bluuebunny/crossref_metadata_2025_split huggingface dataset:
First Installations of the 9-5/8-in. Enhanced Single-Trip Multi-Zone Sand Control Technology in Offshore Brunei
Authors: Fourie Bernard , Marpaung Billman , Jansen Rene , Wong Andrew , Mok David , Karlsey Narmesh Singh 
Published: October 2012

Abstract
Brunei Shell Petroleum (BSP) operates the mature South West Ampa (SWA) and Bugan Fields in Brunei Darussalam. The fields, located 10 to 21 kilometers offshore Brunei in water depths ranging from 10 to 40m, are major sources of oil and gas production. Controlling sand production is a key completion challenge as the reservoirs are composed of multilayer unconsolidated sands, requiring sand control for safe production. Cased-hole, stack-pack systems were considered as the default solution for shallow reservoir zones and wells. Due to the reduced production rates in some reservoirs in the fields and increasing rig costs there is a demand to improve the cased-hole gravel pack efficiency.
The wells require zonal isolation and sand-control treatment. Cased-hole stack packs have been a reliable completion method, due to their capabilities for better zonal isolation and multi-zone functionality. Due to the reduced production rates in the mature fields, however, wells were no longer considered economically feasible. Therefore, BSP decided to try a new 9-5/8-in. enhanced single trip multi zone gravel pack system. This system appeared capable of providing significantly greater cost efficiency than conventional cased-hole stack-pack systems, which would make the marginal wells profitable.
This paper describes the 3 wells completed by BSP in 2010 and 2011 using the enhanced single trip multi zone gravel pack system. For the 3 wells, a total of 10 zones required a sand control treatment. The paper also will describe why the enhanced single trip multi zone gravel pack system was chosen and will discuss the wellbore configuration, the implementation, and other field possibilities for the system. Finally, the paper will discuss the "best practices" learned from the first enhanced single trip multi zone gravel pack system installations; the challenges encountered during the job execution, and also, will compare the enhanced single trip multi zone gravel pack system with the conventional cased-hole stack-pack system to highlight the advantages of the new system.
Intelligent Well Type and Optimum Completion Designs for Complex, Multi-Stacked, Compartmentalized, Oil-Rim Reservoirs
Authors: Masoudi Rahim , Jiew Danny Chong , Karkooti Hooman , Othman Mohamad B. , Chan Keng Seng , Finley Douglas 
Published: October 2012

Abstract
In the quest of improving the hydrocarbon recovery and reducing the development cost in the challenging multi-stacked compartmentalized fields as well as oil rim reservoirs in Malaysia, well type and completion design was found to play a major role. Intelligent well design and completions, namely multi-lateral, selective and controlled injection and depletion, dynamic active flow control valves and down-hole pressure/temperature/composition monitoring have been identified as an essential component in the enhancement of the development strategy. Smart/intelligent completions have the ability to prevent/delay water or gas breakthrough, increase the productivity index and also to properly control drawdown to mitigate wellbore instability, sand failure and conformance issue. Active flow control valves also allow for fewer wells to be drilled by enabling efficient commingled injection and production wells. Moreover, with down-hole monitoring and surveillances, unplanned and challenging work-overs can be avoided, further reducing operating costs. The study also focuses on well architecture that entails well type selection, well reservoir penetration, well inclination and orientation, well completion simplification, well placement and well-count optimization.
In this paper, examples of mature complex multi-stacked and compartmentalized reservoirs with very thin to thick oil columns have been studied for improving the development and exploitation strategies through application of intelligent well type and optimum completion design and engineering. The suggested technology tool box including the applied workflow, guideline, procedures and standards with the field examples and desired results are to be presented and discussed. The study will cover from the assessment to the implementation and execution as well as the modeling methodology of the smart well technology on the selected fields in Malaysia.
Well Des gn and Well Spacing Optimisation in Unconventional Plays
Authors: Baker M. , Mazumder S. , Sharma H. , Philpot J. A. , Scott M. , Wittemeier R. 
Published: October 2012

Abstract
The risk profile for an unconventional resource play differs from a conventional opportunity in that the producibility, per well Estimated Ultimate Recovery (EUR) and Unit Technical Cost (UTC) are more important for identifying potential success than proving the presence of in-place volumes.
Unconventional plays are often characterised by a large number of wells, lower density of subsurface data, large geographical extent and corresponding large range of uncertainty in subsurface parameters. The rapid economic screening of well design and spacing parameters for multiple subsurface realisations is integral in the planning stages of large unconventional plays. An additional complexity is the use of horizontal or complex geometry well designs which may limit or complicate the application of full field reservoir simulation methods.
Recoverable volumes are strongly dependent on the proposed well design and spacing. These should be systematically evaluated and optimised by identifying the well density beyond which the incremental recovery and commerciality benefit begins to erode due to the extra well costs and/or interference between wells.
A method for efficient analysis and comparison of complex well design and well spacing options has been designed to assist in unconventional play planning and evaluation. The method involves the automatic generation and analysis of a large number (thousands) of dynamic reservoir simulation models. The models are analysed systematically for major value drivers to: identify the most efficient well design and optimal spacing factors; select the most economic well designs; assess the impact of subsurface uncertainties; and assist in rig selection and surface planning.
Case Histories of Life Cycle Well Integrity Management Using iWIT Software
Authors: Smith L. M. , Lunt G. 
Published: October 2012

Abstract
The Intetech Well Integrity Toolkit (iWIT) is a web-based program which provides a comprehensive approach to well integrity management covering all potential integrity threats to the whole well. Using its own or existing client databases, this software carries out quantitative data analysis in real-time and provides feedback to the operator about the condition of individual wells and also overviews of the whole field integrity status to support timely, informed, decision-making.
Case histories are described of seven different operations introducing the software. The diverse reasons for introducing the software and the direct and indirect benefits ensuing are described. Each is a unique story, highlighting how flexible and comprehensive this successful software product has been. A common element is the management of data spread across multiple 3rd party datasystems which have been successfully integrated in each case, sometimes utilizing data entered in tablet PCs in the field directly linked to iWIT. More challenging is the vast range of data analysis and presentation which has been customized for each client to achieve their goal. This includes risk evaluation against complex criteria, determination of tubing condition based upon varying production conditions, calculating MAASP values per well per annulus, managing and generating well handover documentation from the software, tracking scaling issues, determining mean time to failure of equipment to establish risk-based inspection frequencies and many more detailed analyses,
The iWIT software has allowed these operators to prove their adherence to Well Integrity Management policies and provides numerous report formats including email alerts for engineers and managers. By ensuring well problems are proactively identified and responded to within guideline timeframes the software ensures that well integrity related shut-downs are reduced, thus providing improved productivity from the well stock and at the same time raising safety within the operations.

Key Benefits of the iWIT Software Identified from Case Histories
Enhanced Petrophysics Analysis to Identify By-passed Zone in Gas Field - A Badak Field Success Story
Authors: Wibowo Ari , Suhendar Ade Diar 
Published: October 2012

Abstract
The Badak Field, operated by VICO Indonesia, is one of the world's giant gas fields. Located in East Kalimantan, the field lies in the northern part of the Badak – Handil giant anticline. Discovered in January 1972, production started in October 1976 and reached a peak of 1,1 BCFD in December 1990. Up until now, cumulative production has exceeded 6 TCF.
Today, Badak is a very mature gas field which produces 80 MMscfd. The drilling of new wells and the well intervention activities continue to be the main way to maintain production in the field. Most of the reservoirs units, especially the larger ones, have been intensively drained over the life of the field. Only a few of them are producing, but at relatively low rates, due to their significant depletion. Finding zones with remaining production potential has become a much more difficult task, especially if some of these zones have incomplete suites of logs.
In VICO, the improvement in the subsurface analytical methods has proven successful in helping identify additional reservoir opportunities. Recently, a method has been developed to identify "bypassed gas zones" in shallow reservoirs. This method uses the sonic log as the main tool for analysis. It also incorporates all of the subsurface data that has been acquired through time. The method has proven very successful in the Badak field in areas where no Density-Neutron log has been acquired.
Theoretically, the sonic log can be used as a complimentary tool to identify gas in the reservoirs. The problem arises when trying to differentiate between the event of gas and the effect of poor or under-compacted shallow reservoirs, as in many cases these events will present a similar feature across the sonic log. The development and implementation of these methods have helped significantly to maintain production in the Badak field.
Taking the First Steps: Stimulating the Nappamerri Trough Resource Play
Authors: Pitkin M. C. , Wadham T. H. , McGowen J. M. , Thom W. W. 
Published: October 2012

Abstract
The Nappamerri Trough in the Cooper Basin has long been recognised as a potential unconventional resource play with both deep-basin (Hillis et al. 2001) or basin-centred gas, and, more recently, as a potential shale gas target. However, initial attempts to fracture stimulate sandstones on conventional structural highs in and around the trough proved difficult. High treating pressures reached the limits of the well designs, and unsuccessful stimulation treatments resulted. A review of geomechanical information suggested that fracture complexity might have resulted from fractures initiating vertically and then twisting off to horizontal further into the reservoir (Nelson et al. 2007).
From 2010 to 2012, Beach Energy undertook a two-well exploration drilling program aimed at assessing the shale gas potential of the Nappamerri Trough and proving the presence of gas outside of structural closure. The wells were initially planned to gather base geological information from the core, but it was recognised that key fracture stimulation uncertainties could be addressed by these wells that would have significant benefit for future well design.
With the knowledge gained from previous stimulation treatments, the wells were designed to incorporate
Acid-soluble cement to improve the connection to the reservoir A fracture completion string—wellhead and pumping equipment suitable for higher treating pressures A surface tiltmeter monitoring array to ascertain whether treatments were twisting into the horizontal plane
The two wells, Holdfast-1 and Encounter-1, were successfully stimulated with 13 different treatments. This paper summarises the interpretation of the treating pressure data and the tiltmeter responses. Through diligent pre-project planning, the observed treating pressures were manageable, although higher than pressure gradients in other published shales and tight-gas areas. Large near-wellbore (NWB) pressure losses in most intervals were successfully reduced to allow treatments to be placed using moderately low viscosity fluids.
The interpretation of the tiltmeter array data indicated predominately vertical fracture development, which is a positive outcome for maximising stimulated reservoir volume (SRV) in future horizontal wells. However, the fracture orientation determined from the tiltmeters was not consistent with the anticipated maximum stress orientation from borehole logs and regional studies, and further investigation is required to resolve this difference.
The Role of Detailed Petrophysical Reservoir Characterization in Hydraulic Fracture Modeling of Shale Gas Reservoirs
Authors: Shebl M. A. , Yalavarthi R. , Nyaaba C. 
Published: October 2012

Abstract
Successful production in shale gas plays largely depend on identifying hydraulically fracable zones. Considerable lithological and petrophysical heterogeneity is expressed by changes in clay, silt, carbonate, and organic content. These changes correspond to variation of the dynamic rock mechanical properties. The contrast of rock mechanical properties amongst the layers influences the fracture dimensions. Detailed petrophysical analysis of shale gas reservoirs facilitates the mapping of the vertical and lateral distribution of various petrophysical and rock properties.
Id ntifying the most suitable zones for well placement, fracture initiation, and optimal distribution of proppant, maximizes the well performance. Geomechanical modeling in conjunction with the distribution of reservoir a d rock properties, determined through detailed petrophysical analysis, can be used to determine the optimum lateral placement and fracture design in shale gas plays. Geomechanical modeling aids in estimating fracture dimensions, fracture conductivities, and also identify zones that can potentially inhibit vertical fracture growth.
This paper describes a petrophysical analysis workflow for analyzing shale gas well logs and how the results from the analysis may be used to identify potential lateral well placement targets. Sensitivity studies showing the influence of rock properties and changes in stimulation design on fracture growth are also presented.
Experimental Design Methodology for Reserves Quantification Based on Soft Computing Modelling
Authors: Gupta R , Van Elk J. F. , Tjia D. , Smith G. C. 
Published: October 2012

Abstract
Over the past decade the statistical experimental design and analysis (EDA) methodology has been used widely in multiple deterministic modelling for a range of applications such as the development of surrogate models for estimation of ultimate recovery, history matching, screening of potential development options etc. Typically the first step in the EDA application is to quantify all uncertainties, secondly to generate the appropriate design with a minimal number of scenarios, thirdly create and simulate 3D geological models and finally calculate a surrogate model.
The goal of the EDA methodology is to minimize the number of 3D model scenarios simulation, necessary to accurately estimate hydrocarbon reserves for a given uncertainty profile. The fundamental question here is "How is an optimal design selected with in the EDA methodology?". The answer is simple; first we lock in the method that will be used to develop surrogate model and then search for the best scenarios to simulate that minimize errors in the final surrogate model. For instance if we plan to use response surface regression modelling, then designs like Placket-Burman, factorial designs or D-optimal designs are a good choice. Alternatively if we propose to use multi-dimensional kriging for surrogate modelling then space filling designs are a better choice.
In general we cannot mix-and-match designs with surrogate modelling methods. With increasing computing power there is a trend in the industry to try new soft computing methods such as neural network and decision tree based modelling to develop surrogate models. In this paper we will demonstrate that soft computing methods can be used for surrogate modeling. However the classical designs are in this case not the best choice. In these instances, the space filling designs like LHD perform better. The use of an incorrect design can lead to serious over estimation of the P90, which must be avoided.
Stimulation of Tight Gas Reservoir using coupled Hydraulic and CO2 Cold-frac Technology
Authors: Mueller Martin , Amro Mohammed , Haefner Frieder Karl , Hossain Md Mofazzal 
Published: October 2012

Abstract
Conventional hydraulic fracture stimulation technique has been widely used to enhance the production from tight gas reservoirs. Success of this technique, however, substantially depends on fracturing fluids and it responses to fracturing fluid-in the treated formations. This technology predominantly has been used to stimulate the tight sandstone reservoir. There are very limited applications for low permeable tight carbonate reservoirs due to complexities associated with the physical and mechanical properties of carbonate rocks and its interaction with fracturing fluid. This study has been focused on the development of a new fracture stimulation technique especially for tight carbonate reservoir, where the fracture will be created by hydraulic pressure and cold CO2.
This paper presents a numerical model that has been developed to simulate the stimulated fracture created by proposed technology with an emphasis on the evaluation of the relative permeability of supercritical CO2, brine/liquid CO2, created achieved fracture porosity and permeability; and the prediction of the production performance of stimulated fractures. Numerical simulation employing the development model has been conducted to: understand the science; investigate the thermo-hydro-fluid-mechanical behaviour; and identify the key parameters influencing the production performance for tight carbonate reservoirs using representative field data. The potential field application of the proposed technique for other formations such as tight sand and shale plays including adsorption effects on the shale and displacement efficiency of CO2 and advantages of this technique are also elaborated in this paper.
Effect of Fluid Leakoff on Fracture Geometry Evolution during Fracpack Treatments
Authors: Karale Chaitanya , Pinto Mario , Choudhary Yogesh 
Published: October 2012

Abstract
In recent years, the use of fracpack treatments has gained attention and is becoming increasingly popular because of their dualbenefits of stimulation and sand control. A fracpack is a hydraulic fracturing treatment using a very high proppant concentration that attempts to "pack-off" the mouth of the fracture. Fracpacking is widely used in high-permeability, poorly consolidated to unconsolidated sandstone formations. Accurate estimation of fracture width is important for both fracpacking and hydraulic fracturing to help ensure a successful treatment.
With the development of low-leakoff fluid systems, it has become possible to force the fluid through the proppant pack and out through the tip of the fracture without losing all the fluid through the fracture faces in a high-permeability, soft formation. In such scenarios, the effec of fluid leakoff on the fracture width profile for the case of arbitrary pressure distribution developed as a result of flow of non-Newtonian fluid through the proppant pack has been discussed in the literature. In this paper, the work has been further extended to include the effect of fluid leakoff through fracture faces for radial fractures.
The fracture face leakoff phenomenon is modeled using a generalized Carter equation, with different leakoff rates being incorporated in the form of fracture face leakoff coefficient values. The effect of fracture face leakoff on the final width profile, net pressure, fracture volume, and pack radius was investigated. It was observed that the width profile is significantly affected when fluid leakoff through the entire fracture face is considered. Controlling fluid leakoff through the fracture faces can result in much wider fractures because of large net pressure developed inside the fracture from fluid squeezing through the proppant pack.
An Evaluation of Risk of Hydrate Formation at the Top of a Pipeline
Authors: Nazeri Mahmoud , Tohidi Bahman , Chapoy Antonin 
Published: October 2012

Abstract
Water condensation and/or hydrate formation at the top of pipelines are serious design/operation consideration in pipelines with stratified flow. Water condensation could result in top of the line corrosion, in particular in sour gas systems. Hydrate formation is believed to be another serious risk if the inhibitor in the aqueous cannot protect hydrate formation at the top of the pipeline.
In this communication we report the results of some preliminary tests conducted in a new experimental set-up constructed for investigating gas hydrate risks in various operational scenarios, e.g., top of pipelines, dead legs/jumpers, start-ups, shut-downs, etc. The reported series of tests conducted in the new experimental set-up address hydrate formation risks at the top of pipelines or dead legs due to temperature gradient, amd risk of hydrate formation in the gas phase in the presence KHI during pipeline cool down and start-up. The results give a better evaluation of the risks involved in various systems and provide guidelines for avoiding the associated problems.
Innovative Circulating Technology Delivers Reduction in Lost Time and Materials While Drilling Depleted Formations
Authors: Herrington D. , Barton S. , Hepp T. , Clausen J. 
Published: October 2012

Abstract
Mitigating down time, while curing losses, is a critical part of designing and executing a good well plan. Even when anticipated, the loss of drilling fluids to depleted formations is a costly event resulting in excessive down time for the entire rig as well additional costs in replacing costly drilling fluids.
The search for new hydrocarbon reserves increasingly sends us back to proven fields where drilling through depleted zones as become an increasing liability to daily operations. The costly time required to pump multiple activation and deactivation balls down the string makes operating conventional tools tedious and time consuming. A more efficient tool for the placement of lost circulation materials (LCM) that does not require the exorbitant lost time and complicated cycling methods of the current technology has not been available for over a decade.
Today, a new tool, utilizing innovative shifting technology, provides unlimited open / close cycles. With this technology, drillers can shift an unlimited number of times and in as little as 5% of the time required by conventional tools. These capabilities result in direct reduction of lost time operating the tool as well as a quantifiable reduction in fluids lost while operating the tool. Simplified operation also makes the tool uniquely easy to operate reducing the potential for user errors that frequently plague existing technology.
This paper details how the use of this innovative circulating technology has assisted a major service company in reducing downtime and excessive costs during lost circulation events. The design has proven simpler to operate and has effectively reduced the non-productive time and lost fluid versus operation of conventional circulating subs. Supporting case studies are included to detail the increase in efficiency and reduction in costs.