scholarly journals An Analytical Solution of the Pseudosteady State Productivity Index for the Fracture Geometry Optimization of Fractured Wells

Energies ◽  
2019 ◽  
Vol 12 (1) ◽  
pp. 176
Author(s):  
Hui Gao ◽  
Yule Hu ◽  
Longchen Duan ◽  
Kun Ai
Keyword(s):  
Analytical Solution ◽  
Flow Model ◽  
Oil And Gas ◽  
Geometry Optimization ◽  
Horizontal Wells ◽  
Productivity Index ◽  
Fracture Geometry ◽  
Aspect Ratios ◽  
Fractured Horizontal Wells ◽  
Fractured Well

The pseudosteady state productivity index is very important for evaluating the production from oil and gas wells. It is usually used as an objective function for the optimization of fractured wells. However, there is no analytical solution for it, especially when the proppant number of the fractured well is greater than 0.1. This paper extends the established fitting solution for proppant numbers less than 0.1 by introducing an explicit expression of the shape factor. It also proposes a new asymptotic solution based on the trilinear-flow model for proppant numbers greater than 0.1. The two solutions are combined to evaluate the pseudosteady state productivity index. The evaluation results are verified by the numerical method. The new solution can be directly used for fracture geometry optimization. The optimization results are consistent with those given by the unified fracture design (UFD) method. Using the analytical solution for the pseudosteady state productivity index, optimization results can be obtained for rectangular drainage areas with arbitrary aspect ratios without requiring any interpolation or extrapolation. Moreover, the new solution provides more rigorous optimization results than the UFD method, especially for fractured horizontal wells.

Investigation of Horizontal Wells with Multi-Stage Hydraulic Fracturing Technological Efficiency in the Development of Low-Permeability Oil Reservoirs

2021 ◽  
Author(s):  
Aleksander Valerievich Miroshnichenko ◽  
Valery Alekseevich Korotovskikh ◽  
Timur Ravilevich Musabirov ◽  
Aleksei Eduardovich Fedorov ◽  
Khakim Khalilovich Suleimanov
Keyword(s):  
Hydraulic Fracturing ◽  
Performance Indicators ◽  
Oil And Gas ◽  
Horizontal Wells ◽  
Productivity Index ◽  
Specific Mass ◽  
Horizontal Section ◽  
Technological Complexity ◽  
Multi Stage ◽  
Effective Development

Abstract The deterioration of the reservoir properties of potential oil and gas bearing areas on mature and green fields, as well as the increase in the volume of hard-to-recover reserves on low-permeable reservoirs set us new challenges in searching and using effective development technologies to maintain and even increase the oil production levels. Based on successful international experience, Russian oil and gas companies use horizontal wells (HW) with multi-stage hydraulic fracturing (MSHF) for the cost-effective development of low-permeable reservoirs. Thus, since the first pilot works of drilling technologies and completion of HW with MSHF in 2011, at the beginning of 2020, over 1,200 HW with MSHF were drilled and came on stream at the fields of LLC RN-Yuganskneftegaz, about half of which are at the exploitation play AS10-12 of the northern license territory (NLT) of the Priobskoye field. In searching the best technologies and engineering solutions, the company tested different lengths of horizontal section of HW, the number of hydraulic fracturing (HF) stages and distances between hydraulic fracturing ports, as well as different specific mass of the proppant per frac port. Recently, there has been a tendency in design solutions to increase the length of the HWs and the number of hydraulic fractures with a decreasing distance between the frac ports and a decreasing specific mass of the proppant per frac port. This work studies the actual and theoretical efficiency of HW with MSHF of various designs (different lengths of horizontal section of HW and the number of HF stages) and to assess the viability of increasing the technological complexity, as well as to analyze the actual impact of loading the proppant mass per port on performing HW with MSHF. The study is based on the results of the analysis of the factual experience accumulated over the entire history of the development of the exploitation play AS10-12 of the NLT of the Priobskoye field of the Rosneft Company. In studying the viability of increasing the technological complexity, especially, increasing the length of horizontal section of HW, increasing the number of HF stages, and reducing the distance between the frac ports: we discovered the typical methodological errors made in analyzing the efficiency of wells of various designs; we developed the methodology for analysis of the actual multiplicity of indicators of wells of various designs, in particular, HW with MSHF relative to deviated wells (DW) with HF; we carried out the statistical analysis of the actual values of the multiplicity of performance indicators and completion parameters of HW with MSHF of various designs relative to the surrounding DW with HF of the exploitation play AS10-12 of the NLT of the Priobskoye field; we performed the theoretical calculation of the multiplicity of the productivity coefficient for the HW with MSHF of various designs relative to DW with HF for the standard development system of the exploitation play AS10-12 of the NLT of the Priobskoye field; we compared the actual and theoretical results. The paper also presents the results of studying the actual effect of changes of proppant's mass per port on performance indicators of HW with MSHF of the same design and with an increase in the number of fractures of the hydraulic fracturing without changing the length of horizontal section of HW. As for performance indicators, being the basis for estimating the efficiency of HW with MSHF of various designs, we used the productivity index per meter of the effective reservoir thickness and the cumulative fluid production per meter of the effective reservoir thickness per a certain period of operation. And as the completion parameters, we used the length of the horizontal section of HW, the number of HF stages, the distance between the frac ports, and the specific mass of the proppant per meter of the effective reservoir thickness per frac port. The results of this work are the determining vector of development for future design decisions in improving the efficiency of HW with MSHF.

A New Approach To Estimating Ultimate Recovery for Multistage Hydraulically Fractured Horizontal Wells by Utilizing Completion Parameters Using Machine Learning

2021 ◽  
pp. 1-16
Author(s):  
Sulaiman A. Alarifi ◽  
Jennifer Miskimins
Keyword(s):  
Oil And Gas ◽  
Horizontal Wells ◽  
Oil And Gas Industry ◽  
Gas Industry ◽  
New Approach ◽  
History Data ◽  
Well Completion ◽  
Production History ◽  
Early Production ◽  
Fractured Horizontal Wells

Summary Reserves estimation is an essential part of developing any reservoir. Predicting the long-term production performance and estimated ultimate recovery (EUR) in unconventional wells has always been a challenge. Developing a reliable and accurate production forecast in the oil and gas industry is mandatory because it plays a crucial part in decision-making. Several methods are used to estimate EUR in the oil and gas industry, and each has its advantages and limitations. Decline curve analysis (DCA) is a traditional reserves estimation technique that is widely used to estimate EUR in conventional reservoirs. However, when it comes to unconventional reservoirs, traditional methods are frequently unreliable for predicting production trends for low-permeability plays. In recent years, many approaches have been developed to accommodate the high complexity of unconventional plays and establish reliable estimates of reserves. This paper provides a methodology to predict EUR for multistage hydraulically fractured horizontal wells that outperforms many current methods, incorporates completion data, and overcomes some of the limitations of using DCA or other traditional methods to forecast production. This new approach is introduced to predict EUR for multistage hydraulically fractured horizontal wells and is presented as a workflow consisting of production history matching and forecasting using DCA combined with artificial neural network (ANN) predictive models. The developed workflow combines production history data, forecasting using DCA models and completion data to enhance EUR predictions. The predictive models use ANN techniques to predict EUR given short early production history data (3 months to 2 years). The new approach was developed and tested using actual production and completion data from 989 multistage hydraulically fractured horizontal wells from four different formations. Sixteen models were developed (four models for each formation) varying in terms of input parameters, structure, and the production history data period it requires. The developed models showed high accuracy (correlation coefficients of 0.85 to 0.99) in predicting EUR given only 3 months to 2 years of production data. The developed models use production forecasts from different DCA models along with well completion data to improve EUR predictions. Using completion parameters in predicting EUR along with the typical DCA is a major addition provided by this study. The end product of this work is a comprehensive workflow to predict EUR that can be implemented in different formations by using well completion data along with early production history data.

History Matching and Rate Forecasting in Unconventional Oil Reservoirs With an Approximate Analytical Solution to the Double-Porosity Model

2015 ◽  
Vol 19 (01) ◽  
pp. 070-082 ◽  
Author(s):  
B. A. Ogunyomi ◽  
T. W. Patzek ◽  
L. W. Lake ◽  
C. S. Kabir
Keyword(s):  
Analytical Solution ◽  
History Matching ◽  
Horizontal Wells ◽  
Double Porosity ◽  
Unconventional Reservoirs ◽  
Production Data ◽  
Time Space ◽  
Double Porosity Model ◽  
Fractured Horizontal Wells ◽  
Porosity Model

Summary Production data from most fractured horizontal wells in gas and liquid-rich unconventional reservoirs plot as straight lines with a one-half slope on a log-log plot of rate vs. time. This production signature (half-slope) is identical to that expected from a 1D linear flow from reservoir matrix to the fracture face, when production occurs at constant bottomhole pressure. In addition, microseismic data obtained around these fractured wells suggest that an area of enhanced permeability is developed around the horizontal well, and outside this region is an undisturbed part of the reservoir with low permeability. On the basis of these observations, geoscientists have, in general, adopted the conceptual double-porosity model in modeling production from fractured horizontal wells in unconventional reservoirs. The analytical solution to this mathematical model exists in Laplace space, but it cannot be inverted back to real-time space without use of a numerical inversion algorithm. We present a new approximate analytical solution to the double-porosity model in real-time space and its use in modeling and forecasting production from unconventional oil reservoirs. The first step in developing the approximate solution was to convert the systems of partial-differential equations (PDEs) for the double-porosity model into a system of ordinary-differential equations (ODEs). After which, we developed a function that gives the relationship between the average pressures in the high- and the low-permeability regions. With this relationship, the system of ODEs was solved and used to obtain a rate/time function that one can use to predict oil production from unconventional reservoirs. The approximate solution was validated with numerical reservoir simulation. We then performed a sensitivity analysis on the model parameters to understand how the model behaves. After the model was validated and tested, we applied it to field-production data by partially history matching and forecasting the expected ultimate recovery (EUR). The rate/time function fits production data and also yields realistic estimates of ultimate oil recovery. We also investigated the existence of any correlation between the model-derived parameters and available reservoir and well-completion parameters.

Characterizing Tight Oil Reservoirs With Dual- and Triple-Porosity Models

2016 ◽  
Vol 138 (3) ◽  
Author(s):  
Ezulike Daniel Obinna ◽  
Dehghanpour Hassan
Keyword(s):  
Aspect Ratio ◽  
Horizontal Wells ◽  
Production Data ◽  
Hydraulic Fractures ◽  
High Fracture ◽  
Type Curves ◽  
Fracture Spacing ◽  
Aspect Ratios ◽  
Fractured Horizontal Wells ◽  
Porosity Model

The response of existing transient triple-porosity models for fractured horizontal wells do not converge to that of linear dual-porosity model (DPM) in the absence of natural/microfractures (MFs). The main reason is the assumption of sequential-depletion from matrix to MF, and from MF to hydraulic-fractures (HFs). This can result in unreasonable estimates of MF and/or HF parameters. Hence, the authors proposed a quadrilinear flow model (QFM) in a previous paper which relaxes this sequential-depletion assumption to allow simultaneous matrix–MF and matrix–HF depletion. Also, it is proved that QFM simplifies to both DPM and linear sequential triple-porosity model (STPM). This work considers the implications of applying QFM, STPM, and DPM type-curves and analysis equations on production data of two fractured horizontal wells completed in the Bakken and Cardium Formations. A comparative study of the reservoir parameters estimated from the application of these models to the same production data reveals two key results. First, the application of DPM on the production data from reservoirs with active MF could result in overestimation of HF half-length. This happens to compensate for the extra fluid depletion pathways provided by MF. Second, the application of STPM on the production data from the reservoirs with active matrix–HF communication could result in overestimation of the MF intensity. Results from this study are significant when selecting the appropriate model for interpreting production data from fractured horizontal wells completed in formations with or without active MF. The DPM is appropriate if analog studies (e.g., outcrop, microseismic and image log analyses) reveal high fracture spacing aspect ratio (negligible MF) in the reservoir. Fracture spacing aspect ratio is MF spacing divided by the HF spacing. The STPM is appropriate if analog studies reveal low spacing aspect ratio (e.g., matrix–HF face damage or high MF intensity within a given HF spacing). QFM is appropriate for all fracture spacing aspect ratios.

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.

OCTG Connection Testing Aiding in the Integrity of Multi-Fractured Horizontal Wells

2021 ◽  
Author(s):  
Carlos Blanc ◽  
Nestor Santi ◽  
Leandro Abel Perello ◽  
Adonis Ichim ◽  
Alexandru Adrian Zestran ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Mechanical Load ◽  
Horizontal Wells ◽  
Testing Procedure ◽  
American Petroleum Institute ◽  
Expert Working Group ◽  
Number Of Cycles ◽  
Fractured Horizontal Wells ◽  
Integrity Assurance ◽  
Testing Protocols

Abstract With the increase in shale oil and gas activity and complexity, companies deploy new solutions to safely and efficiently drill, complete, and produce wells in unconventional plays. These include Oil Country Tubular Goods (OCTG) connections, which must withstand installation, stimulation, and production loads specific to this application. Industry available standards provide manufacturers and operators a framework for quality founded on best practices and testing. In some instances, existing testing protocols may not be adequate (e.g. insufficient or overconservative) to assess connections’ performance for this application. For this reason, the American Petroleum Institute established an expert working group to develop Technical Report 5SF (TR 5SF) intended to evaluate casing connections performance in multi-fractured horizontal wells. The objective of this paper is to present a set of verified testing protocols applicable to casing connections used in the most common shale plays, complementing the existing body of knowledge. We discuss testing elements and parameters tailored to the conditions of various shale plays. Based on the operations planned for the life of a well, the testing procedure is adjusted to resemble the expected conditions and loads in the correct order. This includes make-up, high-cycle fatigue associated with the casing string installation, thread compound degradation under temperature and time, and mechanical load cycles generated by stimulation. Specimen sealability is confirmed under production loads, after which failure testing is performed. Some of the inputs to build the testing protocol are: maximum internal pressure, axial load, dogleg severity, number of cycles, temperature, and fluid type. Since connections play a crucial role in the integrity of a well, a testing procedure to ensure their performance is shown. Testing protocols for Multi-fractured Horizontal Wells (MFHW) applied to two connection types are presented, highlighting how tailored testing protocols and robust engineering improve product reliability and well integrity assurance. We compile a set of testing inputs for the most relevant shale plays worldwide, together with the testing elements, sequence, and acceptance criteria. This should help end users validate and benchmark products’ performance while improving industry knowledge of connections capabilities.

scholarly journals GPU-Based Computation of Formation Pressure for Multistage Hydraulically Fractured Horizontal Wells in Tight Oil and Gas Reservoirs

2018 ◽  
Vol 2018 ◽  
pp. 1-10
Author(s):  
Rongwang Yin ◽  
Qingyu Li ◽  
Peichao Li ◽  
Yang Guo ◽  
Yurong An ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Superposition Principle ◽  
Horizontal Wells ◽  
Tight Oil ◽  
Formation Pressure ◽  
Gas Reservoirs ◽  
Integral Forms ◽  
Oil And Gas Reservoirs ◽  
Fractured Horizontal Wells ◽  
Tight Oil And Gas

A mathematical model for multistage hydraulically fractured horizontal wells (MFHWs) in tight oil and gas reservoirs was derived by considering the variations in the permeability and porosity of tight oil and gas reservoirs that depend on formation pressure and mixed fluid properties and introducing the pseudo-pressure; analytical solutions were presented using the Newman superposition principle. The CPU-GPU asynchronous computing model was designed based on the CUDA platform, and the analytic solution was decomposed into infinite summation and integral forms for parallel computation. Implementation of this algorithm on an Intel i5 4590 CPU and NVIDIA GT 730 GPU demonstrates that computation speed increased by almost 80 times, which meets the requirement for real-time calculation of the formation pressure of MFHWs.

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