bluuebunny/crossref_metadata_2025_split huggingface dataset:
Geomechanical Analysis of Frac-Hits Using a 3D Poroelastic Hydraulic Fracture Model
Authors: Kumar Dharmendra , Ghassemi Ahmad , Riley Spencer , Elliott Brendan 
Published: October 2018

Abstract
Well-to-well interference or communication between the production or "Parent" well and the infill or "child" well is one of the main concern in horizontal wells refracturing, which results in a decrease of productivity of both the wells. Many field observations have demonstrated that the "child" well fractures could have a tendency to propagate towards the "parent" well resulting in well-to-well interference or "frac-hits" issues. This paper presents a geomechanical perspective to better understand the problem of "frac-hits" in horizontal well refracturing and to design solutions for it using geomechanics analysis and modeling. The numerical analysis is based on a fully coupled 3D model "GeoFrac3D" with the capabilities to simulate multistage fracturing of multiple horizontal wells. The model fully couples pore pressure to stresses and allows for dynamic modeling of production/injection and fracture propagation. The modeling results show that production from the parent well gives rise to a non-uniform reduction of the reservoir pore pressure around the production fractures leading to anisotropic decrease of the reservoir total stresses which may result in stress reorientation or reversal. The decrease of total stresses in the vicinity of the parent well fractures creates an attraction zone for the child well fractures. The child well fractures have a tendency for asymmetric growth towards the lower stress zone. The impact on the parent and child well production and the risk of "frac-hits" will vary with the reservoir stress regime and production time. Optimizing fracture and well spacing, fluid viscosity, and the timing of refracturing can help to minimize problems. The simulation results demonstrate that the risks of "frac-hits" issue can be mitigated by re-pressurization of the parent well before child well. Traditional methods of refracturing simulation usually use two different codes to solve the problem and mostly use stress analysis rather than explicit fracture propagation. The model used in this study can simulate both aspects of the problem i.e., the reservoir depletion analysis and the subsequent child well fracturing.
Smart Oilfield Technologies and Management: Maximizing Real-Time Surveillance and Utilization
Authors: Al-Kadem Mohammad , Al Yateem Karam , Al Amri Meshal 
Published: October 2018

Abstract
Smart oilfield technologies and management real-time data surveillance, in terms of reliability and availability, has proven essential in the process of prolonging asset lifespan, improving asset integrity, and proactively preventing problems. This illustrates a leadership role in the integration of cutting-edge technologies by utilizing an Intelligent Field concept. Surveillance capitalizes on real-time data transmitted from Intelligent Field equipment, where mathematical algorithms and logic are automated and imposed. The application captures specific sets of data to help identify and analyze challenges associated with Intelligent Field equipment. Major prevailing benefits include, identifying systematic techniques to utilize automated diagnostics for reduction in human intervention, develop field level surveillance, cross-validating measurements through online modeling, and further enhance collaboration. This paper details the methodology, the outcome, the requirements, and considerations associated with effective real-time data utilization in energy industry applications. The platform allows business team members and their partners to communicate, collaborate, and coordinate activities in real time.
Simulation of Viscoelastic Polymer Flooding - From the Lab to the Field
Authors: Qi Pengpeng , Lashgari Hamid , Luo Haishan , Delshad Mojdeh , Pope Gary , Balhoff Matthew 
Published: October 2018

Abstract
Experimental data in numerous publications show that viscoelastic polymers can significantly reduce residual oil saturation under favorable conditions. The effect of viscoelasticity is in addition to improved sweep efficiency of polymer flooding. The residual oil saturation decreases with increasing dimensionless Deborah number (a measure of the relative elasticity). We used these extensive coreflood data to develop a new model that is referred to here as an Elastic Desaturation Curve (EDC). The new EDC model was implemented into a reservoir simulator and used to simulate polymer floods at both the lab and field scales. The simulated coreflood results match the experimental oil cut, oil recovery and pressure drop data. The simulator was then used to predict the effectiveness of polymer floods in a quarter five-spot well pattern under favorable field conditions. The field-scale simulations show that a viscoelastic polymer flood can recover significantly more oil (12% OOIP for the base case simulation) compared to an inelastic polymer flood of the same polymer viscosity. A sensitivity analysis shows that polymer concentration, salinity, well spacing, permeability, heterogeneity and injection rate affect the incremental oil recovery due to elasticity. The results suggest that the use of viscoelastic polymers could be a beneficial enhanced oil recovery strategy at the field scale under favorable conditions.
Advanced Fracture Diagnostics by Utilizing Over 250 Fracture Diagnostic Tests in Indian Volcanic Tight Gas Reservoir
Authors: Pathak Shashank , Tibbles Raymond Joseph , Tiwari Shobhit , Anand Saurabh , Ranjan Vishal , Siddarth Punj , Bohra Avinash 
Published: October 2018

Abstract
This paper documents the basis of fracturing diagnostic test design and analysis methodology adopted while fracturing one of the few commercial volcanic gas reservoir in the world. More than 10 distinct types of diagnostic tests were performed with each having specific objective. These tests were primarily conducted to:
Reduce the uncertainty while fracturing Improve reservoir & hydraulic fracture understanding to enhance production Validate qualitative sources of information
These tests included standard pre-frac injection tests, post injection surveys as well as innovative modifications which significantly helped to enhance operational efficiency and improved production results. To achieve maximum net pay coverage with minimum number of frac stages, limited entry fracture technology best suited the economics of this field. Since limited entry technique was selected even with its inherent uncertainties with respect to diversion in individual fracture cluster, the overall performance of this field heavily depended on its effectiveness. To maximize the probability of success, uncertainties & risks were evaluated and a workflow was designed. This workflow consisted diagnostic tests with specific deliverables such as DFITs to calibrate mechanical earth model (MEM), Step rate tests to estimate the efficiency of fluid diversion, temperature surveys to validate fluid distribution, production logs to confirm production performance. These standard tests were also modified to minimize cost/time implication while ensuring specific information was acquired as expected from these tests. Fracture model calibration was achieved by a combination of injection tests, post injection test/fracturing temperature surveys, along with a consistent method for fracture history matching. Final verification was obtained using a series of production logs. Over 13 Diagnostic Fracture Injection Tests (DFITS), 63 Step Rate Tests (SRT), 80 Step Down Tests, 58 post SRT/Fracturing Temperature Surveys, over 50 production logs are incorporated in this study.
All of this augmented reservoir understanding and helped to save operational time and reduce cost. These tests further helped to increase from 3 clusters per frac to 6 cluster per frac, thus increased net pay coverage with same frac stages. The contribution of 6 clusters was also validated from production logs. Completion improvements have resulted in productivity and Estimated Ultimate Recovery (EUR) increases of 80% and 20% respectively. Screen out rates have dropped from 33% in the very first campaign to 5% in the most recent campaign.
Detailed analysis and key engineering findings from all of these tests. Representative case histories including, DFITS, Step rate tests, Mini Fracs, Temperature surveys and production logs to back up the results. The results from these learnings are summarized in this paper.
Self-Adaptive Depth of Cut Control Technology: A Path-Breaking Approach to Address Torsional Dysfunction and Securing Drilling Performance Gain in Challenging Deepwater Gulf of Mexico Well
Authors: Roy Chowdhury Ashabikash , Serrano Ralph , Martin Brisk , Landry Jonathan 
Published: October 2018

Abstract
Torsional instability in a drilling system is a significant challenge that limits performance. In its extreme form, known as stick-slip, the drillstring stops and restarts, exposing its downhole equipment to extreme forces that can lead to failures, unintended trips, and escalated operation costs. Torsional instability can also trigger lateral dysfunctions and whirl, creating further risk of bit and bottomhole assembly (BHA) failure. The risk of torsional dysfunction is heightened in applications involving concentric reamers and long drillstring, high-angle wells.
The correlation of polycrystalline diamond compact (PDC) bits with torsional dysfunction is well known, and different approaches have been suggested to address the issue. The fixed depth of cut control (DOCC) approach, which is commonly used to address the issue, limits the PDC bit and formation engagement at a pre-determined ratio of rate of penetration (ROP) and drillstring RPM. However, this approach has an uncertain success rate when drilling conditions change. To address the challenge of torsional dysfunction while drilling a directional well with a 12¼-in. pilot bit and a 14½-in. concentric reamer, a self-adaptive DOCC technology was deployed in a deepwater well in the Gulf of Mexico (GOM). The self-adaptive DOCC technology automatically adjusts the depth of cut engagement threshold as drilling conditions change, eliminating the manual parameter adjustment required at surface to manage torsional dysfunction.
The application of self-adaptive drill bit technology in the target well yielded excellent results, and the section was completed with a single bit/BHA run. Ninety-eight percent of the interval was drilled with no torsional dysfunction. The drillstring whirl was negligible, and 99% of the interval was drilled without lateral vibration. Eliminating harmful dynamic dysfunction significantly enhanced drilling performance and increased the ROP by 57% over the best PDC offset run. The dull bit condition was very encouraging; the bit displayed very low wear and no undesired impact damage, showing the effectiveness of the technology.
This paper uses real-time drilling dynamics field data measured downhole and demonstrates the effectiveness of self-adaptive DOCC technology for drilling performance improvement in deepwater directional well where torsional dysfunction continues to remain a significant challenge and could be a performance limiter.
Proposal and Experimental Trials on an Autonomous Robot for Rigless Well Intervention
Authors: Santos Hugo , Paz Paulo , Kretli Igor , Reis Ney , Pinto Hardy , Galassi Maurício , Pozzani Daniel , Lanzilotta Alessandro , Castro Bruno , Ferreira André , Thomé Lincoln , Beal Valter 
Published: October 2018

Abstract
This paper proposes the development of an autonomous robot for rigless well interventions in order to reduce costs by avoiding the need of a rig to do so, especially for light workover operations in offshore locations. It also presents experimental tests performed in a laboratory string and in a test well in order to evaluate the feasibility of this technology.
Pressure Pulse Testing Method for Caprock Characterization
Authors: Mosaheb Mojtaba , Zeidouni Mehdi , Shakiba Mahmood 
Published: October 2018

Abstract
Pressure transient testing is a method to obtain information on reservoir characteristics. Thin shale layers isolating productive intervals in a reservoir have important implications for reservoir development and EOR strategies. In addition, weaknesses in caprocks overlying injection intervals may adversely affect the safety of fluid injection approaches including gas storage, waste water disposal, and CO2 geological storage. Even low permeability of a caprock overlying the injection zone can be very important by allowing for pressure dissipation out of the reservoir. In this work, we apply harmonic pressure testing method to characterize a caprock overlying a given injection zone. The diffusivity equations are written and solved in frequency domain for system of injection layer and above zone with the low permeability caprock in between. A vertical well is perforated in the middle of the injection layer. A periodic flow rate pulse is disseminated from the injection well. The pressure pulses traveled through the caprock are observed in the above zone. The hydraulic characteristics of the low permeability caprock are estimated applying the analytical solution based on the above zone pressure amplitude. The caprock diffusivity is found to be in acceptable agreement with the true value. It is shown that the harmonic pulse testing is useful to characterize the intra/inter reservoir low permeability layers (caprocks).
Computational Fluid Dynamics Modeling of Slip Flow Coupled with Gas Adsorption/Desorption Kinetics in Complex Pore Space
Authors: Yao Shanshan , Pini Ronny , Wang Xiangzeng , Zeng Fanhua , Ju Ning 
Published: October 2018

Abstract
At reservoir conditions, gas flow confined in submicron pores of shale falls within slip flow and transition flow regimes. Beyond the common instant equilibrium assumption, we believe that gas adsorption/desorption on rough pore surfaces could be in non-equilibrium status when gas pressure keeps decreasing during production. We investigate the interplay of gas slip flow inside complex submicron-scale pores and gas adsorption/desorption kinetics on pore surfaces with computational fluid dynamics (CFD) under unsteady-state flow conditions.
Different from previous studies, the gas adsorption/desorption is in non-equilibrium state, which is closer to real reservoir conditions. Given pore pressure Pp at time t, linear driving force model with gas desorption rate coefficient kd is applied to describe the difference between the equilibrium adsorption amount (calculated with adsorption isotherms) and the actual adsorption amount per unit pore surface area. Free gas flow inside 3D reconstructions of shale pore space is modeled by Navier-Stokes equations with Maxwell's first-order slip boundary conditions. To include gas contributions from desorption, extra source with strength equal to the gas desorption rate is added to the slip boundaries.
Any type of adsorption isotherms can be incorporated into our CFD modeling. We investigate the coupling of slip flow and Langmuir adsorption isotherms for methane in 3D reconstructed pore space. We observe that not all of adsorbed gas measured in adsorption isotherms contribute to gas production. In our study the pore pressure, Pp, decreases along with time t. One significant finding is that there exists a key time point, tk, after which adsorbed gas starts desorbing off pore surfaces and the decreasing rate of pore pressure becomes smaller. The higher the gas desorption rate coefficient, kd, is, the earlier tk occurs. But the decreasing rate of pore pressure is no longer sensitive to the coefficient, kd, when kd is larger than 0.0005. Another significant finding is that optimum gas production rate should be chosen according to kd values. It is always better to have high production rate when kd is larger than 0.0005. If the kd is smaller than 0.0005, simulations are necessary to determine optimum gas production rate by balancing the development efficiency and final amount of gas desorption.
Gas adsorption/desorption is always regarded as an instant equilibrium process in shale reservoir simulations. This study considers the non-equilibrium gas adsorption/desorption process, which is closer to real reservoir conditions. No studies in the literature have considered the influence of gas adsorption/desorption kinetics when choosing optimum production rates. CFD simulations in this study provide insight and guidelines on optimizing shale gas development with evaluating slip flow as well as gas adsorption/desorption characteristics.
On the Prediction of Gas Solubility in Brine Solutions for Applications of CO2 Capture and Sequestration
Authors: Ratnakar Ram R. , Venkatraman Ashwin , Kalra Amrit , Dindoruk Birol 
Published: October 2018

Abstract
Geological storage of CO2 in deep saline aquifers has become a well-accepted method for CO2 sequestration. CO2-solubility in these brine solutions is one of the most important factors in determining the amount of CO2 sequestered in these aquifers. Since the type of salt can significantly alter the CO2-solubility in brine solutions, the impact of water chemistry on CO2 solubility is investigated in this work and results are compared against experimental observations.
The current work for predicting solubility of a gas in brine solution containing various salts is based on the extension of well-known Setschenow relation that has been commonly used for salts with monovalent ions. In this research, we extend the Setschenow approach by expressing the solubility in terms of ionic strengths and molar concentrations of each salt. The method also characterizes each component (e.g., gas, anions and cations) against the experimental measurements.
A simple methodology, developed with a theoretical framework, is presented to predict the impact of different types of salts on solubility of CO2. This approach can be extended to any type of gases or other solutes (e.g. CH4, H2S etc.) in brine solutions. In particular, The gas solubility in brines is expressed in terms of molar components and ionic strength of each salt. The expression contains unique/characteristic parameters for each component (gas, anions and cations). These parameters for anions and cations of typical formation water (present in oil/gas reservoirs) and CO2/novel solvents are obtained from literature or using regression on experimental data.Results of CO2-solubility were compared with published data in literature, demonstrating that the methodology (presented in the work) can predict the effect of water-chemistry on solubility predictions.The proposed method was tested for a novel solvent (dimethyl ether) and comparison with experimental solubility data show an excellent match between the predictions and measurements.
Improved Collaboration and Transparency of Oil & Gas Capital Projects Using a Digital Project Delivery System
Authors: Stroh Jeffrey , Naik Harit , Memi Edmund 
Published: October 2018

Abstract
The adoption of a digital project delivery methods utilized by the manufacturing industry can be applied to oil and gas capital projects. Benefits include: greater collaboration and transparency between an EPC and owner-operator, the use of near real-time data to facilitate and drive better project decision-making, and the ability to save resources through increased efficiencies. To better understand poor performance on capital projects, different methods must be looked at. A case study using implementation of a digital project delivery approach through Project Lifecycle Management (PLM) is compared to a legacy project delivery using disconnected tools. This new approach to project delivery shows how adapting PLM software brings together engineering data with planning information, digital action workflows, collaborative review sessions, and visualization of status using a 3D model into a new way of delivering oil and gas capital projects more efficiently. The project schedule is merged with the master deliverables register and data coding to create live project dashboards and end-to-end schedule visibility. Going beyond the technological aspects, the behavioral and organizational challenges of project execution are examined, highlighting the limitations of legacy approaches and the project benefits gains using the digital project delivery approach.
By leveraging the interconnectedness of data, the real-time insights that can be derived, and with the right project team support model, all of these factors come together to show how application of digital project delivery systems enables better project management visibility and capital project performance.
Review of Permian Completion Designs and Results
Authors: Jaripatke Omkar A. , Barman Indranil , Ndungu John G. , Schein Gary W. , Flumerfelt Raymond W. , Burnett Nikki , Bello Hector D. , Barzola Gervasio J. 
Published: October 2018

Abstract
One of the most significant elements in the successful development of an unconventional multi-layered horizontal shale play, such as the Permian Basin Wolfcamp and Spraberry shales, is the continuous refinement of completion design programs in order to account for the specific geological characteristics of the target formation and spatial considerations. This paper examines a number of well completions, a large percentage of which are multi-stacked, over a four-year period in the Permian Basin.
In this paper, we describe the ways in which a completion design program has been constantly refined in the development of Wolfcamp and Spraberry formations over certain areas of Midland Basin. Key performance drivers, such as regional pore pressure, rock properties and stresses, well spacing, etc. along with multidisciplinary data sets such as microseismic, tracers, bottom hole reservoir pressure, and production history are incorporated into modeling the completion designs.
Details of the workflow, analysis of results and implementation of the Permian multi-stack design optimization plan are presented. The paper includes lessons learned from early vintages to modern completions, parent/child mitigation strategies, and future ideas to further optimize the operations.
Information presented in this paper will help multi-disciplinary asset teams, consisting of engineers, geologists, analysts and managers; design a workflow for selecting appropriate design solutions for their individual shale assets.