bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experience in Developing a Web Base Workflow to Enhance Competency
Authors: Ming Yeow Lei 
Published: December 2007

Abstract
How do one ensure consistent work quality and process in a large organization with multiple projects and a wide range of technical staff with various competencies and experience ? A web base Production Technology workflow was developed to meet the challenge. Production Technology work process was mapped, reviewed, validated, improved and integrated with other subsurface related disciplines in field development i.e. Geophysics, Geology, Petrophysics, Reservoir Engineering, Drilling and Petroleum Economics. The web base workflow was then implemented across the organization. Steps taken in the mapping, review, validation, improvement and integration process, learning points and benefits of developing such a system are discussed in this paper.
The workflow was categorized into issues identification, term of reference, data acquisition, processing, interpretation, model and archive for all disciplines. Knowledge and experiences of all Production Technologists in the organization was compiled and mapped. A high level workflow was first developed. Points of integration with other disciplines were identified. A "drilled down" process was used to detail out each step until the lowest level consisting of guidelines on each work step.
Steps in preparing the workflow consist of:
– Preparing a high level work flow – Appointing each engineer to prepare a specific work process covering well completion design, material selection, sand control, well flow modeling, completion fluids, cement evaluation, wellhead & Christmas trees, artificial lift, etc. – A review process to improve the work flow and formulate the best way to put it in a web base format – A web base format was developed, reviewed and improved – A validation process with selected projects to ensure all steps are considered and realistic – The web site was implemented across the organization – Encouraging project teams to follow the work process
Learning points includes:
– in-house experiences are more important with consultants as facilitator to compile and integrate the process – fitting workflow of different disciplines in the same categories needs flexibility – engineers working on daily business can contribute to corporate initiatives – concentrated and focus workshop sessions speed up the process
Benefits of the web base workflow includes:
– a reference point for engineers to perform their job – more efficient mentoring and guidance from experienced engineers to young engineers – a reference point to quality check work and approve Field Development Plan – one point data base to compile work experiences, company standards and previous work reports for reference
Interfacing Fracturing and Sand Control Completion Strategies into Multilateral Technology; Considerations and Solutions
Authors: Cavender Travis , Roane Thomas O. , Restarick H. L. 
Published: December 2007

Abstract
Multilateral technology offers the oilfield many advantages since it can deploy a completion system that can mechanically connect several lateral wellbores to a parent wellbore and will allow selective or commingled production. In most cases, these capabilities can provide more cost-effective well construction since reservoir exposure from one wellbore is increased. These advantages are particularly beneficial in offshore and deepwater environments where slot and/or sub-sea templates are limited, and rig costs are substantially higher. Because of the flexibility of this technique and its capability to offer various production options, it helps to mitigate the risks previously associated with directional/horizontal wells in new field developments as well as in revitalization of mature fields. Because of continual improvement in drilling techniques and the increase in field success, multilateral technology continues to gain in popularity; however, as with all completion techniques, it must be remembered that existing completion options must be evaluated for each case, and if needed, adapted to meet specific reservoir objectives and concerns.
This paper will focus on considerations, applications, and benefits of specific tool configurations developed for interfacing sand-control fracturing stimulation with multilateral technology. The techniques discussed include existing, modified, and conceptual completion methods that can be deployed into multilateral field-development strategies. The strategies address window selection, junction isolation, fluid loss, debris management, and lateral accessibility. Several completion sequences, which include a new Technology Advancement for Multi-Lateral (TAML) level 4 single-trip, gravel-pack methods and installation of expandable screen technology, will also be presented.
Unique Application of Floating Proppant to Stimulate Sandstone Formations with High Contrast in Permeability
Authors: Arinto Antonius D. , Anggono Sukinto , Nur Hasyim , Arfie Mezlul , Dusterhoft Ron , Kritzler Torsten 
Published: December 2007

AbstractThe Minas Oilfield in Sumatra, operated by Caltex Pacific Indonesia since 1952, has been extensively water flooded to improve recovery. In the past, propped hydraulic fracturing was not commonly used to stimulate the very high permeability sandstone formations. However, new logging techniques have indicated that, in certain zones where the permeability varies from top to bottom, oil saturation remains high at the top of the sand.A technique was sought to stimulate only the top section of the sand, which would improve conductivity and allow oil production. The idea of floating proppant was conceived; a hydraulic fracture would be created with proppant that had lower specific gravity than the fracturing fluid. At the end of pumping, the proppant would float to the top of the created fracture before it closed.Most of the sands have a fining upward sequence. The upper part of the top sand has low permeability. The lower part has very high permeability and has generally been swept with water. No stress barrier exists between the low and high-permeability sections of the reservoir. As an effort to recover oil from the top tight sand, a "floating proppant" frac was considered to be an alternative solution. Three treatments have been executed successfully. Oil production increased, water cut decreased and liquid production was stable. Two more wells will be treated this year.This paper describes the technical challenges that were overcome to deliver this solution to the unique problem in high-permeability wells. Challenges include proppant selection, fracturing fluid design, fracture modeling and design, candidate selection and job execution. Challenges in interpreting and analyzing the minifrac and the pressure behavior during the main treatments are also discussed.
Coiled Tubing Acid Corrosion Protection: Laboratory vs. Field Performance
Authors: Metcalf Steve , Delorey John , Allen Scott 
Published: December 2007

Abstract
Laboratory testing of the effects of acidic fluids on metallic samples representative of those used under downhole conditions is the normal procedure to establish additive requirements. Under sour conditions (Hydrogen Sulfide gas contaminated production), test methods utilizing differing amounts of H2S in the gas phase with subsequent contamination of the test solution under bottomhole temperatures is required. Underbalanced acid washing combined with follow-up acid squeezes is becoming more and more prevalent in carbonate wells with sour production. Typically, these treatments are conveyed using Coiled Tubing strings. The thin walled nature of these tubulars makes corrosion control of the utmost importance.
Corrosion testing using modified NACE cells under pressures varying from 500 to 6,000 psi and magnetic stirring systems can test various acid systems at temperatures varying from 27° to 315°C (80° to 600°F) over any exposure time. Safety factors, weight loss and pitting guidelines are employed to attempt to ensure the continued integrity of the Coiled Tubing through many treatments. In addition, evaluations of sections of Coiled Tubing after various treatments using the pearlite layer at the concentric center of the Coiled Tubing determine material losses both on the outside and the inside. Surface inspections are also performed to search for pitting or other acid corrosion associated defects.
This paper presents the comparison of laboratory acid corrosion testing and the actual effects on Coiled Tubing strings employed. Data from wells treated that produce from 23 to 60% H2S and have bottomhole temperatures ranging from 86° to 110°C (187° to 230°F) are presented. Treatments consisted of acid washes followed by acid squeezes. The varying material deterioration of actual coils, specifically, a loss in wall thickness and surface corrosion features and how this compare to laboratory test data is discussed.
Drilling Processes: The Other Half of the Barite Sag Equation
Authors: Dye William , Mullen Gregory , Gusler William 
Published: December 2007

Abstract
Barite sag is a well recognized, but poorly understood phenomenon in the drilling industry. Historically it has been associated with a static well environment; consequently test devices and rheological measurements were originally based on static conditions. Dynamic barite sag is now recognized as the major contributor to sag-related drilling problems. There are two prominent variables conducive to creating dynamic sag; 1) low shear rate conditions (drilling process-related) and 2) insufficient ultra-low shear rate viscosity (drilling fluid-related). Dynamic sag is not entirely a mud-related problem and, under certain conditions, will occur despite appropriate control of drilling fluid viscosity.
Barite sag is typically attributed to the mud system and the traditional approach to manage barite sag is to modify (increase) certain rheological properties of the mud system. These efforts are often frustrating because; 1) the proposed solution is ineffective, 2) the solution creates a new problem such as ECD management and 3) expectations are not met. This paper proposes that dynamic sag is related to both the drilling process and drilling fluid, and that these two variables cannot be treated independently from one another.
Journey Towards Remote Operation in Sabah Offshore Operations
Authors: Boon Liew Kok , Fook Lo Su 
Published: December 2007

Abstract
The paper describes the pioneer experience relating to implementing and operating of the first offshore oil and gas platform with full Remote Operations capabilities in KNDP-A and subsequent remote operations projects in offshore oil and gas facilities located in Sabah water, Malaysia. Part-1 describes the experience of implementing and operating a new-development (green-field) project whilst Part-2 relates the experience of retrofitting and operating Remote Operation facilities on existing (brown-field) projects. It calls for different strategy and approach though the objectives are the same. The reason is that there is very little incremental cost to implement full remote operation capabilities on green-field projects, whilst the same cannot be said for the existing brown-field projects for it has to take into account of the offshore implementation costs and facilities shutdown for final tie-in/ commissioning etc. However, it could still be cost effective if it is implemented in conjunction with other projects.
Multiphase Flow Measurement Using Tracer Technology at Dulang Oil Field, Malaysia
Authors: Ali M. Bohari M. , de Leeuw H. , Nilsson C. 
Published: December 2007

Abstract
Multiphase wellhead flow measurements using the tracer technology method have been successfully applied to over 65 wells in the Dulang field, located offshore Malaysia. A large range of flow conditions were covered with gas rates ranging between 943 m3/d and 165,900 sm3/d, oil rates between 20 m3/d and 319 m3/d, and water rates up to 489 m3/d. The watercut varied between 0% and 93%. The results obtained using the tracer technique was used as a cross-reference to the results obtained from conventional well tests using the test separator and to a separate multiphase meter during a trial period.
The present tracer method involves injection of selected tracers for oil, gas and water at a specific injection rate into the production stream followed by subsequent sampling of the fluids at a suitable downstream location. Measurement of the tracer dilution ratios allows the accurate determination of the individual fluid flow rates.
The application has proven the tracer technology method to be a robust and accurate multiphase flow measurement technique over a wide range of flow conditions. In practice the tracer method is capable of measuring over a much wider range than most test separators and multiphase flow meters making the technique very well suited for in-situ verification and calibration of installed multiphase and wet gas flow meters.
Multiphase Meters -- Operational Experience in the Asia-Pacific
Authors: Frantzen Karl H. , Brandt Morten , Olsvik Kenneth 
Published: December 2007

Abstract
In recent years, oil field operators in the Asia Pacific region have installed and made operational a significant number of multiphase flow meters.
During the 1990's a few test meters were installed at various locations in the Asia – Pacific. The first commercially supplied multiphase meters were installed in 1998, and since then a large number of meters have been supplied for various projects and operators.
Most of the installations in this area are on small, unmanned wellhead platforms with very limited power and communication. The multiphase metering technology has proven to be a very cost-effective and attractive solution for these types of fields.
The paper describes and discusses some of the particular challenges and solutions for multiphase meters used on unmanned wellhead platforms. One of the main challenges is how to build confidence in the measurements, as there is normally no alternative method for verification of the measurements on the platform. Suitable operating concepts for multiphase metering at remote wellhead platforms are presented.
Roxar has now supplied around 40 multiphase meters to this region, and as a consequence, a substantial amount of experience has been acquired. Operational experience and data from several installations is presented and discussed.
Drag Reducer Increases Pipeline Capacity to Accommodate the Successful of Field Development
Authors: Prasetyo Indra 
Published: December 2007

Abstract
Kaji-Semoga ("KS") field, located in south Sumatera, Indonesia, began to produce in March 1997, with 77MMBO proven reserves and peak production forecast at 40 MBO/d in year 1999–2000. To transport the production of KS field to Plaju refinery, PT Exspan Nusantara ("EXSPAN") built a two-pipeline system comprising 2×4-in diameter pipelines tied up to Tempino–Plaju pipeline, and one 8-in diameter pipeline tied up to EXSPAN owned Jene-Km 3 pipeline, with three booster pump stations built along this pipeline.
As the development drilling continued, the reservoir calculation of proven reserves increased to 135 MMBO and the peak production forecast increased to 68 MBO/d in year 2001. Problems arose due to the limited pipeline capacity. To solve these problems, some alternatives were discussed, such as developing other pipelines or a loop line system.
Both alternatives needed substantial initial investment and time to be developed. For example, approximately 1.5 years and an initial investment of $12 million were needed to develop a loop line system. One alternative, which can be applied in a short time and does not require a high initial investment, was suggested. The option called for the use of Drag Reducing Agents ("DRA").
DRA is a chemical agent used to optimize the pipeline capacity by reducing drag and lowering the pressure drop across the pipeline. The DRA was applied at Kaji and booster stations along Kaji–KM.3 pipeline. With DRA injection, we could increase the Kaji–KM.3 pipeline capacity by more than South Sumatera, which is transported through the Kaji-KM.3 pipeline system treated with a drag reducer, has been refined without any incidents.
90% from its baseline capacity, whilst maintaining the pipeline operating pressure within an allowable range.
With DRA application, production from KS field could be accelerated, allowing EXSPAN to benefit from the Domestic Market Obligation (DMO) free period incentive and the crude price increment, with minimum investment and operating costs. Within 1.5 years (estimated time required to develop a loop line) EXSPAN had a net share increment of about $22 million and saved about $0.7 million per year from shutting down one of three booster pump stations along Kaji–KM.3 pipeline. And within the same period of time, the government of Indonesia had a net share increment of about $126 million.
Non-Linear Optimization Model for Gas Transmission System: A Case of Grissik - Duri Pipeline
Authors: Arsegianto A. , Soewono Edy , Apri Mochamad 
Published: December 2007

Abstract
A non-linear optimization model is developed for gas flow through transmission line with few branches of sources and sinks. The existence of compressors is also facilitated in the model. Given constraints at sources and sinks, the model searches the optimum pipe diameters and compressor's sizes for minimum cost. The model is applied to simulate the existing gas line from Grissik to Duri in Sumatra to make a comparative study between theory and application.
Transporting oil and gas mixture in gathering system at White Tiger oil field
Authors: Khang Nguyen Thuc , Van Bich Ha , Son Tong Canh , Hoe Le Dinh 
Published: December 2007

Abstract
Transport of oil and gas from producing wells to separation units in two-phase flow by one pipeline could significantly reduce the budget for building the product gathering system. However, practice and studies showed that it would be effective only if the gas flow rate ratio β≤ 0.7.
JV Vietsovpetro crude oil, mainly being produced from the basement of southern part of the White Tiger field, is transported in form of two-phase flow from Satellite Platforms (SP) to Central Processing Platform (CPP) for gas separation through submarine pipeline (without thermal insulation). The crude has high wax content (up to 27% by weight), high pour point temperature 33-34°C, and average GOR of 166 m3/m3 @ 20°C & 100 kPa(a). The transport and gas separation processes encountered many difficulties due to pressure and flow rate fluctuations. Increasing pressure in the pipelines to 2200-2500 kPa(g) improved the situation, but not enough. A consequence was also that the well flow rates were decreased.
This paper describes the results from a full-scale field test on transportation of 5848 m3/day (@ 20°C & 100 kPa(a)) well product from SP to CPP as an oil and gas mixture. Studies were carried out on subsea un-insulated pipeline with OD 0.324m and length around 2000m, with gas flow rate ratios, varying from 0.623 to 0.868. Developed on the above basis the technology of preliminary gas separation on the SP and then transport of the gas and oil by two separate pipelines has assisted JV Vietsovpetro in elimination of a/m difficulties. Application of this technology would gain significant benefits when most of the wells on the SP moved to gaslift production.
Exceptional Proppant Flowback Control for the Most Extreme Well Environments: The Shape of Things to Come
Authors: Brannon Harold D. , Rickards Allan R. , Stephenson Christopher J. 
Published: December 2007

Abstract
Proppant flowback in deep hot, highly productive wells is a major problem in the oil and gas industry. Under these extreme conditions, many of the current products and processes to control flowback often fail. As such, improved or alternative technology and procedures are constantly being sought. One such technology is the development of deformable proppants.
Material and structural improvement to a deformable proppant has allowed laboratory test conditions to be extended to higher temperature, closure stress and flowrate. As a result of this fine tuning, exceptional proppant flowback control has been obtained. Testing of this new deformable proppant, blended with typical fracturing proppant, has shown 50 fold increases in flowrate and 100 fold increases in pressure drop are attainable without pack failure, while still maintaining fracture conductivity.
This deformable proppant has been applied in wells where current technology would either fail or have serious drawbacks. In two primarily gas producing reservoirs, the addition of this deformable proppant to proppant packs placed during fracturing treatments, has been observed to very effectively control proppant flowback under conditions of high bottom hole temperature, high fracture closure stress and high production regimes. The developmental testing, successful application and well performance all indicates significant improvement in proppant pack integrity.
A Preliminary Study of Development of Coalbed Methane (CBM) in South Sumatra
Authors: Kurnely Kun , Tamtomo Budi , Aprilian Salis , Doria Indria 
Published: December 2007

Abstract
Increasing gas demand significantly in Indonesia and its surrounding regions in the last decade affects on exploration of gas resources. Moreover, when the Indonesia government gradually cut subsidizing of oil based fuel price, then the gas price becomes more competitive.
However, the conventional gas reserves are decreased and more difficult to be found. The alternate gas sources, therefore, should be substituted to fulfill the gas demand in the near future. One of the most prospective gas sources is Coalbed Methane (CBM). This unconventional gas source has not been developed yet because of its exploitation technology limited.
Based on the previous study done jointly by Pertamina and PT. CPI, CBM in Indonesia is the seventh biggest resource in the world. It is about 337 TCF of CBM resources located in several Indonesia Basins. Among them, the largest part is in South Sumatra onshore (it is around 120 TCF of CBM) where it is close to gas consumers.
This paper presents a preliminary study of assessing detailed subsurface data (geologic, geophysics, geochemical and reservoir data) to look into the possibilities of CBM development including the evaluation of economics and environment aspects. This integrated feasibility study has been doing by analyzing shallow logging data, seismic, satellite images, laboratory data, topography, and environment data. The steps of study are discussed in details. A pilot project of exploitation/production of CBM is prepared by utilizing the existing gas facilities, and it is scheduled after a preliminary study finished.
Many benefits could be drawn from this work especially for backing up the energy consumption needs not only in South Sumatra regions but also in Indonesia and its neighboring countries.