Experimental Research for Breakthrough Position of Horizontal Wells in Reservoirs with Bottom Water

2012 ◽  
Vol 524-527 ◽  
pp. 1232-1235 ◽  
Author(s):  
Li Feng Li ◽  
Xiang An Yue ◽  
Li Juan Zhang
Keyword(s):  
Pressure Drop ◽  
Bottom Water ◽  
Horizontal Wells ◽  
Concave Part ◽  
Entry Points ◽  
Heterogeneous Models ◽  
Two Factors ◽  
Well Trajectory ◽  
Trajectory Models ◽  
Swept Area

Finding the breakthrough position of horizontal wells is essential to water plugging and improving oil production in bottom water drive reservoirs. Physical modeling was carried out in this paper to research the law of bottom water’s movement. The experimental results indicated that: pressure drop in wells, well trajectory and area reservoir heterogeneity were all sensitive factors for breakthrough of bottom water, and the entry points of horizontal wells were determined by the combined function of them. In different well trajectory models, the concave down part of the well cooperate with pressure drop influenced the breakthrough position. Bottom water below the heel end reached the well earliest if the concave down part located at the heel end. When the concave part located at the middle of the well, the two factors played role respectively which resulted in breaking through of bottom water at two places with larger swept area. In different heterogeneous models, permeability difference and pressure drop were both favorable factors for bottom water’s non-uniformly rise. In the model that the heel end located at high permeability part, bottom water under the heel end reached the well earliest. If the heel end was set at the low permeability part, the breakthrough of bottom water occurred at the middle of the well.

Effects of Pressure Drop in Horizontal Wells and Optimum Well Length

SPE Journal ◽  
1999 ◽  
Vol 4 (03) ◽  
pp. 215-223 ◽  
Author(s):  
V.R. Penmatcha ◽  
Sepehr Arbabi ◽  
Khalid Aziz
Keyword(s):  
Pressure Drop ◽  
Horizontal Wells

Comprehensive Analysis of Production Loggings in Fuling Shale Gas Play in China

2021 ◽  
Author(s):  
Yaowen Liu ◽  
Wei Pang ◽  
Jincai Shen ◽  
Ying Mi
Keyword(s):  
Shale Gas ◽  
Mineral Content ◽  
Horizontal Wells ◽  
Organic Content ◽  
Gas Production ◽  
Liquid Loading ◽  
Comprehensive Overview ◽  
Gas Field ◽  
Well Trajectory ◽  
Positive Effect

Abstract Fuling shale gas field is one of the most successful shale gas play in China. Production logging is one of the vital technologies to evaluate the shale gas contribution in different stages and different clusters. Production logging has been conducted in over 40 wells and most of the operations are successful and good results have been observed. Some previous studies have unveiled one or several wells production logging results in Fuling shale gas play. But production logging results show huge difference between different wells. In order to get better understanding of the results, a comprehensive overview is carried out. The effect of lithology layers, TOC (total organic content), porosity, brittle mineral content, well trajectory is analyzed. Results show that the production logging result is consistent with the geology understanding, and fractures in the favorable layers make more gas contribution. Rate contribution shows positive correlation with TOC, the higher the TOC, the greater the rate contribution per stage. For wells with higher TOC, the rate contribution difference per stage is relatively smaller, but for wells with lower TOC, it shows huge rate contribution variation, fracture stages with TOC lower than 2% contribute very little, and there exist one or several dominant fractures which contributes most gas rate. Porosity and brittle minerals also show positive effect on rate contribution. The gas rate contribution per fracture stage increases with the increase of porosity and brittle minerals. The gas contribution of the front half lateral and that of latter half lateral are relatively close for the "upward" or horizontal wells. However, for the "downward" wells, the latter half lateral contribute much more gas than the front half lateral. It is believed that the liquid loading in the toe parts reduced the gas contribution in the front half lateral. The overview research is important to get a compressive understanding of production logging and different fractures’ contribution in shale gas production. It is also useful to guide the design of horizontal laterals and fractures scenarios design.

Can We Engineer Better Multistage Horizontal Completions? Evidence of the Importance of Near-wellbore Fracture Geometry from Theory, Lab and Field Experiments

2015 ◽  
Author(s):  
B.. Lecampion ◽  
J.. Desroches ◽  
X.. Weng ◽  
J.. Burghardt ◽  
J.E.. E. Brown
Keyword(s):  
Pressure Drop ◽  
Field Experiments ◽  
Horizontal Wells ◽  
Fracture Plane ◽  
Hydraulic Fractures ◽  
Multiple Fractures ◽  
Fracture Geometry ◽  
Complex Fracture ◽  
Limited Entry ◽  
The Impact

Abstract There is accepted evidence that multistage fracturing of horizontal wells in shale reservoirs results in significant production variation from perforation cluster to perforation cluster. Typically, between 30 and 40% of the clusters do not significantly contribute to production while the majority of the production comes from only 20 to 30% of the clusters. Based on numerical modeling, laboratory and field experiments, we investigate the process of simultaneously initiating and propagating several hydraulic fractures. In particular, we clarify the interplay between the impact of perforation friction and stress shadow on the stability of the propagation of multiple fractures. We show that a sufficiently large perforation pressure drop (limited entry) can counteract the stress interference between different growing fractures. We also discuss the robustness of the current design practices (cluster location, limited entry) in the presence of characterized stress heterogeneities. Laboratory experiments highlight the complexity of the fracture geometry in the near-wellbore region. Such complex fracture path results from local stress perturbations around the well and the perforations, as well as the rock fabric. The fracture complexity (i.e., the merging of multiple fractures and the reorientation towards the preferred far-field fracture plane) induces a strong nonlinear pressure drop on a scale of a few meters. Single entry field experiments in horizontal wells show that this near-wellbore effect is larger in magnitude than perforation friction and is highly variable between clusters, without being predictable. Through a combination of field measurements and modeling, we show that such variability results in a very heterogeneous slurry rate distribution; and therefore, proppant intake between clusters during a stage, even in the presence of limited entry techniques. We also note that the estimated distribution of proppant intake between clusters appears similar to published production log data. We conclude that understanding and accounting for the complex fracture geometry in the near-wellbore is an important missing link to better engineer horizontal well multistage completions.

Best Practices in DFIT Interpretation: Comparative Analysis of 62 DFITs from Nine Different Shale Plays

2022 ◽  
Author(s):  
Mark Mcclure ◽  
Garrett Fowler ◽  
Matteo Picone
Keyword(s):  
Pressure Drop ◽  
Pore Pressure ◽  
Time Pressure ◽  
Early Time ◽  
Horizontal Wells ◽  
Late Time ◽  
Fracture Length ◽  
Well Spacing ◽  
Net Pressure ◽  
The Difference

Abstract In URTeC-123-2019, a group of operators and service companies presented a step-by-step procedure for interpretation of diagnostic fracture injection tests (DFITs). The procedure has now been applied on a wide variety of data across North and South America. This paper statistically summarizes results from 62 of these DFITs, contributed by ten operators spanning nine different shale plays. URTeC-123-2019 made several novel claims, which are tested and validated in this paper. We find that: (1) a ‘compliance method’ closure signature is apparent in the significant majority of DFITs; (2) in horizontal wells, early time pressure drop due to near-wellbore/midfield tortuosity is substantial and varies greatly, from 500 to 6000+ psi; (3) in vertical wells, early-time pressure drop is far weaker; this supports the interpretation that early- time pressure drop in horizontal wells is caused by near-wellbore/midfield tortuosity from transverse fracture propagation; (4) the (not recommended) tangent method of estimating closure yields Shmin estimates that are 100-1000+ psi lower than the estimate from the (recommended) compliance method; the implied net pressure values are 2.5x higher on average and up to 5-6x higher; (5) as predicted by theory, the difference between the tangent and compliance stress and net pressure estimates increases in formations with greater difference between Shmin and pore pressure; (6) the h-function and G-function methods allow permeability to be estimated from truncated data that never reaches late-time impulse flow; comparison shows that they give results that are close to the permeability estimates from impulse linear flow; (7) false radial flow signatures occur in the significant majority of gas shale DFITs, and are rare in oil shale DFITs; (8) if false radial signatures are used to estimate permeability, they tend to overestimate permeability, often by 100x or more; (9) the holistic-method permeability correlation overestimates permeability by 10-1000x; (10) in tests that do not reach late-time impulse transients, it is reasonable to make an approximate pore pressure estimate by extrapolating the pressure from the peak in t*dP/dt using a scaling of t^(-1/2) in oil shales and t^(3/4) in gas shales. The findings have direct practical implications for operators. Accurate permeability estimates are needed for calculating effective fracture length and for optimizing well spacing and frac design. Accurate stress estimation is fundamental to hydraulic fracture design and other geomechanics applications.

scholarly journals A Numerical Model for Investigating the Steam Conformance along the Dual-String Horizontal Wells in SAGD Operations

Energies ◽  
2020 ◽  
Vol 13 (15) ◽  
pp. 3981
Author(s):  
Peng Li ◽  
Yanyu Zhang ◽  
Xiaofei Sun ◽  
Huijuan Chen ◽  
Yang Liu
Keyword(s):  
Pressure Drop ◽  
Horizontal Wells ◽  
Pressure Profile ◽  
Steam Injection ◽  
Steam Pressure ◽  
Optimization Method ◽  
Injection Time ◽  
Reservoir Model ◽  
Landing Position ◽  
Steam Chamber

Non-uniformity of the steam-assisted gravity drainage (SAGD) steam chamber significantly decreases the development of heavy oil reservoirs. In this study, to investigate the steam conformance in SAGD operations, a wellbore model is developed for fluid flow in dual-string horizontal wells. Then, a three-dimensional, three-phase reservoir model is presented. Next, the coupled wellbore and reservoir model is solved with a fully implicit finite difference method. Finally, the effects of the injector wellbore configuration, steam injection ratio and injection time on the steam conformance are investigated. The results indicate that under different injector wellbore configurations, the closer the differences between the pressure drop from the landing position of the short string to the heel of the wellbore and the pressure drop from the landing position of the short string to the toe of the wellbore, the better is the steam conformance. The smaller the difference in the steam injection rate between the long and short injection strings, the higher is the uniformity of the steam chamber. The injector annular pressure profile uniformity is consistent with the steam conformance. Creating a more uniform steam pressure in the annulus of the injector improves the uniformity of the steam chamber. The steam conformance decreases with increasing injection time, so the optimization method of steam chamber uniformity should be adjusted according to different injection times.

Non-Darcy Binomial Deliverability Equations for Partially Penetrating Vertical Gas Wells and Horizontal Gas Wells

2009 ◽  
Author(s):  
Tao Zhu ◽  
Jing Lu
Keyword(s):  
Bottom Water ◽  
Horizontal Wells ◽  
Vertical Wells ◽  
Gas Wells ◽  
Gas Reservoirs ◽  
Gas Reservoir ◽  
Gas Well ◽  
Increase Productivity ◽  
Flow Domain ◽  
Inflow Performance

Many gas reservoirs are with bottom water drive. In order to prevent or delay unwanted water into the wellbore, the producing wells are often completed as partially penetrating vertical wells, and more and more horizontal wells have been drilled in recent years in bottom water drive gas reservoirs to reduce water coning and increase productivity. For a well, non-Darcy flow is inherently a near wellbore phenomenon. In spite of the considerable study that non-Darcy behavior of fully penetrating vertical wells, there has been no study of a partially penetrating vertical well or a horizontal well in a gas reservoir with bottom water drive. This paper presents new binomial deliverability equations for partially penetrating vertical gas wells and horizontal gas wells, assuming that only radial flow occurs in the near wellbore non-Darcy’s flow domain. The inflow performance of a vertical gas well is compared with that of a horizontal gas well. The proposed equations can account for the advantages of horizontal gas wells.

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