bluuebunny/crossref_metadata_2025_split huggingface dataset:
Kikeh ESS Well Test - A Case History of a Deepwater Well Test, Offshore Malaysia
Authors: Hampshire Kenneth C , Stokes Dan , Omar Norjusni F , Tomkins Patrick G 
Published: December 2007

Abstract
It has been demonstrated that Expandable Sand Screen (ESS) technologies can be implemented rapidly and effectively without the requirement of a dedicated completion brine and well clean-up.
This paper will discuss a case history of the Kikeh #4 deepwater well test, performed in Block K, offshore Sabah, Malaysia. The test was performed in 4500 WD, from Diamond Offshore's fifth generation semi-submersible rig, "Ocean Rover".
Due to poor flow performance on the initial frac-packed completion, the decision was made to fast track this non-conventional approach to deepwater well test design. Key topics of discussion include: an integrated oil-based drill-in and completion fluid, expandable sand screen (ESS) selection, well test objectives, and well performance. Other points of discussion will include recommended practices and lessons learned using this completion technique. The completion and well test exceeded the objectives at a reduced cost and lower risk than conventional completion methods. As a result of the success of this methodology, it will be adopted for subsequent well tests in the area and is currently under consideration as the mainstay completion technique for the Kikeh development program.
Subsea Leaks Cured with Pressure-Activated Sealant
Authors: Rusch David W. 
Published: December 2007

Abstract
The paper describes the use of a pressure activated sealant technology to cure leaks in subsea wellbore equipment and control systems. The benefit of this technology is that use of an injectable pressure activated sealant to cure leaks provides a safe, cost-effective alternative to conventional well interventions. The paper outlines the capabilities of the pressure-activated sealants, the procedures used and the results of the sealant operations including case histories.
Building the Case for Raw Seawater Injection Scheme in Barton
Authors: Flatval Kirsti Berg , Sathyamoorthy Sekhar , Kuijvenhoven Cor , Ligthelm Dick 
Published: December 2007

Abstract
Shell Malaysia Exploration & Production (SM-EP) is planning for secondary recovery via water injection in the Barton field by using the novel concept of raw seawater injection. Raw seawater injection is essentially injection of minimally treated, fully aerated seawater. The seawater having undergone limited solids interception only by coarse filtration. The concept of raw seawater injection has not received much interest from operators due to lack of understanding on issues such as reservoir souring and impact of oxygen on the reservoir. However, raw seawater injection has proven to be the most cost effective secondary recovery design for mature fields like Barton, which do not boast huge reserves. This paper will focus on work carried out to identify and mitigate additional risks from raw seawater injection, principally on issues of reservoir souring, increased corrosion on production system, increased levels of suspended solids and impact of oxygen on the reservoir scale. Raw seawater injection in Barton will be the first of its type in the Shell Group and only the second known attempt in the industry.
Vessel-Less S3: Advanced Solution to Slugging Pipelines
Authors: Kovalev K. , Seelen M. G. W. M. , Haandrikman G. 
Published: December 2007

Abstract
In a flowline/riser system large liquid slugs and gas surges can be formed by operational changes or can be due to the specific flow conditions and physical characteristics of the flowline. These liquid slugs and gas surges may result into significant oil and gas production deferment. Slugging may cause high-level trips in separators and can lead to unstable operation of topside facilities.
Slug mitigation plays a very important role in the drive of exploration and production companies for operational excellence and increased profits. Shell Global Solutions is developing cutting-edge technologies to solve problems associated with slugging. In the late nineties Shell Global Solutions developed the Slug Suppression System (S3) that is now in operation in the North Sea. The field experience with the system has proven that the S3 controls/mitigates slugging.
Striving for advanced technical and cost-efficient solutions, we have developed a new slug suppression device: the Vessel-Less S3. The new product integrates the benefits of the conventional S3 controller schemes and the T-junction in-line separation technology as an efficient means of slug mitigation. The new system comprises a stratifier, a downcomer, two T-junctions, gas and liquid outlets and two control valves. The control algorithms of the original S3 are applied for the slug mitigation and control. Instead of the vessel, standard piping is used in the construction of the Vessel-Less S3.
On the way to a new commercial product, the Vessel-Less S3 has now been proven in laboratory environment, and needs to be tested further in the field. The Vessel-Less S3 has the potential to become an attractive device for slug mitigation and control. The development of the Vessel-Less S3 will enable operating companies to implement the S3 technology at lower costs and with reduced weight/space requirements.
Managing Subsidence Risk in Gas Carbonate Fields Offshore Sarawak
Authors: Mah Kok-Gin , Draup Awang 
Published: December 2007

Abstract
The porous carbonate formations in the Central Luconia Province offshore Sarawak generally form prolific gas producing reservoirs. As more and more gas is being produced from those high-porosity mouldic limestone reservoirs, the platform structures at surface gradually "sink" deeper into the seabed of the South China Sea. Although the exact magnitude of this subsidence is always not simple to predict, the general effect is catered for in the various technical designs of the platform complexes.
Asset and well integrity of these fields are crucial to ensure security of gas supply. An intensive surveillance programme is in place to ensure all relevant data are obtained to assess asset integrity risks. Dedicated studies and modeling are also being carried out to provide improved subsurface understanding of sudsidence behavior, as well as to evaluate structural integrity. No field is currently subject to integrity threat associated with compaction and subsidence. By formulating early mitigation plans, we are able to ensure safe operations of all the fields. The particular merit of this paper is to share some of the lessons learnt from field case histories and the surveillance approach and mitigating measures taken to manage the risks.
Stybarrow Oil Field - From Seismic to Production, The Integrated Story So Far
Authors: Ementon Neil , Hill Robin , Flynn Mark , Motta Bob , Sinclair Steve 
Published: December 2007

Abstract
The Stybarrow Oil Field is located in Block WA-255-P offshore Western Australia, in an average water depth of 800m. This paper is a work-in-progress case-study of the process of discovery and appraisal of the Stybarrow field, and the influence on appraisal and development decisions of integrating the various types of geological, geophysical, and engineering data and techniques available to the modern oil company and their partners.
In the fault bounded Stybarrow structure, medium viscosity, medium GOR oil is reservoired in high quality but friable sandstones of the Lower Cretaceous Macedon Member. The average reservoir depth is around 2200mSS. High quality 3D seismic data has been used to both significantly reduce uncertainty in modelling the Stybarrow structure, and attempt to predict reservoir quality and distribution using well-calibrated seismic inversion to relative acoustic impedance. Results from the use of seismic inversion have been fundamental in constructing static reservoir models. The static geological modelling has been used in the construction of simulation models, with the view to simulating flow of the near-saturated oil through the relatively thin Macedon reservoir and thus predicting production. Pre-project feasibility simulation results were used to select a preferred reservoir management scheme. A simulation derived Integrated Production Model was then constructed. This allowed examination of the interaction of reservoir with a proposed processing and facilities under given processing facility design constraints.
The influence of a number of data types on appraisal decision making and development planning is discussed. Elaboration is also made on the impact of near-field exploration potential, and the possible influence of this potential on Stybarrow development planning is also discussed.
Rapid Derivation of in-place Hydrocarbon Volumes in Large, Complex Field Settings
Authors: Holyoak Steve 
Published: December 2007

Proposal
South West Ampa Field in Brunei is a large, structurally complex oil and gas field offshore Belait, Brunei Darussalam. Starting with seismic interpretation in the time domain, this paper describes a modeling workflow culminating in the derivation of initial in-place volumes for oil, associated gas, and non-associated gas. At the centre of the process is an integrated full-field reservoir model. The initial phases of the workflow are summarised only; these are described in more detail in Reference 1. In this paper emphasis is placed on the derivation of the hydrocarbon volumes, and is based on work carried out over the last year.
Deriving volumetrics from an integrated full-field reservoir model has several advantages over more traditional methodologies: Graphically auditableForced consistency with the live reservoir modelRapidly re-run through pre-existing user-defined workflowsOutput format facilitates further analysis using spreadsheets or relational databases
This paper also discusses areas for possible improvement: The method is more susceptible to gridding artifactsCurrently the volumes are largely deterministic in nature; probabilistic modeling is feasible, but at the detailed reservoir level is likely to require a much more hands-on approachAdditional software enhancements are required to further streamline the process
To date the emphasis has been on designing a suitable workflow. This has now been achieved, and the study will move forward to a phase of comparison with the existing corporate volumetrics database. This may generate additional opportunities for infill drilling.
There are many additional benefits of the full-field model.
These include: Rapid output of maps and cross-sections for reports and well proposalsWell planning in a collaborative three-dimensional environmentEase of integration of diverse datasets (for example well paths, seismic data, formation tops)Live model updating with results of ongoing activitiesThe ability to use the full field model as the basis of detailed models for dynamic simulation
The model is already playing an important role in the drive to maximise hydrocarbon recovery from this large but highly mature field.
Experimental Design Methodology for Quantifying UR Distribution Curve - Lessons Learnt and Still to be Learnt
Authors: Peng Cheong Yaw , Gupta Ritu , Vijayan Kaipillil , Smith Gregory C. , Rayfield Mark A. , DePledge David R. 
Published: December 2007

AbstractExperimental design and analysis (EDA) methods have been proved to have a great potential in multiple deterministic and stochastic approaches to quantify the ultimate recovery uncertainty of a subsurface reservoir. Nevertheless, it is still at the very beginning stage, and is important to improve the performance and the efficiency of the methods in such oil/gas applications. This paper provides some lessons learnt in such studies, and propose the lessons still to be learnt.A brief summary of the EDA methods that are applied in ultimate recovery uncertainty studies is presented, and this paper emphasised on the importance of expert knowledge in improving the efficiency of the EDA methodology in such oil/gas applications, where the number of settings of the uncertainties is small and only a small number of models can be simulated. Response surface method in conjunction with the design matrix guided by expert knowledge turns out to be the best approach to develop a surrogate model (simple mathematical function) of ultimate recovery based on uncertainties. Once the model is fitted it is important to quantify the accuracy of the surrogate model. This surrogate model can be put to multiple use like prediction, optimisation etc.
Operational Experience of Wet Gas Metering in Malaysia
Authors: de Leeuw H. , Dybdahl B. , Nilsson C. N. , Kamal Mustaffa 
Published: December 2007

Abstract
Wet gas metering technology was chosen by ExxonMobil for continuous well testing and advanced production measurement at two satellite platforms located in the South China Sea offshore Malaysia. The satellite facilities are equipped with permanently installed SmartVent wet gas venturi based meters at each well location. Special wet gas flow calculation and monitoring software have been developed and installed on a separate flow computer installation interfaced to the host platform DCS system.
Prior to installation the wet gas meters have been subjected to full scale testing at a representative high pressure gas/liquid flow test facility. This has resulted in valuable measurement experience and a unique set of experimental wet gas data. After start up of the field on-site verification/calibration will be performed using the tracer technology method. As of today valuable results have been obtained from the system.
The present application is a demonstration that wet gas flow measurement is increasingly gaining acceptance in replacing expensive well test separators and related infrastructure in gas/condensate field developments. Besides the significant cost savings, the availability of continuous readings of each well&#39;s production rates allows for enhanced reservoir management and production optimisation. At the same time experience has shown that successful implementation of wet gas flow measurement requires adequate attention to every aspect of the metering process.
Challenges to Improve Turbomachinery Availability
Authors: Hasnan Nasir , Nazim Saiful , Yusof Yuzaini 
Published: December 2007

Abstract
This paper presents challenges and initiatives to improve turbomachinery availability to maximize production. Since 1996 it had gradually increased from 85% to 96% in 2003. Various initiatives were implemented and ongoing to make the improvement. However, year 2004 turn out to be an extremely challenging year with plenty of unplan downtime due to something that was never anticipated.
Control Medium Selection for Unmanned Wellhead Platforms
Authors: Morgan Julie , Shipchandler Arif , Mukhopadhyay Santanu 
Published: December 2007

Abstract
Cost effective design of unmanned wellhead platforms require highly reliable, low maintenance equipment/systems which minimize production downtime and reduce the frequency of site visits. In the Asia Pacific region, in line with this philosophy untreated wellhead gas is commonly used in lieu of instrument air. However the quality of this gas is poorer than instrument air which could reduce the control system reliability and accelerate wear and tear of control components. Granherne Inc has developed an innovative treatment scheme which produces wellhead (instrument) gas comparable in quality to instrument air using reliable, inexpensive and low maintenance equipment. This paper describes this scheme and identifies its potential benefits over an alternative control medium such as a hydraulic fluid.
A New Approach for Regime Optimization of Oil and Gas Mixture Pipeline Transportation
Authors: Khang Nguyen Thuc , van Bich Ha , Son Tong Canh , Hoe Le Dinh , Thuc Phung Dinh 
Published: December 2007

Abstract
The performance of pipeline transportation of oil & gas mixtures can be optimized by different ways. This paper introduces a synergetic statistical approach based on field data to analyzing the oscillations of pressure by determining simultaneously Hausdorff's Dimension "D", Hurst's Index "H" and the Entropies "E", as a useful tool for managing the multiphase pipeline transportation systems.
Inhibitor Squeeze Design and Returns Monitoring to Manage Downhole Scale Problem
Authors: Darwish Sameh F. , Moniem Alaa A. 
Published: December 2007

Proposal
Downhole scale deposition in producing well bores is becoming a serious problem to most of oil companies, especially when dealing with deep wells. The problem will be greater for those companies that are using water flood to maintain the reservoir pressure as the scale is often Calcium, Barium, and Strontium Sulphates.
The options for the scale removal varies from chemical, mechanical removals and at the worst conditions full rig work over to replace the production tubing could be the only available option. The oil field scale treatment philosophy is "scale prevention is better than curing", accordingly, implementing inhibition programs is generally become the most efficient scale treatment technology. However this inhibition technology is based on many factors to enable an appropriate assessment and reliable conclusions: How the inhibitor interact with the formation rock matrix.Thermal stability of inhibitor.Deployment and return profile.
In this paper, a sever downhole scale problem occurred at Ras Budran field that located at the eastern coast of Gulf of Suez in Red Sea territory, were presented and focused on: The treatment parameters starting from the traditional chemical & mechanical removal techniques and finalizing by the squeeze inhibition programs.Inhibition programs and its modification to overcome the formation problems.Inhibitor deployment, fluid returns monitoring and optimization.Inhibition lifetimes pronounced improvement for all the scaling wells.Study different chemistry of scale inhibitors to improve adsorption/desorption profile.
KLX/KLY Reservoir Management Using Integrated Asset Modeling, Case Study
Authors: Tjahyadi Riza , Suyasa I Made 
Published: December 2007

Abstract
One of the most important areas in Offshore North West Java is KLX/KLY fields, considering their high contribution to the West Java total gas production. Four platforms have been developed in this field to produce gas from shallow, thick and low strength carbonate reservoir. The large gas accumulation in this field is within a thick carbonate build up formation with average gas column thickness of 350-400 ft underlain by the aquifer. The reservoir has high porosities ranging from 32 to 45% and high permeabilities up to several Darcies. As consequences of dominating gas production, reservoir pressure has dropped and gas production rate decreased in this area. To ensure production continuation, well problem anticipation and surface facility remediation, Integrated Asset Modeling (IAM) have been built. Currently, this Asset is focusing on three important sectors, which are Low Pressure Compression, Well Surveillances Planning and Subsidence Management. Low Pressure Compressor ProjectSome scenarios for Low Pressure Compressor Project had been created to optimize gas production and maximize reservoir ultimate recovery.Well Surveillance PlanningIn this section, IAM has been used to control, monitor and perform forecasting for each well. Potential well problem in the future have been predict and planned the appropriate solution through scheduled well intervention.Subsidence ManagementKLX/KLY produce from Carbonate build up reservoir with low rock compressibility. Subsidence phenomena have been observed; therefore, integrated reservoir management is very important in this area. Ultimate subsidence, facility remediation and subsidence effect have been investigated.
The purpose of this paper is to present the importance of IAM for KLX/KLY asset to ensure production continuation through the integrated engineering study on reservoir modeling, core analysis, facility remediation and effect of reservoir subsidence on gas production/reservoir performance and surface facility.
A Case Study of a Mature Field Redevelopment Using Propped Hydraulic Fracturing
Authors: Burnstad R. G. , Martin A. N. , Stemberger D. J. , Purwanto B. 
Published: December 2007

Abstract
This paper will detail how a mature oil field in the South Kalimantan region of Indonesia was revitalised by the use of hydraulic fracturing. The Tanjung Raya field is a complex, multilayered, mature oil field. This field was initially developed in the 1960's, with production peaking at over 55,000 bopd. By the mid 1990's, production had declined to less than 1,200 bopd. The introduction of a water flood increased production to a peak of 10,000 bopd, but this quickly declined at an average rate of circa 33% per year. With the introduction of a fracturing programme, based on treating existing and new wells, production has been maintained at a flat 7,000 bopd over the past two years. The hydraulic fracturing program has accounted for 80% of these significant production gains, adding more than 5.7 million barrels of recoverable reserves and extending the economic life of the field by more than 2.5 years.
Hydraulic fracturing is a process that is relatively underutilised in the Asia-Pacific region, as compared to North America, Latin America and the Middle East. With a couple of recent noticeable exceptions, the technique is either not considered during field development and redevelopment, or it is used on a one-off, remedial basis. However, fracturing can be an integral part of well design, and an effective tool when the technique is applied systematically by practitioners who understand its capabilities; as demonstrated in the Tanjung Raya field.
This paper will discuss how a significant increase in oil productivity from a mature field was attained with a very high propped fracture treatment success rate. It will also detail how the correct design of fracture treatments can enhance reservoir recovery rates, and fully utilise vertical wells as a low cost, effective alternative to horizontal wells, or to increase well spacing. The paper will also discuss the most significant issues of implementing such a program and how these issues were effectively dealt with in the Tanjung field.
Coiled Tubing Conveyed Fracturing System Allows Longer Zones to be Isolated in a Single Trip Multiple Times
Authors: Stricker Michael P. , Romano Frank J. , Simmons Rickey L. 
Published: December 2007

Abstract
Increased production and lower costs in shallow gas wells are closely linked to developing and refining new coiled-tubing drilling, completion, and production techniques. Innovations in coiled tubing have reduced the costs of drilling and completing these wells and increased their productivity and life cycles. Coiled-tubing fracturing is one such innovation. This has been used for some time now, predominantly in North American shallow gas wells. In these wells, the cost advantages associated with working over the well in a live condition while reducing job time are attractive.
Coiled-tubing fracturing operations usually employ straddle-type tool configurations. However, with a typical maximum lubricator length of about 30 ft, straddle interval lengths have been restricted, which increases the amount of resets required to effectively fracture individual zones. This restriction also increases the potential risk of communication above the assembly.
This paper describes the development of an economical and reliable coiled-tubing fracturing system that allows selective fracturing of previously bypassed pay zones. This is now possible because the system can be conveyed in a tandem configuration that works within current lubricator restrictions, but is capable of setting repeatedly as a retrievable bridge plug and treating packer combination. This allows longer zones to be precisely isolated multiple times in a single trip in hole.
This innovative technique can not only reduce intervention costs but also reduce the total time required to complete the operation. This paper examines a case history, with emphasis on pre-job planning, equipment selection, wellsite execution and post-job results.