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Practical Chemical Formulation Design – Time to Break Away from Micellar Polymer Floods, Again
Abstract
With a resurgence of chemical EOR opportunities throughout the world, high concentration surfactant design has re-emerged its uneconomic face. High concentration surfactant formulation is the micellar polymer design from the past that produced high oil recoveries in the lab but were uneconomic in the field. Formulation designs must consider factors beyond simply oil recovery for economic success and to minimize production issues in the field.
Analysis and comparison of micellar polymer design projects from the 1970-1980s to current SP/ASP formulation designs are discussed. A simple formulation cost calculator is showcased, costs of all formulations are presented, and price per incremental barrel produced (chemical cost only) are shown assuming a 0.1 PV of incremental recovery.
Analysis concludes the following:
Micellar polymer floods were phased out because they were uneconomic. Key reasons are high cost of surfactant and emulsion problems faced when produced surfactant concentration exceed a certain threshold resulting in either greater production cost or disposal of produced oil in the form an unbreakable emulsion. Alkali can improve economics as a low-cost commodity product that can be used to reduce surfactant concentration required to attain high oil recoveries. Alkali is an order of magnitude lower cost per pound than the typical surfactant and can be used as an enhancing agent to improve the performance of other injected chemicals. Alkali is not a "silver bullet" that will save economics, and adds challenges and cost for water softening, which can be economically detrimental to field projects. Many high concentration surfactant formulation floods are being re-introduced to the industry. Not only are these designs un-economic but include multiple chemicals that add complexity and cost to the facilities and difficulty for facility personnel. A formulation that requires more than 50/bbl oil. Key differences between laboratory results and field implementation results are discussed. Geologic uncertainty is addressed since it is the greatest challenge to field economic success.
The industry is taking steps back to an uneconomic time of chemical EOR by obscuring the difference between designs meant to increase reserves (economic oil) versus those that serve an academic or research purpose. Operators are unwittingly paying the price to advance the science of chemical EOR when service companies provide formulations that are not economic. This paper is meant to remind the industry that high concentration surfactant formulations never were economic and certainly will not be economic in today's price environment.
... Therefore, impractical formulations are developed due to high chemical concentrations. 32 In view of this, this study focuses on evaluating the oil recovery potential of ternary combinations of alternative chemical agents for ASP flooding. A simplified cost analysis was included to evaluate the feasibility of deploying the proposed formulations in field applications. ...
... Estimation of the chemical cost of injected barrel of solution is performed in three steps. 32,42 First, the chemical cost per barrel injected is calculated using eq 4 ...
... As mentioned earlier, the design of novel chemical formulations for EOR without consideration of the cost implications leads to the development of impractical formulations. 32 In view of this, a simple UTC estimation was made for the various ASP formulations to give insights into their practicability. The UTC does not incorporate the price of oil, but a comparison between the unit cost and price of oil could give a fair idea on the profitability of a project. ...
This study explores alternative chemical agents to enhance oil recovery in sandstone and carbonate reservoirs, aiming to address limitations in alkali–surfactant–polymer (ASP) flooding. Existing ASP methods face technical and environmental challenges, prompting research into alternative chemical agents. However, there are limited field deployments of these alternative chemical agents due to high costs, and ternary combinations of these agents remain unexplored. The study investigates a combination of organic alkali, amino acid-based surfactant/surface-active ionic liquid, and biopolymer. Comparative analysis with conventional ASP formulations reveals promising results. Organic alkali and biopolymer combination mitigates the adverse effects of inorganic alkalis on partially hydrolyzed polyacrylamide, enhancing the oil recovery potential. A unit technical cost (UTC) calculation showed that despite higher chemical costs per incremental barrel of oil, the alternative ASP formulations demonstrate comparable costs due to reduced facility cost. Cost-effectiveness will improve with incorporation of factors such as environmental friendliness and reduced preflush requirements. Mass production of these agents could further enhance the economic feasibility. Therefore, this study reveals that careful cost-benefit analysis, the development of low-concentration formulations, and mass production of these chemical agents could facilitate the implementation of these alternatives, ensuring compliance with environmental regulations and enabling ASP flooding in challenging reservoir conditions.
... Nonetheless, field-scale applications of combined chemical agents have remained the same as polymer flooding applications (Delamaide, 2020). Combining chemical agents involves multiple chemistries and complex chemical mechanisms, challenging the qualification process for field-scale applications due to the significantly higher costs of injected chemical agents (Dean et al., 2020). ...
... The main challenge for AP flooding is the scale deposition in the production wells (Delamaide et al., 2014;Hunter et al., 2013;Volokitin et al., 2018); hence, scale mitigation steps need to be addressed in advance (Hunter et al., 2013;Karazincir et al., 2011). Further challenges are the higher costs of the chemicals to ensure the project is economically viable (Dean et al., 2020;Dijk et al., 2010;Flaaten et al., 2009;Kaiser et al., 2015), treatment of the back-produced fluids (emulsions) at the production wells and chemicals adsorption at the reservoir rock surface while flowing through porous media. ...
We investigate into optimizing alkali-polymer (AP) flooding in brownfields, focusing on the critical initiation of fluid-fluid and rock-fluid interactions for enhanced oil recovery. A detailed screening of the AP cocktail is vital for cost efficiency and for maximising the efficacy of the chemical slug. Our research outlines industry-standard laboratory methods to screen chemicals for AP pilots and field implementation, using the example of an AP pilot in Austria.
The key to our screening process is fluid characterisation, enabling the selection of chemical concentrations suitable for the targeted interactions. Crucial to the fluid-fluid interaction assessment is the stability of produced emulsion, interfacial tension (IFT) measurements, and comprehensive fluid rheology analysis. For probing rock-fluid interactions, we employed both single-phase and two-phase core floods, which are fundamental for understanding the dynamics within the heterogeneous reservoir. Core floods were conducted using low permeability (perm) and high perm core plugs to capture the breadth of reservoir conditions. This approach allowed for a detailed evaluation of displacement efficiency and potential injectivity limitations.
In a novel extension of our study, we simulated the in-situ ageing of the AP slug, considering its increased anionicity. This involved conducting two-phase core floods with aged chemicals, providing unique insights into the temporal evolution of chemical efficacy and interaction. Our findings revealed a specific alkali concentration of 7,500 ppm as optimal for the AP slug—the interaction between the alkali-polymer and high Total Acid Number (TAN) dead oil produced emulsions. A noteworthy observation was the micro-instability of these emulsions, evidenced by changes in viscosity and volume over time. Regarding injectivity, single-phase core floods indicated that the vendor-B AP slug (PolymerB) outperformed the vendor-A AP slug (PolymerA), although challenges in mechanical stability were observed. Interestingly, the additional recovery factors (RF) were higher for PolymerA-based AP slugs than PolymerB-based APs from high perm core plugs. A similar trend for the additional RF for low perm plugs was observed. Furthermore, a consistent trend in additional oil recovery was observed for both aged and un-aged chemical slugs through high perm core plugs. This led to the conclusion that in-situ ageing of the AP slug could be a viable strategy for reducing costs (low concentrations) while enhancing injectivity.
Overall, we provided valuable insights into the in-situ stability of the AP slug derived from fluid-fluid optimisation and rock-fluid interactions. It also underscores the significance of in-situ stability as it directly impacts injectivity and sweep efficiency in porous media. The findings presented are crucial for refining the screening criteria for the pilot project. Moreover, ensuring a more effective and economically enhanced brownfield oil recovery process.
... Static tests involve rock powder, while in dynamic tests, a rock plug (by core flooding) is used to investigate the surfactant adsorption for a surfactant under specific conditions. Surfactants are the most expensive chemicals used in a chemical EOR project, often costing up to five times more than other assisting chemicals like alkalis (Dean et al., 2020;Sheng, 2010). In a standard flood design, surfactants may cost between $1.45-$4.50 ...
... In general, compensating for just a 30% loss of surfactants can increase the cost of an ASP chemical EOR injection process using surfactant (which costs $1.65 per pound) from $2.315 per barrel to $2.66 per barrel, resulting in a 15% increase. For a project requiring a daily injection of 10,000 barrels, this cost would increase from $23,150 to $26,600 per day (Dean et al., 2020). ...
In mature reservoirs, over 60% of oil remains trapped after waterflooding and can only be recovered using
enhanced oil recovery (EOR) methods, including chemical EOR. Surfactants are one of the main components of
the chemical formulations used for chemical enhanced oil recovery (CEOR) processes. Despite the great success
in developing superior chemistries of surfactants for high efficiency in even harsh conditions, the adsorption of
surfactants is still a significant challenge the industry faces today. Loss of surfactants leads to inadequate performance and poor oil recovery efficiency; consequently, the management and control of surfactant retention are
highly researched in academia and industry. Surfactant adsorption follows several mechanisms, and understanding these mechanisms is key to effectively controlling their retention in CEOR processes. This review focuses on the various mechanisms of surfactant adsorption onto different rock types and minerals encountered in
reservoirs. The effect of several parameters on adsorption, such as surfactant structure, temperature, brine
composition, and surface properties, is discussed in detail. As CEOR requires combinations of surfactants in
applications, the adsorption behavior of surfactant mixtures is also well elaborated. In addition, the review
covers recent trends in mitigating surfactant adsorption, such as using sacrificial agents, alkalis, low-salinity
brine, nanoparticles, and ionic liquids. Furthermore, schemes for adsorption control, such as low salinity preflush and negative salinity gradient, are discussed. Overall, this review aims to provide a comprehensive understanding of surfactant adsorption behavior and mitigation techniques to improve the efficiency of CEOR
processes.
... However, the number of large-scale applications has not increased at the same pace as polymer flooding applications without using alkali or alkali and surfactants (Delamaide 2020). Hereby, the complex methods that involve multiple chemistries can be challenging to qualify as a suitable business case owing to the high costs of the injection chemicals (Dean et al. 2020). ...
... The economics of chemical EOR projects are challenging owing to the costs of the injected chemicals (e.g., Dean et al. 2020). Chemical costs for AP or alkali-surfactant-polymer projects are substantially increased over polymer only. ...
Alkali polymer (AP) flooding is a promising enhanced oil recovery (EOR) method to increase oil recovery from reactive oils. It is essential to carefully select the alkali and polymer type and concentration to optimize incremental oil recovery. In addition to the conventional laboratory tests for polymer flooding, the effects of the high pH on the polymer and its evolving properties over time need to be investigated. Consideration of near-wellbore and reservoir effects is key in designing the process. We are showing how understanding and taking advantage of the polymer performance in a high pH environment allow for cost reduction and increase in injectivity and incremental oil recovery for AP projects.
The polymer performance was evaluated for AP flooding of the Matzen field (Austria). Evaluations included changes in polymer rheology during aging at high pH conditions, phase behavior tests, and single-/two-phase corefloods with aged and nonaged polymer solutions. In addition, adsorption of the aged polymer and interfacial tension (IFT) were measured. The aging was studied in anaerobic conditions at reservoir temperature and through an accelerated method at elevated temperatures. The accelerated method developed earlier for neutral pH range provides a possibility to run aging at elevated temperatures in a short time frame and transfer the data to reservoir temperature to give information on the long-term performance. The transfer takes place through a conversion factor derived from the first-order kinetics of acrylamide hydrolysis in pH 6–8. In the present work, the applicability of the accelerated method is evaluated for elevated pH by determining the degree of polymer hydrolysis over time via nuclear magnetic resonance and linking it to viscosity performance at various temperatures.
The AP conditions in the Matzen AP flooding project (pH > 10) lead to an increased initial rate of polymer hydrolysis of the tested hydrolyzed polyacrylamide (HPAM) by a factor of 100 compared to hydrolysis at a neutral pH level. This resulted in a rapid increase in a polymer solution viscosity of 160% compared with initial conditions within days at a reservoir temperature of 49°C, after which the viscosity leveled off. Accelerated aging experiments at higher temperatures predict long-term stability of the increased viscosity level for several years. Single-phase injection test in a representative core confirmed the performance of the aged solution compared to a nonaged solution at the same polymer concentration. The retention of polymers is reduced in AP conditions compared with traditional neutral pH conditions, 19 vs. 48 µg/g in the static adsorption test, respectively. Two-phase coreflood tests showed increased polymer viscosity at reservoir conditions. The displacement efficiency of the aged and nonaged polymer solution was similar, confirming the potential for cost savings using lower polymer concentration. This is leading to an improved injectivity and makes use of the increased polymer viscosity down in the reservoir through hydrolysis.
The current work combines multiple aspects that should be considered in the proper planning of AP projects—not only improvements in polymer viscosity performance due to water softening but also long-term effects due to increased pH. Additionally, these aspects are combined with changes in adsorption properties. The results show that the design of AP projects will benefit from the holistic approach and understanding the changes in polymer rheology with time. The costs of AP projects can be reduced owing to the lower required polymer concentrations for the same displacement efficiency and reduced retention of polymer. An efficient design of AP projects takes good injectivity of nonaged polymers and the aging of the polymer solutions in alkali into account. Overall, we aim to reduce the polymer concentration—which is a key cost driver—compared with a nonaged application. We show that for AP effects, these effects should be evaluated to improve the economics.
... Feasibility study on ASP flooding projects. According to Dean et al. [108], the development of ASP formulations and their implementation in the field/pilot units has two main objectives: 1) academic applications aiming at a better understanding of the mechanism, and 2) practical applications pursuing economic benefits through the production of incremental oil. Based on a number of publications that are describing any ASP technology implementation at a pilot scale, it is observed that the authors refrain from providing the economic performance of any given project. ...
Polymer flooding is a promising and effective chemical Enhanced Oil Recovery (cEOR) technology. Polymer flooding is especially cost-effective, whereas other chemical flooding methods, such as Alkaline Surfactant Polymer (ASP), are not profitable and cause serious on-site problems (scaling, uptime decrease, injectivity is-sue, hard-breaking emulsions). Recent papers in the literature mention ~30 field polymer floods. Most of them reported technical success. Although, polymer flooding has been applied ~60 years, itstill requires fur-ther investigation to provide improvements. Thus, this paper describes important aspects and performances during for polymer flooding based on a review of recent projects, combined with the Kalamkas field experi-ence. A comprehensive literature review examines the applicability range in temperature, brine salinity, water source selection, oil properties, formation type, and permeability. Water source selection has an essential role during pilot/field project design and is one of the most responsible technical and economic success decisions. Polymer slug design has been extensively analyzed especially for the high viscosity oil fields, the selected oil/polymer viscosity ratio was usually much less than one. We placed significant emphasis on clarifying ob-served high polymer injectivities. We conducted feasibility studies of some reported ASP floods to clarify that this technology is not profitable at current oil prices. Also, we performed TAN analysis of three Kazakh-stan oil fields for screening of ASP flood.
... There are several challenges that need to be considered for the injection of multicomponents in chemical floods: The selection of the chemical agents needs to be robust to mobilize oil at reservoir conditions (e.g., Hirasaki et al. 2011;Stoll and Finol 2011;Fortenberry et al. 2015;Panthi et al. 2016), scale deposition in the production wells need to be addressed (e.g., Hunter et al. 2013;Delamaide et al. 2014;Volokitin et al. 2018), potential chromatography effects have to be considered (e.g., Van der Lee and Van den Pol 2015; Levitt et al. 2015;Lüftenegger and Clemens 2017), the surface facilities need to be able to handle the back produced fluids (e.g., Weatherill 2009;Alwi et al. 2014;Kaiser et al. 2015), and the chemical agents need to be at sufficiently low costs to ensure an economically viable project (e.g., Flaaten et al. 2009;Dean et al. 2020). ...
Alkali/polymer (AP) flooding of high-TAN oil is a promising enhanced oil recovery (EOR) method. Phase tests reveal that the generated emulsions are thermodynamically unstable macroemulsions rather than Winsor-type emulsions as observed in alkali/surfactant (AS) systems. We investigated the effect of gas on the phase behavior and displacement efficiency of AS systems. The reason is that the impact of gas in solution on the displacement efficiency in alkali projects is significant, neglecting the gas effects underestimates the incremental recovery factor by >15%.
Experiments and analysis were performed to investigate the effects of alkali injection into a live and dead high-TAN oil. Viscosity measurements using a capillary rheometer and oscillating u-tube were done to ensure the same viscosity of the dead oil (adding cyclohexane) to live oil. Alkali phase behavior scans were used to determine the amount of emulsions formed initially and over time. The structure and characteristics of the emulsions were investigated using a high-resolution microscope. Micromodel experiments (dead oil only) were performed to elucidate the displacement efficiency effects on pore scale, while flooding experiments showed the displacement efficiency on core scale.
Phase experiments showed that initially, a substantial amount of emulsions is formed. The volume of the emulsion is changing over time reaching zero for the live and dead oil. The microscope pictures show that in the initial stage, a “middle phase” macroemulsion is present. With time, the middle phase disappears supporting the results of thermodynamically unstable emulsions seen in the phase experiments. Micromodels show that oil is mobilized by AP injection on a local scale by elongating ganglia and reducing the size of trapped oil and only a limited amount of macroemulsions is formed at the oil/alkali/water interface. The increased oil recovery is thus an effect of the local capillary number and mobilization of ganglia. Here, no stable three-phase system consisting of oil/microemulsion/water as in AS system is generated. Live oil AP corefloods lead to recovery factors of 95% compared with 74% for dead oil. The gas in solution improves the local pore scale sweep efficiency and needs to be included in the evaluation of AP flooding to ensure that incremental oil production is not underestimated for high TAN number oils. The main findings are as follows:
Phase experiments of alkali with dead and live high TAN oil show that initially a large amount of emulsions is generated. However, these emulsions are thermodynamically unstable macroemulsions. Micromodel investigations show that the local pore scale displacement efficiency is improved by injecting AP solutions. Gas in solution is substantially improving the local displacement efficiency and needs to be included to correctly determine incremental oil production from AP flooding.
Alkali-Polymer (AP) flooding is currently piloted as an Enhanced Oil Recovery (EOR) method in Matzen field. Assessing the remaining oil saturation (Sor) both before and after AP is essential for determining the potential gain and effectiveness of this EOR method. We present the application of Partitioning Inter-Well Tracer Test (PITT) in Matzen field to estimate the remaining oil saturation. Additionally, the validation of the PITT results through a series of core flood experiments is discussed.
The PITT deployment involves simultaneous injection of one ideal water-tracer together with a partitioning-tracer. While the ideal water-tracer only follows the water phase, the partitioning-tracer partitions into both oil and water phases at a predetermined ratio (K-value). Analyzing the time delay between the tracers enables the estimation of Sor between wells. Two PITTs were carried out in 8.TH and 16.TH reservoir of the Matzen field before AP pilot. A series of core flood experiments (with PITTs) were also conducted before and after AP to compare the estimated Sor from the PITT with the measured Sor from the core flood.
For all the projects, the K-value of the selected partitioning tracer was measured under reservoir condition by using representative oil and water fluids. A proper sampling regime were designed based on the estimated tracer arrivals and the collected samples were analyzed to measure the concentration of both ideal and partitioning tracers for Sor interpretation. The results of the core flood experiments show a good agreement between the measured Sor from the core and the estimated Sor from the PITT for both pre- and post-AP stages. The consistent result further validates the application of PITT method in Matzen. Additionally, the field PITT results provided an estimation of the remaining oil saturation between the well pairs, helping to assess the potential gain from AP and economic feasibility of the method. Furthermore, a comparison between the results of the ideal water tracer with the previous inter-well water tracer tests during the water and polymer floods improved the reservoir understand about the changes in flow paths and swept volume during each displacement method.
The study enhances the validation and application of the PITT method, particularly for estimating remaining oil saturation between injectors and producers in mature fields. The results are crucial for EOR methods, particularly in addressing AP flooding. The Matzen field showed higher residual oil saturation, reducing economic risk, and improving EOR opportunities.
Alkali Polymer (AP) flooding is a promising Enhanced Oil Recovery (EOR) method to increase oil recovery from reactive oils. It is essential to carefully select the alkali and polymer type and concentration to optimize incremental oil recovery. In addition to the conventional laboratory tests for polymer flooding, the effects of the high pH on the polymer and its evolving properties over time need to be investigated. Consideration of near-wellbore and reservoir effects is a key in designing the process. We are showing how understanding and taking advantage of the polymer performance in a high pH environment allows to reduce costs, increase injectivity and incremental oil recovery for AP projects.
The polymer performance was evaluated for AP flooding of the Matzen field (Austria). Evaluations included changes in polymer rheology during aging at high pH conditions, phase behavior tests, and single/two-phase core floods with aged and non-aged polymer solutions. In addition, adsorption of the aged polymer and interfacial tension was measured. The aging was studied in anaerobic conditions at reservoir temperature and through an accelerated method at elevated temperature. The degree of polymer hydrolysis over time was determined via NMR and linked to viscosity performance.
The AP conditions in the Matzen AP flooding project (pH > 10) lead to an increased initial rate of polymer hydrolysis of the tested HPAM by a factor of 100 compared to hydrolysis at a neutral pH level. This resulted in a rapid increase in polymer solution viscosity of 160 % compared with initial conditions within days at reservoir temperature of 49 °C, after which the increase leveled off. Accelerated aging experiments at higher temperature predict long-term stability of the increased viscosity level for several years. Single-phase injection test in representative core confirmed the performance of the aged solution compared to a non-aged solution at the same polymer concentration. The retention of polymers is reduced in AP conditions compared with traditional neutral pH conditions. Two-phase core flood tests showed the increased polymer viscosity at reservoir conditions. The displacement efficiency of the aged and non-aged polymer solution was similar confirming the potential for cost savings using lower polymer concentration and making use of the increased polymer viscosity owing to hydrolysis.
The results show that the design of alkali polymer projects needs to take the changing polymer rheology with time into account. The costs of alkali polymer projects can be reduced owing to the lower required polymer concentrations for the same displacement efficiency and reduced retention of polymer. An efficient design of alkali polymer projects takes good injectivity of non-aged polymers and the aging of the polymer solutions in alkali into account.
Objectives/Scope
This paper demonstrates the potential of alkali surfactant polymer (ASP) within the Central California Oil Fields, which covers Kern, Tulare, and Fresno Counties. Typically, enhanced oil recovery (EOR) screening is performed across a wide range of processes and is applied to individual reservoirs on a case-by-case basis. This study focuses on a single EOR ASP process across multiple fields and pools specific to Central California.
Methods, Procedures, Process
Reservoir characteristics and Canadian analogs were used to screen for the ASP potential in Central California. Reservoir characteristics data were digitized and taken from what is locally known as the "Gold Book" of Central California (Volume 1, 1998, published by the California Division of Oil & Gas, subsequently renamed CalGEM (California Geologic Energy Management Division). The book contains data for 137 oil and gas fields with 605 pools. Various ASP screening methods and analogs were applied to this dataset. Candidates were then ranked for detailed future analyses.
Results, Observations, and Conclusions
Screening resulted in the identification of 166 of the 605 pools that passed the Taber and Delamaide screening methods and compared well to analogous Canadian successful commercial ASP projects. Fields were then ranked according to various reservoir properties, size of potential recovery, and location (access to chemicals). The top five, with supporting data, are shown. Graphs and maps were used to illustrate the top-ranked pools along with their locations.
Novel/Additive Information
The results of initial screening and ranking of Central Californian pools illustrate its potential for ASP applications. Although there have been some ASP studies and pilots conducted in the San Joaquin Basin oil fields, the results are not in the public sphere. Some data have been published by CalGEM on two successful ASP pilots in the Shallow Oil Zone of the Elk Hills Oil Field, California. This study was performed to show possible application of ASP in 166 pools within the 605 pools in the San Joaquin Basin by using publicly available information to identify oil fields that warrant further detailed investigations of oil chemistry, core analysis, reservoir simulation, risk assessments, and in-depth economic studies.
The first surfactant-based pilots can be traced back to the 1960s and since then almost a hundred field tests have taken place. Interestingly, almost half of these pilots have used an alkali (ASP) and the other half has not (SP). This reflects the current status of the industry which is divided along the same lines and over the same question: do surfactant-based processes require alkali or not? This paper proposes to address this question by providing explanations and discussing case studies.
The paper will start by reminding the reader of the role of both surfactant and alkali and will review the pros and cons of alkali in terms of formulation performances, adsorption but also surface facilities and logistics. Several cases studies (lab and field) will be discussed to show when alkali can and cannot be used, and what solutions are available as alternatives to the use of alkali.
Although alkali allows reducing both surfactant concentration and adsorption, it can also cause severe scaling and requires additional facilities including water softening; in addition, the large volumes of alkali required can cause logistical challenges. On the other hand, the main challenges of formulations without alkali is finding surfactants that can develop a low enough Interfacial Tension and low adsorption, or to find an acceptable adsorption mitigation strategy such as salinity gradient or adsorption inhibitors. In the early years of SP projects, very high surfactant concentrations were used (micellar process) and the process was not economic; as a result, alkali was seen as the only realistic solution. This appears to no longer be the case due to the developments of new surfactants. Although most projects in recent years have favoured the use of alkali, it seems that a trend towards SP is growing, with recent field projects in Kuwait, Oman, China and Russia favouring the SP solution.
This paper will provide a discussion on the pros and cons of the use of alkali in surfactant-based processes. It will show that although using alkali has been a standard for many years it also entails severe surface issues such as scaling and requires additional capital for water softening and logistics. More importantly, recent developments in surfactants now seem to provide alkali-free solutions that can compete in terms of formulation performances. This now needs to be confirmed in the field.
The Sabriyah Upper Burgan is a major oil reservoir in North Kuwait with high oil saturation and is currently considered for mobility control via polymer flooding. Although there is high confidence in the selected technology, there are technological and geologic challenges that must be understood to transition towards phased commercial field development. Engineering and geologic screening suggested that chemical flood technologies were superior to either miscible gas or waterflood technologies. Of the chemical flood technologies, mobility control flooding was considered the best choice due to available water ion composition and total dissolved solids (TDS). Evaluation of operational and economic considerations were instrumental in recommending mobility control polymer flooding for pilot testing. Laboratory selected acceptable polymer for use with coreflood incremental oil recovery being up to 9% OOIP. Numerical simulation recommended two commercial size pilots, a 3-pattern and a 5-pattern of irregular five spots, with forecast incremental oil recovery factors of 5.6% OOIP over waterflood. Geologic uncertainty is the greatest challenge in the oil and gas industry, which is exacerbated with any EOR project. Screening of the Upper Burgan reservoirs indicates that UB4 channel sands are the best candidates for EOR technologies. Reservoir quality is excellent and there is sufficient reservoir volume in the northwest quadrant of the field to justify not only a pilot but also future expansion. There is a limited edge water drive of unknown strength that will need to be assessed. The channel facies sandstones have porosities of +25%, permeabilities in the Darcy range, and initial oil saturations of +90%. Pore volume (PV) of the two recommended pilot varies from 29 to 45 million barrels. A total of 0.7 PV of polymer is expected to be injected in 5.6 and 7.9 years for the 3-pattern pilot and the 5-pattern pilot, respectively, with a water drive flush to follow for an additional 5 to 7 years. Incremental cost per incremental barrel of oil of a mobility control polymer flood which includes OPEX and CAPEX costs is $20 (USD). This paper evaluates the (commercial size) pilot design and addresses field development uncertainties.
The West Salym oil field is located in the West Siberian oil province (Russia). Its reservoir conditions are typical for the region: sandstone formation with temperatures as high as 83 °C, low crude oil viscosities of about 2 cP, and brine salinities in the range of 14,000-16,000 ppm. The field is waterflooded to maintain the reservoir pressure close to its initial level and to optimize oil recovery. Oil production from West Salym peaked in 2011 and since declined with increasing water cuts. The expected ultimate recovery factor due to waterflood, as reported in the field development plan, is between 35-40%. This recovery will be achieved through an evergreen waterflood optimization process consisting of infill/side-track drilling campaigns, pattern rebalancing, well workovers, etc.
To increase the recovery factor, a tertiary oil recovery technique called Alkaline-Surfactant-Polymer (ASP) flooding was selected. Earlier studies indicated a potential of 15-20% incremental oil recovery due to ASP injection. Laboratory studies were started in 2008 with the surfactant/polymer screening and selection followed by core flooding experiments. In 2009, a successful single-well chemical tracer test was conducted to prove the efficiency of the developed ASP formulation at field conditions. In 2012 a final investment decision was taken to conduct a multi-well pilot to demonstrate oil recovery potential of the ASP flooding process and to collect sufficient information for decisions on subsequent commercial projects. Pilot operation was started in February 2016 with the start-up of the ASP mixing and injection plant. Active injection was completed in January 2018 and the end of production is expected in Q1 2018.
The paper focuses on the pilot performance results, principal operational challenges and strategies to overcome them. The ASP injection resulted in the mobilization of a significant volume of oil in the confined 5-spot pattern. The water cut dropped from 98% prior to ASP injection to 88% due to oil mobilization by the ASP solution. The estimated incremental recovery is above 16% of the pilot STOIIP. Together with the mobilized oil a larger than predicted concentration of injected chemicals has been back-produced through the pilot producing wells. This has led to production issues, most notably failure of electric submersible pumps in the pilot producing wells due to carbonate scale and production of stable oil-water emulsions. Both issues required the use of methodologies and chemicals that were novel for West Salym field. The laboratory data and field observations collected during the pilot operation phase are presented to support our conclusions. Finally, actual vs. expected results of the ASP pilot and remaining uncertainties to further develop the chemical flooding technology are discussed.
In the West Salym field, a mature waterflood is ongoing with increasing water cuts and declining oil production. To counter the decline a tertiary oil recovery technique called Alkaline-Surfactant-Polymer (ASP) flooding was selected. Earlier studies indicated 15-20% potential incremental oil recovery due to ASP injection. An injection/production pilot to demonstrate oil recovery potential of the ASP flooding and collect information to decide on the subsequent commercial ASP projects was started with the preflush injection in February 2016. ASP injection started in July 2016 and was followed by the injection of polymer slug in February 2017. By the end of 2017 polymer injection is to be followed by the injection of postflush till the end of the project.
As the project is still ongoing the paper focuses on the pilot status, progress achieved, and plans for the remaining part of the project. To meet project objectives and collect data on the ASP flooding performance a dedicated surveillance program was developed and the results of the program are discussed below. Technical challenges encountered during the operation phase and the solutions applied to resolve those challenges are also the focus of this paper. Additional studies were performed to assess the performance of ongoing ASP flooding and their results are presented. Finally, laboratory data and field observations collected during the pilot operation phase are presented to support our conclusions.
To ensure the physics of multiphase flow in porous media is rightly modelled, the balance between capillary, viscous, and gravity forces need to be understood. Capillary pressure (Pc) and relative permeability (kr) are critical parameters representing capillary and viscous forces respectively. Both are typically determined by special core analysis in the laboratory. The importance of application of proper capillary pressure curves for different processes and the consistency between the kr and Pc input are investigated.
In this study, we used the idea of Numerical Coreflood Experiment (NCFE) where detailed geology and known oil-water relative permeability and capillary pressure curves are used. Various NCFEs' production and pressure data can be generated for different conditions and used to estimate the kr and Pc. Here, we used a commercial application to back calculate a set of relative permeability and capillary pressure that fits the given production and pressure data for the examined cases. Afterward, we compared the resulting kr and Pc curves with those that were used to generate the NCFEs data to begin with.
In this study, we focused on the two-phase oil-water system to assess the process of obtaining a history- matched relative permeability by fitting the core-flood experiment data while setting capillary pressure to zero (ignoring Pc) in the simulation model. We compared different cases that we examined to identify the role and importance of Pc measurements in core-scale and reservoir-scale numerical simulations. The conclusion is that using appropriate input capillary pressure measurement is an essential step to ensure proper representation of the multi-phase flow physics. Ignoring Pc or using inaccurate Pc measurements could lead to inaccurate relative permeability curves and as a results unrealistic production and pressure output.
The results of this study can be used by researchers and practicing reservoir engineers in oil and gas industry. NCFE is an inexpensive and easy-to-use technique to evaluate the current experimental procedures and suggest improvements. NCFE can be extended to cover a wider-range of evaluations including the effect of gravity, injection rate and heterogeneities.
Salym Petroleum Development N.V. (SPD) is a joint venture company of Shell and Gazprom Neft. SPD operates a group of oil fields located in Western Siberia (Russia) of which West Salym is the largest. The field is a mature waterflood with increasing water cuts and declining oil production. To counter the decline a tertiary oil recovery technique called Alkaline-Surfactant-Polymer (ASP) flooding was selected. According to our earlier studies the potential incremental oil recovery factor due to ASP injection may reach 15-20% of the ASP-targeted field STOIIP. Having identified significant target for the ASP flooding, SPD carried out laboratory program to establish a working ASP formulation. The formulation was tested under subsurface conditions in a single-well chemical tracer field trial. The trial has demonstrated significant reduction of oil saturation in the flooded zone due to the ASP injection. An investment decision for the next development stage of the West Salym ASP project, a multi-well injection - production pilot, was taken in Q4 2012. In 2014 SPD plans to construct the surface facilities and ASP injection is expected in 2015.
The paper focuses on the current status of the ASP pilot project. The objectives of the pilot are to demonstrate the oil recovery potential of ASP technology and collect enough information for decisions on the subsequent commercial stage. The pilot surveillance program, the surface facilities and the subsurface configurations were specifically designed to meet these objectives.
In this paper our recent progress on optimization of chemical formulation is also discussed to demonstrate how the properties of chemical ingredients of an ASP flood are influencing the design of the surface facilities. Different design options for the key elements of the surface facilities were evaluated emphasizing the role of process requirements determined by properties of the chemicals used, as well as logistics and the harsh weather conditions.
West Salym reservoir rock and fluid properties are typical for West Siberian oil fields. Hence, success of this ASP pilot project could pave the way for subsequent ASP projects in other West Siberian oil fields and have significant impact on the Russian oil industry.
Alkaline-surfactant-polymer (ASP) flooding is a combination process in which alkali, surfactant and polymer are injected at the same slug. Because of the synergy of these three components, ASP is the current world-wide focus of research and field trial in chemical enhanced oil recovery.
This paper is to provide a comprehensive review of the ASP process. The reviewed topics include the following:
ASP synergy and its EOR mechanisms Screening criteria Laboratory work Numerical simulation work Summary of pilots and large-scale applications Project economics Chemicals used Water quality Salinity gradient Mobility control requirement Problems associated with ASP flooding
In addition to the comprehensive review, future developments are also discussed. Data and analyzed results presented in this review will help oil operators save research and pilot costs, and to build their confidence to execute and expedite their ASP projects.
This study focuses on a multi-well pilot test for a chemical enhanced oil recovery (CEOR) project in Sabriyah Lower Burgan reservoir that is located in the north of Kuwait. The objective of this research is to evaluate the economic applicability of a proposed Alkaline Surfactant Polymer (ASP) formulation based on laboratory core flooding in a multi-well pattern of the candidate reservoir. Simulation and economic modelling was used for this evaluation. Sabriyah Lower Burgan is a large sandstone reservoir with excellent rock properties (Darcy permeabilities). The field is currently developed through primary depletion with an active edge water drive. All forms of EOR were evaluated and CEOR was the only practical technology that passed all screening criteria. Understanding the reservoir behavior is critical and evaluating multiple implementation strategies is important to insure economic success.
The objective of the pilot test is to demonstrate that the recommended ASP formulation can economically mobilize remaining oil (ROS) in Sabriyah Lower Burgan reservoir. The process to achieve this objective includes: Expand a small scale pilot into a large multi-well pilot.Evaluate different well pattern configurations using numerical simulation to demonstrate the effectiveness of CEOR in producing additional oil.Apply economics to all case studies to determine applicability and commerciality of the different proposed case studies.List observated key challenges associated with large scaled field implementation.
Including economics in a technical CEOR assessment will help understand practical aspects of field CEOR implementation for the Sabriyah Lower Burgan field.
This paper discusses the design and implementation of a Single Well Chemical Tracer Test (SWCTT) to evaluate the efficacy of a lab-optimized surfactant-polymer formulation for the Raudhatain Lower Burgan (RALB) reservoir in North Kuwait.
A SWCTT was designed upon completing extensive lab and simulation work as discussed in a previous publication (Al-Murayri et al. 2017 and Al-Murayri et al. 2018). SWCTT design work was aimed at confirming the optimal injection/production sequence determined at core flood scale in terms of minimal volumes, rates and duration. The main uncertainties were assessed using numerous sensitivity scenarios. Afterwards, the SWCTT was implemented in the field and the results were carefully analyzed and compared to previously obtained lab andsimulation results.
The main objective of this SWCTT was to validate the efficacy of polymer and surfactant solutions in terms of residual oil saturation reduction and injectivity. This invovles comparing residual oil saturation estimates before and after chemical flooding while monitoring injection rates and corresponding wellhead pressures. The SWCTT injection sequence included the following steps:Initial water-flooding, followed by tracer injection, soaking and production to measure oil saturation post water flooding.Pre-flush followed by a main-slug (with 5,000 ppm of surfactant and 500 ppm of polymer) and a post-flush (with only polymer).Sea-water push, followed by tracer injection, soaking and production to measure oil saturation post chemical flooding.
Simulation work prior to the execution of the SWCTT test showed encouraging oil desaturation results post chemical flooding within a distance of 10 ft from the well. However, upon analyzing the pilot results, it was realized that there is a gap between the actual SWCTT results and previously obtained lab andsimulation results. This paper sheds light on the design and implementation of the above-mentioned SWCTTwith emphasis on the potential reasons for the realized gap between actual field data and lab/simulation results. The insights from this study are expected to assist in further optimization of surfactant-polymer flooding to economically increase oil recovery from relatively mature reservoirs.
Single Well Chemical Tracer Testing (SWCTT) is traditionally performed to determine oil saturation after waterflooding and after enhanced oil recovery techniques. Raudhatain Lower Burgan (RALB) and Sabriyah Lower Burgan (SALB) SWCTT oil saturation reduction due to injection of surfactant-polymer and alkali-surfactant solutions, respectively, were 7 and 8% OOIP, respectively. During SWCTT, injection rate and surface pressure are routinely measured for each injected solution. Injection rate and surface pressure permit additional determinations to be made as outlined below: Pseudo resistance factor to any fluid "i" can be calculated and, from this, changes in injectivity can be determinedFlowing viscosity of injected fluids relative to waterEffective permeability to injected fluidsInjectivity factors
Pseudo resistance factor for RALB continually increased with seawater injection, from 0.5 to 1.0 indicating a reduction of kwro to approximately half and a twofold loss of injectivity. SALB kwro showed a three-fold loss of injectivity with seawater injection (pseudo resistance factor increased to 1.0 from 0.36). RALB pseudo residual resistance factor was 6.0 indicating a six-fold loss of injectivity due to surfactant-polymer and polymer drive solution injection even though the oil saturation was reduced by 7% OOIP. SALB pseudo resistance factor increased to 1.7 during alkaline-surfactant solution, indicating a loss of injectivity and an increase in flowing viscosity. SALB pseudo residual resistance factors were 0.89 to 1.06 suggesting no damage to reservoir rock and no loss to a slight increase of injectivity or an increase of kwro after an 8% OOIP saturation reduction. RALB surfactant-polymer rheometer viscosity was 0.55 cP while flowing viscosity was 0.21 cP as calculated from pseudo resistance factor data with the comparative polymer drive solution viscosities being 1.9 cP rheometer and 0.16 cP flowing. SALB alkaline-surfactant solution flowing viscosity was calculated to be 0.80 cP compared to water viscosity of 0.50 cP. Calculated SALB kwro values for injection of water, alkaline-surfactant, and water flush after alkaline-surfactant are 0.012, 0.007, and 0.011 to 0.015mD, respectively. Calculated RALB kwro values for injection of seawater and seawater flush after surfactant-polymer/polymer flush are 0.019 and 0.004 mD.
A one-spot EOR pilot was successfully completed to demonstrate the efficacy of a lab-optimized ASP formulation to mobilize remaining oil from a giant sandstone reservoir in Kuwait. This one-spot EOR pilot, which also referred to as a Single Well Chemical Tracer (SWCT) test, was a significant milestone in de-risking ASP flooding for multi-well pilot implementation.
The vertical zone of investigation for the Raudhatain Zubair (RAZU) SWCT was chosen to be a confined channel sand with relatively homogeneous and representative properties in a producer near the proposed pilot area. Two SWCT tests were performed and the difference in residual oil saturation from post water flood and post ASP injection tracer tests quantitatively determines the displacement efficiency of the ASP slug. The tracer chemicals for the tests included a hydrolyzing, partitioning tracer (ethyl acetate) and two alcohols (n-propyl alcohol and isopropyl alcohol) that serve as cover tracer and material balance tracer, respectively, to ensure robustness of test interpretation.
The water flood SWCT test showed ideal behavior with well-defined profiles. Interpretation of this test was accomplished using a single layer model and showed that at the end of the water flood, the residual oil saturation to water was 0.24 ± 0.02% in the 23 -ft interval for the SWCT test. The ASP tracer test was complicated due to poor injectivity, well mechanical issues, and dilution from a zone which did not accept any SWCT test injection fluids but contributed substantially to production. Due to the dilution from another zone, the ASP tracer test profiles were more dispersed than the water flood tracer test but were adequately modeled using a two-layer model with irreversible flow. Analysis of the ASP SWCT test showed that the average oil saturation was reduced to 0.06 ± 0.05%, which represents a ~67% reduction in residual oil saturation.
Despite poor injectivity leading to a reduced polymer drive and taper injection and dilution from another zone resulting in a non-idealized tracer response, careful interpretation of the SWCT test measurements resulted in a reliable estimate of the post-ASP oil saturation. The SWCT test results demonstrate the feasibility of applying ASP flooding to increase oil recovery from a giant high-temperature sandstone reservoir in North Kuwait.
This paper sheds light on the design of a one-spot surfactant-polymer (SP) flooding pilot in a reservoir with oil viscosity greater than 1000 cP using a vertical well. The results of this pilot will be important to optimize the selected chemical formulation and finalize the recommended injection sequence with the purpose of de-risking subsequent multi-well surfactant-polymer flooding deployment.
Based on systematic screening, preliminary laboratory evaluation and reservoir simulation, SP flooding was identified as a promising EOR method for the Ratqa Lower Fars (RQLF) reservoir in Kuwait. This was followed by extensive laboratory work to design a robust chemical formulation based on specific reservoir properties and operating conditions. The performance of the developed chemical formulation was validated by means of simulation. Thereafter, a one-spot EOR pilot, which is also referred to as a Single Well Chemical Tracer Test (SWCTT), was designed to assess the effectiveness of the selected chemical formulation mainly in terms of injectivity and oil desaturation.
It was envisioned that the injectivity of a lab-optimized SP formulation for the RQLF heave oil reservoir needs to be confirmed in connection with oil desaturation using a one-spot EOR pilot due to the relatively high reservoir oil viscosity and low injection pressure to maintain cap rock integrity. Assuming favourable injectivity, incremental oil recovery in a one-spot EOR pilot is represented by the difference in residual oil saturation after water flooding and after chemical (SP) flooding. However, achieving low oil saturation as a result of waterflooding in a heavy oil reservoir takes a long time and requires large water volumes that are not applicable to full-field deployment. Therefore, the objective of the one-spot EOR pilot that is discussed in this paper was adjusted to validate oil desaturation as result of polymer and surfactant injection upon confirming water injectivity within a 3ft radius of investigation as outlined below: Initial water injectivity testPolymer solution injectionMeasurement of oil saturationSurfactant-polymer injection followed by polymer driveMeasurement of oil saturation
This paper describes a methodical approach to de-risk surfactant-polymer flooding in a heavy oil reservoir using a one-spot EOR pilot. There is limited reference in the literature, if any, to field deployment of surfactant flooding in heavy oil reservoirs with an oil viscosity of more than 1000 cP. The findings of this study can be used to evaluate and potentially improve the techno-economic feasibility of chemical EOR in heavy oil reservoirs with similar properties.
Following encouraging results from laboratory experiments, simulation studies and a one-spot EOR pilot for the Raudhatain Zubair (RAZU) reservoir in Kuwait, a multi-well pilot is planned in the near future. A combination of high temperature (90°C), in-situ brine salinity (>250,000 ppm) and divalent ion concentration (>20,000 ppm) make implementation of Alkaline Surfactant Polymer (ASP) flooding in RAZU quite challenging. The presence of a ‘Tar Mat’ interval in the pilot area further complicates pilot design. This paper outlines some of the risk mitigation measures for a successful ASP pilot.
Laboratory experiments were performed to evaluate different polymers for improved thermal stability and to obviate the risk of polymer precipitation at the producers. Based on long-term thermal stability studies and producer scaling considerations, HPAM/ATBS based polymer was chosen over HPAM -based polymer. The original formulation which was used in the one-spot EOR pilot required 3.5% co-solvent to overcome surfactant separation at optimal salinity. Several alternative alcohols were tested and finally an appropriate co-solvent that gave adequate performance at 1.5 wt% was selected to reduce cost and logistical requirements. Additionally, optimization experiments were conducted to de-risk emulsification potential of produced oil by reducing the concentration of the injected surfactants. Finally, experiments were carried out to characterize the nature of the hydrocarbon and rock in the ‘Tar Mat’ interval to evaluate the risk versus reward of perforating it in the pilot area.
This is the first time, to our knowledge, that ASP injection is being considered in a reservoir in such a harsh environment due to combination of high temperature, salinity and divalent ion concentration in formation brine. The presence of a ‘Tar Mat’ interval further complicates pilot design. The successful execution of this pilot will push the envelope of ASP deployment in other challenging reservoirs worldwide.
The Marmul inverted five-spot pilot was successfully completed in 2016, demonstrating the effectiveness of Alkaline Surfactant Polymer (ASP) flooding in improving oil recovery from Al khalata reservoir. Earlier studies including core flood experiments, single well chemical tracer tests and small scale models indicated a potential of >10% of ASP incremental recovery over polymer flood and >20% over water flood. The pilot included a custom-built ASP facility, a first of its kind of scale squeeze treatment for high pH, state-of-the-art nuclear magnetic resonance (NMR) technology for vertical saturation estimates and very extensive sampling and surveillance programme. Overall, the pilot operation was very smooth and stable, achieving high facility uptime, good injectivity, accurate chemical dosing and met the surveillance target.
The estimated ASP incremental recovery from the pilot was over 30%, which increased the interest in a field-wide ASP injection. The acquired pilot results and operation experience were used to scale up the facilities design and assess the impact of key uncertainties observed in the field and the lab. Major factors influencing the recovery factor and project efficiency were analysed including chemicals formulation, facilities design and water treatment technologies. A mind-shift on the formulation cocktail and facilities design was proposed to improve the economic attractiveness of the process on large scale implementations. A phased development is proposed to de-risk subsurface and surface concepts which are different from those in the pilot.
This paper discusses in brief the pilot operation & performance, scaling up the results to full field implementation and key design considerations for a cost effective ASP project.
A tertiary alkaline/surfactant/polymer (ASP) multi-well pilot flood was carried out in the San Francisco field, Colombia. The pilot had mixed results, as the positive subsurface response was counterbalanced by serious operational issues, that in the end did not allowed the pilot to realize its full potential. The complexity of the flow paths in a multi-sand reservoir with irregular well spacing lead to large quantities of chemicals being recirculated, which trigger the operational issues, becoming a complex loop where these issues led to closing wells, which led to changing the flow paths and generating more operational issues. The paper presents the design of the pilot, the extensive work that was carried out to understand and improve the flow in the pilot area, the response of the pilot, the challenges that were faced during its operation, and the analysis and lessons learned from this pilot.
Surfactant-polymer (SP) flooding (also known as micellar flooding) is an enhanced oil recovery (EOR) process resulting from the interaction of three mechanisms: (1) oil solubilization, (2) interfacial tension reduction, and (3) aqueous-phase mobility reduction by polymer. Surfactant-polymer flooding has been studied both in the laboratory and field pilot tests for several decades. In SP flooding, traditionally a tapered polymer solution follows the injected surfactant slug. However, in recent years, co-injection of surfactant and a relatively high concentration of polymer solution has been used in several field trials. Despite a significant increase in oil recovery in several surfactant-polymer flood projects, the increased oil production period has been of short duration.
The first objective of this paper is to present two field pilot tests which encountered productivity impairment, and the second objective is to describe the probable causes of the productivity impairment. The third objective of the paper is to present a methodology, using field and laboratory data, to anticipate the nature of long-term problems. To shed light on the issues, we will present two pilot tests located in the Illinois basin in the United States and San Francisco Field in Colombia. The results of the pilot tests and several laboratory experiments will be presented to address the productivity loss observed in the two pilot projects. Laboratory measurements to determine crude oil propensity for emulsions, with and without surfactants, are not part of the routine chemical EOR protocol in the industry. Nonetheless, understanding the cause and type of emulsion formation in crude oil, brine, and polymer at different salinities is critical and will be presented in the paper. In addition, in the paper, we will present the results of a numerical simulator to evaluate experimental laboratory results and the field test performance. In conclusion, because of the experience with numerous laboratory experiments and the conduct of associated field tests, we will be able to shed light on the complexity of surfactant-polymer EOR field applications.
Alkaline Surfactant Polymer (ASP) flooding was identified as a potential field development option for a clastic field in Southern Sultanate of Oman. Extensive laboratory studies and field tests have been conducted to evaluate and mature this development option. Core floods showed that ASP can recover more than 90% of the oil remaining after waterflood resulting in remaining oil saturation below 5%. Simulation studies showed that ASP can potentially increase the field recovery factor by more than 20% over waterflood or 10% over polymer flood. A successful ASP single-well tracer test (SWCTT) and a micro-pilot in this field validated the laboratory results, confirmed the significant desaturation by ASP and the low residual oil saturation after ASP. The potential size of the prize for ASP flooding in this field alone is significant.
Upon further evaluation of ASP as a development option, significant risks and uncertainties associated with implementing ASP at field scale were identified. An ASP continuous injection pilot was designed with well-defined objectives to reduce the risks and to quantify the uncertainties. In this pilot, the ASP process was evaluated in one of the main producing zones in the flank of the field utilizing a small (75m × 75m or 1.4 acres) inverted 5-spot pattern with a total of 7 wells (4 producers, 1 injector, 1 observation well, and 1 sampling well). The short injector-to-producer distance enabled a quick response and ensured completion of the field trial within one year at the target injection rate. The pilot was commissioned in Q1 2014 with water pre-flush to establish a waterflood baseline. Injection of the 0.3 PV ASP-slug started in February 2016, followed by 0.9 PV of polymer and a water post flush that was concluded in December 2016.
A custom-built surface facility was constructed to mix and inject the required chemicals and to assess and treat produced fluids through a specialized flow loop. Dedicated Multi Phase Flow Meters (MPFM) were deployed at each producing well to provide accurate phase rates to quantify ASP incremental oil volumes. Detailed chemical analyses of injected and produced fluids were conducted throughout the pilot execution. Desaturation assessments were carried out through detailed surveillance activities in the dedicated logging observation well that involved a comprehensive suite of logs and evaluation tools, including time-lapse Nuclear Magnetic Resonance (NMR) for saturation monitoring that were used for the first time in the field.
The pilot achieved stable and safe operations with good injectivity, uptime, accurate chemical dosing, sampling and analysis as well as detailed surveillance. It recovered a significant incremental volume of oil above waterflood from decline curve analysis vs. a target of 20%, hence doubling the recovery as achieved with waterflood. Significant water cut reversal (25% - 30%) in producers and 31% reduction in oil saturation in the observation well due to ASP were observed by the time lapse NMR data. No injectivity issues were encountered with 50cP ASP and polymer chase. No scale was encountered during pilot period due to the successful and early deployment of scale inhibitor. The pilot produced saleable quality oil, free from emulsion with negligible increase in BSW over waterflood.
This paper re-iterates the pilot objectives and design, summarizes the pilot results, including well performance, chemical analysis and surveillance data, surface facility performance during pilot execution, and the dynamic simulation and analysis of the pilot performance.
Central element of MOL Hungarian Oil and Gas Plc. (MOL) US strategy is to increase the hydrocarbon production at Hungarian oil and gas fields using technologies that are more efficient. The main goals of this activity are to increase the recovery factor in fields depleted with extensive water flooding, improving efficiency of recovery technologies. For this purpose, new materials and technologies should be developed and applied at both Hungarian and foreign matured oil fields. That is the biggest challenge of the research and development (R&D) activity of the MOL Upstream. The R&D project began more than ten years ago to meet these challenges and increase the oil recovery factor of the Algyo field, which is the largest Hungarian oil field. This paper describes how a countless number of surfactants, co-surfactants and their mixtures were synthetized, developed and tested in the laboratory to achieve the objective, developing a combined surfactant-polymer (SP) flooding technology. The most important properties of these complex fluids were the thermal stability at reservoir conditions (98°C and 170 bar), the colloid chemical stability in electrolyte medium (formation water) and the compatibility with reservoir rock and pore filling fluids. The primary findings of this job show that several surfactants were effective at high temperature; low salinity reservoir conditions and have good solubilisation and displacement effect and low interfacial tension and low reversible adsorption on reservoir rock. Synergetic effect was observed between surfactants and polymers therefore surfactant-polymer mixtures were produced and tested in core flooding tests. Based on numerous displacement tests on reservoir core plugs it can be stated that the calculated recovery factor was 20-25% using the developed SP mixtures. The successful laboratory displacement tests were also reproduced by numerical simulation on numerical core samples as well as the injectivity test on the new 3D reservoir model that was carried out to see the effect of developed SP mixture under real reservoir conditions. This paper will present the results of several years of research and development work for SP formulation targeting SP flooding in high pressure and high temperature reservoir. The field implementation through an injectivity test will also be presented demonstrating that injection of 2,000 m3 SP solution has huge effect on oil production even 3 years later. Based on the outstanding field results a SP flooding pilot was started in 2016.
A new absolute permeability upscaling method based on geological hierarchical models that affect different scales reservoir heterogeneities is presented. Reservoir anisotropy is evaluated via horizontal permeability (Kh) and vertical permeability (Kv). The new approach based on the geologic viewpoint that various geologic hierarchical-elements set result in relevant permeability display of different reservoir scales. For reservoirs, from micro-scale to macro-scale, influencing factors of permeability become abstruse. In conventional scenario, the calculation method based on single-phase numerical simulation test, core analysis and data statistics integrates all these factors as much as possible to upscale permeability. Considering reservoir anisotropy, horizontal permeability (Kh) and vertical permeability (Kv) are studied to show how anisotropy changes according to different reservoir heterogeneities. In the case study of Mackay River Oil Sand Block, Alberta, Canada, database includes regional depositional setting, core, and logging data for more than 20 wells. Generally, reservoir sedimentary setting poses a direct effect on permeability. Local rock bedding affects permeability anisotropy greatly, as well. There is no obvious linear parity between horizontal permeability (Kh) and vertical permeability (Kv) in core-plug. Vertical and lateral grain size variance also alters permeability. The mm-cm scale mud drapes have a worse effect on vertical permeability (Kv) than on horizontal permeability (Kh). Besides, bioturbations in the transitional facies could be favor of permeability. The three factors have non-linear relationship on effecting permeability. The new upscaling model synthesizes all these factors to upscale the permeability for nearly all scales of reservoirs, from the scale of core to lithofacies or even to the entire reservoir. Comparisons study is also conducted between this model and current upscaling algorithms such as arithmetic average, harmonic average, etc. The results showed that the upscaling model of this paper is more reasonable. Meanwhile, reservoir characterization hierarchical models can also be applied to explicate heterogeneity effect on the attribute of reservoir fluid qualitatively. The novelty of this approach lies in solving reservoir fluids' attributes quantitatively through exact heterogeneities analysis.
This paper presents a regional scale 3D geomechanical modeling study of the HB large produced gas field located in the northwest of China, which was converted to UGS facility in June 2013. The reservoir is approximately 3500m deep and there are three faults completely penetrate the caprock. The potential of the caprock failure and reservoir-bounding faults leakage after 14 years depleted production and their dynamic containment during UGS operations must be comprehensively evaluated.
In this study, a multi-disciplinary approach was used to build the static regional-scale 3D geomechanical model through interagrated analysis of geologic, seismic, well drilling, logging and rock experimental data. Gas-bearing reservoir, primary and secondary caprock, three main faults as well as underburden were all covered in this model. Comparing to the reservoir model, the regional scale geomechanical model is expanded laterally by about 5 times. Reservoir pressure during gas production and subsequent annual gas injection/withdrawal was passed to the model using Eclipse software.
The 3D fluid-dynamical geomechanical model was calibrated using the surface vertical displacements measured by InSAR interferometry over the second operation cycle. Simulation indicated that the change of reservoir pressure has a significant impact on the state of the regional-scale stress. Significant differences of in-situ stress have occurred on the both sides of the faults after gas production. It was found that the caprock failure and fault slip had not occur during past gas production, thus ensuring the safety of the UGS conversion. However, distribution of the in-situ stress became more heterogeneous due to high rate gas injection and withdrawal during the UGS operations that may have a significant impact on well integrity. Shear failure and hydraulic fracture of the caprock will not occur during the long term gas storage operations. But the model predicted a maximum shear slip up to 5 cm associated with cyclic gas injection and extraction and the slip tendency of the Southern fault is increasing with the UGS operations which will be weak spot of the UGS integrity. Consequently, it is strongly recommended to strengthen the dynamic monitoring of the Southern fault.
This paper provides a comprehensive geomechanical simulation method for assessment of the risk of caprock integrity failure and fault leakage of large UGS in produced gas filed during long term operations. This work is particularly important in the selection and design of UGS in complex faulted depleted gas filed in China.
In this paper, geomechanics is coupled with reservoir flow for modeling the depletion and deformation in fractured vuggy carbonate reservoir. Different from the dual- and triple-porosity models or the coupled approaches in which the vugs are considered as a continuous porosity, the vugs are treated as virtual volumes in this study. For each vug, the fluid exchange at the vug-matrix interface is dynamically calculated with time evolution and the pore pressure in the vugs is updated through considering both the fluid material balance and the volume change due to the mechanical deformation of vug. The fluid-mechanical interaction in the rock matrix and natural fractures is calculated based on the framework of Biot's poroelstic theory. The mechanical and hydraulic interactions between vugs and matrix are preserved and the stress evolution due to the depletion can be dynamically updated. The results in this study show that, the depletion process is mainly controlled by the fluid storage of the vugs. Fluid modulus is thus a more sensitive parameter than the rock/fracture modulus in terms of the depletion. However, the rock/fracture modulus can also affect the deformation of the system and thus affect the volume and pressure changes of the vugs.
Although Alkali-Surfactant-Polymer (ASP) flooding enhance oil recovery (EOR) technique has been put forward many years ago, it was not until 2014 that it is first put into industrial application in Daqing Oilfield in China. Under such low oil price, ASP flooding advance in China provides confidence for ASP flooding as a chemical EOR technology. In 2014, ASP flooding entered into industrial application stage first time in history. Crude oil production from ASP flooding in 2015 and 2016 in Daqing Oilfield was 3.5million and 4 million ton, which accounts for the 9% and 11% total oil production respectively. In 2016, another large scale ASP flooding field test in high temperature (81 °C) reservoir in central was seen staged incremental oil recovery 7.7% in central well zone. 30 ASP flooding field tests in China were reviewed to help promote wiser use of this promising technology. ASP flooding in Daqing Oilfield deserves most attention. Strong alkali (NaOH) ASP flooding (SASP) was given more emphasis than weak alkali alkali (Na2CO3) ASP flooding (WASP) in a long time in Daqing, lower interfacial tension(IFT) of surfactant and higher recovery in presence of NaOH than Na2CO3 the most important reason. Other ASP flooding field tests finished in China are all Na2CO3 based, including one using mixture of NaOH and Na2CO3. With progress in surfactant production, a recent large scale WASP field tests in Daqing was seen incremental oil recovery of near 30%, higher than most previous SASP ones, and near to the most successful SASP one. However, this most successful SASP was partly attributed to the weak alkali factor. Recent studies shows that WASP incremental oil recovery factor could be as good as SASP but with much better economic benefits. According to Daqing Oilfield review, the equipment IFT is more determinant than dynamic IFT in contribution to displacement efficiency, thus it is better to choose lower dynamic IFT when equilibrium IFT met the 10-3 orders of magnitude requirement. However, it is impossible for many surfactants to form equilibrium IFT, thus dynamic minimum IFT was chosen as criteria. For low acid value Daqing crude oil, asphaltene and resin component plays a very important role in reducing oil/water IFT, and asphaltene is believed more influential, though more work are required to answer this controversial issue. Progress in surfactant production, overcoming of scaling and produced fluid handling challenger is the foundation of ASP industrial application. Dynamic adjustment in ASP flooding is common practice in Daqing. For the compatibility between ASP and formation pore structure, especially considering emulsion and formation damage, no satisfactory standards are found yet. Further work should be on emulsification effect in ASP flooding. Mixture of cation and anion surfactants used in Henan Oilfield may be a good choice to face the high temperature challenge. Ultra-high temperature reservoir ASP flooding with organic alkali is under investigation and a field test is in schedule. It is very difficult to carry out ASP flooding in high temperature and high divalent cation reservoir and no success was seen in such kind of reservoirs in China. According to one field test, EOR routine should be selected with consideration of residual oil type to decide whether to enlarge sweep volume or/and displacement efficiency. Micellar flooding failure in Yumen Laojunmiao (YM-LJM) reservoir makes subsequent field tests choose the "small concentration large slug" technical route instead of "high concentration small slug" one like YM-LJM. ASP flooding can increase oil recovery by 30% and control the cost below 30 US dollar/bbl, thus it can be used to face low oil price challenge.
Sandstone reservoirs containing significant amount of clays (30-40 wt%) with moderate permeability (20-50 mD) provide a unique challenge to surfactant based enhanced oil recovery (EOR) processes. A critical risk factor for these types of reservoirs is adsorption of surfactants due to greater surface area attributed to clays. Clays also have high cation exchange capacity (CEC) and can release significant amounts of di-valents that lead to increased retention of the surfactant. These factors could adversely affect the economics of a flood.
We present a case study where a robust formulation was designed and tested in lab/field for a reservoir located in Wyoming, USA and contains up to 35-40 wt% clays (predominately Kaolinite and Illite). The residual oil saturation is high (Sor=0.4) while the permeability of the formation is between 20-50 mD. The reservoir has been waterflooded historically with low salinity water which has led to formation permeability damage. Due to high levels of clays, adsorption of the surfactant on the rock surface was determined to be between 3-4 mg/g rock by static adsorption tests.
This publication demonstrates how the following challenges have been successfully addressed in the lab as well as in the field in the form of single well chemical tracer test (SWCTT).
Designed a robust alkaline-surfactant-polymer (ASP) formulation that showed ultra-low interfacial tension (IFT) values and aqueous solubility remains soluble in the aqueous solution over a broad range of salinity.
Mitigated surfactant adsorption issues to make the cEOR solution economic. A sacrificial agent was identified that acted synergistically with alkali and also did not alter the optimum salinity of the formulation.
Performed restored state core analysis using the available damaged core material. The main challenge being restoration of the coreplugs to current reservoir conditions for coreflood experiment without causing additional formation damage due to injection of low salinity formation brine.
Designed a flood that utilized a pre-flush to provide a favorable salinity gradient and to inject sacrificial agent ahead of the surfactant front.
Performed polymer screening to select right molecular weight of polymer so that the right balance of mobility control and injectivity in the reservoir can be obtained.
A Polymer Flooding pilot trial has being implemented in a heavy oil field, in the South of Oman. A joint team composed of personnel from Sultan Qaboos University, Poweltec and Petroleum Development of Oman provided full laboratory support which included polymer products screening, and core-flooding experimental tests. The reservoir under investigation is a high-permeability sandstone with oil viscosity of around 500 mPa.s, brine salinity of around 5,000 ppm TDS and a subsurface temperature of 50°C. The reservoir characteristics are within the upper boundaries of known polymer flooding applications worldwide. This is further compounded by the presence of a strong bottom aquifer drive which requires the optimization of well placement.
Laboratory work consisted of both bulk and core-flood testing, in which different commercial hydrolyzed polyacrylamides were submitted to rheology, filtration and stability tests, from which one product was qualified. An intensive coreflood program was executed, consisting of rheology, adsorption and displacement experiments. Due to mild reservoir conditions (low salinity and temperature), the main focus was on filtration quality of the products. Following on from the filtration tests, coreflooding programs were implemented with very long sequence of polymer injection at a rate representative of polymer propagation in the reservoir.
Adsorption was found to be quite low (around 20 µg/g) for all the tested products. In-situ rheology was correlatable to the viscosity trends. The program of tests finally qualified a product with molecular weight of around 20 million Dalton. Above this level, long-term filtration becomes questionable with a slow but continuous ramp up of pressure noticeable after about 50 Pore Volumes.
The Mangala field in the state of Rajasthan of western India was the first major oil discovery in the Barmer basin and is the largest discovered oil field in the basin. It contains paraffinic oil with average viscosity of ~15 cp and wax appearance temperature only about 5°C lower than reservoir temperature of 65°C. The initial development plan was a hot waterflood to prevent any in situ wax deposition; recently, though chemical EOR methods have started to play an important role in the development of the field.
A polymer flood pilot was successfully conducted in the field. It was followed by an ASP pilot trial which used the same set of wells. Unlike the polymer pilot, ASP injection was confined to a single continuous sand to reduce interference with nearby wells and to reduce the uncertainty in interpretation of pilot results. A combination of a high molecular weight branched alcohol PO-EO sulfate and a high carbon number sulfonate was selected for the ASP formulation. The selected surfactants functioned well in the desired salinity range and were stable in an aqueous solution up to half a percent higher alkali concentration than the optimal concentration.
The pilot facilities needed to meet a number of challenges arising from using neat surfactants-mainly handling of viscous/gelling material, maintaining accurate dosing rates, maintaining the right ratio of two surfactants, and maintaining stability of the sulfate itself. These challenges were surmounted in the pilot by using a blended surfactant solution, diluted with water, with activity of 24%.
ASP injection led to mobilization of significant volume of oil in the confined 5-spot pattern. The oil-cut of the central producer increased from 10% to 80%. The oil production rate showed almost an eight fold increase from 50 bopd to nearly 400 bopd. The estimated incremental recovery over polymer flooding is nearly 20% of the pilot STOIIP. Later in the pilot project the expected increase in water-cut was accompanied with the production of the injected chemicals along with rise in the pH of the produced water, indicating that favourable mobility was maintained during ASP injection. Some production challenges were encountered—most notably the failure of the producer's electrical submersible pump (ESP); this required the producer to be put on jet pump intermittently when the ESP was not functioning. The saturation observation wells located within the pattern area showed significant desaturation of oil. Sponge cores acquired after the pilot showed very low remaining oil saturation in the flooded sections. The paper will discuss the pilot operations, monitoring and quality control, the pilot results, and lessons learnt.
The design of an alkali-surfactant-polymer (ASP) formulation for chemical Enhanced Oil Recovery poses multiple challenges from the experimental point of view. The present research examines the laboratory procedures and experimental results aimed at selecting the most suitable chemicals for an ASP pilot trial at the Caracara Sur field (Los Llanos Basin, Colombia). The key challenge was the limited compatibility of the surfactant and polymer selected under reservoir conditions (temperature and total salinity), leading to phase separation of the ASP solution and losses of the activity of both chemicals. An extension of the experimental program was required to re-design the formulation and mitigate risks of damaging the formation in the following field trials. The formulation comprised an alkyl benzene sulfonate as main ingredient, a hydrolyzed polyacrylamide as viscosifying agent and some weak alkali to reach the optimum salinity of the mixture. A mono-alkyl diphenyl disulfonate ether was added as coupling agent to improve compatibility of the ASP mixture. The performance of the selected ASP formulation was assessed by means of interfacial tension measurements, long-term thermal stability tests and dynamic core-flooding tests. The formulation provided ultra-low interfacial tension (< 10⁻² mN/m) and viscosity enough to assure an appropriate mobility control. Hence, the formulation was considered to be suitable for further testing in the field pilot.
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–Monitoring needs: base line establishment, injection and production follow up,–Surface issues related to the pilot in this offshore context: injection and production top side facilities–Chemical logistics when part of the formulation is a R&D chemical, to be manufactured on purpose, and imported in due time, including the choice of premix versus on line mixing products–Management of a pilot as a project but still with the specificities of derisking and qualifying a technology on a mature field (from preliminary study to project execution)–Offshore concerns, with the added difficulty of a H2S environment
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
ASP process is the current worldwide focus of research and field trial in chemical enhanced oil recovery. The process has potential to enhance tertiary oil recovery by reducing the residual oil saturation left after prolonged water flooding in depletion type of reservoir.
The present paper presents the results of the pilot test in K-XII sand of Kalol field in Ahmedabad Asset of ONGC. Kalol field is a multi-layered reservoir having 11 hydrocarbon pay zones. It is a depletion drive type reservoir and was put on production put on production in 1966. Since 1972, central line drive injection pattern was in operation for pressure maintenance and improvement in oil recovery. K-XII reservoir has produced about 30% of OIIP with the help of water injection. It is a light oil reservoir having viscosity of about 0.38–1.87 cP at reservoir temperature of 82°C and permeability varying from 20–700 mD. The acidic component is 0.10 mg of KOH/gm of oil.
After extensive laboratory and simulation studies, a small pilot consisting of 1 injector and 2 producers in line drive pattern and 1 offset well was selected for pilot testing. Single Well Chemical Tracer (SWCT) test was conducted to know the current saturation in the pilot area and was found to be 26%, which was coinciding with the laboratory determined ROS value. This indicates that pilot is almost flooded and saturation is close to residual oil. Injection commenced with injection of 20% of Ammonium Thiocyanate tracer in Oct. 2013 to monitor the front movement. ASP injection started in Feb. 2014.
ASP solution consisting of 0.30 Pore Volume (Alkali -3.0 Wt.%, Surfactant-2000 ppm, Polymer – 300 ppm) has been injected and injection of 0.20 PV of mobility buffer (300 ppm) started in May 2015, which will be followed by chase water. The results of last 15 months of the pilot are encouraging and incremental oil produced is about 3876 m³ (June 2015), which is about 68% of the envisaged oil through simulation. Average Water cut reduction is about 10–15 %, however, significant water cut reduction was observed in one offset well, from 87% to 40 %. The effectiveness of the pilot is also reflected in the production of oil in form of emulsion which was generated in-situ by reaction of oil with alkali and surfactant.
This paper discusses the details of the laboratory studies, simulation study, pilot design, injection schedule, monitoring of injection fluid quality, production performance and lessons learnt. The success of this pilot leads to expansion and application of this CEOR process to other major reservoirs of Kalol field.
Chemical Enhanced Oil Recovery (CEOR) in a multi-layered reservoir environment with moderate to strong natural water-drive is a complex process with associated risks and uncertainties. Reservoir simulation is one of the most important tools available to predict behavior under chemical flooding conditions and to study sensitivities aimed to a cost-effective CEOR process implementation. Key to the success of a reliable reservoir simulation is the application of a de-risking process and the acquisition of important calibration data, such as laboratory core-flood data and field-scale pilot experiments.
A CEOR pilot is currently undertaken in the Caracara Sur (CCS) field (Llanos Basin, Colombia) which has an unfavorable mobility ratio and very low water salinity. However challenges exist, such as strong water drive (no water injection experience), high temperature and a complex geological nature (up to 15 reservoir layers that made up of multiple isolated distributary channels). A detailed reservoir simulation model was built to study full field implementation of CEOR in Caracara Sur. The model was calibrated with laboratory tests data, residual oil saturations from Single Well CEOR ASP Well Tracer Test Pilots, injectivity tests and breakthrough times from inter-well tracer tests.
The paper discusses the approaches taken for full field modeling of Caracara Sur using commercial software and describes how the data collected from alkaline/surfactant/polymer (ASP) core flooding were up scaled and used in pilot sector modeling and for designing tracer back flow tests (TBFT) and single well tracer tests (SWTT) before and after ASP flooding. The TBFT and SWTT results in a pilot injection well, in the middle of three producers, confirmed the absence of aquifer drift, which was also predicted by pilot sector modeling. The paper explains how the obtained results from the tracer tests (residual oil saturations, breakthrough times) and well injectivity were used to calibrate the full field numerical model for reliable prediction of the effectiveness of the ASP flooding.
Scaling up from lab to pilot is one of the challenges to meet in any ASP project to accomplish the requirements at full implementation. Tailored EOR surfactants developed and manufactured in the laboratory, to achieve the lowest interfacial tension (IFT) between oil and water at the reservoir conditions, have to be viable and robust in the manufacture, capable in performance and compatible in the formulation, not only at laboratory scale, but also at industrial scale.
It is described in this poster the route map in the development and manufacture of alkyl aryl sulfonates surfactants for the Cepsa ASP pilot project in the Caracara Sur field, Los Llanos basin (Colombia) from a continuous feed-back of the laboratory tests. The surfactant employed for the project was selected from other surfactants from several suppliers and dyalkylbenzene sodium sulfonate was the one achieving the lowest interfacial tension for Caracara field conditions. The dyalkylbenzene sodium sulfonate was accompanied by a co-surfactant improving the solubility and performance properties.
Pilot ASP injection started in May 2015 and some conclusions were obtained during the production of the surfactants in several manufacture batches:
Composition, molecular weight even isomerism of alkylbenzenes may impact strongly on the interfacial activity of alkyl aryl sulfonates surfactants.
Sulfonation and neutralization of alkylbenzenes are critical processes to comply the requirements of alkyl aryl surfactants for any cEOR project.
Finally, the laboratory in the field for quality assurance and quality control (QA/QC) of surfactants is completely necessary. Periodical sampling and on-site analyses are scheduled but also samples delivery to research center for more sophisticated analyses. These data are essential for the final performance evaluation and the project success.
Several alkaline-surfactant/polymers (ASP) were used to recover oil in the Cambridge field in Crook County, WY. ASP provided ultralow interfacial tension and optimal phase behavior by using surfactant concentration of 0.1 wt%. For alkali concentrations of 0.75-2 wt%, interfacial-tension values in the order of 10 -3 dynes/cm were achieved between Cambridge crude oil and solutions of 0.1 wt%-active surfactant plus sodium carbonate. Ultimate oil recovery from the ASP flood of the Cambridge field was 60.9% original oil in place (OOIP) compared with the numerical-simulation-waterflood predicted recovery of 34.1% OOIP. The essential factors in the success of ASP flooding include reservoir engineering, injected-fluid design, numerical simulation, and facilities design and construction.
Surfactant flooding in high salinity reservoirs (total dissolved solid (TDS) levels S: 100,000 mg/L) has been challenging, because many currently available surfactant candidates will fall out of the solution due to the solubility limit. Stewart Fee and SE Hewitt are two reservoirs of interested with high salinity formation brine of 165,000 mg/L and 102,300 mg/L TDS, respectively. Two ternary surfactant systems composed of conventional and extended surfactants were formulated for each reservoir. Single well chemical EOR pilots were performed in both reservoirs and single well chemical tracer tests (SWCTT) were conducted to estimate the near wellbore residual oil saturation (Sor) before and after chemical EOR injection. Ternary surfactant systems were optimized using phase behavior tests and IFT measurements for each reservoir. Laboratory sand pack and coreflood tests were conducted to evaluate the displacement efficiency of optimized surfactant systems prior to field injection. The optimized systems reached ultra-low IFT in the order of 10-3 mN/m, recovered more than 60% of the Sor in sand packs and coreflood tests with actual formation brine salinity from each reservoir. As part of the SWCTT, the partitioning coefficient of the reactive tracer (ethyl formate) is measured in the lab under reservoir temperature and formation brine salinity. Numerical simulation was used to model and interpret the SWCTTs. The number of layers, Sor, dispersivity coefficient, ester reaction rate and flow fraction in each layer were used as the matching parameters. Total injection rate was adjusted according to the material balance tracer recovery. The partitioning coefficient decreased with presence of surfactant in experimental tests. Simulation results indicated that the reaction rate of reaction tracer was decreased in post-SWCTTs relative to pre-SWCTTs in both cases. This is because the coupled effects of lower partitioning coefficient and the drop of reservoir temperature due to water injection. The field test tracer profiles of two reservoirs were all best fitted by a two layers model. For Stewart Fee, the Sor in pre-chemical EOR SWCTT were 0.49 and 0.22 in each layer, and were decreased to 0.15 in both layers after the chemical EOR.For SE Hewitt, the Sor in pre-chemical EOR SWCTT were 0.20 and 0.12, and were decreased to 0.03 in both layers after the chemical EOR. From the simulation results, the post EOR oil recovery in the field was between 60-90%, showing that the developed ternary systems are all very promising and effective for EOR in high salinity reservoirs. The combined efforts of conducting experiments and modeling and numerical interpretation of SW- CTTs for two high salinity reservoirs showed that the formulated two ternary surfactant systems composing of extended and conventional surfactants mobilized more than 60% of residual oil at low surfactant concentration of 0.5 wt%, which are all very promising for chemical EOR in high salinity reservoirs.
Assessing the residual oil saturation of different EOR techniques is of paramount importance to accurately select a suitable tertiary development and properly quantify remaining reserves in a given field. The Single Well Chemical Tracer Test (SWCTT) has proved to be a reliable technique to consistently measure the residual oil saturation in a representative formation volume.
This work describes the design, operations and results of a sequence of three SWCTTs performed in a very heterogeneous and complex reservoir, on-shore in West Africa. The aim of the pilot tests is the evaluation of low salinity water and surfactant flood efficiency compared to current sea water injection. The EOR techniques were selected to improve the oil recovery factor in the field after an intensive experimental work and the effects were evaluated by means of simulation models.
The SWCTTs were executed with cycles of injection, shut-in and production periods to measure the residual oil saturation after sea water, low salinity water and then surfactant injection to compare with experimental and simulation results. Favorable results were achieved for surfactant flooding with considerable reduction in residual oil, confirming that a performing surfactant mixture at harsh field condition was found. The SWCTT results showed, instead, a minor effect for low salinity water and the difference in core and field results were then investigated.
A peculiar SWCTT program was executed to verify and compare the efficiency of two EOR methods at field conditions. Thanks to the encouraging surfactant results and the gained field experience, an extension of the EOR technique is under design in a cost-effective surfactant-polymer inter-well pilot. This assessment will provide optimization of chemical formulation in terms of compatibility, surfactant concentration, polymer viscosity and slug volumes.
In May 2006, the Warner Mannville B ASP flood was the first field wide ASP flood implemented in Canada. The objective was to successfully implement a commercially viable ASP flood. In this project produced water is treated and reinjected into the reservoir. As of December 2012, an incremental 420 103m3 (2.65 million bbl) of oil has been recovered with an expected total incremental recovery of 777 103m3 (4.89 million bbl), which represents 11.1% of the OOIP. In October 2008, after 0.35 pore volume of ASP injection, the project moved into the Polymer only injection phase. Polymer injection will continue as long as is economically feasible.
A comprehensive monitoring and testing program was implemented to evaluate flood response and performance. This allowed for the optimization of the flood through continuous adjustment to flow rates and led to successful infill drilling locations.
Many challenges have been encountered during this project, including: silicate scale production, treating issues related to the water quality of the recycled injection water, and loss of injectivity in many injection wells.
The challenges were overcome and it has been an economic success with a cumulative positive cashflow within 5 years. The results of this flood have led to the implementation of an additional four floods. The lessons learned from this project have improved numerous aspects of how future floods are designed and implemented.
Kuwait Oil Company has recognized the implications of the recent technological advances that are very likely to transform the oil industry and make chemical enhanced oil recovery methods such as alkaline-surfactant-polymer (ASP) flooding a hallmark of enhanced oil recovery. An ambitious program to apply chemical EOR to both sandstone and carbonate oil reservoirs , Kuwait is already underway. In this paper, we present the first field results of this effort. First we discuss the approach used to design a novel surfactant formulation for a high-salinity, high-temperature, highly heterogeneous carbonate reservoir, the Sabriyah-Mauddud , Kuwait,and the evaluation of the ASP process in three one-spot ASP pilots (i.e., three two-stage single well chemical tracer tests). We summarize the results of the surfactant laboratory experiments used to select the final ASP formulation and we present detailed results and interpretation of the subsequent single-well chemical tracer test (SWCTTs) results using ASP chemicals as well as details of the field operation including quality control measurements performed in the field lab. The residual oil saturations measured before and after the injection of the ASP slug and polymer drives clearly show that the chemical solution was effective in mobilizing and displacing residual oil saturation following injection of water. The injectivity of high molecular weight polyacrylamide polymer was excellent despite the low permeability of the formation.
Chemical Enhanced Oil Recovery (CEOR) use is expected to increase as more production companies implement tertiary oil recovery methods. This case study provides an outline of the process used to determine the applicability of an Alkaline-Surfactant-Polymer (ASP) flood, how the ASP chemical package was selected and tested, and the current field trial status. The selected field for this project is the low temperature Mooney field in north-central Alberta, Canada, producing ~16° API gravity oil with a viscosity of 150 to 1,500 mPa-s from the Cretaceous Bluesky sand formation at a depth of approximately 900 meters.
In 2006 a waterflood pilot test recovered an incremental 3% of the original oil in place (OOIP) over the primary production recovery (~4 to 5%). A three well polymer-only pilot was started in 2008 for 14 months and showed a total recovery of 18% OOIP suggesting a tertiary recovery method could be more successful than a waterflood. An independent laboratory tested multiple ASP packages, formulated with various surfactant types, either NaOH or Na2CO3 as the alkali in softened injection water, and with a partially hydrolyzed copolymers of acrylamide and acrylic acid. This independent reservoir screening identified several ultra-low interfacial tension ASP chemical package candidates, and core flooding confirmed increased oil recovery. Low chemical concentrations were specifically tested to minimize ASP chemical costs and downstream issues with emulsions. Economics were promising enough to proceed with company and Canadian approvals for ASP Phase One field implementation. Commercial injection began September 2011.
The Phase One ASP scheme consists of 25 injectors and 26 producers. Production from the ASP flooded area increased from approximately 175 barrels of oil per day (BOPD) in summer 2011 to a current high of ~2600 BOPD in December 2013, a period of 30 months. ASP chemical injection is continuing. Some injection delays have been caused by operational issues (water source and pipeline/facility modifications). These promising oil recovery results allowed Phase Two to be approved, and it is slated to be completed in 2014. Phase Three development is in the planning stage including drilling 16 additional primary horizontal wells.
The ASP flood of the Mooney field is a multi-well ASP flood that is progressing well but is still in the preliminary stages of data collection. The reservoir will continue to be monitored over the coming years to develop a comprehensive analysis of the tertiary oil recovery and how it compares with the initial laboratory ASP test results and predictions.
Mitigating production decline is a challenging task that every oil company will be faced with at some point over the life of an oil reservoir. However, depending on the existing reservoir fluid and rock characteristics, saturation distribution, and the level of heterogeneity of the reservoir rock, Enhanced Oil Recovery (EOR) programs can be implemented to alleviate the decline in oil rate and improve overall recovery.
This paper presents an example of a how a mature waterflooded field in southwestern Saskatchewan, Canada could be revitalized using Alkaline-Surfactant-Polymer (ASP) flooding. In this study, laboratory tests were undertaken to select effective chemicals and optimize concentrations that would yield the highest potential oil recovery. Subsequent radial coreflood experiments demonstrated a wide range of potential recovery that depended on slug size and chemical concentration. A detailed numerical simulation of the optimum core displacement was performed in order to calibrate the interaction of the EOR agent with the reservoir rock and fluids, and ultimately upscaled to the full field numerical model Reservoir simulation sensitivity runs were conducted in order to identify an optimum field development strategy using the selected ASP fluid. The results from this optimized development strategy were compared to the waterflood base case to demonstrate the potential upside of the chemical flood. This paper also presents a holistic roadmap for developing EOR projects from initial concept to field implementation and beyond.
French, M.S., SPE-AIME, Shell Oil Co. Keys, G.W., SPE-AIME, Shell Oil Co. Stegemeier, G.L., SPE-AIME, Shell Oil Co. Ueber, R.C., SPE-AIME, Shell Oil Co. Abrams, A., SPE-AIME, Shell Development Co. Hill, H.J., SPE-AIME, Shell Development Co.
In this pilot study, which involved drilling five process wells, three observation wells, and four evaluation core holes, there were four injection phases:a preflood,a slug of chemical solution,a drive solution, anda fresh-water flood.
Although the oil cut in the pilot increased appreciably, the chemical system would have to be modified pilot increased appreciably, the chemical system would have to be modified for commercial application of the process.
Introduction
A tertiary process for recovering oil left by conventional waterflooding has been applied in a 1-acre pilot in the Benton field, Franklin County, III. The pilot was a five-spot pattern with three observation wells drilled around one injection well to provide data for early evaluation of the process (see Fig. 1). The process tested in the pilot consisted of four injection phases:a preflood of low-salinity water to displace the high-salinity formation water from the vicinity of the injection wells;a slug of chemical solution that contained a surfactanta controlled-mobility drive solutionan ordinary waterflood with fresh water.
The chemical slug used in Phase 2 was based upon work by Hill et al., carried out in the Shell Development Co. Bellaire Research Center. Adsorption and mobility experiments in small Benton cores provided the technological design requirements for the chemical system. However, both technological and economic factors were considered in arriving at the final design. During the operation of the pilot, one of the injectors experienced poor receptivity and was abandoned before significant chemical was injected. After the four phases had been injected, four core holes were cored through the objective zones and swab-produced to provide data on reservoir conditions.
Reservoir Characteristics
The Tar Springs sandstone in the Benton flood unit is a northwest-southeast trending distributary channel bordered on both sides by delta fringe deposits. The 1-acre pilot site was located in the fringe portion in the southern part of the field (see Fig. 2). Only the upper 20-ft sand interval was included in the chemical pilot, with impermeable layers separating this interval pilot, with impermeable layers separating this interval from the remaining sand, This site was selected because of suitable sand thickness, low-permeability layers above and below the sand representing layering in much of the field, and sand quality representative of most of the field. Restriction of the test to the 20-ft interval reduced the cost of the project and the time required to complete the test. The interval selected for the pilot can be sub-divided into three zones on the basis of sedimentary features, average permeability, and frequency distribution of permeability. The upper zone (Zone A) averages 8 ft in thickness and consists of ripple-bedded, very fine-grained sandstones; the middle zone (Zone B) averages approximately 4 ft in thickness and consists of medium-scale, cross-bedded, fine-grained sandstone; the lower zone (Zone C) averages 10 ft in thickness and is similar in appearance to Zone A. These three zones appear in the same order in all wells at the pilot site. Porosity averages about 17 percent. Pore volume in Zone B was 4,970 bbl.
JPT
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This paper was prepared for the Improved Oil Recovery Symposium of the Society of Petroleum Engineers of AIME, to be held in Tulsa, Okla., April 16–19, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.
Introduction
This paper reviews field test experience with the Maraflood* oil recovery process with special emphasis on the evaluation of field testing in the Pennsylvanian aged Robinson sands of Southern Illinois. The Maraflood process utilizes a slug of micellar solution process utilizes a slug of micellar solution to displace in situ crude oil. This slug is, in turn, displaced by a bank of fluid of control mobility (referred to as mobility buffer). The flooding sequence is completed with the injection of drive water.
Detailed discussions on the nature of micellar solutions and laboratory experiments evaluating their performance have been previously reported. Initial field testing previously reported. Initial field testing was started in 1962 in the Robinson sand. Since that time, eleven tests have been reported. Six of these tests have been or are being carried out in the Robinson sand. Two other tests are in progress in Illinois, one in the Kirkwood or Cypress sand and the other in the Aux Vases sand. Three tests have been completed or are underway in Pennsylvania.
The evolution of micellar solution flooding is reviewed in this paper with examples from six tests carried out in the Robinson sand. Test experience on these six tests is given first. Next, the development of the test pattern philosophy is discussed as covers the ten-year testing period. Then the progress of design and evaluation method is described by using examples from specific tests. Finally, economics are considered as related to fluid and project costs in the Robinson sandstone.
TEST EXPERIENCE
The micellar solutions used in all tests consisted of a surfactant, hydrocarbon and water. Small quantities of a cosurfactant and electrolyte were also added in most tests. Table 1 shows the compositional ranges of three categories of micellar solutions which have been developed for field use. The designation of oil-external and water-external in the table indicates the non-dispersed phase of the micellar solution. Systems falling within the three categories of Table 1 have been studied extensively in the laboratory.
A tertiary alkaline/surfactant/polymer (ASP) pilot flood was implemented during 2010 in the Illinois basin of the US, and is continuing currently. With initial discovery of the Bridgeport sandstone formation in the early 1900s and more than 60 years of waterflooding, the pilot was designed to demonstrate that ASP flooding could produce sufficient quantities of incremental oil to sanction a commercial project. Laboratory experiments, including corefloods, were performed to determine the optimal chemical formulation for the pilot and to provide essential parameters for a numerical-simulation model. Polymer-injectivity tests, single well chemical tracer tests (SWCTTs), and an interwell-tracer-test (TWIT) program were all performed to prepare for and support a full interpretation of the pilot results. A field laboratory was run through the duration of the pilot to monitor the quality of the injection and production fluids, which turned out to be critical to the success of the pilot. We present the results and interpretation of the ASP pilot to date, the challenges faced during the project, and the lessons learned from the field perspective.
Angsi field is located offshore Terengganu, Malaysia. It was identified as the candidate for a pilot project to evaluate the effectiveness of chemical enhanced oil recovery (CEOR). Injection of alkali-surfactant (AS) slug was used to improve recovery factor through the reduction of residual oil saturation (Sor). The pilot project utilized single well chemical tracer test technique (SWCTT) to measure Sor change near well bore due to reactions of CEOR process. The pilot results were later used to update the reservoir dynamic model and to support decision making for potential expanded field application.
The pilot project faced many challenging technical and operational obstacles: offshore location, high reservoir temperature, sea water as injection water, water softening facilities requirement, and unmanned satellite platform with limited space. In addition, compliance to all Health, Safety, and Environment (HSE) requirements is a must, to ensure the pilot operation is carried out in a safe manner.
This paper will focus on the overall pilot design, planning and some results. Operational, HSE and quality control will also be discussed as background to the pilot project.
In 1975 Gary Energy Corporation, as operator of the Bell Creek Field, entered into a cost sharing contract with ERDA (now DOE) to develop a 160 acre (6.5 × 105 m2) micellar-polymer pilot project in the Bell Creek Muddy Sand Unit "A". This paper reviews the micellar process used, design of the pilot facilities, and operation of these facilities in the successful injection of the necessary chemicals at this pilot project.
Introduction
Laboratory and theoretical work which was done to determine a suitable tertiary recovery technique for the Bell Creek Muddy Sand indicated that it is exceptionally well suited to a micellar—polymer type chemical flood. Furthermore, this work forecasts a potential recovery of 45 × 106 bbl (7.2 Mm3) of additional oil through field wide application of a micellar-polymer process. To provide the best possible chance of duplicating these promising possible chance of duplicating these promising results under field conditions, a prime concern is the design and operation of field facilities that will allow placement of the chemicals in the reservoir at their optimum conditions. This paper reviews the Bell Creek pilot field facilities design and operation. Problems encountered in the pilot design and operation are covered. Design changes applied to the pilot facilities as well as future design changes which appear warranted are presented.
RESERVOIR PROPERTIES
Reservoir rock and fluid properties are an important consideration in the design of pilot facilities. The productive interval in the field is developed in offshore sandbar and deltaic deposits of the lower Cretaceous Muddy sandstone at an average depth of 4,500 feet (1370 m). The micellar-polymer pilot lies in the extreme northern end of the field (Fig. 1) in an area previously swept by a line drive waterflood. The Pilot consists of one confined 40 acre (1.6 × 105 m2) five spot developed in a total 160 acre (6.5 × 105 m2) area (Fig. 2) and contains four injection wells and nine producing wells. Average net thickness of the producing interval in the pilot area is 8.1 feet (2.5 m) while porosity averages 29% and permeability is 1050 MD porosity averages 29% and permeability is 1050 MD (1 mu m2). The reservoir is water wet and has a residual oil saturation of approximately 35% based upon material balance calculations. The oil is a sweet paraffin base crude of 32.50 API gravity with a viscosity of 2.75 Cp (3 mPa.s) at saturation pressure. Water in the reservoir prior to initiation pressure. Water in the reservoir prior to initiation of the pilot had a total dissolved solids content of 3540 PPM; however, make-up injection water is being produced from the Madison formation for injection produced from the Madison formation for injection into the Muddy Sand. This Madison make-up water has a total dissolved solids content of only 1060 PPM. PPM.
MICELLAR PROCESS
The micellar process chosen for the Bell Creek pilot is of the oil external type developed by Union pilot is of the oil external type developed by Union oil Company of California (Uniflood process). It consists of a caustic-water preflush injection volume, an oil external micellar volume, and a polymer-water mobility control volume. Handling and polymer-water mobility control volume. Handling and injection of the various components is a very important consideration in the facilities design and description of the composition and volume of each of these steps follows.
PREFLUSH INJECTION PREFLUSH INJECTIONA reservoir conditioning preflush comprising 16% PV (352,000 bbl (5.6 × 104 m3)) began the chemical PV (352,000 bbl (5.6 × 104 m3)) began the chemical injections. The preflush consisted of softened water containing .661% caustic soda and .520% sodium silicate. The chemicals were intended to increase the Ph of the reservoir fluid and to neutralize the Ph of the reservoir fluid and to neutralize the calcium and magnesium already existing in the reservoir. This phase of injection was accomplished by premixing volumes of softened water, caustic soda, and sodium silicate in tanks prior to injection.
An alkaline-surfactant-polymer flood was initiated in September 1987 in the Minnelusa Lower "B" sand at the West Kiehl Unit. Subsequent to unitization, two producing wells were drilled outside the Unit boundary. While this extended the productive geologic interpretation of the field, it did not effect the Unit interpretation of the alkaline-surfactant-polymer flood. Production from primary and chemical injection into State 31-36 through November 1991 resulted in 517,521 barrels of oil (82,279 m3) from the Unit wells, of which 456,361 barrels (72,555 m3) were from the area swept by injection into State 31-36. The two Kottraba wells (north of the Unit) have produced 180,686 barrels of oil (28,727 m3) as of November 1991. The original average oil saturation in the gross swept area was 71.8% PV (69.0% PV in stock tank barrels). The gross swept pore volume of the Unit is 1,294,800 barrels (205,857 m3). The oil recovery efficiency in the gross swept area as of November 1991 is 51.1% OOIP. Projected ultimate production from the gross swept area is 541,158 barrels of oil (86,037 m3) or 60.6% OOIP.
Projected ultimate production from the Unit is 602,318 barrels of oil (95,761 m3). This compares with a primary plus waterflood oil recovery estimate of 39.9% OOIP recovery for the West Kiehl Unit gross swept area. Comparison of the oil recovery efficiency of the West Kiehl with other Minnelusa waterfloods and polymer floods suggests the West Kiehl has out performed these other Minnelusa floods. Using the Slider technique, the displacement efficiencies of the areas swept by the State 32-36 and State 42-36 in the Unit and Kottraba Federal 2515 were 71.3%, 52.7% and 58.1%, respectively. Comparative efficiency factors for a waterflood in the Hamm Unit and a polymer flood in the OK Field are 28.5% and 45.6%. The West Kiehl, OK Field, and Hamm Unit are all Lower "B" Minnelusa Fields. A total of 184,794 incremental barrels of oil (29,380 m3 ) are projected for the Unit at an incremental cost of 2.13 per incremental barrel of oil ($13.40 per m3).
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The Viraj oil field lies in Ahmedabad-Mehsana tectonic block of Cambay Basin in India. The field has been under exploitation for the last nearly two decades and produces 18.9°API oil from the sandstone reservoir with an average porosity of 30%and permeability ranging from 4.5 to 9.9 Darcy. Reservoir temperature is 81°C and initial reservoir pressure is 135 kg/cm2. Ultimate oil recovery estimated from the field, producing under active water drive, is 32 % of OIIP.
After analyzing the rock and fluid properties, extensive laboratory studies were undertaken on native cores by R & D institute of ONGC to evaluate the efficacy of Alkaline – Surfactant – Polymer (ASP) process in Viraj field. Laboratory studies indicated an incremental oil recovery of 18 % of OIIP over water flood. On the basis of these encouraging results, a pilot was designed with four inverted 5-spot patterns. Facilities have been created to ensure proper dosing of chemicals, optimum fluid injection and monitoring of injection fluid quality. A comprehensive data-acquisition strategy has been adopted right from the beginning. First phase of the pilot i.e. injection of Pre-flush and ASP slug(20 % PV) having composition of 1.5 wt.% alkali, 0.2 wt % (100% Active) surfactant and 800 ppm anionic polymer have been completed.
This paper aims to present salient features of the laboratory findings and the ASP pilot in progress. The data generated during the first phase of the pilot analyzed and presented in this paper shows encouraging results. Final evaluation of the pilot is, however, planned after completion of the targeted ASP/Polymer/Chase water injection.
Single well chemical tracer tests (SWCT) were carried out at the VLA-1325 well located in Lagomar, C4 reservoir, Lake Maracaibo, Venezuela, to measure residual oil saturation in zone C4-U3 before and after an ASP injection, in order to determine the swept efficiency of a custom made blend. The tests included: Phase I, measurement of residual oil saturation to water (SorW) of the pay zone, previous to an ASP application and after waterflooding procedure; Phase II, application of an ASP blend, specially designed for the aforementioned zone; and Phase III, second measurement of residual oil saturation to ASP (SorASP) after ASP application.
The results show that prior to the ASP injection, the residual oil saturation at the VLA-1325 was (31 ± 3)%. This saturation measurement represents pore space in a 6.7 m (22 ft) thickness portion (1,842.4 - 1,849.1 m; 6,048 - 6,070 ft) of the C4-U3 zone from the well bore to a radial position of about 3.04 m (10 ft). A few days after this initial residual saturation, measurement was completed. A 0.35 porous volume, Vp, (1,750 bbl) ASP injection was carried out in the same 6.7 m (22 ft) completion of the C4-U3 zone. This ASP mixture was followed by 0.15 Vp (750 bbl) polymer drive solution, and a 1.2 Vp (6,000 bbl) of fresh water to push the ASP mixture and any mobilized oil about 15.8 m (52 ft) away from the test well-bore. After ASP treatment, the residual oil saturation measurement was repeated in the same pore space as the initial SWCT test investigated. This post-ASP flood SWCT test showed that the residual oil saturation in this pore space had been reduced to (16±3)%. This reduction in the SorW represents (48±1)% mobilized oil by the chemical treatment. The reported Sor measurements represent the average Sor s for the sub-zones penetrated by the tracer fluids during the test. The field data recorded during the test are presented, and compared with best-fitting simulation model results.
Caltex Pacific Indonesia (CPI) recognizes the enormous potential that a large scale tertiary enhanced oil recovery (EOR) project like Light Oil Steam Flood or Surfactant Flood can have on extending the operations in Minas oil field well into the 21st century. With 4.5 billion barrels of remaining target oil, a successful tertiary EOR process will have a significant economic impact on future operations. Tertiary projects are capital intensive and carry a high degree of risk, however, decision analysis (DA) studies for Minas indicate they have tremendous upside potential. In depth EOR screening identified two major processes for potential application in this high temperature, shallow reservoirs: Surfactant Flooding and Light Oil Steam Flooding. A successful Surfactant Field Trial in Minas will pave the way to potentially implement the process in several CPI fields in the Central Sumatra Basin.
The Minas Surfactant Field Trial is a unique project where two new low-cost surfactant systems, Lignin II and Synthetic Petroleum Sulfonate, have been specifically designed for Minas reservoir conditions. Lab tests indicated significant and comparable recovery from both systems in Berea and field cores. They are ready to be tested in the field for the first time.
Four different polymers, designed to provide a favorable mobility ratio in displacing the surfactant, will also be tested to select the most cost-effective system for Minas' high temperature environment. The purpose of the Field Trial is to validate the lab results, reduce the range of technical and economic uncertainties associated with recovery efficiency and field operations, and select the most cost-effective surfactant for field scale application.
The Surfactant Field Trial area is a 4.3 acre, 5-spot pattern utilizing 4 injectors and one central producer. Five sampling wells and four observation wells will be drilled to monitor the flood performance in both the A1 and A2 sands. The evaluation of flood results have been based on actual log and core data collected before, during and after surfactant injection. A reservoir simulation model will be used to history match production performance and to scale up the process for field wide performance predictions. The selected finite difference simulation package is equipped with surfactant and polymer options.
This paper will discuss both reservoir and facility aspects of the Surfactant Field Trial design and implementation. In the future, actual recovery efficiency of both surfactant systems will be reported and compared to performance predicted from laboratory test results & reservoir modeling.
Historically surfactant floods have not been viewed favorably due to their high cost & moderate recovery1. However, the low cost of production of Lignin II and Synthetic Petroleum Sulfonate may change the way we view surfactant flooding if their high recovery is proven in the field trial.
Introduction & Overview
The giant Minas Oil Field, located in the central Sumatra basin, is a faulted transgressional anticline approximately 28 km long by 10 km wide. Shown in Figure 1, Minas is one of the largest oil fields in Southeast Asia, with estimated original oil in place of about 9 billion barrels. Discovered in 1944 and placed on production in 1952, Minas has produced over 4.2 billion barrels of oil to-date. The primary reservoir consists of five major sand bodies within the Sihapas Formation, designated as A-1, A-2, B-1, B-2, and D sands. A Minas type log displaying the Sihapas sand package is shown in Figure 2. These sands have an average total gross thickness of approximately 260 feet and lie at a depth of about 2000 feet sub-sea.
Introduction
Amoco Production Company is conducting a tertiary micellar pilot flood in a high-temperature (200 degrees F) reservoir in the Sloss Field, Kimball County, Nebraska. The well arrangement is an isolated nine-acre normal five-spot pattern (Figure 1). The primary objectives of the pilot are:to demonstrate that the recovery method mobilizes and efficiently displaces the tertiary oil remaining after waterflooding andto establish technology which will permit reliable projections of fieldwide performance.
This pilot flood is "unconfined" with respect to the perimeter of the pilot area, the pilot injection-withdrawal ratio (IWR) being slightly greater than unity. Because of this factor, the flow configuration, i.e., streamline geometry, is different from that for a fieldwide flood. A portion of the tertiary oil recovery will come portion of the tertiary oil recovery will come from outside the pilot area. From an interpretability standpoint it is important that the pilot flow paths and area contributing to the pilot pilot flow paths and area contributing to the pilot production remain as constant as possible with production remain as constant as possible with time. To achieve this, the pilot design and operation were based on maintaining the IWR of each injector-producer pair constant with time.
The design sequence of injection consists of four fluids: preflush water, micellar, polymer, and, finally, chase water until termination of the process. The micellar formulation was designed to process. The micellar formulation was designed to efficiently displace tertiary oil and be stable at the reservoir temperature of 200 degrees F. The mobilities of the micellar and polymer were adjusted so that they were approximately equivalent to the mobility of the tertiary oil-water bank.
To be able to adequately interpret pilot performance, a good reservoir description is performance, a good reservoir description is required. Therefore, prior to initiation of micellar injection, a comprehensive program was conducted to obtain a reservoir description. The program consisted of coring, logging, production program consisted of coring, logging, production tests, pressure transient tests, pulse tests and tracer injection. In addition, a geological study was made. A detailed reservoir description of the area affected by the pilot flood was obtained. With this description, micellar flood performance predictions were made to determine expected injectivities and oil recovery and response.
Micellar injection was initiated on February 26, 1977. Polymer injection commenced on March 30, 1977, and is still in progress. A definite tertiary oil response has occurred. In this paper, pilot performance through mid-January, 1978, is summarized. performance through mid-January, 1978, is summarized.
MICELLAR FLUID FORMULATION AND TESTING
The Sloss Muddy J reservoir conditions are basically amenable to micellar flooding. The porosity is 17 percent, the permeability is 80 md, the inplace water is fresh (TDS = 2500 ppm, hardness = 50 ppm) and low salinity water is available (TDS = 260 ppm, hardness = 25 ppm). The high temperature (200 degrees F) of this reservoir makes it a unique pilot. The National Petroleum Council study of 1976 projected temperatures Petroleum Council study of 1976 projected temperatures of only 170 degrees F for current technology. In particular, thermal stability of polyacrlyamide molecules has not been tested under actual high temperature reservoir conditions.
The micellar fluid for the Sloss pilot was designed by going through a series of tests similar to that described earlier. Principal components finally selected for these tests were Amoco Mahogany AA sulfonate (62% active), isopropyl alcohol (IPA), Dow pusher 700 polymer, Great Salt Lakes Minerals and pusher 700 polymer, Great Salt Lakes Minerals and Chemical Corporation sodium chloride, and Sloss fresh water. These were chosen on the basis of availability, performance, and stability. Similar laboratory systems performance, and stability. Similar laboratory systems have been extensively studied.
A successful surfactant (microemulsion) flood pilot est has been completed by Exxon in a watered-out portion of the Weiler sand, Loudon Field, Fayette County, Illinois. The microemulsion system tested was designed to be effective in the presence of high-salinity formation water containing 104,000 ppM (mg/l) total dissolved solids (TDS) without use of a preflush. The test was conducted in a single, 0.68-acre 5-spot operated to approximate a confined pattern. Approximately 60 percent of the waterflood residual oil present in the pilot pattern was recovered. Extensive data for determining sweep and displacement efficiencies were obtained from observation well logs and fluid tracers. Although problems were encountered with bacterial degradation of biopolymer and with produced oil-water emulsions, the test is considered to be a technical success and confirms the effectiveness of the high-salinity microemulsion formulation. Additional pilot tests are needed to determine the effects on oil recovery of microemulsion bank size and well spacing.
This paper describes field operations with attendant problems encountered during a micellar polymer flood process in the Hxa sand of the Wilmington Field, California.
Problems encountered include completion techniques, extreme corrosion, emulsions of produced fluids, and field handling of polymer.
The micellar polymer flood described here is Marathon Oil Company's Maraflood (TM) process and was designed by Marathon after much laboratory and field testing. The project was co-sponsored with D.O.E. and the City of Long Beach with the goal of establishing a tertiary oil recovery technique applicable to unconsolidated oil sands typical of the California region.
The test pattern selected, after conducting several computer model studies, is a staggered line drive consisting of four injection wells and six producing wells, with all injectors backed up by a North South trending fault. The sand selected for this pilot is located in the watered-out area of the Hxa sand of the Upper Terminal V-B Pool. Selection was made because of sand thickness, uniform sand body, good permeability, and because it was a watered out area which would facilitate the project evaluation.
The pilot project includes a total oil sand volume of 596 acre-feet underlying an area of about ten acres ith an average net sand thickness of 58 feet (17.7m). The permeability to air is about 400 md. The residual oil saturation after water flooding is estimated to be 38%. Recovery to date is estimated to be 38% of the 445 M barrels (70749 m3) of oil in place at the beginning of this project. The incremental oil recovery is expected to be 176,000 barrels (27982 m3) at abandomnent time.
The importance of this test is not only to determine he validity of the process in watered out areas of the vast Wilmington Field, but to determine and overcome field operating problems associated with a micellar polymer flood.
Gary Energy Corporation is conducting a DOE Pilot Demonstration to determine whether micellar-polymer waterflooding is an economically feasible technique for enhanced oil recovery at the Bell Creek Field, Powder River County, Montana. The pilot is a contained 40-acre 5-spot embedded in a representative watered-out portion of the field. The reservoir is sandstone with an average net pay of 6.4 feet, air permeability of 1050 md, porosity of 29%, and water TDS of 4000 ppm. The pilot has four injectors (Wells MPP-1, MPP-2, MPP-3 and MPP-4) and one producer (Well 12-1). The overall micellar-polymer oil recovery is estimated at 47% of the remaining oil at the initiation of the micellar-polymer flood.
Since the last review of this project* the micellar slug and approximately one-half of the polymer slug have been injected. Problems encountered during chemical injection and their treatment are discussed. A review of the produced fluid data is presented; and the numerical simulator prediction of oil recovery, completed prior to initiation of chemical injection, is compared to field data. Pilot costs and derived economic ratios are set forth. Finally, the evolution and structure of a post-pilot analysis are presented.
This paper describes the design of a micellar/polymer system to displace the heavy crude from a Wilmington Field, California, reservoir. Pattern design, transient testing, and the injectivity test are discussed also. The design problem was complicated by the unconsolidated nature of the reservoir rock. Initial design work was performed in sandpacks with available sand samples. After confirmation that a viable micellar/polymer solution could be designed, fresh cores were obtained. These cores were frozen at the wellsite and thawed only after placement in a laboratory core holder. System optimization work then was conducted. This work was complicated by some unusual problems.
Introduction
The HXa subzone of the Upper Terminal of the Wilmington field produces a 35-cp (0.035-Pa.s) oil with an API gravity of 18 degrees (0.95 g/cm3). This is considered the heaviest oil for which a micellar/polymer process has been designed. A good system design requires extensive laboratory core flood testing using actual reservoir fluids and actual reservoir rock. The latter requirement was complicated by the fact that the upper terminal sand is unconsolidated.This paper describes problems and procedures used to overcome those problems in preparation for a test [approximately 10 acres (40 500 m2)] of Marathon Oil Co.'s Maraflood process in this field. The City of Long Beach operates this property with Long Beach Oil Development Co. as its sub-contractor. This project is cosponsored by the U.S. DOE. More details may be found in the first and second annual reports published by the U.S. DOE on this project and the pending third annual report.
Core Flooding Procedure
The core floods were conducted with a radial core flood apparatus designed at Marathon's Research Center in which actual reservoir core material was used. Fig. 1 shows how a reservoir core disk is flooded. The core holder was adapted to take a 5 1/2 in. (14-cm) diameter core. Flooding was from the center to the outer perimeter. Overburden pressures were maintained by axial loading. The Phase A core floods used available unconsolidated upper terminal and Ranger sand samples. The samples were (1) cold cleaned with a series of solvents, (2) vacuum dried and (3) packed into the core holder. The sand was
packed in synthetic produced water and then dried. It then was (1) saturated with the synthetic produced water, (2) flooded with reservoir oil to residual water and (3) flooded with water to residual oil. At this point, the micellar/polymer fluids were injected. The core floods were conducted in a constant-temperature bath maintained at the mean reservoir temperature of 125 degrees F (52 degrees C). Overburden pressure of 1,400 psi (9653 kPa) was maintained. Core pore volume and water permeability were determined during the water saturation phase of the operation.A constant-rate nonpulsating positive displacement pump was used to displace fluid. Each core was flooded with 1.5 PV of fluid from the center to the outer perimeter. Pressures were measured at the injection point and at the two locations across the top of the core as shown in Fig. 1. Produced fluids were collected and measured to determine oil recovery.Pressure data gave indication of the mobility control achieved in the core floods. The ring between the wellbore and the first tap includes 7.7% of the core pore volume. The first and second taps encompass the pore volume from 7.7% to 32.5%. The second tap to perimeter encompasses a pore volume from 32.5 to 100%. A reciprocal relative mobility was obtained by rearrangement of the Darcy radial flow equation for radial conditions.
JPT
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