Optimization Methods ◽  
Gas Production ◽  
Production Performance ◽  
Vertical Wells ◽  
Coal Seams ◽  
Gas Field ◽  
Well Completion ◽  
Artificial Lift ◽  
Coalbed Methane Production

Abstract The Coalbed Methane in Australia Surat Basin is main gas source for LNG project in east coast of Australia[1]. Traditionally, Coalbed Methane are drilled by vertical wells. But there are big intensively farmed land coverage in the Surat Basin, the multiple wells on single, larger pad from the surface, the bores slant away at around 70 degrees to intersect multiple, thin coal seams are applied to avoid the extra "footprint" and decrease the environment affect. Many pad wells production failure because of poor interburden isolation. Excessive solids production in pad wells resulted in new failures of holes in tubing due to accelerated erosion, which bring big challenges for the Coalbed methane production in deviated pad wells. The gas production in pad wells are analysised and the new pad wells optimization are proposed. First, the complete wire log (at least include GR and density log curves) need to acquire for correct thin coal seams correlation and locate the interburden sandstone position for future good sandstone isolation. Second the customized completion strategy and placement (swell packer) are applied in the pad wells and specialized tubing with enhanced erosion resistance to extend the run life. Thirdly ESP pumps and optimized tubing are installed in new deviated wells for good gas production. After the pad wells were put into production, the gas production was kept well for long time without pump problems. Swell able packer completion significantly eliminates sand problem by isolating in excess of or close to 80% of interburden sand. The above well completion and artificial lift optimization methods bring good production performance for the new pad wells and contribute much production for the producing gas field. The swellable packer completion also can be used in vertical wells and will be standard well completion methods for future gas development wells.

scholarly journals Tight carbonate gas well deliverability evaluation and reasonable production proration analysis

2021 ◽  
Author(s):  
Jiang Li ◽  
Xianchao Chen ◽  
Ping Gao ◽  
Jingchao Zhou
Keyword(s):  
Numerical Model ◽  
Stress Sensitivity ◽  
Gas Production ◽  
Productivity Index ◽  
Dual Porosity ◽  
Gas Reservoirs ◽  
Gas Well ◽  
Well Production ◽  
Tight Carbonate ◽  
Single Well

AbstractIt is very important to accurately predict the gas well productivity and reasonably allocate the gas production at the early development stage of gas reservoirs. However, both the non-Darcy and stress sensitivity effects have not been investigated in dual-porosity model of tight carbonate gas reservoirs. This paper proposed a new dual-porosity binomial deliverability model and single-well production proration numerical model, which consider the effects of non-Darcy and stress sensitivity. The field gas well deliverability tests data validated the accuracy of the new analytical model, which is a very helpful deliverability method when lacking deliverability test. A geological model was built on the results of the well log, well testing, and well production analysis. Then, a reasonable production proration analysis was conducted based on history matched single-well numerical model. The gas productivity index curve and production–prediction of MX22 several simulation cases were adopted to analyze the reasonable production proration. The results indicate that 1/6 may be suitable for high productivity gas well proration. In addition, the absolute open flow rate from the numerical simulation is higher than that from the new deliverability equation, which also shows that the pressure transient analysis sometimes has some deviation in formation property prediction. It is suggested comprehensively utilizing the analytical binomial model and the single-well numerical model in tight carbonate gas well deliverability evaluation.

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