bluuebunny/crossref_metadata_2025 huggingface dataset:
Intelligent Drill Pipe Creates the Drilling Network
Authors: Jellison Michael J. , Prideco Grant , Hall David R.
Published: December 2007

Drill pipe capable of transmitting high-bandwidth downhole data and surface control signals has been developed and successfully tested. The system incorporates a high-speed data cable protected in a high-pressure conduit that runs the length of the joint. The cable terminates at induction coils that are installed in protecting grooves machined in the secondary torque shoulders of double-shoulder tool joints at each end of the pipe. The system is virtually transparent to standard rig procedures and offers robust, reliable operation.

The new system has successfully demonstrated error-free, data transmission rates of up to 2,000,000 bits/sec. The bi-directional system can transmit real time MWD/LWD data, as well as, send commands or signals from the surface to operate downhole tools and sensors. Full-length prototype joints have been used extensively to drill and transmit data in test wells. Results of these tests, along with plans for field-testing in actual drilling environments, are presented.

Potential drilling enhancements include improved bit life, optimized casing point selection, enhanced kick detection and control, and elimination of wireline log runs and survey time to retrieve MWD/LWD data. Telemetry drill pipe can expand the potential for Underbalanced Drilling (UBD) techniques and improve the safety of UBD operations. The paper presents overviews of new concepts and technologies that can take advantage of the high-bandwidth, two-way communication capabilities of the system. Seismic-While-Drilling with the ability to look ahead of the bit, enhanced well control systems with sensors distributed along the drill string and drill string dynamics monitoring systems represent areas for innovation with the telemetry drill pipe.

Telemetry drill pipe can improve well and field productivity by providing more complete, real-time logging information and reduce drilling time and costs and enhance well control by providing real-time downhole drilling data and early kick detection.
Under-Balanced Drilling Experience in a Shallow Clastic Oil Field, Offshore Sabah, South China Sea
Authors: Bourgeois Gilles David , Chu Joanne , Terwogt Jan Hendrik , Mahran Awang Kasumajaya , Wisnugroho Alberthnego
Published: December 2007

Following encouraging results of Under-Balanced Drilling ("UBD") applications in the North Sea and onshore Canada, Shell Malaysia Exploration and Production ("SM-EP") embarked upon the application of this technology in a shallow clastic oil field in offshore Sabah. Relatively little information is available in the public domain regarding the effectiveness of UBD in clastic oil reservoirs. This paper provides factual evidence relevant to the assessment of UBD-induced added value. The paper also provides a comparison between the cost and benefit of UBD with that of Under-Balanced Perforating ("UBP") in a two-well trial.

Every pressure regime, reservoir fluid type, geological circumstance, etc, requires a specific operational configuration custom made for the situation at hand. This is a major source of UBD-induced incremental cost. Different reservoirs require different UBD configurations so analogies that assist the business case of a UBD project are currently limited and are difficult to find. This was the first offshore application of crude oil and hydrocarbon gas injection as drilling fluid in jointed pipe operations. A description of the incentives and risks of our specific geological circumstances is provided. Detail will be provided regarding our UBD design, main operational-risk mitigation measures, and the strategy used to appraise the added value of UBD. The complexities, incentives, and pitfalls of our UBD strategy will be chronicled. The initial results of this first-ever UBD trial within SM_EP will be published, along with the lessons that we have learned.
Pushing the Limit with Coiled Tubing Perforating
Authors: Acorda Edgar Paul R. , Engel Stephen P. , Chu Joanne L. J.
Published: December 2007

The use of coiled tubing in the oil and gas industry has become wide and varied since its inception some forty years ago. From its early applications of sand clean out and unloading wells, coiled tubing is also now frequently used to convey perforating guns. With the trend of new wells drilled to a more complex trajectory and with horizontal sections becoming longer and longer, perforating with e-line has become difficult, if not impossible. With the added benefit of underbalanced conditions, extreme lengths and weights of guns to perforate extensive intervals in a single run, coiled tubing has evolved into an invaluable tool.

This paper presents a case history where 2" coiled tubing was used to successfully convey some 2,900 ft of guns having a BHA weight in the order of 14 ½ tons. The trend of ever increasing BHA weights is extending the operating envelope and creating new records of longest and heaviest coiled tubing deployed perforating. Meticulous engineering and pre-job planning is a prerequisite for deploying these types of assemblies. Job simulation and operational data are presented to highlight the reliability of computer models in predicting the proximity of what can and cannot be achieved. Great focus is placed on tools and techniques that have been employed to reduce the friction in the BHA and coil. The paper also discusses the risk assessment and mitigation plans of pushing the technology to such limits.
Fit-for-Purpose Technologies Applications in Commercialising a Marginal Oil Field
Authors: Musa Mohd Bahrulnizam , Wai Foo Kok , Kheng Looi Lai
Published: December 2007

Alab is an oil field offshore Sabah, east Malaysia. It is about four kilometres from nearby offshore facilities and its water depth is 48 metres. With limited data from the only discovery well and a marginal STOIIP, it definitely required unconventional approach to commercialise the resource.

Among the possible development options, extended reach drilling (ERD) from the nearby facilities was chosen. The other options were satellite platform and subsea wellhead developments. Both are to be tied back to the nearby facilities. ERD technology was opted for its low CAPEX and early oil production due to ullage availability at the host facilities.

The marginal resource means little room for error, yet there are many uncertainties associated with the limited data. Reservoir simulation technology was used to assess the geological and operational uncertainties and risks. The reservoir simulation study results was used to firm up the reservoir development plan and to prepare risks mitigation plan. Using a structured analysis approach, the drilling uncertainties and risks are included in the probabilistically estimated wells’ duration and cost. In the way, the drilling uncertainties and risks are incorporated into the wells’ AFE.

In drilling the ERD wells, rotary steerable bottomhole assembly technology was used to drill the difficult turn-and-drop profile in production sections where normal mud motor is unable to overcome high sliding drag. To ensure good well production performance and to prevent the unconsolidated sand production, expandable sand screen technology was selected over gravel pack due to near horizontal well trajectories. The well trajectories have also made periodic reservoir monitoring such as PBU requires expensive CTU jobs. A bottomhole permanent gauge was installed in one of the ERD wells for the purpose, as it is more economics.

This paper is concluded with the benefits and value creations of the mentioned fit-for-purpose technologies.
Marginal Oil Developed in a BIG Way – A Case Study of the Development of Oil Reserves in the Pattani Basin
Authors: Schut Gerard , Kaweeyanun Pairoj , Duke Matthew , Samingkaew Kowit , Maroongroge Vichai
Published: December 2007

This paper describes how oil is being developed from small compartmentalized fluviatile reservoirs, stacked vertically from around 4000’ to 9000’ below sea level. The oil reservoirs are encountered intermittently amongst gas reservoirs. The oil and gas reserves are being developed through low cost wells and platforms that are installed and brought on production in a back-to-back manner in order to maintain the oil rate at the facility capacity of a new oil processing platform.

The paper provides some historical background and explains the challenges that were faced in bringing this project to fruition. Initially, the oil was considered a problem within the context of an existing and established gas infrastructure. Given the limited size of the oil reservoirs and the incompatibility of oil in the gas systems, an innovative development plan was required, that would enable sufficient economies of scale to reach economic viability.

A focussed team was formed to review options to develop the oil-rich gas prospects that were geographically spread over an area of around 250 km2. The oil development scheme that was chosen requires the back-to-back installation of over 10 wellhead platforms and drilling of over 105 wells. The oil is transported through 3-phase pipelines to a new oil-processing platform, from which oil is exported to a new export system and an FSO and gas is transferred to the existing gas infrastructure. Development costs are balanced against reservoir recovery using "fit for purpose" solutions to make the project economically viable. The paper describes the full development scheme, ranging from well design (spacing, drilling, formation evaluation, completion) through oil processing to oil export/storage, and explains which "fit for purpose" solutions were applied.

The project was fast-tracked, and risk management was applied to deal with the uncertainties in oil reserves/recovery and cost exposure associated with the oil development. From drilling the exploration wells to "first oil" production took only 19 months. The paper also reviews several factors that contributed to the ability to fast track and manage the risks of the project.
E8 Innovative Field Development
Authors: Bos Aat , Hamdan Idawati , Voon Chin Hon , Singh Updesh
Published: December 2007

E8 is a carbonate reservoir with an estimated ultimate recovery of 2.157 Tscf gas and 35 million stb of condensate. The reservoir is a carbonate build-up, consisting of two pinnacles connected through a saddle area. The field will be developed at a peak capacity of 600 MMscf/d. As a result of the study work for the FDP, the expectation recovery has increased by 370 Bscf gas. This is driven by an updated structural model based on a revised seismic interpretation. This has been achieved through a combination of improved depth conversion method (Depth Team Express) as well as uncertainty reduction based on seismic inversion techniques.

In the era of uncertain hydrocarbon prices, optimisation is aimed at ensuring high system availability, maintaining safety and environmental standards while achieving an economic development. This paper describes the efforts undertaken to maximise recovery from the field and the initiatives undertaken to resolve challenges. The main challenges faced in converting the development concept from standalone to satellite were production forecasting, security of supply, slug management and unmanned operations.
Merging "People" And Technology – A Case Study
Authors: Deka Mousumi
Published: December 2007

Oil India Limited is a premier Public Sector E&P petroleum company having major operational areas in the remote North-Eastern part of India with more than hundred years of experience in the business.

With the change in the economic environment and globalisation of Indian economy, it has become imperative for Oil India Limited to take advantage of new technology and merge it with existing culture and legacy seamlessly. Adoption of new tools in Information Technology for decision support and knowledge management has been the need of the hour.

To achieve the objective, a tailor made approach targeted towards ‘user traits’ was adopted. IT professionals worked closely with the professionals of different disciplines and, thereby, got the detailed insight into the mindset, functioning and procedures of various functions of the company. The ‘merger of minds’ of IT professionals with other core functions increased the acceptability of IT solutions at all levels.

This paper describes various methodologies Oil India Ltd. has adopted to introduce computerised crude oil reconciliation and special efforts channelised towards "people acceptance" of the new tools in lieu of largely manual system hitherto being followed in the company.
Competency, Development, and Training: Tools for Building Engineers of the Future
Authors: Suryodipuro Hudi D. , Thomas Bruce D.
Published: December 2007

How adequately are engineers prepared to meet the challenges of the industry today, using various tools such as competencies, development programs, and state-of-the-art training techniques?

This paper will describe a global development and competency framework for technical personnel that both describes and tracks job competencies to the task level, with respect workflow processes, through the three points below:

Utilizing blended learning techniques (combination of instructor-led activity, online training, simulations, seminars, and university programs) will provide the means of developing knowledge. By participating in development programs, engineers will work under a mentor to learn the application of a particular role, of skills and of behaviors that are associated with the role. The competency process, as the gateway, will be used to assess and ensure that all knowledge, skills, and behavior are sufficient to perform tasks in accordance with company standards.
Experience in Developing a Web Base Workflow to Enhance Competency
Authors: Ming Yeow Lei
Published: December 2007

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

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

The 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

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

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

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

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

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

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

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

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

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

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.
Tele-Maintenance for Remote Online Diagnostic and Evaluation of Problems at Offshore Facilities, Sarawak
Authors: Mayer George , Zubir Wan Abdullah , Ming Lim Ai , Chang Robert
Published: December 2007

Shell Malaysia EP (SMEP) is the major gas supplier to Malaysia Liquefied Natural Plants (MLNG) namely MLNG- Satu and MLNG-Dua. Gas is piped from SMEP's five offshore Gas platforms – E11, F6, F23 (Central Luconia) – serving MLNG-Satu and M1 and M3 (M Fields) catering to the demand of MLNG-Dua. MLNG-Tiga, the third MLNG plant is scheduled to come on-stream in 2004.

With production levels reaching new heights and even tighter margins between supply and demand, it has warranted the Maintenance team to re-look at new ways to manage and secure uninterrupted gas supply to the customers.

Traditionally, whenever there was a situation which could lead to a possible gas supply interruption, frontline operation technicians on the platforms would provide the first line of "defense" in reinstating the plant and the troubleshooting process very often involved conventional telephone communication with the shore-based specialists in the head office to try and resolve the problem jointly. Failure to resolve the problem in this manner would result in the deployment of a support specialist to the affected location. An impediment faced by the support team in this arrangement is that very often it is difficult to accurately ‘visualize’ the problem and provision of the ‘correct’ advice becomes constrained. As experience has shown, some plant outages have fallen in the order of more than 24 hours and this is highly undesirable.

As it is impossible to guarantee a plant uptime of 100% indefinitely, SMEP's main stumbling block was to ensure that recovery time was kept at a bare minimal. If this can be limited to three hours or less (based on the packed pipelines pressure retention time), gas supply interruption to the customers can be avoided. Armed with the determination to seek this solution, SMEP began its journey through the threshold that marked the birth of Tele-Maintenance.

SMEP realized that to further enhance current communications between on-site technicians and shore-based specialists, a ‘visual’ perspective was vital to supplement the existing ’audio’ element via traditional telephone communication. With the innovative use of Information Technology (IT), Tele-Maintenance came into being and it was specifically designed to circumvent similar incidents. In essence, Tele-Maintenance is a tool that enables specialists to be ‘virtually’ present at these situations albeit remotely from their office. With this real-time ‘sight’, specialists are now able to collectively provide offshore support within a shorter time frame, thus eliminating the need to travel offshore (if problem can be resolved remotely), ultimately minimizing down-time.

This paper illustrates, in detail, SMEP's experience as the pioneers in the Shell Group to successfully develop and implement Tele-Maintenance for its offshore locations.
Implementation of Data Collection Automation to Support Predictive Maintenance in the Minas Field
Authors: Wulandari Nur Diani , Irawan Wawan
Published: December 2007

Production equipments should be maintained if it is to fulfill its function for a useful life. One of the strategies is predictive maintenance (PM) where accurate and sufficient data availability is very important. Nowadays, Human Machine Interface and microprocessor-based field instrumentation becomes a standard tool of plant stations operation in the Minas field and reduce human limitation for equipment data archival. This system combined with powerful database provides good information for PM strategies.
Improving Production Monitoring and Surveillance by Using an Integrated Production Data Management
Authors: Aprilian Salis , Maria Regina
Published: December 2007

Pertamina Upstream's strategy is "First Quality, Then Growth". As a part of Pertamina's drive to improve quality (productivity and efficiency), Pertamina DOH SBS which is the biggest upstream business unit of Pertamina located in South Sumatra initiated the steps, towards the end of the year 2000, to improve the overall data quality and information management process related to production monitoring and surveillance.

With the vision to fully automate the production information system, Pertamina DOH SBS reviewed the availably commercial software offered in the area of production information management. The solution is intended to provide a structured data capturing system as well as overall framework towards an integrated Production Data Management System (PDMS) for Pertamina DOH SBS.

The system implementation was successfully completed in the first quarter of 2002. It is used everyday to capture daily field production data, production allocation, and it provides "Daily Morning Production Report" posted at the Pertamina DOH SBS website (intranet) by 8am every morning.

This field data capture system replaced the MS Excel™ spreadsheet files that were used previously to capture and store daily production data. It also provides the user quality control tools like graphical visualization of historical data, which has significantly contributed towards increasing the confidence in the quality of data.

This Production Data Management System provides the engineers with reliable data, thus minimize time spend for data collecting. Instead, more time will be spent for engineering analysis to increase field productivity. Besides savings in the time, the improved quality and timely availability of data will considerably improve the success rate by allowing users to make well informed decisions.
ESP Run Life Improvement in Harsh Elastomer Environments, the Moomba Field
Authors: Young J. , Kappelhoff G. H. , Watson A.
Published: December 2007

Typical run lives of electric submersible pumps (ESPs) in the Cooper Basin in Australia are in the range of 600 to 900 days. ESPs have been used in 15 different reservoirs in this area. When highly productive oil reservoirs were recently discovered in the Moomba area similar run lives were expected.

However, the first 12 installations in the Moomba fields only ran an average of 87 days. In 2001 a team was formed to target improved run lives. The team included production, manufacturing, engineering and management personnel from the operating company and equipment supplier.

The main problem areas identified were protector and electrical wellhead feedthru failures and power supply quality. This paper outlines the operational, engineering and equipment changes made in each of the problem areas and the resulting increase in run lives.

Failure analysis of pulled equipment demonstrated that the elastomers utilized for motor protection were being degraded. Compatibility testing of elastomers, produced fluids and injected chemicals revealed that the produced oil and water were causing the elastomers to breakdown. Although the wells were vertical, conventional labyrinth protectors could not be used because of the low gravity of the crude. The solution was to engineer a new motor protection system that was virtually elastomer free. The design utilizes metal bellows, high-density oil for gravity separation protection and high-grade o-rings. This design resulted in the first ESP motor protection system that can be used in environments with light crude that is incompatible with standard elastomers.

In addition, analysis of the power quality showed that the crude fuel utilized to power the generator sets was affecting power quality. The poor quality of the power supplied to the ESPs was potentially contributing to motor burns and wellhead penetrator failures. To improve power quality a cleaner fuel supply was sourced.

The run life improvement project is ongoing and the outcome of increased run lives is readily demonstrated.
Comparative Evaluation of Single Vs. Multi-Mandrel Gas Lift System for an India Offshore Field
Authors: Kumar Adesh , Gupta V. P.
Published: December 2007

Mumbai High field is located in Western Offshore of India, 160 km South West off Mumbai City. The field was discovered in the year 1974 and put on production in May 1976. Massive development plan was undertaken in phases and a peak production rate of about 400,000 bopd was achieved during year 1984. To maintain reservoir pressure, suitable water injection scheme was put in place in 1984-85. The conventional multi-mandrel gas lift system was applied as artificial lift mode and operating in the field since 1987.

In multi-mandrel conventional gas lift system, 4-6 mandrels are used in the well. The GLVs in upper mandrels work as unloading valves and orifice valve in last mandrel act as operating valve. As mentioned earlier, the gas lift started in the year 1987 in this field and in 1994-95, a significant number of wells (more than 100 wells) were put on gas lift. The system utilizes compressed gas at 1000 to 1350 psi (at well head) in different complexes. The existing compression system is an integrated system, which supplies gas to gas-lift network and balance gas to sales line leading to onshore plant. Presently, 381 wells are operating on gas lift (out of 454 wells completed with gas lift) and contributing about 80% of total oil production from Mumbai High.

During the incipient stages of gas lift, CFP recommended single mandrel single point gas lift system with a gas lift pressure of 1800 psi for unloading and 1400 psi for normal gas lift operation. Considering the availability of present gas compression system at about 1400 psig, as per worldwide practice, conventional gas lift system with multi-mandrels in place was accepted by ONGC. By doing so, major compression system revamp and consequent delays were avoided.

In the recent past, some of the major operators, especially in North Sea, have applied the Single Mandrel Gas Lift System (referred here as Single Point Gas Lift) to overcome the inherent disadvantages of conventional gas lift system. Presently, Mumbai High is undergoing major additional re-development plan to augment oil production, the present conventional gas lift system needed re-look to draw a learning curve. It is in this context, a detailed exercise has been carried out to evaluate the present conventional gas lift system involving its efficacy and well servicing costs.

The present paper analyzes advantages of single point gas lift over conventional gas lift, the requirements of single point gas lift for Mumbai High, efficacy of conventional gas lift system, present major and minor well servicing costs and other related issues for implementation in Mumbai High. A detailed techno-economic analysis is presented. It is observed that the multi-mandrel system of gas lift is more effective for this field and should be pursued for future development schemes of this field.

The field is currently undergoing a major redevelopment exercise. Hence, a cost-economic evaluation of present system is essential for future decision process.