bluuebunny/crossref_metadata_2025_split huggingface dataset:
Simulation Study of Surfactant Imbibition Mechanisms in Naturally Fractured Reservoirs
Authors: Cheng Xiaoqian , Kleppe Jon , Torsæter Ole 
Published: April 2018

Abstract
Naturally fractured reservoirs with low permeability and mixed-wet properties usually have poor waterflood performance because the imbibition of water into matrix is not very significant. Surfactants could be used to change matrix wettability to more water-wet and thereby improving the imbibition of water into matrix. Surfactants can also decrease water/oil interfacial tension (IFT) resulting in mobilization of residual oil. The goal of this study is to analyze the wettability alteration and IFT decrease in the imbibition process in fractured reservoirs by simulating surfactant imbibition at core scale.
The simulator Eclipse is used to simulate wettability alteration and IFT decrease separately or simultaneously. A 3D model is set up to model a core surrounded by water/surfactant solution in a container with an injector and a producer. The injection and production rates are 0.01 cm3/hr, therefore, the viscous force can be ignored. Three different kinds of surfactant with different properties are used. Two of them have only one mechanism each, either wettability alteration or IFT decrease, and the other has both mechanisms.
In the simulation study of the injection of the surfactant that only changes the wettability to more waterwet, the ultimate oil recovery is larger and oil recovery rate is bigger than for the case with no surfactant injection. The simulation study with the surfactant that only reduces the IFT shows that ultimate oil recovery is increased when the IFT at critical micelle concentration (CMC), which is expressed as IFTCMC, is lower than 0.05 mN/m. However, at the beginning of the imbibition, the lower IFT leads to a lower recovery rate. The study of the surfactant that has both mechanisms shows that there exist optimal IFTCMC's at different wettability conditions. If the matrix is rendered strongly water-wet by surfactant, the optimal IFTCMC is 19 mN/m. If the surfactant has a weak capability of wettability alteration (the matrix is still mixed-wet), the IFTCMC needs to be reduced to ultralow value. The present studies show that wettability alteration is a more important parameter for the surfactant imbibition in fractured reservoirs than changes in IFT.
This work improves the understanding of the interplay between the main mechanisms of surfactant enhanced oil recovery (EOR) from fractured reservoirs, and provides a reference for the surfactant screening for improving oil recovery in naturally fractured mixed-wet or oil-wet reservoirs.
DeepString: Robotic Remote Deepwater Oil and Gas Production
Authors: Edwards David L. 
Published: April 2018

Abstract
New technology to address the fundamental challenge of accessing remote Arctic (i.e. overhead hazard) deepwater reserves, with no requirement for near-source separation, no requirement for production platforms (i.e. fixed or floating ‘islands’), no requirement for ultra-long pipelines over complex submarine topography (hence also no power-boosters), and no requirement for the release of burnt gases damaging to the environment. May be likened to a string of sausages – each a storage unit – comprising a multitude of casings all so linked that a long vertically-aligned string is formed where gas separated from oil up exits all units down. System as a whole at its lowermost, stabs, lubricates and locks into a permanent subsea station serving also as a multi-subsea well hub. Station has separate inlets and outlets. Outlet gas fills another set, or is reinjected, creating a complete hydrodynamic reservoir communication cycle. Filled strings are replaced with towing to and from market. Elegant, flexible, replaceable (‘one-size-fits-all’), and immediately repairable; the compartmentalisation of the interlinked units and enhanced turning-circle providing additional environmental transit security against technogenic catastrophe. Could theoretically be installed even prior to drilling for blowout fluids containment. Eliminates fundamentally therefore also the limitations of the profitability criteria applicable to wells within the platform context.
Sand Management - The Key to EOR from Mature Fields. Research into Multiple Production Optimization Applications
Authors: Arefjord Anders , Malinauskaite Giedre 
Published: April 2018

Abstract
This paper will investigate multiple production optimization case studies from the North Sea where sand management strategy contributed to increased and optimized well production, reduced integrity issues, and maintenance cost.
A new approach to sand management strategy can highly reduce, and in some cases, eliminate the needs for costly intervention operations in addition to providing uninterrupted and increased production possibilities. This paper will investigate different use of top side solids removal technology as integral part of sand management strategy and will discuss how implementing a sand management strategy that maintains solids free flow enables operators to optimize production by: Operating at maximized flow rate below ASROptimizing well performanceReducing well down timeIncreasing ultimate recoveryReducing cost per barrelExtending the life of the well and protecting the wellbore and process equipment from solids buildup and long-term erosional damage:Reducing need for CT (coiled tubing) and HWO (hydraulic workover - snubbing) sand clean-out
Case studies will investigate several cases from North Sea where new approach, integrating top sides solids removal technology into sand management strategy has contributed to production increase and optimization.
Choosing a right solids management strategy and technology can increase production while reducing production cost per barrel. Using an integrated top side solids management system enables production increase from existing wells without exceeding acceptable sand rate (ASR) level and while keeping top side process integrity intact. A deliberate sand removal strategy contributes majorly to enhancing production performance of underperforming wells.
Production data, technology applications, and results will be analyzed and compared challenging existing approach to sand management. Concrete results from several case studies will be presented showing the impact a novel approach to sand management can have to production data of mature fields, including cost reduction, well optimization and integrity issues.
Value of Cross-Disciplinary History Matching in Reservoir Modeling of the Grane Field
Authors: Moraveji M. , Roy S. S. , Fagerbakke A-K. , Sæbø A. , Ullern A. , Elde R. M. 
Published: April 2018

Abstract
Integration of all available data in history matching of reservoir modeling requires continuous effort by multidisciplinary teams. Availability and quality of input data, reservoir complexity, level of detail and effort used to construct the model can validate the model and support its following use for planning purposes.
This paper will cover such data integration; focusing on 4D data to improve well modelling and consequently achieve a better history match for the Grane Field reservoir simulation model.
The Grane heavy oil field; located in the Norwegian part of the North Sea, has been successfully produced since the start-up in September 2003. The present recovery factor is estimated at 50% with an ambition of ultimate recovery as high as 70%.
In Grane, a 4D Monitoring program was initiated in 2005 to map reservoir dynamics. After 5 repeated streamer monitors, a permanent reservoir monitoring (PRM) system was installed in 2014. By today seven PRM acquisitions have been completed. The data that is used in this study includes both 3D and 4D seismic data, production logging tool data (PLTs), pressure data and production history data. A cross-disciplinary history matching of the Grane dynamic reservoir model has clearly added value, as the model can now be used with greater accuracy when conducting simulation studies.
Practical Use of the Ensemble-Based Conjugate Gradient Method for Production Optimization in the Brugge Benchmark Study
Authors: Zhang Y. T. , Lorentzen R. J. , Stordal A. S. 
Published: April 2018

Abstract
The concept of the ensemble-based optimization has matured over the last several years and is rooted in the field of reservoir-model-based production optimization. Usually, a backtracking line search scheme is used, but this approach often leads to inefficient searching path direction (e.g. zig-zag patterns). As such, it has some redundancies in finding an optimal solution effectively, increasing the computational overhead with greater risk of problematic numerical instability. Here, we introduce a trust-region conjugate gradient method embedded in EnOpt, motivated by the general applicability and the success in practice. The approach is tested on a synthetic truth model developed by TNO, namely the Brugge benchmark model. The optimization strategy is to control maximum allowed water cut in each connection at which control valves (ICVs) are closed, and the objective is to maximize the net-present-value (NPV). Injectors are controlled using voidage replacement. The methodology performs well on the case considered here. In particular, we use the entire ensemble of controls to adapt the covariance matrix. As such, the gradient estimate of EnOpt is statistically equivalent to that of a Gaussian Mutation Optimization (GMO) algorithm.
Non-Operator Partners: Improve Analysis Time to Make More Accurate Decisions
Authors: Castro Juan Carlos 
Published: April 2018

Abstract
It is understood that on the modern oil field, large amounts of data are generated, and control of these data and efficient use is key for organizations. However, are these data helping production engineers to optimize oil production by making timely decisions or is the process of acquiring and organizing data taking most of their time, leaving a small percentage for the engineering analysis?
A common practice in the Norwegian continental shelf (NCS), is that operator companies share production data with their business partners through a common online portal. Usually, the formats selected to deliver the daily production reports and daily allocation values consist of reports in standardized XML schemas, text, Microsoft Access or Microsoft Excel files. The time frequency these files are shared varies, from daily for the daily production reports (DPR) to 2 weeks to 3 months for the allocation figures. Frequently, subtle changes in the file formats are not detected by the system, forcing the production engineers to invest time modifying the file to a recognizable format, and thus reducing the time for the engineering analysis.
A new workflow approach overcomes the operational challenges involved in this kind of process. The workflow approach includes processes that will assist in reducing the time of data acquisition, and the additional time allowed for analysis and interpretation of the data will drive faster and more accurate decisions. Different strategies were used to overcome challenges, including the creation of integrated workflows aligned to existing system architectures and key performance indicators.
The workflows will help anyone currently working on the acquisition and analysis of data from a business partner or designing a solution to overcome the challenges of data acquisition and organization.
Low Salinity EOR Effects After Seawater Flooding in a High Temperature and High Salinity Offshore Sandstone Reservoir
Authors: Aghaeifar Zahra , Puntervold Tina , Strand Skule , Austad Tor , Maghsoudi Behrouz , Ferreira Jose da 
Published: April 2018

Abstract
Many offshore reservoirs have been seawater-flooded, which could affect the low salinity EOR potential. This paper evaluates the low salinity EOR potential after seawater flooding for a high temperature (148 °C), high salinity (~170000 ppm) sandstone reservoir. Secondary oil recovery by low salinity injection is compared to secondary seawater and tertiary low salinity water injection.
Oil recovery experiments were performed at reservoir temperature using preserved reservoir cores. To mimic initial wetting conditions of the original oil reservoir, the cores were mildly cleaned and restored with the formation water and reservoir crude oil. Secondary seawater injection was performed, as well as secondary and tertiary low salinity water injection. Solid-brine surface reactivity tests were performed to evaluate chemical interactions, initial wetting, and potential for wettability alteration in the reservoir system.
The pH of the first produced water in the oil recovery tests indicated favorable initial wetting conditions, i.e. mixed wettability, which is necessary for obtaining low salinity EOR effects by wettability alteration. However, the oil recovery tests showed no tertiary low salinity EOR effects after seawater flooding. Secondary low salinity injection resulted in 6-10% higher oil recovery compared to that obtained by secondary seawater injection. Low salinity injection normally generates cation exchange on the pore mineral surface promoting a pH increase and good conditions for observing wettability alteration. The produced water sample pH show that unfavorable Crude Oil-Brine-Rock interactions reduced the pH increment and the low salinity EOR potential after seawater injection. The surface reactivity tests also confirmed higher EOR potential by secondary low salinity injection, seen by a higher pH increase, which during low salinity injection triggers wettability alteration of the rock surface towards more water-wet, thereby recovering more oil.
The results show that low salinity injection into a seawater-flooded reservoir is likely to be less efficient due to unfavorable chemical interactions and reduced pH increase, and therefore there is a reduced potential for wettability alteration. However, for this high temperature and high salinity reservoir secondary low salinity water injection could be an efficient EOR method.
Cement Plug Hydraulic Integrity - The Ultimate Objective of Cement Plug Integrity
Authors: Bois Axel-Pierre , Vu Manh-Huyen , Noël Kim , Badalamenti Antony , Delabroy Laurent , Thérond Emmanuel , Hansen Knut 
Published: April 2018

Abstract
In the last years, the industry has focused on ensuring that cement is efficiently placed in the wellbore and that it does not become mechanically damaged during the life of the well. However, little work has been done on how cement mechanical integrity (CMI) relates to cement hydraulic integrity (CHI), i.e., evaluating the flow rate that could take place through the cement barrier, even if CHI is one of the ultimate objectives of cement integrity.
The analysis of hydraulic integrity requires that a CMI model is used to compute the state of stress and pore pressure in the cement and to estimate which type of mechanical failure may occur during the life of the well. It also requires that a CHI model is integrated with the CMI model to estimate the rate and amount of fluid that may flow through a cement barrier, should it mechanically fail. This provides the engineer insight into the long-term integrity of the cement plug.
This paper describes the work done on CMI/CHI models for cement plugs and presents a sensitivity analysis that demonstrates the value of an integrated CMI/CHI model. The study indicates that: 1) Well geometry, cement properties, reservoirs' pressures, cement heat of hydration, and fluids' properties are required inputs for proper analysis; 2) The changes of stresses and pore pressure over time need to be computed along the length of the cement plug, with sensitivity analysis to take the existing uncertainties into account; 3) A cement plug may preserve its sealing capability, even if the CMI model shows the existence of a micro-annulus, for example, when the fluid viscosity is very high; 4) A cement plug may lose its sealing capacity, even if the CMI model shows no induced defect, for example when a micro- annulus is propagated as a hydraulic fracture.
These last two observations are of significant importance because they show that what a CMI model cannot predict, a CHI model can.
Drilling Digital Twin Success Stories the Last 10 Years
Authors: Mayani M. Gholami , Svendsen M. , Oedegaard S. I. 
Published: April 2018

Abstract
Objective of the paper is to describe and present results of using a "Digital Twin" in Drilling Operations (Planning and Engineering, Training and Operational Support) in the last 10 years for Operators worldwide. The concept of Digital Twin was first introduced by Michael Grieves at the University of Michigan in 2003 through Grieves’ Executive Course on Product Lifecycle Management.
Winning a Formula 1 race is no longer just about building the fastest car, hiring the bravest driver and praying for luck. These days, when a McLaren technology group races in Monaco or Singapore, it beams data from hundreds of sensors wired in the car to Woking, England. There, analysts study that data and use complex computer models to relay optimal race strategies back to the driver. The McLaren race crew and the online retailers both harness data and use algorithms to make reasonable projections about the future, Parris explains. The concept is called Digital Twin [1].
A Digital Twin contains information such as a piece of equipment or asset, including its physical description, instrumentation, data and history. A Digital Twin can be created for assets ranging from a well to a piece of equipment to an entire oilfield. For example, a subsea system could have a Digital Twin via a simulation model of a subsea system's components, including the blowout preventer, tiebacks, risers, manifolds, umbilical and moorings.
Drilling and extracting simulations can determine whether virtual designs can actually be built using the machines available," GE said. "Last but not least, real-time data feeds from sensors in a physical operating asset are now used to know the exact state and condition of an operating-asset product, no matter where it is in the world"[2].
An Interactive Decision Support System for Geosteering Operations
Authors: Alyaev Sergey , Bratvold Reidar Brumer , Luo Xiaodong , Suter Erich , Vefring Erlend H. 
Published: April 2018

Abstract
In this work we present a systematic geosteering workflow that automatically integrates a priori information and the real-time measurements for updating of geomodel with uncertainties, and uses the latest model predictions in a Decision Support System (DSS). The DSS supports geosteering decisions by evaluating production potential versus drilling and completion risks.
In our workflow, the uncertainty in the geological interpretation around the well is represented via multiple realizations of the geology. The realizations are updated using EnKF (Ensemble Kalman Filter) in real-time when new LWD measurements become available, providing a modified prediction of the geology ahead of the bit. For every geosteering decision, the most recent representation of the geological uncertainty is used as input for the DSS. It suggests steering correction or stopping, considering complete well trajectories ahead-of-the-bit against the always updated representation of key uncertainties. The optimized well trajectories and the uncertainties are presented to the users of the DSS via a GUI. This interface enables interactive adjustment of decision criteria and constraints, which are applied in a matter of seconds using advanced dynamic programming algorithms yielding consistently updated decision suggestions.
To illustrate the benefits of the DSS, we consider synthetic cases for which we demonstrate the model updating and the decision recommendations. The DSS is particularly advantageous for unbiased high-quality decision making when navigating in complex reservoirs with several potential targets and significant interpretation uncertainty. The initial results demonstrate statistically optimal landing and navigating of the well in such a complex reservoir. Furthermore, the capability to adjust and re-weight the objectives provides the geosteering team with the ability to change the selected trade-offs between the objectives as they drill. Under challenging conditions, model-based results as input to a decision process that is traditionally much based on human intuition and judgement is expected to yield superior decisions.
The novel DSS offers a new paradigm for geosteering where the geosteering experts control the input to the DSS by choosing decision criteria. At the same time, the DSS identifies the optimal decisions through multi-objective optimization under uncertainty. It bridges the gap between developments in formation evaluation and reservoir mapping on one side, and automation of the drilling process on the other. Hence, the approach creates value based on the existing instrumentation and technology.
A Numerical Comparison and Uncertainty Analysis of Two Transient Models for Kick Management in a Backpressure MPD System
Authors: Gomes D. , Frøyen J. , Fjelde K. K. , Bjørkevoll Knut 
Published: April 2018

Abstract
The objective is to compare two different transient models for evaluating kick management in backpressure managed pressure drilling systems and to analyse numerical uncertainties and impact on simulation results.
Two different numerical methods will be compared with respect to how accurate they describe the maximum surface rates occurring during a kick scenario with water based mud. The importance of being aware of the uncertainty in results due to numerical diffusion is demonstrated. In addition, different techniques for reducing the numerical diffusion will be discussed and the impact on the predicted rates will be demonstrated. This will include a study of grid refinement and application of front tracking or slope limiter techniques. In addition, a comparison of a kick in oil based mud vs. water based mud in a HPHT MPD scenario will also be shown to highlight the main difference between these systems.
A backpressure managed pressure drilling system makes it possible to manage small pressure margins since bottomhole pressure can be controlled by choke pressure adjustments. However, when operating close to pore pressure, small kicks can be taken. These influxes can be circulated to surface if the surface equipment can handle the pressure and the mud gas separator have sufficient capacity. How large kicks one can handle is a decision that can be supported by transient simulations. Here it will be demonstrated that it is important to be aware of and reduce the numerical diffusion to improve prediction of the maximum rates that will occur. It will be shown that by increasing number of boxes in the discretization and introducing methods for reducing numerical diffusion, a more accurate prediction of the maximum rates occurring can be obtained.
The main contribution of this work will be to make engineers aware of that there can be uncertainties involved in the simulation tools they are using and to share knowledge about how one can reduce those uncertainties.