bluuebunny/crossref_metadata_2025_split huggingface dataset:
Influencing Factors of the Microstructure and Macroscopic Performance of Foamed Cement
Authors: Pang Xueyu , Singh John P. , Jimenez Walmy Cuello , Prince Aaron C. 
Published: September 2016

Abstract
Foamed cement has provided zonal isolation in oil and gas wells since the 1980s. However, the lack of an experimental technique that fully characterizes foamed cement properties is limiting its application. This study uses X-ray microcomputed tomography (micro-CT) to elucidate relationships between the foaming process, foamed cement microstructure or morphology, and macroscopic performance of the material’s mechanical properties.
During this study, foamed cement slurries were prepared using a traditional multiblade laboratory blender to investigate the influencing factors on foamed cement properties. The influences of shear rate, mixing energy, surfactant concentration, and base cement slurry composition on the properties of set foamed cement were specifically studied. A MACS® multiple analysis cement system was also used to study the gas pressure and blender geometry effect on test results. Approximately 25 foamed cement slurries with foam qualities (FQs) ranging from 20 to 80% were produced. The microstructure and macroscopic performance of the foamed cement were quantified using micro-CT analysis and uniaxial compression tests.
Test results indicate there is an important mixing energy threshold value that needs to be supplied to produce stable foamed cement. The maximum achievable FQ is determined by the shear rate during the foaming process. Once the minimum qualifications for obtaining stable foamed cement and a target FQ are met, a further increase in mixing energy or shear rate has little effect on the foamed cement microstructure or macroscopic performance. However, excessive mixing energy supplied at a high shear rate can lead to a higher initial slurry temperature, a less homogenous microstructure, and relatively poor mechanical properties after the foamed cement has set. The primary determining factors of the foamed cement microstructure are FQ and gas pressure. In samples generated using the multiblade laboratory blender at atmospheric conditions, the median gas bubble size increased significantly from 116 µm at 20% FQ to 1400 µm at 80% FQ. The median gas bubble size in the 20% FQ samples generated using the MACS device decreased significantly when gas pressure increased from 133 µm at atmospheric pressure to 39 µm at 1,000 psig.
Production Pressure Drawdown Management for Fractured Horizontal Wells in Shale Gas Formations
Authors: Mirani Ankit , Marongiu-Porcu Matteo , Wang HanYi , Enkababian Philippe 
Published: September 2016

Abstract
The development of unconventional shale gas formations in North America with horizontal multifractured wells is mature enough to identify production malpractices and abnormal productivity declines generally observed within 18 to 24 months of initial production. The primary objective of this study is to address all known causes of these productivity declines and to develop a fully coupled geomechanical-flow simulation model to simulate these production conditions.
This model mimics the impact of depletion-induced in-situ stress variations on short-term and long-term productivity by taking into account several phenomena, such as stress-dependent matrix and natural fracture permeability as well as reduction in hydraulic fracture conductivity due to proppant crushing, deformation, embedment, and fracture-face creep. Matrix permeability evolutions, considering the conflicting effects of non-Darcy flow, and compaction, have also been accounted for in this model. Numerical solutions for simplified hydraulic fracture planar geometries are then obtained using a finite element method (FEM) scheme.
A synthetic case was defined to investigate the effects of each individual phenomenon on short-term and long-term production. Results show that the combined effects of permeability alterations in matrix and natural fractures as well as conductivity losses in hydraulic fractures may result in substantial gas cumulative production loss. The model also reproduces familiar field-observed trends, with lower long-term production corresponding to higher and higher drawdowns. This behavior is attributed to the stress-dependent evolution of reservoir permeability and hydraulic fracture conductivity. The results conclude that ignoring impacts of any of the above phenomena results in overestimation of ultimate recovery. Furthermore, it is shown that proper management of pressure drawdown and the penalty for lower initial production rates in unconventional shale gas reservoirs can yield substantially higher ultimate recovery.
The model is fully versatile and allows modeling and characterization of all profoundly different (on a petrophysical level) shale gas formations as well as proppant materials utilized for the stimulation treatments. This integrated model can be used for optimization of key parameters during the hydraulic fracture design, for fine-tuning production history matching, and, especially, as a predictive tool for pressure drawdown management.
ROP Optimization Using Artificial Intelligence Techniques with Statistical Regression Coupling
Authors: Mantha B. , Samuel R. 
Published: September 2016

Abstract
Predictive data-driven analytics has driven massive interest, primarily because of its successful implementation in several industries. Data-driven modeling and its application to predict downhole environment will prove to be the future of drilling operations, as they hold the potential to optimize highly complex drilling operations. In general, rate of penetration (ROP) optimization involves adjustment of the weight on bit (WOB) and rotary speed (RPM) for efficient drilling. ROP follows a complex relationship with several other parameters such as formation properties, mud properties, mud hydraulics, borehole deviation as well as the size/type of bit.
Traditional regression analysis models have limitations and have limited accuracy while attempting to describe the dependence of one observed quantity on another observed quantity. On the other hand, the artificial intelligence methods face drawbacks trying to understand the physics behind the operations. To ensure the physical and technical feasibility of the prediction, coupling conditions between the two have been developed for the ROP optimization.
In this study, a new model based on statistical regression and artificial neural networks (ANNs) was designed to predict ROP using field data gathered from the North Sea Horizontal Wells. Exploratory analysis was performed to find correlations between variables, followed by measurement of predictor importance to infer relative contributions and weights of inputs. Cross-validation was employed to prevent overtraining of models. Several models such as Step-Wise regression, neural networks (NN, KNN), support vector regression (SVR), classification regression trees (CART), were applied for prediction. Ensemble methods such as Random Forests (RF) and Boosting helped increase accuracy and reduce errors. The algorithm designed was further tested on other wells and was shown to predict with significant accuracy. This proves that several parameters need to be comprehensively considered while optimizing the ROP. Since the algorithm presented here doesn't depend on a single model but rather several predictor models, it can be effectively employed independent of location or formation.
How to Develop a Well Specific Blowout Contingency Plan that Covers Engineering Analysis of the Deployment, Installation, and Soft Shut-In of a Subsea Capping Operation
Authors: Oskarsen Ray T. , Emilsen Morten H. , Paknejad Amir S. , Cargol Mike , See Kwee Choong 
Published: September 2016

Abstract
Post Macondo, industry publications have discussed the equipment, connections, and interfaces needed for capping and containing a blowing subsea well, but they give little insight into developing a well-specific subsea-capping contingency plan. The planning process described here, which has been used successfully on multiple projects and source-control drills, involves assessing the feasibility of deploying a capping stack from a floating vessel, the weight and stability of the capping stack to overcome the force of the blowout jet, and dynamic flow simulations of closing the capping stack outlets without loss of well integrity. This process not only assesses the feasibility, complexity, and risk exposure of the capping operation, but may also justify further planning, studies, or expenditure.
Advanced Inflow Control Device in Horizontal Well Extends Economic Field Life: A Case Study and Technological Overview
Authors: Jalan Shiv Narayan , Kotecha Rohit Kumar , Gazi Naz H. , Al-Sabea Salem , Bu-Qurais Abdullah , Al-Azmi Mohammad Saad , Al-Houti Naser 
Published: September 2016

Abstract
The Passive Inflow Control Device enhances the well productivity and recovery by removing Heel to Toe effect in a homogeneous reservoir and allowing production optimization along the entire horizontal section in case of heterogeneous reservoir. But these ICDs have their own limitations in controlling the high water producing zones in horizontal wells. The introduction of Sliding Sleeve Technology in horizontal wells has added a greater value to ICDs by further controlling water production from undesired zones. The new Advanced Inflow Control Device with sliding sleeve approach is built upon the usefulness of sliding sleeve technology in horizontal wells. This rigless technology can be used to maximize oil production from horizontal wells, save huge rig workover cost and extend the economic life. This paper describes a case study in Greater Burgan Field showing the challenges encountered while drilling the horizontal well and benefits associated with the integration of the passive Inflow Control Devices (ICD) with Sliding Sleeves in complex horizontal wells. After the well was put on production, Production Logging Tool (PLT) was run to identify the high water producing compartments and accordingly plan was made to close these ICDs by mechanically shifting the sliding sleeves. Pre and post DTS survey clearly confirmed the successful closure of high water producing ICDs. Several flow tests were done before and after shifting the sliding sleeves to monitor the reduction in water cut.
A complete case study is presented to permit the readers to know the benefits of using sliding sleeves along with ICDs in horizontal wells and thus improve the hydrocarbon recovery. Leveraged knowledge from this pilot has provided an insight into the capabilities of sliding sleeve type of ICDs.
The PetroChallenge – An Innovative E&P Learning Experience Using an Interactive Learning Simulation
Authors: Venugopal Kalyanaraman , Kelly Paula , Jamaluddin Abul , McConnell Charles , Alger Monty , Morgan Eugene , Ni Rui , Dunn Ronald , Grasselli Giovani 
Published: September 2016

Abstract
For decades, the university education has provided a base foundation and prepared students to join the workforce. Despite the technical foundation, students lack practical exposure. To bridge the practical knowledge gap, the industry has launched various short duration interns/externs programs. Even then these programs are not broad enough to provide a holistic understanding of the Oil and Gas Industry. Therefore, in 2015 to address this practical application NExT, a Schlumberger company, launched an interactive simulation based learning competition called PetroChallenge sponsored by Oil and Gas companies. The students are grouped into integrated teams of 3 or 4 participants; for example, an engineer, geoscientist and a business major student forms a team. Each team then acts as an operating company being fully exposed to the complete upstream cycle of the oil and gas industry using a web-based simulator called OilSim. Throughout the event, these teams make Exploration and Production (E&P) decisions and their actions and choices are then judged through the Net Present Value (NPV) of their company. The winning teams are declared based on the combined highest NPV and credibility points, earned by each team based on their challenge decisions and corporate social activities and engagements.
As E&P companies are making a stride to reduce the "Time to Autonomy" for new recruits, an event like the PetroChallenge can be a good enabler for students to be better prepared when joining the workforce. In these unique events, the sponsoring companies have an opportunity to evaluate potential recruits in action, not only from a technical perspective, but also, their business acumen including negotiation, risk taking and decision making skills. In the same token, students get an opportunity to network with their potential employers.
In 2015, three Universities (Rice, Penn State and University of Toronto) and ShawCor partnered with NExT and launched the inaugural PetroChallenge. These three events marked a phenomenal impact in students' learning and understanding of the oil and gas decision making process. Two winning teams from each of these events met at the North America finals, with Penn State becoming the first North American PetroChallenge university champions.
This presentation is prepared to share the key learnings and benefits of this type of student engagement prior to them moving into the real world.
Enabling Expected Value Economics Thinking within a Capital Budget Constrained E&P Portfolio
Authors: Adejumo Adebola , de Jesus Justin , Casey-Yorro Meaghan 
Published: September 2016

Abstract
One of the most important investment decisions that exploration and production (E&P) organizations make is allocating limited capital amongst the myriad projects in the corporate portfolio. The importance of making more effective capital allocation has become more apparent with the prevailing depressed oil price environment. This paper enumerates the methods used in deciding which projects to fund and puts them in the context of prevailing market conditions. It then identifies shortcomings in the most common methods used and suggests an optimal alternative.
In the prevailing depressed market conditions, most E&P organizations face significant capital spend cuts. More often than not, capital is allocated to projects based on a net present value (NPV) optimized portfolio. This sometimes results in the unintended consequence of sanctioning relatively capital inefficient projects that return less value per capital spend. A case study of a hypothetical portfolio of 12 projects including exploration, development, and production assets is used here to demonstrate this issue. Three methods—a rank and cut, NPV-optimized, and discounted profitability index (DPI) optimized—were used to determine projects to fund.
Results and insights from this analysis show that optimizing a portfolio based on NPV to allocate capital results in the unintended consequence of funding lower DPI projects, especially in an era of deep capital spend cuts, when prudence and corporate survival take precedence over production and reserves replacement targets. This paper highlights the value of expected value thinking in decision making and concludes that a DPI-optimized portfolio for capital allocation ensures E&P organizations obtain better value for capital spend and helps identify divestiture candidates when the need to raise capital ensues.
This paper leverages the effective use of cloud-enabled integrated solutions to evaluate prospects in a timely manner with minimal information and fewer resources, delivering results in a matter of minutes that would hitherto have taken a team of professionals several months to achieve.
Advanced Distributed Fiber Optic Sensors to Monitor Cement Hydration and Detect Annular Hydrocarbon Migration for Enhanced Zonal Isolation
Authors: Wu Qian , Nair Sriramya , Shuck Michelle , van Oort Eric , Guzik Artur , Kishida Kinzo 
Published: September 2016

Abstract
This paper presents an advanced fiber optic distributed temperature and strain sensing (DTSS) system designed for real-time in-situ monitoring of cement annuli in an oil and gas well. The DTSS system used in this study of cement quality and zonal isolation uses both Brillouin and Rayleigh backscattering phenomena, allowing one to separate strain and temperature using a single optical fiber.
The first part of the paper focuses on monitoring the exothermic cement hydration process after a cement slurry is displaced into an annular space. In the laboratory, temperature and strain profiles were measured independently using the DTSS system and thermocouples at various temperatures to quantify the effect of heat release during cement hydration. These independent temperature measurements showed excellent agreement. Contamination of cement due to incomplete displacement of drilling muds by cement slurry was also simulated in the experiments. Contamination was found to decrease the amount of heat generated during the cement hydration process. The degree of cement hydration and the presence of cement in the annular space – or lack thereof - could thereby be quantified. It is shown that the temperature profiles measured using the hybrid-DTSS system can be used to detect both the top of cement (TOC) as well as annular sections that are either left uncemented or contaminated with drilling fluid. This is highly relevant information, because contamination of cement is one of the main factors that negatively affects zonal isolation directly by creating paths for hydrocarbon migration or indirectly by weakening the cement, making it susceptible to damage from cyclical pressure/temperature loads.
In addition to monitoring cement hydration, specially designed fiber optic sensing cables were used to detect the presence and migration of hydrocarbons in cemented annuli, either because the cement was absent or compromised by cracking/fracturing. The presence of hydrocarbons in cemented annuli could be detected even after the cables were exposed to well construction fluids such as synthetic-based drilling mud and spacer fluid. Moreover, the materials used were sensitive to the type of hydrocarbon, allowing indirect hydrocarbon fingerprinting and determination of the origin of the hydrocarbons behind pipe. This presents a powerful new tool to assess the quality of zonal isolation behind casing, with the ability to monitor in real-time over the entire lifecycle of the well. In this capacity, it may provide guidance on such important decisions as the need for well intervention and remedial cementing.
Application of Simultaneous Operations in Saudi Arabia's Causeway Oilfields Development
Authors: Arukhe James O. , Duthie Laurie S. , Hernandez Jose Rodulfo , Ahmari Abdulrahman S , Hanbzazah Shadi M 
Published: September 2016

Abstract
Crude oil delivery expectations under timeline constraints sometimes necessitate simultaneous operations (SIMOPS) for completing field development requirements. During one such SIMOPS exercise on Field X, a major sour oilfield in causeway sites close to the Arabian Gulf in Saudi Arabia, different sub-organizations coordinated potentially different, yet complimentary operations or activities in the same location together. Challenges from the exercise included instituting an interface criteria for promoting safe operations and good technical standards for all parties. After considering work requirements, a SIMOPS team facilitated an assessment review, devised a response framework with rescue, evacuation, or emergency response plans in the event of accidental release of H2S, besides making certain other modifications to satisfy multiple stakeholders. An auditable matrix was instituted for regulating and supporting permissible simultaneous rigless and construction activities while upholding health, safety, and the environment.
The scope of this paper is to show how SIMOPS was successfully planned, executed, and managed for the first time in causeway drill sites in Saudi Aramco to prevent safety and environment incidents while ensuring to meet well tie-ins and field production targets.
The approach involved delineating clear reporting lines or control hierarchy for various stages of operation, avoiding schedule clashes by outlining clear scenarios for each organization. Guidelines were binding for all team members because of collaboration among multidisciplinary team members to develop suitable hazards identification and risk management plans thus formulating the foundations for the SIMOPS and ensuring safety of workers.
SIMOPS facilitated the unlocking of the giant field's potential while optimizing potentially conflicting but complimentary activities on the same drill site to meet crude demand reliably and safely. Success with SIMOPS has allowed oil production delivery from the field and safe working environment for crews.
A Critical Examination of the Way the Drilling Industry Traditionally Calculates Pressure Drop for Fluids in Laminar Flow
Authors: Hemphill Terry 
Published: September 2016

Abstract
Recent advances in the calculation of circulating pressure drop produced by drillpipe rotation have led to questions regarding the way the drilling industry traditionally calculates pressure drop in a circulating annulus. Because few publications discuss the hydraulics of rotation of an inner pipe in an annulus where the outer wall is stationary, there is still not a large volume of work on the subject. This paper reviews the published literature on fluids in laminar flow and discusses what is missing from the equations and the way forward.
Common equations in the literature use multiple factors to calculate pressure drop in annuli without including the effects of drillpipe rotation. The most frequently used equations include shear rate at the wall (various methods), shear stress at the wall, numerous coefficients used as patches to power-law (PL) and Bingham plastic (BP) hydraulic models, shear rate and hole geometry correction factors, drillpipe roughness factors, and drillpipe eccentricity (ε). All of the equations are missing a general, straightforward method for calculating pressure drop, both with and without rotation of an inner pipe.
Because the current API Recommended Practice 13D "Rheology and Hydraulics of Oil-well Fluids" (2010) recommends the Herschel-Bulkley (HB) rheological model for hydraulics calculations, special mention is made in this paper regarding use of the pertinent equations employing the HB model. In short, there should be a fairly straightforward method for calculating laminar flow pressure drop for axial flow with no drillpipe rotation and for helical flow that is produced by drillpipe rotation in a circulating annulus.
The proposed method for calculation of fluids in laminar flow includes: A grid across the narrowest annular gap as defined by the input drillpipe eccentricity (ε).A single velocity equation that predicts point velocities across the annular gap.Average shear rates calculated for each pair of predicted velocities in adjacent cells.Average local shear stresses calculated for each average annular shear rate.Cumulative shear stresses necessary to move the entire annular cross-sectional area.Pressure drops calculated from the cumulative shear stresses.
With this fairly straightforward method, hydraulic calculations are simplified because special coefficients or correction factors are not used. Drilling engineers should find that the outlined methods help to clarify traditional pressure drop calculations for fluids in laminar flow.