The targeted reservoir for foam mobility control is usually layered or heterogeneous. However, a major limitation of existing foam models is that there are no dependencies of the foam modeling parameters on permeability, even though the permeability is accounted inherently only through changes in gas-water capillary pressure and shear rate. This results in considerable errors in predicting the foam mobility at largely varying permeabilities, which prevents users from simulating correctly the conformance achievable with the help of foam in heterogeneous reservoirs.
Developing a foam simulator with systematic permeability-dependencies of foam properties is a key enabler for the rigorous simulation of foam floods in the field. An advanced population-balance foam model has been developed with reasonable physical mechanisms associated with the effect of permeability on the bubble density, foam generation and stability in porous media. The derivations indicate that the gas viscosity scaling constant increases with permeability exponentially, while the upper limit of foam texture, the foam generation coefficient, and the limiting capillary pressure decrease exponentially as the permeability increases. All these factors collectively affect the foam mobility. The upper limit of foam texture and the foam generation coefficient share the same power-law exponent with permeability because of the similar fundament. As a result, three additional power-law exponents are needed to correlate with permeability in the new model.
To verify the correlations of the parameters with the permeability change, an automated regression program was applied to fit the resistance factors of several groups of foam flood experiments with foam quality scans at different permeabilities. The newly developed permeability-dependency functions showed its great competency in matching all the experimental data in a wide range of permeability. The optimized parameters are largely consistent with the theoretical exponents of the power-law functions of the aforementioned physical properties correlated to permeability, but also suggest extra modifications. In particular, the exponent for the limiting capillary pressure is about -0.5, which is equivalent to that the limiting water saturation is approximately independent of the permeability according to the Leverett J-function. As a result, the new functions of permeability dependencies for the foam-model parameters in the population-balance model enables the foam modeling with only a single input of foam parameters at a referenced permeability. A 2D layered reservoir case was used to test the new permeability functions, which shows the significant difference in terms of the oil recovery and the injector BHP between whether considering the permeability effect or not.
This paper proposed, for the first time, a systematic methodology to account for the critical permeability effect to simulate foam flooding in heterogeneous reservoirs. This is a key advance in consideration of the major limitation of existing reservoir simulators using fixed or ad-hoc foam-model parameters throughout the entire reservoir. This new model enables the reservoir engineers to simulate and optimize the foam performance in real fields with better accuracy of foam physics in porous media.
Al-Amrie, Omar (Total Abu Al Bukhoosh) | Blondeau, Christophe (Total Abu Al Bukhoosh) | Berthier, Maxime (Total Abu Al Bukhoosh) | Ruau, Olivier (Total SA) | Baylaucq, Antoine (Total SA) | Massoue, Didier (Total SA) | Lescoute, Laurent (Total SA)
Total has been operating oil and gas production from a series of heterogeneous reservoirs offshore Abu Dhabi since 1974. Today's world class recovery factor obtained on some of the fields is due to early application of new technologies such as enhanced artificial lift multi-lateral wells, field-wide tracer and state-of-the-art reservoir monitoring and well management. High-complexity in such a field required very fine reservoir monitoring to update production allocation from multi-drain wells, to extend field production.
Developing reliable and cost effective monitoring tools is primordial to reduce operating cost, especially for mature fields in a low oil price environment. Since the middle of the 1990's, allocation by geochemistry has been regularly used to allocate production between reservoirs with significant oil signature differences. It has been mainly used to reduce the number of production logging acquisition runs and to provide a production allocation in wells for which the production logging is not possible.
This technique has proved to be a reliable technique but has had a major drawback associated with the time and logistics required to collect and send well head samples to laboratories for batch analysis. Delays of up to 6 months from sample collection to results availability have had inevitable consequences on the implementation of the required actions.
The first in-line GeoChemistry remote Tool (GCT) has been developed by Total and successfully field tested on oil wells in 2015. This tool allows for automated sequential sampling operations, oil separation and oil signature analysis, enables within a few hours, an individual reservoir oil production allocation to be estimated. This tool connects directly to well heads while sampling produced fluids. Fluids are sent in the dual-skid system through a sampler where oil, gas and water are separated and from here then to an analyzer which is a coupling between gel permeation chromatography with ultra violet detector. Finally, results can be obtained in real time after processing and correlation of analytical data through statistical software (oil composition & production split between producing layers).
This paper describes challenges encountered to implement and test the tool in the field. Indeed, after validation of this first pilot, the offshore environment combined with a large typology of wells tested (high water cut, high GOR, H2S, gas activations, slugging behaviour) led to an upgrade of the prototype which will provide greater accuracy and wider range of application in the campaign planned for 2016.
Total has been operating oil and gas production from a series of heterogeneous reservoirs offshore Abu Dhabi since 1974. One of the main oil producing reservoirs of Jurassic age has been the subject of a number of EOR studies at lab and field scale to achieve a higher ultimate recovery factor.
In 1991, TABK initiated its first gas injection EOR Pilot with full-field expansion in 1997. In 2014 a successful Chemical EOR Pilot was carried out that showed a significant drop in residual oil saturation around the target well. As all the pumping equipment was available for the Chemical EOR project a window of opportunity opened up at short notice to perform a second EOR test on other wells.
The literature has recently highlighted successful applications of a relatively cheap commercially available enzyme in mature oil wells around the world with no environmental impact. This would be the first Enzyme EOR application in the Middle Eastern carbonates and, if successful, could provide a logistically simple, cheap method for enhancing oil recovery and assist Abu Dhabi to achieve its objective of 70% recovery factors.
Although there had been no time to evaluate the product in Total’s labs it was decided to go ahead with the test anyway in the spirit of supporting ADNOC’s initiative to accelerate the application of emerging technologies. This paper discusses the design, reservoir monitoring and lessons learnt from a "Huff-n- Puff" application of Enzyme EOR.
In terms of operations, the campaign was completed successfully; it demonstrated that the application poses no risk of flow assurance or to the environment and has provided invaluable experience of incorporating an EOR Pilot in day-to-day operations. In terms of EOR effect, an increase in oil rate is observed in only one well with no significant decrease in the water cut; in addition, the increase could be equally explained by well stimulation and/or better well stability (less slugging).
Madathil, Asok (Total UAE Romain Bursaux, Total SA) | Azrak, Omar (Total UAE Romain Bursaux, Total SA) | Pearce, Adrian (Total UAE Romain Bursaux, Total SA) | Al Amrie, Omar (Total UAE Romain Bursaux, Total SA) | Gunasan, Erkan (Total UAE Romain Bursaux, Total SA) | Blondeau, Christophe (Total UAE Romain Bursaux, Total SA)
Total has been operating oil and gas production from a series of heterogeneous reservoirs offshore Abu Dhabi since 1974. Today's world class recovery factor is due to early application of new technologies such as ESPs, gas lift, multi-lateral wells, field-wide tracer and state-of-the art reservoir monitoring and well management. But the main contributor to this high recovery factor is the application of EOR through Immiscible Tertiary Gas Injection since as early as 1991 in 2 of the main reservoirs, it resulted in a recovery factor of over 50% in one of the main reservoir; a top class achievement for a carbonate reservoir and it is still contributing to more than 15% of today's field production.
After 17 years of production, the water cut reached almost 90% in one of the main reservoir. It was imperative to improve oil mobility and recovery in the reservoir to guarantee long term production. Of the various EOR methods considered, injection of natural gas was found to be the most technically and commercially viable. Several laboratory experiments and simulation studies have been performed to confirm the benefit of gas injection. Then, 2 successful pilots in 1991 and 1993 resulted in the decision to develop the technique on a full field configuration.
The Tertiary Gas Injection has been developed on the 2 main reservoirs of the field. These 2 reservoirs have comparable OOIP but very different properties and configuration. One reservoir is 160m thick with good vertical communication and has pressure support by an active bottom aquifer. The second reservoir has 14 thin layers; each layer is 3 to 20m thick and is separated from each other by anhydrite layers with no aquifer support.
This paper will describe the practical experience of immiscible Tertiary gas injection, present the results after 24 years of injection and analyze the possible reasons for differences in performance between the wells and reservoirs. In addition, it will describe how today's strong reservoir management, integrating surface constraints, helps to optimize the production leading to a constant level of production over the past 4 years; which, for a mature oil field that normally declines at 10–15% per year, represents a great achievement.
Total has been operating oil and gas production from a series of heterogeneous reservoirs offshore Abu Dhabi since 1974. The recovery efficiency is already one of the highest in the industry compared to analogous carbonate reservoirs worldwide and the lessons learnt on this field can be usefully applied in the future on other less mature fields in the region.
Since the drilling of the first multilateral well in 1996 most of the infill wells drilled are multilateral with up to 6 drains per well slot targeting different reservoir layers. The layers have different permeabilities, porosities, oil quality, depletion and residual oil saturation. A database containing 20 years of production data from ca. 130 horizontal or multi-lateral penetrations cross-referenced with log and core data now exists.
This paper describes how Total has applied pragmatic technologies in a challenging environment to give itself the best chance of economic success when drilling this type of well. In particular, issues such as target choice, anti-collision with existing wells, flexibility to make “last-minute” target changes, keeping the well within thin layers and the production benefits of zone selectivity will be discussed.
In a 40 year old water-flooded reservoir with diminishing infill targets scattered across the field it has been important to maximize the chances of economic success by maximizing the use of existing data and introducing flexibility in the drilling proposal and well design.
After over 30 years of water-flood and average well water cut of 92%, the risk of drilling an infill well in an already swept region is high. Recent drilling results confirm, however, that remaining pockets of un-swept oil exist but with increasing operating costs and the low production levels targeted (150-600 bopd) the use of cost-effective technologies, effective use of historical data and flexibility whilst drilling have been vital.
Oil is produced from different reservoirs, covering Triassic, Jurassic and Cretaceous. Current development is focused on a heterogeneous reservoir which has the largest amount of unswept mobile oil. It is made of alternating reservoir layers (dolomite-prone) and inter-zones (anhydrite), with different petrophysical properties, initial contacts and oil qualities. Although the rock properties are more or less homogeneous horizontally, an intense fracturation (sub-seismic resolution) is present and tends to compartimentalize the field.
Due to the varying petrophysical properties, each individual reservoir layer has evolved separately through the 40 years of production. Water and gas injection have been partially successful as is confirmed by the areal and vertical variations in pressure seen today. Tracer data has also confirmed the movement of water and gas between injector/producer pairs.
Targeting the remaining sweet spots has been largely successful. It has been achieved since 1996 by drilling up to 6 multi-lateral wells per slot in order to maximize the reservoir contact. As some layers may already be well swept, it is necessary to have a completion allowing drain selectivity in order to manage each horizontal drain separately once the well is on production.
This paper details how these multi-lateral wells are drilled in order to provide the maximum chance of economic success. It also identifies some of the lessons learnt.
Total has been operating oil and gas production from a series of heterogeneous reservoirs offshore Abu Dhabi since 1974. Today, maximizing oil production is critically dependent on how the facilities can cope with handling the associated gas and water rather than treating the oil itself. The nature of these 40-year old facilities and the variable and sometimes erratic performance of individual wells mean that decisions have to be made on a daily basis regarding allocation of available gas for injection into the reservoir for enhancing oil recovery versus its use for gas lift. The decisions have to be made on the basis of predicted incremental oil but in the context of surface gas and water handling constraints.
This paper will describe how a holistic approach seamlessly integrates historical reservoir and well behavior, the daily surface constraints and provide a means to easily and automatically allocate any gas that is available to optimize oil production. A well prioritization list is updated regularly to explicit to which well gas should be allocated and whether it should be used for lifting high water-cut wells or injecting into the reservoir to provide tertiary gas injection for enhancing oil recovery.
This approach has led to a virtually constant level of oil production over the past 3 years; which for a mature oil field that would normally decline at 10-15% per year has been a major success. In addition, the successful full-field Tertiary Gas Injection project has resulted in a recovery factor of over 50% in the main reservoir; a top class achievement for a carbonate reservoir. Today, 15 years after implementation, the TGI effect contributes over 30% to the oil production from the reservoir.
The field was brought on-stream in 1974, less than two years after sanction; and was developed rapidly to reach the plateau early. It was launched on the basis of achieving a 16% recovery in the poorest reservoirs and 38% in the best. Despite the initial view that the field would be uneconomic beyond the mid 1990s, the application of innovative and cost-effective technologies has extended the field life. Following a series of safety and technical upgrades that were carried out on the limited 1970s field architecture, production is still thriving and is expected to carry on economically for many years to come. Today individual layer recovery factors fall between 30 to 65% which is excellent for a heterogeneous, carbonate reservoir of this type in the region.
This best in class results were obtained due to efficient reservoir management utilizing the in-depth knowledge of the reservoir and a good medium/long term planning to maintain economic production potential. Geological and operational challenges faced during the development of the field were solved using innovative technologies. The field has passed through a number of development stages and currently is in a very mature state. The latest technological developments were screened and utilized in the field throughout its life if they were found applicable and economically viable. Classic secondary production mechanisms have been supported by EOR (Tertiary Gas Injection) as well as Multi-lateral wells of which over 30 exist on the field today.
Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Middle East Oil and Gas Show and -------------------- held in Manama, Bahrain, 10-13 March 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.