Characterizing Horizontal Well Performance in a Tight Gas Sand Using Pressure Transient, Production Logging and Geological Data

1996 ◽  
Author(s):  
P.L. Churcher ◽  
J. Kenny ◽  
D.H. Lamb ◽  
P.D. Flach
Keyword(s):  
Horizontal Well ◽  
Tight Gas ◽  
Geological Data ◽  
Well Performance ◽  
Pressure Transient

A Semianalytical Methodology To Diagnose the Locations of Underperforming Hydraulic Fractures Through Pressure-Transient Analysis in Tight Gas Reservoir

SPE Journal ◽  
2016 ◽  
Vol 22 (03) ◽  
pp. 924-939 ◽  
Author(s):  
Youwei He ◽  
Shiqing Cheng ◽  
Shuang Li ◽  
Yao Huang ◽  
Jiazheng Qin ◽  
...  
Keyword(s):  
Production Rate ◽  
Transient Analysis ◽  
Gas Production ◽  
Hydraulic Fractures ◽  
Tight Gas ◽  
Well Performance ◽  
Gas Reservoir ◽  
Pressure Transient ◽  
Type Curves ◽  
Tight Gas Reservoir

Summary The increasing activities in tight reservoir exploitation through fractured wells have attracted interests of pressure-transient analysis (PTA) for well-performance evaluation. The production rates of different fractures were assumed to be equal in previous models. However, different fractures have unequal contributions to the total-gas-production rate because of the differences of fracture scale (e.g., half-length, height), heterogeneity of gas saturation, formation damage, and fracture closure. This paper considers the effect of unequal gas-production rate of each fracture (UGPREF) on pressure-transient behaviors, and develops a semianalytical methodology to diagnose the specific locations of underperforming fractures through PTA by use of bottomhole-pressure (BHP) data. First, new semianalytical solutions of a multifractured horizontal well (MFHW) in a tight gas reservoir are derived on the basis of the Green function (Gringarten and Ramey 1973) and Newman product method (Newman 1936). Second, the model is validated by comparison with the numerical model in KAPPA Ecrin (Saphir) software (Essca 2011). Third, type curves are developed, and sensitivity analysis is further investigated. Results show that there exist clear distinctions among these type curves between equal gas-production rate of each fracture (EGPREF) and UGPREF. The early radial flow is distinguishable and behaves as a horizontal line with the value of 0.5/N* (N* = N for EGPREF, N*≠N for UGPREF) in the pseudopressure-derivative curves when the interferences between fractures do not overlap this period. If the early-radial flow was mistakenly regarded as pseudoradial flow, the interpreted permeability would be N* times smaller than the accurate result. Furthermore, the methodology is applied to a field case of the Daniudi tight gas reservoir in the Ordos Basin, which illustrates its physical consistency and practicability to diagnose the specific locations of underperforming hydraulic fractures through pressure-history matching. It also provides feasible references for reservoir engineers in well-performance evaluation and field strategy (e.g., refracturing, acidizing, or other stimulation treatments) to enhance hydrocarbon production.

The Effect of Well Azimuth or Don't Let Your Landman Plan Your Well Path!

2015 ◽  
Author(s):  
Fen Yang ◽  
Larry K. Britt ◽  
Shari Dunn-Norman
Keyword(s):  
Horizontal Well ◽  
Oil And Gas ◽  
Horizontal Wells ◽  
Horizontal Stress ◽  
Well Performance ◽  
Gas Reservoirs ◽  
Principal Stresses ◽  
Lateral Direction ◽  
Well Completion ◽  
Stimulation Of

Abstract Since the late 1980's when Maersk published their work on multiple fracturing of horizontal wells in the Dan Field, the use of transverse multiple fractured horizontal wells has become the completion of choice and become the “industry standard” for unconventional and tight oil and tight gas reservoirs. Today approximately sixty percent of all wells drilled in the United States are drilled horizontally and nearly all of them are multiple fractured. Because a horizontal well adds additional cost and complexity to the drilling, completion, and stimulation of the well we need to fully understand anything that affects the cost and complexity. In other words, we need to understand the affects of the principal stresses, both direction and magnitude, on the drilling completion, and stimulation of these wells. However, little work has been done to address and understand the relationship between the principal stresses and the lateral direction. This paper has as its goal to fundamentally address the question, in what direction should I drill my lateral? Do I drill it in the direction of the maximum horizontal stress (longitudinal) or do I drill it in the direction of the minimum horizontal stress (transverse)? The answer to this question relates directly back to the title of this paper and please "Don't let your land man drive that decision." This paper focuses on the horizontal well's lateral direction (longitudinal or transverse fracture orientation) and how that direction influences productivity, reserves, and economics of horizontal wells. Optimization studies using a single phase fully three dimensional numeric simulator including convergent non-Darcy flow were used to highlight the importance of lateral direction as a function of reservoir permeability. These studies, conducted for both oil and gas, are used to identify the point on the permeability continuum where longitudinal wells outperform transverse wells. The simulations compare and contrast the transverse multiple fractured horizontal well to longitudinal wells based on the number of fractures and stages. Further, the effects of lateral length, fracture half-length, and fracture conductivity were investigated to see how these parameters affected the decision over lateral direction in both oil and gas reservoirs. Additionally, how does completion style affect the lateral direction? That is, how does an open hole completion compare to a cased hole completion and should the type of completion affect the decision on in what direction the lateral should be drilled? These simulation results will be used to discuss the various horizontal well completion and stimulation metrics (rate, recovery, and economics) and how the choice of metrics affects the choice of lateral direction. This paper will also show a series of field case studies to illustrate actual field comparisons in both oil and gas reservoirs of longitudinal versus transverse horizontal wells and tie these field examples and results to the numeric simulation study. This work benefits the petroleum industry by: Establishing well performance and economic based criteria as a function of permeability for drilling longitudinal or transverse horizontal wells,Integrating the reservoir objectives and geomechanic limitations into a horizontal well completion and stimulation strategy,Developing well performance and economic objectives for horizontal well direction (transverse versus longitudinal) and highlighting the incremental benefits of various completion and stimulation strategies.

Beyond Volumetrics: Unconventional Petrophysics for Efficient Resource Appraisal (Example from the Khazzan Field, Sultanate of Oman)

2015 ◽  
Author(s):  
David R. Spain ◽  
German D. Merletti ◽  
William Dawson
Keyword(s):  
Gas Permeability ◽  
Stress Profile ◽  
Tight Gas ◽  
Well Performance ◽  
Flow Properties ◽  
Dynamic Flow ◽  
Stress Regime ◽  
Flow Units ◽  
Fluid Saturation ◽  
Rock Typing

Abstract The Middle East region holds substantial resources of unconventional tight gas and shale gas. The efficient extraction of these resources requires significant technology and expertise across numerous disciplines, including reservoir description and geomechanical characterization, hydraulic fracture modelling and design, advanced numerical simulation capabilities, sensor and surveillance technologies, and tightly integrated workflows. The effective application of these integrated subsurface and completion workflows leads to improved capital efficiency and well performance through increased well potential, increased ultimate recovery, and reduced costs. Key elements include dynamic rock typing to highlight potential flow units that will maximize gas deliverability, geomechanical modelling to provide a calibrated stress profile, and an integrated model that demonstrates the importance of understanding both dynamic flow properties and geomechanical response in complex tectonic environments. Dynamic rock typing focuses on using both depositional and petrophysical properties including rock type, porosity, and effective gas permeability at reservoir conditions to divide the reservoir into flow units in the context of their saturation history. The geomechanical profiling generates a tectonics-corrected minimum horizontal stress (SHmin) and the net confining stress (NCS). The rock-log-test calibration requires the evaluation and integration of subsurface fracture tests, including After-Closure Analysis (ACA), Data Fracs and Micro Fracs. All three involve different injection volumes and sampled reservoir volumes. Tight gas petrophysical studies must go “beyond volumetrics”, and should consider not only the static (storage) and dynamic (flow) properties within the context of the petroleum system and evolution of the current day pore geometry and fluid saturation distribution, but also the geomechanical stress regime and its implications for efficient completion optimization. Alternative interpretations test the range of uncertainty and are useful in designing field trials and surveillance strategies to reduce the subsurface uncertainty and to mitigate development risks.

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