energies-logo

Journal Browser

Journal Browser

Hydrocarbon Development in Unconventional Shale and Carbonate Fields: Decline Curve Analysis Methods Combined with Data Analytics

A special issue of Energies (ISSN 1996-1073). This special issue belongs to the section "H: Geo-Energy".

Deadline for manuscript submissions: closed (1 July 2021) | Viewed by 25610

Special Issue Editors

Petroleum Engineering Department, College of Petroleum Engineering & Geosciences, King Fahd University of Petroleum & Minerals, Dhahran, Saudi Arabia
Interests: flow in fractured porous media; hydraulic fracture propagation; wellbore stability under anisotropy; reservoir models; production forecasting
Special Issues, Collections and Topics in MDPI journals
Earth Sciences and Engineering Division, Director of Ali I. Al-Naimi Petroleum Engineering Research Center, King Abdullah University of Science and Technology, Saudi Arabia
Interests: field-scale data-driven models of shale production; predictions of possible futures of shale plays; global analysis of oil and lease condensate production; global energy system transitions
Hildebrand Department of Petroleum and Geosystems Engineering, UT Austin, Texas, USA
Interests: formation evaluation; rock physics; fluid flow in spatially heterogeneous rocks; geophysics; laboratory measurements of rock properties; reservoir geophysics; machine learning
Provost and Chair Professor, Southern University of Science and Technology, Shenzhen, China
Interests: stochastic uncertainty quantification; inverse modeling; machine learning; mechanisms for shale gas and coalbed methane production; geological carbon sequestration

Special Issue Information

Dear Colleagues,

MDPI Energies, a peer-reviewed open access journal, is soliciting original and high-quality research articles related to the modeling of unconventional reservoirs. This Special Issue gathers original and high quality research articles related to physics-based and advanced methods for production forecasting based on history matching well data with decline curve analysis (DCA) methods. Our principal interest is in DCA methods applied to hydraulically fractured multistage wells, and improved forecasting of well performance and of the estimated ultimate recovery (EUR) in unconventional reservoirs. Application to field cases from a global variety of active and emerging shale and tight carbonate plays is of particular interest. Physics-based DCA methods should be emphasized, and, where possible, in combination with data analytics.

Please consider submitting your paper to MDPI Energies. We look forward to reviewing your work. The deadline for submission of manuscripts is 31 December, 2020. Papers will be peer- reviewed in a timely manner, and published upon acceptance. Accepted papers are published online in Energies without delay and will later appear in our collated Special Issue, which will be published in hard copy.

Of particular interest are original papers focusing on:

  • Advanced physics-based DCA models for multistage fractured wells
  • Linking DCA methods with flow regime changes in reservoirs
  • DCA-based production forecasting techniques for better reserves estimation
  • Uncertainty quantification and history matching using real field data
  • Field studies of well performance and probabilistic reserves estimation
  • Data-driven, field-scale history matches and predictions of possible futures of shale plays around the world
  • Field development strategies based on DCA models
  • Formation evaluation and petromechanics of spatially complex and tight rocks
  • Wholistic methods of interpretation of well and laboratory measurements

Other topics:

  • Effects of extreme rock complexity on pressure equilibration and flow
  • Coupled geomechanical–flow effects on shale production
  • Controls on the spatial variability of shale storage and production
  • Formation evaluation of organic shales
  • New laboratory measurements for evaluation of the storage and production potential of organic shales

Prof. Dr. Ruud Weijermars
Prof. Dr. Tadeusz W. Patzek
Prof. Dr. Carlos Torres-Verdin
Prof. Dr. Dongxiao Zhang
Guest Editors

Manuscript Submission Information

Manuscripts should be submitted online at www.mdpi.com by registering and logging in to this website. Once you are registered, click here to go to the submission form. Manuscripts can be submitted until the deadline. All submissions that pass pre-check are peer-reviewed. Accepted papers will be published continuously in the journal (as soon as accepted) and will be listed together on the special issue website. Research articles, review articles as well as short communications are invited. For planned papers, a title and short abstract (about 100 words) can be sent to the Editorial Office for announcement on this website.

Submitted manuscripts should not have been published previously, nor be under consideration for publication elsewhere (except conference proceedings papers). All manuscripts are thoroughly refereed through a single-blind peer-review process. A guide for authors and other relevant information for submission of manuscripts is available on the Instructions for Authors page. Energies is an international peer-reviewed open access semimonthly journal published by MDPI.

Please visit the Instructions for Authors page before submitting a manuscript. The Article Processing Charge (APC) for publication in this open access journal is 2600 CHF (Swiss Francs). Submitted papers should be well formatted and use good English. Authors may use MDPI's English editing service prior to publication or during author revisions.

Keywords

  • Decline curve analysis (DCA)
  • Production forecasting
  • History matching
  • Estimated ultimate recovery (EUR)
  • Uncertainty quantification
  • Reserves reporting using DCA methods

Published Papers (10 papers)

Order results
Result details
Select all
Export citation of selected articles as:

Research

Jump to: Review

23 pages, 4839 KiB  
Article
Gaussian Decline Curve Analysis of Hydraulically Fractured Wells in Shale Plays: Examples from HFTS-1 (Hydraulic Fracture Test Site-1, Midland Basin, West Texas)
by Ruud Weijermars
Energies 2022, 15(17), 6433; https://0-doi-org.brum.beds.ac.uk/10.3390/en15176433 - 02 Sep 2022
Cited by 7 | Viewed by 1159
Abstract
The present study shows how new Gaussian solutions of the pressure diffusion equation can be applied to model the pressure depletion of reservoirs produced with hydraulically multi-fractured well systems. Three practical application modes are discussed: (1) Gaussian decline curve analysis (DCA), (2) Gaussian [...] Read more.
The present study shows how new Gaussian solutions of the pressure diffusion equation can be applied to model the pressure depletion of reservoirs produced with hydraulically multi-fractured well systems. Three practical application modes are discussed: (1) Gaussian decline curve analysis (DCA), (2) Gaussian pressure-transient analysis (PTA) and (3) Gaussian reservoir models (GRMs). The Gaussian DCA is a new history matching tool for production forecasting, which uses only one matching parameter and therefore is more practical than hyperbolic DCA methods. The Gaussian DCA was compared with the traditional Arps DCA through production analysis of 11 wells in the Wolfcamp Formation at Hydraulic Fracture Test Site-1 (HFTS-1). The hydraulic diffusivity of the reservoir region drained by the well system can be accurately estimated based on Gaussian DCA matches. Next, Gaussian PTA was used to infer the variation in effective fracture half-length of the hydraulic fractures in the HFTS-1 wells. Also included in this study is a brief example of how the full GRM solution can accurately track the fluid flow-paths in a reservoir and predict the consequent production rates of hydraulically fractured well systems. The GRM can model reservoir depletion and the associated well rates for single parent wells as well as for arrays of multiple parent–parent and parent–child wells. Full article
Show Figures

Figure 1

17 pages, 4542 KiB  
Article
Anisotropy of Strength and Elastic Properties of Lower Paleozoic Shales from the Baltic Basin, Poland
by Przemyslaw Michal Wilczynski, Andrzej Domonik and Pawel Lukaszewski
Energies 2021, 14(11), 2995; https://0-doi-org.brum.beds.ac.uk/10.3390/en14112995 - 21 May 2021
Cited by 12 | Viewed by 1819
Abstract
The paper presents the results of laboratory studies on the strength–strain properties of shales representing four siltstone-claystone lithostratigraphic units occurring in the Baltic Basin. Laboratory studies in a triaxial stress state were conducted as single failure tests on cylindrical samples oriented parallel and [...] Read more.
The paper presents the results of laboratory studies on the strength–strain properties of shales representing four siltstone-claystone lithostratigraphic units occurring in the Baltic Basin. Laboratory studies in a triaxial stress state were conducted as single failure tests on cylindrical samples oriented parallel and perpendicular to lamination within the rocks. Mutually perpendicular samples were cut out from the same drill core sections in order to determine mechanical anisotropy. Samples oriented parallel to lamination were characterised by values of the static Young’s modulus twice as high as from samples oriented perpendicular to lamination. Similar variability was observed in the case of maximum differential stress values and Poisson’s ratio. Samples parallel to lamination registered notably lower axial strains, which influenced increased values of Young’s modulus and Poisson’s ratio. The rocks studied are characterised by VTI type (vertical transverse isotropy) internal anisotropy of the rock matrix, which significantly influences the anisotropy of their geomechanical properties. Full article
Show Figures

Figure 1

22 pages, 36593 KiB  
Article
The Impact of the Geometry of the Effective Propped Volume on the Economic Performance of Shale Gas Well Production
by Andres Soage, Ruben Juanes, Ignasi Colominas and Luis Cueto-Felgueroso
Energies 2021, 14(9), 2475; https://0-doi-org.brum.beds.ac.uk/10.3390/en14092475 - 26 Apr 2021
Cited by 1 | Viewed by 1610
Abstract
We analyze the effect that the geometry of the Effective Propped Volume (EPV) has on the economic performance of hydrofractured multistage shale gas wells. We study the sensitivity of gas production to the EPV’s geometry and we compare it with the sensitivity to [...] Read more.
We analyze the effect that the geometry of the Effective Propped Volume (EPV) has on the economic performance of hydrofractured multistage shale gas wells. We study the sensitivity of gas production to the EPV’s geometry and we compare it with the sensitivity to other parameters whose relevance in the production of shale gas is well known: porosity, kerogen content and permeability induced in the Stimulated Recovery Volume (SRV). To understand these sensitivities, we develop a high-fidelity 3D numerical model of shale gas flow that allows determining both the Estimated Ultimate Recovery (EUR) of gas as well as analyzing the decline curves of gas production (DCA). We find that the geometry of the EPV plays an important role in the economic performance and gas production of shale wells. The relative contribution of EPV geometry is comparable to that of induced permeability of the SRV or formation porosity. Our results may lead to interesting technological developments in the oild and gas industry that improve economic efficiency in shale gas production. Full article
Show Figures

Graphical abstract

42 pages, 10671 KiB  
Article
Predicting the Performance of Undeveloped Multi-Fractured Marcellus Gas Wells Using an Analytical Flow-Cell Model (FCM)
by David Waters and Ruud Weijermars
Energies 2021, 14(6), 1734; https://0-doi-org.brum.beds.ac.uk/10.3390/en14061734 - 20 Mar 2021
Cited by 8 | Viewed by 1920
Abstract
The objective of the present study is to predict how changes in the fracture treatment design parameters will affect the production performance of new gas wells in a target zone of the Marcellus shale. A recently developed analytical flow-cell model can estimate future [...] Read more.
The objective of the present study is to predict how changes in the fracture treatment design parameters will affect the production performance of new gas wells in a target zone of the Marcellus shale. A recently developed analytical flow-cell model can estimate future production for new wells with different completion designs. The flow-cell model predictions were benchmarked using historic data of 11 wells and 6 different completion designs. First, a type well was generated and used with the flow-cell model to predict the performance of the later infill wells—with variable completion designs—based off the performance of earlier wells. The flow-cell model takes into account known hyperbolic forecast parameters (qi, Di, and b-factor) and fracture parameters (height, half-length, and spacing) of a type well. Next, the flow-cell model generates the hyperbolic decline parameters for an offset well based on the selected changes in the fracture treatment design parameters. Using a numerical simulator, the flow-cell model was verified as an accurate modeling technique for forecasting the production performance of horizontal, multi-fractured, gas wells. Full article
Show Figures

Figure 1

13 pages, 5907 KiB  
Article
Pore-Scale Simulations of CO2/Oil Flow Behavior in Heterogeneous Porous Media under Various Conditions
by Qingsong Ma, Zhanpeng Zheng, Jiarui Fan, Jingdong Jia, Jingjing Bi, Pei Hu, Qilin Wang, Mengxin Li, Wei Wei and Dayong Wang
Energies 2021, 14(3), 533; https://0-doi-org.brum.beds.ac.uk/10.3390/en14030533 - 20 Jan 2021
Cited by 13 | Viewed by 2602
Abstract
Miscible and near-miscible flooding are used to improve the performance of carbon-dioxide-enhanced oil recovery in heterogeneous porous media. However, knowledge of the effects of heterogeneous pore structure on CO2/oil flow behavior under these two flooding conditions is insufficient. In this study, [...] Read more.
Miscible and near-miscible flooding are used to improve the performance of carbon-dioxide-enhanced oil recovery in heterogeneous porous media. However, knowledge of the effects of heterogeneous pore structure on CO2/oil flow behavior under these two flooding conditions is insufficient. In this study, we construct pore-scale CO2/oil flooding models for various flooding methods and comparatively analyze CO2/oil flow behavior and oil recovery efficiency in heterogeneous porous media. The simulation results indicate that compared to immiscible flooding, near-miscible flooding can increase the CO2 sweep area to some extent, but it is still inefficient to displace oil in small pore throats. For miscible flooding, although CO2 still preferentially displaces oil through big throats, it may subsequently invade small pore throats. In order to substantially increase oil recovery efficiency, miscible flooding is the priority choice; however, the increase of CO2 diffusivity has little effect on oil recovery enhancement. For immiscible and near-miscible flooding, CO2 injection velocity needs to be optimized. High CO2 injection velocity can speed up the oil recovery process while maintaining equivalent oil recovery efficiency for immiscible flooding, and low CO2 injection velocity may be beneficial to further enhancing oil recovery efficiency under near-miscible conditions. Full article
Show Figures

Figure 1

24 pages, 8180 KiB  
Article
Optimization of Fracture Spacing and Well Spacing in Utica Shale Play Using Fast Analytical Flow-Cell Model (FCM) Calibrated with Numerical Reservoir Simulator
by Ruud Weijermars
Energies 2020, 13(24), 6736; https://0-doi-org.brum.beds.ac.uk/10.3390/en13246736 - 21 Dec 2020
Cited by 5 | Viewed by 1890
Abstract
Recently, a flow-cell model (FCM) was specifically developed to quickly generate physics-based forecasts of production rates and estimated ultimate resources (EURs) for infill wells, as the basis for the estimation of proven undeveloped reserves. Such reserves estimations provide operators with key collateral for [...] Read more.
Recently, a flow-cell model (FCM) was specifically developed to quickly generate physics-based forecasts of production rates and estimated ultimate resources (EURs) for infill wells, as the basis for the estimation of proven undeveloped reserves. Such reserves estimations provide operators with key collateral for further field development with reserves-based loans. FCM has been verified in previous studies to accurately forecast production rates and EURs for both black oil and dry gas wells. This study aims to expand the application range of FCM to predict the production performance and EURs of wells planned in undeveloped acreage of the wet gas window. Forecasts of the well rates and EURs with FCM are compared with the performance predictions generated with an integrated reservoir simulator for multi-fractured wells, using detailed field data from the Utica Field Experiment. Results of FCM, with adjustment factors to account for wet gas compressibility effects, match closely with the numerical performance forecasts. The advantage of FCM is that it can run on a fast spreadsheet template. Once calibrated for wet gas wells by a numerical reservoir simulator accounting for compositional flow, FCM can forecast the performance of future wells when completion design parameters, such as fracture spacing and well spacing, are changed. Full article
Show Figures

Figure 1

22 pages, 11436 KiB  
Article
The Key Factors That Determine the Economically Viable, Horizontal Hydrofractured Gas Wells in Mudrocks
by Syed Haider, Wardana Saputra and Tadeusz Patzek
Energies 2020, 13(9), 2348; https://0-doi-org.brum.beds.ac.uk/10.3390/en13092348 - 08 May 2020
Cited by 15 | Viewed by 3040
Abstract
We assemble a multiscale physical model of gas production in a mudrock (shale). We then tested our model on 45 horizontal gas wells in the Barnett with 12–15 years on production. When properly used, our model may enable shale companies to gain operational [...] Read more.
We assemble a multiscale physical model of gas production in a mudrock (shale). We then tested our model on 45 horizontal gas wells in the Barnett with 12–15 years on production. When properly used, our model may enable shale companies to gain operational insights into how to complete a particular well in a particular shale. Macrofractures, microfractures, and nanopores form a multiscale system that controls gas flow in mudrocks. Near a horizontal well, hydraulic fracturing creates fractures at many scales and increases permeability of the source rock. We model the physical properties of the fracture network embedded in the Stimulated Reservoir Volume (SRV) with a fractal of dimension D < 2 . This fracture network interacts with the poorly connected nanopores in the organic matrix that are the source of almost all produced gas. In the practically impermeable mudrock, the known volumes of fracturing water and proppant must create an equal volume of fractures at all scales. Therefore, the surface area and the number of macrofractures created after hydrofracturing are constrained by the volume of injected water and proppant. The coupling between the fracture network and the organic matrix controls gas production from a horizontal well. The fracture permeability, k f , and the microscale source term, s, affect this coupling, thus controlling the reservoir pressure decline and mass transfer from the nanopore network to the fractures. Particular values of k f and s are determined by numerically fitting well production data with an optimization algorithm. The relationship between k f and s is somewhat hyperbolic and defines the type of fracture system created after hydrofracturing. The extremes of this relationship create two end-members of the fracture systems. A small value of the ratio k f / s causes faster production decline because of the high microscale source term, s. The effective fracture permeability is lower, but gas flow through the matrix to fractures is efficient, thus nullifying the negative effect of the smaller k f . For the high values of k f / s , production decline is slower. In summary, the fracture network permeability at the macroscale and the microscale source term control production rate of shale wells. The best quality wells have good, but not too good, macroscale connectivity. Full article
Show Figures

Graphical abstract

29 pages, 24218 KiB  
Article
Physical Scaling of Oil Production Rates and Ultimate Recovery from All Horizontal Wells in the Bakken Shale
by Wardana Saputra, Wissem Kirati and Tadeusz Patzek
Energies 2020, 13(8), 2052; https://0-doi-org.brum.beds.ac.uk/10.3390/en13082052 - 20 Apr 2020
Cited by 24 | Viewed by 4195
Abstract
A recent study by the Wall Street Journal reveals that the hydrofractured horizontal wells in shales have been producing less than the industrial forecasts with the empirical hyperbolic decline curve analysis (DCA). As an alternative to DCA, we introduce a simple, fast and [...] Read more.
A recent study by the Wall Street Journal reveals that the hydrofractured horizontal wells in shales have been producing less than the industrial forecasts with the empirical hyperbolic decline curve analysis (DCA). As an alternative to DCA, we introduce a simple, fast and accurate method of estimating ultimate recovery in oil shales. We adopt a physics-based scaling approach to analyze oil rates and ultimate recovery from 14,888 active horizontal oil wells in the Bakken shale. To predict the Estimated Ultimate Recovery (EUR), we collapse production records from individual horizontal shale oil wells onto two segments of a master curve: (1) We find that cumulative oil production from 4845 wells is still growing linearly with the square root of time; and (2) 6401 wells are already in exponential decline after approximately seven years on production. In addition, 2363 wells have discontinuous production records, because of refracturing or changes in downhole flowing pressure, and are matched with a linear combination of scaling curves superposed in time. The remaining 1279 new wells with less than 12 months on production have too few production records to allow for robust matches. These wells are scaled with the slopes of other comparable wells in the square-root-of-time flow regime. In the end, we predict that total ultimate recovery from all existing horizontal wells in Bakken will be some 4.5 billion barrels of oil. We also find that wells completed in the Middle Bakken formation, in general, produce more oil than those completed in the Upper Three Forks formation. The newly completed longer wells with larger hydrofractures have higher initial production rates, but they decline faster and have EURs similar to the cheaper old wells. There is little correlation among EUR, lateral length, and the number and size of hydrofractures. Therefore, technology may not help much in boosting production of new wells completed in the poor immature areas along the edges of the Williston Basin. Operators and policymakers may use our findings to optimize the possible futures of the Bakken shale and other plays. More importantly, the petroleum industry may adopt our physics-based method as an alternative to the overly optimistic hyperbolic DCA that yields an ‘illusory picture’ of shale oil resources. Full article
Show Figures

Graphical abstract

27 pages, 9682 KiB  
Article
Pre-Drilling Production Forecasting of Parent and Child Wells Using a 2-Segment Decline Curve Analysis (DCA) Method Based on an Analytical Flow-Cell Model Scaled by a Single Type Well
by Ruud Weijermars and Kiran Nandlal
Energies 2020, 13(6), 1525; https://0-doi-org.brum.beds.ac.uk/10.3390/en13061525 - 24 Mar 2020
Cited by 6 | Viewed by 3804
Abstract
This paper advances a practical tool for production forecasting, using a 2-segment Decline Curve Analysis (DCA) method, based on an analytical flow-cell model for multi-stage fractured shale wells. The flow-cell model uses a type well and can forecast the production rate and estimated [...] Read more.
This paper advances a practical tool for production forecasting, using a 2-segment Decline Curve Analysis (DCA) method, based on an analytical flow-cell model for multi-stage fractured shale wells. The flow-cell model uses a type well and can forecast the production rate and estimated ultimate recovery (EUR) of newly planned wells, accounting for changes in completion design (fracture spacing, height, half-length), total well length, and well spacing. The basic equations for the flow-cell model have been derived in two earlier papers, the first one dedicated to well forecasts with fracture down-spacing, the second one to well performance forecasts when inter-well spacing changes (and for wells drilled at different times, to account for parent-child well interaction). The present paper provides a practical workflow, introduces correction parameters to account for acreage quality and fracture treatment quality. Further adjustments to the flow-cell model based 2-segment DCA method are made after history matching field data and numerical reservoir simulations, which indicate that terminal decline is not exponential (b = 0) but hyperbolic (with 0 < b< 1). The timing for the onset of boundary dominated flow was also better constrained, using inputs from a reservoir simulator. The new 2-segment DCA method is applied to real field data from the Eagle Ford Formation. Among the major insights of our analyses are: (1) fracture down-spacing does not increase the long-term EUR, and (2) fracture down-spacing of real wells does not result in the rate increases predicted by either the flow-cell model based 2-segment DCA (or its matching reservoir simulations) with the assumed perfect fractures in the down-spaced well models. Our conclusion is that real wells with down-spaced fracture clusters, involving up to 5000 perforations, are unlikely to develop successful hydraulic fractures from each cluster. The fracture treatment quality factor (TQF) or failure rate (1-TQF) can be estimated by comparing the actual well performance with the well forecast based on the ideal well model (albeit flow-cell model or reservoir model, both history-matched on the type curve). Full article
Show Figures

Figure 1

Review

Jump to: Research

16 pages, 2064 KiB  
Review
The Evaluation and Sensitivity of Decline Curve Modelling
by Prinisha Manda and Diakanua Bavon Nkazi
Energies 2020, 13(11), 2765; https://0-doi-org.brum.beds.ac.uk/10.3390/en13112765 - 01 Jun 2020
Cited by 17 | Viewed by 2375
Abstract
The development of prediction tools for production performance and the lifespan of shale gas reservoirs has been a focus for petroleum engineers. Several decline curve models have been developed and compared with data from shale gas production. To accurately forecast the estimated ultimate [...] Read more.
The development of prediction tools for production performance and the lifespan of shale gas reservoirs has been a focus for petroleum engineers. Several decline curve models have been developed and compared with data from shale gas production. To accurately forecast the estimated ultimate recovery for shale gas reservoirs, consistent and accurate decline curve modelling is required. In this paper, the current decline curve models are evaluated using the goodness of fit as a measure of accuracy with field data. The evaluation found that there are advantages in using the current DCA models; however, they also have limitations associated with them that have to be addressed. Based on the accuracy assessment conducted on the different models, it appears that the Stretched Exponential Decline Model (SEDM) and Logistic Growth Model (LGM), followed by the Extended Exponential Decline Model (EEDM), the Power Law Exponential Model (PLE), the Doung’s Model, and lastly, the Arps Hyperbolic Decline Model, provide the best fit with production data. Full article
Show Figures

Graphical abstract

Back to TopTop