bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integration of Real-Time LWD Spectroscopy Data to Optimize Drilling through Paleosols Supports Low Energy Drilling Operations
Authors: Cook Michael , Horstmann Mathias , Irondelle Matthieu , Hugall Jeremy 
Published: June 2014

Abstract
Paleosols are fossil soils, and provide additional challenges to drilling and completion operations as they are generally weaker and more friable than rocks such as shale or sandstone. This weakness often results in borehole degradation, wash- or breakouts and even formation collapse, which poses challenges to well operations. It is therefore important to identify paleosol horizons whilst drilling and perform operations in a manner that will minimize damage to these formations. Conventional log data is in many cases unable to uniquely identify paleosols.
Recent analysis of real-time GR capture spectroscopy, which is available in logging-while-drilling, has assisted in identifying these horizons and aided the successful drilling and completion of several wells on the Gullfaks Satellite fields. Previous work demonstrated that paleosols could be characterized using iron content. Spectroscopy data was used to determine the concentration of a suite of elements whilst drilling. By combining conventional log data with measurements of iron content it has been possible to identify weaker paleosol horizons based on an increased iron content, high Gamma Ray signature, and high bulk densities. This data has been utilized in real-time to avoid excessive work of the drillstring over the paleosol zones, particularly with respect to stabilisers and the bit, and to optimize the position of the bottom hole assembly (BHA) during formation pressure testing.
In order to reduce formation damage whilst drilling, a Low Energy Drilling Operations (LEDO) strategy in which the drilling parameters are only changed one at a time in order to establish trends, off bottom circulation is minimized and ROP is limited has been used. This technique was combined with traditional LWD triple combo data along with GR spectroscopy, measured matrix properties and borehole images. This approach has made it possible to successfully drill several wells through paleosol- rich formations.
Advances in Real-Time Data Monitoring for Pressure Pumping
Authors: Svensson I. , Sach M. , MacLeod A. 
Published: June 2014

Abstract
In the 2000s the focus for real-time data transfer, monitoring and visualization has been in the drilling domain. The WITSML open exchange standard has been a key factor to this success. Compared to the legacy WITS standard, WITSML has advantages in interoperability, the ability to load historical data and the capability to get updated data, e.g., for post-acquisition quality control and assurance.
Recently, Baker Hughes has completed several developments related to the transfer of real-time data from pressure pumping services based on WITSML. One typical case history is real-time monitoring of wellbore intervention performed with coiled tubing in Norway, and another important application is fracturing operations in the US. We will also show examples of integrated coiled tubing drilling operations in Norway and acidizing and gravel pack jobs done in Brazil.
Baker Hughes is now also supporting the new WITSML stimJob object. Fracturing operations can create large volumes of data, and the stimJob object creates a valuable and timely post-job treatment report. The data in the report can be integrated with other data, like production data, for production optimization. We will show examples of successful transfer of stimJob data to Geological and Geophysical support applications.
Even a Small Change in Procedures can Give Unexpected and Unwanted Results: A Troll Experience
Authors: Carlsen Truls , Hanøy Kim Richard 
Published: June 2014

Abstract
Severe losses when RIH with 10 ¾ x 9 ⅝" MLT liner in the reservoir on the Troll field was observed in three successive wells. A detailed study to find the cause was undertaken. The only deviation from previous liner runs was a new circulation procedure at 12 ¼ section TD. After re-establing the best practice procedures no further loss incidents have been observed. This paper confirms the need for multi-disciplinary discussions before the drilling procedures are changed.
An Investigation of Different Approaches for Probabilistic Cost and Time Estimation of Rigless P&A in Subsea Multi-Well Campaign
Authors: Moeinikia Fatemeh , Fjelde Kjell Kåre , Saasen Arild , Vrålstad Torbjørn 
Published: June 2014

Abstract
High demand for plug and abandonment (P&A) of subsea wells in the forthcoming years on Norwegian Continental Shelf, low availability and high daily rate of semisubmersible rigs as well as high proportion of P&A cost to total cost of drilling exploration wells challenge industry and intensify looking for alternatives and rigless technologies which can make P&A operation more cost effective and release time of semisubmersible rig earlier. Light well intervention vessels currently can take over some parts of P&A operation and release time of semisubmersible rigs in order to function in drilling and completing of new wells. In addition these vessels have a low daily rate compared to semisubmersible rigs and decrease cost associated with P&A. A systematic yet simple approach is required to acquire a correct picture for expenditure and time of these alternative technologies.
In this paper, potentials and experiences of light well intervention vessels for P&A and benefits associated with them will be discussed. An example case is considered wherein a new technology is deployed from a light well intervention vessel to set surface plugs in a multi-well campaign. Thereafter, benefits associated with application of this rigless technology are discussed and highlighted.
The paper will discuss different approaches for structuring probabilistic time and cost estimation of multi-well P&A campaigns discussing at which level these should be performed and what is the most appropriate approach with respect to modularity and efficiency. This will also be seen in relation to the Oil and Gas UK cost estimation guideline for P&A and the NORSOK technical specification. The objective is to keep the simulations simple while still acquiring the correct range of time and cost for multi-well P&A operation in order to make the proposed approach applicable for the industry.
Development of a Smart Flow Diverter
Authors: Spreckelmeyer Niko , Regener Thorsten , Schwartze Sascha , Clemmensen Carl C. , Eidem Morten , Grindhaug Gaute 
Published: June 2014

Abstract
In liner drilling operations the annular velocity of the drilling fluid drops significantly when it transits from the narrow cross section of the openhole-liner annulus into the increased annular volume between the casing and the drillpipe above the liner. The reduced annular velocity might cause critical hole-cleaning problems that can jeopardize the entire drilling operation and therefore needs to be managed.
To effectively mitigate this problem Statoil (operator) and Baker Hughes (service company) have jointly developed and tested a smart flow diverter (FLD) that can be positioned in the drillstring directly above the liner running tool.
The FLD is designed as a standalone tool that can be placed anywhere in the drillstring and can be used in different applications where enhanced hole cleaning is required, independently of the measurement-while-drilling (MWD) supplier. The tool ultimately must deliver a continuous flow split during the drilling operation, so the main considerations of required features and specifications were carefully reviewed in the early phase of the project:
Unlimited activation/de-activation on demand Failsafe closed No compromising of and interference with normal well-control procedures Direction of flow exit to annulus Adjustable flow split No interference with mud pulse telemetry
The tool is activated either by drillstring rotation and a differential pressure threshold or by a flow pattern signal if string rotation is not possible. Both activations can be incorporated in standard connection procedures, thereby eliminating non-productive time (NPT). This paper highlights and discusses the background for the development, specifications, features and method of activation.
Drilling Technology Taking Drilling Operations to New Frontiers
Authors: Yadav Anurag , Al-Tajar Tammam , Ali Anis 
Published: June 2014

Abstract
Drilling performance on horizontal wells typically drilled in re-entry / workover operation is key for the project to become economically feasible to produce hydrocarbon. Due to presence of a non-linear pressure gradient, a re-entry well-construction design required a casing before entering reservoir and drilling further in a slim-hole. A slim-hole ie 3 7/8″ hole, was not meeting well objectives from logging and completion perspective. Hence, a 5 ½″ x 7″ expandable liner was required to be set in order to drill a 5 ½″ production hole. To accommodate a 5 ½″x 7″ expandable liner, a 6 1/8″ pilot-hole was required to be drilled and enlarged up to 7″; this was historically achieved by a dedicated hole opening trip after drilling a conventional 6 1/8″ because the section was drilling through extremely challenging hard anhydrite layers which were not only hostile towards directional work but were also generating malign drilling environment through severe shocks & vibrations and poor penetration rates (causing lot of tool failures and damages). Since the well design called for high dogleg severity well profiles, motor assemblies were used to drill the well because conventional rotary steerable systems (RSS) were unable to deliver the required directional performance due to unfavorable directional response of the formations. In this operation, an integrated engineering approach was developed to design a drilling system that can simultaneously drill and enlarge hole that lead to successful delivery of a high dog-leg severity well profile without causing any tool failures or mechanical damages. This operation was a first such example in the industry where this drilling system was utilized. The success of the operation relied on selection criterions used for adopting technologies in the BHA and was based on the design process followed to conduct advanced engineering studies. The engineering approach taken in this successful operation highlighted how an innovative application of a truly hybrid high build rate RSS tool had expanded an existing drilling envelope to new frontiers.
Back-Pressure MPD in Extended-Reach Wells - Limiting Factors for the Ability to Achieve Accurate Pressure Control
Authors: Gravdal Jan Einar , Siahaan Hardy , Bjørkevoll Knut S. 
Published: June 2014

Abstract
Extended-Reach Drilling (ERD) with narrow pressure margin or uncertain geo-pressure is a challenge with respect to accurate pressure control. The back-pressure Managed Pressure Drilling (MPD) method has been widely used in drilling operations with the aim of controlling annulus pressure within safe bounds, and may also be applicable for ERD wells. However, the ability to control the pressure accurately is limited by several factors. Some of which are related to back-pressure MPD operations in general and some of which are more specific to ERD wells. In this paper a study is presented on how pressure control is affected and sometimes limited by the actual data availability and quality, equipment, hydraulic models, control algorithms, and downhole conditions during an MPD operation in an ERD well. By using a transient well flow model, the theoretically obtainable MPD performance can be simulated. In particular, the benefit by utilizing real-time downhole pressure measurements transmitted by a wired drill pipe is demonstrated by simulations. It is shown quantitatively how variations in sensor delay and bandwidth will influence the ability to control downhole pressure accurately in an ERD well.
Benefit by this approach is a more accurate prediction of what is obtainable with MPD and how various factors may influence the ability to control downhole pressure.
Wellbore Investigation and Perforation of a Highly Deviated Well Using a Wireline Tractor and Strip Guns Offshore Angola
Authors: Guerra Enrique , Guillory Ryan , Bhattacharyya Biswajit 
Published: June 2014

Abstract
Since the early decades, through-tubing wireline (WL) interventions have been a necessary routine of the oil and gas industry. The practice of well intervention has benefited from the evolution of WL tools on its imposed quest to keep up with the trend of increasing complexity in wellbore and completion development.
Deployment of WL tools through tubing, from early and simple devices (e.g., gauge cutters, lead impression blocks, tubing plugs) to state-of-the-art logging and well intervention prototypes, experienced a significant leap forward with the application of electric line (e-line) tractors in the mid-1990s. Since then, many oil companies have implemented the use of tractors to make a great variety of rigless well interventions feasible, both technically and economically.
Over these lines, WL perforating of long, highly deviated wells through tubing, especially those with relevant ID restrictions, indubitably requires challenging, ingenious, and risked-assessed selection of the most convenient perforating and deployment systems. Working in remote locations, where availability of specialized tools and qualified personnel on short notice are often limited, adds an extra burden to the everyday complexity of operations.
This paper describes the unconventional, but successful, use of a WL tractor to (1) investigate a tubing-conveyed perforating (TCP) completion failure and (2) save the highly deviated "S-shaped" well from a costly offshore rig workover by perforating with a strip gun deployed more than 14,000 ft from surface. The well is located in Angola at a water depth of 1,206 ft.
When BlackOil Approximates Compositional Simulation on Dry Gas Injection - A Case Study in Oseberg Vestflanken Field, Norway
Authors: Xiao-Qian Lin , Meisingset Knut Kristian , Nybø Roger , Espelid Øystein 
Published: June 2014

Abstract
Dry gas injection has been widely practiced across the oil and gas industry. Under this approach, lean gas is injected into the producing formation to attain amongst many others the three key physical responses: (1) Reduction in reservoir pressure depletion (2) Re-vaporization of in-situ condensate dropout (3) Swelling of reservoir oil. All of these reactions could yield to improved hydrocarbon recovery. However, not all of the responses are fully described by standard blackoil simulation. In such instances, compositional modeling is required to provide for accurate estimate of field recovery but at the cost of time and human resources.
Through a field case study on the Vestflanken reservoirs, this paper will reveal the strategy used to evaluate and justify the necessity of compositional modeling in a dry gas injection project. Blackoil and compositional models were constructed with the use of Eclipse 100/300 and the results were compared.
The study has concluded that (1) Pressure depletion was equally well described in blackoil and compositional simulations (2) In the event of short injection time during which the injected gas stream was unproduced, re-vaporization of dropout condensate would not be a dominant recovery process. Blackoil simulation approximates the results of compositional model (3) In saturated reservoir conditions, oil swelling is insignificant.
In addition, the study has also recommended on a workflow that enable the engineers to estimate the maximum impact of condensate re-vaporization on field recovery in the absence of compositional model. By the use of vapor incremental rate function in blackoil simulator, the uncertainty range in re-vaporization rate, which also equates to the key discrepancy between blackoil and compositional simulations on re-vaporization behavior could be quickly established. The magnitude of discrepancy serves to justify the necessity of compositional modeling work thereafter.
An accurate reservoir simulation is important for large investment like dry gas injection. General impression amongst engineers were such that compositional modeling is imminent but this paper has demonstrated a case scenario in which blackoil provides just as good a representation of the fluid behavior as the compositional simulation. It serves as a good analogue and reference for all reservoirs and projects of similar nature.
Tail-In Proppant and its Importance in Channel Fracturing Technique
Authors: Barasia A. , Pankaj P. 
Published: June 2014

Abstract
The channel fracturing technique achieves heterogeneous proppant placement by pumping pulses of proppant laden slurry and clean fluid in alternating sequence. Successful creation of proppant banks in the fracture provides stable channels of infinite conductivity which reduces pressure drop across the hydraulic fracture and enhances production. To date, more than 15,000 fracturing jobs have been successfully placed in various types of formation and completions using the heterogeneous proppant placement technique.
The mechanics of delivering the treatment involves pumping pulses of alternating clean and dirty pulses of fluid with fibers that keeps the proppant in suspension. This is then followed by a continuous proppant "tail-in" stage towards the end of the job before the flush stage. This tail-in ensures continuous proppant bank at the near wellbore region to ascertain good connectivity between wellbore and the channel spaces created during the treatment.
To understand importance and requirement of tail-in, simulations and field execution of jobs with or without tail-in in channel fracturing treatment have been done. Furthermore, a bigger sized unconventional rod-shaped proppants have been also used towards end of the channel fracturing treatments. The unconventional proppants not only helped on such treatments to minimize pressure drop across the tail-in but also helped to reduce proppant flowback in softer formations.
The impact of tail-in on pressure drop and production rates in different formations have been consolidated in this study which provides proppant selection criteria for channel fracturing tail-in stage. Simulation results in shale and sandstone reservoirs and the field treatment case histories comparing the production results for wells completed with and without tail-in in channel fracturing treatment are presented.
Potential Utilization of Geopolymers in Plug and Abandonment Operations
Authors: Khalifeh Mahmoud , Saasen Arild , Vrålstad Torbjørn 
Published: June 2014

Abstract
When a well reaches the end of its life-cycle, it should be permanently plugged and abandoned. Geopolymers have recently attracted attention as potential alternative materials to cement, and hence, have the potential to be used as permanent barriers. This paper presents a brief overview of geopolymers and their chemo-physical properties and how they can be applied to the plug and abandonment (P&A) operation.
To give a better understanding of geopolymers, Class C fly ash-based geopolymers were prepared and examined. Fly ashbased geopolymers were produced by the alkali –activation of the Class C fly ash with an activator solution (a mixture of NaOH and sodium silicate solution). The NaOH solution was prepared at three concentrations of 6, 8 and 10 mol/L and it was mixed with the sodium silicate solution at a mass ratio of 1 in order to prepare the activator solution. The fly ash-C to liquid mass ratio was 1.9, typically producing final densities in the range of 2.44 s.g. In order to investigate the effect of curing temperature on the mechanical property of the obtained geopolymer, specimens were cured at two different temperatures (87 °C and 125 °C) under a pressure of 5000 psi. This work studies the effect of curing temperature and NaOH concentration on the mechanical properties of the specimens. Uniaxial compressive strength (UCS) tests and Ultrasonic cement analyzer (UCA) tests were carried out to measure the compressive strength development of the specimens. Scanning Electron Microscope (SEM) images were taken to study the microstructure of the specimens. Measurements of pH of ground specimens was performed and based on the obtained results pH alters during the curing time. These measurements will found a basis for selecting the correct material for the P&A operation.
A New Benchmark in HPHT Operations: Safe and Successful Well Testing On the Jackdaw Gas Condensate Field in the North Sea, UK
Authors: Shumakov Y. , Williams A. , Hetherington G. , Davidson B. , Whittle T. M. 
Published: June 2014

Abstract
Well Testing for reservoir characterisation and production assessment has always been critical, especially in offshore high-pressure, high-temperature (HPHT) environments. A limitation of technology available for HPHT environments in conjunction with strict safety and environmental constraints elevate the operational challenges over those associated with non-HPHT well testing.
The use of a conventional test separator from well opening in gas-condensate well testing is not straight forward, especially in high pressure wells, due to slugging and rapid and continuous phase changes in the early life of the test. Concurrently, accurate flow rate measurement from well opening is crucial for well test interpretation, and estimation of total recovered well effluent. Well test interpretation of fast reservoir pressure response typically observed in HPHT conditions becomes complex, and thus the pressure change needs to be accurately measured at a high scanning rate by downhole memory gauges. Furthermore, and throughout the duration of the well test, personnel safety and environmental responsibility are paramount, thus emphasizing the importance of up-front planning and application of advanced technology, qualified to maximum anticipated conditions, to eliminate and mitigate the associated risks of HPHT well testing.
This paper describes the unique combination of technology, selection, and qualification process of downhole equipment for long duration and anticipated operation conditions that enabled successful well testing on the high profile HPHT Jackdaw gas - condensate field situated in Block 30/2 & 3, the North Sea. The paper also describes the benefits of using a new generation of well test separator, which is equipped with coriolis meters and an adjustable weir plate for optimum separation efficiency in HPHT environments. It also demonstrates how real-time collaboration of experts at multiple sites via a real-time data delivery system was crucial in acquiring high quality data and providing concurrent feedback to ensure safe and trouble-free well testing operations.