bluuebunny/crossref_metadata_2025_split huggingface dataset:
Managing Change in a Changing Environment: Creating an Improved Logistics Organization for Offshore East Kalimantan
Authors: Kovacevich S. T. , Hinrichs L. J. , Hasan U. 
Published: December 2007

Abstract
This report documents an original case study summarizing the success of an East Kalimantan oil & gas operator in creating an improved logistics organization. The Logistics and Supply-Chain Management (L&SCM) Project was designed and implemented in an eighteen (18) month period beginning in October 1998. It focuses on the operational aspects of aviation, marine services and the supply base function. The paper describes key project management aspects from preliminary planning, sponsorship and team selection through the management of change (MOC) during transition to implementation. A chronological review addresses the original charter, the discovery phase, analyses, recommendations, implementation and provisions for continuity and continuous improvement.
Performance to deliverables, keys to success and lessons learned are detailed including the implementation of new standards/policies/procedures, innovative technology and empowered personnel. Dealing with challenges both internal and external to the organization will be discussed, in particular resistance to change, legacy thinking and the supply market.
The paper also reveals new information generated from field data and computer modeling of marine logistics activities. These applications and resulting information were paramount in leading us to a successful business solution to improving the logistics operation.
Final conclusions revolve around an implemented logistics program that created quantifiable value to all stakeholders and generated client/market acceptability. Major results include creating a new, accountable logistics organization that operates 20% less expensively. Internal clients enjoy a transparent operation providing safer and more reliable service. Management has a more cost-effective, disciplined organization that is measurable. Suppliers and contractors better understand business needs and have provided quality resources.
Peninsular Malaysia Gas Utilisation Project – Challenges in Gas Supply Planning
Authors: Samsudin Abdul Rahim , bin Mohamed Mohd Sabri 
Published: December 2007

Abstract
The history of natural gas utilisation in Peninsular Malaysia started with the commencement of the Peninsular Malaysia Gas Utilisation (PGU) project in 1984. The project was developed in three phases over a period of less than two decades covering almost the entire area of Peninsular Malaysia.
While the power sector will continue to drive the future growth of PGU gas demand, the demand from the gas based industries is also expected to increase rapidly in tandem with the growth of the national economy. In recent years, the role of natural gas is becoming more important as the existing and upcoming petrochemical industries rely heavily on the natural gas for the feed stocks to generate high value added products. Indeed, the PGU project acts as a catalyst to the power generation sector and other gas based industries providing significant contribution to the national economy.
Malaysia is endowed with abundant natural gas resources to support the long term development of the PGU project. In addition to the commitment to develop the discovered gas resources, PETRONAS through its Production Sharing Contractors (PSCs) is also committed to intensify exploration efforts to discover new gas resources. Prudent planning is therefore vital for ensuring a sustainable natural gas supply to the gas projects.
This paper will review the historical and future outlook of the gas industry in Peninsular Malaysia. Among others, the paper will cover topics on an overview of the PGU project and challenges in gas supply planning to meet demand. Prudent gas supply planning will result in an optimum gas supply and demand matching, sufficient excess capacity margin and optimisation in gas development and evacuation which in turn will improve companies' bottom line as well as other benefits to all parties.
Conductor Sharing Wellheads - More for Less
Authors: Anchaboh L. , de Lange F. P. A. , van Beelen C. J. , Tan R. K. W. 
Published: December 2007

Abstract
All brown field operators face the challenge to further develop mature fields from existing facilities, whilst ensuring that infill wells continue to add value to their business. Implementation of innovative drilling and completion technology is an important ingredient to achieve this objective. Conductor Sharing Wellhead (CSW™) technology was identified by Brunei Shell Petroleum Company Sdn. Bhd. (BSP) as one of several key enablers for the cost effective development of mature fields offshore Brunei. This technology maximizes the utilization of the remaining existing surface facilities by accommodating two (or more) new wells in one single conductor slot. Additionally, it has been demonstrated that the application of CSW™ technology markedly reduces overall development costs.
The application of CSW™ technology is therefore not restricted to brown field developments only, but it will also allow new field developments to become more attractive. It is demonstrated that CSW™ allow the installation of smaller platforms that can realize the full potential of their big brothers at reduced capital investment, engineering and installation costs.
The first CSW™ system was installed offshore Brunei in December 1998 in Block 14 in the Champion field. This development utilized two of the existing spare 30" conductors to drill and complete three new horizontal wells with one shared well slot remaining for future use. This initial success led to the identification of additional similar applications and an alternative application such as drilling two wells (per slot) from abandoned conductor slots, recovering their conductors and drilling four new wells from the salvaged conductor slots.
The experience gained with CSW™ technology indicates that drilling two wells from one conductor can save USD 1.0 million compared to two conventional wells, whilst better planning and design improvements have reduced the installation times of the CSW™ by some 50 percent.
This paper describes the details of the planning and execution phases during the CSW™ project. We will also discuss lessons learnt during the course of the project, which resulted in significant cost savings, specific design changes and the delivery of a wellhead system that has now been established as a new drilling standard for the development of brown fields and new field developments alike. Close cooperation between field staff and office staff of both the operator and the wellhead supplier were key in realizing a step change in technological and economic opportunities.
Estimation of Rock Dynamic Elastic Property Profiles through a Combination of Soft Computing, Acoustic Velocity Modeling, and Laboratory Dynamic Test on Core Samples
Authors: Widarsono B. , Wong P. M. , Saptono F. 
Published: December 2007

Abstract
This paper presents a new approach for estimating rock elastic properties in wells, especially for wells with limited log suites. The approach is basically a combination of efforts that are put is a series of steps. Firstly, is to model a synthetic S-wave velocity profile for a key well, with support from laboratory acoustic measurement on core samples, enabling the establishment of profiles of elastic properties through the theory of elasticity. Secondly, the modeling and validating of relationship between P-wave velocity, Poisson ratio (as an example in this paper), porosity, water saturation, shale contents, and matrix density based on the log data available for the key well. Thirdly, prediction of all missing log suites (if any) for other wells using soft computing (artificial intelligence/neural network) that has been ‘trained’ using data from the key well and other wells that have more or less complete log data. Fourthly, estimation of rock elastic properties for all wells (except the key well) using soft computing. Finally, evaluation of results using comparison with the model validated in the key well. The method has been applied on 14 wells of an active oil reservoir in Java, Indonesia. Comparisons of porosity and water saturation values between results from standard log interpretation and results from the validated model serve as indicators for the success of the method. The reasonably good comparisons achieved have proved that the new approach is applicable, and the use of the model relationship avoids ‘blind’ estimation often practiced in reservoir characterization.
Introduction Experiences of a New High Accuracy Through-Tubing Pulsed Neutron Reservoir Management Solution in Asia-Pacific
Authors: Simpson G. A. , Fox P. , Chafai N. , Truax J. A. 
Published: December 2007

Abstract
Evaluation of three-phase reservoirs in gas injection fields has been a major challenge in the Asia-Pacific region. Low-to-mid porosity and complex wellbore completion environments create a difficult, pulsed neutron logging environment for analyses of remaining oil saturation, fluid contacts, and identification of flood breakthrough.
A new, through-tubing, pulsed neutron measurement system has recently been introduced to the industry in the Asia-Pacific region. Refinements have achieved the highest available spectral resolution and accuracy of any slim tool, extending multi-phase reservoir evaluation to lower porosity formations and to more complex wellbore environments. Features of the tool include single-pass simultaneous carbon/oxygen (C/O) and capture cross section (S) logs, quantified water flow analysis, porosity logs, and elemental analysis, all acquired at higher speeds than previously available. Modern tool characterization and adherence to well-established best practices have enabled reliable decision making based on application of the higher quality pulsed neutron measurements to these difficult situations, which were previously considered infeasible.
This paper discusses potential for economic gains that can be realized from enhanced reservoir characterization with the new pulsed neutron system. Additional hydrocarbon reserves can be delivered from application of the modern technology within these more challenging environments. Log examples included in this paper will show that the new tool is capable of determining gas, oil, and water volumes in formations with less than 10 percent porosity. It includes details of an interpretation method tailored to a specific reservoir yet applicable to many multiphase situations. With advanced pulsed neutron devices as part of a well designed investigative package, more robust support of reservoir management can be realized.
Monetising Small Oil Fields-In Pursuit of Innovative Solutions
Authors: Hashim Kamarudin , Shabudin Aidil 
Published: December 2007

Abstract
One of the challenge for the petroleum industry sector in Malaysia is to monetise oil resources at earliest possible timing. After production since early 1970's, there are about 3.43 billion barrels of remaining oil reserves located offshore Malaysia. About 550 million barrels of the oil reserves are contained in some 62 fields with estimated ultimate recovery (EUR) of less than 30 million stock tank barrels (MMstb) per field. For these small oil fields, efforts undertaken by the petroleum producers in Malaysia, for examples; PETRONAS Carigali Sendirian Berhad (PCSB), Esso Production Malaysia Incorporated (EPMI) and Sarawak Shell Berhad / Sabah Shell Petroleum Company (SSB/SSPC), have yielded achievements which have begun to pave paths for prospective successes in developing the small oil fields.
In addressing the challenge to monetise oil reserves expeditiously, the petroleum producers in Malaysia have harnessed their efforts to achieve cost effective development for the reserves. Cost effective developments lead to improved project profit margin. Optimization efforts on small oil field development concepts have been aggressively pursued since the middle 1990's. Depending on development concept adopted, the development costs estimated for small fields offshore Malaysia have since improved from over RM 400 million (USD 160 milion) to less than RM 100 million (USD 26 million) per platform excluding the development drilling costs. The difference in cost is the result of continuous efforts in development concepts optimisation.
Geothermal Hot-Water Flood-Balam South Telisa Sand, Sumatra, Indonesia
Authors: Pederson John M. , Sitorus Jayadi H. 
Published: December 2007

Abstract
Hot water flooding is a mature technology that dates back to the 1960's. Although a technical success, heating injected water by burning a fuel proved to be uneconomic in those days. However, using hot water from geothermal sources eliminates the need to burn oil and results in a true increase in ultimate recovery with attractive development costs.
This technique is particularly useful in fields with shallow, high viscosity waxy oil formations and deeper water bearing formations with relatively low salt concentrations. Many oil fields in the Sumatra basin fit this category. Costs to drill geothermal source wells in Sumatra are economic because of the high geothermal gradient observed in the central Sumatra basin (0.03 to 0.04 °F/ft).
This paper shows a novel approach of combining typical waterflood operations with geothermal hotwater sources is not only cost effective for new enhanced oil recovery projects but is also an effective optimization technique for existing waterfloods. A case study of the Balam South Telisa reservoir is presented. Results from two other fields in Sumatra are also shown to illustrate the application of this concept to other fields.
Studying the Mechanism of Magnetic Field Influence on Paraffin Crude Oil Viscosity and Wax Deposition Reductions
Authors: Tung Nguyen Phuong , Van Vuong Nguyen , Long Bui Quang Khanh , Vinh Ngo Quang , Hung Pham Viet , Hue Vu Tam , Hoe Le Dinh 
Published: December 2007

Abstract
Dragon and White Tiger crude oils are two different kinds of paraffin crude oils of Vietnam. The screening studies on their fluidity changes under the influence of magnetic forces have been completed. The relationships between their viscosity changes and magnetic force strength, temperature, and duration of treatment were obtained, the optimal conditions for the viscosity reducing were found. The changes in paraffin crystallization under magnetic fields were studied using scanning electronic microscopy (SEM). The possibilities to defense and remove wax clogging and deposition obtained by magnetic treatment was also studied and proved. Base on these data, the mechanism of the influence of magnetic fields on paraffin deposition control was proposed. The data can also serve as a basic in designing and construction high effective magnetic tools to improve liquidity of high waxy crude oils in this area.
Investigation of a Problematic Well to Restore Production
Authors: Gai H. 
Published: December 2007

Abstract
This paper describes a series of investigations carried out in an ESP lifted well (below bubble point production) that experienced a cluster of unexpected problems resulting in loss of production, and how the investigations restored production. The problems among others included apparent severe productivity drop coupled with downhole temperature rise, and the investigations eventually led to the discovery of asphaltene that has not been found in the field before. Analysis of all the problems and investigations including lessons learnt are shared in detail.
Determination of Volumetric Sweep Efficiency in Barrancas Unit, Barrancas Field
Authors: Vicente M. , Crosta D. , Eliseche L. , Scolari J. , Castelo R. 
Published: December 2007

Abstract
This paper describes the analysis of the evaluation and surveillance of the waterflooding in the South of the Barrancas Field, after more than 30 years of water injection. The volumetric sweep efficiency is a parameter of complex evaluation in a mature field, and it has importance in the determination of the amount and spatial distribution of the additional oil recovery.
The volumetric sweep efficiency can be calculated and predicted by means of two complementary methods that use basic principles of material balance, oil displacement by water and conformance plots. This procedure may help to evaluate the water injection efficiency with the current operation. Therefore the displacement efficiency and the remaining average oil saturation can be predicted.
The evaluation techniques of volumetric sweep efficiency and water injection efficiency are tools that can be used with conventional decline curve analysis, to estimate and predict the unswept fraction of the reservoir by water injection and the additional oil recovery potential. This method needs production and injection data, and can be applied to any configuration of patterns. Finally, this lead to take the correct actions in the management of the waterflood and estimate whether the success of the performance of the waterflooding depends on volumetric efficiency or displacement efficiency.
Simulation Based Dimensionless Type Curves for Predicting Waterflood Recovery
Authors: Dunn M. D. , Chukwu G. A. 
Published: December 2007

Abstract
Predicting waterflood recovery with simulation based dimensionless performance curves has advantages over the more traditional approaches in certain applications. This paper discusses the advantages of the type curve approach, how the curves are created, and how they can be applied to predict pattern and full-field performance. This technique is suitable for screening/ranking projects, and is particularly helpful when sensitivity and uncertainty analyses are necessary to improve reservoir management decisions.
The dimensionless type curve methodology can be applied to many types of fields. A case study of a large, waterflooded field is presented to show how the curves are created and how they can be applied. In this field, a study of the geology and stratigraphy indicated that reservoir continuity, permeability variance, and effects of faulting were the most important drivers of recovery efficiency. Simulations were performed on 45 datasets to describe waterflood performance over the range of variation. A spreadsheet program was created to predict recovery of any description, based on interpolations of the simulation results.
The dimensionless curves can be used to compare actual well performance to predicted performance, to predict full-field performance by summing well curves, and/or as the basis of an integrated evaluation tool. Using correlations to predict recoveries allows for ease of sensitivity analyses, and ease of application by casual users in an organization. This paper should benefit anyone who struggles with the task of applying simulation-based knowledge to everyday decisions when optimizing waterflood recovery.
Funding For Abandonment of Cook Inlet Alaska Oil and Gas Facilities: A Landowner's Perspective
Authors: Van Dyke William , Zobrist Daniel H. 
Published: December 2007

Abstract
Offshore oil and gas production platforms must undergo (possibly) expensive abandonment operations at the end of field life. In Cook Inlet Alaska, lessees are required, at abandonment, to dismantle and remove materials, machinery, equipment, etc. and return the leased lands in good order and condition as required under the oil and gas leases. Failure to complete abandonment responsibilities allows a claim for damages, as well as causing a default of the lease. In the worst-case scenario, default forces the landowner to step in and assume the responsibility of abandonment operations. To mitigate this risk, the landowner requires of the lessee financial guarantees such as bonds or independent escrow accounts funded to cover the cost of abandonment. At the Middle Ground Shoal Field in Alaska the landowner (State of Alaska) considers the value of the oil and gas reserves as collateral. This reduces other mitigation mechanisms that may be required of smaller independent producers when taking an assignment of the leases and facilities from giant, multinational, integrated oil firms. Accepting underlying proven reserves as collateral lowers the overhead costs to lessees, and frees investment dollars for incremental field development and exploration.
Field Test of a Novel Low Viscosity Fracturing Fluid in the Lost Hills Field, California
Authors: Vasudevan S. , Willberg D. M. , Wise J. A. , Gorham T. L. , Dacar R. C. , Sullivan P. F. , Boney C. L. , Mueller F. 
Published: December 2007

Abstract
The Monterey formation, Belridge Diatomite is a high porosity (45%) low permeability (0.5 – 7 md), low Young's modulus (~100,000 psi) oil reservoir with few stress barriers for fracture containment. Due to the low permeability it is desirable to optimize the fracture length per pound of proppant placed. Conventional cross-linked fluids are not well suited for this purpose as they create excessive width – reducing the effective fracture length generated for a given amount of proppant. Post-treatment production tests often show only 30 – 100 ft of effective fracture length even for relatively large treatments designed for longer length. Not only is production limited by these shorter-than-designed half-lengths; excessive fracture width combined with low closure stress often leads to serious sand production problems. Pseudo-3D simulations indicated that longer fractures could be realized by significantly reducing fluid viscosity.
A novel low viscosity fracturing fluid, designed to address the serious problems unique to low-modulus formations, was field-tested in the Lost Hills field, California. The low-viscosity fluid developed for this application was composed of a linear gel and a fibrous material. Laboratory studies established that the fiber greatly hinders proppant settling, while maintaining a low slurry viscosity required for fracture length creation. Proppant concentrations up to 12 PPA were pumped with this fluid.
Seven new wells were treated with the novel fluid. All wells were fractured in multiple stages; 1,250,000 to lbm of proppant was used in each well. Real-time pressure data was collected on all stages, and treatments on the first two wells were observed with downhole tiltmeters. Both pressure and tiltmeter data indicated that for similar sized treatments, longer fracture half-lengths were achieved with the new fluid – 200–400 ft – versus 30–100 ft for conventional crosslinked gels. Production from the test wells compares favorably to offsets, while using 30% less proppant than conventional treatments. Furthermore, it appears that proppant flowback and sanding problems are significantly reduced.