For the screening of a significant new LNG development a multi-tiered optimization tool was built with the following objectives:
To optimise the sequence of drilling and producing condensate and gas from a field consisting of multiple stacked reservoirs.
To understand that gas requirements could be fulfilled to supply gas to the multiple planned LNG trains
To evaluate if the tool delivered export results of various scenarios for economic screening and future auditing
An integrated model was built consisting of a Controlling Optimization Software (Resolve) to communicate and control the link between a Surface Network Development (GAP), the wells (Prosper), material balance model (MBAL) and a data export and plotting software (Excel). Visual workflow programming in Resolve allowed for simple adjustment of constraints and inputs through all the linked models which can optimise of multiple scenarios.
Parameters that were optimised included:
Sequence of reservoirs to produce
Well phasing over the different reservoirs showing varying condensate gas ratios
Well type, count and respective targeted reservoir
Surface infrastructure including pipelines
The fully integrated model provided the required flexibility for evaluating various scenarios while delivering credible consistent results. Running quick scenarios can help to make decisions for the planning of the surface network and production thus helping to reduce CAPEX. Using central controlling software simplified varying both subsurface and surface constraints for the LNG development. This included seasonality influenced safety margins, the addition of compression as soon as the gas rate potential drops below critical levels and drilling new wells into the optimal reservoir when required to fill the LNG trains.
Andersen, Niels (National Space Institute – DTU Space & Polar DTU) | Bekker, Pieter (University of Dundee and Steptoe & Johnson LLP) | Bishopp, David (Galp Energia) | Nassif, Toufic (Sonde Resources Corporation) | Nordentoft-Lauridsen, Sune (National Space Institute & Polar DTU) | van de Poll, Robert (Fugro N.V.)
This paper provides an overview of the history of global maritime boundary issues, mechanisms to resolve boundary disputes, and the economic potential that can be unlocked by coastal States through the exploitation of hydrocarbons trapped in areas currently unavailable for exploration and production operations.
Vast hydrocarbon reserves are tied up in areas, either underlying waters greater than 200 nm offshore or disputed by coastal States. In the former case technology in the form of deepwater drilling has made testing the potential feasible, whilst in the latter case many of the 311 or so areas in dispute are able to be tested and developed using conventional techniques.
Anything that appears to show a sovereign entity ceding control of land or sea to another country inevitably takes on a high profile in the countries concerned, which in the worst case can lead to armed conflict. It is a credit to those States that subscribe to the principles of the United Nations Charter and the United Nations Convention on the Law of the Sea ("UNCLOS") that they have reached agreement on how the economic potential trapped in disputed areas may be divided or shared.
High-profile, high-stakes disputes relating to offshore oil and gas deposits underscore the importance of the modern law of the sea, and international law generally, to the peaceful settlement of boundary disputes affecting the energy industry. Yet boundary disputes form an overlooked area of investment risk management in the energy sector.
This paper will introduce the technical and legal principles behind the solutions reached by States and will highlight some of the areas with the greatest hydrocarbon potential that have yet to be exploited as well as the areas of risk that require mitigation before investors will advance risk capital.
Downstream Refineries and Chemical Plants have benefited from real time optimization systems (RTO) for the last 30 years. Downstream RTO is a well established and permanent fixture in many plants - the "way we do things ‘round here!??. Upstream E&P operations have "come to this party?? much more recently and are using RTO more sparingly, even though the economic and HSSE benefits can be very significant.
There are key differences between downstream and upstream. For example, downstream facilities do not deal with sub-surface uncertainties, multiphase flow and isolated/harsh environments; while upstream operations do not usually have to deal with complex chemical processes.
Integrated Oil Companies run upstream and downstream operations and integration of tools/practices across both regimes is often perceived to be of significant value. Hence, the purpose of this paper is to compare and contrast downstream and upstream RTO learnings with a view to identifying and describing:
• similarities in production unit operations e.g. fluid separation, compression etc.;
• key differences between production unit operations;
• cultural differences between operations;
• RTO activities from a technical perspective;
• RTO business benefits and how these might be leveraged and sustained in both directions.
What will emerge from this analysis will be a comparison, highlighting points of commonality and differences, leading to a better understanding of how RTO can be more effectively exploited in the upstream business - the cheapest oil available!
Specifically, it is concluded that RTO in upstream operations is feasible and lucrative, but is relatively rare with sustainability a challenge. Downstream RTO is more common and sustainable, significantly less lucrative, but a "must do?? to compete in a highly competitive, margin constrained business.
Cramer, Ron (Shell Global Solutions) | Mehrotra, Shailendra (Shell) | Goh, Keat-Choon (Shell Global Solutions Intl BV) | Steover, Matt (Shell Global Solutions US Inc) | Berendschot, Leo F. (Shell Global Solutions)
Downstream Refineries and Chemical Plants have benefited from real time optimization systems (RTO) for the last 30 years. Downstream RTO is a well established and permanent fixture in many plants - the "way we do things'round here!". Upstream E&P operations have "come to this party" much more recently and are using RTO more sparingly, even though the economic and HSSE benefits can be very significant. There are key differences between downstream and upstream. For example, downstream facilities do not deal with subsurface uncertainties, multiphase flow and isolated/harsh environments; while upstream operations do not usually have to deal with complex chemical processes. Integrated Oil Companies run upstream and downstream operations and integration of tools/practices across both regimes is often perceived to be of significant value. Hence, the purpose of this paper is to compare and contrast downstream and upstream RTO learnings with a view to identifying and describing: - similarities in production unit operations e.g.
Bruni, Corrado (BG) | Odumboni, Idowu Bashir (BG Group plc) | Sellami, Besma (British Gas Tunisia Ltd.) | Turner, Marcus (Services Tech. Schlumberger) | Sanguinetti, Marco (Schlumberger) | Kazmer, Jorge (Schlumberger)
The Abiod formation is the principal target in the Miskar field, offshore Tunisia. Consisting of fractured geomechanically stressed carbonate with a measured matrix permeability as low as 0.1 mD. The formation dates from Campanian to lower Maastrichtian and forms a horst structure. The formation has been under production since 1996.
Obtaining formation pressure data was considered critical for determining the magnitude of depletion from production, well-to-well comparisons for vertical and lateral connectivity, forward modeling, completion decisions, and refinement of the field development plan. Historically, this has been a challenge with conventional wireline (WL) formation testers for the following reasons:
• Severe depletion and well deviation causing differential sticking
• High temperatures (150 to 195° C) at the limit of tool electronics
• Low permeability
• Fractures and breakouts that can impact seal success
This was overcome with a systematic multidisciplinary approach. After review of historical formation testing data, and influence on seal success with probe vs. packer elements, it was decided to apply formation-pressure-while-drilling (FPWD) technology. The key questions with FPWD in this environment are: Can we achieve a good transient profile and what is potential impact of supercharging? These questions were addressed with advanced prejob modeling, which enabled determination of an optimized pretest configuration and testing procedure to minimize potential supercharging effects.
While drilling, stage-in procedures were used, and mud logging total gas data were gathered to identify areas of liberated gas. Pre-run wireline petrophysical data were gathered to characterize the Petrophysical properties of the reservoir and to calculate an intrinsic permeability profile. Ultrasonic borehole images and caliper data were used to determine the principal horizontal stress directions, fracture frequency, and orientation and to confirm the stratigraphic dipping of the structure. Combined, this information allowed a focused orientation of the FPWD probe and optimal station selection avoiding fractures and breakouts.
This novel approach resulted in 100% seal success, >50% improvement. Four days of rig time were saved, and the required data were obtained.
Bruni, Corrado (BG) | Sellami, Besma (British Gas Tunisia Ltd.) | Odumboni, Idowu Bashir (BG Group plc) | Turner, Marcus (Schlumberger Italiana SPA) | Sanguinetti, Marco (Schlumberger) | Kazmer, Jorge (Schlumberger)
James, Bruce Rennie (Woodside Energy) | Kerr, Kevin (Woodside Energy) | Lim, Stephanie (Woodside Energy) | Lewandowski, Ed (Woodside Energy) | Knight, Craig (Woodside Energy) | Bell, Richard Guy Dryden
Using improved integration, data efficiency and more informed decision making, Woodside's Intelligent Fields Management (IFM) has created a step change improvement in the way the Cossack-Wanaea-Lambert-Hermes (CWLH) fields are managed. There is tremendous value in IFM in numerous and often unexpected places. However, the greatest value likely lies within the improved integration of data and work practices and longer-term reservoir management. The benefit-cost ratio of IFM on the CWLH fields is likely in the order of ten to one. This paper demonstrates what a mid-sized oil and gas company can accomplish within 12 months and at relatively low-cost using off-the-shelf technology and starting with little pre-existing knowledge.
CWLH is four oil fields with 11 subsea wells tied back to a floating production storage offtake (FPSO) vessel located offshore on the North West Shelf of Australia. The initial focus of Woodside's Intelligent Field Management program is on near-term field management issues, including reducing well testing, daily optimisation, production allocation, and managing sand erosion. Woodside's IFM program is currently being implemented on two other oil assets, with an expansion to gas and longer-term reservoir management planned for later in 2008.
The Petroleum Experts' Integrated Field Manager™ is the calculation engine used in the IFM program, allowing for custom workflows to be automated and scheduled. For example, workflows have been created that can run every 30 minutes and automatically identify elements of an integrated asset model, where measured behaviour significantly diverges from calculated behaviour. Powerful visualisation for interpreting data, particularly across disciplines, was critical for success and was realised through ISS Group's Babelfish™ web based viewer.
Successful implementation relies on a highly motivated interdisciplinary team, dedicated IT and management support and close interaction with asset teams. Long-term success will require ongoing IT and super-user support.
Madray, Ravi (BG Group plc) | Coll, Carolina (BG Group plc) | Veitch, Gordon (British Gas Intl.) | Chiboub, Chokri (British Gas Intl.) | Butter, Machiel (British Gas Intl.) | Azouzi, Samy (Schlumberger) | Bahri, Sami (British Gas Intl.) | Yaich, Brahim (British Gas Intl.) | Saada, Tamer (British Gas Intl.)
This paper describes the implementation of the Integrated Field Modelling project in the Miskar Field, Tunisia. Integrated Asset/Field Models (IAM) are based on the
concept of having a fully integrated asset model that goes from reservoir to wells, topsides and production facilities.
The IAM tools are then integrated with data feeds to allow online surveillance monitoring and automation of client field/business management workflows. The project has been implemented in two phases. Phase I, which has already been concluded, links reservoir models to wells models and topsides whereas Phase-II (ongoing) will integrate the onshore processing plant and economic models. This unified model is achieved by linking the various models from simulation models at the reservoir level up, to nodal analysis at the wells, to topsides models and production system models that replicate the processing of hydrocarbons. The integrated model should be robust and incorporate the basic physics at each step from the reservoir to the production networks. The connection to economic models closes the evaluation cycle enabling production and economic optimization. One of the major drivers to implement this system in Tunisia was to be able to forecast, in real time using high frequency data, the gas
composition at the platform (CO2/H2S/N2) and liquids production of the Miskar Field after infill drilling.
Production Optimization routines are being implemented to:
• maximize gas and liquid production within the constraints of the current Miskar platform facilities
• monitor the gas blend that is sent to the beach to ensure that the blend is maintained within the current operational constraints of the Hannibal plant and Miskar export.
In Phase I this was accomplished by building an integrated model from reservoir to inlet of the onshore facilities. The resulting model shows the interaction of the various
elements in the production system. Further, from this full field model, we can then run full field production optimization and forecasting linked to the economic models. The optimization scenarios can be defined as tasks or as an event list that control a forecast period. Running multiple scenarios allow integrated teams to make informed decisions on a daily basis for production and/or regarding the future production of the field. The integrated sub-surface team can collaborate with production engineering teams to implement rule sets which ensure the long term versus short term optimisation objectives are observed within the forecasting workflows.
The project has also linked-up the models to the existing real time Production Data Management System (PDMS) to enable real time optimization for gas composition. This
results in a ‘real-time' monitoring and surveillance of the field. The real time monitoring consists of well rate estimation of gas, water and condensate, as well as the gas
compositions for blending forecast.
The loading of regular well tests and the use of customized workflows results in a semi-automated well test validation and analysis procedure. This makes regular updates of the reservoir model easier to carry out. Use of this type of real time full field modelling integration can leverage workflows to validate the full model on a much more regular basis. This results in time reductions for model calibration and quality control which then leads to greater confidence in model advisories and performance.
The tool that has been deployed to integrate data and workflows is Integrated Field Management (IFM) from Petroleum Experts which is built upon their existing Integrated Production Modelling (IPM) Architecture.
To develop its Miskar field offshore Tunisia, BG Tunisia made a call for tenders in 2005 during tight market conditions prevailing at the time.
After further study review of the MODU characteristics a second generation Semi Submersible from Pride International "Sea Explorer" was selected. This unit was designed in late 70's & did not have all necessary features and capacities to drill a High Temperature and extended reach well (range: TMD 6.740 m (22.200 ft) andTVD 3.400 m (11.150 ft)). Some minor modifications had to be made to the unit as well as some specific procedures in order to drill such wells in accordance with rigorous standard practices.
The paper will highlight:
This paper will present a brief well history, the drilling campaign results and highlights the lessons learnt.
Following the successful completion of the actual drilling campaign, this Paper concludes on the upgrade potential and capacity for a second generation semi to match the challenges of today's high profile wells. It also highlights the benefits of close collaboration between operator and contractor.
BG Tunisia planned to further develop the Miskar field located in the Gulf of Gabes 110 km east south east of Sfax in Tunisia (refer to Map position fig 1) by drilling 2 sub sea production wells. The sub sea drill centre is located 2.75km south of the Miskar Platform. Both wells were drilled from this seabed location using 2 separate subsea production flow bases tied into a central manifold. The two subsea wellheads were 35m apart . The semi sub anchoring plan is shown in figure 2.
The water depth is 60m. The weather condition or oceano meteorological criteria are mild: the 5 year return wave has an Hs of 3.6 m and the period is 8s.The anticipated heave movement of a drilling semi type Aker H3 was around 2 feet.
The well Miskar R1A was a two -level horizontal well within the Miskar Concession to reach two reservoirs. The second well Miskar R1D was a high angle drift well reaching the same reservoir sections as R1A.The well trajectory is shown in figures 3 and 4.
The wells were planned to reach total measured depths of up to 6740m at a true vertical depth of 3675m and horizontal sections extending to 1700m. The casing program is classical and outlined in figure 5.