bluuebunny/crossref_metadata_2025_split huggingface dataset:
Successful KCl-Free, Highly Inhibitive and Cost-Effective Water-Based Application, Offshore East Kalimantan, Indonesia
Authors: Huadi F. , Aldea C. , Mackereth B. , Mukhlis T. 
Published: February 2011

Abstract
Historically Total E&P Indonesie, operating offshore East Kalimantan (Indonesia), has used a 12 to 14% KCl/polymer water-based drilling fluid to drill the intermediate hole section. Excessive hole washouts requiring significant cement volumes to properly cement the casing have been noted. Another drawback to the standard KCl/polymer system is that general hole conditions related to torque/drag and excessive time tripping in and out have affected overall efficiency. Additionally, with the necessity to maintain mud density not greater than 1.15 SG (9.6 lb/gal) for this intermediate section, significantly large dilution rates have been required while drilling with the KCl/polymer system. There was a need to improve the drilling fluid which led to the successful introduction of a novel polyamine clay hydration suppressant as a KCl alternative in this area.
Novel polyamine at 2 vol% has been used as alternative to 12 to 14 wt% of KCl. The polyamine significantly improved the clay/shale inhibition with a noticeable improvement in cuttings integrity observed across the shale shakers. Seawater with 5 to 8 wt% of sodium chloride (NaCl) was used as the base fluid for the system. The system was easy to engineer and easy to maintain at rigsite. A combination of xanthan gum and polyanionic cellulose (PAC) was used to provide the required rheology and fluid loss control in the system. There was no specific addition and handling of mixing facilities for this system.
After initial trials on 3 wells, the decision was made to replace the KCl/polymer system with this new inhibitive system as the “fluid of choice” for water-based drilling fluid sections. The system has now been selected as an alternative to KCl in offshore operations East Kalimantan, Indonesia.
To date, a total of 15 surface and intermediate sections of 12 wells have been drilled, cased and cemented successfully in Offshore East Kalimantan, Indonesia using this novel polyamine system. Dilution rates were significantly reduced by about ⅔ as compared to dilutions rates using the KCl/polymer system.
Reservoir Souring in a Field With Sulphate Removal: A Case Study
Authors: Robinson Keith , Ginty William , Samuelsen Eivind , Lundgaard Thomas , Skovhus Torben Lund 
Published: February 2011

Abstract
This paper presents the results of a reservoir souring study in Hess' South Arne field (North Sea, Denmark). The field produces from a 115°C chalk reservoir and utilizes sulphate rejection membrane (SRM) technology to generate low-sulphate seawater (LSSW) for water injection.
In addition to achieving the primary objective of barium sulfate scaling control, eight years of historical data show that the injection of LSSW also significantly reduced the severity of reservoir souring to levels acceptable for continued use of the existing wells and facilities from a corrosion and gas handling point of view.
This case study is especially important information for deep sea oilfields where high-strength steel risers, which are susceptible to sulphide stress corrosion cracking, are utilized and where installation of SRM units can be a significant part of a viable souring mitigation strategy.
In November 2008, an innovative and successful water shut-off operation was performed for oil producer Well-L and production was commenced after a 2 year shut-in. Three weeks later, an unexpected H2S alert was experienced during oil export to a tanker. A follow up H2S survey indicated up to 15 ppm in the bulk gas and in excess of 35 ppm in gas from Well-L. A comprehensive study was therefore initiated to fully understand the causes of souring and to develop a new H2S management strategy to deal with the issue.
Analysis of produced water and H2S concentrations in oil, water and gas was used to generate mass balances of sulphate and sulphide for the reservoir and production system. Analysis of the sulphur isotopes in H2S was made together with a review of the historical H2S scavenger usage and pre-water injection well-test H2S measurements. This showed that reservoir souring was the dominant H2S source and that a significant proportion of the sulphate introduced to the reservoir by the injection water was converted to H2S.
Molecular microbiological methods (MMM) showed high concentrations of sulphate-reducing archaea (a group of thermophilic microbes producing H2S, but genetically very different to sulphate-reducing bacteria) in produced fluids, while traditional most probable number (MPN) techniques gave zero readings.
Microbiological sulphate reduction may minimize the field's barium sulphate scaling risk by reducing sulphate concentrations in the injection water below those achievable by South Arne's SRM equipment alone.
Equipment Design Change Improves Cementing Operations from MODUs Operating in Rough Sea Environment: Case Histories for Two North Sea Jobs
Authors: Romstad T. H. , Rogers H. E. , Saetre T. 
Published: February 2011

Abstract
During the well-construction phase in the oil and gas industry, cementing materials are used to provide annular isolation between the casing and the wellbore. The methods and equipment used to place cementitious fluids in the annulus have evolved significantly over the last several decades. One specific area where significant changes in placement methods and equipment have occurred is in the offshore environment; specifically, cementing operations from mobile offshore drilling units (MODUs). The benefits of traditional inner-string cementing (ISC) methods have not been available to operations in rough seas from floating platforms where the ocean swells exceed the capabilities of the compensators on the rig. As such, new equipment designs are needed to enable use of the inner-string cementing method from MODUs operating in rough seas.
This paper details the problems encountered when attempting inner-string cementing operations from floaters operating in the North Atlantic and newly designed equipment that enables MODU operators to benefit from the successful use of inner-string cementing methods in rough seas. Three case histories are presented that validate the successful use of the newly designed extended-length ISC equipment from a mobile platform operating in rough seas.
The Evolution of the Role of Openhole Packers in Advanced Horizontal Completions: from Optional Accessory to Critical Key of Success
Authors: Gavioli Paolo , Vicario Roberto 
Published: February 2011

Abstract
Openhole packers have been proven to be very effective in many different applications, including curing losses, controlling high-permeability zones and fractures, improving equalization in passive and active inflow control device (ICD) completions, and, most importantly, controlling water and gas production. The usage of these tools increased exponentially in the last few years and will continue to grow. This paper summarizes the most important findings and lessons learned about the role of zonal isolation in advanced horizontal completions.
More than 12 years of experience using reservoir-optimized completions, including passive or active ICDs and openhole packers, has led to the accumulation of best practices and rules of thumb. The approach for openhole packers has changed markedly with time, along with the industry learning about the importance of these tools in advanced horizontal completions.
Important considerations have been generated to design horizontal completions under different fluid properties, reservoir uncertainties, and optimum operational considerations allowing for equalization of flow along the entire length of the horizontal section. These best practices came from extensive run history and lessons learned and it has been found that openhole packers often play the most critical role for a completion’s success. In addition, the availability of a wide range of new zonal isolation tools on the market makes it easier for operators to obtain the best and most cost-effective solution for each application.
Openhole packers for compartmentalization are key for success in many applications and offer benefits for inflow and annulus flow control. An extremely important consequence is the ability to control gas and/or water after breakthrough. This has been proven from analyzing a significant amount of production logs post-installation. Actual well performance data and simulations will be shown to support the discussion and illustrate concepts and findings.
Simulation of Dragon Wells in Thin Oil Rim Reservoirs Using a Segmented Inflow Approach
Authors: Montero Jacobo , Nwankwo Cosmas 
Published: February 2011

Abstract
A study was carried out to establish the performance of a dragon well, or a well that dramatically changes inclination, in a thin oil rim reservoir. A well was simulated using commercial nodal analysis software by segmenting the inflow in multiple sections in order to incorporate the changes in trajectory and intersections with various reservoir layers. This simulation considered the pressure losses along the well bore for the varying trajectory, calculated for individual well sections, layers and combined commingle productivity and pressure profile; and was used to evaluate the well performance for a range of reservoir conditions (depletion, gas-oil ratio and water cut changes). This paper describes the approach used and key observations obtained from the results.
A "segmented" inflow simulation approach can be used to model a dragon well. The method can be applied for modelling wells with sinusoidal trajectories in thin oil reservoirs. The results can be used to guide well and reservoir modellers in the concept assessment of this type of wells in field development studies. The model calculates the segment, layer, and total inflow and pressure profile in a complex trajectory. For the field and reservoir characteristics considered, the simulation indicated that the dragon well can produce through a wide range of conditions, including gas and water break-through. Good initial productivity can be expected from the well, but deteriorates fast with increasing GOR and water cut. As expected, the drawdown is not uniform along the trajectory; hence a drawdown stabilization strategy was addressed for the subject well through the use of a smart well completion. There is limited industry experience on sinusoidal or dragon wells modelling hence the results of the paper should be of interest to production technologists and reservoir engineers. This documented methodology can also be extended to simulation of complex horizontal or multilateral wells.
An Automated System for Determining Analog Formations for Unconventional Gas Reservoirs
Authors: Kun Cheng , Wenyan Wu , Holditch S. A. , Ayers W. B. , McVay D. A. 
Published: February 2011

Abstract
Today, many countries are evaluating unconventional gas resources, which are estimated to exceed 30,000 trillion cubic feet, worldwide. Owing to declining conventional gas production, the U.S. has led the world in development of unconventional gas resources (UGR) and technology over the past 3 decades. To facilitate transfer of unconventional gas technology and development internationally, we developed a software, FAST (Formation Analog Selection Tool), as a tool to objectively and rapidly identify and rank analog formations. FAST software uses an existing database (BASIN) that contains geoscience and engineering parameters for approximately 240 formations in 25 North American basins that are mature for conventional and unconventional oil and gas production. We designed a FAST report module that provides both general and detailed interpretation graphs and tables. FAST reports give an overview of analog results, and they allow insights into the quantitative details of reservoir parameter comparisons. Although the software needs further validation, preliminary testing shows consistent results. Planned and ongoing improvements to FAST include quality checking of formation parameters in the database, assessment of parameter weighting factors, validation of the analog selection performance against the literature and independent studies regarding analog formations, and linkage of FAST with a Drilling & Completion Advisory System to identify the best engineering practices to be applied in early stages of testing analogous target formations.
Sand Erosion Modelling
Authors: Wong Chong , Wu Jie , Zamberi Amir , Solnordal Chris , Graham Lachlan 
Published: February 2011

Abstract
Influx of sand into gas or oil pipelines is often experienced in offshore oil & gas fields. Erosion on pipelines, screens, throttle valves and other pipe fittings by sand particles is a concern to the safety and reliability of operation of the oil & gas infrastructure. To avoid potential erosion during operations, it is beneficial to optimise the design and operational parameters to minimise the erosion rate. It is therefore highly desirable to predict the erosion damage by sand particles through modelling.
Particle erosion modelling is complex and requires a good understanding of the dynamics of particles – specifically, the particle velocity and impingement angle, and its relationship to the removal of material at the equipment surface (e.g. pipe). CSIRO Australia has developed a comprehensive modelling approach utilising laboratory testing in parallel with computational fluid dynamics (CFD) simulations to determine the erosion rate for a given flow geometry, fluid-solid flow condition, material properties and erodent characteristic.
This paper presents an overview of CSIRO's laboratory modelling and testing methods for erosion damage assessment for design optimisation. A method to calibrate a CFD erosion model is presented, and a rapid laboratory visual erosion approach employing a multi-layer paint erosion modelling is also introduced.
Years of Success with Premium Expandable Screens System through Managed Applications and Installation
Authors: Ripa Giuseppe , Bowen Eddie G. , Conte Antonio 
Published: February 2011

Abstract
Since the inception of expandable sand screen technology in the late 1990's, it has seen its ups and downs during its inaugural and acceptance phase. Expandable premium screen technology has seen in recent years an increase in the number of applications in several oilfield typologies. From high rate gas producers to Oil production up to the most challenging gas storage application expandable screens have shown to be a reliable completion for a variety of well types.
As with any new technology there were lessons learned. This knowledge led to the fine tuning of the entire system and required adjustments to the operation procedures and design parameters in order to improve its reliability. The ultimate goal of any technology is to reduce operational cost, maximize productivity, and deliver a reliable completion for many years to come.
After several years of activity, it is now possible to provide a summary of experience in several different applications. The quantity of Expandable Premium screen installations to date supply the opportunity to statistically evaluate the success of this technology but also provide significant operational experience.
The objective is to go through the data base of installations owned by operator and Service Company and provide a Best Practice handbook used not only to optimize deployment and operations but also to increase productivity and improve well longevity. Through the evaluation of several expandable premium screen applications it will describe how starting from conventional sand control techniques the operating procedures have been refined, modified and improved to meet the requirements that the new technology requires for successful execution.
Understanding the Effects of Leak-off Tests on Wellbore Strength
Authors: Wang Hong (Max) , Soliman M. Y. , Shan Zhaohui , Meng Frank , Towler Brian F. 
Published: February 2011

Abstract
Leak-off tests (LOT) are performed to test the "strength" or pressure containment of the shoe after a cement job to help ensure the new hole has been securely isolated from what has been cased off. A successful LOT can also be used to calibrate the least principal stress, or many times the minimum horizontal stress, for geomechanics modeling. This will require initiating a fracture at the wellbore. Due to the near-wellbore stress concentration, for the geomechanics calibration purpose, it is preferred to take the leak-off to the far-field stress region. To perform this extended LOT (XLOT) a relatively long fracture has to be created. Though an XLOT is needed for these reasons, some engineers tend to refrain from performing this test for fear that the test may damage the wellbore and consequently cause drilling problems.
This paper addresses this issue by investigating the effect of wellbore damage on wellbore "strength" or pressure containment. Various issues are discussed to help engineers determine when it may or may not be a concern. This should give practicing engineers the necessary insight into this complex rock mechanics issue. The discussions are supported with results from analytical and numerical simulations based on rock mechanics principles.
Nano-emulsions as Cement Spacer Improve the Cleaning of Casing Bore During Cementing Operations
Authors: Maserati G. , Daturi E. , Belloni A. , Del Gaudio L. , Bolzoni S. , Lazzari W. , Leo G. 
Published: February 2011

Abstract
Nano-emulsions are emulsions where the droplet size of internal phase is less than 500 nm. Due to their small dimensions they have a high surface area and show very peculiar properties. Solvent in water nano-emulsions combine the high efficiency of the small dimensions of solvent to a low interfacial tension, due to the presence of the surfactant mixture used to prepare nanoemulsions. Solvent in water nano-emulsions used as cement spacer formulation could allow optimizing the cleaning of the casing during the cement job with a high improvement of the performances of the spacers currently in use. This methodology, based on high efficiency system with reduced chemical dosage, could also result in a considerable optimization of product cost of cement operation. The objective of this study has been the formulation of direct nano-emulsions (o/w), with a selected solvent as internal phase, in order to improve the casing - open hole cleaning and reverse the surfaces wettabitlity to allow better adhesion of slurry between casing and hole.
Specific laboratory tests have been carried out to compare commercial spacers currently used in common drilling practice with nano-emulsions formulated in Eni Laboratories. Different nano-emulsions were performed in function of solvent content.
The nano-emulsion efficiency was evaluated throughout different methods: Metallic Grid Test, Wettability Test, Contact Angle, Shear bond test. All tests highlight good cleaning properties of nano-emulsions and their better efficiency compared with common spacers.
Impact of Fracture Conductivity and Matrix Relative Permeability on Load Recovery
Authors: Gdanski Rick , Walters Harold 
Published: February 2011

Abstract
The cleanup of fracturing treatments in tight-gas sands has been a subject of focus because of the disappointing performance of many treatments. A fit-for-purpose fracture-cleanup simulator was used to explore factors that might impact cleanup. The simulator includes physics of flow and chemical physics of overall complexity that cannot be effectively studied in the laboratory. Numerical simulations were conducted to study the impact of dimensionless fracture conductivity (Fcd), matrix relative-permeability quality for gas and water, and shut-in times on load recovery after a treatment. Simulation results included the impact of these various factors on gas production rates, total load-recovery volumes, and fracturing-fluid dilution profiles. Three sets of relative permeabilities (rel-perms), four Fcds, and various shut-in times were studied.
Numerical simulations demonstrated the complex interactions of fracture conductivity, matrix rel-perm quality, and shut-in on load recovery and gas productivity. The results gave insight into preferred procedures and practices for cleaning up fracturing treatments in tight-gas sands. Gas-production rates and load recoveries were strongly affected by conductivity and matrix rel-perm quality. Rel-perm sets with a crossover at 10% of rel-perm exhibited good load recovery at high Fcd and poor recovery at low Fcd, with gas-production rates dominated by Fcd alone. A crossover at 0.1% of rel-perm exhibited slow recovery of fluid and slow improvement in gas rates, with peak rates not occurring for months. Extended shut-in times reduced load recoveries for high-quality rel-perms the most. Fracturing-fluid dilution profiles were observed to be a function of both Fcd and rel-perm quality.
This work demonstrates that an arbitrary choice of matrix rel-perms for water and gas can result in prediction of either good or poor load recovery, depending on the quality of rel-perms chosen. In fact, variation in rel-perm quality from reservoir to reservoir might help explain contradictory observations on best practices regarding shut-in times.
Benefits Evaluation of Deepwater Intelligent Completion on Three Isolated Productive Zones Offshore Nigeria
Authors: Arena M. , Di Vincenzo S. , Rossi M. 
Published: February 2011

Abstract
This paper describes the experience and advantages of both the operator and service company in using Intelligent Completion (IC) technology in deepwater challenging environment. Following a feasibility and risk analysis study performed by the operator, a single well with a triple zone the IC was selected as the best completion solution compared to a dual zone or single wells cluster solutions. The increased cost of this technology was justified by the overall CAPEX project reduction, increment of expected cumulative production and anticipated reservoir's lower layers production.
While two zones IC can be completed with the flow control valves run above the gravel packed zones, the same cannot be done in triple zone IC; in this case, to allow fully independent zonal monitoring and control, two out of three of flow control valves and gauges needs to be run inside the lower zone gravel pack assemblies, bringing a complete new set of interface challenges between the upper and lower completion equipment.
Equipment and procedure's risks were addressed and mitigated through Failure Mode and Effects Criticality Analysis (FMECA) reviews and completion System Integration Test (SIT).
Flow control valve's choke design were also checked, based on the expected production profiles and downhole PVT, to cover the entire production rate and achieve the best draw down applicable.
The well was completed across November and December 2008 with no incident and lost time and the completion solution adopted proved not only to solve all the initial reservoir challenges but also to reduce the number of well interventions, workover costs and risk. The well was successfully started up in February 2009 with a NPV increment of 15% and a reservoir recovery factor increase of 6%.