bluuebunny/crossref_metadata_2025_split huggingface dataset:
Multiscale Imaging of Gas Adsorption in Shales
Authors: Aljamaan Hamza , Ross Cynthia M. , Kovscek Anthony R. 
Published: February 2017

Abstract
Four intact one-inch diameter cores from different shale plays (Barnett, Haynesville, Eagle Ford, and Permian Basin) were analyzed for their gas storage capacity using a novel multiscale imaging methodology spanning from cm- to nm-scale. Gas storage capacity was investigated at the core-scale with carbon dioxide (CO2) and krypton (Kr) using X-ray computed tomography (CT) with voxel dimensions of 190×190×1000 μm. Also, 2D tiled images were acquired using a scanning electron microscope (SEM) and stitched together to form one-inch diameter mosaics with a pixel resolution of 1.5 μm. Multiscale image registration was then carried out to align the CT data with the SEM mosaics. Energy dispersive spectroscopy (EDS) generated elemental spectra maps and subsequent component maps for regions with either substantial or minimal gas storage to assess the interplay of structural features (e.g., fractures) and matrix composition with respect to gas accessibility and adsorption.
Registration of CT scans (vacuumed and gas-filled) as well as 190 µm-resolution CT-derived gas storage maps with 1.5 µm-resolution SEM mosaics is straight forward for samples with dense features (such as calcite-filled fractures) that are resolvable by CT imaging. Alignment methods were developed for samples lacking these features including registration marks using silver paint and intermediate resolution microCT scans with cubic voxel dimensions of 27 μm. Once aligned, the relationship of enhanced adsorption zones with open fractures and reduced adsorption regions with secondary mineralization (such as nodules) is apparent for the carbonaceous samples. For the clay-rich Barnett sample, fracture-filling calcite is associated with reduced adsorption similar to the other samples; however, secondary carbonate cementation within the clay matrix aligns with regions with substantial Kr and CO2 gas storage. In contrast, clay-rich matrix regions lacking secondary carbonate cementation exhibit minimal gas storage potential. Causes for this unexpected result include reduced gas accessibility and, possibly, low organic matter content in the clay-rich matrix compared to secondary cemented matrix.
These gas adsorption experiments prove the feasibility of dynamic core- to nm-scale CT/SEM/EDS image registration to improve sample characterization. To our knowledge, this is the first investigation of core-scale CO2 gas adsorption employing multiscale imaging. CT and SEM image registration reveal spatial details regarding gas accessibility and storativity at the core-scale. This work also supports the potential of carbon storage in shale formations as well as guides engineers toward optimal CO2 injection zones for enhanced gas recovery.
Historical Terminal Decline Rates Review of Unconventional Reservoirs in the United States
Authors: Hale Brent W , Hall Russell K 
Published: February 2017

Abstract
The United States has had a significant oil and gas industry since Mr. Drake's oil well in Pennsylvania in 1859 attracted attention to the drilling of wells to produce oil. In the last decade, technology advances in both drilling and completion technology have had a significant impact on the ability to develop oil and gas reserves and have produced a new generation of wells for which extensive histories are not available at this time. A review of available historical data helps establish reasonable limits for decline trends of newer developments.
In order to better place limits on terminal decline rates for unconventional plays, data are presented showing terminal decline rates for a selected vertical developments and for selected horizontal developments in the United States. The curves reviewed include 292 type wells in 54 different producing horizons in the United States.
Some oil and gas developments have over 60 years of history and low decline rates. Others have high initial decline rates which do not flatten as expected for horizontal wells in low permeability reservoirs. The data for many of the developments also shows that decline trends beyond 10 to 20 years are frequently impacted by workovers and recompletions which have a significant impact on projected decline rates for a large number of long life wells.
Where both vertical and horizontal wells have been developed in an unconventional play, vertical well decline rates are generally less than horizontal well decline rates. The data also shows that gas decline rates are generally less than oil decline rates. When considered as a group, there is a band of decline rates which establishes reasonable upper and lower limits for newer developments using horizontal drilling and newer completion technology.
Experimental Investigation for Microscale Stimulation of Shales By Water Imbibition During the Shut-in Periods
Authors: Gupta Aadish , Xu Mingxiang , Dehghanpour Hassan , Bearinger Doug 
Published: February 2017

Abstract
Imbibition of water into the shale matrix is known as the primary reason for inefficient water recovery after hydraulic fracturing treatments. The hydration of clay minerals may induce microfractures in clay-rich shale samples. The increased porosity and permeability due to induced microfractures has been considered to be partly responsible for 1) excessive water uptake of gas shales, and 2) increase in hydrocarbon production rate after prolonged shut-in periods. To test this hypothesis, it is necessary to measure imbibition-induced strain and stress under representative laboratory conditions.
In this study, we conduct laboratory tests to 1) measure the strain and stress induced by water imbibition in gas shales and 2) investigate the effect of confining load on the rate of water imbibition. We conduct a three-phase study on rock samples from the Horn River Basin (HRB) and the Duvernay (DUV) Formation, located in the Western Canadian Sedimentary Basin. In the first phase, we measure baselines for water and kerosene imbibition into the rock samples by conducting spontaneous imbibition tests. In the second phase, we measure expansion of the rock samples during imbibition of water and kerosene, in separate tests, using a linear variable differential transformer (LVDT). In the third phase, we measure imbibition-induced tensile stress during water imbibition into the samples.
The results show that both HRB and DUV shale samples imbibe more water than kerosene, due to water adsorption by clay minerals. Imbibition of water increases the porosity of the HRB and the DUV samples by up to 0.94 and 0.25 percentage points, respectively. Expansion of all samples is anisotropic, with higher expansion perpendicular to the depositional lamination. Water imbibition into the samples induces an expansive stress as high as 17 psi. Moreover, applying confining stress reduces the imbibition of water by up to 18.1% and 33.7% in the HRB and DUV samples, respectively.
Factors Affecting Huff-n-Puff Efficiency in Hydraulically-Fractured Tight Reservoirs
Authors: Kanfar M. S. , Clarkson C. R. 
Published: February 2017

Abstract
Evaluation of enhanced liquid recovery from tight or shale reservoirs is currently of great interest to operators. One reason is the low primary oil recovery of tight/shale reservoirs, which ranges between 5-10% (Shoaib and Hoffman, 2009) even after expensive multi-stage hydraulic fracture stimulation. Enhanced recovery using the "huff-n-puff" process could be an effective solution to increase recovery without drilling new wells.
There are a number of published lab and simulation studies that investigate the efficiency of huff-n-puff in tight/shale reservoirs. These studies, however, have yielded contradictory results. For example, Chen et al. (2014) concluded that huff-n-puff has a negative impact on recovery while Yu et al. (2014) concluded that it improves recovery by 2-9%. These conflicting results underscore the need for further research. The current study, therefore, endeavors to investigate possible causes of these discrepancies.
Compositional numerical simulation is used to investigate key simulation model setup and reservoir controls on huff-n-puff efficiency in tight reservoirs. Some of these controls have never been investigated for tight reservoirs, such as the influence of grid refinement, in-situ fluid composition, and fracture pore volume/hydraulic fracture representation.
One important finding of this work is that grid refinement, and fracture pseudo width, greatly impact huff-n-puff results. The combination of coarse gridding and improper fracture representation through the pseudo width approach can lead to falsely optimistic incremental recovery associated with huff-n-puff relative to primary recovery.
While the findings presented herein are useful in explaining possible causes of the discrepancies in results reported in previous work, they can also be used to improve huff-n-puff design. For example, the combination of fine fracture spacing in multi-fractured horizontal wells and increased fracture complexity can positively influence incremental recovery obtained from huff-n-puff. Further, the results suggest that huff-n-puff timing (with respect to primary production operations) should be carefully considered.
This study will help simulation engineers improve their evaluations of huff-n-puff in tight/shales reservoirs. Additionally, it will help operators decide which reservoir is suitable for huff-n-puff operations to improve liquids recovery. Application of the findings of this study to actual field scenarios will be presented as a separate work.
Practical Completion Design Optimization in the Powder River Basin - An Operator Case Study
Authors: Ingle T. , Ketter C. , Anderson D. M. , Thompson J. M. 
Published: February 2017

Abstract
This case study reviews the full development cycle of Devon Energy's Parkman asset in the Powder River Basin, from exploitation to infill drilling. The focus is on successive adjustments to drilling and completion design, with the objective of net-present-value (NPV) optimization. This effort is supported primarily through timely collection and interpretation of data, which has awarded Devon with exceptional returns on investment with reasonably low risk and capital expenditure, even in a low oil price environment. Devon's success in the Parkman is largely due to the practical and adaptive nature of the underlying engineering workflows supporting key decisions as well as management's strong support for the value of information.
The methodology is based on an integrated workflow, combining core, open-hole logs, reservoir surveillance (radioactive tracers and fiber optics) along with production and flowing pressure data. Rate Transient Analysis, fracture modeling and reservoir simulation are central components of the integrated model. At every stage in the development cycle, the model is calibrated to the latest data, at which point sensitivities can be run to evaluate alternative scenarios for optimizations required for the next stage. Through successive drilling and completion improvements, Devon has successfully increased the NPV of their Parkman asset. The steps toward optimization include increasing lateral length from 4,000' to 9,500'; adjusting cluster spacing between 60' and 100' and transitioning their completion method from plug-andperf to pinpoint. Understanding the impact of oil price is critical for achieving these optimizations. The improvements were supported by reservoir simulation and ultimately confirmed with field data, which is included in this work.
This work brings to the forefront lessons that could add significant value to the business of any unconventional operator: A practical methodology for quickly converting collected data into actionable knowledge; allowing continual adjustments to be made to an unconventional completion design that maximize its performance and economic benefitIntegration of engineering and geoscience disciplines to better understand the major influences on well performance in an unconventional playOptimizing completion design to maximize the profitability of a field development plan. In the case of the Parkman, pinpoint proves to be a more optimal completion technique
Application of Monte Carlo Simulation for Estimation of Vertical and Horizontal Biot's Constants Through Calibration of the Minimum Horizontal Stress in the Tight Gas Monteith Formation
Authors: Lopez Bruno , Aguilera Roberto 
Published: February 2017

Abstract
Tight formations are characterized by permeabilities equal to or less than 0.1 md. Due to these low permeability values, tight gas reservoirs have been economically produced through the implementation of multi-stage hydraulic fracturing. This operation requires a proper stimulation design, which depends on the knowledge of rock properties such as Biot's constants. Therefore, the purpose of this study is to determine vertical and horizontal Biot's constants through calibration of minimum horizontal stress (MHS) with the use of well logs and mini-frac data in the tight gas Monteith formation of the Western Canada Sedimentary Basin (W CSB).
The procedure utilized in this work consists of the determination of actual MHS values from mini-frac tests. It is assumed that MHS is equal to fracture closure pressure (FCP). Two non-linear regression equations are used to estimate MHS. Statistical analysis is performed to test the appropriateness of the non-linear regression expressions for MHS modeling. Next, MHS values are calculated from well log data using an existing correlation and by the application of Monte Carlo simulation. Uniform, triangular and beta-PERT distributions are considered in this study. Then, MHS values obtained from the above two methods are matched for calibration purposes. Finally, both vertical and horizontal Biot's constants are determined from the match previously obtained.
Statistical analysis of the two non-linear regression expressions for MHS modeling reveals that FCP ranges from 10.72 MPa to 17.78 MPa in the study area. From Monte Carlo simulations, it is found that horizontal Biot's constant values are most consistent among the different distributions considered in this study as compared with the case of the vertical Biot's constant. This large variation in vertical Biot's constants is a result of the uncertainty associated with the definition of the most suitable distribution for this variable. Horizontal Biot's constant values vary from 0.81 to 0.97 whereas vertical Biot's constant ranges from 0.66 to 0.95. It is concluded that beta-PERT distribution better represents Biot's constants, however, this finding has to be corroborated against experimental data.
The methodology presented in this work is robust and represents a practical method to determine Biot's constants instead of following the assumptions considered by current commercial 3D hydraulic fracture simulators. This is the first time that non-linear regression techniques, statistical analysis, and Monte Carlo simulation are coupled all together with both well log and mini-frac data to estimate Biot's constants. This methodology can be easily applied in other tight formations.
Proppant Optimization for Foam Fracturing in Shale and Tight Reservoirs
Authors: Gu Ming , Fan Ming , Chen Cheng 
Published: February 2017

Abstract
Slickwater frac is widely used for stimulating the productivity of unconventional shale and tight reservoirs nowadays. Slickwater produces long skinny fractures, but only the near wellbore region is propped due to fast settling of sand. Adding gel can slow down sand settling, but gel damages the fracture surface and proppant pack. Other issues include large water consumption, water damage, and high water disposal cost. Recently, a non-damaging, less water-intensive fracturing fluid system with improved sand placement efficiency, known as polymer-free foam (PFF), is developed by Gu (2013). The current objective is to study the impacts of sand pumping designs on PFF fracturing efficiency by conducting numerical modeling. In the first step, discrete element method (DEM) and lattice Boltzmann method (LBM) are employed to simulate proppant particle compression, rearrangement, and conductivity for different mesh sizes and areal concentrations under different fracture closure stresses. Next, the conductivity results are input in an in-house fracture propagation model to simulate the fracture conductivity distribution after foam fracturing. After that, the fracture conductivity distribution is input in a reservoir production model to predict the productivity. A parametric study is conducted to understand the impacts of sand mesh size and pumping load on foam frac. With the study, the optimal sand size and concentration are determined for the new fracturing fluid system in shale and tight reservoirs. Our results show, for 140 nD shale gas reservoirs, pumping mesh 100 sand at a volume ratio of 0.15 v/v, 0.125 v/v, and 0.1 v/v are optimal sand pumping designs for PFF treatments with foam quality of 60, 70, and 80%, respectively. If the reservoir permeability is ten times larger, the optimal sand pumping designs for 60, 70, and 80% quality PFF treatments are mesh 30/50 at 0.15 v/v, mesh 100 at 0.125 v/v, and mesh 100 at 0.125 v/v, respectively. With the optimization of sand pumping design, well production can be increased by 110% for low permeability shale, or by 70-100% for high permeability tight or naturally-fractured shale formations. This paper develops a time-efficient workflow to optimize sand pumping strategy for the new PFF fracturing system. The methodology includes coupled DEM/LBM modeling of proppant conductivity, fracture modeling, and reservoir production simulation. The PFF fracturing system with optimized sand mesh size and load can provide enhanced productivity with less water consumption, less gel and water damage, and lower water disposal cost.
Measured Crude Oil MMPs with Pure and Mixed CO2, Methane, and Ethane, and Their Relevance to Enhanced Oil Recovery from Middle Bakken and Bakken Shales
Authors: Hawthorne Steven B. , Miller David J. , Grabanski Carol B. , Sorensen Jim A. , Pekot Lawremce J. , Kurz Bethany A. , Gorecki Charles D. , Steadman Edward N. , Harju John A. , Melzer Stephen 
Published: February 2017

Abstract
Enhanced oil recovery (EOR) processes using CO2 in tight unconventional plays like the Bakken Formation are expected to be very different from the processes which control EOR in conventional reservoirs. During CO2 EOR in conventional reservoirs, CO2 flows through the permeable rock, and the minimum miscibility pressure (MMP) is an important operational parameter for achieving a successful "miscible" flood. In contrast, in tight fractured systems like the Bakken, CO2 flow may be dominated by fracture flow, and not by CO2 flowing through the rock matrix as in a conventional reservoir flood. Since fracture-dominated CO2 flow could essentially eliminate the "flushing" mechanisms responsible for increased recovery in conventional reservoirs, operation at or slightly above MMP may or may not be relevant for the success of an EOR flood in such tight fractured reservoirs. To investigate this concept, capillary-rise vanishing interfacial tension (VIT) was used to measure MMP values for a typical Bakken crude oil (API gravity 41.5) with CO2, methane, and ethane at 110°C (230°F) typical for the reservoir. The effect of these different fluids, as well as the effect of pressures at, above, and well above MMP on recovering crude oil hydrocarbons was determined for small rock core samples from the productive Middle Bakken laminated zone as well as from Upper and Lower Bakken samples.
Compared to the MMP value for CO2 of 2520 psi, MMP with methane nearly doubled at 4510 psi, but was nearly cut in 1/2 for ethane at 1360 psi. The recovery of crude oil hydrocarbons from both the Middle Bakken and Lower Bakken shale samples with 24-hour exposures to these fluids at reservoir pressures showed efficiencies that parallel the MMPs determined with each fluid; i.e., ethane yielded faster and more efficient recovery of the crude oil than CO2, but both CO2 and ethane were much more efficient than methane at recovering the crude oil from the 11-mm round rod rock samples. Although hydrocarbon recoveries from the rock samples paralleled each injectant's respective MMP values, extractions with CO2 at the MMP, and at ca. double and triple the MMP pressure showed much more efficient crude oil recoveries at higher pressures from both the Middle Bakken and Lower Bakken shale, demonstrating that EOR pressures much higher than the MMP could substantially increase oil recoveries in tight unconventional systems like the Bakken.
Estimating Oil Saturation Index OSI from NMR Logging and Comparison with Rock-Eval Pyrolysis Measurements in a Shale Oil Reservoir
Authors: Piedrahita Jaime , Aguilera Roberto 
Published: February 2017

Abstract
Identification of potential oil flow zones in shale reservoirs has been conducted in the past with the use of an oil saturation index (OSI) determined from Rock-Eval pyrolysis measurements on samples collected at pre-specified depths (partial sampling). This study introduces a new equation that allow continuous OSI determination with the use of the Nuclear Magnetic Resonance (NMR) log.
Geochemical analysis using measurements from Rock-Eval pyrolysis and LECO Carbon Analyzer laboratory techniques were carried out in a shale oil reservoir for estimating parameters such as total organic carbon (TOC) and OSI. This allowed identification of hydrocarbons zones. Next, Cross-over and OSI cut-off techniques were applied to distinguish intervals with producible and non-producible hydrocarbons. Subsequently, NMR total response relaxation time, T2, was divided into eight T2 cut-offs to calculate bin porosities. A sensitivity analysis for T2 cut-offs was run in order to establish a good match between the bin porosity and OSI values that indicate producible hydrocarbons.
A good agreement was reached among OSI greater than 100 mg HC/gTOC and the bin porosities estimated between T2 = 33ms and 80 ms. This match was corroborated by the visual "oil cross-over" from geochemical analysis. An OSI cut-off equal to 100 mg HC/g TOC has been recommended in the past by several authors to differentiate producible from non-producible oil intervals. That cutoff compares well with the NMR bin porosity developed in this paper. Thus, the porosity estimation between above T2 cut-offs is a good indicator of producible hydrocarbons in a shale oil reservoir. This observation has led to the development of a new equation in this paper to convert the NMR bin porosity to OSI (or vice versa) continuously throughout the NMR logged interval.
Also, if TOC is already known from a given method (for example, Passey, Smocker, GR spectral, Uranium), the S1 parameter can be estimated from only well logs resulting in continuous S1 and OSI curves. This is a very significant advantage since Rock-Eval pyrolysis and LECO analyzer are run on samples which are taken at predefined depths (partial sampling); therefore, possible producible oil zones could be bypassed if only core results are taking into account.