Maximising Oil Recovery of a Thin Oil Rim through an Optimised Field Development Plan

2011 ◽  
Author(s):  
Sai V.S. Garimella ◽  
Jeremy Marws Harris ◽  
Ali Kalbani ◽  
Ali A. Al-Lamki ◽  
Khalid Khabouri
Keyword(s):  
Oil Recovery ◽  
Development Plan ◽  
Field Development ◽  
Oil Rim

scholarly journals Integrated Halo Model And Hydrodynamic Simulation For Optimization Oil Production In Crystalline Fractured Reservoirs

2021 ◽  
Author(s):  
Hung Vo Thanh ◽  
Kang-Kun Lee
Keyword(s):  
Oil Recovery ◽  
History Matching ◽  
Fractured Reservoirs ◽  
Petroleum Industry ◽  
Oil Production ◽  
Modelling And Simulation ◽  
Development Plan ◽  
Sweep Efficiency ◽  
Field Development ◽  
The World

Abstract Basement formation is known as the unique reservoir in the world. The fractured basement reservoir was contributed a large amount of oil and gas for Vietnam petroleum industry. However, the geological modelling and optimization of oil production is still a challenge for fractured basement reservoirs. Thus, this study aims to introduce the efficient workflow construction reservoir models for proposing the field development plan in a fractured crystalline reservoir. First, the Halo method was adapted for building the petrophysical model. Then, Drill stem history matching is conducted for adjusting the simulation results and pressure measurement. Next, the history-matched models are used to conduct the simulation scenarios to predict future reservoir performance. The possible potential design has four producers and three injectors in the fracture reservoir system. The field prediction results indicate that this scenario increases approximately 8 % oil recovery factor compared to the natural depletion production. This finding suggests that a suitable field development plan is necessary to improve sweep efficiency in the fractured oil formation. The critical contribution of this research is the proposed modelling and simulation with less data for the field development plan in fractured crystalline reservoir. This research's modelling and simulation findings provide a new solution for optimizing oil production that can be applied in Vietnam and other reservoirs in the world.

scholarly journals Simulating the strategies of oil field development for enhanced oil recovery

2020 ◽  
Vol 24 (Suppl. 1) ◽  
pp. 411-422
Author(s):  
Muhammad Tahir ◽  
Wei Liu ◽  
Asadullah Memon ◽  
Hongtao Zhou ◽  
Wei Liu ◽  
...  
Keyword(s):  
Simulation Model ◽  
Oil Recovery ◽  
Oil Field ◽  
Development Plan ◽  
Rapid Decline ◽  
Formation Pressure ◽  
Compositional Simulation ◽  
Field Development ◽  
Oil Field Development ◽  
Development Plans

Many years have passed in oil field development but primary challenges faced by the X reservoir are the rapid decline of formation pressure and the significant solution gas released from the formation, which impairs production. Based on these challenges, a compositional simulation model of the X reservoir was constructed and run to establish the future development plans. The basic reservoir data collection and processing, quality assurance of the data, characteristic pressure-volume-temperature (PVT) matching by ECLIPSE PVTi, and simulation of various adjustment strategies to forecast development plans, as well as data sensitivity analysis and optimization has been included in this study. In addition, to establish a desirable development plan, the simulation model is set up in great consistency with the geological model resulted from the seismic and logging interpretations. Also, emphases are paid on establishing matches with the reported lab data from production wells by PVTi. Results revealed that the specific reservoir development plan intends to reinstate or maintain formation pressure of the X reservoir. All design and optimization studies are set to comprehend the reservoir with the numerical model.

Alternative Method of Assessing Optimum Number of Water Injection and Infill Wells in a Field Development Plan

2021 ◽  
Author(s):  
M. Fitri Ramli ◽  
M. Shahrul M. Long ◽  
Amol Nivrutti Pote ◽  
Khairul Azri Ishak
Keyword(s):  
Oil Recovery ◽  
History Matching ◽  
Net Present Value ◽  
Water Injection ◽  
Numerical Approach ◽  
Development Plan ◽  
Alternative Methods ◽  
Optimum Number ◽  
Injection Wells ◽  
Field Development

Abstract This paper discusses the workflow and method of selecting optimum number of infill and injection wells based on incremental recovery. Normally, for infill wells study, a ‘creaming curve’ method is used to evaluate the optimum number of wells against incremental recovery from the field. However, in the case of determining number of infill wells together with water injection wells, a more comprehensive approach is needed. One needs to evaluate the pressure depletion rate from existing and infill wells together with the dynamic of the producer-injector pairings as well as the sweeping factor. The paper is based on infill and water injection development plan for a brown field in Sabah basin which located in Malaysia. To maintain operatability of the field in the future, several new infill and water injection wells options are evaluated for optimum field life oil production. Unlike infill or producer-only assessment, the same ‘creaming curve’ approach for combination of infill and water injection wells is less effective as large number of simulation runs are needed to sample the combination of these wells that generate optimum oil recovery. This has proven to be challenging especially when the models are large which is normally the case for brown fields and it requires extensive computational hours. In the first part, a modified approach bringing some pre-analytic assessment of producer-injector pairing is being used. The pairings are first ranked based on streamlines visualization, drainage tables and their respective contributions towards oil recovery. The ‘creaming curve’ is then built based on the highest contribution as well as the sequencing of the pairings. The second method mentioned in this paper is the numerical approach through multi-objective optimization using assisted history matching and uncertainty tool. With the help of optimizer, the number of simulation runs can be drastically reduced when only best combination of infills and injectors for each total number of wells are considered. Both alternative methods will be compared with the full computational runs, sampling every single combination of wells. Finally, the optimum number of wells with the combination of infill and water injection wells are analysed based on cumulative oil recovery against the Net Present Value (NPV). This case study therefore demonstrates how alternative methods can be used to resolve the optimum number of infill and water injection wells to avoid lengthy and very large numbers of simulation runs.

The Rubie Field, Block 15/28b, UK North Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 790-803 ◽  
Author(s):  
Graham Tegerdine
Keyword(s):  
North Sea ◽  
Oil Recovery ◽  
Initial Rate ◽  
Development Plan ◽  
Recovery Factor ◽  
Life Extension ◽  
Field Development ◽  
Phillips Petroleum ◽  
Moray Firth

AbstractThe Rubie Field is located within the Outer Moray Firth in Block 15/28b, towards the eastern end of the Renee Ridge and 6 km east of the Renee Field. The block was awarded to a BNOC-operated group following the 7th Licensing Round in 1980. The 15/28b-4 discovery was drilled by Britoil in 1985, encountering hydrocarbons at two stratigraphic levels within the Paleocene Andrew Sandstone unit and Eocene Cromarty Sandstone Member reservoirs. No further appraisal was undertaken prior to a late 1997 Annex B submission for a joint Renee and Rubie Field development by new operator, Phillips Petroleum. The Rubie development plan comprised a single 6000 ft Andrew Sandstone horizontal producer which was completed in March 1999 and tested at an initial rate of 9700 bopd and 1.65 MMscfgd. Export of fluids was via a 6 km-long pipeline to the Renee Field manifold and then onwards to the host facility in the Ivanhoe–Rob Roy fields. Rubie was brought on stream on 29 May 1999. Abandonment was originally scheduled for end 2006, but field-life extension initiatives deferred cessation of production (COP) to March 2009. Cumulative Andrew Sandstone production at COP was 11.5 MMbbl and the oil recovery factor 50%, based on a final mapped oil-in-place of 23 MMbbl.

60 Years Field Performance Data-Driven Analytics to Generate Updated Waterflood Field Development Plan in a North Kuwait Giant Carbonate Reservoir

2021 ◽  
Author(s):  
Basel AL-Otaibi ◽  
Issa Abu Shiekah ◽  
Manish Kumar Jha ◽  
Gerbert de Bruijn ◽  
Peter Male ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Oil Production ◽  
Horizontal Wells ◽  
Carbonate Reservoir ◽  
Development Plan ◽  
Data Driven ◽  
Water Flooding ◽  
Field Development ◽  
The Impact

Abstract After 40 years of depletion drive, a mature, giant and multi-layer carbonate reservoir is developed through waterflooding. Oil production, sustained through infill drilling and new development patterns, is often associated with increasingly higher water production compared to earlier development phases. A field re-development plan has been established to alleviate the impact of reservoir heterogeneities on oil recovery, driven by the analysis of the historical performance of production and injection of a range of well types. The field is developed through historical opportunistic development concepts utilizing evolving technology trends. Therefore, the field has initially wide spacing vertical waterflooding patterns followed by horizontal wells, subjected to seawater or produced water injection, applying a range of wells placement or completion technologies and different water injection operating strategies. Systematic categorization, grouping and analyzing of a rich data set of wells performance have been complemented and integrated with insights from coarse full field and conceptual sector dynamic modeling activities. This workflow efficiently paved the way to optimize the field development aiming for increased oil recovery and cost saving opportunities. Integrated analysis of evolving historical development decisions revealed and ranked the primary subsurface and operational drivers behind the limited sweep efficiency and increased watercut. This helped mapping the impact of fundamental subsurface attributes from well placement, completion, or water injection strategies. Excellent vertical wells performance during the primary depletion and the early stage of water flooding was slowly outperformed by a more sustainable horizontal well production and injection strategy. This is consistent with a conceptual model in which the reservoir is dominated by extensive high conductive features that contributed in the early life of the field to good oil production before becoming the primary source of premature water breakthrough after a limited fraction of pore volume water was injected. The next level of analysis provided actual field evidence to support informed decisions to optimize the front runner horizontal wells development concept to cover wells length, orientation, vertical placement in the stratigraphy, spacing, pattern strategy and completion design. The findings enabled delivering updated field development plan covering the field life cycle to sustain and increase field oil production through adding ~ 200 additional wells and introducing more structured water flooding patterns in addition to establishing improved wells reservoir management practices. This integrated study manifests the power, efficiency and value from data driven analysis to capture lessons learned from evolving wells and development concepts applied in a complex brown field over six decades. The workflow enabled the delivery of an updated field development plan and production forecasts within a year through utilizing data analytics to compensate for the recognized limitations of subsurface models in addition to providing input to steer the more time-consuming modeling activities.

Adapting Field Development Plan of Compartmentalized Oil Rim Reservoir with Significant Gas Cap and Water Aquifer - Case Study

2016 ◽  
Author(s):  
Ashraf Lotfy El Gazar ◽  
Tariq Ali Al Shabibi ◽  
Lenin Loredo ◽  
Ravi Kumar ◽  
Syofvas Syofyan ◽  
...  
Keyword(s):  
Development Plan ◽  
Field Development ◽  
Oil Rim

Oil Reserves Evaluation and Field Development plan of Hakim Oil Field in Libya

2016 ◽  
Vol 18 (1) ◽  
pp. 39-53
Author(s):  
Omar Salih ◽  
Mahmoud Tantawy ◽  
Sayed Elayouty ◽  
Atef Abd Hady
Keyword(s):  
Oil Field ◽  
Development Plan ◽  
Field Development ◽  
Oil Reserves

scholarly journals Practical CO2—WAG Field Operational Designs Using Hybrid Numerical-Machine-Learning Approaches

Energies ◽  
2021 ◽  
Vol 14 (4) ◽  
pp. 1055
Author(s):  
Qian Sun ◽  
William Ampomah ◽  
Junyu You ◽  
Martha Cather ◽  
Robert Balch
Keyword(s):  
Machine Learning ◽  
Oil Recovery ◽  
History Matching ◽  
Optimization Problems ◽  
Learning Technologies ◽  
Petroleum Engineering ◽  
Support Vector ◽  
Learning Approaches ◽  
Field Development ◽  
Proxy Models

Machine-learning technologies have exhibited robust competences in solving many petroleum engineering problems. The accurate predictivity and fast computational speed enable a large volume of time-consuming engineering processes such as history-matching and field development optimization. The Southwest Regional Partnership on Carbon Sequestration (SWP) project desires rigorous history-matching and multi-objective optimization processes, which fits the superiorities of the machine-learning approaches. Although the machine-learning proxy models are trained and validated before imposing to solve practical problems, the error margin would essentially introduce uncertainties to the results. In this paper, a hybrid numerical machine-learning workflow solving various optimization problems is presented. By coupling the expert machine-learning proxies with a global optimizer, the workflow successfully solves the history-matching and CO2 water alternative gas (WAG) design problem with low computational overheads. The history-matching work considers the heterogeneities of multiphase relative characteristics, and the CO2-WAG injection design takes multiple techno-economic objective functions into accounts. This work trained an expert response surface, a support vector machine, and a multi-layer neural network as proxy models to effectively learn the high-dimensional nonlinear data structure. The proposed workflow suggests revisiting the high-fidelity numerical simulator for validation purposes. The experience gained from this work would provide valuable guiding insights to similar CO2 enhanced oil recovery (EOR) projects.

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