bluuebunny/crossref_metadata_2025_split huggingface dataset:
Refrac Screening Processes in Unconventional Reservoirs, A Geomechanics Perspective
Authors: Wang Yarlong , Dusseault Maurice 
Published: March 2019

Abstract
Refracturing is often required in shale and tight gas formations because of inadequate initial HF design or unexpectedly rapid production decline. Water blocking because of fracturing liquid incompatibility, unexpected proppant embedment and crushing, shorter or curved primary fracture length because of premature screen off, general pressure depletion, primary fracture mis-orientation from stress shadowing, unfavourable poroelastic effects limiting the performance of the stimulated volume, and, in general, formation permeability reduction from stress sensitivity may all contribute to unsatisfactory or rapidly declining production. We emphasize the role of geomechanics in candidate screening and review the major factors leading to production decline in unconventional reservoirs. Although the fracture geometry may be altered in a staged fracturing process, the primary focus should be given to the formation permeability enhancement either due to shear dilation or induced fractured network elongation.
Enhanced Hydraulic Modeling and Event Detection Using Real-Time Fluid Properties and Fluid Position Tracking Software
Authors: Porter Aidan , Lie Vivek , Gollapalli Joshua 
Published: March 2019

Abstract
Replicating downhole conditions using real-time software helps reduce nonproductive time. Hydraulic outputs trend against sensor outputs, enabling event detection. Using real-time fluid properties with fluid tracking hydraulic software helps improve predictions for comparison, enabling faster and more reliable detection of downhole conditions.
Two instances of real-time hydraulics simulators capable of tracking property changes of fluid and the positions of discrete fluid volumes within the wellbore were used. One simulator was used with a real-time fluid properties apparatus that provided full six-speed rheology and fluid density in real time. The second simulator used fluid updates provided by the mud engineer on location. The calculated equivalent circulating density (ECD) and predicted standpipe pressure (SPP) from the hydraulics software was compared to actual pressure while drilling (PWD) and measured SPP sensor outputs.
The real-time fluid apparatus provided real-time rheology and density values consistently while drilling the section, and data was provided directly to the hydraulics simulator. Comparing ECD predictions with and without the real-time fluid properties made it possible to identify any improvements achieved using such equipment. Although both sets of data showed that the hydraulics simulator was highly accurate, using real-time fluid inputs enabled ECD predictions to trend considerably closer to the PWD measurements. The capability of tracking the predicted ECD against actual sensor outputs enables users to quickly determine deviations in sensor outputs associated with downhole conditions and to observe deviations occurring as a result of inconsistencies within the fluid system.
Data presented in this paper are taken from some of the first global deployments of real-time fluid properties measurement equipment used in conjunction with real-time hydraulics software.
Is Steamflooding a Form of Low Salinity Waterflooding?
Authors: Al-Saedi Hasan N. , Al-Bazzaz Waleed , Flori Ralph E. 
Published: March 2019

Abstract
Previously, Al-Saedi and Flori et al. 2018d proposed a novel steam-low salinity EOR technique called low salinity-alternating-steam flooding (LSASF) into a reservoir core with a high reservoir temperature. Naturally, if a reservoir's temperature is very low, then oil is heavy. Using thermal EOR techniques in such a low-temperature reservoir resulted in considerable heat loss. In this study, we investigate the steam lifespan from the injector to the producer in order to check if the injected steam is still active throughout the flooding process or if it will condense because of the heat loss. The Bartlesville Sandstone Reservoir, as with other heavy oil reservoirs, is a low temperature (23°C) shallow reservoir containing heavy oil (600 cP). We believe that steam injected into various cores from the Bartlesville Sandstone Reservoir will condense due to the low reservoir temperature. The question is whether or not this condensed steam behave similarly to low salinity (LS) waterflooding.
First, the steam was injected into the oil-free core to determice when the steam condensed and what temperature it condensed at by using a multi-port model to check if the injected steam turned into water.
Several Bartlesville Sandstone Reservoir cores were initially flooded with formation water (FW), and then were flooded with different scenarios of steam and LS water. The temperatures of the inlet, the core, and the outlet were recorded. The effluent was collected from different ports out of the cores and different producer positions in order to follow up the steam position inside the core.
Core contact angle measurements were conducted throughout the flooded cores to determine the wettability alteration between steam and condensed steam (LS water) with the rock.
This study shows that when steam turned into LS water, the sandstone core wettability was altered towards being more water-wet. The condensed steam is considered to be hot LS water, which can reduce oil viscosity and alter the wettability at the same time.
These results were for short length cores. If these results are upscaled up to the oil reservoir scale, then the steam will still be turned into LS cold water (LSCW) as will be illustrated in the analytical model (We are still working on the analytical model). The LSCW will work as a wettability modifier only without reducing the oil viscosity. LSCW is not favorable for use in heavy oil reservoirs because the sweep efficiency is very low due to density differences unless the LS water chemistry is manipulated; however, contact angle measurements showed that the LSCW altered the sandstone wettability towards the neutral wet condition.
Development of an Integrated Monitoring Tool for Oil Field Activities
Authors: Mackenzie G. , Oz O. , Bush E. , Rahimi H. , Janahi M. , Asadalla A. 
Published: March 2019

Abstract
One of the critical processes in managing oil field development is to effectively manage the Annual Work Program and Budget ("AWPB"), a program that contains a company's planned projects, costs, and oil recovery projections, and to execute this AWPB to meet company objectives and goals. Although creating an AWPB in an oil company is a challenge in and of itself, executing the plan with effective control represents a bigger challenge that is the key to achieving success in such a dynamic environment.
To address this challenge with an effective tool, "Tatweer Pulse" was developed as a strategic dashboard that brings the pulse of the field to the decision makers’ fingertips. Tatweer Pulse is a system that monitors the AWPB performance in terms of initiating and tracking field activities, communicating information between stakeholders for effective decision making at any given point, promoting consistency across the organization, improving employee efficiency, and enabling executive management to implement real time planning and change of strategy if needed.
We have successfully completed and tested the pilot phase of Tatweer Pulse, and are currently defining the scope and setting targets for the second phase.
Using Real-Time Data and Integrated Models to Diagnose Scale Problems and Improve Pump Performance
Authors: Al-shammari Baraa Sayyar , Rane Nitin , Ali Shareefa Mulla , Sultan Aala Ahmad , Al Sabea Salem Hamad , Al-naqi Meqdad , Pandey Mukul , Solaeche Fernando Ledesma 
Published: March 2019

Abstract
The Kuwait Integrated Digital Field project for Gathering-Center 01 (KwIDF GC-01) at Burgan Field acquires real-time data from wells and processing facilities as input for its production-surveillance program. Live data from the field is fed into an integrated production model for analyzing and optimizing pump performance. An automated workflow process generates alarms for critical well and facility parameters to identify wells with potential scaling issues. KwIDF workflows are integrated with updated well models to visualize the effect of scale build up on the wellhead performance and thereby assist in quantifying the associated production losses caused by scale deposition. A sensitivity analysis is also performed to identify current and optimal pump operating conditions and prioritize scale cleaning jobs.
The exception-based surveillance of key real-time parameters for wells utilizing electrical submersible pumps (ESPs) in Burgan field has significantly improved diagnostics of scale deposition at wellhead chokes and flowlines. Automated workflows calibrate an integrated production model in real-time, which enables engineers to run a quick analysis of current pump operating conditions and make a proactive plan of action. The application of real-time data and automated models has aided the operator's production team in making informed and timely decisions that enable them to run pumps at optimal operating conditions, with the result that they are able to sustain well production at target levels.
This paper describes an innovative approach to applying real-time data and integrated models in an automated workflow process for enhancing capabilities to diagnose scale deposition in the surface flow network. Examples are presented to demonstrate the application of integrated technology for identifying scaling at wellhead chokes and flowlines and prioritizing a scale removal program for optimizing pump performance.
Real-Time Pore Pressure Prediction in Depleted Reservoirs Using Regression Analysis and Artificial Neural Networks
Authors: Hadi Farqad , Eckert Andreas , Almahdawi Faleh 
Published: March 2019

Abstract
It is known that pore pressure (Pp) is an integral part for the well planning process. Pore pressure can be directly measured from the wireline pressure and well tests, or indirectly measured from seismic velocities, well logs, and shale densities. While the direct measurements are limited due to the cost and time-saving purposes, the indirect methods are often used, especially the techniques that based on the mechanical compaction of fine-grained sediments. However, the loss of porosity in carbonate reservoirs is not only controlled by the effective stresses, but also affected by a variety of depositional environments and diagenetic processes. Most of the previous models were developed to detect the overpressure zones rather than the subnormal (i.e., depleted) zones. There are also some limitations in the traditional methods, as they are based on empirical relations and constants that can differ from basins to others. This study presents a regression analysis (RA) and artificial neural networks (ANNs) capable of predicting the Pp using measurable well logs.
A field case, located in SE Iraq, has been investigated to determine the Pp from well log data. A database for five offset wells of Mishrif reservoir was subjected to the predictive methods. Two traditional methods, the Eaton and the Ratio methods, were also conducted to compare their performance with in-situ pore pressure data in carbonate reservoirs.
The current results showed that the true vertical depth, bulk density, neutron porosity, gamma ray, compressional travel time, and unconfined compressive strength are the key parameters for the Pp prediction. An empirical model with a good performance using ANNs has been developed to estimate the Pp using petrophysical well logs. Although both RA and ANNs are conservative in predicting Pp, the higher value of determination coefficient (0.96) of ANNs demonstrated that the ANN can predict the subnormal pore pressures in carbonate reservoirs. While the Eaton and the Ratio methods which are based on the drilling derived dc values showed a closer alignment with the in-situ Pp direct measurements, they are not applicable in depleted carbonate reservoirs. Other indicators of the prediction Pp should be used in conjunction with penetration rate. The validity of the proposed models was successfully checked with the data from another field study in SE Iraq. This study presents efficient and cost-effective models to estimate the formation pore pressure in depleted carbonate environments utilizing petrophysical well logs.
Coreflood Model Optimization Workflow for ASP Pilot Design Risk Analysis
Authors: Borozdina Olga , Mamaghani Magnolia , Barsalou Romain , Lantoine Martin , Pain Agnes 
Published: March 2019

Abstract
This work presents a new workflow to obtain a better-constrained reservoir-scale model for an Alkaline-Surfactant-Polymer (ASP) injection pilot design. It is explained how the impact of uncertain parameters related to ASP flooding can be quantified, using calibrated core-scale simulation based on experimental results, and how the influential parameters range for future reservoir-scale simulation can be determined. Computational costs of core-scale model are therefore much lower, and the final reservoir model is better constrained.
ASP flooding feasibility implies core scale studies, where chemical formulations are validated in the laboratory under field conditions. In the objective of the pilot designing, a numerical model is constructed and calibrated to history-match the core flood sequences: Remaining Oil Saturation (ROS), surfactant-polymer (SP) and polymer-alkaline (PA) injection and eventually the chase water slug. In order to quantify the impact of ASP chemical parameters on the history match, the Global Sensitivity Analysis (GSA) was performed using Response Surface Modeling (RSM). To obtain the acceptable range of influential parameters for future reservoir-scale simulation, the Bayesian optimization is used.
Applying this methodology on a real reservoir core, the laboratory measurements are accurately reproduced. Nevertheless, once the core-scale model was matched, the transition to reservoir-scale model must be done. Due to a large number of parameters and their associated uncertainties, this transition is not straight-forward. Thus, an additional step in our workflow is included. A new methodology is applied to firstly quantify the impact of uncertain parameters related to ASP flooding (adsorption of surfactant on the rock, critical micellar concentration, water mobility reduction by polymer etc.). To do so, the RSM is used and influential parameters are identified. In this study, the surfactant adsorption coefficients are the most influential parameters while others related to SPA have a poor impact on experiment results matching. Secondly, the acceptable range of influential parameters for future reservoir-scale simulation and feasibility study is obtained during Bayesian optimization. Thus, instead of using a wide (prior) range of uncertain parameters values, refined (posterior) distribution laws can be used for future reservoir model.
While the classical approach consists in matching experimental results to obtain calibrated values of certain properties (that are then entered in the reservoir model) and finally determine the influential parameters at the reservoir scale, here the choice was made to determine influential parameters and characterize their impacts at the core scale. This step helps to better constrain the reservoir model. Ongoing work is using the results of this workflow for pilot design and risk analysis.
Experimental Investigation of Boundary Conditions Effects on Spontaneous Imbibition in Oil-Water and Gas-Water Systems for Tight Sandstones
Authors: Cheng Zhilin , Ning Zhengfu , Wang Qing , Li Mingqi , Sui Weibo 
Published: March 2019

Abstract
As potential alternative resources, tight oil and gas reservoirs are generally exploited with multistage hydraulic fracturing technology to meet the rising demand for energy in the world. Considerable production recovered by the infiltration of fracturing fluids into the rock matrix shows that spontaneous imbibition (SI) is an effective oil recovery method. Through the use of Nuclear Magnetic Resonance (NMR) detection technique, the features of SI in oil-water and gas-water systems for tight sandstones were studied. The T2 spectra of these samples were used to reflect the migration patterns of fluids in various pores under different imbibition systems. In addition, the impacts of the boundary conditions on imbibition outcomes were also determined via the variations in T2 spectra under imbibition stages. The results indicate that tight sandstone samples display the feature of complex pore structure with a wide range of pore size distribution, and the dominant types are micropores and small mesopores. With the progression of imbibition experiments, oil in micropores will be more easily displaced by wetting fluid and flow out through interconnected smaller pores due to greater capillary pressure. The majority of the production through imbibition can be attributed to the contribution made by the micropores. However, water could not enter the mesopores readily under the gas-water system if it is only driven by capillary pressure owing to the snap-off effect of gas. The boundary conditions have notable effects on the imbibition rate and ultimate recovery for the oil-water system and increasing the areas available for water imbibition helps to maintain higher imbibition rate and recovery. However, regarding the gas-water system, boundary conditions have little influence on the imbibition recovery but have a remarkable influence on the imbibition rate. The traditional scaling equations used to scale the imbibition data for both the oil-water and gas-water systems and predict imbibition recovery is acceptable if the wettability of the tight medium remains unchanged. This research aims to uncover the imbibition characteristics of fluids and the nontrivial effect of boundary conditions in tight sandstone samples, which would contribute to the successful development of tight formations.
A New Approach to Operational Excellence for Oil and Gas
Authors: Buzzo Marco , Mazzoni Marco 
Published: March 2019

Abstract
Organizations generally run several improvement initiatives simultaneously targeting different aspects of their operations. These initiatives will improve the specific operation efficiency, but due to the fragmented approach don't necessarily lead the organization to lasting results. The overall effectiveness can be improved by an all-embracing program allowing all initiatives to align, leverage one another and succeed – approach commonly identified as Operational Excellence (OE) [1]. Even if a standard definition of OE is not specified, its concept has been developed around 2000 in the Quality circles [2] and rapidly spread as an evolution of the total quality management [3]. OE - due to its amplitude, requires a long-term sustained commitment from executives, senior leaders and employees. In the past this approach would have made little sense for most operations in the Oil and Gas industry due to their predictability and stability. In the last decade this industry has been under a continuous pressure due to a constant decline in the oil barrel price coupled with rising exploration, development and production costs, putting margins under significant pressure. Furthermore, the market push for risk reduction even when the industry is taking new challenges like drilling in ultra-deep-water or in the Arctic, intensive onshore operations in populated areas (like shale gas in the northeastern US) and pioneering technologies like floating liquefied natural gas terminals. Industry executives are working to define and deliver OE at such frontiers, where few benchmarks exist.
The need of enterprise-wide operational effectiveness and to achieve consistently better results in the Oil and Gas industry has been also seen as market evolution from the top consulting firms that offer such dedicated services. It has been estimated that a 10% production capacity is locked up in complexity and inefficiency—a valuable opportunity for improvement [4]. Despite these opportunities, OE implementation literature in Oil and Gas is marginal and experiences have been mainly reported limited to the field of health, safety and environment [5], [6], [7].
This work presents a novel approach to OE in the Oil and Gas industry, carried out at Backer Hughes, a GE Company in its Turbomachinery & Process Solutions division. This part of the organization represents a common complex case study in this industry, due its global footprint where a constellation of more than 100 manufacturing, engineering and service sites hosting more than 12000 employees. The next chapters present the assessment, selection and adoption of a standard OE model, the evaluation of current operations with respect to the model and the development of initiatives supporting it.
High-Pressure, High-Flow-Rate Stimulation Equipment for Shale Fracture Treatments
Authors: Surjaatmadja Jim B. , Logan Tom , Hunter Timothy H. , Stephenson Stanley V. , Bull Brad , Lucas Bryan 
Published: March 2019

Abstract
The success of the Americas with stimulating shale formations has drawn attention to unconventional implementations globally. While excellent production results and economic successes are well publicized, equipment performance is one of the major factors responsible for economically delivering effective as-designed stimulation treatments. Delivery efficiency is the top priority of well servicing equipment design and maintenance personnel.
Equipment redesign is occurring industry-wide, and new system offerings promise greater operational efficiencies—some have already demonstrated success and others are still being developed to identify or provide improved efficiency solutions. To accomplish this, each piece of equipment, whether a pump, a blender, a container, or even a measuring/monitoring device, is carefully evaluated. Their collaborative task is to deliver treatment material and energy from some known surface point to a specific point or zone of a wellbore within the geological formation. Every subsystem is evaluated so that each subtask is performed effectively at a reduced time and cost.
Shale development affects decisions on how to develop a geological formation for maximized economic return. Multiwell pads, increased well density, and fracture requirements are pushing equipment to their limits, including requiring pumping equipment to continuously deliver high pressure fluid with little idle time for maintenance and repair or replacement (blending equipment has similar limits). Material delivery from source to location is important; this is particularly true for proppants because a continuous supply of 3,000 to 15,000 lbm/min is typically necessary. Finally, while well spacing is being drastically reduced, the ability to treat many wells in quick succession has become necessary.
This paper discusses steps taken to improve high horsepower treatment issues, reduce nonproductive time, and achieve efficiency targets.