Global uncertainty and heavy competition require E&P companies to remain effective in investments and prudent in people development. These challenges compel us to have a learning system that links to business objectives and enables effective knowledge transfers. This paper outlines a structured learning framework which is a competency-based system that links learning objectives to desired business results and establishes a mechanism for identifying, developing, measuring and tracking individual competencies and capabilities.
The Technology Mastery Program is part of an integrated program, which covered data, processes, tool and people as the heart of the program. It is to maximize the return on investment in technology, reduce interpretation cycle time, enhance the workflow application, improve quality of the result and decision-making.
The structure uses a credit-based system to monitor and measure technical competencies through accreditation of technical skills. The learning curriculum is built to facilitate cross training by offering broad-based competencies in multiple disciplines. The learning sequence complements the methodology by providing web-based training before, and after the course, immediate application in the current work, mentoring, and assessment. The process addresses common problems that occur with many training programs including timeliness, relevancy, transfer of skills to the job, and learner accountability for results.
People can accelerate their acquisition of technical knowledge and increase professional development in this self-driven framework. Furthermore, the program is aligned to meet the requirements that lead to the specialist technical ladder which was recently introduced in the company.
The program was conducted in stages commencing mid-August 1999 and has proven to be very successful. It is currently in its third stage and as each stage progressed, new disciplines were added and program upgrades made based on lessons learnt. As of June 2003, one hundred and eighty five staffs from Geology, Geophysics, Formation Evaluation, Reservoir Engineering, Production Technology and Petroleum Economics have enrolled into this program. They are working either in exploration, development or production based projects and have benefited from this program, which resulted in reserves addition, and profitability of the company.
Betancourt, Soraya S. (Schlumberger-Doll Research) | Fujisawa, Go (Schlumberger-Doll Research) | Mullins, Oliver C. (Schlumberger-Doll Research) | Eriksen, Kare Otto (Statoil ASA) | Dong, Chengli (Schlumberger) | Pop, Julian (Schlumberger) | Carnegie, Andrew (Schlumberger)
In addition to geological and petrophysical data acquisition during the exploration stage, in-situ fluid analysis provides a wealth of information for the appraisal of new discoveries. A recently introduced wireline sampling tool incorporating a downhole fluid analyzer is capable of analyzing fluid composition in real time at downhole conditions, and of measuring the fluorescence spectra of crude oils. These new measurements provide valuable information necessary for the identification and validation of reservoir structures that define the distribution of fluids in the accumulation. The relevance of high quality fluid data in the early stages of the producing life of the reservoir is widely recognized. We present field results of the application of the new sampling tool in an exploration well, where a composition gradient was detected along a 30m liquid hydrocarbon column grading from a 45API crude on the top to a 33API crude on the bottom. During the sampling of the gas cap, retrograde dew formation was detected identifying the fluid and identifying valid sampling conditions. This new information was used to modify the sampling program. Fluid composition analysis relies on optical absorption methods and is currently capable of providing the mass fraction of three hydrocarbon molecular groups: C1, C2-5 and C6+, and CO2. We perform fluorescence spectroscopy by measuring light emission in the green and red ranges of the spectrum after excitation with blue light. Fluorescence in this range is related to the concentration of polycyclic aromatic hydrocarbons (PAH's) in the crude oil. Using the pump-out module to segregate different fluid phase enhances phase detection with fluorescence.
Flew, Stephen (Schlumberger) | Mulcahy, Matthew (Schlumberger) | Stelzer, Hermann (Schlumberger) | Boitel, Alain (Schlumberger) | Zainuddin, Faizal (Petronas Carigali Sdn Bhd) | Harun, Abd Rahman (Petronas Carigali Sdn Bhd) | Hassan, Zulkarnain (Petronas Carigali Sdn Bhd) | Aziz, Kamaroll Zaman A. (Petronas Carigali Sdn Bhd)
After more than 20 years of production, the 800 million STB Bokor field, offshore Sarawak, Malaysia, is set to undergo a revitalization to increase production rates and recovery factors. A joint PETRONAS Carigali (PCSB)-Schlumberger team was formed to review the field and develop the first full field simulation model, which will be utilized as a ‘live' model for identifying further potential and for future reviews. This paper outlines the modeling workflow and processes developed to allow the study to be completed within a shorter duration than with a conventional approach, as well as the key study results.
Made up of some 130 vertically stacked reservoirs over a 6,000-ft interval, evaluation of the field is hampered by the lack of any useful seismic images over the hydrocarbon zone, owing to shallow gas and other anomalies. Understanding the reservoir behaviour has always been a challenge, with the degree of sand consolidation in the reservoirs varying from totally unconsolidated at 1,500 ft subsea, filled with 10 cP oil, to consolidated deeper sands, with 0.1 cP oil at 7,500 ft subsea. In addition, the limited pressure depletion owing to the presence of a very strong aquifer, and the fact that many fluid contacts have not been penetrated, means that significant uncertainty still exists over the likely stock-tank oil initially in place (STOIIP).
By fully utilising all available data and an iterative team-based approach to history-matching the geostatistical models with production data, an understanding of the key parameters was gained. This revealed that in many reservoirs, what was previously considered poor-quality rock was in fact a major contributor to reservoir flow, being neither as poor in permeability nor as high in water saturation as previous interpretations suggested.
Through the increased understanding gained during the review, robust predictions have allowed new facilities to be appropriately sized, allowing the field to begin its new lease of life.
Although application of horizontal well technology is categorized as a relatively new and expensive but it has been proven more effective and efficient in producing oil. However, the production rate strategy to obtain optimal result has not been well developed due to the difficulties to identify the influence and interaction of forces related to fluid flow mechanisms in reservoir. Particularly for oil reservoir with bottom water drive, the movement of water-oil contact/interface in a reservoir is strongly affected by interaction of the acting forces, such as: viscous force, gravity force and capillary force.
The main objective of this research is to study and investigate the influence of the forces interaction on production performance of the horizontal well producing oil from bottom water drive reservoir. For this purpose, a physical scaled model has been successfully constructed to simulate the production performance. Scaling down and construction of the model are performed by using dimensional analysis.
Results show that the interaction of the forces in the reservoir strongly affects the well production, in which the production performance increases as the ratio of gravity to viscous forces increases for all cases examined. Meanwhile, the changing of capillary force, which was believed by several researchers that it has no pronounced effect to the fluid flow mechanism in the reservoir, shows significant effect to the production performance of the well. The influence of reduced capillary forces in reservoir will enhance the well production performance. Consequently, in term of the ratio of gravity to capillary force, an increase in the ratio tends to improve the oil recovery.
Naturally Fractured Reservoir (NFR) characterization represents an increased focus for oil and gas companies as it becomes more and more admitted that they represent a substantial part of their portfolio. However the complexity of the understanding of fractured reservoirs, in terms of fracturing mechanism, fracture density, orientation, and the complexity of their management issues (i.e. infill drilling, water production, steam injection, to list few of these issues) pushed several service and integrated companies to tackle the fractured reservoir characterization challenge. Moreover the use of integrated approaches with the help of 3D seismic and new technologies are started to show successful results. This paper will present two technologies where 3D seismic attributes along with geologic and engineering data are being used to characterize fractured reservoirs. The first technology will show how the use of post-stack seismic in an integrated approach, involving high resolution seismic inversion, spectral imaging and static geological modeling, provides an accurate fracture reservoir model that can be applied in the reservoir simulation and development stage. The second technology will highlight the use of pre-stack seismic to actually image the fracture distribution. Application of these technologies is presented on two different fields.
This paper explores the application of LCC (Life Cycle Costing) concepts in the oil and gas industry. The paper details research into the development of a LCC model for using in SAP (System, Application and Products in Data Processing). Information held in the existing system in the oil and gas industry has been investigated in order to determine whether or not it is adequate to support LCC application for assets. The conceptual framework will develop the LCC technique as a tool to carry out costing analysis for new and existing systems. It will ensure that existing systems data are optimized for use in LCC applications and will investigate the feasibility of integrating the LCC model with existing systems. Based on this conceptual framework a LCC model will be developed.
The proposed system model provides a structural breakdown of cost (SBC) that can be applied to any asset at any level, such as super system, system, sub-system and equipment level in its lifecycle. The purpose of this SBC is to act as an aide memoir, as the starting point for developing a project/asset specific SBC that is tailored to the needs of a particular LCC requirement. The overview of SBC is provided to identify the data requirement for estimated cost element and provides a definition for cost element.
Consequently, if SAP-LCC is used for analysis at every, it is possible to identify the level that is the most significant in order to develop or reduce the cost in LCC at that level.
Effective management of oil and gas fields over field life with the objective of maximising asset value can be a complex affair. Application and integration of various skills from subsurface (geology, geophysics, petrophysics, reservoir engineering, production technology and drilling) to surface engineering, production operations / surveillance and economics disciplines are required to manage technical, commercial and political challenges and uncertainties. In large organizations, there are the additional challenges of ensuring consistent work quality and process with multiple projects and technical personnel with different levels of skills and experience.
Subsurface and economic disciplines workflow over a field life from acquisition of exploration or development areas, exploration, development, production and abandonment work activities were mapped, improved and integrated to ensure work are executed more efficiently and correctly.
This paper describes the techniques and activities involved in developing this workflow which incorporates data and information management, technology mastery and promoting a collaborative and integrated multidiscipline approach. It was developed and deployed in two phases over 3 years and became the first web enabled workflow in the organisation. Pilot implementation was carried out on a number of domestic, international and outsource Field Development and Field Review projects.
Case histories of the application, benefits gained and lessons learnt are discussed this paper.
The paper introduces some problems that subdivision injection and production technology is facing in the stage of extra-high water cut production in Daqing Oilfield, the problems have become main factors affecting sustained development of Daqing Oilfield, like subdivision water injection, separate layer fracturing in thin restraining barrier and injecting surfactant to reduce pressure problem, each of them is close to challenge technical limit.
This paper introduces the performance history of the Daqing Oilfield and analyzes the potential for further development.
The residual oil distribution characteristics are analyzed taking the advantage of the core data of Well La8-JP182 and Well Bei1-330-J49. Then the numerical simulation method is used to analyze the recovery ratio, production rate, and the variation of pressure gradient under different production conditions. Finally, the technology of potential tapping of the isolated untabulated reservoirs, tabulated reservoirs, the huge thick reservoirs, and multiple rhythm reservoirs are brought forward in this paper.
Daqing Oilfield has undergone the water flooding stage, the artificial lift production stage, and the stage of polymer flooding since the oilfield was put into production in 1960. The pressure gradient between the producers and the injectors were raised after each conversion of the stages. As a result, the pressure gradient rose from 0.15MPa/60m in the flowing production stage to 0.62MPa/60m in the polymer flooding stage. The production rate and the recovery ratio were increased. There is little room left for increasing the pressure gradient further. Whereas, The analysis of the reserve potential in Daqing placanticline area indicated that the residual recorerable reserves in basic well pattern and the first round infilled wells pattern are still relatively reacher, which is 19,287×104tons and 14,871×104tons respectively. Therefore, the optimization and the combination of various development regimes, the production methods should be taken into consideration to tap the potential further. Moreover, the efficiency of the combinations should be forcasted either through numerical smulation method. The following pages analyze the residual oil potential in Daqing Oilfield, the simulation results, and the technologies to be taken for different layers.
Residual Oil Potential Analysis
The Daqing Oilfield has been developed for 44 years. And 36.81% of the total OOIP has been produced by water drive method, which accounts for 75.57% of the recoverable reserves. Current water cut of the oilfield is 88.9%. The annual output of polymer flooding is 1,134×104tons. The oilfield has entered the late stage of high water cut period. Therefore, It becomes harder and harder to continue producing as much as before. The potential distribution analysis is base for further develop the oilfield.
Core data of Well La8-JP182 and Well Bei1-330-J49 were used to analyze the status and the distribution characteristic of the residual oil.
Core data of Well La8-JP182 were got before polymer driven. The analysis of the data revealed watered out status of the core. The Well La8-JP182 encounted three sets of oil reservoirs vertically, which are S, P, and G reservoirs respectively. All the layers in these three groups add up to 73.9m, among which 15.4m are not watered out, 4.9m are watered out slightly, 36.1m are watered out medially, and 17.4m are watered out heavily. In terms of percentage, they are 20.9%, 6.7%, 48.9%, and 23.5% respectively. There is 26.3% of thickness of S reservoirs layers unwatered out. That of G reservoirs is 37.4%. As for the P group, on the other hand, there is 3.91% of thickness that is not watered out. Threfore, the residual oil potential in S and G reservoirs are much richer than that of P reservoirs after water drive.
The total thickness of isolated untabulated reservoirs in this well is 26m, among which 22.7m are not watered out. The unwatered out thickness accounts for nearly 90% of the total isolated untabulated reservoirs thickness.
The Well Bei1-330-J49 was drilled after polymer flooding. The core data of this well indicates that more than 74.3% of total thickickness are watered out. Whereas, watered out layers are mainly concentrated in the PI2 payzone, while the other layers are washed slightly. After polymer flooding, there are still some potential to be tapped in relative thinner layers.
The paper introduces oil production engineering series for heterogeneous, multilayer sandstone oilfield in the basis of separate zone production in the four development phases including production and stable production. The technologies provide technical means for realizing "Three-changes" of oilfield development, make an important contribution for keeping stable production of 50 million tons for 27 years in heterogeneous, multilayer sandstone oilfield. The development process and several technologies for different development phase are introduced in the paper.