Al-Amrie, Omar

Total has been operating oil and gas production from a series of heterogeneous carbonate reservoirs offshore Abu Dhabi since 1974. New technologies to increase oil recovery have been always tested and deployed on this field as tertiary gas injection since the 1990's or chemical EOR with a surfactant polymer pilot recently. On the same dynamic, we tested chemical water shut off treatment on two highly waterflooded wells with the injection of relative permeability modifiers (microgels).

This paper describes the full workflow followed for the pilot implementation and lessons learnt.

A particularity of this field is to produce in commingle oil from different thin reservoirs, with permeabilities ranging from to 0.5 to 50mD. Well production is combined through a single sliding sleeve, thus any mechanical shut off is impossible to block the water coming from the high permeability zones that is why the injection of RPM was considered.

Microgels were preferred over conventional polymers gels due to their higher resistance to salinity, shear, and H₂S.

Laboratory studies were conducted to select the best microgel size and to obtain inputs for near well-bore model simulation (microgel adsorption, permeability reduction, injectivity). Numerical simulations were performed to predict the well responses and to define the optimal slug injection.

For this first pilot using microgels in high salinity environment, two vertical wells producing from two different reservoirs were tested, with watercut of 92 and 97%.

The microgel fluids were bullheaded into the whole perforated interval, the fluids were prepared on a nearby marine vessel; the operational challenges faced are detailed.

Preliminary results and way forward are described. The application of this microgel technology to high salinity and moderate temperature carbonate fields has a great potential to improve recovery in very mature fields at low cost.

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.

In 2014, Total performed a surfactant-polymer one spot pilot offshore to test the effectiveness of inhouse developed surfactant molecules to mobilize trapped oil. This paper describes the deployment of this pilot, as a key step of the derisking roadmap of chemical EOR under the harsh salinity and temperature conditions of Middle East carbonates. During several years of R&D and focused studies on this field of the Emirates, a surfactant polymer formulation has been developed able to achieve very low residual oil saturation at core level. The question of testing the formulation in the field has been addressed in parallel to the laboratory work, through extensive surface and subsurface integrated studies, in order to define which type of pilot would be the more suitable.

The paper addresses several aspects: –

Pilot type selection from a geosciences point of view and versus objectives and information provided: where, how many wells, time response, cost

After a cautious analysis of the pros and cons, a one spot pilot has been sanctioned. The design of the pilot versus effective realization is provided, together with the decision tree that was constructed in order to face any operational issue. The paper emphasizes how a strong project management, and headquarters/operational team collaboration allowed completing a safe and successful pilot, ultimately achieving ultra low residual oil at the one spot scale.

The success of a pilot project is conditioned to the strict application of a rigorous methodology of study, validation, and execution, like any development project

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).

In 2014, Total performed a surfactant-polymer single-well pilot to test the effectiveness of a surfactant formulation developed in-house, and including a new proprietary class of surfactants with improved temperature- and salinity-tolerance characteristics. This paper unveils the results of this pilot which targeted a high temperature, high salinity carbonate reservoir. The operations were performed on an oil bearing reservoir of Lower Cretaceous age, in an offshore field operated by Total since 1974 and located 180 km offshore Abu Dhabi. Dedicated topsides were designed and installed for this EOR project. Extensive in-house laboratory studies were performed to select and synthesize the chemicals. Specific simulations, using laboratory results as input, were carried out to predict the pilot performance, design the Single Well Tracer Tests (SWTTs), and size the equipment.

In this paper we will discuss the workflow used to select the most appropriate well and present the methods and results used to characterize the reservoir. Then we will relate it to the surfactant-polymer injection field operations. Finally the reservoir monitoring activities that were necessary to preserve reservoir integrity and demonstrate the pilot efficiency will be described.

The strong decrease in remaining oil saturation measured after the chemical EOR pilot clearly proves the effectiveness of the chemicals synthesized by Total to mobilize the remaining immobile oil after water-flood.

These positive outcomes change the perception of CEOR in hot, saline Middle-East carbonate reservoirs, and could be a "game changer".

Abstract

Oil demand is increasing globally while new oil developments are getting smaller and more challenging to develop (unconventional oil & gas reservoirs, deep offshore, tight reservoirs, heavy oil, acid gas, shale gas etc). In this context, extending the life of mature, conventional oil fields plays an important role in supporting world oil demand.

Reservoir management and development of these mature fields is challenging and requires innovative solutions given the increasing technical costs as production declines and asset/well integrity costs rise. Technically, a good understanding of reservoir behaviour and production mechanisms leads to implementing appropriate solutions to maximize field life, recovery factor and curb production decline. Commercially, the challenge is to find pragmatic and economically viable solutions.

The field discussed in this paper is a mature carbonate offshore oilfield in the territorial waters of Abu Dhabi operated since 1974. After 40 years of production, the field is still producing economically and currently is producing with an average water cut of more than 90%. This paper presents the continuous evolution of the technologies that have been deployed throughout the years to further valorise resources, in response to the growing maturity and complexity of the field.

Various IOR techniques have been employed in this field ranging from ESP’s, gas lift, intelligent completions, multi-lateral wells, splitter wells, dumpflood to selective completions.  In addition, various EOR techniques have been used ranging from full field tertiary hydrocarbon gas injection to chemical and enzyme EOR pilots.

Given the aging production facilities, field management is a daily challenge. The complex gas scheme composed of simultaneous gas production, tertiary gas injection, gas lift, gas recompression and gas export requires continuous arbitration between activation gain and tertiary recovery.

Lessons learnt, good and bad, will help maximize future recovery in other less mature fields in the UAE.

Introduction

The field discussed in this paper is an Abu-Dhabi offshore field operated since 1974. The initial development plan of the field was composed of 1 central platform and 9 wells and the field life span was estimated to 15-20 years.  Today, 40 years later, oil is still being produced, and will continue for many years to come.

The successive phases of the field development over the past decades to further valorize the field resources in response to its growing maturity will be described in this paper.

A remarkably large variety of means and techniques has been deployed all along field development to curb the production decline and extend the field life and its installations. Those techniques include extensive reservoir description, monitoring and modelling, phased development approach, secondary reservoirs development, well activation, production mechanism optimization, use of emerging technologies, understanding of heterogeneities, field management, surface equipment replacement and upgrade.