bluuebunny/crossref_metadata_2025_split huggingface dataset:
Full-Scale Laboratory Study of the Impact of Drilling Fluid Composition and Properties on Penetration Rates in Brazilian Pre-Salt Carbonates
Authors: Curry David , Bland Ron , Lourenco Affonso , Lutes Paul , da Fonseca Carlos Eduardo , de Sa Carlos Henrique , Lomba Rosana 
Published: June 2014

Abstract
Full-scale laboratory drilling tests investigated the drilling performance potential of a number of different drilling fluids in three analogue rocks for the pre-salt formations offshore Brazil: Bonne Terre dolomite, Carthage limestone, and Navajo Gold travertine. High-pressure drilling tests were performed in each of these rocks using a total of nine different drilling fluids, including a synthetic-based fluid used as reference for performance comparison.
There was a consistent ranking of drilling fluids in terms of their penetration rate and mechanical specific energy in all three rocks. Several of the fluids tested showed penetration rates ∼50% higher and mechanical specific energies ∼35% lower than those seen with the baseline synthetic-based fluid. There was no clear correlation between good drilling performance and base fluid, rheology, or suspended solids. There was, however, evidence of a correlation between drilling performance and continuous phase viscosity; drilling performance apparently increased as the continuous phase viscosity decreased. This effect is consistent with a hypothesis that filtrate invasion into the damaged rock can relax so-called chip hold-down forces and thereby reduce their negative impact on the efficiency of the rock destruction process.
The results presented here yielded what is believed to be the first evidence that increasing drilling fluid temperature can lead to an increase in penetration rate and a decrease in mechanical specific energy when all other conditions and operating parameters are held constant.
Experiences With an Efficient Rate-Management Approach for the 8th Tortonian Reservoir in the Vienna Basin
Authors: Kornberger Martin , Thiele Marco R. 
Published: June 2014

SummaryActive well-rate management to promote the efficient use of injected fluids and to demote fluid cycling is a simple way to increase recovery in brown fields while minimizing costs and preserving existing field/well-fluid-handling constraints. In this work, we present the application of an efficient flow-based surveillance technique to drive rate-management decisions for the 8th Tortonian reservoir in the Vienna basin, Austria. The 8th Tortonian is a typical example of a decade-long peripheral waterflood on a long, steady decline for which it is difficult to justify expensive drilling/workover programs. Active rate management to improve pattern sweep presents an inexpensive solution to increase recovery. In case of the 8th Tortonian, EUR 10 000 (USD 13,000) was spent to modify well rates, resulting in approximately 5700-m3 (approximately 35,000-STB) incremental oil recovered during a 30-month period. The current oil rate remains higher than the oil rate before the start of the project.Our approach takes advantage of streamline-derived well-allocation factors (WAFs) to quantify injector/producer connections. It is simple and efficient to estimate WAFs with total historical well-fluid rates, well locations, and a geological model. With the WAFs, the ratio of produced oil to injected water (efficiency) of each injector/producer pair can be estimated. Well-pair efficiencies are the starting point for the rate-management approach described in this work.A simple, single-homogeneous-layer system was used in conjunction with historical rates and well locations to estimate the WAFs for the 8th Tortonian reservoir. Connections were compared with available tracer data, and an area of interest was subsequently selected in which both streamlines and tracer data confirmed oil recovery by injected water. A key constraint was to maintain the total gross rate of the area selected at current capacity. New target rates were determined and implemented, resulting in a 30% increase of oil rate during a 30-month period. Considering the simplicity and efficiency of the approach, this is a notable result. The production response of the selected wells showed an increased recovery in conjunction with a relatively constant water cut, suggesting contact with previously unswept oil. All operations and modifications were performed at minimal cost. There were no perforation changes or acidizing jobs involved, and rate changes were obtained simply by changing pump sizes or increasing the number of strokes by changing the V-belt pulley.
Fifteen Years of Expandable-Sand-Screen Performance and Reliability
Authors: Ismail I.M.. M. , Geddes M.W.. W. 
Published: June 2014

Summary
Expandable-sand-screen (ESS), a technology concept envisaged by Shell and initially developed by Petroline, was first field trialed in 1997 with the idea that eliminating the annulus between the sand screen and wellbore would improve downhole sand control and allow enhanced reservoir performance and management. By the end of 2012, ESS was installed in 677 wells, with 418,184 ft of screen deployed globally. As such, ESS has matured as a viable sand-control technology combining openhole-gravel-pack functionality with the installation simplicity of a standalone-screen (SAS) completion.
With performance, reliability, and long-term well life expectancy of paramount importance to field-development economics, an extensive internal installation database has been maintained for Weatherford's ESS systems. Over the past 15 years, observation and analysis of design, planning, field implementation, and useful life cycle have been documented in this database. This performance insight provides the foundation for future reliability and has been used to identify learning opportunities, influencing the product evolution and technology-application envelope.
With performance and reliability analysis provided and discussed in detail, the applicable ESS envelope is outlined. Product-design enhancement, methodical application evaluation, and rigorous operating procedures result in improved successful use. Analysis of both infant and production failure trends are presented and show improvement. These data are used to estimate future life predictions by use of recognized reliability-analysis tools. The applicability of ESS in openhole wells is highlighted, with continuing performance in oil producers, gas producers, water injectors, and underground-gas-storage applications. There are various sand-control technologies successfully used in reservoirs around the globe. This study outlines the applicable envelope for ESS use, providing insight to enable informed evaluation, life-of-well risk appraisal, and, ultimately, reliable sand-control-completion selection for existing or new field-development appraisal.
Next Step in Offshore Heavy Oil - Mariner Reservoir Development
Authors: Berg Eirik A. , Silcock Simone , Østbø-Bjåstad Bodil 
Published: June 2014

Abstract
Mariner is a large heavy oil discovery in block UK-9/11, located 320 km north east of Aberdeen. The execution and development of the project will be from Statoil's new Aberdeen office. The discovery contains 1–2 Billion Barrels of Oil in Place in two reservoirs (Maureen and Heimdal). 19 appraisal wells have been drilled. The oil viscosities are 67 cp (Maureen) to 508 cp (Heimdal) at reservoir conditions. Production start is in February 2017. The reservoir development is based on use of re-injected produced water. ESP pumps are used for artificial lift. In total 100 wells are planned including multilateral slanted wells and horizontal wells. Two drilling rigs and one work-over rig will be active in parallel the first 4 years. Challenges to be met are related to high oil viscosity which gives early water breakthrough and mapping of remobilized Heimdal channel sands. The available seismic only allows for a stochastic Heimdal reservoir model. A full field broadband seismic survey will be available in 2013, applying the newest advances in technology to aim at better imaging the Heimdal sands. Current development strategy for the Heimdal reservoir is pattern drilling using an inverted 9-spot pattern. The work going forward will focus on use of the new seismic data to establish a deterministic reservoir model to be used for well planning. Work is on-going to significantly optimize the Heimdal development. Active geosteering will be important to limit the use of pilot holes and improve Heimdal reservoir sand mapping. The reservoir simulation model is very computer time consuming. Coupled segment models have been constructed that replicates the full field simulation but with significant reduction in simulation time. A polymer flooding study has been initiated to realize the EOR potential.
An Improved Approach to Simulate Low-Permeability Fractured Reservoirs with Dynamic Hybrid Dual-Porosity Model
Authors: Li Xiaobo , Wu Shuhong , Li Qiaoyun , Li Hua , Wang Baohua 
Published: June 2014

Abstract
For traditional dual porosity/permeability model, the fracture system is assumed to remains a steady state which the width, length, density of the fractures in reservoir does not change during the whole production, and it is not possible to simulate fractures variation effect with these models. Hower, the above assumption does not hold in low permeability fractured reservoir where the fracture system will change with the formation pressure.
In order to simulate the unsteady state of fracture system, an improved approach to simulate low-permeability fractured reservoirs is proposed in this paper which a dynamic transitivity tensor model is overlapped to dual porosity model. It is assumed that the fracture network is the primary continuum for fluid flow, and the matrix of high storability is considered to be a sink or source to the fracture. In this approach, the fluid exchange between the matrix and the fracture is expressed by an exchange term, and the variation of fractured system is described by dynamic permeability, which is a function of pressure, stress, density of fractures.
The paper will detail the dynamic hybrid dual-porosity model such as its assumptions, equations, mechanisms and also its applications in the fractured reservoirs simulation. The simulation results show that the dynamic hybrid model has high potential to accurately simulate the dynamic fracture network for low-permeability resevoirs.
Improving the Operational Life of Riser Line Seals and Telescopic Joint Packers
Authors: Örjasaeter Oddvin , Delhaye Virgile , Haukenes John , Solberg Stian , Björneklett Borge 
Published: June 2014

Abstract
Dynamic seals for drilling risers have in some cases shown unpredictable performance – especially under demanding conditions. In future the "nice wells" will diminish in number and the challenging HT/HP and complex drilling situations will be the focus for future developments in the Middle East in particular and also worldwide in general.
The paper will present novel findings and development of full-scale testing of seals and packers: Short term damage (e.g. mounting), long term cyclic deterioration, materials applied, and differences between various seal types and produce are included.
The investigations quantified the relative importance of operational parameters and constraints on seals performance in full-scale seal tests. The results will used in the future developments of seals for demanding field environments.
Impact of Well Completion on the Uncertainty in Technically Recoverable Resource Estimation in Bakken and Three Forks
Authors: Ganpule Sameer , Cherian Bilu , Gonzales Veronica , Hudgens Paul , Reyes Aguirre Pascual , Mata Domingo , Olarte Diana Paola , Yunuskhojayev Alisher , Moore William Ray 
Published: June 2014

Abstract
The Bakken formation ranks as one of the largest oil developments in North America in the past 40 years. Various estimates place the total resources (recoverable and non-recoverable) with today's technology, from 2 to up to 24 billion barrels of oil (BBO). According to the North Dakota Industrial Commission (NDIC) there were 6,884 horizontal wells by end of 2012 in North Dakota with majority of these wells completed in the Bakken formation. The main target for exploitation has been the middle Bakken siltstone member which is sandwiched between Upper Bakken Shale and Lower Bakken Shale. However, targets below Lower Bakken Shale have shown commercial production notably from the Three Forks benches and sporadically occurring Pronghorn member. The close proximity of these targets coupled with the need for hydraulic fracturing, introduces uncertainty in the "source" of oil production in wells and hence in technically recoverable resource forecasts.
In this paper, we discuss models built to replicate well performance under various completion configuration and depletion pattern to demonstrate the challenges in estimating technically recoverable resource early in to the life of a well or group of wells. These challenges may arise from the stimulated reservoir volume (SRV) not contained within a single reservoir but straddling more than one reservoir at a time. Connectivity between multiple reservoirs and the wellbore may vary with time due to change in stress contrast related to fluid production or by hydraulic fracture conductivity degradation; such varying connectivity can further complicate production allocation from multiple reservoirs. A lack of understanding of SRV distribution and subsequent drainage from multiple reservoirs may lead to significant uncertainty in technically recoverable resource estimation - especially when using short-term production data.
This paper also highlights the effects of completion interference between a well and its infill offsets on uncertainty in estimating technically recoverable resource. We intend to emphasize the issues previously mentioned to the broader audience with the intention to promote further technical discussion on the role that well completion plays in resource evaluation of unconventional plays such as the Bakken Shale.
Stimulation Lab Tests to Increase and Maintain Well Production: Field Cases
Authors: Arevalo-Villagran J. A. , De Antunano-Munoz Y , Pumar-Martinez F. , Lysandrou-Costa M. 
Published: June 2014

Abstract
This article presents the development of laboratory tests and workflow methodologies at Pemex E&P to identify the type and mechanism of formation damage arising during the production life of oil and gas wells in carbonate and sand formations. More than 130 workflow procedures were designed and developed for matrix stimulation and fracturing treatments at Pemex E&P from 2006-2012 and, as a result, a 413% production increase was achieved, highlighting the importance of developing the TIDP (Tests to Identify Damage Type) laboratory test methodology, which may be applied throughout the life cycle of a well. To test the methodology, it was first applied to 100 fluid samples taken at the surface and at the bottom hole of oil wells in which the productivity had decreased, with the following results: 75% of the damage was from stable emulsions formed by oil, water and solids, 20% was from organic deposits, and 5% from inorganic deposits. The TIDP methodology was also applied to completion wells, analyzing 50 fluid samples taken mainly at the bottom hole, and indicated that 85% of the damage was a result of mud emulsion + solids + brine + well fluids, 10% resulted from mud emulsion + solids + well fluids, and 5% from mud emulsion + well fluids. Once the damage types and location in the reservoir and well production system were identified, 40 candidate wells were selected and treatment types were determined, depending on the laboratory test results and the formation type. From these 40 wells, it was concluded that through the identification of the damage types and mechanisms that were obtained with the methodology, it was possible in the short term to achieve 30-400% production increases in these wells and economic benefits of more than $2 million USD per day.
Multivariate Analysis of Job Pause Time Data Using Classification and Regression Tree and Kernel Clustering
Authors: Maucec Marko , Singh Ajay , Bhattacharya Srimoyee , Yarus Jeffrey , Fulton Dwight , Orth Jon 
Published: June 2014

AbstractThe well treatment program is an important part of the field development plan, and certain variables, such as job pause time (JPT), can affect its efficiency. JPT is the time during which pumping is paused between subsequent treatments of a job. The objectives of this work are to investigate whether, from existing data, it is possible to find patterns in significant variables that affect the extreme values of JPT in a particular region. The answers are sought by applying a classification and regression tree (CART) to both categorical and continuous variables in the database. The practical application of CART is presented using case studies first using classical CART analysis, then using CART analysis with enhancement tools such as the normal score transform (NST), and then dividing the large dataset into smaller groups using clustering. Significant variables are found that affect the response variables, and predictor variables are ranked in order of their importance. Such information can be used to control predictor variables that cause high JPT.The results are outlined in an intuitive way, including categorical, continuous, and missing values. Because CART is a data driven, deterministic model, we cannot calculate the confidence interval of the predicted response. Confidence in the results is purely based on the historical values, and the accuracy of the result produced by a tree model depends on the quality of the recorded data measured in terms of volume, reliability, and consistency. The prediction capability of CART is enhanced by the use of NST and clustering techniques. The approach presented in this paper analyzes a dataset with limited information and high uncertainty and should lead to developing a method for generating proxy models to find future success indices (e.g., for drilling efficiency or production from a fracture). This could standardize stimulation and generate decision ‘best practices’ to save costs in field development and the optimization process.
Knowledge Intelligence (ki)
Authors: Saxby D.. , Burridge G.. 
Published: June 2014

Abstract
Despite huge capital investment and over a century of experience, oil and gas companies are facing huge challenges in terms of the governance of their own expertise and knowledge. This challenge is exacerbated by the Big Crew Change, technological revolutions and high technical staff mobility.
For an industry such as Upstream Oil & Gas, harnessing all that the organisation knows and is capable of is a significant and pressing management priority. While the industry has dealt with the Information Age, it has yet to master Knowledge.
In this paper, we outline a methodology to benchmark a company’s maturity in this key aspectof organisational effectiveness through a parameter we call Knowledge Intelligence (Ki), measures of wealth of indicators in business process, technology and people performance within the organisation are all in this process. We use the measurement of Ki to map out solid implications for innovation, risk reduction and certainty augmentation, and ultimately, for organisational performance.
We illustrate this through a theoretical scheme showing the sequential importance of how Ki is built up from first principles of governance of data, information and knowledge and its mastery and the fact that its value derives from a systematic attention to all aspects of the Ki enhancement cycle.
To demonstrate the practical use of this methodology, we provide a case study of Ki for several different example organisations and the effect it has on their strategic KPI’s of risk, uncertainty and value generation.
The opinions represented in this paper are those solely of the authors and this work has been carried out independently of their organizations.
Innovative Solution to Produce Intelligently From a Multi-zone Gravel-packed Completion With a Multi Drop Hydraulic Module First in Offshore Malaysia
Authors: Mohammed Tawfik M. E. , Mohd S.. , Ogbonna C.. , Ahmad A.. , Raw Ian , Goh Gordon , Kaka Singh P. K. 
Published: June 2014

Abstract
The "M" field is located offshore East Malaysia, with a major lateral fault separating the field into North and South. The south area main reservoirs are I, K and L with strong water drive and highly unconsolidated formations. These reservoirs contain approximately 200 MMSTB STOIIP with a current recovery factor of 24%. The major challenges in this field are (1) high well deviation, (2) sand production and (3) early water break-through.
In order to dynamically mitigate these challenges, a pilot well with intelligent well technology was considered for one of the new highly deviated infill wells which targeted 3 producing zones. A combination of cased-hole gravel-packing and open- hole stand-alone screens (SAS) was installed at the reservoir sections.
This Intelligent Completion IC system is equipped with innovative multi-drop hydraulic modules. The first IC system, successfully installed 2 years ago in 2 wells of an offset field pilot, has had a significant impact on production to date. These systems used the conventional control line configuration of an N+1 system, where N = the number of zones to be completed. However, the newly installed IC system provides an engineering solution to reduce the required number of control lines from 4 to only 2 to control 3 zones, i.e. an N-1 control line configuration.
This innovative solution was essential to the project to avoid modifications to the wellhead due to the short lead-time before the installation. This solution also reduced the installation time compared to the first edition of the IC system.
This paper highlights the screening process for candidate selection and the successful installation of IC system in multi stack reservoirs with gravel pack assembly and also the lessons learned from the full collaboration between the project team and service provider.
Areal Field Surveillance – Applying The Right Solutions For Each Asset
Authors: Engbers Peter , Zwaan Marcel , Grandi Samantha 
Published: June 2014

Abstract
As part of Smart Fields, deployment of surveillance solutions adds a lot of value to further field development and well and reservoir management by providing insight into the reservoir behaviour and therefore enabling timely decisions. Solutions need to be tailored for the specific field, production type, purpose, or environment. We have developed a framework to ensure that we deploy the right Field Surveillance solutions for each type of field and asset.
In this paper, we describe how we screen, decide applicability, and deploy integrated Field Surveillance solutions for the Shell portfolio. As guidance, we make use of a newly build Solutions Advisory. This advisory, for example, highlights which solutions are standard in which environment, meaning that you would have to justify why not to implement. We will describe how this assessment and deployment works with a field example from an onshore EOR field. Substantial value has been added as a result of the optimized, fit for purpose surveillance program, linked to a decision-logic with identified control measures.