The Schoonebeek heavy-oil field was first developed by Nederlandse Aardolie Maatschappij B.V. (NAM) in the late 1940s. Because of economics, it was abandoned in 1996. In 2008, the Schoonebeek Redevelopment Project, using a gravity-assistedsteamflood (GASF) design concept, was initiated with 73 wells (44 producers, 25 injectors, and 4 observation wells). Steam injection and cool-down cycles subject a cement sheath to some of the most severe load conditions in the industry. Wellbore thermal modeling predicted that surface and production sections would experience temperatures in excess of 285°C (545°F) and considerable stress across weak formations. A key design requirement was long-term integrity of the cement sheath over an expected 25- to 30-year field life span. Complicating this requirement was the need for lightweight cementing systems, because lost-circulation issues were expected in both hole sections, particularly in the mechanically weak Bentheim sandstone. The long-term integrity challenge was divided into chemical and mechanical elements. Prior research on high-temperature cement performance by the operator provided necessary guidance for this project. Laboratory mechanical and analytical tests were conducted to confirm the high-temperature stability of the chosen design. In addition to using lightweight components, foaming the slurry allowed the density, mechanical, and economic targets to be met. A standardized logistical plan was put in place to allow use of the same base blend for the entire well, adjusted as needed, using liquid additives, and applying the foaming process when necessary. This single-blend approach greatly simplified bulk-handling logistics, allowing use of dedicated bulk-handling equipment. The first well was constructed in January 2009; all 73 wells have been successfully cemented to surface. The steaming process, initiated in May 2011, has progressed with no well integrity issues to date.
In 2010, Qatar Shell Upstream International B.V. (QSUI) re-entered Exploration in Qatar focusing on the relatively deep conventional Pre-Khuff gas plays with a view to discover additional hydrocarbons in the State of Qatar. The Pre-Khuff plays pose two main challenges; firstly the geophysical challenge of being able to image the deep Pre-Khuff structure and hence trapping configurations and secondly the geological challenge of being able to realistically predict reservoir and top seal quality. This paper highlights the approach to geological issues associated with Pre-Khuff exploration and how technologies were deployed to address pre drill exploration challenges in the venture.
Significant uncertainty exists in relation to the deep structure of the Qatar Arch particularly when in the region the Pre- Hercynian package has been shown to be structurally different to the overburden. 2D seismic reprocessing has helped to significantly improve seismic imaging encompassing clear improvements in seismic data quality with better reflector continuity and elucidation of structural and stratigraphic complexity. The overall structure of the Qatar Arch and the trap styles in the Pre-Khuff are assessed using a combination of gravity anomaly data and interpretation of 2D seismic profiles, while incremental restoration of 2D seismic lines provides insight on the timing of trap formation.
The Devonian Jauf and the Permo-Carboniferous Unayzah plays are primary targets in Block D. Key petroleum system risks are taken as top seal retention, reservoir quality and charge timing and migration. To address these geological factors, data has been re-assessed and new work undertaken on stratigraphic definition, depositional models, reservoir quality prediction, integrated charge evaluation and seal integrity of the Pre-Khuff. Pre-Khuff top seal effectiveness in the focus plays have been assessed through MICP analysis and demonstrates that the relevant seals can hold back significant gas columns. Revised depositional models, based on core observations, have been used to extend potentially successful play fairways into Qatar. New petrographic analysis programs address the diagenetic controls on reservoir quality and their relationship with depositional environments aiding the prediction of potential net viable reservoirs at depths greater than conventional cementation floors. Integrated charge evaluation using basin modeling and geochemical techniques comprising Compound Specific Isotope, TOC, visual kerogen and chitinozoan reflectance analysis suggests a working petroleum system for Pre-Khuff reservoirs. 1D basin models suggest the Pre-Khuff on the Qatar Arch has received gas charge over the last 100 Ma but despite these favorable conditions, a key risk remains the presence of effective vertical migration pathways (i.e. faults) from the source rock into the prospective reservoirs.
Masalmeh, Shehadeh K. (Shell Technology Oman) | Wei, Lingli (Shell International Exploration & Production B.V.) | Hillgartner, Heiko (Petroleum Development Oman) | Al-Mjeni, Rifaat (Shell) | Blom, Carl P.A. (Shell Intl E&P)
Enhanced oil recovery (EOR) has become increasingly important to maintain and extend the production plateaus of existing oil reservoirs. Simulation models for EOR studies require the right level of spatial resolution to capture reservoir heterogeneity. Data acquired from the dedicated observation wells are essential in defining the required resolution to capture reservoir heterogeneity. For giant reservoirs with long production history, their full field models usually have grid block sizes that are of similar scale as the distance between injectors and observation wells, with the consequence of losing the value of the time lapse saturation logs from dedicated observation wells. Therefore, using high resolution sector models, especially from the part of the reservoir where static and dynamic data sets are rich, is a must.
The objective of this paper is to present an improved and integrated reservoir characterization, modelling and water and gas injection history matching procedure of a giant Cretaceous carbonate reservoir in the Middle East. The applied workflow integrates geological, petrophysical, and dynamic data in order to understand the production history and the remaining oil saturation distribution in the reservoir. Large amounts of field data, including time lapse saturation logs from observation wells, have been collected over the last decades to provide insight into the sweep efficiency and flow paths of the injected water.
Iterative simulations were performed to investigate different scenarios and various sensitivities with each iteration involving an update of the static model to honor both the dynamic and core/log data. While applying this iterative process it was also acknowledged that conventional core data (e.g. 1 plug per foot) may not capture the high permeability streaks in these heterogeneous reservoirs that control much of the reservoir flow behaviour, hence much denser plugging and core examination is required. In addition, permeability upscaling procedures need to take into account the fact that core plugs may not represent the effective permeability of the larger connected vuggy pore systems.
The improved understanding of reservoir heterogeneity, the more robust reservoir characterization, and the improved history matching demonstrates that a better representation of reservoir dynamics is achieved. This provides a solid platform for designing and planning future EOR schemes.
Carbonate reservoirs contain more than 50% of world's remaining conventional hydrocarbon reserves and on average have relatively low recovery factors. With the insight that the era of "easy oil?? (conventional oil and natural gas that are relatively easy to extract) is phasing out, enhanced oil recovery (EOR) becomes increasingly important to maintain and extend the production plateaus from existing oil reservoirs. EOR technologies, however, require a refined understanding of reservoir heterogeneities and dynamic field performance. Simulation models for EOR studies need to have the right level of resolution and details. Often, we find that for a giant reservoir with a long waterflood history, working with full field models with coarse simulation grids is not adequate to understand the reservoir performance and calibrate the static model. Therefore, using high resolution sector models, especially from the part of the reservoir where static and dynamic data sets are rich, is a must.
Latief, Agus Izudin (Roxar (M) Sdn. Bhd.) | Ridzuan, Ahmad Idriszuldin (Petronas (Kuala Lumpur)) | Faehrmann, Paul A. (Shell) | Macdonald, Alister C. (Roxar Software Solutions) | Arina, Wardah (Petronas) | Rahman, Gozali (Roxar Software Solutions) | ab rahman, mohd elzrey
Baram is a giant mature field situated, offshore Sarawak Malaysia. Reservoirs consist of an approximately 7000 ft thick-stacked sequence of shallow marine sands, distributed in excess of 200 zones. The field is extensively faulted. Early Growth faulting followed by a later compressional phase has led to complex fault geometries. The field has been producing for over 40 years and presently has 175 wells.
Although the reservoirs are generally of good quality, the field currently has relatively low production rates, a low recovery factor, and a significant amount of remaining reserves. The geological complexity poses a key challenge, and a robust static reservoir model is a prerequisite for efficient reservoir management and for identifying viable Improved Oil Recovery (IOR) measures.
Static models of the Baram field had previously been constructed. This modelling took in excess two years to complete and the models were segmented into 10 pieces, as technology during this period was unable to tackle complex fault geometries. Due to the results of the static / dynamic modelling being insufficiently robust when tested during a drilling campaign in 2009, the decision was made to remodel.
The Baram subsurface team was challenged with building a static model which could be used for field management and IOR /EOR process selection and optimization within a six month timeframe. This is to allow for early investment decisions and an accelerated reversal of production decline. The key aspects of the fixed timeframe static model construction are described below. They consist of:
1. The subdivision of the field into independent models.
2. The utilization of a modern algorithm to model complex fault geometry.
3. Nested stratigraphic modeling.
4. Parallel property modeling and the re-combining of results into a single simulation grid to enable integrated reservoir
A full focus on the importance of the timeline and early investment, plus the adoption of a variety of strategic project
management measures and use of "state of the art" modeling technology can allow fit-for-purpose static models to be delivered on time.
A broadly applicable methodology is presented to reliably predict crude oil liquid viscosity from only a gas chromatographic assay composition (C30+ is recommended). The viscosity model employs a Walther-type correlation of double log viscosity with log temperature to predict the viscosity of dead and live crude oils and mixtures. The model has three parameters: the slope and intercept of the Walther plot and a viscosibility factor to account for pressure effects. Simple mass based mixing rules are applied on these three parameters to obtain mixture viscosity. The three parameters were correlated to component molecular weight and therefore a gas chromatographic assay is the only required input apart from the temperature and pressure.
The methodology was developed from a Western Canadian dataset of two bitumens, one heavy oil, and one condensate, and then tested on an independent dataset of 10 conventional and heavy crude oils from the Gulf of Mexico, the Middle East, Asia, and Europe. The model provides un-tuned viscosity predictions within a factor of two of the measured values for dead and live crude oils ranging in viscosity from 0.5 to 500,000 mPa.s. A single multiplier is used to tune the model. Models tuned to dead oil data predict live oil viscosities and mixtures of oils with solvents to within 30% of the measured values. Models tuned to the viscosity at the saturation pressure predict the effect of temperature and pressure to within 20% of the measured values.
The method retains its accuracy when components are lumped into a few pseudo-components and is ideally suited for use in simulators for accurate liquid phase viscosity predictions over a wide range of compositions, pressures, and temperatures. It would be necessary to include the proposed mixing rules in numerical simulators. An additional advantage of the method is the reduction in viscosity measurements needed to construct an accurate viscosity model.
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.
The increased use of deep, highly-deviated and tortuous wells has increased the risk of wireline logging tool strings getting stuck downhole. If this risk is not appropriately managed and effectively mitigated, significant financial exposure can result from the cost of the multi-day fishing operations, the lost-in-hole and replacement charges, and -most importantly- the loss of opportunity to acquire critical subsurface data. This exposure is even higher in environments with large operating costs, such as deep water.
Historically, formation testing and fluid sampling tools have been among the most frequently stuck, fished and lost logging equipment. On the other hand, formation testing continues to provide some of the most essential information for reservoir characterization. Therefore, managing the risks associated with tool deployment is essential.
This paper discusses the sticking mechanisms of formation testing and fluid sampling tool strings, and provides specific recommendations for the planning and execution of such operations. The various factors that lead to differential sticking or keyseating of the tool string and the wireline cable are discussed. A dataset that explores a wide variety of situations is analyzed to provide a pragmatic guideline for effective mitigation of tool and cable sticking. A specific example from highly deviated deep water well is shown to highlight the significance of proactive planning.
This paper provides insight into the Caisson ESP Technology Maturation for subsea boosting systems with high GOR and viscous fluids. It will focus on the developmental research on the effects of viscosity and two phase (liquid & gas) fluids on electric submersible pumps (ESPs), which are multistage centrifugal pumps for deep boreholes.
The Electrical Submersible Pump (ESP) system is an important artificial lift method commonly used for subsea boosting systems. Multiphase flow and viscous fluids cause problems in pump applications. Free gas inside an ESP causes many operational problems such as loss of pump performance or gas lock conditions (Barrios 2010 ). The objective of this study is to predict the operational conditions that cause degradation and gas lock. This paper provides a summary on the Technology maturation for a high scale ESP Multi-Vane Pump (MVP) for high GOR fields to in support of Shell's BC-10 developments. These novel projects continue the long tradition of Shell's leadership in the challenging deepwater environment. This paper will describe the capability and effects of viscosity and two phase (liquid & gas) fluids using a MVP 875 series G470 as a charged pump in a standard ESP system 1025 series tandem WJE 1000 mixed-type pump.
Extensive testing and qualification of the subsea boosting system was undertaken prior to field considerations. Testing was conducted at the world's only 1500-hp ESP test facility capable of controlling multi-phase fluid viscosities and temperatures. A comprehensive suite of tests was performed in conjunction with Baker Hughes Centrilift replicating the expected conditions and performance requirements for Shell's deepwater assets. This paper describes the subsea boosting system maturity process, and reports the effects of viscosity and two phase liquid - gas fluids on ESPs. The test facility work was performed using pumps with ten or more stages moving fluids with viscosity from 2 to 400 cP at various speed, intake pressure, and gas void fractions (GVF, aka gas volume fractions). The testing at Shell's Gasmer facility revealed that the MVP-ESP system is robust and performance tracked theoretical predictions over a wide range of two-phase flow rates and light-viscosity oils
Quantitative integration of spatial and temporal information provided by time-lapse (4D) seismic surveys to dynamic reservoir models calls for an efficient and effective workflow. To solve this issue, we propose a novel workflow which uses a Bayesian/MCMC approach and experimental design-based proxies for selected 4D seismic observables to update dynamic reservoir models. This methodology includes the following steps: (1) create probability maps to select locations where 4D seismic data is assimilated; (2) run a sensitivity analysis; (3) create high-order proxy models; and (4) run an MCMC inversion to determine a set of models that best fit the 4D seismic data and quantify uncertainty. This new workflow has been applied in 3 cases including two synthetic models and one field case. This first synthetic example is called the Imperial College Fault Model (ICFM).The second synthetic model is a fluvial reservoir model with 10 uncertain parameters. The field example is a
deepwater turbidite reservoir undergoing a waterflood with a reasonably long production history and high-quality 4D seismic data. Following the four steps of this workflow, all the models are successfully history matched by conditioning to 4D seismic data. Uncertainty quantification was also provided as part of the MCMC inversion. We also compare different scenarios using production data and/or 4D seismic data in the model updating process to show the value of the 4D seismic data. For our field case, the updated models can be used for production forecasting, reserves booking and identification of further development opportunities.