bluuebunny/crossref_metadata_2025_split huggingface dataset:
Bridging Operational Information with Real-Time Data: Enhancing Real-Time Monitoring Engineer‘s Situational Awareness
Authors: Borjas Ricardo , Hamzah Mohammad Khairi 
Published: June 2014

Abstract
In recent years, oilfield companies have realized the value of real-time data and have set up real-time centers to monitor multiple wells in a given area remotely. With the advancement of rig communications, several wells can be streamed to these real-time centers where they are monitored by real-time engineers.
In addition to the data streamed from both surface and downhole sensors to real-time centers, operational information is communicated electronically via emails, daily reports, and meetings; this information must be manually entered or interpreted by real-time engineers. We have observed that this takes precious time away from the real-time engineers’ core function of monitoring.
However, as real-time centers mature, there must be a focus on merging operational information with real-time streaming data to reduce communication lag time and raise the real-time engineer’s situational awareness at all times. Coupling business systems with real-time monitoring software will have an immediate impact on the entire process, reducing communication time and instantaneously syncing the real-time center with rig operations.
A first step towards this goal is to provide the real-time monitoring software with the ability to pull in and merge operational data with streamed data from the wellsite. Operational data can then be viewed on demand and updated automatically as well as visualized together with the streamed data through predefined dashboards. Up-to-date operations information changes will be synchronized to the real-time monitoring systems and brought to the attention of the real-time engineers.
As a result of the implementation, a step change has been observed in the situational awareness of real-time engineers, improving their interpretation of the current situation and their influence on operational changes. Finally, there remains a need to move towards digital information exchange between these systems in both directions to provide a more collaborative environment.
Delivering Real-Time 220,000-Channel 3D Seismic Experience for the First Time in Kuwait
Authors: Joseph Binu Thomas 
Published: June 2014

Abstract
The need to create a real-time experience was crucial to remotely show a seismic acquisition system at the recorder, located 35 km away from an event venue built in the desert. This was achieved through live audiovisual communication for 200 participants. Major challenges faced were: the event location was outside the scope of conventional IT support; the large number of participants; 30-day time constraint; conducting a feasibility study in the field; conduct a continuous test until a proposed in-house solution was functional; and otherwise integrate with an alternative third-party-produced backup solution.
The proposed solution describes how a packet-switched network and H.323 signaling protocol operating on an IP-based network was used for videoconferencing (VC) between two remote locations. The two main components of the signaling protocol were the registration admission status that controls the entire video network, used between the gatekeeper and the VC unit, and the Q.931 responsible for establishing and cancelling the connection between the VC units. The remote screen- sharing tool for broadcasting the seismic acquisition system uses the secure socket layer (SSL) for communications security. The key exchange protocol used was remote access service, while the data encryption is AES256-SHA used by means of the web browser that supports it. A follow-up with the supplier was made to double the current bandwidth to prevent a drop in the network performance.
The successful outcome of the event demonstrated how IT can contribute outside their normal scope of work by providing event design and coordination, and can succeed in helping participants make informed decisions by facilitating a real-time seismic experience that saved the business USD 30K.
This paper depicts the high value of IT by delivering business solutions.
Upstream Workflow Transformation in a Mature Joint Venture Asset:- Design, Implementation and Adoption for Value Creation
Authors: Adeyemi O. S. 
Published: June 2014

Abstract
Production optimization from mature assets with limited well instrumentation, aging facilities and depleting reservoir energy is a big challenge. The economic viability of retrofitting these assets to enable - instrumentation for seamless data capture, remote transmission, storage and integration with engineering applications is sometimes challenged.
A methodology and practical approach for designing and implementing integrated field (i-field)in a mature joint venture asset in Chevron Nigeria is presented in this paper. The various fields span several kilometers cutting across different terrain including land, swamp and shallow offshore locations with maximum water depth of 150 ft. The first well spudded in December 1963 came on production in March 1965 and still producing 48 years later (in 2013). There are more than thirty fields currently producing across over 2.2 MM acres. The extent of the geographical spread not only comes with different terrains but also presents complexity with design and application of i-field within Chevron Nigeria Limited (CNL).
The identification, prioritization and deployment of petro-technical transformational workflows were discussed. The implementation of a robust IT architectural foundation is pivotal to the adoption of existing and emerging solutions. The methodology for ranking the assets was largely based on current production and remaining reserves, existing downhole or wellhead instrumentation, availability of SCADA network and ease of implementation through a proof of concept (POC). Using a phased approach, multiple components of the i-fieldprogram were implemented. The first wave of solutions recorded a value of $2.5 MM in 2012 from better collaboration, production optimization, and management by exception. In addition, significant savings resulting from improved productivity, safety and operation excellence was attained in several assets/fields that are more than 40 years old. The overall impacts of these deployments have resulted in early gains resulting from reduction in OPEX and loss production opportunity (LPO) and improved reliability.
Some of the challenges encountered include ability to retrofit existing wells and facilities especially with diminishing reserves and aging facilities. Value proposition for marginal field and lack or limited infrastructure related to bandwidth for communication was a big challenge. In addition, best practices and lessons learned for development and deployment of i- fieldinitiatives in mature brown fields are presented.
Tangible Values for Running Distributed Temperature Survey (DTS) as Part of Stimulating Multi-Lateral Injection Wells
Authors: Al-Gamber S. D. , Mehmood Sajid , Aramco Saudi , Ahmed Danish , Burov Anton , Brown George , Barkat Souhaibe , Shrake Gwynne 
Published: June 2014

Abstract
Proven to maximize hydrocarbon production or well injectivity, horizontal multilateral completions have witnessed growth both in number and complexity over the years. These well types brought challenges with respect to well accessibility for rigless well intervention, and the ability to access these wells has been developed using coiled tubing (CT) to enable operations, such as reservoir stimulation, to be carried out.
One of the main challenges is to identify and access each lateral, to be able to perform the stimulation to maximize well production. This challenge has been encountered in Saudi Arabian multilateral wells, which are drilled in a carbonate reservoir with an open hole (OH) completion and where the laterals are typically left with a high formation damage (skin effect) after drilling, thus requiring stimulation to improve their performance.
At present there is no single technique for lateral identification without tagging TD. In this paper we describe how a combination of multilateral tool (MLT) along with CT downhole measurement system is used to locate and access laterals, selectively acquiring a gamma ray profile across each of the laterals, then optimizing the stimulation operation using distributed temperature survey (DTS) measurements.
This paper discusses the planning, execution and evaluation of the results in a stimulation job performed on an open hole multilateral water injector employing a CT with fiber optics that enables a real-time downhole measurement tool (pressure, temperature, casing collar locator, gamma ray) and MLT. The results highlight the effectiveness of the technique in maximizing the wells performance.
The Art of Intelligent Energy (iE) Part 2 - Insights and Lessons Learned from the application of iE between 2009 and 2012.
Authors: Edwards A. R. , Helm P.. , Dhubaib T.. 
Published: June 2014

Abstract:
Intelligent Energy (iE) has been a major performance improvement initiative within many oil and gas companies for much of the last decade. It is therefore surprising to find that, although many companies have been successful, many continue to find it difficult to scale and sustain the change in the new way of working enabled by iE. This paper builds on the original paper presented at the Intelligent Energy 2010 conference and draws on the authors’ most recent experience of the practical implementation of iE in major oil and gas companies both international and national.
This paper gives insights and lessons learned into the skilled practice of the application of iE drawn from experiences major oil and gas companies. It will explore such topics as: Scope of iE implementationHow do you scale iE?How do you sustain iE?Big bang versus evolutionary approachContracting strategies for iELeadership and management of changeScaling of iE across an organisationThe role of a central programme officeWhat is next for iE?
It will also draw attention to some of the numerous pitfalls to be encountered along the way. It will finish by highlighting some of the new challenges and opportunities in iE.
First Openhole Hydraulic Fracturing Treatment Using Diverter Technology in India
Authors: Adil Faraaz , Pande Karan , Raina Bhavna 
Published: June 2014

Abstract
This paper discusses the hydraulic fracturing (HF) treatment of a tight gas well owned by a major power service company in India. The objective was to perform a HF treatment on the openhole (OH) section to assess the reservoir potential for future development work. The success of this treatment could unlock the oil and gas reserves in this area of the country, which are estimated to be massive.
The fracturing treatment of the tight gas reservoir was to be performed under these conditions for the first time in the area, so there was no previous information to help design the treatment nor predict the result. Injectivity and mini-frac tests were performed to analyze the reservoir properties before designing the final fracturing design and execution.
One of the major challenges was to perform the fracturing treatment on an OH section under extremely strenuous operational deadlines, which eliminated the options of using any more suitable well completion methods. Thus, it was proposed to use a diverting agent in the fracturing treatment design to help maximize the stimulated reservoir volume (SRV) in the OH section. The objective was to create at least two to three multiple independent fractures in the OH section. The challenge was to manage the injection rates and deliver the diverter accurately to the bottomhole to create a bridge at the open fracture, isolate it, and initiate a new fracture. This paper discusses this process, and the the lessons learned during the treatment execution.
In addition to the description above, the following issues had to be addressed before progressing to the primary fracturing treatment: heavy mud was in the wellbore and OH section, this was a low-permeability reservoir, operator's Christmas tree pressure rating was low, this was a deep well with a long OH interval, there was an extremely short operational execution deadline, and this well's close proximity to an adjacent well, leading to possible communication between the wells.
This paper discusses the fracturing analyses performed to design the fracturing treatment, the ideologies used for performing the successful fracturing treatment using diverter technology, and the results achieved using this technique.
Horizontal Well Development in Unconventional Resource Play Using an Integrated Completion and Production Workflow: Delaware Basin Case Study
Authors: Sharma Anoop , Yates Malcolm E. , Pope Tim , Fisher Kelvin , Brown Randy , Honeyman Les , Bates Bradley 
Published: June 2014

Abstract
Horizontal wells give a great opportunity for maximizing the potential of unconventional resource play developments by providing enhanced reservoir contact but present multiple challenges in the process due to the heterogeneous nature of the unconventional reservoir rock.
This study covers the implementation of an integrated completion and production workflow to optimize a horizontal well development project in the Delaware Basin located in Reeves County, Texas. By undertaking a vertical well pilot logging program, the acreage was evaluated for petrophysical and geomechanical properties using advanced geo-chemical and full-wave sonic tools to quantify reservoir quality (RQ) and completion quality (CQ), respectively. Detailed fracture simulations were performed at multiple depths to locate the optimum landing point that maximized reservoir contact. Incorporating the key findings of the wellbore stability analysis, the well was geo-steered using a rotary steerable system (RSS) and a logging-while drilling (LWD) resistivity tool that placed 100% of the lateral in the target zone. Further completion simulations were performed to determine a perforating and staging strategy which would optimize the number of stages. The flow-channel fracturing technique, which provides a novel approach for achieving fracture conductivity, was also implemented on the studied well to significantly improve the effectiveness of the fracture stimulation treatment. Fracture diagnostics, detailed post fracture modeling, and production analysis techniques, which utilized rate-transient analysis and history matching, were performed to provide better understanding of the effectiveness of the stimulation treatments (fracture lengths/conductivity), thereby allowing further optimization of the stimulation program.
This study has demonstrated how the implementation of an integrated design and evaluation workflow can optimize the overall well production performance as well as reduce drilling and stimulation costs in unconventional resource play developments.
Getting Back to Basics: Using Routine Drilling Mud Logging Data for Reservoir Characterization
Authors: Hayton Shaun , Tischler Gerold 
Published: June 2014

Abstract
Reservoir characterization in unconventional reservoirs can be problematic due to the magnitude of uncertainties in the measurements being made. While significant advances continue to be made in logging tool capabilities and the integration of detailed core and petrophysical analyses, the utilization of these results on a routine basis for reservoir characterization during development using horizontal drilling is cost prohibitive. Additionally, time delays in obtaining results from core analysis make this approach inappropriate for operational situations.
Detailed reservoir characterization in horizontal wells to design targeted hydraulic fracture stimulation is a fundamental aspect of Saudi Aramco's forward plan for developing unconventional shale and tight gas sand reservoirs. A method by which detailed reservoir characterization can be undertaken in a cost-effective and timely manner is required.
This paper describes the results from the trial testing of the Geological Differential Method (GDM). The trial uses routine drilling parameters, mud gas data, lithology data and associated core calibrated petrophysical analyses from multiple (model) wells to determine routine petrophysical properties such as porosity and fluid/gas volumes in unknown (prediction) wells. This new technique is fundamentally different from existing neural networks and other statistical based systems. Rather than using input data to provide a basis for informed inference or extrapolation, GDM uses the input data as part of a predictive process. This paper summarizes the work flows and results of three separate projects involving nine lower Paleozoic exploration wells and a variety of unconventional targets (shale and tight gas sands). We describe the work flows in general and show comparisons between reservoir characteristics determined by routine petrophysical analysis and predictions using the GDM for three separate blind tests.
As with any model driven analysis, the answers are only as good as the input data. Due to uncertainty over how to petrophysically obtain the desired outputs for the shale model wells, work on the shales was halted early in the program. Subsequently, testing has successfully shown that we were able to relatively quickly (within 2-3 weeks) develop a predictive model, which could, within reason, predict basic reservoir characteristics for tight gas sands from routine drilling parameters, mud gas and lithology data. While further input data preparation is required, initial results provided significant encouragement and highlighted the potential of this technique for both real-time and post-drilling analysis.
Application of Integrated PTA and PDA Approach in a Tight Gas Reservoir in China
Authors: Tongyi Zhang , Wei Pang , Juan Du , Jun Mao , Ying He , Qiong Wu , Xiaoxu Feng , Panglu Jiang , Dejia Di 
Published: June 2014

Abstract
It is quite common for production/injection wells to install permanent or temporary downhole pressure gauges. When the well is shut in, the pressure gauge will record the falloff/buildup (BU) transient data lasting from hours to several days with high frequency. The pressure transient analysis (PTA) can be carried out using the recorded data. When the well is producing, surface pressure and rate will be recorded daily or monthly based on which production data analysis (PDA) can be performed. For a fractured tight gas well, we may get accurate permeability from PTA if a radial flow is reached; however, seldom is the case that we can obtain boundary information from PTA because the permeability is too low. On the contrary, we may easily get boundary and volume from PDA if the well is producing long enough, but sometimes it's hard to get permeability estimation. If we can integrate PTA and PDA together, we may get both permeability and boundary, and increase the interpretation's confidence by letting PTA and PDA result consistent with each other.
This study illustrates one fractured vertical well in a typical tight gas reservoir in China. The well contained one pre-fracture buildup test and annual pressure buildup tests in 6 subsequent years. From the pre-fracture buildup test, we get the accurate permeability with value of 0.086md; the annual buildup tests showed continuous changes in the fracture morphology with fracture conductivity decreasing from 3000 to 300 md.ft and fracture half-length increasing from 226m to 322m.
Such successive Buildups recordings are rare and the observed changes in fracture conductivity and length over time were unanticipated. It reveals that variation of fracture half-length and conductivity may be a typical factor we should consider in pressure transient analysis. The PDA shows the difficulties in determining formation and fracture parameters when the transient response lacks radial flow.
Water Dumping Improved Recovery for Bounded Thin Oil Reservoir of East China Offshore
Authors: Zhang Guohua , Li Yangfan , Xu Fa , Jia Jianyi 
Published: June 2014

Abstract
Bounded thin oil reservoir, which is characterized by less reserves, thin thickness, and weak energy of edge or bottom water, could hardly be developed with high cost, low recovery and high risk. Bajiaoting oil field, which is located in East China Offshore, has all the characteristics of bounded thin oil reservoir, what's more, it has low permeability: less than 10mD. As a result, it could not be developed without water injection wells, but water injection cases could not be taken in East China Offshore due to the restrictions of the producing platform. Face all the difficulties, Water Dumping, which could maintain pressure and improve recovery with low cost, was applied in Bajiaoting oil field, and it is the first time that this technology applied in China offshore. Traditionally, water injection wells are located in the edge of the reservoirs and oil wells are located in the centre area. By contrary, new case was put forward: transform the oil well which located in the center into water dumping well in the appropriate time. Therefore, dumping water could spread from edge to the center, and then, to the other edge. In this study, related calculation methods for pressure and injection rate are applied, and the effects and simulation results of some adjustment cases are discussed.
Improved Underbalanced Operations with Uncertainty Analysis
Authors: Udegbunam John Emeka , Lohne Hans Petter , Fjelde Kjell Kåre , Arild Øystein , Ford Eric 
Published: June 2014

Abstract
Underbalanced operations (UBO) involve handling of a highly dynamic system. Therefore, the use of flow models in the well planning, training, and subsequent operations is indispensable. These model predictions, however, are subject to uncertainties, due to input errors or imperfect modeling algorithms or both.
In the preceding work, the effects of uncertainties related to gas-slip parameters and frictional pressure loss on annular pressure during underbalanced drilling have been discussed. The work demonstrates the advantages the proposed stochastic flow model has over the deterministic formulations currently used in the industry.
The present work specifically focuses on how to include uncertainties associated with reservoir inflow performance and choke operability. Monte Carlo simulation is used as a means to propagate these uncertainties. Because reservoir influx is expected during UBO, understanding the impact this will have on annular pressure will be very beneficial when selecting the optimal operational conditions.
The stochastic modeling of UBO has demonstrated its potential as a future tool for managing the associated risks and uncertainties. Improving the planning process with the uncertainty approach can make the application of the drilling technique more attractive to oil and gas operators.