Building EOR culture

SPE-174694-MS Building an Enhanced Oil Recovery Culture to Maximise Asset Values M. Rotondi, A. Lamberti, F. Masserano, K. Mogensen, eni SpA

Copyright 2015, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Enhanced Oil Recovery Conference held in Kuala Lumpur, Malaysia, 11–13 August 2015. 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 stora ge 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.

Abstract Global energy demand is forecasted to rise by over one-third from now until 2035. As the relatively easy oil reserves deplete, focus will shift to development of extremely complex reservoirs in challenging environments including those in ultradeepwater and the Arctic. Another source of supply to fill the void will be from Enhanced Oil Recovery (EOR) techniques applied to existing fields. The current global ultimate average recovery factor for oilfields is roughly 35%. This means that about two-thirds of the already discovered oil is left within the reservoir. Pushing the recovery factors from 35% up to 45% would bring an additional one trillion barrels of oil to an energy-hungry world. Even though the EOR prize is high, many oil companies are still struggling to build an EOR culture. The lack of a systematic approach, costs and time-to-market of EOR projects and the general belief that EOR should only be applied to mature fields are preventing a wider spread of EOR deployment. In order to promote a new wave of EOR applications, it was decided at Top Management level to restructure the EOR Unit by creating a multidisciplinary team of laboratory, subsurface, production, project and procurement personnel. New best practices were also circulated in order to force reservoir engineers to evaluate the benefits of EOR techniques for every new green and brown field reservoir study. This was a breakthrough that facilitated the changing mindset of company professionals as EOR may be applied from the beginning of a field’s life and not only in maturity stages. The EOR workflow from laboratory to field implementation was duly revised in order to try to shorten the time-to-market of EOR projects by means of: a faster screening phase due to a new in-house tool; the deployment of a quicker and high resolution simulator for full field cases and ad-hoc simulators for more detailed sector models; the use of single well chemical tracer tests to promptly prove the effectiveness of EOR agents; and finally, standard practices for pilot implementation and monitoring. A strong focus on containing costs was proposed to explore cheaper and more promising EOR techniques such as Low Salinity. The whole company reservoir portfolio was screened at a high level to identify the most prominent EOR techniques to focus on and the unconstrained additional EOR RF calculated. Finally, some interesting cases on water-alternate-gas projects for mature fields, chemical EOR and water conformance by means of thermally activated particles will be presented. The adoption of the new workflow showed a great time reduction from screening to pilot phase and that in some cases EOR techniques are still viable even in a low oil price scenario.

Introduction EOR includes any technique that alters the fluid flow properties and thus recovers hydrocarbons that are not produced during primary and secondary depletion. EOR techniques can be grouped in 3 main families: Thermal, Gas Injection (GI) and Chemical methods. Besides the above groups, there are other emerging techniques such as Microbial EOR and nanoparticles. Thermal EOR is the most widely used method, which involves heating up the oil to decrease its viscosity. Therefore, it is mainly used for heavy and extra-heavy oil. Gas injection or miscible flooding reduces oil viscosity and interfacial tension, increases the oil swelling and maintains reservoir pressure. The injected gas may be hydrocarbon, carbon dioxide, nitrogen, etc. depending on gas availability and infrastructures, reservoir conditions and the overall field development strategy. Finally, chemical EOR (CEOR) includes all techniques in which a chemical additive is mixed with injection water in order to improve the vertical/areal sweep efficiency of the water flooding scheme and/or increase the microscopic efficiency by altering the chemical/physical properties of the reservoir rock. Low-salinity flooding would also fall within the Chemical EOR category.

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Figure 1. Enhanced Oil Recovery families.

The optimal application of each EOR method depends on reservoir parameters such as temperature, pressure, depth, permeability and fluid properties, mainly viscosity. Several screening criteria have been developed in the industry, please refer to Taber et al. (1997) for further details. A renewed focus and increase of EOR deployments have recently been observed in the US and Canada, but as well in many other regions of the world, thanks to the stable oil price scenario experienced until the end of 2014. According to IEA (2012), production coming from EOR techniques will be equivalent to roughly 25% of total world oil production in 2035.

Figure 2. Worldwide future oil production and demand (modified after IEA, 2012).

Even though the IEA forecast is showing an encouraging steep increase in EOR production, there are still many challenges to be faced in the next decades and especially in low oil price scenarios like the current one. Reducing time-to-market and costs of EOR projects and changing the mindset of O&G professionals are some of the issues that oil companies will have to address in order to meet the global oil demand. Eni is committed to increase the recovery factors of its assets deploying the most advanced technologies in a cost-efficient way.

Enhanced Oil Recovery Challenges Next paragraphs will be focused on the main EOR challenges, such as: project time to market, costs and mindset which prevented a wider spread of EOR deployments in the past. The authors will show as well eni efforts and implemented strategy to address the above challenges and ensure a faster and cost-efficient deployment of EOR techniques.

EOR Project Time to Market An EOR project may require several years of studies and usually follows a set of defined steps before its sanction, namely: a screening phase of the optimal technique, laboratory analyses and 3D simulation, a first pilot to investigate the EOR effects at well scale (single well chemical tracer test, log-inject-log test, etc.), then an inter-well pilot involving a bigger area of the reservoir and eventually the full field implementation (see Figure 3). Therefore, a successful project may take up to 6-8 years, or even more, to be completed. This standard timeline is more and more clashing with current needs of accelerating time to market of development projects and recovering EOR expenditure before the end of production licenses, which in mature fields is even more critical.

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Figure 3. EOR project timeline. Moving from a sequential to a quicker parallel approach.

The length of the standard approach was internally seen as one of the main obstacles to EOR deployments. For this reason a revised workflow was designed identifying areas of possible improvements for each EOR step, moving from a solely sequential approach to a quicker parallel one (Figure 3): 

Screening Phase – The methodology adopted by eni is the results of collaboration between eni and Politecnico of Milan. The underlying concept is that similar EOR techniques may be successfully applied to fields sharing similar characteristics (Siena et al., 2015). A data-base considering worldwide EOR field experiences was defined and for each field, average parameters were collected: reservoir depth and temperature, porosity and permeability, oil viscosity and density. These properties are critical elements for the assessment of the potential of different and sometimes competing EOR techniques. A screening of target analogs is obtained by classification of documented EOR projects through a Bayesian clustering algorithm. A preliminary reduction of the dimensionality of the parameter space over which EOR projects are classified is accomplished through Principal Component Analysis (PCA). Moreover an inter-cluster refinement is obtained by ordering cluster elements on the basis of a weighted Euclidean distance from the target field in the parameter space. Fields belonging to the same cluster are considered analogues. Based on Euclidean distance it is moreover possible to define a further ranking between them. Output of the approach is, therefore, a benchmarking of the most applied techniques in the cluster, the list of analogues on which technologies were applied and references related to worldwide EOR experiences, thus enabling to acquire from the earliest stages of the project evaluation a technical know-how on the most applied EOR techniques (Figure 4). Thanks to this tool in few minutes the reservoir engineer has access to valuable information and can easily learn from previous experiences.

Figure 4. In house screening tool for EOR analogues.

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Laboratory Analyses and Modeling Phase – The eni laboratories were reinforced and restructured. The laboratories are equipped with most advanced experimental set-ups and capable of running every kind of EOR analyses.

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From a modeling point of view, a strong focus was put on the understanding of reservoir behavior by exploiting both ‘old school’ reservoir engineering tools and high resolution simulators. The workflow consists in a stepwise addition of complexity integrating the results coming from advanced production data analysis (APA), a semi-automated proprietary tool for multi-tank models and streamlines simulation. This step is used to fully understand the reservoir dynamics and to build a solid conceptual model before moving to the 3D modelling. In particular streamlines represent the path of communications inside the reservoir between injectors and producers and are useful to estimate and improve efficiency of an existing water injection scenario. Sector and full field modelling are more and more frequently built by means of a new high resolution simulator (Cominelli et al., 2014) which has led to impressive results in terms of simulation time reduction: up to a factor of 100 when compared to standard simulators. In addition, the coupling of the new simulator with eni computing center, one of the most advanced in the world, is allowing to effectively simulate highly detailed and complex models (in some cases avoiding upscaling and its related approximation) in economic timeframes. This is crucial, not only from a time to market point of view, but also to produce reliable and accurate forecasts, which is mandatory to evaluate the economics of EOR processes. Finally, another action to accelerate this phase is to ensure that project teams have easy access to all reservoir and fluid-related data. Whereas production and injection data are often available in digital form, this is not necessarily the case for other types of data. From an EOR perspective, building and maintenance of databases (PVT, SCAL, EOR core floods, etc.) is regarded as a necessity for a company the size of eni. Below is shown an example taken from the ongoing construction of a database comprising all PVT experiments conducted on reservoir fluids from across the eni field portfolio. Figure 5 shows how PVT properties in a given geographical area may possibly originate from the same source. The methane mole fraction correlates remarkably well with the measured saturation pressure even though temperature, gas-oil ratio, and formation volume factor vary considerably between the fields. Subsequent development of black-oil and miscibility correlations will be incorporated into the proprietary EOR screening tool.

Figure 5. Correlation of methane fraction with saturation pressure for reservoirs belonging to the same geographical region.

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Pilot at Well Scale – A key technical input parameter for any EOR project is the assessment of residual oil saturation (Sor) after primary and secondary development. To evaluate oil left in reservoir is fundamental to assess the benefits for any further development. The Single Well Chemical Tracer Test (SWCTT) is a field trial that provides, using tracer technology, a consistent estimate of Sor at a near-wellbore scale resolution (typical radius of investigation is 2-6 m). It represents an intermediate step from laboratory analysis to inter-well field application. The SWCTT is carried out on a watered out formation interval by injecting, and then producing back from the same well, a volume of fluid labeled with appropriate chemical tracers. The residual oil saturation insitu is obtained from back-produced tracer concentration profiles through analytical methods and numerical simulation (see Figure 6). The efficiency of a specific EOR technique is obtained by comparing Sor evaluated with two subsequent SWCTTs: the first after conventional water injection and the second after EOR technique injection.

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Figure 6. Back-produced tracer data (dots) and type curve (lines) fits for a real field application.

The test is non-destructive and can be repeated on a single zone; it is a relatively short test (typical duration is 6 days) and allows reducing risks before a more complex and costly EOR multi-well development. Eni successfully performed different SWCTTs to assess efficiency of Low Salinity water and Surfactant flood in North and West African projects. The results of the tests were used to guide the decision process and support following phases of the EOR projects (Callegaro et al., 2014; Callegaro et al., 2015). 

Interwell Pilot – Four main actions were identified in order to accelerate interwell pilot execution. The first one is the definition of standard procedures and best practices for pilot design and monitoring. The objective is to learn from previous experiences and accelerate the decision process and the pilot definition. Monitoring plan is an useful tool to guide data collection and objective driven analysis. The second one is a revised contractual strategy, based on framework agreements with service providers that can guarantee the applicability of same contractual conditions to projects in different countries. Procurement phases that are often time consuming can be consequently accelerated. The third one is the definition of an integrated EOR project team that includes all involved professional families (reservoir, laboratories, production and development) as like as people working on a daily base at the field. This integration should avoid waste of time from unfeasible options and should construct the background for an efficient hand-over of the project after pilot start-up. The forth is the synergies with existing facilities that could accelerate the execution phase and minimize the required investments before assessing the effectiveness of the target EOR technology.

By combining the above findings and best practices and moving from a solely sequential to a more parallel approach, it was possible to dramatically reduce the first four steps of the EOR timeline, as will be illustrated in some of the case histories. Another key factor was to anticipate as much as possible the interwell and intrawell pilot phases, in order to obtain early indication of EOR effectiveness and gradually incorporate related information into sector and full field dynamic models.

EOR Costs EOR projects are strongly influenced by economics and long term crude oil prices. The current EOR renaissance may be impaired by present low barrel cost. However, to better understand the EOR future, it is crucial to look back to what happened during the eighties and the nineties, when the oil price dropped below 15 USD (Stosur et al., 1994, Brasher et al., 1989). EOR projects had experienced a tremendous growth at the end of the seventies showing a close correlation between new project start-ups and oil price. When in 1986 the crude touched 12 USD per barrel many companies stopped EOR investments and the number of project start-ups sharply decreased. However, despite this scenario, an increase in EOR production was observed. This production was coming from a smaller, but more robust, number of projects, which were eventually expanded. The low oil price had triggered a sort of “natural selection” process whereby the most effective and efficient EOR techniques continued to flourish, while those less successful were retained for additional technology development. In particular, thermal and gas injection methods continued to contribute to EOR production, while the deployment of chemical techniques was drastically reduced. Chemical methods were, indeed, too expensive and less reliable

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at that time. The growth of EOR production, in spite of declining oil prices and fewer EOR start-ups, is an example of how the petroleum industry is able to adapt to the rapidly changing economic conditions finding new routes to success. In the mid 2000’s crude prices, and subsequently EOR activities, began to rise again. Whether nowadays EOR production will continue to increase or will stabilize depends on the skill of operators and researchers in providing methods to keep production costs in line with oil selling prices. However, it is foreseen that a strong focus on EOR will still remain. Indeed, a trend towards smaller discoveries is set to continue and, where large fields remain to be discovered, they are likely to be in increasingly remote locations, such as deepwater and the Arctic. These types of development are not only expensive, but in many cases at the limit of current technology. The end of “easy oil” may be as well appreciated by the increasing number of drilling activities. For the ten years prior to 2000 the production growth was maintained with a relatively stable rig count, while a similar rate has required a 50% increase of active rigs since 2000. Despite EOR is generally perceived as expensive, it currently shows comparable or even lower production costs with respect to other oil resources (IEA, 2013) In addition, future EOR finding and development (F&D) costs, weighted by related production over the period to 2035 will be even lower (IEA, 2014). Therefore, EOR will be more and more attractive when compared to the development of more expensive oil resources.

GTL

Oil Shale

CTL

Heavy Oil

Tight Oil UDW

Arctic

EOR Conv. Oil

Already Produced

MENA

Figure 7. Oil production costs for different resource categories (IEA, 2013).

Figure 8. Finding and development costs for different resource categories projected to 2035 (IEA, 2014).

To ensure a stable growth of EOR projects within its asset portfolio, even in a low oil price scenario, eni is considering the following points: 

A collaborative R&D environment between operators, universities, service companies and governments should be promoted in order to fully understand EOR mechanisms and deploy recent and most promising EOR

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    

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techniques, guarantee aggressive technology transfer between all the involved players and avoid costly failures. The worldwide recovery factor efficiency has increased of about 10% within a short period of 20 years and current RF is averaging 35%. The role of new technologies and collaborative research will be crucial to further push this current limit. Robust EOR planning, combining advanced simulation capable of mimicking physical and chemical processes and economic evaluation at each step of the engineering design process should be promoted. Proactive planning and earlier deployment of EOR techniques during initial field development, rather than declining production stage, may improve EOR project NPVs of about 20-35%. A stronger focus should be put on low cost EOR techniques such as Low Salinity (Marcolini et al. 2009; Callegaro et al. 2013; Rotondi et al., 2014; Spagnuolo et al. 2015) and Smart Water. More field trials should be planned and performed in order to commercially prove these technologies. A new contract management strategy should be encouraged, favoring framework agreements and long term contracts with service and chemical providers. Finally lateral thinking and creative approach should be stimulated to generate new ideas for old and mature fields. Sometimes EOR techniques may be extremely cheap while providing remarkable production gain, as it will be shown in the first case study of this paper.

EOR Mindset When it comes to success in EOR deployments, there is nothing more important than the right mindset. A positive and open attitude is much more crucial than tools and processes. However, instilling a new mindset is not an easy task and may require time and radical changes within a company organization. EOR is, indeed, still wrongly perceived as a reservoir or laboratory subject, while it requires a fully multidisciplinary approach involving all E&P expertises. It is sometimes considered a technological frontier, even if some techniques such as WAG are mature and field proven. In addition, EOR should not be exclusive to mature fields and requires a strong top management support and long term vision to ensure continuity. In order to overcome the above issues and give birth to a new EOR ‘Culture’ within the company, the EOR team was firstly reorganized by grouping the know-how that was spread among different departments and subsequently reinforced by hiring some EOR experts from the market. The new EOR team was asked to promote know-how dissemination through several workshops, webinars, lectures, meetings etc. in order to spread the EOR knowledge at every level within the organization. Internal guidelines and best practices were issued. For example every new reservoir study has now a chapter dedicated to EOR screening and possible EOR implementations. This is forcing the reservoir team to think about EOR techniques from day one even in green-field developments. Finally, the number of external collaborations in Joint Industry Programs was increased. The above actions should hopefully facilitate the growing of an EOR professional generation in order to support future EOR developments to increase the recovery factors of company assets.

Figure 9. Building an internal EOR ‘Culture’.

Building an Enhanced Oil Recovery Culture: eni’s Strategy After having restructured and reinforced the EOR team, at the beginning of 2013 the whole company portfolio was systematically screened in order to identify the optimal and most promising EOR techniques and evaluate the related additional EOR resources as shown in below figure. It was found that gas injection followed by chemical methods and low

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salinity flooding are in sequence the most appropriate techniques for the company portfolio. This helped to revise the overall R&D strategy and company focus concentrating the main efforts on the above methods. The estimated value of potential production coming from EOR was so attractive that a second level screening, field by field, was performed. The implemented workflow, leveraging on the EOR analogues in-house tool, allowed identifying several opportunities in a very pragmatic and straightforward approach. At this point the objective was twofold: deployment of more mature and ‘safer’ techniques as WAG, in order to obtain quick results in terms of production gain and in parallel study and implement chemical methods to build internal competencies on these less mature techniques. Another useful action was to critically review all past studies where EOR opportunities had been duly evaluated, but, for different reasons, not proven in the field. This approach helped to ignite the EOR ‘culture’ and obtain top management support thanks to successful results of first deployments, while at the same time allowed to gain knowledge on different techniques to cover the entire asset portfolio.

Figure 10. eni EOR strategy.

Successful Case Histories & Studies Thanks to the implemented strategy, illustrated in previous paragraphs, several new EOR initiatives, which are now in different stages of maturity, were launched and previous projects drastically accelerated to pilot / full field phases. Some of these successful case histories will be presented below.

Gas Injection Methods Gas injection for pressure maintenance as well as for enhanced oil recovery has been practiced with success for several decades. We refer to the SPE Monographs of Stalkup (1983) and Jarrell et al. (2002) for an in-depth literature review of early flood performance. Improvement in oil recovery by water-alternating-gas as opposed to continuous gas injection has been documented by Christensen et al. (2001). Our case histories will focus on three hydrocarbon Water-Alternating-Gas (WAG) schemes, miscible as well as immiscible. WAG is regarded as a key enhanced oil recovery method in eni. Miscible Hydrocarbon WAG The field under study is part of eni’s vast portfolio of North-African fields. Discovered some two decades ago, the field has ten years of production history and the development strategy up until now has centered on gas injection as well as water injection for pressure maintenance. The crude oil is light and develops multi-contact miscibility with its own solution gas at current reservoir conditions. To honor a zero-flaring policy, all produced gas must be re-injected. Production performance data analysis in conjunction with reservoir simulation studies have indicated that potential for further recovery exists by replacing the current gas and water injection practice with a tapered WAG scheme. Moreover, the presence in the field of gas and water injection facilities guarantees a limited investment and fast implementation of the EOR project.

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A WAG pilot phase was initiated in 2013, where water injection well WAG1 was converted to gas injection to sweep attic oil not contacted by water and to furthermore enable redistribution of the injected gas in order to address gas breakthrough concerns in other parts of the field. The positive effects from the WAG pilot on production performance of neighboring production well Prod1 are clearly seen in Figure 11. Part of the observed improvement in oil rate can be explained by the ability to inject more fluid (in reservoir volumes) due to the compressibility of the gas. However, there is no doubt that gas is sweeping areas not previously contacted by the water. Further details on field tests and monitoring strategy are described in Maffeis et al. (2015).

Figure 11. Effect of WAG start-up in well WAG1 on closest producer Prod1.

This case is perfectly addressing the above discussed EOR challenges: time to market, EOR costs and mindset. As regards the time to market and related investments, the project was defined and executed in only 12 months taking advantage from easy on-shore environment and existing injection facilities bringing to an estimated cost per additional oil barrel lower than 0,5 $/bbl and an expected ultimate recovery factor around 60%. Immiscible Downdip WAG Immiscible WAG injection can be applied in mature fields to maximize ultimate oil recovery factor. The case under study is a structurally complex offshore field, developed by means of peripheral water injection and crestal off-spec gas disposal. Current WCT is above 90% while production wells in the gas injection area are suffering from high GOR with consequent reduction in performances. During 2014 eni became field operator launching a process of field rejuvenation. The approach considered the use of APA, streamlines and updated 3D model to understand actual field performance, injection water flowpaths, producer-injector connections and reservoir response to WAG application. The analysis showed that the current water injection scheme is no longer efficient: water moves through most permeable layers leaving unswept by-passed attic oil due to gravitational segregation (see Figure 12).

Figure 12. Water moves into most permeable layer leaving behind unswept attic oil.

Application of WAG can lead to additional oil recovery by reducing residual oil saturation and pushing attic oil toward production wells. Estimations indicate an increase of almost 2% of ultimate oil recovery factor from full field WAG application.

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Moreover, presence of gas and water injection facilities reduces the required investments, making the project really attractive and economically viable. Last but not least, WAG application turns gas disposal from issue to opportunity, by optimizing gas injection scheme avoiding anticipated gas break-through. eni is planning a WAG pilot to confirm effectiveness of the technology by the end of 2015. The pilot is considering two water injectors that will be converted into WAG wells and few connected producers. Based on pilot results, the technology will be extended at full field converting 2 additional injection wells. For this case it only took 1.5 years from study to pilot Foam Assisted WAG Last case of WAG shows an example of EOR implementation since day one in a deepwater asset in West Africa. Nearby field operated by another major with WAG scheme showed anticipated gas breakthrough with consequent reduction in well performance and severe issues at gas handling facilities. Gas injection suffers from poor macroscopic sweep due to gravity override and viscous fingering effects. Foam-assisted WAG is an attempt to reduce gas mobility while preserving the beneficial effect of the WAG scheme (Figure 13). An early application of FAWAG in the Snorre field in Norway was presented by Skauge et al. (2002). OP1

OP1 WAG2

WAG2

0.9

0.5

0.03

After 7 years of injection WAG

FAWAG

Figure 13. 3D dynamic model highlighted effect of Foam in delaying gas breakthrough.

Thus a FAWAG project was launched in order to mitigate the risks of gas breakthrough. The project is particularly challenging because the field is in production through an FPSO; therefore the engineering will be crucial to minimize the space occupied by any additional facilities. An initial phase of laboratory analysis was initiated to support the design of the field application that is foreseen in 2016.

Maximizing Water Flooding Efficiency Many fields under water injection show poor sweep efficiency and moderate recovery factors due to geological heterogeneities, presence of thief zones, unfavorable mobility ratios and/or high residual oil saturations. The efficiency of mature water floods may be drastically improved by a better field understanding coupled with the deployment of new technologies (Rotondi et al., 2011). The strategy implemented by eni is to identify and recover unswept oil by means of the combination of different IOR and EOR techniques such as water conformance, polymer injection, surfactant and low salinity flooding. Water Conformance by Thermally Activated Particles Thermally Activated Particles (TAP) can be applied as in deep conformance technology to mitigate anticipated water break-through due to reservoir heterogeneity. Bright Water ® (BW) is a TAP polymer injected with water that reacts at defined temperature by increasing its size. This phenomenon obstructs high permeable and watered out layers, forcing injected water to find alternative flow-paths and hence displacing unswept oil. The expected results are an improvement in sweep efficiency, the reduction in water production and the extension of well production life.

Figure 14. Thief zones plugged by Bright Water treatment.

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The technology was applied by eni in different fields. The case presented here is related to giant onshore mature oil field located in North Africa. The reservoir is characterized by facies heterogeneity and high vertical permeability contrast. Conventional water injection was successfully implemented since 1970s to support the reservoir energy. The field is currently producing at very high water cut. Pilot TAP project (one producer and one injector) was successfully implemented in 2010 and results were profitable, giving an early pay out time of less than one year (Galli et al., 2012). These encouraging results led at the beginning of 2013 to applying the BW project at larger scale, involving six oil producers and two water injectors. Current results are showing both a clear increase in oil rates and a simultaneous reduction in water cut, leading to an estimated extension of well life of about 5 years.

Figure 15. Bright Water Application in Mature Field. Oil production (green) vs decline curve (black).

Polymer Flooding The field, located in North Africa, is a heterogeneous sandstone reservoir, containing medium heavy oil (23 cp @ RC). The reservoir was discovered in 1992 when the exploration well found a heavier, biodegraded and more viscous hydrocarbon than the surrounding fields. For this reason, this structure was only developed 16 years later, keeping the first well in production in the meanwhile. In 2006 the field was reassessed and it was decided to develop the field by means of 12 producers. In 2011-2014, due to the rapid production decline, the field went through an IOR phase characterized by infill drilling and the start-up of dispersed water injection. Later on, after a detailed EOR screening analysis, polymer injection was selected as the most promising technique to optimize the field recovery factor (Pizzinelli et al. 2015). Dedicated in-house laboratory studies were performed to choose a suitable polymer considering temperature, injected water salinity and divalent ions content. The influence of these parameters on polymer viscosity was evaluated together with mechanical and thermochemical stability. Once the polymer, HPAM with copolymers, was pre-selected, bulk viscosity measurements were carried out to find the polymer concentration to obtain, a target viscosity of 7 cP at reservoir conditions. Then core floodings were performed to evaluate the effectiveness of polymer injection at reservoir conditions. Moreover, since polymeric solutions often exhibit non-Newtonian behavior, polymer rheology in porous media was investigated to better evaluate well injectivity. In addition, laboratory analyses evidenced a high concentration of iron ions in the injection water which is detrimental for polymeric solution effectiveness. For this reason it was also necessary to build an additional unit to treat injection water for iron removal. A simplified plant design is reported in Figure 16.

Figure 16. Polymer injection plant sketch and picture.

Based on promising laboratory results, 3D reservoir simulations were carried out. A full field model was built including new information obtained from PLTs, interwell tracers and production data. The model was then used to forecast and define

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the injection strategy of a pilot consisting of two polymer injectors. Results, reported in Figure 17, show that the EOR pilot will lead to an incremental cumulative oil production of more than 10% compared to the water injection scenario.

Figure 17. Field historical oil production and forecast for CEOR pilot.

A detailed monitoring plan was defined, in order to evaluate polymer injection effectiveness, field behavior and plant performance. Water cut has been monitored with particular care, as it is a crucial parameter for the evaluation of the field response. The polymer exhibited good injectivity and encouraging preliminary results have been obtained so far. Water cut reductions were observed in oil producers close to the pilot injectors, as in the example reported below. 100 90 80

WCT [%]

70

Polymer injection start-up

Measured WCT and Mobile av. on 30 days Polymer BT in PW

60 50 40 30 20 10 0

Figure 18. Well A - WC reduction due to polymer injection.

Moreover, a delayed breakthrough time, measured by means of interwell tracers, was observed with respect to previous WI phase. The current plan is to keep focusing on well monitoring to confirm effectiveness of the polymer injection and extend the EOR application to full field. Last, but not least, this project opened the way to similar applications in other reservoirs operated by eni. Thanks to the acquired knowledge, it was possible to accelerate the whole process and combine different EOR techniques such as polymer, low salinity and thermally activated particles in order to maximize the overall water injection efficiency as illustrated in next case study. Low Salinity & Polymer Flooding This giant on-shore field is located in North Africa and it is composed of 12 heavily faulted reservoirs characterised by turbiditic and deltaic sandstone with interbedded shales and anhydrite intercalations ranging from lower to upper Miocene age. The field is characterized by medium viscous oil (oil viscosity @ RC ranging from 4 to 8 cp). Production started up as primary depletion in the fifties and in 1985 peripheral water injection was implemented. Due to the medium oil viscosity, water injection is characterised by unfavourable mobility ratio, causing anticipated water breakthrough and leaving a high percentage of by-passed oil behind the water front.

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Starting from 2009 many processes have been evaluated in order to increase the sweep efficiency of water injection. After a screening phase, dispersed polymer injection and low salinity water were selected as the optimal chemical EOR technique. As regards polymer injection, a sector of the field was selected to implement a pilot to test the effectiveness of the technology before applying it to other areas of the field. A laboratory screening was carried out to select and characterize the optimal polymer formulation (Braccalenti et al., 2013). Core floodings were executed to assess the performance of polymer injection at reservoir conditions, and evaluate the rheology in porous media.

Figure 19. Polymer Coreflooding experiment results

Based on the positive laboratory results, detailed 3D simulations were carried out to define the optimal EOR injection scheme and assess the expected oil gain. A change in the injection strategy from a peripheral to a dispersed pattern was suggested to increase the water flooding performance. Moreover, dispersed injection guarantees a more efficient areal displacement of the polymer toward the producers (Raniolo et al., 2013, Nobili et al., 2014). The pilot started in April 2015. An accurate monitoring plan was defined to assess the efficiency of the technology and guide the decision process.

Figure 20. Polymer injection plant sketch.

As regards low salinity water the scope is to decrease residual oil saturation, by modifying the wettability of the rock from oil wet toward more water wet system. Low salinity was positively tested at lab scale. Core flooding experiments highlighted an improved oil recovery of about 7%. The technology was then tested at well level by means of SWCTT. Positive results showed a reduction of residual oil saturation of 5-9 points (Callegaro et al., 2015).

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Figure 21. SWCTT results. Residual oil saturation after sea water and low salinity flooding.

Currently a pilot of low salinity is under study to confirm efficiency of the technology. A candidate dispersed water injector was selected. Surrounding wells are producing at already high WCT. This environment should anticipate effect of low salinity injection that is contributing to production once residual oil saturation conditions are reached. Furthermore eni is evaluating the possibility of combining the two technologies. The target is to take advantage of improved volumetric and microscopic sweep efficiencies by means of polymer and low salinity respectively (see Figure 22).

3 months water preflush

1st polymer slug 3 cP 2nd polymer slug 6 cP in Low Sal

Water drive

Figure 22. Results of 3D simulation with combined technologies in green (dispersed Polymer + Low Salinity)

Thermal EOR As previously reported, the eni field portfolio does not include many operated HO fields. However, eni is active in developing and testing innovative technologies to enhance heavy oil recovery. In particular, in the last years, attention was focused on two main technologies: electrical heating and radiofrequencies. A pilot of electrical heating was implemented in an off-shore mature heavy oil field in West Africa. Scope of the technology is to reduce viscosity by heating the oil inside the tubing and in the area around the production well. Heated oil can more easily flow inside the well maximizing well productivity and minimizing friction losses along the tubing (Bottazzi et al., 2013). Radiofrequencies were studied as alternative technology to electrical heating. Indeed also electromagnetic irradiation through down-hole antennae can be a suitable method for in-situ heating of reservoir. The advantage with respect to electrical heating is the greater radius at which reservoir is heated and the lower energy consumption. An R&D project is ongoing to define the optimal conditions to implement the technology, in terms of well completion and radiating element design (Bientinesi et al., 2013).

Conclusions The lack of a systematic approach, costs and time-to-market of EOR projects and the general belief that EOR should only be applied to mature fields are preventing a wider spread of EOR deployments. In order to promote a new wave of EOR applications in eni, it was decided at Top Management level to restructure the EOR unit by creating a multidisciplinary team of laboratory, subsurface, production, project and procurement personnel. New best practices were also circulated in order to encourage reservoir engineers to evaluate the benefits of EOR techniques for every new green and brown field reservoir study. This was a breakthrough that facilitated the changing mindset of company professionals as EOR may be applied from

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the beginning of a field’s life and not only in maturity stages. The EOR workflow from laboratory to field implementation was duly revised in order to try to shorten the time-to-market of EOR projects by means of: a faster screening phase due to a new in-house tool; the deployment of a quicker and high resolution simulator for full field cases and ad-hoc simulators for more detailed sector models; the use of single well chemical tracer tests to promptly prove the effectiveness of EOR agents; and finally, standard practices for pilot implementation and monitoring. A strong focus on containing costs was proposed to explore cheaper and more promising EOR techniques such as low salinity. The whole company reservoir portfolio was screened at a high level to identify the most prominent EOR techniques and the unconstrained additional EOR RF was calculated. Some interesting cases on water-alternate-gas projects for mature fields, water conformance by means of thermally activated particles and chemical EOR were presented. The adoption of the new workflow showed a great time reduction from screening to pilot phase. In addition, it was highlighted that in some cases EOR techniques are still viable even in a low oil price scenario, especially if a proactive and positive mindset is adopted. Some technical challenges, such as bringing EOR offshore and deepwater, better understanding of EOR mechanisms in carbonates and common procedures for EOR pilot monitoring should still be addressed. Therefore, it is crucial to keep investing in people and technology in order to maximize RF even in the current low oil price scenario.

Acknowledgements The authors would like to acknowledge eni SpA, its affiliates and partners for granting permission to publish and present this paper. In addition, they would like to thank all eni colleagues involved in EOR activities.

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