bluuebunny/crossref_metadata_2025_split huggingface dataset:
Data-Analytics Method Helps Engineers Optimize Well Placement Under Uncertainty
Authors: Wilson Adam 
Published: October 2018

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 188265, “Use of Data Analytics To Improve Well-Placement Optimization Under Uncertainty,” by Daniel Busby, SPE, Frédérik Pivot, and Amine Tadjer, Total, prepared for the 2017 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 13–16 November. The paper has not been peer reviewed.
Well-placement optimization is one of the more challenging problems in the oil and gas industry. Although several optimization methods have been proposed, the most-used approach remains that of manual optimization by reservoir engineers. The work flow proposed here uses a machine-learning algorithm trained on simulated data to evaluate the performance of possible well locations and configurations.
Introduction
Extensive literature has been published about well-placement optimization; authors have proposed many different approaches (e.g., advanced optimization techniques, adjoint methods, experimental design, and streamline solutions). Real field experience, however, has shown that these techniques are rarely used. In practice, expert engineers usually identify the main factors affecting a future well’s production. They consider these factors in obtaining the best well configurations. These are then evaluated with a full-field reservoir-simulation model. Uncertainty is handled in the process typically in a second phase to test the robustness of the proposed development plan by running a few alternative models corresponding to some low and high cases and, more rarely, on a full Monte Carlo set of models generated by the full prior-model uncertainty.
The reasons the different optimization methods proposed in the literature are not used in operations can vary: difficulty in handling all the operational constraints during optimization, a prohibitive number of simulation runs, relatively poor performance of the optimization methods when considering many complex production and injection wells, and the complexity of the method and its configuration. The approach proposed here is not a proper well-placement optimization method; it is more a set of data-analytics tools aimed at helping reservoir engineers to explore the extremely large domain of possible solutions and, it is hoped, to find better solutions. This paper’s objective is to provide a methodology and some guidelines that can be adapted to each specific field case. The idea is to follow the typical work flow used by reservoir engineers while adding data-analytics techniques to improve the decision-making process.
Methodology
This work presents a methodology to address the problem of field development planning mainly for greenfields, although a similar work flow can be applied to mature fields. The first step in field development planning is to perform a study to incorporate geological, seismic, and fluid data into a reservoir-simulation model.
Solvent-Based and Solvent-Assisted Recovery Processes: State of the Art
Authors: Bayestehparvin Bita , Farouq Ali S. M. , Abedi Jalal 
Published: October 2018

Summary
Steam injection is a widely used oil-recovery method that has been commercially successful in many types of heavy-oil reservoirs, including the oil sands of Alberta, Canada. Steam is very effective in delivering heat that is the key to heavy-oil mobilization. In the distant past in California, and also recently in Alberta, solvents were/are being used as additives to steam for additional viscosity reduction. The current applications are in field projects involving steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS).
The past and present projects using solvents alone or in combination with steam are reviewed and evaluated, including enhanced solvent SAGD (ES-SAGD) and liquid addition to steam for enhancing recovery (LASER). The use of solvent in other processes, such as effective solvent extraction incorporating electromagnetic heating (ESEIEH) and after cold-heavy-oil production with sand (CHOPS), are also reviewed. The theories behind the use of solvents with steam are outlined. These postulate additional heavy-oil/bitumen mobilization; oil mobilization ahead of the steam front; and oil mobilization by solvent dispersion caused by frontal instability. The plausibility of the different approaches and solvent availability and economics are also discussed.
A Mass-Conservative Sequential Implicit Multiscale Method for Isothermal Equation-of-State Compositional Problems
Authors: Møyner Olav , Tchelepi Hamdi A. 
Published: October 2018

SummaryCompositional simulation is necessary for a wide variety of reservoir-simulation applications, and it is especially valuable for accurate modeling of near-miscible gas injection for enhanced oil recovery. Because the nonlinear behavior of gas injection is sensitive to the resolution of the simulation grid used, it is important to use a fine grid to accurately resolve the compositional and saturation gradients. Compositional simulation of highly detailed reservoir models entails the use of small timesteps and large, poorly conditioned linear systems. The high computational cost of solving such systems renders field-scale simulations practically unfeasible. The coupling of the flow and transport to the phase-equilibrium calculations adds to the challenge. This is especially the case for near-miscible gas injection, in which the phase state and the phase compositions are very strong functions of space and time.We present a multiscale solver for compositional displacements with three-phase fluid flow. The thermodynamic phase behavior is described by general nonlinear cubic equations of state (EOS). The fully implicit (FI) natural-variables formulation is used as the basis to derive a sequential implicit (SI) solution strategy, whereby the pressure field is decoupled from the multicomponent transport. The SI scheme is mass conservative without the need to iterate between the pressure and transport equations during the timestep. This conservation property allows the errors caused by fixing the total-velocity field between the pressure- and transport-updating steps to be represented as a volume error. The method computes approximate pressure solutions—within a prescribed residual tolerance—that yield conservative fluxes on the computational grid of interest (fine, coarse, or intermediate). We use basis functions computed using restricted smoothing to allow for generally unstructured grids.The new method is verified against existing research and commercial compositional simulators using a simple conceptual test case and also using more-complex cases represented on both unstructured and corner-point grids with strong heterogeneity, faults, and pinched-out and eroded cells.The SI method and the implementation described here represent the first demonstrated multiscale method applicable to general compositional problems with complexity relevant for industrial-reservoir simulation.
Automatic Flare-Stack Monitoring
Authors: Janssen R.. , Sepasian N.. 
Published: October 2018

Summary
Flare stacks must be monitored continuously to ensure ignition of released gases during the plant operation. Generally, the process of flare detection refers to detecting the presence or absence of a flare. Flare monitoring adds the capability of tracking the size of the flare to this process. By setting lower and upper monitoring boundaries, an alarm can be generated if the flare becomes too small or too big. Reliable flare-stack monitoring becomes crucial to ensure that no unburned toxic or waste gas is released into the atmosphere, causing environmental issues and possible fire hazards. It also gives the operator an extra handle to optimize the production process. In this paper, we introduce an automatic flare-detection and monitoring system. Our user-friendly system is computer-vision-based, plug-and-play, and designed as a built-in part of the camera. By taking advantage of the geometrical properties of the flare as well as temporal information obtained by video analytics, we create a monitoring system that is robust to various parameters such as wind direction. To the best of our knowledge, we are the first to present an automatic flare-stack-monitoring system with flare-size tracking and automatic event signaling. Our presented system has been tested for live monitoring in the Rotterdam Botlek area, The Netherlands. The preliminary results illustrate a reliable system that is free of false alarms.
Construction of a 3D Geomechanical Model for Development of a Shale Gas Reservoir in the Sichuan Basin
Authors: Xie Jun , Qiu Kaibin , Zhong Bing , Pan Yuanwei , Shi Xuewen , Wang Lizhi 
Published: October 2018

SummaryCurrently, there is large-scale shale gas exploration and development in the Sichuan Basin, western China. Caused by high tectonic stress and presence of fracture systems at various scales in the lower Silurian Longmaxi reservoir formation, hydraulic fracturing in shale gas reservoirs in the Sichuan Basin has encountered many difficulties, such as placing sufficient proppant, poor-production performance for some wells, and ambiguity as to the factors controlling the production of reservoirs. It has been recognized that lack of geomechanical understanding of the shale gas reservoirs is a major obstacle to effectively addressing these difficulties.A 3D full-field geomechanics model was constructed for the Changning shale gas reservoir in the Sichuan Basin through integrating seismic, geological structure, log, and core data by following a newly formulated work flow. The 3D geomechanical model includes 3D anisotropic mechanical properties, 3D pore pressure, and the 3D in-situ stress field. Through leveraging measurements from an advanced sonic tool and core data, the anisotropy of the formation was captured at wellbores and propagated to 3D space guided by prestack seismic inversion data. The 3D pore-pressure prediction was conducted with seismic data, and calibrated against pressure measurements, mud-logging data, and flowback data. A discrete-fracture-network (DFN) model, which represents multiscale natural-fracture systems, was integrated into the 3D geomechanical model during stress modeling to reflect the disturbance on the in-situ stress field by the presence of the natural-fracture systems.The 3D pore-pressure model was used to calculate more-reliable estimates of gas in place in the shale gas reservoir, and the geomechanical model was used to reveal the root cause of difficulties of proppant placement in this tectonically active and unevenly fractured shale gas reservoir.The paper presents the highlights and innovations in constructing the 3D geomechanical model for the shale gas reservoir, and explains how the 3D geomechanical model is used to address technical challenges encountered during drilling and completion. Also, it demonstrates that a reliable 3D geomechanical model, with proper characterization of anisotropy, pore pressure, and natural fractures, provides a critical opportunity to improve the development in this shale gas reservoir.
A Mechanistic Model to Predict Flow Pattern Transitions in Electrical Submersible Pump under Gassy Flow Condition
Authors: Zhu Jianjun , Zhang Jiecheng , Zhu Haiwen , Zhang Hong-Quan 
Published: October 2018

AbstractGas entrainment is frequently encountered in electrical submersible pump (ESP) as an artificial lift method for oil production. When this occurs, ESP suffers from moderate to serve performance degradation depending on inlet gas volumetric fraction (GVF). The resulted pressure surging may cause vibrations and short run-life of ESPs. For better design of ESP system, a mechanistic model is needed to accurately predict its performance with gas-liquid flow. Similar to modeling multiphase pipe flow, the flow pattern identification and classification inside a rotating ESP is thus of great importance. In this paper, we propose a new mechanistic model to map flow patterns in ESP operated under gassy flow conditions. The model is validated by comparing to experimental results with good agreement.The experimental facility for testing ESP two-phase performance was designed and constructed. The main flow loop comprises a 3" stainless steel liquid flow loop and V" gas flow loop. A radial-type ESP with 14 stages assembled in series is horizontally mounted on a testing bench. Pressure ports were drilled at each stage to measure stage-by-stage pump pressure increment. The mixture of gas and liquid is separated in a horizontal separator, where excessive air is vented and liquid continues circulation. Experimental data are acquired with two types of tests (mapping and surging tests) to completely evaluate the pump behaviors at different operational conditions. The water/gas flow rates, ESP rotational speeds, intake pressure and surfactant concentrations are controlled in the experiments.For two-phase flow, ESP pressure increment suffers from more severe degradation as gas flow rate increases. With the performance curves obtained in surging or mapping tests, ESP flow patterns including dispersed bubble flow, bubbly flow, intermittent flow and segregated flow can be identified. The pattern transition boundaries are mapped. Starting from the free body diagram on a stable single bubble, the transition boundaries of dispersed bubble flow to bubbly flow and bubbly flow to intermittent flow are formulated. Based on the combined momentum equation, the transition criterion of intermittent flow to segregated flow is derived. The flow pattern map calculated from the new mechanistic model agrees well with that detected from ESP performance curves.
Evaluating Tailpipe Systems Designed to Optimize Artificial Lift Performance in Horizontal Wells
Authors: Humphreys C. R. , Vangolen B. N. , Allison A. P. , Yin D.. , Yicon C.. 
Published: October 2018

Abstract

Objectives/Scope
The performance of artificial lift systems on horizontal wells is greatly influenced by both the volume of gas produced and the tendency for gas slugging. With a sucker rod pump (SRP) system, this behaviour leads to gas interference at the pump, reducing system efficiency and equipment run life. With an electric submersible pump (ESP), gas slugs can cause cycling of the ESP, which may significantly shorten its run life. A trial project was launched to evaluate the performance of two tailpipe systems that could be applied to both forms of artificial lift to achieve the following goals:

Methods, Procedures, Process
Two tailpipe systems were tested in a number of wells using both SRPs and one ESP for lift. The systems differ in both separator design and packer location. The first uses a conventional packer-style gas separator with a reduced inner diameter (ID) tailpipe extending below the separator and past the KOP. The second uses a specialty cyclonic separator with a reduced ID tailpipe, and the packer is located at the lower end of the tailpipe.
Some of these installations are outfitted with downhole gauges (DHGs) measuring pressure and temperature at several points along the tailpipe. The DHGs recorded pressure at the tailpipe inlet, tailpipe outlet, pump intake pressure, and pump discharge pressure. This surveillance package allowed for real-time monitoring of the performance of both the tailpipe and the artificial lift system, while also providing data for modelling the flow regime through the tailpipe. The modelling results were used to forecast long-term performance of the system as the well production declines over time.

Results, Observations, Conclusions
Results from the field trial show the performance of each system from a variety of standpoints: changes in flowing bottomhole pressure, flowing behaviour through the tailpipe, separation effectiveness, and changes in production. Challenges were noted, and potential solutions or courses of investigation are proposed. Conclusions were drawn regarding the overall effectiveness of the concept, as well as the relative effectiveness of the two systems.

Novel/Additive Information
We examined the differences between two tailpipe systems regarding the isolation location, whether at the top or bottom of the tailpipe, to aid us in designing future systems. A comparison of the two separators was attempted, and various operational challenges are discussed so as to improve the design, installation, startup, and operation of these systems.
Unconventional Lift for Unconventional Wells
Authors: Bill Jackson W. J. 
Published: October 2018

Abstract
At some point during production, all wells experience a drop-in reservoir pressure that hinders production. This requires an artificial lift system to reduce the hydrostatic pressure on the formation, in order to encourage more production to the surface. Selecting the proper artificial lift method is critical to the performance and profitability of today's unconventional wells. This presentation will examine the range of artificial lift solutions available for horizontal and multi-stage wells and discuss the advantages of hydraulic jet pumps versus rod pumps, electronic submersible pumps, and gas lift systems. A review of typical producing Permian Basin, Eagle Ford, and East Texas sites will show the efficiency, versatility and reliability of hydraulic jet pumps can provide unmatched advantages when addressing the artificial lift challenges presented by unconventional, horizontal, multi-stage wells.
Cultural Change in ALS Real Time Operation and Optimization in Vaca Muerta Through CWE
Authors: Claramunt J. I. , Bizzotto P. E. , Sapag F.. , Ferrigno E.. , Barros J. L. , Martinez G.. 
Published: October 2018

Abstract
The present work summarizes the experiences and lessons learned around the deployment of the first Collaborative Work Environment (CWE) at the Loma Campana field, producer of the Unconventional formation Vaca Muerta in YPF SA, Argentina.
In the context of the development of the first Unconventional field in Argentina, it was decided to telesupervise and automate all the facilities and wells. It was decided to create a centralized decision support centre (DSC) to manage the entire field operation, and to optimize the production in real time.
Despite the technological capabilities of the telesupervision tools, there was an opportunity to improve online diagnosis and the process of decision-making for well optimization based on real-time information and data from the field.
This opportunity was the starter for the creation of the first CWE in YPF Upstrem operations, to unify and coordinate online actions detected between production supervisros, DSC Supervisors, production and reservoir engineers.
Effective Approach to Wellbore Clean Out Operation: A Case Study from Zawtika Phase 1B
Authors: Choodesh Attawit , Rutland Marvin Gary , Graham Grant Colin William 
Published: October 2018

Abstract
Free sand movement and fines mobilization during production in Zawtika field is one of the main challenges and can result in failures of production systems leading to SSHE exposure, loss of production or even well suspended. The optimum completion design Cased Hole Gravel Pack (CHGP) allows the well to maintain solid-free gas production with (limiting skin) selectivity, longevity and integrity throughout the life cycle.
The Sand Control completion deployment, effectiveness and well productivity is directly related to the cleanliness of cased well bore and completion brine. The Total Solid Suspension (TSS) and Nephelometric Turbidity Units (NTU) or clarity of the fluid is the key indicator of well cleanliness. Zawtika Phase 1A post job review highlighted that Wellbore Cleanout (WBCO) is one of the most time consuming operation. To overcome this challenge and create areas of opportunities for improvement based on efficiencies, several possible solutions identified below.
Excessive pipe dope, metal debris and rust from casing can collect within the well bore, bridge in perforation tunnels and ultimately damage reservoir or seriously hinder running completion components. The correct combination of Pipe Dope applying procedure, Chemical Displacement, Mechanical Movement and Hydraulic Displacement are the main key contributing factors to improved operation safety, deployment operational efficiency. Lab scale test conducted to simulate test for pipe dope removal chemical, Mechanical Casing Scraper and casing brush simulate testing in order to remove casing vanishing coating, also applying wellbore cleaning concept from drilling - rotational, pump rate and trip speed
Recovery of metal or other debris in a limited number of runs gives several advantages: - Minimize reservoir damage - Reduces risks of screen plugging - Saves rig time. This paper will describe planning process, pipe dope procedure, wellbore clean out chemical / mechanical tool selection based on laboratory testing, displacement techniques, and operation summary. The potential cost saving to project can be more than 5 Million USD. The combination of this improvement in WBCO operation is able to reduce the operation time and cost in Phase 1B more than 71% comparing to Phase 1A performances in 2014-2015
Successful UBD Application through the Full Operation Cycle of the Production Section on an Exploration Gas Well in Thailand: A Case History
Authors: Wang Ping 
Published: October 2018

Abstract
Major challenges faced by today's industry in drilling fractured carbonate reservoirs are formation damage and potential drilling problems such as fluid loss and differential sticking. To drill such formations, underbalanced drilling (UBD) technology has been used as it can intentionally keep the bottomhole pressure (BHP) lower than the pore pressure (PP), which will eliminate the near-wellbore damage, and mitigate drilling problems like fluid losses. This technology was also used onshore in Thailand, mostly for development wells with low-pressure reservoirs. Well-A, located in the fractured carbonate Pha Nok Khao (PNK) formation of northeast Thailand is an exploration well with expected reservoir pressure around 6,000 psi (13 ppg in equivalent density), whose operator was determined to utilize UBD for the production section in order to minimize formation damage and maximize and test productivity.
The higher reservoir pressure leads to higher operational risks for UBD. While drilling, single-phase water based mud (WBM) was used to keep proper drawdown for this section. In order to have safe and efficient tripping operations, tandem downhole deployment valves (DDV) were utilized to provide ultra-reliable isolation of the wellbore for all the trips during drilling, logging and completion, which eliminated the need to snub or kill the well—any of which would lead to potential formation damage and safety issues. After completion, isochronal well testing was conducted using the same UBD package and later, in order to obtain more data to determine whether the operator could commercially develop the field. After that, a long-term well-test operation was conducted by continuously flaring the well at variable rates for 15 days using the same package.
As the well was in an underbalanced condition through all the operation phases, no formation damage, fluid losses and NPT happened during the whole operation. The use of same UBD package from drilling till well testing for the full operation cycle also minimized costs and rig time.
This paper details the UBD approaches used to minimize formation damage and evaluate reservoir productivity for the Well-A in the PNK formation of northeast Thailand.