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Collaborating Authors
SPE Unconventional Resources Conference
Abstract Unconventional reservoirs, including shale formations and many tight-gas sands, contain natural fractures, fissures, faults, and microfractures that contribute to the rock flow capacity. In most cases, core-measured permeability, and especially crushed-core permeability measurements, may not be representative of the true reservoir rock flow capacity. Evaluating the in-situ rock permeability, and simulating production, requires sampling not only the matrix, but also the fractures and fissures that contribute to the unconventional rock system permeability. A properly designed well test in an unconventional reservoir will sample a volume of reservoir rock that is representative of the whole. In other words, a well test should sample a representative elementary volume, which is the smallest volume of rock with properties characteristic of the whole. Diagnostic fracture-injection/falloff tests (DFIT) have been routinely implemented since the late 1990s to understand leakoff mechanisms, identify fracture closure stress, estimate initial reservoir pressure, and determine permeability-thickness in unconventional reservoirs. In almost every unconventional well completed, a DFIT is the only well test that will be completed during the well lifecycle, but historically, the tests have been designed empirically based on analog formations and without considering the volume of rock investigated. We demonstrate a new method for calculating the volume of rock investigated by a DFIT, and we show how a DFIT design can allow for sampling a representative elementary volume of the reservoir.
- Europe (0.68)
- North America > United States > Colorado > Garfield County (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.54)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin (0.99)
- North America > United States > Nebraska > Laramie Basin > Niobrara Formation (0.99)
- (6 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
The Impact of Completion Technique on Well Performance
Anderson, D. M. (Anderson Thompson Reservoir Strategies) | Thompson, J. M. (Anderson Thompson Reservoir Strategies) | Popp, M.. (Anderson Thompson Reservoir Strategies) | Behmanesh, H.. (Anderson Thompson Reservoir Strategies) | Liang, P.. (Anderson Thompson Reservoir Strategies)
Abstract There are several different technologies available for completing and stimulating multi-stage horizontal wells. By far the most common of these is to use a cemented liner with multiple perforation clusters treated simultaneously in a single stage (plug-and-perf). One alternative method gaining popularity also employs the use of a cemented liner but with sliding sleeves allowing for single point entry into the formation (pinpoint). The objective of this paper is to compare the expected and observed reservoir performance resulting from each of these approaches. To accomplish the objectives, two methods are appliedtheoretical and experimental. The theoretical approach uses a hydraulic fracture simulator to predict fracture geometry for both plug-and-perf and pinpoint completion techniques for a predefined set of treatment parameters. A reservoir simulator is then used to predict production and ultimate recovery for each case. The experimental approach involves choosing a drilling spacing unit (DSU) where these two completion techniques have been applied (in close proximity) while controlling, or normalizing for, as many other reservoir and completion variables as possible. The well performance data is analyzed using rate transient analysis (RTA), and the results compared to the predictions made by the theoretical models. Theoretical modeling predicts that slightly better reservoir performance ought to be obtained in pinpoint completions, over plug-and-perf. Experimental (empirical) analysis of actual well performance data supports the theoretical predictions directionally, but significantly exceeds the uplift predicted by the theoretical models. Ideally, the experimental data should be collected under controlled conditions. In reality, this is not the case as operations on a typical well pad (as is the case in this study) are continuously subjected to disturbances, unconstrained variables and incomplete and/or inaccurate measurements. Thus, results from RTA are somewhat subjective and error prone. The confidence of these results improve dramatically as the sample data set increases. To our knowledge, this work represents the first objective comparison of different completion types using rate transient analysis as an evaluation tool. The experimental benchmarking procedure introduced in this work is novel and represents a significant improvement over existing industry standards for understanding how completion technology can impact well performance.
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Texas > Permian Basin > Midland Basin (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- (26 more...)
Abstract This paper presents a new integrated workflow that couples geology, geomechanics and geophysics (3G) with a constrained asymmetric frac model as applied to a Wolfcamp well to address the concerns of well interference. The proposed workflow enables the ability to adapt the frac design of each stage based on the in-situ geologic and geomechanical variability. The objective of this approach is to identify the variable treatment parameters required to overcome the stress heterogeneity and estimate the impact of the adaptive frac design on the final fracture geometry. The lateral stress gradients resulting from the pressure depletion due to a nearby producing well and the fluid leak-off due to opening of natural fractures are fine-tuned to account for asymmetry observed in the geomechanical modeling. The role of the natural fractures is emphasized and practical approaches to estimate a validated natural fracture model are described and illustrated. A validation well is used to highlight the importance of the input natural fracture model in calculating validated differential stress and strain that reproduce the main features of the microseismic. With this validated strain model, a constrained frac design provides the proper asymmetric fracture geometry able to pinpoint the poor and good frac stages. Once the workflow is extensively validated, it can be used on target wells to avoid frac hits. In this Wolfcamp example, the challenge was to find the optimal frac design to minimize interference of an infill well with existing offset producers. To address the possible zones of interference, the stage spacing was locally increased to 152 m (500 ft), and the treatment was especially modified in the middle stages of the well. This resulted in reducing the number of stages from 40 to 34, specifically in zones indicating high probability of interference. The design was altered from pumping a mixture of 320,000 lb of 100 mesh and 40/70 mesh sand to 220,000 lb of 40/70 mesh sand, and the injected fluid viscosity was increased from 10 centipoise (cP) for slick water to 30 cP for linear gel as better carrying capacity was required to pump only 40/70 mesh sand. Additonally, the injection rate was reduced from 105 bbl/min to 80 bbl/min. The integrated approach allows for the ability to adapt the frac design to in-situ conditions including heterogeneity in the stress fields and the pressure depletion from existing producers. Adaptive frac design significantly reduces the probability of frac hits and well interference. The proposed modeling workflow enables greater investment efficiency and overall field development optimization.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.50)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.41)
- Information Technology > Modeling & Simulation (0.47)
- Information Technology > Software (0.34)
Abstract Success of the unconventional multi-fractured horizontal well revolution depends on creation of a Stimulated Reservoir Volume (SRV). Advances in stimulation technology have been geared towards creating increasingly larger SRV's. However, the techniques for evaluating the size and shape of the SRV from production data analysis have not kept pace, and need to be improved. In this paper, we review the diagnostic methods that are currently used, and share learnings obtained from analyzing hundreds of unconventional wells from different unconventional plays. We describe the existing specialized analyses, namely plots utilizing square-root of time (and other time functions), along with type curves that were developed for Compound Linear Flow. We demonstrate that even though these type curves do not account for SRV, they can still be used partially to learn about the SRV characteristics. We have studied the behavior of the EFR (Enhanced Frac Region) model and show how it deviates from the Compound Linear Flow type curves. We demonstrate that what is often considered to be linear flow is only a transition between two flow regimes and results in misinterpretation of the linear flow parameters, and consequently, of SRV properties. We have developed a new EFR type curve that helps characterize the SRV. It should provide a better understanding and interpretation of the currently accepted multi-fractured horizontal well/reservoir system, and improve the diagnostic analysis that precedes and reinforces modeling.
Abstract Shale gas is a very important energy resource for humans in the 21st century. However, the mechanism underlying the transoport behavior of shale gas in nanopores (typically 1 nm to 100 nm) remains a huge challenge in industries, as well as in research. In this study, we investigated the free gas transport in nanopores of shale rocks by using the real gas equation of state (EOS) and elastic hard-sphere (HS) model. Excellent results were obtained from the validation of the real gas model on the basis of molecular simulation and experimental data. This paper discusses the following: (1) the model efficiently and reasonably describes the known gas transport behavior in nanopores by establishing the relationship among real gas effect, molecular interactions and collisions, and gas transport behavior; (2) the use of real gas HS EOS considers repulsion, which reduces Knudsen diffusion and laminar slip flow conductance. In addition, packing fraction in EOS provides minimum boundaries for Knudsen number and flow regime; (3) the molecule-wall collision is mainly dominated by pore diameter, and the intermolecular collision is mainly dominated by pressure in nanopores. Under 10 MPa, the molecule-wall collision dominates in nanopores. Otherwise, the intermolecular collision dominates; (4) the laminar slip flow conductance increases with the corresponding increase in strength of intermolecular collision. With increased strength in the molecule-wall collision, Knudsen diffusion conductance increases, thereby improving the transport efficiency, as shown by apparent permeability.
- North America > Canada > Alberta (0.68)
- North America > Canada > British Columbia (0.46)
- North America > United States > Texas (0.46)
Abstract This paper presents comprehensive rock-fluid experiments to study the possibility of oil recovery improvement when CO2 is injected as a fracturing fluid in the Montney tight-oil play, located in the Western Canadian Sedimentary Basin. This study consists of four phases: In phase 1, we conduct constant composition expansion (CCE) tests with different CO2 concentrations using a PVT cell. In phase 2, we visualize CO2-oil interactions at reservoir pressure and temperature in a custom-designed visual cell. Then, we conduct SEM/EDS analysis on the solid precipitates in the visual cell due to CO2-oil interactions. In phase 3, we soak the oil-saturated core plugs in the visual cell, pressurize the cell with CO2, and measure the oil recovery. In phase 4, we conduct cyclic CO2 tests using a core flooding system, and measure the oil recovery. We also evaluate the oil viscosity and wettability of the core plugs before and after cyclic CO2 process. The results of the CCE tests conducted using the PVT cell and visualization tests conducted using the visual cell show that CO2 can significantly dissolve into and expand the Montney oil. The results of the CO2 soaking tests and cyclic CO2 process show that the oil swelling due to CO2-oil interactions results in high oil recovery factor from the oil-saturated core plugs. In addition, we observe solid precipitates due to CO2-oil interactions at the bulk-phase conditions in the visual cell. SEM/EDS analysis on the solid precipitates show the existence of carbon and sulfur, the main components of asphaltene. The results of IP-143 test confirm the formation asphaltene when the Montney oil contacts CO2 at reservoir conditions.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.82)
Abstract The purpose of this work is to perform an improved method to optimize different CO2 Enhanced Oil Recovery (EOR) processes in unconventional liquid reservoirs, particularly in the volatile oil region of the Eagle Ford shale. Previous simulation studies of CO2 EOR in the unconventional liquid reservoirs were not done in full field-scale and were not history matched before applying CO2 EOR to the model. Without history matching step, the simulation might generate misleading results in CO2 EOR studies. The dual-porosity, structured grid model in this paper will be history-matched with actual data collected from the field to ensure the results of CO2 EOR study to be meaningful. In addition, we are implementing the simulation in the dual-porosity mode to account for the presence of natural fractures which have been observed on Eagle Ford outcrop. First, all data will be gathered from public sources. These data include production reports, outcrop map, natural fracture, hydraulic fracture, geology, rock, and fluid. Multiple grid sizes and number of refinements for hydraulic fractures will be tested to ensure the accuracy of the simulation is preserved yet speed up computational time. Several sensitivity analyses will be conducted to investigate which parameters from the matrix system and the natural fracture system would have a significant impact on the incremental oil recovery. These parameters will be adjusted scientifically in the process of history matching to capture the primary depletion. Then, this history-matched model will be used to apply multiple CO2 EOR studies. The history matched model suggests that matrix porosity in the volatile oil region of Eagle Ford shale might be overestimated in many previous investigations. Also, the sensitivity analyses show that the natural fracture permeability perpendicular to the direction of the horizontal well has a significant impact on oil rates in numerical simulation. Among different CO2 EOR methods tested in this research, huff-n-puff yields the most promising outcome as compared to continuous injection and WAG (Water-alternating-gas) in both oil production and economic performance in the volatile oil region of the Eagle Ford shale. In some circumstances, continuous injection method might yield great utilization efficiency but it contains high possibility of negative incremental oil recovery at the end of EOR practice due to pressure loss during CO2 injection time, incomplete miscible process between CO2 and residual oil, and viscous fingering.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.69)
- Geology > Geological Subdiscipline (0.68)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.68)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (3 more...)
Building Calibrated Hydraulic Fracture Models from Low Quality Micro-Seismic Data and Utilizing it for Optimization: Montney Example
Kassim, Rashid S. (Missouri University of Science and Technology) | Britt, Larry K. (NSI Fracturing, LLC) | Dunn-Norman, Shari (Missouri University of Science and Technology) | Lang, Bryan (Black Swan Energy Ltd.)
Abstract The Montney Formation stretches from southwestern Alberta to northeast British Columbia in Canada, and is one of the largest and most prolific shale plays in North America. The Montney Formation is also unique because it has conventional, over-pressured gas and an over-pressured liquids rich fairway. However, since the first multiple fractured horizontal well was drilled in 2005, there has been proposals for optimizing completions using different fracturing fluid systems and completion techniques. The low oil and gas price environment and the ensuing cost control mechanisms coupled with better understanding of what works in the Montney Formation, made the utility of some of the previously proposed optimization designs like "fracture effectiveness" which used energized fracturing fluids less desirable completions method. However, completion optimization methods like "operational effectiveness" which used high-rate slick water with increasing proppant mass per stage become the dominant stimulation method in the Montney Formation. But what has been missing was how to integrate fracture design and optimizations using all available information such as step-rate test, mini-frac, DFIT (diagnostic fracture injection test) analysis, well logs, geo-mechanical data, fracability index, core data, micro-seismic mapping data, and post-fracture analysis to improve fracture design and optimize the well completions. The objective of this paper is to present a new methodology for building calibrated fracture models from low quality micro-seismic data that has either location uncertainty or signal-to-noise ratio issues, and use it to optimize well completions. The process involves two-steps; first, the hydraulic fracture design was modeled and then calibrated using only micro-seismic mapping data from fracture stages that were closest to the micro-seismic geophones (avoiding location uncertainty or signal-to-noise ratio issues). This allowed us to construct a robust and reliable fracture geometry model. For each of the wells in the study, all fracture stages were then history matched and remodeled using the calibrated fracture model. Secondly, each well was optimized by incorporating fracture cluster sensitivity (2, 3, 4, and 5 clusters per stage), proppant mass sensitivity (50 kg, 75 kg, 100 kg, and 150 kg per stage) and fracture spacing sensitivity (20 m, 25 m, 33 m, 49 m and 98 m per stage). The result from this study shows that a highly optimized fracture model can be constructed from low quality micro-seismic mapping data that had location uncertainty due to the use of one monitoring well or signal-to-noise ratio issues. Secondly, the result also shows that increasing the number of clusters per stage and proppant mass per stage improves well production and recovery. However, the question is are these improvements short time gains, and what is the balance between well productivity and economics? Thirdly, in this study, we propose using measureable and known metrics to optimize wells such as average "hydraulic" fracture half-length, propped fracture half-length and conductivity for multi-clustered fracture stages. Ideally, well performance should be obtained from lookbacks instead of pounds per lateral length of the horizontal well (i.e. 2,400 lb. /ft.) or fixed volume/proppant for each stage or fixed clusters per stage without any empirical data to support it. While there are no two shale formations that are alike, most of the findings from this study are transferable and applicable to other unconventional resources. For instance, the paper presents; A new method for building calibrated fracture models from low quality micro-seismic mapping data that has location uncertainty or signal-to- noise ratio issues. A new method for optimizing fracture designs using cluster sensitivity analysis with varying proppant mass per fracture stage that can be used for scenarios analysis. A methodology for optimizing fracture design models by adjusting fracture treatment volumes and proppant mass per stage based on well stage location and available net treatment pressure.
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.56)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.34)
Abstract Flowing material balance (FMB) analysis is a practical method for determining original hydrocarbon volumes in-place. It is attractive because it enables performing material balance calculations without having to shut-in wells to obtain estimates of reservoir pressure. However, with some exceptions, its application is limited to single-phase oil and/or gas reservoirs over limited pressure ranges during depletion. In unconventional reservoirs, reservoir and/or production complexities may further restrict FMB usage. Among these complexities are significant production/injection of water, production resulting in higher Gas-Oil-Ratios and pressure drawdowns, geomechanical effects, and multi-well production effects. As a result, application of the conventional FMB to unconventional reservoirs may lead to significant errors in hydrocarbons-in-place estimation. This paper first discusses the application of conventional FMB to the analysis of single or multi-phase flow in single or multi-well scenarios, and then provides a new, comprehensive version of the FMB to address the above-mentioned complications. For the new FMB, pseudo-pressure is used to account for two-phase oil and gas flow. In addition, by using a general material balance equation, water production/injection and multi-well effects are included in the analysis. The new FMB analysis approach is validated by comparing results against numerical simulation of multi-fractured horizontal wells (MFHWs). These comparisons demonstrate that, not only gas production, but also water production/injection, can have a significant effect on the calculated original in-place hydrocarbon volumes. The new FMB analysis approach provided herein successfully accounts for all flowing phases in the reservoir, and is demonstrated to be applicable for multi-well scenarios. The methodology presented in this paper maintains the simplicity of FMB, yet accounts for multi-phase flow and multi-well complications. The developed FMB and the presented approach can be used by reservoir engineers to reasonably determine the original volumes of hydrocarbons in-place in both conventional and unconventional reservoirs.
- Europe (0.46)
- North America > Canada > Alberta (0.28)
Abstract Common earth modeling practice propagates rock properties into the model from depositional lithofacies obtained from log and core analyses. The primary objection to this method is that the rocks, particularly carbonates, do not truly reflect the depositional framework. Diagenetic and other post-depositional processes have extensively modified the rocks. These processes tend to homogenize depositional fabrics, thus obliterating specific relationships needed to accurately predict and propagate properties. Geologically reliable lithofacies for conventional and unconventional reservoir modeling can be obtained with unsupervised multivariate classification procedures applied to suites of log curves. Data analytics applied to log data can provide lithologies and flow units across the reservoir. Important rock properties that are critical inputs for a static earth model are included as part of the lithofacies definition. Because lithofacies obtained from logs are partially based on the analysis of crossplots calibrated to rocks when possible, log-based facies definitions are subject to the experience-based bias of the project interpreter. Crossplots used for facies analysis often show complex patterns that suggest the multivariate nature of relationships between individual logs. Incorrect facies specification can lead to an inaccurate depiction of the lithologic geometry, which is a key shortcoming of this approach. The paper describes data analytics as applied to log data, developed as an aid to understanding lithologies and flow units across a stratigraphic interval. A workflow was created that enables natural groups inherent in the data to be obtained. This approach does not require a priori rock type information. Multivariate procedures are applied to a selection of curves that comprise a log suite over an interval of interest to obtain log response groups based on log curve variation. These response groups can be used to propagate critical porosity and permeability data into the model. The workflow described in this paper was successfully applied in several mature areas that include unconventional plays in the Delaware and Midland basins of west Texas and the Burgos basin of Mexico. New well locations and horizontal drilling targets selected with the recommended methods have performed significantly better than wells drilled without using this approach. The new approach to rock typing presented in this paper is compatible with modern earth modeling methods and can improve drilling success by highlighting areas with more favorable rock properties. The sequence in which individual methods are applied is important in this workflow. Assumptions regarding distributional properties of the individual data elements are not required. Experience shows that this workflow provides improved understanding of lithological variation over the volume of interest, increasing the probability of better well performance.
- North America > United States > Texas (1.00)
- North America > Mexico (1.00)
- Geology > Rock Type > Sedimentary Rock (0.94)
- Geology > Geological Subdiscipline > Stratigraphy (0.88)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Midland Basin > Wolfcamp A Formation (0.99)
- (18 more...)