bluuebunny/crossref_metadata_2025_split huggingface dataset:
Innovative Work Scheme: Real Time Analysis During Well Test Operations
Authors: Ferreira A. , Vidal J. , Abi-Ramia R. , Jouti I. , Flores S. , Essenfeld D. , Cañas J. , Rey F. , Landinez G. , Maizeret P. , Villanueva G. , Cabanilla J. , Alves R. 
Published: March 2012

Abstract
In 2007, a new Independent Brazilian Oil and Gas company acquired 21 exploration offshore blocks, increasing its portfolio up to 29 blocks by March 2009. Ambitious exploration and production goals were set, such as Drilling Commencement by Q3 2009, Minimum Well Drilling Commitments in four Basins by 2010/11, Initial Development in the Campos Basin and First Oil by 2012. The first three initial goals have already been met and the fourth one is well online to be met as expected with the FPSO already in the Brazilian coast.
One of the key elements to reach these objectives is recognized to be the implementation of a focused innovative decision workflow, supported by a real time monitoring process from a cross-disciplinary Operations Support Center (OSC). This paper presents this innovative work scheme, based on a collaborative working environment between the operating and service companies during the well testing operations, with the most advanced monitoring and interpretation tools.
It includes a concrete field case which resulted not only in improved risk identification, prevention and mitigation, but also in operational performance optimization. This case was a horizontal open hole test of 1080 mts with 90 deg deviation. The real-time collaboration resulted in significant rig time savings, mitigation of unexpected events consequences, and delivery of higher productivity comparing similar wells results in the area.
This innovative decision workflow implemented in Brazil is considered as a high-technological reference model for operating companies, locally in Brazil and others around the world, to achieve success during challenging Well Testing operations.
Intelligent Energy and Other Industries - Lessons Learned
Authors: Strathman Michael , Lochmann Mark J. 
Published: March 2012

Abstract
If we have learned anything from the amazing gains and re-engineering that has occurred in exploration and other industries, it is that information technology, when properly applied, changes the rules of the game. Venture capital firms are always looking for companies that can secure a "first-mover" advantage because these startups offer the best opportunity for maximum returns. Those who move quickly to take advantage of new opportunities benefit the most. However, studies show that other industries are innovating much faster than exploration and production (E&P).
Manufacturing and process industries, such as chemicals, automotive, and refining, have all been forced to adopt new ways of working as a result of business imperatives or crises. Much can be learned by studying the challenges already addressed in those industries and assessing their applicability in E&P, particularly in production operations.
The capabilities of existing technology far exceed production operation's willingness to apply it today. It has been said that producers are in a mad dash to be second. They believe an early mover advantage is in reality a "first-mover" penalty. This paper will examine some of the pros and cons of a first-mover strategy for E&P companies.
It is a widely held opinion that our industry is unique and, therefore cannot use proven solution approaches and tools from other industries. Process and manufacturing industries have learned to look beyond their borders and have found that solutions can be reconfigured and successfully adapted to their businesses; they have replaced outdated problem-solving approaches with new ways of working. Oil and gas should be no exception.
Standard or enterprise-wide solutions and best practices assume a degree of commonality across assets, and this is assumed to be problematical in E&P. However, other industries contain assets with a high degree of variability, yet they have still overcome these barriers to innovation and rolled out common solutions.
This paper explores drivers, barriers, attitudes, and ways to apply important lessons from other industries to the upstream industry by comparing them to E&P to identify ways to make oil and gas operations more "intelligent."
The survey data shared in this paper is intended to highlight issues for further research and was not designed for statistically valid sampling.
Choices, Changes and Challenges: Lessons for the Future Development of the Digital Oilfield
Authors: Dickens Jeff , Feineman David , Roberts Steve 
Published: March 2012

Abstract
BP has had an active digital oilfield programme for over 10 years with our Field of the Future technology flagship. This paper identifies some key learnings from both our own experience and comparison with activity across the industry. We then examine the implications for the future of the digital oilfield concept.
In retrospect, we characterize BP's activities into two distinct phases. We believe the characteristics of these phases also apply more generally in the industry.
Phase 1 (2000-05) dealt with communicating a compelling vision and demonstrating the validity and potential of the digital oilfield concept. This phase dealt with engaging asset and major project teams in understanding the potential value in new ways of working by accessing real time operational information. In an R&D sense, Phase 1 was about developing and integrating a diverse set of tools to support technology trials and prove up the concept.
In Phase 2 (2005-11) we started to implement at pace and scale. For BP, the focus was on delivery of discrete real-time remote monitoring solutions and target driven value realization for well monitoring, surveillance by exception (i.e event driven rather than by routine scheduling), equipment reliability, and production optimization. We have documented value delivery of over 70 mboed net cumulative production impacts, plus other benefits. The choice of specific technologies was less important than the drive for sustainable implementation and solid business cases.
The range of industry experience raises an interesting question about options for the next phase of activity. These range from a focus on embedding the success to date as "business as usual", through to targeting the next class of difficult problems or operational risk reduction. Using the skills and experience from Phase 2 could unlock even greater value and further transform the work of energy companies.

RESULTS/CONCLUSIONS
Virtual Worlds-based Immersive Training Simulators for Improved Safety in Operation Start-up and Emergency Response Planning
Authors: Van den Wijngaert Hans , Lagae François 
Published: March 2012

Abstract
Growing offshore infrastructure complexity and capital investments, environmental and economic pressures and experience-age gap in technical workforce present unprecedented challenges to the oil industry. Technology advances positively impact immersive project reviews and enhance asset management practices, delivering new opportunities to mitigate some of these challenges.
Evaluation and rehearsal of emergency response procedures and in-context training of field operators for operation start-ups can now be performed in an intuitive game-like graphics environment, delivering high-value simulations and high-retention training sessions.
3D Immersive Training Simulator (ITS) provides scenario-driven training capability, leveraging the photo-realistic, real-time rendering of massive 3D VR industrial asset models.
The Development and Successful Application of an Automated Real-Time Drilling Fluids Measurement System
Authors: Stock Tore , Ronaes Egil , Fossdal Truls , Bjerkaas Johnny 
Published: March 2012

Abstract
The technically challenging development of the marginal resources in the mature fields in the North Sea requires new levels of planning and execution to control the drilling process.
Over the past few years, improved dataflow between drilling rigs and shore-based operator and service providers support organizations has created a renewed interest in automated monitoring of drilling parameters. Development of data transmission systems like InterACT and data formats like WITSML have initiated the search for and the development of new sensors that can be used for automated real-time monitoring of critical drilling fluid parameters.
Increased focus on HSE in general and the use of harmful test chemicals, vapors and the risk of explosions in particular also has been an important driver for this development. Introducing a level of automation described in this paper can reduce by 70-80% the exposure time of fluids engineer in the rig laboratory without compromising service quality.
Moreover, the development and use of advanced hydraulic simulation programs frequently employed for extended reach drilling and managed pressure drilling (MPD) have increased the focus on more reliable and more frequent operational inputs. The precision of modern simulation software represents a sharp contrast to the current practice of manual rig testing and reporting.
This paper details the selection of fluid parameters considered most important for automation. The authors will describe the sensors developed for monitoring the most important parameters, including Electrical Stability (ES), density, temperature, water content in invert emulsion drilling fluid, XRF elemental analysis, in-line particle size distribution (PSD) and full 3D rheology tests. The parameters that could be monitored with existing sensor technologies used in other industries will be discussed, as well as those requiring development based on current field equipment. In addition, the paper will describe the installation and first field experiences with a full range of automated instruments on various rigs in the North Sea.
Lessons Learned: Seeking Opportunity in Low Resistivity Upper Sihapas Sands in LA Field, Indonesia
Authors: Khresno Sri , Prakoso Ambaria , Kurniawan Akbar , Suderajat Suderajat , Nur Ilhami , Ontowiryo Bambang , Hermawan Rofiq 
Published: March 2012

Abstract
In formation evaluation, resistivity logs are typically used to identify pay zones because of the resistivity contrast between the oil zone and water zone. But not always. When the pay zone exhibits low resistivity, these logs cannot identify oil zones. LA field is a mature oil field in the Malacca Strait PSC in Indonesia that has been on production since 1984. Oil is produced from the Upper Sihapas (US) and Lower Sihapas (LS) sandstones. The LS sands have provided 98% of the oil produced to data. The US sands are thin, low permeability, low pressure and limited in volume (sand lenses) compared to the LS sands.
High water cuts in LS sands have made wells uneconomic to operate. Rather than abandon the wells, US sands were identified and re-completed alone (US sands will not flow when commingled with LS sands). But how to identify oil sands in the US? Resistivity of oil sands and water sands is almost the same. Gas readings and oil show give clues of oil in low-resistivity sands, but depth control is not accurate enough to know exactly which thin sand has oil.
The LA field has seven US producers. Production varies from well to well due to sand heterogeneity. We created a flowchart to determine oil potential, likely reserves and deliverability. Our experience is that low resistivity US sands can produce commercially at low water cut, albeit at low rate due to low pressure and low deliverability.
Pore Pressure Prediction in a Carbonate Reservoir
Authors: Atashbari Vahid , Tingay Mark 
Published: March 2012

Abstract
Knowledge of pore fluid pressure is essential for safe drilling and efficient reservoir modelling. An accurate estimation of pore pressure allows for more efficient selection of casing points and a reliable mud weight design. Current commonly used methods of pore pressure prediction are based on the difference between a ‘normal trend’ in sonic wave velocity, formation resistivity factor (FRF), or d-exponent (a function of drilling parameters) and the observed value of these parameters in over-pressured zones. The majority of the techniques are based on shale behaviour, which typically exhibits a strong relationship between porosity and pore fluid pressure. However, carbonate rocks are stiffer and may contain over-pressures without any associated influence on porosity. Indeed, the application of common pore pressure prediction methods to carbonate rocks can yield large and potentially dangerous errors, even suggesting absences or decrease in abnormal pressure in zones of high magnitude over-pressure. In some cases, the hypothesises which been in the conventional methods seems to be flawed in some cases where pore pressure decreases by depth.
In this research, a new method for effective stress calculation has been obtained using the compressibility attribute of reservoir rocks. In the case of over-pressure generation by undercompaction (as occurs in most clastic over-pressured sequences), pore pressure is dependent on the changes in pore space, which is a function of rock and pore compressibility. In simple terms, pore space decreases while the formation under goes compaction, and this imposes pressure on the fluid which fills the pores. A carbonate reservoir in a field in Iran has been investigated to establish pore fluid pressure generation mechanisms, and to attempt new methods for pore pressure prediction in carbonate rocks.
A Novel, Shear-Stable Fracturing Fluid for High-Temperature Applications
Authors: Kalgaonkar Rajendra , Patil Prajakta 
Published: March 2012

Abstract
Hydraulic fracturing often employs crosslinked polymeric gels, which are pumped into a subterranean formation with sufficient viscosity properties to generate fracture geometry in the subterranean rock and transport solid proppants to hold the fracture open. Crosslinking of a polymeric gel can significantly contribute to the success or failure of a fracturing treatment. Crosslinking agents used in commercial fracturing applications include borate, titanium, and zirconium (Zr) complex ions.
As the fracturing fluid is pumped downhole, it experiences different shears, such as high shear caused by tubulars, and low shear in the fracture. Typically, polymeric gels are shear thinning and will reduce in viscosity on application of high shear. The fracturing fluid's inability to shear recover as it transitions from a high shear regime in tubulars to a low shear regime as it enters the fracture can lead to compromising of near-wellbore (NWB) proppant transport and reduced fracture width, and treatment can screenout. Borate crosslinkers that are known to provide the shear recovery property to the fracturing gel typically have a temperature limitation of 300°F. Conversely, metal crosslinkers that have good temperature stability beyond 300°F are prone to irreversible shear degradation that does not reheal as the fluid passes from the high shear to a low shear regime, thus compromising efficient proppant transportation inside the fracture.
This paper presents the development of a novel fracturing fluid for high-temperature applications with a delay of complete crosslinking until after the fluid is beyond the high shear environment. Rheological characterization was performed with a Model 50-type viscometer at temperatures greater than 300°F, including shear-history profiles. The fluid chemistry presented employs a zirconium crosslinker and buffer combination that controls the crosslinker kinetics to yield a viscoelastic gel crosslink after passing through the high shear-history profile. Additionally, regained-permeability results obtained using conventional breakers demonstrated the fracturing fluid's cleanup efficiency.
Using Dynamic Simulations to Optimize the Start-up Procedure of a Lazy Horizontal Oil Well
Authors: Yusuf Rahel 
Published: March 2012

Abstract
During a well start-up, fluid distribution within the well shifts from a static segregated phase (gas-oil-water) column to a flowing three-phase mixture. For this transition to be successful, the well has to overcome the additional hydrostatic head associated with the phase segregation. This process can be problematic for wells with limited pressure support as an improper bean-up procedure can lead to a situation where the pressure driving force across the well is unable to overcome the hydrostatic head imposed by the liquid column during start-up thus resulting in a failed start-up. The failed start-up may add extra liquid present within the wellbore thus making subsequent start-up attempts even more difficult. For such wells, correct bean-up strategy is important to ensure successful start-up.
In the current work, dynamic simulations are conducted with a commercial transient-multiphase-simulator to understand the start-up flow and pressure transients and optimize the start-up procedure of a lazy horizontal oil well which has experienced start-up problems after a resting period.
Simulations of the failed bean-up procedure showed that a water-lock formation in the tubing hampers a successful well start-up as the hydrostatic head imposed by the water-lock does not allow the well to flow. An alternate bean-up procedure was then virtually tested by simulation where the wellhead choke was quickly opened. This led to a successful start-up as a gas pocket originally trapped in the horizontal section could escape to the vertical tubing only under quick bean-up thus lowering the hydrostatic pressure below the pressure driving force across the well. Dynamic simulations were also used to devise a strategy for the operator as to how long the well be rested before any bean-up is attempted. The proposed strategy enabled the operator to use the readings from downhole pressure gauge as a guide in deciding the resting period and bean-up procedure.
This study brings forth the significance of dynamic simulations in optimizing the start-up of lazy wells where failed bean-ups can lead to higher down times thus adversely affecting production. Further, dynamic simulations also help in arriving at guidelines for the operators on how to avoid failed start-ups.
A Coiled Tubing Perforating Solution Incorporating a Gun Deployment System and Dynamic Underbalance Technique Improves Well Production in High Angle Deep Gas Wells in Saudi Arabia
Authors: Al Jubran Hasan , Leal Jairo , Al BuHassan Shaker , Bolarinwa Simeon , Kharrat Wassim , Pulson Dave , Barnawi Mazen 
Published: March 2012

Abstract
Saudi Aramco has recently initiated a change in gas well design in the Ghawar field of Saudi Arabia. The new approach is to drill deviated cased hole gas wells through the reservoir to increase the length of contact of the productive zone and thereby increase production potential. Typical gas wells were drilled as a vertical cased hole through the reservoir or open hole horizontal gas wells.
The increased well deviations, measured depths and resultant increase in reservoir sections required a new approach to the perforating solution for these wells to connect them to the gas plants. Various techniques were reviewed, considering safety, operating efficiency and well performance. The final solution was to deploy the perforating systems on electric coiled tubing (CT) and run all the guns in one run using completion insertion and retrieval under pressure (CIRP) as a deployment system, which allowed the guns to be run and pulled under live well conditions without having to kill the well.
This paper details the learning curve and lessons learned from the implementation of this technique in five gas wells. The deployment system and pressure control equipment were optimized to satisfy Saudi Aramco’s requirement for three barriers. A CT cleanout run was added before perforation to remove any debris from the wellbore causing a problem to the depth correlation tools. An existing CT tower was used to support the very long wellhead stack, but due to its height limitation a special solution was implemented to enable safe CT operations. A deployment system under live well conditions was used to minimize CT runs, operating time and cost savings. The static underbalance condition was set before running the guns, combined with the dynamic underbalance perforating technique and deep penetrating charge gun design were implemented to optimize the well performance. This technique allowed safe and efficient perforating in a single underbalance run of these five gas wells.
The paper also covers the planning of the perforating solution, health, safety and environment (HSE) considerations, equipment selection, operational procedures, job execution and results.
Design of Gelled Fluid for Debris Removal in Subsea Pipeline
Authors: Misra Chaitali , Danait Achala , Salgaonkar Lalit 
Published: March 2012

Abstract
Transportation of hydrocarbon through a pipeline may be hindered as a result of deposition of debris. The presence of debris within the pipeline leads to reduction in the effective flow area, thus reducing the efficiency of the transportation system. Some of the factors leading to formation of the debris are changes in temperature and/or pressure of the transported fluid and chemical reactions which occur therein.
Pipeline maintenance pigging is routinely performed to extend the operational life of pipelines. Recently, a combination of mechanical and chemical remedial measures has shown beneficial results in pipeline cleaning. Mechanical brush pigs loosen the debris adhering to the walls, while chemical techniques, such as the use of gelled fluids, enhance the carrying capacity and help to transport the loosened debris out of the pipeline.
This paper presents the results of tests conducted to design a fast-breaking gelled fluid for a debris-removal operation in a long, large diameter subsea pipeline in the Asia Pacific region. In addition to exhibiting good stability and debris-carrying capacity under the laboratory test and field conditions, the gel had to be compatible and demonstrate stability when mixed with other additives in the transported hydrocarbon. A highly viscous, aqueous-based linear polysaccharide gel was designed to satisfy these requirements. A key environmental and operational consideration was the easy and fast disposal of the gel after completion of the cleaning operation. With oxidizing breaker, gels prepared in potable water resulted in viscosity of &lt; 10 cp within two days, which was significantly shorter than when seawater-based gels were similarly treated. Preliminary field results indicate that the combined mechanical and gel system removed significant amount of debris. Data from future trials will help evaluate the feasibility of such technique for effective cleaning of the pipeline.