Probabilistic aggregation and dependency estimation are essential in portfolio methods, production forecasting, and resource estimation. The use of arithmetic addition understates the true value of the resource estimates within a portfolio of fields. Potentially, this could result in deferral of a project, or loss of lucrative business and commercial opportunities, such as project investment, facility-sizing decisions, or incremental gas-supply commitments.
A statistically robust method for aggregation of resource estimates that appropriately uses expert opinion is presented in this paper. Using two integrated-project examples, this paper introduces new methods for (1) probabilistic aggregation of the resource estimates for multiple fields and (2) estimating a measure of dependency between the resource estimates of individual fields.
The new analytical method for probabilistic aggregation is based on multivariate skew-normal (MSN) distributions, which can model a wide range of skewness through a shape parameter and are used heavily in financial and actuarial applications.
In studies of the fields in which the multiple-realizations approach is used as a basis for the uncertainty framework, tornado diagrams are generated routinely to describe the dependence of the field resources on reservoir parameters. The improved method for evaluating measures of dependency between the resource estimates within a portfolio of fields uses these tornado diagrams as a basis. Incorporating the expertise and knowledge of geologists and petroleum engineers is a critical element of the method.
These methods for probabilistic aggregation and estimating dependencies were developed within the context of the oil industry, but their use is not limited to the oil industry. They are general and can be used in other probabilistic-aggregation problems. Application of these techniques requires limited time and effort, compared to individual-field studies, and can have a profound impact on the uncertainty range of the total resources for the portfolio of fields.
Forecasting the production of large LNG projects is challenging and must consider:
These challenges establish the need for forecasting tools that cover the full supply chain of a project, from the reservoir to the physical point of sale and the sales contracts. Tools need to be fully integrated taking into account business, strategic and commercial decision-making processes.
Woodside's bespoke Database Integrated Modelling Environment (DIME) has been built specifically for forecasting and optimising complex LNG projects producing from a diversity of fields with significantly different condensate and LPG yields. The tool provides fast, accurate forecasts for:
Because DIME enables modelling from the reservoirs to the plants and sales delivery point, it forecasts sales products and therefore directly provides a forecast for revenue. The model is fully compositional and pressure-sensitive, and designed for system optimisation.
Addis, Michael Anthony (Shell International) | Gunningham, Michael Caspar (Sakhalin Energy Investment Company Ltd) | Brassart, Philippe Charles (Shell) | Webers, Jeroen (Sakhalin Energy Investment Company Ltd) | Subhi, H. (SEIC) | Hother, John Anthony (Proneta Ltd.)
Sand Quantification involves predicting the volumes of sand which can be produced at the sandface completion and transported to the surface facilities for different operational scenarios. Sand quantification estimation is still novel in the industry, and this paper describes its application in completion selection and design, facilities design and operation, and facilities risk evaluation, with reference to a high rate gas field development.
The estimation of sand production volumes for openhole and cased and perforated completions is presented for the high rate gas wells, along with the workflow used for the selection and optimisation of the completion design, based on these estimates. The optimum completion aims to delay the onset of sand to surface for the first 18 years of production, whilst maintaining high gas productivity (>300mmscf/d/well). The selection of contingency sandface completions is also discussed along with mitigation measures in the event of unexpected sand production. The impact of the sand quantification on surface facilities design is discussed based on a probabilistic approach, along with the operational procedures identified to manage this sand.
The operational evaluation is based on a Quantitative Risk Analysis (QRA) of the facilities and wells, which helped identify operational changes to further reduce the ‘as built' low risk operation. This use of sand quantification for completion design and for QRA of facilities forms a new capability and an extension to the existing use of sand prediction technologies.
Offshore gas production, supplying LNG trains, has been carried out in the Indian Ocean off the North West coast of Western Australia since 1989. The producing fields are in water depths of approximately 130m with ambient seawater temperatures and operating conditions that result in only occasional concerns about potential hydrate formation in the production systems. The latest tranche of gas fields under exploration and development offshore WA, which will also supply LNG or GTL facilities, has much more onerous hydrate management challenges, which result in significant facilities demands. Why? This paper discusses the contributory factors, as well as mentioning other challenges to the development of these deepwater gas fields offshore WA.
This paper is a case study, which describes how Quantitative Risk Assessment (QRA) is applied to sand management in the specific case of Lunskoye, to minimise risk of failure, while maximising production, reducing cost, and safeguarding reserves. Lunskoye is a high-rate gas development offshore Sakhalin island. The key concern is safely producing gas at high velocity, while minimising the risk from sand production.
In order to develop a safe method of producing gas, an integrated multidisciplinary team was put together to address the key parameters to manage potential sand production, using QRA.
In particular, consequences, probabilities of occurrence and means of monitoring and control were addressed. The key aspects of this approach are using the right kind of technology to design a safe production system, and then using the appropriate data to monitor and manage the impact of sand production.
The "intelligent tool?? that was used allows an experienced integrated team to focus on the practical aspects of managing sand production in a structured and systematic manner to quantify the residual risk to people, facilities, and the asset as a whole. That tool also allowed us to integrate the inputs from widely spaced geographical locations - the production system was designed in the Netherlands, and was being built in Korea, then relocated to Sakhalin island.
The QRA involved the operator (Sakhalin Energy) and technical advisor (Shell), combining input from the corporate knowledge base with that of the asset team. This delivered operational plans that provide the key guidance for safe operation, which was endorsed by the operator and its shareholders. Overall, the value of this work has significantly reduced the risk exposure to the project, while reducing well completion costs and safeguarding production in the long term.
Neubauer, M.C. (Australian School of Petroleum, University of Adelaide) | Hillis, R.R. (Australian School of Petroleum, University of Adelaide) | Reynolds, S.D. (Australian School of Petroleum, University of Adelaide) | King, R.C. (Australian School of Petroleum, University of Adelaide)
Knowledge of the contemporary stress field is vital to the petroleum industry for assessing trap integrity and establishing drilling directions and mud weights to optimise wellbore stability. High quality image log data from 63 petroleum wells in the Carnarvon Basin were analysed for borehole breakouts and drilling- induced tensile fractures to ascertain the orientation of the contemporary horizontal stresses. Orientations were consistent across the basin, with a regional mean maximum horizontal stress orientation of approximately 105°N. Over 80% of the mean borehole breakout and/or drilling-induced tensile fracture orientations of each well, showed mean stress orientations within 15° of the 105°N mean orientation. Stress orientations were also consistent in the vicinity of faults, contrary to previous interpretations from caliper logs, where faults in the area locally perturb the stress field. A preliminary investigation into the magnitude of the contemporary stress field of the region suggests the Carnarvon Basin is in a strike-slip faulting environment, implying that the most stable drilling direction is horizontal. The majority of faults in the Carnarvon Basin are steeply dipping and strike north-south and northeast-southwest. These fault orientations are not at risk of reactivation in the regional stress field. Results from this study are included in the Australian Stress Map database, which is becoming increasingly recognised for its vital importance to petroleum professionals as a source of contemporary stress information throughout the Australian continent.
The key driver of this study was to investigate the occurrence of anomalous northeast-southwest maximum horizontal stress (SH) orientations derived from caliper logs (Mildren 1997) in the otherwise consistently oriented east-west regional stress field. The extent to which faults perturb the stress field is particularly significant to the pre-drill prediction of stress orientations.
Tan, C.P. (CSIRO Petroleum) | Yaakub, Mohd Azriyuddin (PETRONAS Research & Scientific Services Sdn. Bhd.) | Chen, Xi (CSIRO Petroleum) | Willoughby, D.R. (CSIRO Petroleum) | Choi, S.K. (CSIRO Petroleum) | Wu, B. (CSIRO Petroleum)
The development plan of an oil field in the Sarawak Basin, South China Sea includes extended reach wells. Drilling experience in exploration wells highlighted the issue of wellbore instability in the region. A wide range of wellbore instability-related problems has been experienced, ranging from tight hole (remedied by reaming) to overpull and stuck tool, and a range of drilling fluid designs has been implemented. There was considerable concern regarding wellbore stability, including coal bed instability, its effect on drilling performance and the potential for this to severely impact both schedule and budget. Subsequently, a wellbore stability study, with an emphasis on extended reach wells planned for the field development, was conducted. The aim of the study was to develop a strategy to maintain mechanical and time-dependent stability of the extended reach wells to ensure the well construction encounters minimum wellbore instability-related problems. With the availability of additional well data and the need to push the technical limit of the drilling campaign, a follow-up review study was conducted and the additional information was used to refine the critical mud weight contour plots for a range of wellbore enlargements.
This paper describes the outline of the study, the approach adopted in the development of the strategies and the utilisation of the results from the two studies to develop recommendations for the mud weight programs. The drilling experience, material properties, typical in-situ stresses and formation pressure in the field are presented and discussed. Based on the gathered drilling experience, composite logs and laboratory tests conducted on downhole core materials, dominant failure mechanisms for the key formations and coal beds were identified. An empirical approach was adopted for the prediction of lower bound mud weights for wellbore enlargements ranging form 10% to 40% of wellbore diameter. Examples of critical mud weight contour plots and pore pressure change tables which form part of the strategy for designing optimal drilling fluid program are presented.
Tan, C.P. (CSIRO Petroleum) | Hamid, Pauziyah Abdul (Petronas Research & Scientific Services Sdn. Bhd.) | Chen, X. (CSIRO Petroleum) | Yaakub, Mohd Azriyuddin (Petronas Research & Scientific Services Sdn. Bhd.) | Willoughby, D.R. (CSIRO Petroleum) | Wu, B. (CSIRO Petroleum)
Drilling experience in Alab and Samarang fields in the Sabah Basin highlighted the issue of wellbore stability in the region. A wide range of drilling problems has been experienced, ranging from tight-hole to overpull and stuck pipe, and a range of drilling fluid designs has been implemented. Subsequently, a wellbore stability study was conducted to address the problems in the planned extended reach Alab wells. The aim is to develop a strategy to maintain mechanical and time-dependent stability of the extended reach wells to ensure well constructions encounter minimum wellbore instability-related problems.
This paper describes the outline of the study and the approach adopted in the development of the strategy. The drilling experience, material properties, typical in-situ stresses and formation pressure in the Sabah Basin are presented and discussed. Based on the gathered drilling experience, caliper and composite logs, and laboratory tests conducted on downhole core materials, dominant time-dependent failure mechanisms were identified. Mud weight stability profiles and examples of critical mud weight contour plots which form part of the strategy for designing optimal drilling fluid program are presented.
Comparisons were made between predicted mud weights determined from the contour plots and mud weights used in the field together with associated drilling experience and hole size in a post-drilling review. The comparison showed a good agreement for a low angle well but inconsistent for two high angle wells. The reasons for the inconsistencies and means of reducing the uncertainties of input data required for wellbore stability study are presented and discussed.
Effective two-way communication and data flow between rig and office is essential to optimise decision making in offshore operations. Traditionally, during drilling operations, engineering, geological and formation evaluation while drilling (FEWD) data was only available at the Operator's office via morning and afternoon reports, email, shared folders and telephone. Information technology has now evolved to a stage where office-based geologists and engineers can monitor and evaluate wellsite data in real time using the Internet and any standard web browser. This enables domain experts to provide more effective support to the wellsite staff especially when critical decisions are to be made in a timely manner.
This paper describes how modern information technology such as InterACT (Formerly called InterACT Web Witness: or IWW) facilitates collaborative work in real-time on data being acquired from remote drilling wellsites. The availability of data real-time does create a paradigm shift in the way the asset team and contractors utilize data for early decisions. Challenges, benefits, and lessons learnt on the implementation and application of this technology are highlighted through examples where this technology was used namely: Echo/Yodel development drilling campaign (Woodside Energy Ltd.) for Geosteering Decisions and Melville-1 exploration well (Bass Strait Oil Company Ltd) for monitoring drilling, FEWD and wireline logging.
Experiences from these two projects gained by Schlumberger can be utilized by other companies to put in place a data flow model incorporating real time data.
Drilling for hydrocarbons and minerals often takes place in remote areas. While the operation takes place in the remote location, much of the planning, expertise and decision-making authority is located either in a town office or distributed amongst geographically spread out towns/cities and even operating companies. Data from the remote rig, whether it be land or offshore traditionally has been either faxed to town or communicated over phone. With the advent of higher speed point-to-point data connections, data was sent via e-mail, FTP'd or dropped into a shared folder. This form of communication was usually point-to-point and some cases, point-to-many.4 With the availability of higher speed links and the internet, technology has evolved such that data now can be made available to centrally located servers and distributed to all stakeholders wherever they may be, from remote locations in real-time, without the need of specialized software installation. InterACT© is one such system where data is delivered real time and provides a platform for Data Collaboration.
What is InterACT?1
The InterACT wellsite monitoring and control system provides a Web-based data delivery, which
Is fast and secure,
Is real time
And has interactive/ collaborative tools