Straight-line analysis (SLA) methods, which are a sub-group of model-based techniques used for rate-transient analysis (RTA), have proven to be immensely useful for evaluating unconventional reservoirs. Transient data can be analyzed using SLA methods to extract reservoir/hydraulic fracture information, while boundary-dominated flow data can be interpreted for fluid-in-place estimates. Because transient flow periods may be extensive, it is also advantageous to evaluate the volume of hydrocarbons-in-place contacted over time to assist with reserves assessment. The new SLA method introduced herein enables reservoir/fracture properties and contacted fluid-in-place (CFIP) to be estimated from the same plot, which is an advantage over traditional SLA techniques.
The new SLA method utilizes the
Validation of the new SLA method for an undersaturated oil case is performed through application to synthetic data generated with an analytical model. Thenew SLA results in estimates of LFP and OFIP that are in excellent agreement with model input (within 2%). Further, the results are consistent with the traditional SLA methods used to estimate LFP(e.g. the square-root of time plot) and OFIP (e.g. the flowing material balance plot).
Practical application of the new SLA method is demonstrated using field cases and experimental data. Field cases studied include online oil production from a multi-fractured horizontal well (MFHW) completed in a tight oil reservoir, and flowback water production from a second MFHW, also completed in a tight oil reservoir. Experimental (gas) data generated using a recently-introduced RTA core analysis technique, were also analyzed using the new SLA method. In all cases, the new SLA method results are in excellent agreement with traditional SLA methods.
The new SLA method introduced herein is an easy-to-apply, fully-analytical RTA technique that can be used for both reservoir/fracture characterization and hydrocarbons-in-place assessment. This method should provide important, complementary information to traditionally-used methods, such as square-root of time and flowing material balance plots, which are commonly used by reservoir engineers for evaluating unconventional reservoirs.
Achieving high hydrocarbon recovery is challenging in unconventional tight and shale reservoirs. Although EOR/EGR processes could potentially improve the recovery factor beyond the primary depletion, large-scale field application of these processes are not yet established in these reservoirs. This session will focus on the latest research trends, modelling and experimental work to better understand issues involved in improved economic recovery from such reservoirs.
Clarkson, Christopher R. (University of Calgary) | Yuan, Bin (University of Calgary) | Zhang, Zhenzihao (University of Calgary) | Tabasinejad, Farshad (University of Calgary) | Behmanesh, Hamid (NCS Multistage) | Hamdi, Hamidreza (University of Calgary) | Anderson, Dave (NCS Multistage) | Thompson, John (NCS Multistage) | Lougheed, Dylan (NCS Multistage)
The dominant transient flow regime for multi-fractured horizontal wells producing from low-permeability and shale (unconventional) reservoirs has historically been interpreted to be transient linear flow (TLF) in the framework of classical diffusion (CD). Recently, observed deviations away from this classical behavior for Permian Basin Wolfcamp shale (oil) wells have been attributed to anomalous diffusion (AD). The objective of the current study is to systematically investigate other potential causes of deviations from TLF.
The conventional log-log diagnostics used to identify flow regimes do not account for reservoir complexities such as multi-phase flow and reservoir heterogeneity. Failure to correct for these effects when they are occurring may result in misdiagnosis of flow regimes. A new workflow is therefore introduced herein to improve flow regime identification when reservoir complexities are exhibited, and to provide a more confident diagnosis of AD behavior. The workflow involves the correction of log-log diagnostics for complex reservoir behavior through the use of modified pseudo-variables (pseudo-pressure and pseudo-time) after the complex reservoir behavior is identified. Although reservoir heterogeneity is an accepted cause of deviations from TLF, the impact of multi-phase flow has not been investigated in detail. Therefore, in this study, corrections to pseudo-variables for multi-phase flow, a known reservoir complexity exhibited by Wolfcamp shale wells, are presented. Pressure-dependent permeability is also accounted for in the pseudo-variable calculations, although its impact is demonstrated to be relatively minor in this study.
Application of the new workflow to a simulated case and a Wolfcamp shale field case demonstrates the following: 1) multi-phase flow, and in particular the appearance of a mobile gas phase after two-phase oil and water production, results in deviations from classical TLF behavior when data is analyzed using conventional (uncorrected) diagnostics; 2) this deviation has characteristics similar to that expected for sub-diffusion; 3) application of the modified diagnostics to a simulated case that includes multi-phase flow results in the “true” flow regime signature of TLF being observed; 4) application of the modified diagnostics to a field case exhibiting evidence of multi-phase flow reduces the deviation from TLF.
Lu, Mingjing (China University of Petroleum, Colorado School of Mines) | Su, Yuliang (China University of Petroleum) | Wang, Wendong (China University of Petroleum) | Zhang, Ge (Xianhe Oil producing Plant, Shengli Oilfield, Sinopec)
Refracturing treatment are performed since stimulation effect won't last for entire life. Screening wells for refracturing needs a systematic analysis of huge amounts of data. With literature review, it is obviously that there are many factors controlling the success of refracturing and factors may vary in different oilfields. Proper factors and data processing are the primary principle in candidate selection. The Integrated Multiple Parameters (IMP) method is presented to provide assists in selecting candidate wells.
After deeply researching over 200 restimulated wells, all factors thought to be related with success of refracturing are listed and analyzed, results show that single factor may have great influence on restimulation but no significant patterns can be obtained since too many factors making things complicated. The IMP method proposes five parameters which are all integrated by those single factors. It is emphasized that all parameters have physical or engineering meanings which makes it easier to quantify their correlation in refracturing. Besides, all the parameters are dimensionless which makes it easier for using in mathematical models and statistical analysis.
The five dimensionless parameters are developed considering the most important aspects of candidate wells selection which are showed as followed: fracture reorientation, well completion, reservoir depletion, production decline, oil-water well connectivity. Parameters are calculated for all the restimulated wells to dig into their correlation with the outcomes of refracturing. A simple decision model is built to help with screening wells for refracturing. Results shows that it is more executable to evaluate and predict the success of refracturing with these dimensionless parameters. Fracture reorientation parameter is the primary one to be considered since it leads to fracture reorientation which brings significant production increment. Then two types of potential wells are picked: (a) wells with dissatisfied initial well completion, low production decline rate and high oil-water connectivity parameter; (b) wells with satisfied initial well completion, high well completion parameter, low production decline parameter, reservoir depletion parameter and low oil-water connectivity parameter for wells that are not easy for fracture reorientation. Wells selected are proved to be refracturing potential which verify the reliability and accuracy of IMP method.
The IMP method is an improved approach integrating most of the important factors which makes candidate selection much more predictable and it succeeds in screening out more than 80% of the potential wells in field test. Also, it can be applied widely in different oilfields since all the parameters are dimensionless. By combining with some mathematical methods such as neural networks, it can even predict increment of the restimulation treatment.
Foamed fracturing fluids have been used in unconventional reservoirs to reduce the water use and minimize deleterious impact on water-sensitive formations. As part of a Department of Energy (DOE) sponsored program, we previously identified an optimal thermodynamic pathway to transform wellhead natural gas (NG) into pressurized NG suitable for use as the internal phase in a foamed fracturing fluid. This study now aims to extend that work by determining the impact of using NG foam fracturing fluids on hydraulic fracture geometry and on productivity from the unconventional reservoirs.
The current study is focused on investigating the impact of the NG-based foam of various foam qualities in hydraulic fracture geometries and their production through simulation models. Field data and laboratory-based measurements for NG foam fluid properties are incorporated in the study. In addition, the transient response of the fluid flowback from foam-based fluid is studied using numerical simulation. Comparative analysis is done with typical slickwater, linear gel, and crosslinked fluid application for hydraulic fracturing using 3D-complex hydraulic fracture models. 1D and 2D particle transport models have been used to verify the differences in proppant distribution in the hydraulic fractures.
Rapid wellbore clean-up, low formation damage, and effect of the relative permeability improvement are added advantages apart from reducing the water requirements for hydraulic fracturing. In addition to providing the logistical benefit of using wellsite liberated low pressure gas, NG foamed fracturing fluid has a dynamic fluid leak-off behavior and increased effective viscosity over the base fluid that allows pumping and transporting proppant at least 10% farther in the hydraulic fractures than linear gel. Slickwater displays poor proppant transport and hence poses inability to pump higher concentrations of sand. NG foam fracturing fluid on the other hand displays improved proppant transport and has been shown to create more complexity than slickwater in our simulations.
Use of NG foamed fracturing fluid has not been practiced widely yet. Application of NG Foaming field test and reaping the economic benefit from simplified logistics and improved production would enables operators to invest in creating a safer handling environment for wellsite application of NG foam.
Even with more depletion the initial and prolonged production was superior to the other energized or foamed fracturing treatments they were compared to.
Drilling horizontal and highly permeable sandstone acid-sensitive reservoirs with oil based drilling fluids are normally followed by filter cake and associated organic sludge removal treatments. The acid or cleaning recipes should be compatible with the formation minerals, especially when losses are encountered. The objectives of this paper were to conduct a comprehensive evaluation of HCl/formic acid recipe to dissolve oil-based filter cake, characterize and dissolve associated organic sludges, and assess compatibility with highly permeable acid-sensitive sandstone core plugs.
Filter press experiments were conducted to optimize the fluid recipe. Core flood testing was conducted on sandstone core plugs at 160°F. Compatibility with reservoir fluids were assessed using aging cells. TGA was used to identify organic/inorganic composition of sludge samples XRD and ESEM were used to characterize core plugs and sludge samples. ICP analysis was conducted to analyses effluent from coreflood experiments. GC and GC-MS analysis was conducted to identify and characterize sludge samples. Micro CT scan was used to assess the dissolution of rock minerals.
The removal efficiencies of the oil-based filter cake were between 85-100% by weight using HCl/Formic acid recipe. The characterization of the sludge samples revealed the presence of mainly diesel. The inorganic compounds (50% by weight) were mainly quartz with small amounts of calcite, dolomite, kaolinite, microcline, and pyrite. Maximum solubility of nearly 60 wt% was achieved. Core flooding tests of the acid recipe indicated reduction in permeability of core plug. The coreflood effluent analysis indicated dissolution of mainly Ca, Fe, and Mg with small amounts of Al, Si, and Sr with indication of Si-based precipitation. No major indication of precipitation occured. ESEM and EDS spot analysis of the core plug particles showed the sample was comprised Si, O, Fe, S as the main constituents with small amounts of Al. XRD analysis of the core plug after coreflood testing showed the presence of mainly Quartz and small amounts of Microcline, Pyrite, and Palygorskite. The CT scan of core plug before/after coreflooding indicated the acid dissolved rock minerals. There was no clear indication of core damage or solids plugging.
During hydraulic fracturing treatment, coupled physical processes are at play between the injected fluid and the rock mass. The location of active hydro-mechanical deformation may be controlled by effective stress conditions, rock strength or fracture permeability, each of which are difficult to characterize given limited subsurface observations. An understanding of the hydraulically connected fracture geometry is desirable to assess stimulation efficiency and design hydraulic fracturing treatments to interact optimally with the given rock mass conditions. Numerical modelling may be employed to predict fracture growth; however, a complex geological reality may not be captured in modelled details. This difficulty is compounded, in that few forms of data feedback are available to analyse the dynamic behavior of the rock mass during and after stimulation. Available techniques that allow observation of the coupled processes include measuring subsurface deformation using microseismic response or strain captured from fiber optic sensing. For example, using distributed fiber optic sensing along the wellbore coupled with microseismic interpretation, Molenaar and Cox (2013) demonstrate that production from hydraulic fractures is variable from stage to stage, with each hydraulic fracture exhibiting a unique evolution in terms of growth rate and production. Following fluid injection, pressure/rate transient methods may be used to infer the final fracture geometries using a diagnostic fracture injection test (DFIT) (Zanganeh et al., 2018), or from flow back data (Barree et al., 2005; Ghaderi and Clarkson, 2016).
Confidently establishing single well and/or aggregated production profiles, particularly estimated ultimate recovery (EUR), is both an important and challenging process in unconventional reservoirs. Numerous papers have proposed forecasting techniques, but four fundamental approaches dominate:
Empirical decline curve analysis (DCA), such as multisegment Arps, the modified stretched exponential production decline (YM-SEPD) model, Duong's method, and power-law methods. Rate-transient analysis (RTA), which can include corrections for special dynamic mechanisms (e.g., stress-sensitivity, multiphase flow, adsorption/desorption). Numerical simulation for history-matching and forward modeling. Volumetrically determining in-place resources based on geological data and then applying a recovery factor deemed suitable for the reservoir system and depletion scheme.
Empirical decline curve analysis (DCA), such as multisegment Arps, the modified stretched exponential production decline (YM-SEPD) model, Duong's method, and power-law methods.
Rate-transient analysis (RTA), which can include corrections for special dynamic mechanisms (e.g., stress-sensitivity, multiphase flow, adsorption/desorption).
Numerical simulation for history-matching and forward modeling.
Volumetrically determining in-place resources based on geological data and then applying a recovery factor deemed suitable for the reservoir system and depletion scheme.
Each of these approaches can be implemented using either probabilistic or single-point estimates.
This paper compares and contrasts the DCA methods applied to various field cases in prominent Canadian [Western Canadian Sedimentary Basin (WCSB)] and US unconventional (oil and gas) plays (Bakken, Barnett, Cadomin, Eagle Ford, and Niobrara). Data sets are selectively chosen based on data quality and history length to increase confidence in the appraisal of the DCA approach. Hindcasting is applied to validate the results and conclusions.
From analysis of a number of wells in different types of reservoirs, a new workflow (methodology) is proposed and validated with hindcasting that allows practically and accurately reconciling EURs based on various empirical methods.
This manuscript is the first paper to discuss systematic reconciliation of EURs from varying approaches for horizontal wells in tight/shale reservoirs.
Although EOR/EGR processes could potentially improve the recovery factor beyond the primary depletion, large-scale field application of these processes are not yet established in these reservoirs. This session will focus on the latest research trends, modelling and experimental work to better understand issues involved in improved economic recovery from such reservoirs.