bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Novel Technique to Utilise Surface Data for Transient Analysis in Wet Gas Producers
Authors: Al-Kharaz H. , Farooqui M. Z. , Ansari A. M. , Thakur Kapil 
Published: March 2015

Abstract
Petroleum engineers rely on periodic acquisition of bottom-hole data to monitor changes in well and reservoir inflow characteristics, and to quantify well and reservoir parameters using Pressure Transient Analysis (PTA). However, the acquisition of this data, especially in an offshore high pressure and sour gas environment, presents many logistical challenges and operational risks, and can negatively affect expenditure and downtime performance. On the other hand, surface data is routinely available, sometimes with sufficient frequency and precision to carry out PTA. Surface data is affected by wellbore transients that must be taken into consideration for converting the surface data to bottom hole conditions with the accuracy required for proper analysis.
This paper describes a novel technique to properly account for wellbore transient effects and convert surface data to downhole conditions to enable conventional PTA without the need for well intervention.
The technique combines the transient wellbore modelling with a novel approach of defining coefficients in a modified bottom hole pressure equation which is described in the paper. Coefficients are calibrated using concurrent surface and downhole data sets and then utilised to convert future surface data to downhole conditions.
The paper describes the findings and conclusions from a five-well pilot, which involved wells with a range of reservoir characteristics, single and multi-layer production, and with/without cross-flow. The pilot work compared PTA results utilising this technique and surface data with results generated using downhole data.

Introduction
RasGas and SPT Group (Schlumberger) have conducted a joint evaluation of transient modelling capabilities to accurately predict bottom hole pressure using wellhead pressure data as an input for offshore gas producers. The primary objective of the trial was to enable conventional transient well test analysis using the surface data converted to downhole conditions. This would reduce the need for recording downhole pressure buildup data to obtain wellbore skin and kh during routine production logging operations and hence reduce the operational risk associated with well intervention. The technique will also enable more frequent acquisition of pressure buildup data whenever the well is shut-in for any reason since the wellhead operating parameters are continuously recorded by the Real Time Information System (RTIS) on all RasGas wells.
Barzan Completions Success Through Innovative Stimulation and Testing Technologies
Authors: Clancey Byron , Aly Maher , Bugti Mehboob , Shuchart Chris , Sau Rajes , Grubert Marcel , Farah Ali 
Published: March 2015

Abstract
The North Field Barzan Development was executed with focus on identifying and implementing effective completion solutions that addressed new technical challenges and operational constraints presented by the wells of this project. The primary challenges were in areas of matrix stimulation, spent acid clean-up, and production testing. Stimulation issues included implementing designs for a wide range of permeability contrasts, addressing stimulation vessel pump rate and acid capacity limitations, managing live acid corrosion due to sour environment, and assessing effectiveness without production logs. Spent acid clean-up operations required protecting downhole safety valves and achieving fluids composition criteria required for production into carbon steel pipelines. Production testing challenges included fluids modelling and equipment solutions that decreased Safety, Health and Environment (SHE) risk and operational complexity, while allowing accurate measurement of gas and liquids flow rates and obtaining required fluid samples.
The solutions included improvements to the acid stimulation system chemical diverter and corrosion inhibition package, custom design and manufacture of a subsurface safety valve protection sleeve, adoption of well clean-up criteria tailored to pipeline and facilities requirements, evaluation of multi-phase flow meter and real time fluids analysis technologies, and development of a simplified multi-phase flow rate calculation algorithm based on choke manifold and fluids composition data.
Implementation of differentiating technologies enabled cost savings and SHE benefits due to reduced flaring, execution of single stage stimulations, smaller test equipment layout, and innovative flow rate calculation techniques. Stimulation designs were demonstrated as successful based on interpreted changes in zonal flow contributions derived from minimum surface fluid compositional data. Wells were completed and ready for handover, meeting all requirements for the surface production facilities.

Introduction
Demand for energy in Qatar will grow over the next decade as major initiatives are completed in the transport, health and education sectors, and as new facilities are built for the FIFA World Cup in 2022. The Barzan Development is planned to meet the increased gas demand and is one of the most significant projects undertaken by the State of Qatar.
Several offshore development wells were drilled and completed with a design life of at least 25 years and capacity to produce in excess of 1.0 billion standard cubic feet per day to supply two gas treatment trains. The wells are located on three unmanned wellhead platforms in the North Field, about 80 kilometres offshore Qatar (Figure 1), and are completed in Khuff Zones 1–3 carbonate reservoirs. One well at each platform is designated a 'data well' and was extensively tested to evaluate reservoir and fluids properties.
Multi-agent Collaborative Decision Making for Upstream Asset Management
Authors: Xu Peng , Subrahmanya Niranjan , El-Bakry Amr , Reynolds Carmon 
Published: March 2015

Extended Abstract
Upstream assets are very challenging to manage because the components and processes involved are numerous, dynamic, and interdependent. Managing such assets requires execution of multiple technical tasks such as analyzing data, forecasting behavior and optimizing performance. While software tools are available to help engineers perform individual tasks, the goal of integrating cross-functional asset management tasks to achieve a greater level of automation, or even autonomy, remains elusive. As a result, most technical tasks are run and monitored by engineers; and interdependent tasks and cross-functional workflows are integrated through high-level human interaction.
Many of these tasks and the integration can be and should be conducted automatically with computer programs so that humans can focus on more challenging tasks. To achieve this goal, we study how to develop computer systems that can model complex assets and can autonomously execute asset management tasks.
Before we describe how the autonomous systems work, let us first describe how humans conduct asset management tasks from the decision making prospective. A typical first step is to obtain essential data and convert data and low level information into high level information such as trends and patterns. The second step is to reason upon the high-level information. The reasoning outcomes (e.g., equipment condition, reservoir behavior) provide solid information for decision making. The third step is to evaluate multiple decision options, determine which one will lead to the asset management goal and also satisfy various constraints. Based on these and potentially other metrics, one decision option is selected. The last step is action, through which the selected option is executed.
Note that the aforementioned steps are for one decision making process. There are numerous decision making processes for asset management. While some of the processes run independently, many of them are interdependent. For example, the outcome of one process may be fed into another process. It is through the interaction of these processes, numerous physical entities, software programs, workflows, and operators are integrated to accomplish asset management.
To achieve the lofty goal of an autonomous asset management system, multiple modeling and design steps are needed. One is to model the asset management problem. More specifically, we need to decouple the complex workflows into simpler ones that can be managed by computer entities as decision making processes. The second one is to develop each computer entity to conduct individual decision making tasks. And finally we need to develop an interaction mechanism between those computer entities in such a way to achieve asset management objectives. There are core technical challenges to achieve this vision. In this paper we attempt to address one such challenge by investigating existing interaction mechanisms from multi-agent system technology.
Successful Implementation of Real Time Down-Hole Pressure-Temperature monitoring using Fiber Optic Technology in Deep HT-HP Well in North Kuwait
Authors: Kabir Mir Rezaul , AIi AfzaI , Pradhan S.  P. , Dashti Qasem , AI-Jasmi A. K. , Abid Ridha 
Published: March 2015

Abstract:
The scope of the pilot project was to test fiber optic sensor technology in deep High Temperature (HT-HP) reservoirs and evaluate the best available sensors in the market for real time monitoring of down-hole pressure and temperature (P-T) in such an adverse environment. The task team had selected the optical P-T sensors conveyed on fiber optic cable from a qualified vendor after a thorough evaluation, considering the harsh environment of these reservoirs. After selecting the vendor, the fiber optic system was custom designed and installed down-hole in a selected deep HT-HP well in the Raudhatain field of North Kuwait. The system was installed and commissioned in mid February 2011 and has been successfully working to date, providing real-time pressure and temperature data from the reservoir section.
In this project the P-T signals captured by the optical down-hole sensors are transmitted through the fiber optic cable to the Reservoir Monitoring System (RMS) unit at the surface that is connected to the SCADA system. The SCADA system sends the data through Wi-Max to the Digital Data Gathering Centre in the Field Development Gas (FDG) office. The sensors are continuously providing reservoir data at a time interval as frequent as 60 data points per minute. The technology provided by the vendor for this pilot is found to be robust and reliable. The pressure and temperature sensors employed in this pilot have shown impressive resolution and dynamic response capabilities. Based on the results it is concluded that the pilot is successful and the system is recommended for future implementation in deep HT-HP wells of North Kuwait fields.
The project involved manufacturing, shipping and procuring the material from the Far-East and the USA. It also involved modification of well head to accept fiber optic cable entry into the well bore and use of specially designed low solid content packer fluid. The pilot was considered successfully completed after monitoring for 180 days in the month of August -2011.
In Kuwait Oil Company (KOC) this first fiber optic sensor technology pilot was conducted by Research and Technology (R&T) and Field Development Gas (FDG) with the coordination of Deep Drilling and other groups, in a deep HT-HP well with the primary objective to monitor two key reservoir parameters; temperature and pressure. The reservoirs in North Kuwait are complex soil bodies that have a high potential for condensate and gas. The continuous, real time understanding of these reservoirs is vital in order to optimize their exploitation; hence KOC adopted a strategy of deploying fiber optic monitoring systems.
Qatargas Process Safety Program
Authors: Shenbagarajan Saravanan 
Published: March 2015

Qatargas Process SAFETY Program
We know our limits and we operate within those limits all the time
The Qatargas Process safety Program is one of the business initiatives within Qatargas to achieve the Qatargas Vision 2015. It is a basic, standardized, operational work process that ensures operation within well-defined, well-understood limits. Operation within these limits is continuously achieved through a defined and well- followed set of operational and organizational Behaviors & Procedures at all levels.
High-Resolution Distribution of Organic Matter in Carbonate-rich Oil Shales controlled by climatic cycles and depositional environments
Authors: Caline B. , Dessort D. , Billeaud I. , Cantaloube S. , Allix P. , Krafft J. M. , Le Van Loi R. , Duclerc D. 
Published: March 2015

Abstract
The objective of this joint sedimentological and organic matter study was to document and understand the vertical heterogeneity of organic matter distribution of an oil shale interval which belongs to the lower Muwaqqar Fm in Jordan.
The high resolution logging of organic carbon using new pyrolysis instrument reveals the cm-scale rhythmic bedding of the oil shale deposits. Cyclostratigraphy based on recognition of Milankovitch cycles appears to control the alternation of rich and lean organic layers within this carbonate interval.

Introduction
The objective of this joint sedimentological and organic matter study was to document and understand the vertical heterogeneity of organic matter distribution of an oil shale interval which belongs to the lower Muwaqqar Fm in Jordan (fig. 1 and 2).
Because organic carbon content may show significant variation (e.g. at the mm or cm scale), a new instrument was used for recording high resolution logging of organic carbon on cores: the LIPS (Laser Induced Pyrolysis System).

Study program
Detailed investigation of one cored well (around 130 m long) has included high-resolution sedimentological logging (1:50 scale) and organic matter measurements (1 data point / 2 cm using LIPS on cores. Low resolution Rock-Eval data were acquired in order to calibrate the LIPS signal for calculating high resolution TOC and petroleum potential, regarding the different sedimentological facies.

LIPS: a new instrument for high resolution logging of organic carbon
Methods usually applied to quantity the carbon content or the hydrocarbon potential of sediment samples (Rock-Eval, Fisher Assay, Leco, analysis of thin sections, Iatroscan…) are expensive, provide low resolution data (typically, one sample every 30 cm to 2 m) and are time and sample consuming. Processing of geophysical well logs provides low-resolution logs (about 30 - 50 cm of mobile average data).
Emerging Technologies and the Future of Hydraulic Fracturing Design in Unconventional Gas and Tight Oil
Authors: Fonseca Ernesto 
Published: March 2015

Abstract
As industry leaders seek solutions to the myriad of challenges facing unconventional projects, research and development efforts continue in the area of multistage fracturing design. These research activities are focused on the identification of novel approaches to hydraulic fracturing (HF) design that can lead to more effective design practices in the future.
This paper describes emerging technologies within the building blocks of HF design for multi-stage horizontal wells, and proposes how application of these technologies can lay a foundation for the development and evolution of future industry practices. The industry debate on HF design commonly revolves around a perceived need for more powerful software tools that can capture complex fracture geometries. This perspective or position within the broader industry is due in large part to the cloud of microseismic induced events that is oftentimes observed to envelop a treatment area. Some interpret that these events arise from very complex fracture geometry, and therefore modeling tools with increased specialization are needed.
Rather than focusing only on the ability of the software to replicate complex fracture geometries, a higher-level and integrated view of HF design is recommended. As shown in Fig. 1, this integrated approach considers the progressive analysis and application of subsurface diagnostics and modeling capabilities, and how they can influence meaningful decisions in the area of HF design. In reality, the capability for HF design is as strong as the weakest of these three components and need not rely solely on modeling capability.
Results from the Introduction of a New 3-d Radial Probe for Wireline Formation Testing in Western Siberia
Authors: Charupa M , Weinheber P , Tsiklakov A , Latypov A , Goitia VH , Caraballo J R , Pashinsky A 
Published: March 2015

Abstract
The exploration and appraisal focus in Western Siberia has shifted to more complex and challenging reservoirs. As a result, tools and techniques that may have worked in more benign environments need to be adapted to the more challenging realities. A case in point is the wireline formation tester. The many sizes and shapes that are available have delivered valuable information with respect to rock and fluid characteristics using two basic configurations: either a single probe device or an inflatable straddle packer device. Aside from other nuances, the choice of configuration is essentially a tradeoff between the easy-to-deploy small-area single probe and the difficult-to-deploy but very large-area straddle packer. Into this mix is introduced a new type of probe. This 3-d radial probe attempts to combine the larger flow area of the inflatable dual packer with the easy deployment of a single probe tool. Examples from Western Siberia where all three tools were used are presented to allow us to compare and contrast the performance of each.

Introduction
Modern formation testers are capable of extracting a wide variety of reservoir characteristics including mobility, fluid type, fluid contacts and etc. There are a variety of methods by which the tools interface with the open hole formation but they broadly break down into two types: probes and inflatable dual packers. Probes enjoy the benefit of relatively fast deployment but are limited in the area of formation they can contact - typically on the order of a few square centimeters. Straddle packers isolate nominally 1 m of open hole which can be extended up to 5 m and in certain configurations can reach 12 m or more (Harfoushian, 2013). However they are typically more difficult to deploy than a single probe. To understand the effect of flow area will have on formation tester performance we can review the factors that drive the rate and drawdown characteristics of fluid flow into formation testers. This work is based on equations developed in the very early days of formation testing (Moran, 1962). The rigorous treatment of the modern implementation of this work (Dussan, 2011) allows for application to conditions beyond the circular probe originally considered. Additional work for the straddle packers is also considered. (Onur, 2004).
Operational Excellence in Qatar
Authors: Das Prashun Kumar 
Published: March 2015

Abstract
Qatargas North Field wells are typically 7 inch monobore medium to high deviation wells and are designed to handle high pressure sour gas containing of H2S and CO2. An extensive rigless well intervention program is carried out with 0.23 inch electric line and with 0.125 inch slickline for data acquisition, and for other downhole wireline jobs.
During a rigless PLT operation with 0.23 inch e-line, an accidental closure of the TRSCSSV resulted in cutting of the e-line. This necessitated a rigless heavy duty wireline intervention resulting in a successful, safe and a cost effective fishing operation in recovering 11,414 ft of 0.23 inch braided e-line.
This paper describes the approach and the technique applied in the fishing operation considering the limitations of a rigless operation. It also outlines the extensive workshop trials carried out during the preparatory phase for developing an acceptable double block and bleed barrier arrangement on the PCE for a safe well intervention. It also describes the planning considerations, the procedures developed, the high level Risk Assessment carried out, and the elaborate Load Assessment Study for working with a 90 ft mast and 0.23 inch braided line on a remote un-manned offshore platform.
Introduction:
Qatargas North Field is located offshore, northeast of Qatar in the Arabian Gulf and is the world's largest non-associated gas field. The sour, slightly over-pressured natural gas is contained in the Khuff carbonate formation. Majority of the offshore wells are 7 inch monobore design completed with 7 inch CRA tubing and liner sections. Wells deviations range from vertical to about 70 degrees.
An extensive rigless e-line program is carried out for data acquisition. This comprises of baseline logging program carried out just after PST, followed by a surveillance logging program carried out at a specified interval to study the changes in the reservoir, production and well parameters. The logging program generally comprises of production logging & pressure build-up (PLT-PBU), reservoir saturation survey (RST), and electromagnetic imaging survey (EMIT) and PS Platform Multifinger Imaging Survey (PMIT). The surveys are conducted in shut-in condition as well as in flowing condition at different rates. A drift run is generally conducted prior to any of these intervention jobs to ensure there is no obstruction inside the tubing or casing.
A 70 ft mast is used to rig up the required lengths of lubricators and the Pressure Control equipment. The wells are vertically equipped with a manual Swab Valve (SV), a hydraulically controlled Upper Master Valve (UMV), and a manual Lower Master Valve (LMV). A big bore tubing retrievable surface controlled sub-surface safety valve (TRSCSSV) is a part of the completion. During the well intervention jobs, the hydraulic controls for TRSCSSV and UMV are switched over to a Wireline Panel. This Panel has two remote Emergency Shut Down (ESD) system located at two strategic places to close TRSCSSV and UMV in case of exigency, when approach to the Wireline Panel is not possible.