bluuebunny/crossref_metadata_2025_split huggingface dataset:
Countrywide Integrated Capacity Model – Enabling Production Planning and Performance Management Leveraging Big Data and Digitization of Engineering Workflows
Authors: Al Selaiti Iman , Mabrook Maged , Hoda Mohammad Faizul , Saputelli Luigi , Hafez Hafez , Mohan Richard , Pires Joshua , Asarpota Jyotsna , Hernandez Cristina 
Published: September 2021

Abstract
Production planning and performance management imply diverse challenges, mainly when dealing at corporate level in an integrated operating company. Production forecast considers technical capacities, available capacities, and operationally agreed target capacities. Such complex process may hinder taking advantage of market opportunities at the right time. Proactive scenario management and information visibility across the organization are key for success.
This paper intends to share the lessons learned while rolling out a countrywide integrated capacity model solution supporting corporate production planning and performance management. The rollout processes aimed at digitizing the monthly and yearly production forecasting. In addition, these processes shall enable formulating proactive scenarios for avoiding shortfalls, maximizing gas throughput, production ramp up, and minimizing operating cost from existing capacity.
Abu Dhabi's Integrated Capacity Model is an integrated production planning and optimization system relying on a large-scale subsurface-to-surface integrated asset model system; in this paper, we focus on the incremental progress of the challenges derived from the various rollout efforts. The rollout of such a complex solution relies on basic tenets for managing the change across a large organization.
The first tactic is about continuous stakeholder engagement through value demonstration and capabilities building. Engagement is achieved by continuously providing information about proactive shortfall and opportunity identification within the installed asset capacity. Monthly asset reviews provide the basis for user interaction and initiate the basis for establishing ad-hoc production maximization scenarios. Establishing a data governance and performance metrics were also key for embedding the solution in the business processes.
The solution delivers tangible and intangible value. From the tangible point of view, it contributes to production efficiency gains by compensating during specific proactively identified shortfalls and after-the-fact events. As a result, our solution has been instrumental in deriving cost reduction scenarios and profitability gains due to optimum GOR management. In addition, the system use has reported various intangible gains in terms of better data utilization, enhanced corporate database quality and reduced overall human load in managing production capacity.
The solution described in the paper implements a simpler way the production planning and performance management at corporate level in a large integrated operating company. The in-house developed tool and its implementation is a novel approach in terms of integration, complexity, and practical application to the fields in Abu Dhabi.
Closed Looped Production Rate Evaluation by Means of Virtual Metering and Pressure Transient Analysis
Authors: Ursini Fabrizio , Frau Simone Andrea , D'Addato Francesco , Romice Luigi , Furlani Sergio , Vignati Emanuele , Trevisan Matteo , Montini Marco 
Published: September 2021

Abstract
The Integration of real-time high frequency data in well models allows to infer useful information regarding well and field performance. Virtual Metering (VM) algorithms aim at providing real time well rates solving an inverse problem based on flow equation in the wellbore. Although VM methodologies are based on Pressure/Temperature measurements, they rely on availability of calibration measurements. Pressure Transient Analysis (PTA) can provide useful insight for VM calibration.
An innovative closed-loop workflow combining VM and PTA has been developed to face unreliable or absent rate measurements. VM requires periodical separator tests for model calibration. PTA played an important role in estimating well production rates, using it as a virtual well test to compensate the lack of field tests. VM rates are used as first guess for the PTA interpretation of build-up where production rates are unreliable. PTA log-log derivative plot is compared with the reference one which was interpreted to calibrate the formation K•H. The loop is iterated correcting VM calibration parameters until the match is acceptable.
An implementation of the closed loop rate estimation workflow on an offshore oil asset is presented as an application of the methodology. The asset comprises 15 production wells, most of them with high Gas-Oil Ratio. Virtual Metering has been applied on wells fully equipped with wellhead and bottom-hole sensors. The joint application of PTA with an iterative closed loop philosophy was fundamental to compensate the lack of separator tests and of the sometimes unreliable choke opening data. The accuracy of the production profiles simulated by the VM is confirmed by the comparison with the reference asset fiscal production and by the final pressure history matching obtained with the PTA. The application of the iterative closed-loop workflow plays a fundamental role in the improvement of backallocation, in real time production monitoring and in the implementation of production optimization. Well models based on VM algorithm have been included in production optimization workflow to improve the well line-up and identify production optimization opportunities. Virtual Metering allowed to monitor results of optimization actions by estimating the actual wells production increment.
This paper contains a novel approach, consisting in a reliable and robust closed loop virtual metering workflow, which integrates different tools with the common objective of assessing the actual well production rates for maximising the asset performance. The real-time data and model sharing allowed to set-up a collaborative environment optimizing effective problem solving and field production performance.
A Novel Gemini Cationic Viscoelastic Surfactant-Based Fluid for High Temperature Well Stimulation Applications
Authors: Friesen Dawn , Seymour Brian , Sanders Aaron 
Published: September 2021

Abstract
Viscoelastic surfactant (VES)-based fracturing fluids can reduce the risk of formation damage when compared with conventional polymer-based fracturing systems. However, many VES systems lose viscoelasticity rapidly under high-temperature conditions, leading to high fluid leakoff and problems in proppant placement. A gemini cationic VES-based system offering thermal stability above 250°F and its efficiency in friction reduction is presented in this paper.
Rheology measurements were conducted on viscoelastic cationic gemini surfactant fluids as a function of temperature (70 – 300°F) and surfactant concentration. The length of surfactant alkyl chain was varied to investigate the impact of surfactant chain length on VES fluid viscosity at elevated temperatures. The effect of flow rate on friction reduction capability of the surfactant fluid was measured on a friction flow loop. Foam rheology measurements were conducted to evaluate the VES fluid's ability to maintain high temperature viscosity with reduced surfactant concentration.
A gemini cationic surfactant was used to prepare a viscoelastic surfactant system that could maintain viscosity over 50 cP at a shear rate of 100 s−1up to at least 250°F. With this system, viscoelastic gel viscosity was maintained without degradation for over 18 hours at 250°F, and the fluid showed rapid shear recovery throughout. Decreasing the average alkyl chain length on the surfactant reduced the maximum working temperature of the resulting viscoelastic gel and showed the critical influence of surfactant structure on the resulting fluid performance. The presence of elongated, worm-like micelles in the fluid provided polymer-like friction reduction even at low surfactant concentrations, with friction reduction of over 70% observed during pumping (relative to fresh water) up to a critical Reynolds number. Energized fluids could also be formulated with the gemini surfactant to give foam fluids suitable for hydraulic fracturing or wellbore cleanouts. The resulting viscoelastic surfactant foams had viscosities over 50 cP up to at least 300°F with both nitrogen and carbon dioxide as the gas phase.
The information presented in this paper is important for various field applications where thermal stability of the treatment fluid is essential. This will hopefully expand the use of VES-based systems as an alternative to conventional polymer systems in oilfield applications where a less damaging viscosified fluid system is required.
Accurate Multi-Phase Flow Simulation in Faulted Reservoirs Using Mimetic Finite Difference Methods on Polyhedral Cells
Authors: Dong Rencheng , Alpak Faruk O. , Wheeler Mary F. 
Published: September 2021

Abstract
Faulted reservoirs are commonly modeled by corner-point grids. Since the two-point flux approximation (TPFA) method is not consistent on non-orthogonal grids, multi-phase flow simulation using TPFA on corner-point grids may have significant discretization errors if grids are not K-orthogonal. To improve the simulation accuracy, we developed a novel method where the faults are modeled by polyhedral cells, and mimetic finite difference (MFD) methods are used to solve flow equations. We use a cut-cell approach to build the mesh for faulted reservoirs. A regular orthogonal grid is first constructed,and then fault planes are added by dividing cells at fault planes. Most cells remain orthogonal while irregular non-orthogonal polyhedral cells can be formed with multiple cell divisions. We investigated three spatial discretization methods for solving the pressure equation on general polyhedral grids, including the TPFA, MFD and TPFA-MFD hybrid methods. In the TPFA-MFD hybrid method, the MFD method is only applied to part of the domain while the TPFA method is applied to rest of the domain.
We compared flux accuracy between TPFA and MFD methods by solving a single-phase flow problem. The reference solution is obtained on a rectangular grid while the same problem is solved by TPFA and MFD methods on a grid with distorted cells near a fault. Fluxes computed using TPFA exhibit larger errors in the vicinity of the fault while fluxes computed using MFD are still as accurate as the reference solution. We also compared saturation accuracy of two-phase (oil and water) flow in faulted reservoirs when the pressure equation is solved by different discretization methods. Compared with the reference saturation solution, saturation exhibits non-physical errors near the fault when pressure equation is solved by the TPFA method. Since the MFD method yields accurate fluxes over general polyhedral grids, the resulting saturation solutions match the reference saturation solutions with an enhanced accuracy when the pressure equation is solved by the MFD method. Based on the results of our simulation studies, the accuracy of the TPFA-MFD hybrid method is very close to the accuracy of the MFD method while the TPFA-MFD hybrid method is computationally cheaper than the MFD method.
Integrated Rock and Fluid Workflow to Optimize Geomodeling and History Matching
Authors: Ruiz Elizabeth , Thibodeaux Brandon , Dorion Christopher , Mukisa Herman , Faskhoodi Majid , Hakim Bilal , Garcia German , Xu Wayne , Betancourt Soraya , Canas Jesus , Messonnier Tom , Mullins Oliver 
Published: September 2021

Abstract
Optimized geomodeling and history matching of production data is presented by utilizing an integrated rock and fluid workflow. Facies identification is performed by use of image logs and other geological information. In addition, image logs are used to help define structural geodynamic processes that occurred in the reservoir. Methods of reservoir fluid geodynamics are used to assess the extent of fluid compositional equilibrium, especially the asphaltenes, and thereby the extent of connectivity in these facies. Geochemical determinations are shown to be consistent with measurements of compositional thermodynamic equilibrium. The ability to develop the geo-scenario of the reservoir, the coherent evolution of rock and contained fluids in the reservoir over geologic time, improves the robustness of the geomodel. In particular, the sequence of oil charge, compositional equilibrium, fault block throw, and primary biogenic gas charge are established in this middle Pliocene reservoir with implications for production, field extension,and local basin exploration. History matching of production data prove the accuracy of the geomodel; nevertheless, refinements to the geomodel and improved history matching were obtained by expanded deterministic property estimation from wireline log and other data. Theearly connection of fluid data, both thermodynamic and geochemical, with relevant facies andtheir properties determination enables a more facile method to incorporate this data into the geomodel. Logging data from future wells in the field can be imported into the geomodel allowingdeterministic optimization of this model long after production has commenced. While each reservoir is unique with its own idiosyncrasies, the workflow presented here is generally applicable to all reservoirs and always improves reservoir understanding.
Toward Controllable Infill Completions Using Frac-Driven Interactions FDI Data
Authors: Cai Yuzhe , Dahi Taleghani Arash 
Published: September 2021

Abstract
Infill completions have been explored by many operators in the last few years as a strategy to increase ultimate recovery from unconventional shale oil reservoirs. The stimulation of infill wells often causes pressure increases, known as fracture-driven interactions (FDIs), in nearby wells. Studies have generally focused on the propagation of fractures from infill wells and pressure changes in treatment wells rather than observation wells. Meanwhile, studies regarding the pressure response in the observation (parent) wells are mainly limited to field observations and conjecture. In this study, we provide a partialcorrective to this gap in the research.We model the pressure fluctuations in parent wells induced by fracking infill wells and provide insight into how field operators can use the pressure data from nearby wells to identify different forms of FDI, including fracture hit (frac-hit) and fracture shadowing. First,we model the trajectory of a fracture propagating from an infill well using the extended finite element methods (XFEM). This method allows us to incorporatethe possible intersection of fractures independent of the mesh gridding. Subsequently, we calculate the pressure response from the frac-hit and stress shadowing using a coupled geomechanics and multi-phase fluid flow model. Through numerical examples, we assess different scenarios that might arise because of the interactions between new fractures and old depleted fractures based on the corresponding pressure behavior in the parent wells. Typically, a large increase in bottomhole pressure over a short period is interpreted as a potential indication of a fracture hit. However, we show that a slower increase in bottomhole pressure may also imply a fracture hit, especially if gas repressurization was performed before the infill well was fracked. Ultimately, we find that well storage may buffer the sudden increase in pressure due to the frac-hit. We conclude by summarizing the different FDIs through their pressure footprints.
Stability of Chemically Degraded Friction Reducers and Their Relationship to Regain Conductivity
Authors: Ayazi Philip , Monreal Gabriel , Bleibel Hassan , Zamora Frank , Watters Larry 
Published: September 2021

Abstract
Previously, it was shown that zeta potential could be used as a metric to determine friction reducer (FR) performance. Specifically, the extent of and how quickly the FR reaches peak friction reduction in source water. A correlation postulated from the previous work is zeta potentials relationship to an FR's stability during mechanical or chemical degradation. In other words, can zeta potential be used as a metric to determine the extent of polymer breaking and can this relationship be translated to regained conductivity? This paper describes a laboratory study of zeta potential measurements to track breaker reaction rates, stability of broken polymer dispersions, and the relationship between chemical degradation of FRs and regained conductivity.
The approach of this investigation involves measuring zeta potential of frac fluids formulated using anionic and cationic FRs with varying types and concentrations of breakers at different temperatures and times. These metrics are then correlated with regain conductivity. A quantitative relationship exists between zeta potential, fluid rheology, and regain conductivity. Zeta potential evaluation of degraded FR's in frac fluids correlate to performance in regain conductivity testing. These measurements can expedite the selection of chemical breakers with respect to performance. Zeta potential measurements of degraded FR are indicative of broken FR dispersion stability which has impact on regain conductivity. Tracking behavior of cationic FR's using zeta potential reveals the materials can become anionic with time and temperature and become susceptible to agglomeration with iron. Zeta potential measurements can be used during a chemical breaker selection process as a viable supplement to industry standard tests for assessing the comparative effectiveness of chemical breakers in frac fluids.
Complex Subsurface Well Abandonments Using Relief Well Methodologies
Authors: Dorey Jamie , Rassadkin Georgy , Ridgway Douglas 
Published: September 2021

Abstract
The field experience in the continental US suggests that approximately 33% of plug and abandonment operations are non-routine, and 5% require re-entry (Greer C.R., 2018). In some scenarios, the most cost-efficient option for the intervention is drilling an intercept well to re-enter the target well or multiple wells externally using advanced survey management and magnetic ranging techniques. This paper presents the methods applied of relief well methodologies from the planning to execution of a complex multiple-well abandonment project.
Improvements in Active Magnetic Ranging sensor design and applications have improved the availability of highly precise tools for the purpose of locating and intercepting wellbores where access is not possible. These instruments were commonplace on relief well interventions, however, have found a new application in solving one of the major issues facing the oil and gas industry. Subsurface abandonments are a complex task that requires a robust methodology. In this paper, we describe the techniques that have been built upon the best practices from industry experience (ISCWSA WISC eBook). This paper also illustrates how the combination of advanced survey management, gyro surveying, and magnetic ranging can be used following the best industry practices for fast and cost-efficient non-routine plug and abandonment.
Case studies of several abandonment projects are presented showing the various technical challenges which are common on idle and legacy wells. The projects include wells that are currently under the ownership of an operator and orphaned wells that have been insufficiently abandoned and left idle over many decades. The case studies outline how the application of relief well methodologies to the execution of complex sub surface interventions led to the successful outcomes of meeting environmental and government regulations for wellbore abandonment. This includes performing multiple zonal isolations between reservoirs, water zones and preventing oil and gas seepage to the surface. The projects and their outcomes prove economically viable strategies for tackling the growing issue of idle and orphaned wells globally in a fiscally responsible manner.
Combining industry best practice methods for relief well drilling, along with the technological advancements in magnetic ranging systems is a solution for one of the largest dilemmas facing the oil and gas industry in relation to idle and orphaned wellbores. These applications allow previously considered impossible abandonments to be completed with a high probability of long-term success in permanent abandonment.
Efficient Modeling of Depletion Induced Fracture Deformation in Unconventional Reservoirs
Authors: Pei Yanli , Sepehrnoori Kamy 
Published: September 2021

Abstract
The change of fracture conductivity during reservoir depletion significantly affects the well performance and stress evolution in unconventional formations. A common practice is to model fracture deformation using the traditional finite element method with very dense unstructured grids representing complex fracture geometries. However, the associated computational cost is high, so previous studies mainly use empirical correlations to catch the fracture conductivity loss or neglect fracture deformation during the production period. This work proposes a novel coupled flow and geomechanics model with embedded fracture methods to capture the fracture deformation accurately yet efficiently in unconventional reservoirs. Under a single set of structured grids, an embedded discrete fracture model (EDFM) is employed to characterize fluid flow through discrete fractures by introducing non-neighboring connections, and an extended finite element method (XFEM) is applied to simulate discontinuities over fracture walls by adding phantom nodes. In addition, a modified proppant model is incorporated to represent interactions between proppants and hydraulic surfaces, and an iterative coupling scheme is implemented to link the fracture-related fluid flow and solid mechanics. Being validated against the classical benchmark problem, the coupled model is used to investigate the impacts of proppant strength, closure stress, and bottomhole pressure on fracture deformation, well production, and in-situ stresses. Numerical results indicate that weaker proppant support induces more fracture aperture and production losses, resulting in greater stress changes and higher residual pressure in the depletion region. In comparison, the fracture deformation for a well-propped scenario is modest and barely affects the well performance and stress redistribution. Less stressed formation corresponds to lower closure stress on fracture walls, which triggers limited fracture closure and stabilizes well production. Moreover, a moderate bottomhole pressure decline rate avoids significant fracture closure while preserves relatively high initial production rates. The coupled flow and geomechanics model with embedded fracture methods resolves computational difficulties in modeling complex fracture deformations and delivers more insights on production forecast and stress changes crucial to refracturing and infill operations.