bluuebunny/crossref_metadata_2025_split huggingface dataset:
Challenges and Opportunities for Commercial-Scale Carbon Capture and Storage in Kansas
Authors: Holubnyak Yevhen , Dubois Martin , Hollenbach Jennifer , Hasiuk Franciszek 
Published: September 2019

Abstract
Results of the Integrated CCS for Kansas pre-feasibility study indicate that large-scale CO2 capture, transportation and storage in saline aquifers in Kansas is both technically and economically feasible and deserving of further study. Based on the technical work on multiple geologic sites, there appear to be up to four sites within the North Hugoton Storage Complex (NHSC) in Southwest Kansas where &gt;50 million tons CO2 could be injected over a 25- to 30-year period and safely stored in a set of stacked saline aquifers at ideal depths of 5200-6400 ft. The saline aquifers (Mississippian Osage, Ordovician Viola, and Cambrian-Ordovician) are overlain by oil reservoirs that are candidates for CO2 Enhanced Oil recovery (EOR). Of the four possible sites in the NHSC, the Patterson site was chosen as the primary site for a CarbonSAFE Phase II project. Patterson was chosen because the operator of the overlying fields, Berexco, was a long-term research partner of the Kansas Geological Survey (KGS), having participated in several DOE-funded studies with the KGS. Patterson has EOR opportunities in overlying reservoirs and most of the prospective injection site is already unitized.
Capture, compression and transportation of large volumes of CO2 is economic in the region, particularly since the extension and expansion of Federal 45Q tax credits in February 2018 that provide $35/ton for CO2 stored during EOR and $50/ton if stored in a saline reservoir and can be captured for a 12-year period. Without these credits, saline aquifer storage is not economically viable. The most economic scenario involves CO2 aggregated from multiple ethanol plants via small-diameter pipelines that tie into a main trunk line for delivery to market. CO2 EOR likely needs to be part of the system to provide economy of scale and, potentially, additional subsidy for saline aquifer injection through CO2 sales. High capture costs at the two power plants and refinery in this study make them non-economic options without further subsidy that may arise from a large regional pipeline system.
Legal, regulatory, public policy aspects of a project of the scale envisioned will require significant changes at the State level. In particular, legislation that would regulate capture, transportation, injection and storage as a public utility would be required along with allowances for eminent domain to be used for pipeline right-of-way and pooling of pore space. Streamlining the U.S. EPA UIC Class VI well permit process and/or establishing State primacy would further support development of commercial-scale CCS. Effective public outreach is critical for support of State regulatory changes, and for public acceptance, particularly in light of possibility for induced seismicity due to injection in certain areas and mixed public opinions about pipeline construction.
Identifying Depleted Induced Fractures from Offset Wells Using Common Drilling Data
Authors: Wutherich Kevin , Srinivasan Sridhar , Downie Robert , Katon Bill 
Published: September 2019

Abstract
This paper presents a new methodology that takes readily available drilling data, to identify the location and relative magnitude of localized depletion that is likely caused by induced fractures that are intersected by a newly drilled well. This paper describes the process used to identify the fractures and presents a case study in the Utica Shale that validates the results.
In recent years, mechanical specific energy (MSE) has been used to assess mechanical properties of rocks. It is further known that changes in reservoir pressure will also influence MSE. This new process analyzes a modified mechanical specific energy, and looks for anomalous increases in MSE, which should be present when drilling through a depleted fracture. To verify the existence of depleted fractures, a set of three wells were analyzed using this technique, a parent well, and two child wells.
Analysis showed that there were no signs of depleted fractures detected in the parent well, while the two child wells both contained multiple drilling signatures that were consistent with depleted fractures. The location of the apparent depleted fractures in the child well were not only consistent with the location of the parent well, but also sections in the parent well that were most likely to create dominant fractures.
The identified fractures in the child wells, also were consistent in location, magnitude and area of effect across both wells. These consistencies further promote the conclusion that dominant fractures created while completing the parent well, being penetrated and identified in both child wells.
Based on the work done, there is clear indication that the proposed methodology can potentially be used to identify depleted fractures. This information can further be used in order to design completion strategies aimed at reducing both the probability and severity of parent-child fracture interactions such as frac hits.
The paper presented will describe the first successful attempt to characterize depleted induced fractures using standard drilling data, without the use of any additional tools being run in the wellbore. This process will provide significant impact, not only in designing completions for parent-child well pairs, but will also further the understanding of far field fracture effects such as the extent of fracture extension, depletion around a fracture, and implications for well spacing.
Waterflooding Optimization under Geological Uncertainties by Using Deep Reinforcement Learning Algorithms
Authors: Ma Hongze , Yu Gaoming , She Yuehui , Gu Yongan 
Published: September 2019

Abstract
Recently, substantial technical progress has been made to solve complex tasks in the field of artificial intelligence (AI) by incorporating deep neural networks into reinforcement learning (RL). In this paper, four state-of-the-art deep RL algorithms are applied to optimize the net present value (NPV) of waterflooding (WF) under geological uncertainties by adjusting the water injection rate. They include the deep Q-network (DQN), double DQN (DDQN), dueling DDQN, and deep deterministic policy gradient (DDPG). A set of fifty reservoir realizations are generated by using a geostatistical technique to account for the geological uncertainties. It is found that the deep RL algorithms can optimize the WF in a 3-D 3-phase (oil-water-gas) reservoir under geological uncertainties. More specifically, both DQN and particle swarm optimization (PSO) converge to the same highest NPV, whereas the other three deep RL algorithms can find some local optimum NPVs due to the exploration-exploitation problem. DDPG converges faster than PSO and requires the least numerical simulation runs among all deep RL algorithms. The optimum water injection rate determined in the consideration of geological uncertainties not only increases the expected NPV but also reduces its standard deviation. The optimum WF starting time is found to be in the middle of the primary production. In this way, the solution-gas drive is continued and the water-cut is decreased. The production performances are compared under three different water injection scenarios: no-control, reactive-control, and optimum-control. The optimum-control scenario achieves a low water-cut and a stable oil production rate.
Early Warning Systems - Using PTA Analysis of DFITs to Understand Complex Hydraulic Fractures and Optimize Treatment Designs
Authors: Nicholson A. Kirby , Hawkes Robert V. , Bachman Robert C. 
Published: September 2019

Abstract
This paper outlines methods to characterize hydraulic fracture geometry and optimize full-scale treatments using knowledge gained from Diagnostic Fracture Injection Tests (DFITs) in settings where fracturing pressures are at or above the overburden gradient.
Hydraulic fractures, whether created during a DFIT or a larger scale treatment, are usually represented by vertical plane fracture models. These models work well in a relatively normal stress regime with homogeneous rock fabric where fracturing pressure is less than the Overburden (OB) pressure. However, many hydraulic fracture treatments are pumped above the OB pressure. This high pressure may be caused by near well friction or tortuosity but may also be the result of more complex fractures in multiple planes.
Bachman et al (2012, 2015), Hawkes et al (2018) and Nicholson et al (2019) advanced DFIT analysis by using the Pressure Transient Analysis (PTA) technique. This allows the identification of flow regimes useful for understanding fracture geometry and closure behavior beyond that available from more familiar G-function analysis techniques. In this paper DFITs from the Duvernay, Montney, Rock Creek and Cardium formations of Western Canada are analyzed using the PTA method. Particular attention is given to Early-Time Flow Regimes (ETFRs) present between the end of pump shut-down (End of Job Instantaneous Shut-In Pressure, EOJ ISIP) and the 3/2-slope Nolte flow regime. Identification of pressure gradients at the start and end of these flow regimes is of vital importance to the interpretation process. This allows the authors to build on case histories of DFIT-derived fracture geometry interpretations presented in Nicholson et al (2017, 2019).
Procedures are proposed for picking Farfield Fracture Extension Pressure (FFEP) in place of conventional IIP estimates while distinguishing between storage, friction and tortuosity vs. fracture geometry indicators. Analysis of FFEP and ETFRs combined with the context of rock fabric and stress setting are useful for designing full-scale fracturing operations. A DFIT may help identify potentially problematic multi-plane fractures, predict high fracturing pressures or screen-outs. Fluid and completion system designs, well placement and orientation may be adjusted to mitigate some of these effects using the intelligence gained from the DFIT early warning system.
An Experimental Investigation of Dynamic Behavior of Gravity-Driven Downhole Separators
Authors: Lopez Jorge , Pereyra Eduardo , Sarica Cem 
Published: September 2019

Abstract
An experimental study of a gravity-driven downhole separator for a pumped horizontal or deviated well is presented in this study. It considers the effects of the upstream flow, gas and liquid flow rates and deviation angles on the global separation efficiency and the free gas at the pump intake.
The efficacy of downhole separators is typically tested under steady-state conditions where the fluids are injected above the separator. A new outdoor facility, which allows the injection of a two-phase mixture below the separator was designed, constructed, and used in this study. Gas and liquid flow rates and deviation angle are varied to study the liquid holdup in the liquid-rich outlet and the separator efficiency.
The experimental results demonstrate the effects of the operation conditions and deviation angle on the behavior of downhole separators. It is found that the separator has two regions of performance; namely, high efficiency region and a region where the efficiency decreases with the liquid flow rate. Moreover, the effect of the deviation angle affects the results. The findings provide conditions under which and where the separator can be operated efficiently in the field.
A New Method of Digital Core Construction and Analysis for Unconsolidated Sandstone
Authors: Dai Zong , Li Hailong , Tang Fang , Luo Donghong , Wang Yahui , Yan Zhenghe 
Published: September 2019

Abstract
A new method of digital core construction and analysis for unconsolidated sandstone is presented in this paper to solve the problem for friable cores. Results are compared with conventional experimental techniques and routine digital core construction methods.
The new method procedures: Firstly, rocks are full-closure cored from unconsolidated formation and frozen; multi-scale (meter/millimeter/micron) CT scanning for core samples with original formation fluids, and the core heterogeneity has been analyzed. Then, skeleton and pore space of samples are segmented with the watershed algorithm. Finally, pore network model is extracted with maximum sphere method. After building the digital core, petrophysical parameters and fluid flowing characteristic are simulated.
Compared with conventional experimental method, samples preparation is convenient under lower requirements of the size and shape. Without cleaning, the distortion of experimental parameters are avoided due to damages to the original pore structure of friable core samples, especially for unconsolidated samples. Compared with conventional digital core construction, the focused scanning mode is used for micron scanning, without catching the smaller samples. The new method not only simplifies the preparation of conventional core analysis that reduces the difficulty of sample preparation of unconsolidated sandstone natural core, but also guarantees the quality of core analysis data.
The new method is successfully applied and results are compared in field of South China Sea. The results from different methods with consolidated samples analysis, such as porosity, permeability and parameters of relative permeability, show the relative errors are less than 10%. The results from unconsolidated samples analysis with conventional experimental method show obvious errors: permeability of some samples are more than 15 Darcy, the relative permeability curve is obviously not consistent with the actual field performance. While results from unconsolidated samples analysis with the new method show good agreement with actual field performance.
This method can accurately test the petrophysical parameters of unconsolidated sandstone, reduce the experimental errors caused by conventional methods and shorten the experimental schedule. It could be applied to core analysis of similar formation.
Improved Data Mining for Production Diagnosis of Gas Wells with Plunger Lift through Dynamic Simulations
Authors: Zhu Jianjun , Cao Guangqiang , Tian Wei , Zhao Qingqi , Zhu Haiwen , Song Jie , Peng Jianlin , Lin Zimo , Zhang Hong-Quan 
Published: September 2019

Abstract
Plunger lift has been widely used in unconventional gas wells to remove liquid accumulation from the well.. Production surveillance provides large amount of data of production process and normal and abnormal operations, which can be used in machine learning (ML) and Artificial Intelligence (AI) to develop algorithms for anomaly diagnosis and operation optimization. However, in the surveillance data the majority is related to daily operation and the data of failure cases are rare. Also the failure cases may not be repeatable and many failure case signatures are not available until they happen. Large data size of anomaly cases are needed to improve the ML model accuracy. Dynamic simulation of the plunger lift process offers an alternative way to generate synthetic data on the specified anomalies to be used to train the ML model. It also helps better understand the trends reflected in the surveillance data and their root causes.
From the available surveillance data of gas wells equipped with plunger lift, the simultaneous measurements of different parameters at different points in a production system with normal and abnormal occurrences can be analyzed and the correspondent trends/signatures can be identified. The typical signatures that conform to pre-determined anomalous patterns can be obtained. Using a commercial transient multiphase flow simulator, the actual field data of tubing/casing pressures can be matched through a tuning process. Trial-and-error is needed to improve the dynamic plunger lift model so that a good agreement with the production data can be achieved by adjusting the reservoir performance, plunger parameters or surface pipeline boundary conditions. Following the validation under different flow conditions, synthetic datasets for various operational and flow conditions can be generated by performing parametric studies. Unlike the field data, the synthetic data from the dynamic simulations mainly comprise anomaly signatures (e.g. tubing rupture, missed arrival of plunger, etc.), which can be added to the ML data pool to reduce the data covariance and increase independency.
Flowback Production Optimization for Choke Size Management Strategies in Unconventional Wells
Authors: Bagci Suat , Stolyarov Sergey 
Published: September 2019

Abstract
The flowback period of the unconventional wells is very critical as it can cause determential ecomonical effects if not properly optimized. The success of the well is as dependent of the completion program as it is from the flowback program applied during the initial production period of the well. If ineffective operations are performed on the flowback phase {independently on the completion technology}, the well can underperform and become unsuitable for development.
In unconventional wells, it is necessary to develop the safe well operating envelope in safe zone to prevent the early proppant flowback based on the reservoir parameters and the completions in place. The well can start producing in this developed safe well operating envelope by controlling the wellhead pressure and surface valves and optimizing the proper choke size to keep the well with free proppant production.
Proppant flowback production modeling captured decline of water production as well as the increase of liquid production when a selected choke sizes is applied. By controlling the flowing bottomhole pressure (FBHP) during defined flowback period, the volume of proppant production decreased with decreasing chokes sizes and increasing long flowback periods. This study showed that the optimized choke sizes to improve the longer production periods depended on the sensitivity of pressure drawdown, liquid rates, wellhead pressure, and fracture geometry parameters. Numerical results showed that the critical parameters affecting the stability of the proppant pack are fracture closure pressure, reservoir pressure, proppant type and size, and type of fracturing fluid. Proppant flowback program developed by using optimized choke size, wellhead pressure (WHP) and FBHP, and amount of producible proppant volume predicted for designed flowback production periods. At the beginning of the flowback period, the wellbore is filled with fracturing fluid and the minimum choke size should be used as small as possible (12/64"). The controlled FBHP management over 45 days of flowback period corresponds to an average drawdown rate of 10 psi/day to 200 psi/day. Finally, the developed workflow applied to design flowback periods and selection of choke sizes to prevent excessive proppant production and proppant crushing in hydraulically fractured unconventional wells.
This paper presents the methodology and workflow for selecting the required choke sizes and flowback periods to minimize the risk of production of high volume proppant during the flowback period after fracturing. The case study presented here in will present the benefits of optimizing choke sizes and flowback programs for reducing the damage to fracture conductivity and to increase the cumulative production. The optimized choke sizes, flowback strategies and workflow established with this case study have proven to increase the performance of fractured unconventional wells.
Measurement of Reduced Permeability at Fracture Face Due to Proppant Embedment and Depletion - Part II
Authors: Karazincir Oya , Li Yan , Zaki Karim , Williams Wade , Wu Ruiting , Tan Yunhui , Rijken Peggy , Rickards Allan 
Published: September 2019

Abstract
Fracture face permeability loss related to proppant embedment under depletion conditions is one of the factors that contribute to PI decline in hydraulically fractured reservoirs. The damage is a result of proppant embedment and proppant/core crushing that also generates fines and plugs the pores in the embedment zone. A recently developed test method was used to measure the effects of embedment on permeability reduction at the fracture face as a function of depletion, core porosity and permeability, core UCS and injected fluid types. A range of stresses was applied to the cores and the permeability values across the fracture face were tracked and compared.
Standard proppant conductivity tests only measure permeability / conductivity losses within the proppant pack due to frac gel damage and compaction and do not measure the damage at the fracture face.
Recently, we developed a new test method that can directly measure fracture-face permeability under depletion. The test flows fluid from the matrix into the fracture thus coupling permeability measurements within the proppant pack with those across the fracture face. Initial tests were conducted in intermediate permeability, intermediate strength rock. The resulting core permeabilities were compared to the values from conventional core permeability tests. The proppant conductivity values were compared to those measured using a modified API conductivity test set-up. During the second part of this study, a lower permeability, higher UCS rock system was tested and permeability decline was measured as a function of applied stress and flow rate. Cores saturated with different fluid systems were tested to mimic injected fluid imbibition into the fracture face and their effect on proppant embedment and permeability loss. A numerical model was built to calculate fracture face permeability reduction as a function of depletion and injected fluid systems in different types of fractured formations. By incorporating embedment induced permeability reduction into the detailed reservoir geomechanics model, we are able to evaluate the contribution of proppant embedment on overall PI decline. During post-test analysis, proppant embedment percentage and porosity reduction across the fracture face were measured, using Micro CT-scanning, and the damage was also studied using thin section analysis.
Field Deployment of Fiber Optic Technology to Monitor Overburden Deformation
Authors: Mali Gwyn A , Clark Rory R , Kenyon Scott B , Young Adam W , Paulk Devin H 
Published: September 2019

Abstract
Fiber optic technology has been used in several wells at an oilfield to measure strain to monitor overburden deformation. The application of this technology involved a series of bench tests and field tests to gather some key learnings to enhance well design, well construction, and fiber optic operation.
Prior to installation of the fiber optic, a series of bench tests were conducted to evaluate the coupling of fiber with the capillary lines to determine its impact on the measurement of strain. The testing demonstrated that anchoring the fiber at the top and bottom of the capillary line was sufficient to hold the fiber in place and enabled the effective measurement of strain along the length of the well, which was proven when applied to field conditions.
To enhance well design for strain measurement, several wells had fiber optic capillary lines installed on the inside and outside of casing to investigate the potential dampening effect due to fiber being located inside a string of casing. This was used to determine the optimal casing string to install fiber optic to measure strain in the overburden. Additionally, a novel concept was utilized in the well design that involved using the fiber optic capillary clamps as borehole centralizers, which resulted in equipment and rig cost savings.
The details of the bench tests, well design, operational experience, and their associated lessons learned are presented.