bluuebunny/crossref_metadata_2025_split huggingface dataset:
Augmented Reality: Simulation Enhanced Pressure Core Data
Authors: Erkal Alpay , Christensen Christopher , Powers Garwin , DesAutels Dave 
Published: September 2019

Abstract
Field development decisions are directly related to the original hydrocarbon in-place that leads to proper estimation of recoverable volumes and establish project economics. Oil and gas industry has had pressure core technology that is available to extract and preserve cores from reservoirs near in-situ conditions to determine hydrocarbon in-place values. Pressure core technology is an emerging one and prone to incomplete or partial data acquisition due to design limitations and inadequate implementations. Simulation modeling tool, typically used for reservoir modeling purposes, can augment the underperformances in data acquisition with a lab scale core simulation program.
Noble Energy has developed a modeling approach that allows hydrocarbon desorption rates from a pressure core sample to be simulated by emulating the lab conditions. Early time fluid losses for various reason such as fluid losses while encapsulating the core or during transport via wellbore and to the lab are common. Late time fluid desorption rates are difficult to obtain due to the time constraint that exists for performing experiments in the lab since it’s limited to hours to days timeframe. Both early and late time desorption rates can be augmented by simulation that yields better estimation of in-place volumes and expected recovery values over time while honoring the lab measured data in between.
Pressurized wireline rotary sidewall coring used by the vendors can have seal failures and the procedures implemented would not provide assurance of zero fluid losses since the mechanical equipment has expected operational limitations. The data obtained from such acquisitions may be deemed a failed experiment or even discarded if the losses cannot be quantified properly. Simulation enhancement revitalizes the data acquired and adds value to even partially successful pressure coring programs.
Noble Energy developed modeling approach to simulate fluid flow from the center of a core plug to the exterior surfaces of the plug emulating the lab environment complements the lab measurements even the pressure core had issues during and after acquisition. Simulation enhances pressure core data that may be incomplete or partially acquired based on possible early time losses and provide extended answers for late time desorption by eliminating impractical lab measurement timeframe. Reduced uncertainty in original hydrocarbon in-place volumes will allow better valuation of assets and robust field development plans.
Viscoelastic Polymer Injectivity: A Novel Semi-Analytical Simulation Approach and Impact of Induced Fractures and Horizontal Wells
Authors: Hwang Jongsoo , Sharma Mukul , Chiotoroiu Maria-Magdalena , Clemens Torsten 
Published: September 2019

Abstract
Several field cases reported that polymer injection in a horizontal well is a viable solution to increase oil recovery. The injectivity, however, may vary significantly depending on fluid, reservoir, and geomechanical conditions. Polymer injection without understanding these factors may lead to injectivity impairment, unswept zones, and fractures undesirable for the sweep. In this paper, we present a comprehensive viscoelastic polymer injectivity model for vertical and horizontal wells.
We developed a simulator to compute viscoelastic polymer injectivity by accounting for particle filtration, thermo-poro-elastic stress changes, fracture propagation, flow distributions among multiple layers, and viscoelastic polymer rheology. Simulation results clearly show that the contribution of shear-thickening characteristics on the polymer can have a large impact in un-fractured wells but have a much smaller impact in fractured injectors. The impact of geomechanical stress changes and subsequent induced fractures are also highlighted.
The model was then applied for a field case study to identify critical aspects needed to maintain high injectivity. Two field case wells are presented where water and viscoelastic polymer are injected for a vertical well and a horizontal well accessing the multi-layered reservoir respectively. For the two injectors, water was injected initially, and then HPAM polymer solution followed to improve oil recovery. Fracture growth and injection into a long horizontal lateral are the key factors that allowed the operator to maintain injectivity by reducing the Darcy velocity, shear rate, and shear-thickening zone. For a horizontal well, operating conditions are also identified by simulations to ensure matrix injection, which is the desired conformance and sweep improvement option.
Impact of Injection Water Quality on Injectivity – A Lab Study
Authors: Karazincir Oya , Gomez-Nava Sandra , Evans Paul , Wu Ruiting , Williams Wade , Jones Colin , Rijken Peggy 
Published: September 2019

Abstract
Waterflooding is commonly performed in oil wells for pressure support and increased oil production. Different sources of injection water can be used for waterflooding, such as aquifer water, seawater or produced water. Each of these water sources contain particulates in them that deposit at the injection point forming both an external filter cake on the reservoir face and an internal cake inside the rock surface. The properties of the external and internal filter cake negatively affect injectivity. In order to identify the optimum water filtration specs prior to injection, the contribution of different solid particle types present in the injected water on filter cake properties and injectivity need to be understood.
A lab study has been undertaken to gauge the contribution of different solid types, solid sizes, and the presence of oil droplets on filter cake properties and water injectivity. The solid types tested were silica/quartz, clay, iron oxide, barium sulfate and calcium carbonate, with and without oil contamination. Membrane tests were conducted to understand the correlation between the porosity and the permeability of the external filter cake that forms at the formation face for each particulate type. A heavy slurry of selected solid particulate was mixed in brine and was compressed into a membrane under different applied pressures, and the porosity and the permeability of the cake was calculated at each stage. Core tests were designed to look at the combined effects of the external and internal filter cake on reduction in injectivity. Outcrop cores, representative of the field cores, with similar pore throat size, porosity and permeability were used in the core tests, as particle bridging at pore throats is a function of the comparison between the injected particle size and the pore throat size distribution of the reservoir. A slurry of the selected solid particulates in brine was injected into the core system and the permeability drop across the core was monitored as a function of injected water pore volumes. Both types of tests were repeated in the presence of oil contamination in the injected water. The test data from the membrane tests and the core tests were used in the numerical model to obtain the permeability reduction function for the internal and external filter cake.
Long-Term Productivity Comparison of Gel and Water Fracture Stimulation in Marcellus Shale Play
Authors: Al-Alwani Mustafa A. , Britt Larry K. , Dunn-Norman Shari , Alkinani Husam H. , Al-Hameedi Abo Taleb , Al-Attar Atheer M. 
Published: September 2019

Abstract
The goal of any hydraulic fracturing stimulation is to design and execute the appropriate treatment that is best suited for the stimulated reservoir. Selecting the best treatment must achieve the desired fracture geometry to maximize long-term well productivity and reserve recovery. The main objective of this study is to conduct detailed short and long-term production and well-to-well comparisons of the different types of fracture stimulation fluids in the Marcellus Shale play.
A database of more than 4,000 horizontal, stimulated Marcellus wells was constructed for this study. The wells were divided into four groups according to the type of treating fluid: water, gel, cross-linked, and hybrid fracs. Chemical data from FracFocus were gathered and processed then combined with completion and production data to investigate the gas short and long-term production. Detailed monthly production data for the studied wells were captured from DrillingInfo database and utilized in this study.
This paper reports and compares the Marcellus gas initial production, the gas cumulative production at the end of the first month, first 6 months, first year, 2 years, and 5 years, according to the type of hydraulic fracturing fluid used in primary stimulation. The work provides insights into Marcellus well performance as a function of stimulation parameters such as the volume of stimulation fluid and the amount of pumped proppants. The impact of perforated lateral length is taken into consideration and used to normalize production and stimulation parameters. The study shows that water fracturing fluids outperformed the other types of hydraulic fracturing fluids.
This paper introduces several data processing workflows that serve as a reference for individuals who are interested in extracting and processing data from the FracFocus database. It also documents the occurrence in hydraulic fracturing fluid types and measures the effects of the fracturing fluid volume and total proppant pumped on the initial and cumulative production.
Analytical Models for Interpretation and Analysis of Transient Sandface and Wellbore Temperature Data
Authors: Onur Mustafa , Galvao Mauricio , Bircan Davut Erdem , Carvalho Marcio , Barreto Abelardo 
Published: September 2019

Abstract
The objectives of this study are to (i) provide analytical transient coupled wellbore/reservoir model to interpret/analyze transient temperature drawdown/buildup data acquired at both the producing horizon (sandface) and a gauge depth above the producing horizon (wellbore) and (ii) delineate the information content of both transient sandface and wellbore temperature measurements. The analytical models consider flow of a slightly compressible, single-phase fluid in a homogeneous infinite-acting reservoir system and provide temperature-transient data for drawdown and buildup tests produced at constant rate at any gauge location along the wellbore including the sandface. The production in the wellbore is assumed to be from inside the production casing. The models account for Joule-Thomson (J-T), adiabatic fluid-expansion, conduction and convection effects as well as nearby wellbore damage effects. The well/reservoir system considered is a fully penetrating vertical well in a two-zone radial composite reservoir system. The inner zone may represent a damaged (skin) zone, and the outer (non-skin) zone represents an infinitely extended reservoir. The analytical solutions for the sandface transient temperatures are obtained by solving the decoupled isothermal (pressure) diffusivity and temperature differential equations for the inner and outer zones with the Boltzmann transformation, and the coupled wellbore differential equation is solved by Laplace transformation. The developed solution compares well with the results of a rigorous thermal numerical simulator and determines the information content of the sandface and wellbore temperature data including skin zone effects. The analytical models can be used as forward models for estimating the parameters of interest by nonlinear regression built on any gradient-based estimation method such as the maximum likelihood estimation (MLE).
Tradespace Exploration for Offshore O&G Developments - A Model Based Systems Engineering Approach
Authors: Leocadio da Nova Anderson 
Published: September 2019

Abstract
The objective of this paper is to explore the benefits of using the Interactive Epoch-Era Analysis (IEEA) methodology for evaluating architectural changes in a trade space exploration study. In this paper a subsea tieback offshore Brazil will be used as reference case to investigate this premise from a full field development perspective.
An automated concept exploration tool is employed. It applies meta-heuristics to generate different offshore facilities concepts with varying building blocks. The interaction between reservoir behavior and facilities design is accounted for, meaning pressure and temperature losses throughout the system are taken into account in each concept differently. These concepts are ranked in terms of economic performance indicators (NPV, IRR, etc.), and each run with a given set of boundary conditions covers what is called an Epoch. This process is iterated for the whole life of field with a set of different boundary conditions, such as commercial aspects ($/bbl, $/MMBtu, market demand) and/or technological maturity aspects (TRL, novel technological concepts), generating what is called an Era. The whole data set is then evaluated in an interactive platform thru the Humans-In-the-Loop (HIL) process.
Model Based Systems Engineering (MBSE) is being employed successfully in other engineering fields outside the O&G context such as the aerospace and automotive industries. While digital tools have been identified as a potential key contributor to the future of O&G performance enhancement and further cost reductions, that is yet to be shown. This work intends to provide backing for that argument in one of the potential applications during early concept exploration phases by showing that quick high value assessments following an MBSE approach may be carried out, once significant effort has been put into proper development, verification and validation (V&V) of such digital tools.
While integrated models for asset development have long been a subject of interest for O&G operators, the application of Systems Engineering concepts to it has not yet been thoroughly explored. Systems Engineering provides a rigorous and proven method of dealing with complex systems that is highly applicable to offshore field developments. MBSE is the current State of the Art for capital intensive projects such as space exploration spacecrafts and rovers. Learning from these successful use cases and applying these methodologies in the development of digital technologies may provide a new set of tools in the belt of O&G operators Facilities Engineers and alike. The study case presented shows MBSE’s capability of capturing intrinsic non-linearities and specificities of each O&G field/location while ensuring project wide functional requirements are successfully met.
Characterization and Modeling of the Fault Network of a Brazilian Pre-Salt Reservoir and Upscaling Results
Authors: De Lima Alexandre , Fourno André , Noetinger Benoit , Schiozer Denis José 
Published: September 2019

Abstract
Carbonate Brazilian pre-salt fields have a large number of faults detected by seismic and well data. Nevertheless, because of limitations in seismic resolution, all existent faults cannot be identified. That is one of the main challenges for understanding related heterogeneities (vugs, karst) and the flow behavior. This paper deals with a fault analysis and modeling using an original approach and fault data of three pre-salt reservoirs.
One possible approach for characterizing and modeling the fault network (Verscheure et al, 2010) aims the integration of all available conceptual knowledge and quantitative data. This sub-seismic model keeps the geological consistency of seismic faults through capturing its specific spatial organization. First, geometry of seismic faults was characterized based on fractal methods. Secondly, sub-seismic faults were generated with stochastic algorithm. The work originality is also related to the studied reservoir which is close to two other fractured reservoirs. Each one aims a fault network with a specific fractal dimension. The fractal dimension choice was discussed.
The results presented on this article lead us to discuss the importance of how to choose the samples for modeling sub-seismic faults based on the ensemble of seismic faults available. This article answers the question about which available seismic faults we should use for estimating fractal dimension, should we use all available seismic faults near of the reservoir area or use only the faults inside the reservoir contour. After this short discussion on the fractal dimension choice from a spatial distribution point of view, the impact of this choice on flow was illustrated. The sub-seismic fault models were modeled using different fractal dimension. Subsequently, an upscaling step using analytical upscaling (Oda, 1985) was performed. Finally by comparing the upscaling results of the fault networks, the choice of fractal dimension was characterized from a production point of view. Finally our modeling choice and simulation results were presented.
Characterizing sub-seismic faults has a major impact on the overall flow behavior of the field. The chosen methodology has been applied only on synthetic cases but never published using real data. This work will interest a practicing engineer. The fault network of these neighbor reservoirs allows us to illustrate the importance on the choice of fractal dimension for characterizing the fault network and its impact on the subseismic models and fluid displacement, consequently on production.
Understanding the Influence of Natural Fractures and Stress Anisotropy on Hydraulic Fracturing Design
Authors: Shetty Dinesh , Hillard Robert , Stegent Neil 
Published: September 2019

Abstract
In general, hydraulic fracturing design for unconventional reservoirs is performed using planar fracture model simulators. It is well known that the presence of natural networks combined with varying stress anisotropy can significantly impact the overall stimulation process and hence, associated oil or gas recovery.
In this study, a well-validated fracture simulator is used that explicitly accounts for the interaction between natural and hydraulic fractures under imposed stress anisotropy and performs transport of proppant in the induced complex network. Density of the natural fracture system is varied to study the scenarios, such as hydraulic fracture-governed mode and natural fracture-governed mode. For each of these scenarios, associated stress anisotropy is varied. These two parameters represent the properties of the formation that cannot be controlled. Then, multiple simulations are performed to understand the influence of design parameters, such as total slurry volume, pumping rate, and stage design for each set of fracture density and stress anisotropy. Many indicators are used, such as the stimulated fracture area, total proppant bed area, the area of the fracture above the bed, etc., to assess the efficacy of a design.
This study shows that, depending on the natural fracture density and the stress anisotropy, the benefits of pumping larger volumes of fluid to create longer fractures and effectively distribute the proppant diminishes. It also reveals that modification of the stage design can be utilized to alleviate this problem. The capability to transport proppant by increasing the pumping rate is observed to be strongly dependent on natural fracture density. The result also shows the importance of these factors for whole pad optimization because the natural fractures and stress anisotropy can significantly alter the maximum fracture length.
Thus, it becomes imperative to know the natural fracture distribution and the associated stress anisotropy to efficiently create a hydraulic fracturing design.
Unlocking Additional Barrels From a Mature Conventional Oil Field Through Unconventional Technologies: A Case Study on Rangely Oil Field, Colorado
Authors: Ketineni Sarath Pavan , Tan Yunhui , Hoffman Katrina L. , Jones Matthew , Ghoraishy Mojtaba 
Published: September 2019

Abstract
Demonstrating the viability of multistage hydraulic fractured horizontal wells to unlock otherwise trapped resources is presented through a case study on Rangely. A combination of high-fidelity reservoir models was employed for accurate forecasts and evaluation of hydraulically fractured horizontal wells to improve resources in this mature conventional oil field with ongoing pressure support and tertiary recovery operations. The modeling techniques used in this method can be extended to other mature oil fields to unlock bypassed oil setting a precedent to re-evaluate mature oil fields with the new unconventional completion technologies.
The Rangely Weber Sand Unit is an Eolian sandstone depositional system consisting of 2 billion bbls of oil in place. The Weber Formation is Pennsylvanian to Permian in age, and typically consists of fine-grained and cross bedded calcareous sandstones. Structurally oil is trapped in an anticline with varying dip angles on the flanks. The oil production from this reservoir was managed through primary depletion for the first two decades of production followed by secondary recovery via water flood and concluding through water alternating CO2 injection (WAG) over the last three decades. Due to the heterogeneity in depositional environment, the recovery factors have been low in the eastern end of the field. The east end of the field has relatively lower permeability and lower porosity compared to the rest of the field. A modeling workflow is presented to assist with evaluation and optimization of hydraulically fractured horizontal infill wells to recover bypassed oil in the eastern end of the Rangely field.
A full fidelity static model was built based on dense, high quality well control data. A sector model was history matched, and then used to update pressure, saturations, and stress distribution to present day. The history matched model was subsequently used to evaluate horizontal well performance and hydraulic fracturing completion options to overcome these heterogeneities and improve recovery from a lower quality reservoir.
Completions optimization opportunities were focused on fracture geometry, incremental Estimated Ultimate Recovery (EUR), and economics. Sensitivity studies demonstrated that an optimal balance of cost and recovery is found at the low end of fracture volumes and wider perforation cluster spacing. Forecasting runs show incremental economic recovery which otherwise could not have been recovered through ongoing WAG operations.