bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modeling Fault Reactivation Using Embedded Discrete Fracture Method
Authors: Tavassoli Shayan , Xu Yifei , Sepehrnoori Kamy 
Published: October 2018

Abstract
The integrity of a geological formation is a primary concern in any underground fluid injection project. Hydraulic pressurization due to injection may reduce fault strength, trigger fault slippage, and cause fault reactivation. The reactivated fault affects the fluid migration and loss from the injection zone, which might undermine the efficiency and safety of the project. Hence, a reliable modeling of fault reactivation is critical.
In this work, we propose a new approach to modeling fault reactivation. Faults are complex structures and generally consist of core and damage zones with macroscopic fracture networks. The embedded discrete fracture model (EDFM) is an effective method for simulating complex geometries such as fracture networks and nonplanar hydraulic fractures. We used the EDFM in conjunction with a compositional reservoir simulator to model fault reactivation under hydraulic pressurization. The phase behavior and fluid flow are accurately modeled using the equation of state (EOS) compositional simulation.
The activation of fault occurs at a threshold pressure, which depends on the chemo-mechanical properties of the formation rock. The threshold pressure can be estimated using analytical, numerical, or laboratory methods. In this study, we provided an analytical calculation of the threshold pressure. Moreover, we used a refined, multiphase, compositional, and geomechanical reservoir simulator to predict the threshold pressure. The coupled geomechanical reservoir simulation is computationally expensive; therefore, we suggest using this approach, in the absence of laboratory measurements, to simulate only a few regions of the formation with distinctive rock types. The estimated values of threshold pressures for different geomechanical rock types can be used in our simulations.
We performed large-scale reservoir simulations using the EDFM to investigate the storage capacity of carbon depositional formations representative of the Gulf of Mexico and monitor CO2 migration paths before and after fault reactivation. The results of this study are helpful to evaluate the capacity and integrity of carbon storage sites. Our methodology gives promising results for the prediction of fault reactivation and CO2 migration within a formation.
The proposed approach accurately models faults and their reactivation. It does not require refinement and geomechanical calculation for each gridblock in the domain, which reduces the computational time by at least five times. The significance of this approach becomes more pronounced in large formations with multiple rock types and faults. Although we used our approach for the study of carbon storage, the same methodology can be used for other types of fluid injection, such as water disposal.
Statistical Analysis of Effect of Proppant Design on Production Decline Profile of Shale Wells
Authors: Yang Alex , Stewart Benjamin , Jacob Thomas , Abramov Artem , Ramos-Peon Alexandre 
Published: October 2018

Abstract
In recent years, operators have been pumping more and more proppant per stimulated foot while simultaneously increasing lateral lengths. In order to mitigate the resultant costs and logistical difficulties, operators and service companies have switched to lower cost brown sands sourced from the Hickory Formation. We believe enough time has passed to test the hypothesis that the new design profile of wells-massive amounts of lower crush strength sand-will result in steeper production decline. We have gathered data from fracfocus.org on frac treatment design, supplemented it with data from state databases when available, and rigorously validated and cross-referenced all sources of data. We also gathered monthly production data from said state agencies. We regressed proppant type and intensity against production for every play, including in Texas where raw well level production data is unavailable, and instead allocated production to wells on a lease. We used geographical components and operator fixed effects to control for acreage and operator practices, respectively. In addition to statistical analysis, we also looked at well pads where wells used different types of sand.
While we succeeded in building predictive models for production decline, we did not find that sand color was a significant feature in these models
Investigation of Stress Field and Fracture Development During Shale Maturation Using Analog Rock Systems
Authors: Vega Bolivia , Yang Jie , Tchelepi Hamdi A. , Kovscek Anthony R. 
Published: October 2018

Abstract
The emergence of hydrocarbons within shale as a major recoverable resource has sparked interest in fluid transport through these tight mudstones. Recent studies suggest the importance to recovery of microfracture networks that connect localized zones with large organic content to the inorganic matrix. The paper presents a joint modeling and experimental study to examine the onset, formation, and evolution of microfracture networks as shale matures. Both the stress field and fractures are simulated and imaged.
A novel laboratory-scale, phase-field fracture propagation model was developed to characterize the material failure mechanisms that play a significant role during the shale rock maturation process. The numerical model developed consists of coupled solid deformation, pore pressure, and fracture propagation. Benchmark tests were conducted to validate model accuracy. Laboratory-grade gelatins with varying Young’s modulus were used as scaled-rock analogs in two-dimensional Hele-Shaw cell setups. Yeast within the gelatin generates gas in a fashion analogous to hydrocarbon formation as shale matures. These setups allow study and visualization of host rock elastic-brittle fracture and fracture network propagation mechanisms. The experimental setup was fitted to utilize photoelasticity principles coupled with birefringence properties of gelatin to explore visually the stress field of the gelatin as the fracture network developed. Stress optics image analysis and Linear Elastic Fracture Mechanics (LEFM) principles for crack propagation were used to monitor fracture growth for each gelatin type.
Observed and simulated responses suggest gas diffusion within and deformation of the gelatin matrix as predominant mechanisms for energy dissipation depending on gelatin strength. LEFM, an experimental estimation of principal stress development with fracture growth, at different stages was determined for each gelatin rheology. Synergy between diffusion and deformation determines the resulting frequency and pattern of fractures. Results correlate with Young’s modulus. Experimental and computed stress fields reveal that fractures resulting from internal gas generation are similar to, but not identical to, type 1 opening mode.
The novelty of our work is that microfracture networks are imaged and modeled as they form rather than measured after the fact. Host rock elastic-brittle fracture and fracture network propagation mechanisms are triggered by internal gas generation, microfracture frequency, connectivity, and topology are linked to material properties in a direct fashion.
Optimizing Drilling by Simulation and Automation with Big Data
Authors: Hutchinson Mark , Thornton Ben , Theys Philippe , Bolt Harald 
Published: October 2018

Abstract
For many years the aerospace and automotive industries have realized significant improvements in efficiency, performance and cost savings by simulating multiple prototype vehicle designs and control systems under various operating conditions. These same simulation techniques have now been introduced to the oilfield drilling industry and are delivering insights for more effective drilling tool designs, bottom hole assembly optimization, drilling severity minimization, dysfunction recognition and for drilling performance improvement with fewer downhole failures. Drilling is a non-linear, coupled and dynamic hydro-geomechanical process, the physics for all aspects of which must be captured to enable a robust automated drilling control process.
Drill string, drilling tool and drill bit failures are frequently incorrectly blamed upon the invisible geology through which they drill. Field engineers frequently report more severe downhole vibrations at rotation speeds other than those predicted by linear frequency-based finite element critical speeds analyses. The same multi-body dynamics simulation techniques used by the automotive and aerospace industries, however, are now being applied to capture the non-linear aspects of the drilling process and provide more realistic predictions of drilling performance.
Simulation validation is achieved by comparing virtual data to physical data with an implicit understanding of the uncertainties of each. Recommendations are presented for improving the usefulness and the quality of physical drilling data which simulation can then also help assure.
The ultimate objective is to deliver better quality boreholes which are less costly with fewer drilling tool failures. These novel simulation techniques are enabling manufacturers to benefit from lower development costs and shorter times to market with more reliable proprietary drilling tool designs. Drilling contractors are using simulations to optimize top-drive controls and drill more effectively. Product developers are able to configure higher performing and more optimal bottom hole assemblies. Operators are able to reduce overall drilling costs with the potential benefits of higher performing drilling automation systems and greater production from better quality boreholes.
Estimating Clean Reservoir Fluid Bubblepoint and Other Properties in Real Time Using PCA Asymptote of Optical Sensor Data and Equation of State
Authors: Olapade Peter , Dai Bin , Jones Christopher Michael , Kallehbasti Mehdi Alipour 
Published: October 2018

Abstract
Mud filtrate invasion occurs in the immediate vicinity of the well as a result of the overbalance pressure of the mud column in the well. Oil-based muds (OBM), unlike water-based muds (WBM), are miscible with reservoir fluid, and OBM contamination alters the properties of the original formation fluid. The bubblepoint of contaminated fluid is usually lower than clean fluid. While fluid is pumped out of the formation, it becomes cleaner and the bubblepoint increases; the upper limit of the increase is the clean formation fluid. While increasing the pumping rate can shorten cleanup time, pumping below the bubblepoint can modify the fluid phase behavior and cause asphaltene content in the formation fluid to precipitate out and sensor data to become erratic and noisy. Therefore, it is important not to pump below the bubblepoint, knowing the clean fluid bubblepoint in real time provides a guideline for the field engineer. The purpose of fluid sampling is to collect a representative formation fluid—samples with an acceptably low contamination. The clean fluid bubblepoint provides a lower limit on pumping pressure, which helps ensure pumping does not go below the bubblepoint and the sample is in single phase.
This paper describes how clean fluid compositions are determined from the asymptote of the principal component analysis (PCA) reconstructed scores and then used as input for the equation of state (EOS) program to compute fluid properties such as bubblepoint and gas/oil ratio (GOR). The optical spectral data from the optical fluid analyzer is first despiked, and outliers from the despiked data are removed using the robust ordinary least squares regression (ROLSR) method and robust PCA (RPCA). After removing outliers, clean fluid spectra data are reconstructed using asymptotic PCA scores and PCA loadings. Using a neural network model, clean fluid compositions are determined from reconstructed fluid spectral data, and fluid compositions are used as input for the EOS program to determine fluid properties.
Results confirm that the clean fluid bubblepoint and GOR do not change significantly after a few tens of liters of fluid pumpout. Analysis of the first principal component (PC1) confirms that most of the variations occur during the first few tens of liters of pumpout, indicating the predicted clean fluid compositions and properties are somewhat stable. This approach can help determine the clean fluid properties, even while pumping before taking the sample, helping ensure a monophasic fluid sample. When pumpout accumulated volume reaches 40 to 50 L—within 15 to 20 min of pumping out contaminated fluid—clean fluid compositions and properties can be estimated and used to determine reservoir continuity. Additionally, knowing the clean reservoir GOR and API gravity can help determine the type of reservoir fluid in real time.
First Deepwater Campaign, Offshore Romania: Infrastructure, Design, and Execution to Deliver Drilling and Completion Fluids
Authors: Bussaglia Lucio , Di Marino Rodolfo , Smith Vance 
Published: October 2018

Abstract
The Black Sea, offshore Romania, is one of the world's emerging deepwater basins. The objectives of the campaign presented in this paper include safe and compliant operations, data acquisition, reservoir characterization and de-risking of adjacent prospects over the course of a seven-well, deepwater exploratory campaign. The challenges inherent to deepwater are exacerbated in exploratory wells, with additional focus placed on the reduction of risks associated with ECD management, downhole losses, wellbore instability, gas hydrate formation and mitigation of shallow hazards. The scope of this project presented additional logistical challenges, as there were no dedicated facilities in this area to support large-scale deepwater projects. Deepwater projects in emerging areas present a variety of challenges including planning, constructing, and commissioning facilities with sufficient capacity to prepare and store the requisite volumes of drilling and completion fluids. Infrastructure preparation in this project included the design and construction of two liquid mud plants with the capacity to mix, condition and store large volumes of drilling and completion fluids for a multi-well campaign. Additionally, a bulk facility was built and commissioned for handling barite additives used in the project. Project management and monitoring techniques were used to ensure on-time completion of facilities following the critical paths of the project timeline. All planned operational objectives were safely achieved because of detailed planning, commitment, and capital investments in assets and the infrastructure to support operations. This approach enabled delivery of project objectives without incidents of fluids-related non-productive time (NPT). The logistical objectives were achieved on time, and in an environmentally compliant manner. All fluid volumes were safely prepared and delivered to the 5th generation semi-submersible for use in the target intervals. This included delivery of large volumes of high-density riserless kill fluid (RKF) that was stored for three months on a multi-purpose supply vessel (MPSV) without the occurrence of barite sag. All drilling and formation evaluation objectives were accomplished with a high-performance, non-aqueous fluid (NAF) specifically designed for use in this multi-well campaign. The delivery of well testing, plugging and abandonment objectives was facilitated by use of an integrated suite of wellbore cleanup (WBCU), completion fluids and filtration technologies.
Removal of Iron Sulfide Scale with a New Formulation: A Field Application in a Sandstone Reservoir in Egypt
Authors: Abou Bakr Mohamed , Farid Ibrahim Ahmed , Nasr-El-Din Hisham , Abd El-Hay Ahmed , Amin Ehab 
Published: October 2018

Abstract
Iron sulfide scale is a significant problem in the oil and gas industry whereas the iron sulfide deposition has an adverse impact to the production operations. The scale is present in various species with different iron to sulfur ratios. Iron sulfide species with high iron content is soluble in acids, whereas those rich in sulfur are almost insoluble in acids.
East ZEIT oil wells have been produced for 20 years in Egypt. Scales with iron sulfides as the major components form in nearly every producing well. These scales have minor compositional but form at differing rates and thicknesses in the lower half of tubing string. Well East ZEIT-13 was completed initially in Nubia formation which is communicated with another formation called ‘’Lower Senonian’, whereas the drive mechanism is active water-drive.
The formation is sandstone with the following specs: Lose, pale yellow, quartz, very fine to fine-grained, sub-rounded to rounded, and moderately sorted sand grains. The reservoir temperature is 300°F. The well was producing using a jet pump (JP), the production stopped due to scale formation. A workover started to replace the completion. The JP was used again to produce the well with very low productivity; +/-0.06 bbl/psi. The power fluid of the JP is oil with 1% water cut. The scale was expected to cover all the casing area below the tubing end until PBTD.
A scale sample was obtained and analysis of the scale through XRD showed that the scale composition is as follows; 36% Marcasite (FeS2), 21% Greigite (Fe3S4), 17% Pyrite (FeS2) and 26% Siderite (FeCO3). Both pyrite and marcasite have a very low solubility in HCl, and the only available method of removal in the oil industry is milling. The milling operation failed to solve the problem, therefore, the production was stopped until finding an alternative solution.
An effective treatment strategy proposed to remove the scale efficiently; the technical proposal was designed taking into consideration the complicated nature of the scale. Furthermore, the proposed treatments were conducted and placed using coiled tubing (CT).
The first application using the SCSR-02 solution has been successfully carried out and the job results were outstanding. Production has been returned with an increment of 50% above its original rate. The well is producing natural flow without using the JP, and efficient cost/Bbl.
An Automatic History-Matching Workflow for Unconventional Reservoirs Coupling MCMC and Non-Intrusive EDFM Methods
Authors: Yu Wei , Tripoppoom Sutthaporn , Sepehrnoori Kamy , Miao Jijun 
Published: October 2018

Abstract
Technological advancements enable natural gas to be economically produced from ultratight shale rocks. However, due to the limited availability of long-term production data as well as the complexity of gridding, for reservoir simulation studies, in dealing with hydraulic fractures, an efficient automatic history-matching workflow in a probabilistic manner for performing history matching, production forecasting, and uncertainty quantification is highly needed. This can provide critical insights for the decision-making processes. In this study, we present an integrated history-matching workflow through coupling an innovative non-intrusive EDFM (Embedded Discrete Fracture Model) method, proxy modeling of KNN (K-Nearest Neighboring), and MCMC (Markov-chain Monte Carlo) sampling. The non-intrusive EDFM method can be applied in conjunction with any third-party reservoir simulators without the need of changing the source codes. Through non-neighboring connections, EDFM can accurately and efficiently handle hydraulic fractures, which does not require local grid refinement nearby fractures. The design of experiment is applied to perform sensitivity analysis with the purpose of identifying significant uncertain parameters. The KNN is utilized to build proxy model and its quality can be improved through multiple iterations of the workflow. The classic Metropolis-Hasting (MH) algorithm of MCMC is employed to perform sampling and predict posterior distribution of uncertain parameters. An application of the workflow to a horizontal shale-gas well from Marcellus shale is demonstrated and discussed in this study. Gas desorption effect is considered in the reservoir model. Six uncertain parameters are considered for this well including matrix porosity and permeability, fracture half-length, fracture conductivity, fracture height, and fracture water saturation. Based on 10 iterations and 250 simulation cases, 52 history-matching solutions with reasonable match results against actual gas and water production rates were identified. After history matching, we performed production forecasting for 30 years using all history-matching solutions under the constraint of constant flowing bottomhole pressure of 500 psi. Reliable P10, P50, and P90 of EUR (estimated ultimate recovery) predictions of gas recovery were determined as 11.9, 13.1, and 16.4 Bcf (billion cubic feet), respectively. In addition, the narrower posterior distributions of six uncertain parameters were quantified. The values with the highest frequency for each parameter are determined: porosity is 10.4%, permeability is 0.00034 md, fracture half-length is 450 ft, fracture conductivity is 2.85 md-ft, fracture height is 87.5 ft, and fracture water saturation is 38.8%.
Improved Gravity Drainage by Gas in Fractured, Oil-Wet Carbonate Rocks Using Mobility Control Agents
Authors: Zhou Jimin , Sharma Himanshu , Mohanty Kishore 
Published: October 2018

Abstract
Waterflooding in low permeability, fractured and oil-wet carbonate reservoirs yields extremely low oil recovery due to bypassing through fractures and little imbibition into the matrix resulting in a large amount of oil remaining in the reservoir. Gravity-aided gas injection is studied at the lab-scale in this work to enhance oil recovery from fractured reservoirs. The miscibility of the gas with a model oil (decane with naphthenic acid) is varied by enriching the methane with ethane. Mobility of the gas is decreased by incorporating the gas in foam or glycerol-alternating-gas floods. As the miscibility increases, the oil recovery increases, but reaches a plateau above the near-miscible conditions. The foam flood improves oil recovery by diverting gas into the matrix, if the gas is sufficiently soluble in the oil and the gas-oil capillary pressure is sufficiently low. The pressure gradient generated in the fracture by foam helps in the diversion of the gas into the matrix. Glycerol-alternating-gas floods result in minor additional oil recovery over foam floods because the pressure gradients are about the same. These experiments need to be repeated after gas floods (before conducting foam floods). Near-miscible (and miscible) foam floods increased the oil recovery to high values (about 85% OOIP) in core floods and their scale-up to reservoir scale warrants further study.
An Integrated Platform for IIoT in E&P: Closing the Gap between Data Science and Operations
Authors: Wen Tailai , Evers Karina , Huang Xinwo , Keyes Roy 
Published: October 2018

Abstract
Although major E&P companies have been investing in data-driven modeling and analytics in the Big Data era, expected cost reductions and efficiency improvements have scarcely been realized, mainly due to the overhead related to operationalizing analytics and models. This paper proposes the architecture of an industrial internet of things (IIoT) platform that minimizes the overhead and accelerates value creation in the context of the digital oilfield.
The proposed IIoT platform is an integrated portal for all members working in the same ecosystem, including data scientists, data engineers, operation engineers, business analysts, and IT administrators. It is the first platform focusing on minimizing the gap between in-house modeling teams and operation teams in an industrial context. This work successfully addresses the challenge of operationalizing the digital oilfield, in turn catalyzing smart operations through industrial analytics.