KEMIRA THE DOW CHEMICAL COMPANY · -Foam EOR, wettability alteration to improve water flood and chemical EOR. Patil is also an EOR specialist for field implementation, reservoir engineering

Oilfield Technology invited experts

from Clariant, BASF SE, Kemira, and

The Dow Chemical Company to share their

knowledge on a variety of EOR topics.

Read on for insights from:

Clariant

BASF SE

Biplab Mukherjee currently holds a position as the technical lead for heavy oil recovery research in the Oil, Gas and Mining business at The Dow Chemical Company. He is responsible for innovation, field implementation and growth on various thermal EOR technologies, including steam assisted gravity drainage and high temperature steam foam.

AMIT KATIYAR Amit Katiyar is an EOR specialist for the CO2-Foam and the wettability alteration technologies. His expertise lies in developing and

implementing Dow EOR products from laboratory to fields through laboratory evaluation, modelling, simulation and reservoir engineering.

Pramod D. Patil currently holds a position as technical leader of EOR at The Dow Chemical Company. He is responsible for the innovation, platform growth and EOR field pilots on various EOR technologies such as CO

2-Foam EOR, wettability alteration to improve water flood and chemical EOR. Patil is also an

EOR specialist for field implementation, reservoir engineering and reservoir simulations.

THE DOW CHEMICAL COMPANY

KEMIRA

GABRIELA ALVAREZ JuRGENSON is a Chemical Engineer with a background in Petroleum and a PhD in physical chemistry of dispersed systems. She has worked at BASF for more than eight years across several functions, ranging from technical (Development Manager and team lead) to operative (Product/Marketing Manager). stefan stein a PhD chemist with who has worked for BASF for more than 20 years across several functions and market segments (Research, Marketing and Product Management). He has more than 10 years experience in the oilfield chemicals market with focus on EOR polymers.

ANTON KAISER holds a PhD in Organic Chemistry from Mainz University. He has held multiple functions within his seven year career with Clariant mostly based in Germany, ranging from leading a surfactant synthesis group on new product development to a few years as Global Innovation Manager – EOR for Clariant Oil Services, in The Woodlands, Texas. He now serves as the Global Head of Strategic Innovation for the Clariant Business Unit, Oil & Mining Services in Frankfurt, Germany.

SUSANNA TOIVONEN has an M.Sc. degree in Chemistry from University of Turku, Finland. Susanna has worked in Kemira’s R&D department for several years, leading research teams developing new products for the industry. Currently Susanna works as Key Account Manager for Kemira’s Global Oil & Gas customers.

MEHRDAD HESAMPOUR graduated with a Doctoral Science and Technology degree in Chemical Engineering from Lappeenranta University of Technology, Finland. Working as a principal scientist in Kemira R&D, Finland, he has been developing a portfolio for membrane and water applications, managing water related projects and technical customer services.

PAULA HENDERSON graduated from Robert Gordon University, UK with and MSc in Oil and Gas Engineering. Paula has been in a Global Marketing role with Kemira for the last four years, working closely with the commercial and R&D teams to bring Kemira technology to the marketplace.

| Reprinted from Oilfield Technology January 2018

Chemical flooding and cEOR

Anton Kaiser – Clariant

Chemical flooding methods involve the use of alkaline, surfactant, co-solvent, polymer and combinations

thereof. As such, the evaluation and design of a chemical flood begins with a review of the reservoir conditions and the existing infrastructure of a field location. Many successful chemical flood trials have been reported over the course of the last 40 years. Oil recovery rates can be enhanced by up to 40% OOIP through the addition of chemical cocktails into the injection water. The maximum achievable oil recovery occurs via the synergy between lowering interfacial tension between oil and water to liberate trapped oil droplets and enhancing homogeneous sweep efficiency with the use of viscosifying agents.

A variety of products are available with proven field track records. However, the uniqueness of every reservoir justifies the development of specific chemicals and methods in order to ensure maximum oil recovery at a certain cost target. Presently, surfactant flooding is still viewed as a costly extraction method. The absence of full field case studies makes the cost of forecasting full field surfactant flooding projects challenging, which leads to uncertainty and risk in the investment of the Opex-driven technology. Another area of focus for chemical flooding is effluent management. This occurs when the injected chemicals create emulsions between the residual oil and the injection water, resulting in treatment challenges that must be understood and included in the overall project economics.

Clariant Oil Services has developed offerings in the area of surfactants, co-solvents, and polymers for chemical flooding. End-to-End tailored services offered range from design of injection chemicals, injection, and effluent treatment in order to manage, mitigate, and eliminate potential issues.

Gabriela Alavarez JUrgenson & Stefan Stein - BASF

Among the various EOR technologies, cEOR, which uses polymers and surfactants, is one of the most attractive

because of the significant amount of incremental oil (up to 30 - 40% of OOIP) that could be produced. Brownfields could be revitalised, which might be more economical and less risky than exploration.

Despite its attractiveness, only polymer flooding (standard PAM) can be considered an established technology, applied on a commercial scale in several countries. The commercial use of EOR surfactants is still limited.

The implementation of a cEOR project is often a multi-year task, and a full understanding of the technical and economic viability is usually reached in a late stage; posing not only technical challenges but also financial risks.

So, how could this complexity and risk be handled to optimise the success rate of a cEOR project? A very important (and often overlooked) aspect when assessing a chemical EOR solution is the applicability (chemicals logistics and operational excellence) in the field beyond its performance.

A close collaboration between oil operators and a skillful chemical producer might be the key to successfully implementing cEOR, beyond field trials and mitigating the overall risk of these lengthy complex cEOR projects. One example is Daqing, China, where chemical plants are set-up near the field, raw materials are assured through long-term contracts and the chemical aspect is integrated in the project from an early stage.

A chemical supplier, experienced in polymer and surfactant production could make the difference between a successful or failed cEOR project; not only through its R&D expertise in developing innovative chemistries, but also in key aspects such as: Ì Raw materials selection: by considering costs, logistics

and long-term availability, especially potential requirements for high volumes. Backward integration in key raw materials or a strong purchasing position, are key to mitigating risk.

Ì Competence in scale-up manufacturing and quality control from lab to industrial scale production, while assuring product quality. Analytical support beyond routine quality control measurements can be given during site visits in the start-up phase of a chemical flood.

Ì Multi-purpose plants/diversity of production technologies: to enable initial commercial production of new chemicals at early stages of the projects, at a minimum level of financial investment.

Ì Financial strength: to face production capacity expansion investment that might be needed.

Ì Registration of new chemicals: this topic is especially relevant for the market introduction of new surfactants and must be addressed early as it is not only costly but also may take several months or even years.

Ì Supply chain: a strong global presence helps to set up cost-effective supply chain solutions even for oilfields in remote locations.

Ì Operational excellence: tailoring the products and their formulations to maximise value for EOR operations (handling, asset footprint, ambient conditions)

BASF SE - BASF SE site in Ludwigshafen, Germany.

Reprinted from January 2018 Oilfield Technology |

In order to make cEOR a reality, the industry needs to start by enhancing the way it collaborates and brings the best of the two worlds together, from the very beginning of a project.

Mehrdad Hesampour & Paula Henderson – Kemira

cEOR flooding uses polyacrylamide polymers such as Kemira’s KemSweep™ to improve oil recovery and

extend the life of field. Polymer migration from the injection well to the production wells may occur over field life and as residual polymer enters the production process, separation performance may be impacted. The reduction in separation efficiency can create further challenges where reinjection or disposal water specifications need to be met.

Chemical treatment of the produced water through the simultaneous precipitation of the of oil and polymer with inorganic/organic coagulants is often considered. However, this typically requires a high dosage of coagulants which can be uneconomical and generates a high volume of sticky sludge that has to be disposed of. These effects limit the wider use of coagulants in cEOR produced water treatment.

MaxXtract™ cEOR solutions are designed with the overall chemical treatment programme in mind. The company’s Advanced Water Treatment (AWT) group have evaluated KemSep® water clarifiers as an alternative to conventional coagulants to treat produced water. The objective of the programme was to remove residual polymer from the produced water and reduce the volume of sludge generated, improving separation efficiency and minimising overall treatment costs.

An experimental design method, RSM (response surface methodology) was applied to investigate the influence of different parameters including product dosage, product formulation, and pH on separation efficiency. The results showed higher HPAM removal efficiency at lower dosages with KemSep when benchmarked against inorganic coagulants. To remove 80% of polymer in water, 150 - 250 ppm KemSep was used compared to 350 - 450 ppm of the inorganic. The treatment resulted in less sludge (up to 25%) and reduced the floc stickiness significantly. The results were validated with actual field water containing an average of 150 ppm. In field water, the product demonstrated improved performance by reducing the concentration of polymer and lowering the water viscosity.

The selection of the correct water treatment package is a critical part of cEOR design. CO

2 flooding

Pramod D. Patil & Amit Katiyar –

The Dow Chemical company

Enhanced oil recovery utilising CO2 floods (CO2 EOR) has been commercially implemented in the United States since the early 1970s with about 114 active CO2 floods in the US, contributing to approximately 6% of domestic crude oil production (DOE/NETL-2014/1648). A major challenge in implementing CO2 EOR in the field has been mobility control of CO2. Water alternating gas strategies are typically implemented to provide some mobility control and to maintain field pressures to achieve a good CO2 flood

performance. The lower than expected overall oil recovery factor is primarily attributed to volumetric sweep inefficiencies,

typically the result of viscous fingering, reservoir heterogeneity and gravity segregation. A substantial volume of oil is left behind as a result of these effects on sweep.

There are many conformance control solutions proposed in the literature, including polymer gel treatments to block the high permeability channels in the reservoir, cementing of certain zones of the reservoir near the injection well bore to divert CO2, selective injectivity of CO2 in certain layer of reservoir via coiled tubing, and conformance control via foam assisted water-alternate-gas (FAWAG). The FAWAG approach has been performed in the industry since the early 1990s and there have been multiple successful field trials reported in the literature. Several CO2-foam pilots have been implemented, demonstrating successful implementation of the concept in the US particularly the Rock Creek Field, Rangely Weber Sand Unit, EVGSAU field, SACROC field and Salt Creek Wyoming field. All these field trials clearly demonstrated that the CO2 injectivity was reduced after foam treatment, indicating that the foam was stable in the reservoir during the period of evaluation and some of them also showed significant incremental oil from the foam pilot. Novel CO2 soluble surfactants offer advantages over the water-soluble surfactants for foaming application in terms of deeper foam propagation and low adsorption on the rock.

Alkaline technology

Anton Kaiser – Clariant

Alkaline Flooding technology has been in use for more than 50 years. Oil recovery can be enhanced by the addition of

alkaline to the injection water stream. The main recovery mechanism is driven by the alkaline deprotonation of the carboxylic acid functionalities in the crude oil, which ultimately activates the naturally occurring oil based surfactants. The surfactants are capable of lowering interfacial tension between crude oil and water, resulting in enhanced production of trapped oil. Especially in reservoirs containing crudes with a high total acid number, alkaline flooding can boost oil recovery rates up to 20% and represents a cost-effective method even in a low oil price environment. Alkaline flooding seems to be a simple flooding option, however, there are major concerns limiting the growth of this technology. One of the challenges in alkaline flooding is preventing and controlling the onset of carbonate scale precipitation at high pH due to the addition of an alkaline species such as sodium carbonate. Significant scale deposits may occur in the source water of the flood requiring the water to be softened to minimise carbonate self-scaling. Scale deposits may occur in the reservoir as the injected softened water contacts saline formation water and the high pH induces silicate scales. Such scale deposits can reduce flood efficiency and generate operational and safety problems. Another challenge in alkaline flooding is the formation of stable emulsions and macro-emulsions, which can be of high viscosity and are tough to break with conventional emulsion breakers in existing treatment facilities. In recent years, Clariant Oil Services has developed a products to manage scale and emulsions for alkaline flooding operations to minimise the risk while maximising asset integrity and oil production.

Waterflooding

Dr. Pramod D. Patil – The Dow Chemical Company

The strongly oil wet nature of shale and tight carbonate reservoirs leads to rapidly declining oil

rates during production. Carbonate reservoirs present several

| Reprinted from Oilfield Technology January 2018

characteristics, which lead to low oil production during waterflooding, including reservoir rock heterogeneity and

heterogeneous wettability. Chemical flooding with surfactants has been shown to enhance oil production from water flooding (frontal displacement method and ‘huff & puff’ method) due to spontaneous imbibition of water into oil-rich matrix, leading to oil displacement from tight pores and increased recovery. Success of such surfactant-based improved oil recovery technology depends heavily on developing the optimal surfactant formulation for the field conditions. Anionic, cationic and non-ionic surfactants have been proposed in the literature for wettability alteration. Surfactants are chosen based on the rock geochemistry, oil type, reservoir temperature and brine salinity.

Wettability alteration formulations are first developed and screened for aqueous stability and phase behaviour at reservoir conditions. Tailored hydrophobic surfaces are used to evaluate selected formulations for their potential to shift rock wettability through contact angle measurements. Water-oil interfacial tension behaviour is investigated to elucidate the mechanism of oil recovery. Adsorption behaviour of the chemicals is investigated on various rock minerals to identify formulations with minimal retention and component separation under static conditions. Finally, the candidates are comparatively tested for oil recovery performance in spontaneous imbibition experiments at simulated reservoir conditions. There are industry standard approaches to rigorously design optimal surfactant formulations for improving oil recovery. Surfactant formulations can be designed to provide high temperature stability (between 70 and 130˚C) and high salinity tolerance (>12% TDS). It is critical to have low adsorption (<0.5 mg/g of rock) of the surfactant for economical implementation of the technology.

Polymer technology

Gabriela Alavarez JUrgenson & Stefan Stein - BASF

For more than 20 years polymer flooding has been an established enhanced oil recovery (EOR)

technique, used in both mature and new reservoirs. Anionic polyacrylamides (PAM) have proven to be cost-efficient viscosifiers to reduce mobility of the displacement fluid thus increasing reservoir sweep efficiency.

Several full-scale polymer flooding projects were implemented, first in China, then in Canada, Middle East, India, and several other countries. Despite large success e.g. in Daqing, China, Pelikan Lake, Canada, or Mangala, India, the application of standard PAM is limited to mild field conditions with temperatures below 70˚C and salinities being less than 30 000 ppm. Innovative associative PAM polymers expand the operational window of PAM, to high salinity reservoirs; tailored versions of associative polymers can be applied even in reservoirs with temperatures up to 100˚C.

An key feature of hydrophobically modified, associative PAM polymers is that high in situ viscosities in the reservoir can be obtained at relatively low use levels. This characteristic property allows an efficient management of operational expenses in a polymer flood project. It is worth noting that a broad variety of associative polymers have been tested in the

past. Not all of them performed well and either injectivity

was poor or difficult-to-break emulsions were formed. Although the hydrophobic component makes only a very small part of the associative polymer, its chemical design is decisive for the performance of the resulting polymer.

BASF leveraged competencies in molecular design and formulation technology when developing the Aspiro® P6XXX range of associative polymers. In particular Aspiro P6631 has proven good injectivity at extreme salinities, its molecular design helps ensure thermal stability up to 95˚C even under saline conditions and produced fluids were of no issue. In summary, a close cooperation between the experts of the operator with those of the chemical partner from an early stage on is vital to minimise the risk of a cEOR operation in any phase of the project.

Susanna Toivonen & Paula Henderson – Kemira

Chemical enhanced oil recovery (cEOR) operations are used in mature oilfields to improve the recovery factor

and extend field life. Polymer Flooding is a widely used cEOR method that injects water containing high molecular weight polyacrylamides such as Kemira’s KemSweep™ to improve sweep efficiency. The polymer increases the viscosity of the injection water, improving the mobility ratio between the water and the hydrocarbons trapped in the reservoir.

If polymer migrates to a producing well in the water phase, this can impact separation efficiency and overall field production. The fluid viscosity changes can affect process level controllers and interaction with production chemicals can affect phase separation. Plans for breakthrough should be incorporated into cEOR chemical management programmes including the early detection of the polymer , allowing the operator to monitor, control and mitigate the effects before they become problematic.

A time resolved fluorescence (TRF) technique is being used by Kemira to detect residual cEOR polyacrylamide in produced water on-site. The KemConnect™ EOR technology uses TRF in conjunction with a europium complex and chemical modulators to detect ppm levels in the water. Laboratory and field trials are demonstrating good correlation between KemConnect EOR and conventional methods. The real time measurement enables operators to make informed decisions based on the early warning of polymer breakthrough. Sample analysis is rapid and simple allowing for minimal operator competence and the onsite measurement eliminates the costs and time associated with returning samples onshore for analysis.

The early detection of KemSweep polymers in produced water using Kemira KemConnect EOR is improving the overall efficiency of the cEOR chemical programme and ultimately the field recovery factor.

Anton Kasier – Clariant

Polymer flooding is the most common chemical flooding method and has been successfully applied all

over the world for over 50 years. The economics are now well understood, and as a result, polymer flooding is economically successful for heavy oil production even at <US$50 oil price scenarios. Oil recovery rates can be enhanced by up to 12%

Reprinted from January 2018 Oilfield Technology |

original oil in place (OOIP) by the addition of polymer to the injection water stream. The main recovery mechanism involves a viscosity increase of injection water resulting in viscous crossflow and subsequently improved sweep efficiency of upswept areas of the reservoir. Polyacrylamides are the dominating product class as they are suitable polymers for a variety of reservoir conditions and water chemistries and readily available in the marketplace. Main challenges that affect the efficiency of a polymer flood are related to the water quality. The water quality influences the polymer hydration mechanism, which can cause loss of injectivity if not managed and maintained properly. In addition, it can be observed that the polyacrylamide polymers can stabilise oil-in-water emulsions creating more severe water treatment issues that need to be managed.

More recently, there has been a discussion involving biopolymers as a potential substitute for synthetic polymers in reservoir environments with high temperature and high salinity where the use of polyacrylamides is not cost-effective. The non-ionic character of the polysaccharide biopolymers eliminates the severe oil-in-water emulsion issues, however, there are concerns about the long-term stability of these polymers under reservoir conditions.

In recent years, Clariant Oil Services has focused on the development of efficient water treatment chemicals for polymer floods and has started to investigate the potential of biopolymer flooding in high temperature, high salinity reservoirs.

Heavy oil recovery

Biplab Mukherjee - The Dow Chemical Company

Heavy oil and bitumen are the most abundant but difficult to recover crude oil sources. With viscosities

in the thousands to over 1 million centipoise at reservoir temperatures, these oils need to be heated to be produced. Steam processes involving continuous and cyclic injections and technologies such as conventional steam floods and steam-assisted gravity drainage have been utilised for many years to lower the viscosity of these oils so that they can flow to producing wells. While steam-based technologies are very effective at recovering heavy oil, they are still not efficient when measured by their steam-to-oil ratio. Viscous fingering, gravity override and reservoir heterogeneities can result in premature steam breakthrough in production wells.

To overcome these issues, steam foam has long been considered to control steam conformance and mobility in field. The first known field application of foam in steam floods took place in the mid-1970s and was followed by more in the 1980s and 1990s, mostly in California. The application involved injection of surfactant with steam and a non-condensable gas to generate foam in-situ. Foam can redirect steam, increase its apparent viscosity and reduce steam channelling. Early tests struggled with surfactant stability at high temperatures, however, novel surfactants with stability up to 250˚C have since been developed. The economic success of a steam foam

field application will depend on the choice of the chemical formulation and the injection strategy implemented in

the field. A detailed framework of laboratory experiments coupled with reservoir simulation tools are utilised to identify optimal formulations and design for the field pilot. Surfactant formulations are first developed and screened for phase behaviour, thermal stability and adsorption propensity. Foaming efficiencies in bulk and porous media, in presence and absence of oil, are then validated. Finally, oil recovery experiments using a core flood apparatus are performed to understand the impact of foam on volumetric sweep efficiency and in turn, oil recovery. It is imperative to conduct testing using reservoir matrix and under reservoir conditions. The lab results generated are then used to develop foam models and strategise scale-up options using reservoir-specific models and conditions.

Multifunctional IOR fluids

Mehrdad Hesampour & Paula Henderson – Kemira

The recent downturn in the oil and gas market provided an opening for expanded use of Improved Oil Recovery (IOR) chemical solutions. A new level of multifunctioning IOR fluids provide operators with an opportunity to increase production efficiency without the expense of EOR.

KemRelease reduces the surface and interfacial tension at the oil and water interface, thereby reducing capillary pressure and, in turn, aids spontaneous imbibition which mobilises and disperses accumulated deposits . In addition, optimising the droplet size allows for ‘deeper’ penetration, accessing trapped reserves in lower permeability zones. Combined, these functions improve well performance and total load recovery.

Crude oil and core samples collected from fields in Canada and the United States were used to evaluate KemRelease under lab conditions. Oil recovery sand pack flow tests compared products with differing API petroleum gravity, metal content, and asphaltene fractions. Dosages and products were recommended for field trial based on the total oil recovery compared to traditional IOR fluid systems with field trials mimicking much of the lab result.

In the field, operators have shown improved performance in production, injection, and disposal wells at low dosages: Ì A mature production well experiencing natural decline. The

objective was to improve and maintain production over an extended period of time post treatment. KemRelease was applied directly to the well at aproximately 2 gpt (gallons per thousand). Production increased by >60% and was maintained for over 12 weeks.

Ì Waterflood injector wells experiencing reduced injection pressures. KemRelease was applied directly into the injection water at 2 gpt with the aim of reducing the pressures and increasing water flow rates ensuring peak efficiency and regulatory compliance. In addition, the higher water injection rates resulted in incremental oil production.

Ì A wastewater disposal well with declining injectivity,restricting overall field production. Monthly acid treatments were used to clean the well with reducing levels of success. KemRelease was proposed as an alternative and applied to the well as a batch treatment. Injectivity to the well was improved and full field production was restored. In additon, treatment frequency has been reduced to every 6 months, reducing total operating costs.

Form No. 812-00488