bluuebunny/crossref_metadata_2025_split huggingface dataset:
Wireless Reservoir Monitoring Reducing Reservoir Uncertainty During Barents Sea Appraisal - A Case History for Norvarg
Authors: Champion Brian P. 
Published: March 2016

Abstract
Located in the Bjarmeland Platform area of the Barents Sea, Norvarg was discovered by Total in 2011 via wildcat well 7225/3-1, with gas being confirmed in both Jurassic and Triassic formations. A drill stem test (DST) was performed in the Triassic Upper Kobbe formation, but with non-commercial well productivity resulting. The post-DST vision for Norvarg was for stacked heterolithic tidal bar sands connected by large channel sands having better reservoir properties than tested in the first discovery well.
The objectives of the follow-on Norvarg-2 appraisal well, drilled in 2013, included verifying the presence of the channel sands defined from seismic, quantifying the channel productivity and demonstrating the contribution of other Kobbe facies by performing an extended duration pressure buildup (PBU). It was a requirement that the selected PBU monitoring method would allow the well to be permanently abandoned in accordance with Norwegian legislation without any requirement for further well intervention. This was achieved by using an emergent new electromagnetic (EM) wireless reservoir monitoring technology, which allowed the pressure buildup to continue undisturbed beyond the end of the DST and final well abandonment.
EM wireless monitoring technology is already well established as a means to monitor the reservoir pressure and temperature in abandoned appraisal wells, or suspended development wells, for the purpose of interference testing and reducing uncertainties in connectivity. However, this was the first time that it has been directly applied to monitor a long term PBU beyond final abandonment of a subsea appraisal well. By analysing the pressure transient data the objective was to investigate the presence of any flow barriers in the reservoir that might not be detectable during the course of a typical short duration pressure buildup performed during a DST.
This paper presents a case study of the first time application in the Barents Sea of a post-abandonment wireless monitoring solution that successfully delivered high quality reservoir pressure and temperature data for a period of 9 months beyond the end of a DST. Analysis of the data provided clear evidence of internal flow barriers, located 130m and 280m from the wellbore, that were not observed during the normal DST period. This data proved the limited connected volumes and confirmed the requirement for additional development wells, compared with what was known prior to performing the test. This was important information to support the construction of the full field model and the further evaluation of the Norvarg prospect.
Due to poor reservoir properties and disappointing deliverability, no viable development concept was identified for Norvarg, even with an increased well count and using fractured vertical and horizontal wells. The license for PL535 was subsequently relinquished in May 2014.
LWD Formation Fluid Sampler Tool Collects First Fluid Samples While Drilling In Deep Water On The Norwegian Continental Shelf
Authors: Solbakk Tommy , Riise Henrik Erevik , Strøm Ellen Ambjørnsen , House Jerry , Eriksen Kåre Otto , Digranes Gunnar 
Published: March 2016

Abstract
Fluid samples were acquired in an exploration well and subsequent pilot hole for an operator in deep water on the Norwegian continental shelf to identify the reservoir fluids and to check for potential connectivity between two reservoir targets. Several limiting factors meant that pipe-conveyed logging after drilling was not a viable option. Consequently, a logging while drilling (LWD) formation fluid sampling tool was run as a part of a LWD evaluation program to collect fluid samples while drilling and when pulling out of the hole after reaching TD (total depth) of the section.
A team of global and local experts was established to plan the job. The team performed a risk analysis to identify risks and plan mitigating actions. Several challenges were identified, including the potential damage to equipment from vibration when drilling out the shoe track or from hitting stringers while drilling the formation. Other challenges identified involved potential tool movement from rig heave during sampling and required sampling time as a function of the duration of formation exposure to drilling mud before sampling.
The team assessed the risks and established a plan to mitigate them, and the job was performed according to plan in February and March of 2014. A total of nine fluid samples were collected in two well sections, completing each section in one drilling run. This paper discusses the results of the third-party laboratory sample analysis. The formation evaluation logs were inconclusive as to whether or not the reservoir contained oil, condensate, or gas at some depths because of the laminated structure of the formation. The LWD fluid sampling technology confirmed that the reservoir contained gas. This paper also discusses the job planning, mitigating actions that were introduced, implementation and results of the job, and the benefits of fluid sampling while drilling.
Shoe Track Drillout Analysis: Factors Affecting Drilling Efficiency
Authors: Wiktorski Ekaterina , Kaland Thorbjørn , Belayneh Mesfin 
Published: March 2016

Abstract
Drillout optimization is analyzed based on criteria that includes higher rate of penetration (ROP), reduced overall cost per foot, reduced drilling time, and reduced wear rates. In the industry, there are no mechanistic and empirical models used to simulate shoe track drillout optimization. The current common approach is the use of "best practices," which have been developed by companies throughout years of experience. However, even when the best practices are used, shoe track drillout is often time-consuming and damaging to the operation of the drilling tools.
This paper presents analyses of field shoe track drillouts data, obtained from several wells, to assess the primary drilling controlling parameters with respect to drillout times.
The study reveals primary factors that affect shoe track drillout time. It also provides an understanding of how operational parameters should be manipulated to achieve the desired ROP. Finally, the study results were compared to existing best practices. This comparison was used to create a combined list of recommendations that can be consulted before drilling through a shoe track. Although the elimination of damage to the BHA is an important issue in this topic, it is beyond the scope of this paper and may be the focus of future research.
Addressing the Health Risks of Silica Cement: A Custom Solution for Norway
Authors: Johnson Carl R. , Knowles John , Rønnekleiv Bjørn 
Published: March 2016

Abstract
In recent years, a project was initiated to identify a safe and practical alternative to conventional silica-based cement slurries. The objective was to eliminate exposure to respirable crystalline silica (RCS) in oilfield cementing operations. RCS, as well as being linked to various respiratory illnesses (1), has now been identified as a human lung carcinogen (2), implying there is an established link between exposure to RCS and lung cancer.
When cementing well sections with a bottomhole static temperature (BHST) of over 110°C [230°F], a cement powder containing silica flour must be used to ensure the set cement matrix is stabilized to be able to withstand persistent exposure to these temperatures over time (mitigating against strength retrogression). A certain proportion of the silica within these conventional cement blends is classified as RCS.
The newly developed system, known as zero respirable crystalline silica blend or ‘ZRCS-blend’, was successfully applied on numerous occasions on a Norwegian rig. Interestingly, the system found successful application in a batch-drilled conductor campaign on a high-pressure/high-temperature (HPHT) field where the potential exposure during production exceeded 110°C [230°F]. Whilst being a safer alternative to conventional cement systems, the ZRCS-blend was able to deliver a top of cement (TOC) to the seabed on each and every occasion during the campaign, thus eliminating the need for any remedial operations.
As shown by proven success of the ZRCS-blend offshore on the Norwegian continental shelf, the system provides an alternative to silica-based cement for operations worldwide, to comply with regulations and health, safety, and environmental guidelines.
Evolution of a Well Annular Barrier for Mitigation of SCP
Authors: Bårdsen Johnny , Dagestad Vibjørn 
Published: March 2016

Abstract
A novel, Well Annular Barrier (WAB) was introduced back in 2011 as an open-hole, zonal isolation packer. Its strength, ruggedness and pressure capacity over the past four years has proven it a valuable solution. Especially for ensuring the successful cementing of casing strings which were required to be run through challenging environments such as overburden, depleted zones, water bearing sands or unconsolidated zones.
Work is in progress to develop a verification system for WAB expansion and integrity, further growing its capabilities and the operating envelope in which it can be deployed. This will in turn increase the WABs potential applications, and use as a stand-alone, open-hole barrier. The newly developed system consists of pressure and temperature sensors either mounted independently from, or integrated with, the WAB. Annular sealing integrity will be confirmed by direct pressure measurement down-hole. For SCP applications, this will replace indirect confirmation of integrity via cement bond logs, which is the current practice. A verification table in line with requirements outlined in Norsok D-010 has been prepared to comply with industry standards for barrier verification.
The current climate in the oil & gas industry calls for novel solutions to known challenges. Well integrity in the overburden is one such challenge the industry has a high focus on, and solutions must meet a challenging set of requirements. New solutions need to be equal to or better than existing ones, hence qualification requirements and documentation are paramount in delivering innovative solutions. Some operators do not accept sustained annulus pressure in producing wells, especially in HPHT applications. The WAB combined with this new Well Data Monitor (WDM) for verification of pressure seal is an evolutionary step that could eliminate this challenge. It offers a new ‘tool in the box,’ expanding the operating envelope and enabling advanced well construction with no compromises.
This evolution of the WAB can aid to further prevent surface casing pressure (SCP), a huge concern throughout the industry. With the introduction of the WAB with sealing verification, operators can more easily construct robust and safe wells while at the same time, reducing construction time and cost.
Polymers and Polymer-Based Gelants for Improved Oil Recovery and Water Control Applications in Naturally Fractured Chalk Formations
Authors: Hatzignatiou Dimitrios G. , Giske Nils H. , Stavland Arne 
Published: March 2016

Abstract
Water flooding of naturally fractured carbonate (NFC) formations always poses several challenges related to formation sweep, oil recovery efficiency and rate of extraction from matrix blocks, and water management. The presence of natural fractures decreases formation sweep, delays oil recovery rates, and often yields high injector/producer conductive paths which increase produced water cuts with undesirable impacts on fluids production from technical point of view (ranging from lifting difficulties to well stop flowing) as well as economic one (produced water separation, cleaning, and re-injection).
Downhole and deep-reservoir fluids management becomes important to addressing or reducing negative oil production effects in NFC formations. Injected fluid diversion away from well-established high-conductivity flow paths will be extremely beneficial to (a) sweep previously unswept formation regions, (b) reduce circulation of injected water, and (c) improve the oil recovery rate and ultimate recovery factors. Injected fluid diversion gels, used in such applications, are normally based on a polymer/crosslinker mixture designed to gel at a given distance /location away from a treated well. However, HSE regulations and/or surface facilities requirements may not permit in certain occasions the use of such chemical systems that have been tested and successfully field-applied previously.
In this work, existing commercial polymer and polymer-based chemicals that could be used for water management is NFC reservoirs are screened and evaluated in the laboratory. Several testing bulk- and core-based techniques have been used to achieve this goal with the selected chemicals undergone thorough investigation of their filterability, injectivity, gelation time, gel strength, gel shrinkage, and impact on oil production.
Injection of high and low molecular weight HPAM polymers into fractured cores does not hinder the oil production mechanism in chalk formations yielding a lower oil recovery rate but comparable ultimate recoveries with water injection. The environmental friendly polymer (Polymer B) gelant is "inconsistent" related to the formation of gel; when it gels, the quality of the formed gel is poor and provide no resistance to a post-treatment water injection. The non-environmentally friendly polymer (Polymer A) gelant worked consistently concerning gelation and yielded good quality, strong gels that can withstand post-treatment applied pressures during water injection.
Norwegian Open Source P&A Database
Authors: Myrseth Velaug , Perez-Valdes Gerardo A. , Bakker Steffen J. , Midthun Kjetil T. , Torsæter Malin 
Published: March 2016

Abstract
An estimated 3000 oil wells need to be plugged and abandoned on the Norwegian Continental Shelf (NCS), with approximately 150 new wells being drilled each year. The petroleum industry estimates the total plugging costs to be almost 900 billion Norwegian kroner, and that the work will take up to 40 years to complete. Due to the current tax regulations in Norway, the state indirectly pays 78% of the costs (about 700 billion Norwegian kroner). It is therefore vital to reduce expenses by targeted research and development (R&D) of new technology, and to ensure better planning of plug and abandonment (P&A) operations in and between licenses.
The current study aims to gather available data relevant for Norwegian P&A operations in an open source database – and to develop and use a P&A planning software to derive plugging costs in various scenarios. The software may be used to identify bottlenecks in P&A operations and analyze potential efficiency gains from technology improvements both for single operations and on a system level. We will use a cross-disciplinary approach that combines the fields of operations research with technological expertise.
In this paper, we present the outline of the database and the current status of available data for P&A operations on the NCS, as well as a short literature review. Available data is categorized according to the different choices that need to be made within a single P&A operation, both with regards to technological aspects and existing regulatory framework. We also show how this database will be used to develop a first version of the P&A planning software.
Industry, government and ordinary tax payers will all benefit from knowledge sharing, optimized planning, and more targeted R&D efforts on this topic. The results from this study will be used to identify important cost drivers and to draw up a roadmap for future P&A-related R&D.
Inverse Modeling for Fluid System Characterization Through Machine Learning Algorithms
Authors: Tarrahi Mohammadali , Shadravan Arash 
Published: March 2016

Abstract
Inverse fluid modeling facilities designing drilling, spacer, cement or fracturing fluids. This approach uses several test data available at the laboratory databases for fluid characterization. Without machine learning algorithms it is very hard for fluid engineers to rationalize a plethora of fluid system information, transform them into knowledge and make intelligent and cost-effective decisions to design a fluid system with desired properties. Therefore, trial and error method is considered to be very costly and misleading. Today, there is a need for an expert system which uses all the available fluid design data stored in a database by which we can benefit from its insights for smart fluid designs. This predictive tool suggests a composition for drilling fluids, spacer fluids, fracturing fluids and cement slurries by implementing a machine learning algorithm on imported experimental data.
This study investigates the inverse modeling fluid characterization through machine learning algorithms. A laboratory dataset of measured fluid properties and their corresponding fluid system characteristics are employed as training data to the machine learning routine. GPR as a machine learning method considerably reduced the costs of testing, optimized the material use, integrated available experimental data and eliminated the user bias. This practical nonlinear regression method fosters an efficient and fast prediction analysis which do not require including complex physics of the underlying intricate chemical fluid behavior while integrating all available data from different databases.
Nano-Sized MgO with Engineered Expansive Property for Oil Well Cement Systems
Authors: Jafariesfad Narjes , Gong Yi , Geiker Mette Rica , Skalle Pål 
Published: March 2016

Abstract
The failure of cement sheaths to perform as designed in oil wells can result in loss of zonal isolation. Bulk shrinkage of the cement sheath in the annulus is one of the main causes compromising zonal isolation. Conventional cement systems without compensation for bulk shrinkage have a high risk of failure during all phases of well operation. However, when the volume reduction is compensated, without compromising the mechanical properties, the risk of failure is significantly reduced.
In this study, nano-sized MgO with designed expansive properties has been introduced to the fresh cement slurry. The expansive properties of nano-MgO were achieved by controlling the preparation condition. A dilatometer with corrugated molds was used to measure the linear strain of samples cured at 40 °C.
The reactivity of nano-MgO played a main role in controlling the expansion performance at the required time. The efficiency of nano-MgO with different reactivities for shrinkage compensation of cement system, cured at 40 °C, was studied. Addition of only 2% nano-MgO with appropriate reactivity was sufficient to maintain expansion in the cement system. Controlling the expansion performance of the additive through designing its reactivity is a promising method to limit bulk shrinkage of cement sheaths in oil wells.
The results presented show that nano-MgO with controlled expansive properties can be used to design a cement system with short- and long-term zero-bulk shrinkage.
New Insight to Wormhole Formation in Polymer Gel During Water Chasefloods Using Positron Emission Tomography PET
Authors: Brattekås B. , Steinsbø M. , Graue A. , Fernø M. A. , Espedal H. , Seright R. S. 
Published: March 2016

Abstract
Polymer gel is frequently used for conformance control in fractured reservoirs, where it is injected to reside in fractures or high-permeability streaks to reduce conductivity. With successful polymer gel conformance control in place, increased pressure gradients across matrix blocks may be achieved during chasefloods, diverting water, gas or EOR chemicals into the matrix to displace oil. Knowledge of gel behavior during placement and chase floods is important, because it largely controls the success of subsequent injections. Polymer gel behavior is often studied in core floods, where differential pressure and effluents from fracture and matrix outlets give information about gel deposition during placement and flow paths during chasefloods. The work presented in this paper utilize complimentary PET-CT imaging to quantify the behavior and blocking capacity of Cr(III)-Acetate HPAM gel during chase waterflooding. In-situ imaging provides information about changes that may not be extracted from pressure measurements and material balance only, such as changes in local fluid saturations and dynamic spatial flow within the fracture and within the structure of the gel network.
Polymer gel was placed in core plugs with longitudinal fractures that connected the inlet and outelt, and chase water was subsequently injected to measure the gel blocking capacity. The water phase was labelled with a positron emitting radiopharmaceutical (F-18) to visualize and quantify local flows with positron emission tomography (PET) during gel rupture and subsequent flooding. Using PET, we study gel rupture and the development of wormholes during gel erosion after rupture as a function of flow rate. A particular strength with access to dynamic, local flow patterns is the direct comparison to global measurements, such as differential pressure and production rate, to verify existing gel behavior models.
Integrity of Downscaled Well Models Subject to Cooling
Authors: Todorovic Jelena , Gawel Kamila , Lavrov Alexandre , Torsæter Malin 
Published: March 2016

Abstract
The annular cement is often subject to temperature variations, for example heating during steam injection, or cooling during CO2 injection or hydraulic fracturing. Fractures caused by thermal stresses may create flow paths through the cement sheath thereby jeopardizing the well integrity. The objective of this work was to experimentally and numerically investigate the effect of thermal cycles and harsh cooling on downscaled wellbore sections with a focus on the cement sheath failure.
Downscaled wellbore sections were each prepared by cementing a casing section within a hollow cylinder of Berea sandstone. One specimen was subjected to a thermal cycling program that included cooling to −50 °C and heating to 80 °C. Two other specimens (dry and wet) were used in harsh cooling experiments with solid CO2 and liquid nitrogen. CT scanning was performed before the onset of, during and after the completion of the thermal cycling program or harsh cooling experiments.
No differences in the distribution of voids and fractures in the cement before and after the thermal cycling were observed. This indicates that the applied temperature range was not sufficient to cause damage in the cement sheath. On the other hand, the harsh cooling experiment using liquid nitrogen resulted in fracturing of both the cement and rock in the water-saturated specimen.
Finite-element simulations reproducing the thermal cycling program used in the laboratory experiment were performed. The simulations have shown that thermal radial stresses at cement/casing and cement/sandstone interfaces were relatively low, i.e., from 0.5 to 1.0 MPa, which might explain the lack of thermal-induced damage in CT images. The simulations also suggest that the radial fracture in the water-saturated specimen subject to harsh cooling was caused by a combined effect of tensile hoop stresses and stresses due to water freezing. The fracture was most likely initiated in the sandstone followed by further propagation into the cement. It is likely that well construction materials and the surrounding formation are water-saturated. Thus, cooling well below 0 °C, which may occur during a CO2 blowout, would increase chances for cement and formation failure.