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IOR 2019 – 20th European Symposium on Improved Oil Recovery
- Conference date: April 8-11, 2019
- Location: Pau, France
- Published: 08 April 2019
1 - 100 of 122 results
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Mobilization of By-Passed Oil by Viscous Crossflow in EOR Processes
Authors K.S. Sorbie and A. SkaugeSummaryWe believe that the main target oil for all EOR methods is essentially “bypassed oil” at several length scales from the pore scale, to the core scale, to the bed-form scale, to the reservoir layer scale; indeed, at all the scales of heterogeneity present in an oil reservoir. Thus, a waterflood applied as a secondary recovery process will “bypass” oil at all of these scales leaving behind potentially mobile oil, resulting in a lowered recovery factor. The role of most EOR processes – and here we specifically focus on polymer flooding and WAG – is to improve oil recovery by producing as much of this bypassed oil at all scales as is physically possible.
Conventional polymer flooding is often described as simply “mobility control” implying that a viscous oil linear displacement efficiency may be improved by viscosifying the injected brine. In fact, this is a secondary effect in most polymer floods in the field, even for viscous oils. Frequently, a more important mechanism is viscous crossflow (VX), not just in layered reservoir systems (where it is indeed an efficient mechanism), but in any heterogeneous reservoir system. Where there is heterogeneity at the pore scale, core scale and upwards, this viscous crossflow mechanism is generally present and is the main, or at least an important, contributor to oil recovery improvement.
In this paper, we will use examples from various studies of polymer displacements at the pore, core and field scales to demonstrate the above claims. Furthermore, recent work now shows that the VX mechanism also plays an important role in near-miscible WAG which will also be described briefly here.
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Polymer Flood in Offshore Viscous Oil Reservoirs: Implementation, Performance and Reservoir Management
Authors X. Lu, D. Puckett, J. Xu and Y. LiSummaryPolymer flood applications in offshore fields face more challenges than that of onshore fields. These challenges include limited platform space, costs to transfer polymer chemical, short service life, large well spacing, reduced polymer viscosity when mixed with sea water, and lack of analogs of practical polymer flood projects implemented in offshore. The above challenges make it's hard to directly apply the onshore polymer flood technologies and experiences proved successful.
Taking five offshore viscous oil polymer flood projects as examples, this paper summarizes their implementation, production performance, reservoir management and lessons learned during pilot or field-wide polymer flood process. These projects cover cases in both shallow and dep water, and polymer flood beginning at early, interim, and mature development stages with water-cut < 20 %, between 20% and 60%, and >60%, respectively. Targets of these projects are all high-quality sandstone reservoirs with oil viscosity at reservoir condition varying from 11 to 88 cP. These projects were implemented in phase from single well injectivity test, pilot, to field, achieving an incremental recovery from 4% to 7%.
For the mature field cases, water-cut performance is characterized by typical funnel-shape, experiencing process of decreasing, stabilizing at low, then back to the high level. This corresponds to oil rate changes of the increasing, maintaining at a high, and then drop to low rate production. For the case of polymer flood starting at early development stage, the funnel-shape will never occur. Instead, water-cut rises sustainably, while its increasing trend is obviously arrested.
Effective polymer flood process shows increased injection pressure and resistance factor, dropped water-intake index and improved injecting profile. Production responses to polymer injection is generally earlier than polymer breakthrough timing with average responding duration of 2.6 years comparing with that of average polymer breakthrough of 4.8 years in specific cases.
Lessons learned are: (1) early polymer flood could be a strategy for offshore field, which recovers oil in short time, saves the cost of production fluid processing as well as achieves relatively higher recovery factor; (2) mechanic degradation at the near wellbore is the main source of polymer degradation due to permeability impairment caused by poor quality produced water injection. Rather than the most popular HPAM, the salinity and shearing resistance polymer such as hydrophobic associated polymer is a better solution; (3) effective reservoir management such as zonal polymer solution injection and gel plus polymer flood injection benefits for improving polymer flooding.
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Successful Polymer Pilot Boots 1P, 2P, 3P Reserves in CGSJ: Four Converging Methods
Authors J. Juri, F. Schein, A. Ruiz, V. Serrano, M. Thill and P. GuillenSummaryReliable estimation from successful polymer pilots to multiple expansion scenarios (full-field and analogs) are of fundamental importance for booking polymer flooding reserves.
Here we propose a methodology of four methods (geometrical WOR vs. Np, volumetric, ratio 1P waterflooding to P1 polymer flooding and numerical simulation) to estimate 1P, 2P, and 3P using multiple sources of information. Our results developed criteria to jointly define 1P, 2P and 3P reserves from a successful pilot implemented in Cuenca Golfo San Jorge. These four methods approach makes it easy to cross-check the key parameters that describe the efficiency of polymer flooding, i.e., displacement efficiency, volumetric efficiency. Therefore, they verified the consistency of the results. In addition, the results provide an estimation of the variability that allowed us to add additional criteria to determine 1P, 2P and 3P reserves.
Our studies reveal new aspects of practical usage of the WOR vs Np approach for polymer flooding which need to be taken into consideration for booking reserves. The geometric WOR vs Np method is scale invariant, namely it can be applied with consistency across multiple group of well through the reservoir. We validated this approach with the results of the pilot and testing it with multiple scenarios generated by the simulator. The results obtained in terms of recovery factors throughout different layers and zones in the reservoir agreed well with the upscaled recovery factor obtained in multiple corefloods
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ASP Pilot Trial in Canada Using a Formulation Based on a Novel Associative Polymer
Authors R. Reichenbach-Klinke, R. Giesbrecht, P. Lohateeraparp, G. Herman and K. MaiSummaryAlkali-surfactant-polymer (ASP) flooding is a common chemical enhanced oil recovery (EOR) method. Large full-field applications are limited, but there are numerous pilot trials reported. One reason for the lack of full-field implementations might be the comparatively high chemical cost of the ASP formulations. Hence, there is a continuous need for improving the cost and/or performance of the system. In this regard, new ASP formulations based on hydrophobically modified polyacrylamides, also known as associative polymers, were developed and the best performing candidate was evaluated in a pilot in a heavy oil field in Canada. The major motivation to use an associative polymer was to make use of its superior in-situ viscosifying performance compared to regular polyacrylamide polymer (HPAM). As a high in-situ viscosity was targeted to prevent influx from the aquifer in the reservoir.
Altogether, more than ten different ASP formulations were investigated in sandpacks with cleaned and crushed rock material from the field. A high tertiary oil recovery of almost 69% was observed for an ASP formulation including chelating agent, sodium hydroxide, an alkylether sulfate surfactant and a novel hydrophobically modified polymer.
The field application of this formulation commenced at the start of 2017 into three horizontal injection wells and concluded in Q2 of 2018. Injectivity was proven to be very good. It even did improve if compared to the alkali-polymer injection with a different polymer which was conducted in advance to the ASP pilot. Despite an increase of the injection rate from around 50 m3/d to approx. 70 m3/d, the wellhead pressure dropped from initially 1500-1600 psi down to approx. 1200 psi. This can be possibly explained by the good dissolution characteristics of the polymer, as also confirmed by the less frequent filter changes. Polymer effluent was detected in several production wells, which indicates a good propagation of the polymer through the reservoir. In August 2017 the oil-cut in several producers increased. However, this increase was not sustainable and it was concluded that the dilution effect of the aquifer was too strong to continue the chemical flooding operation.
Altogether, it was shown that the combination of an alkylether sulfate surfactant and a hydrophobically modified polymer revealed excellent injectivity and good propagation through the reservoir. However, a drawback was the strong aquifer effect, which made the additional oil recovery only moderate. This effect needs to be managed more carefully for future chemical EOR program plans.
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Grimbeek Successful Polymer Pilot Extends to 80 Injectors in Factory-Mode Development at CGSJ Basin
Authors J. Juri, A. Ruiz, F. Schein, V. Serrano, M. Thill, P. Guillen, A. Tosi, M. Pacchy, L. Soto, A. Therisod, M. Paura, P. Lauro and P. AlonsoSummaryAfter the successful pilot (14%OOIP incremental oil, Juri et al. 2017 and utility factor of 2 kg polymer/bbl), a series of multiple simulations cases indicated an optimal extension of 3-year cycle factory-mode development. The initial cycle affects 80 polymer injectors distributed in multiple injection satellites across three multilayer reservoirs. After the 3-year cycle, we rotate the polymer skids to other satellites.
The satellites emanate from a peripheral aqueduct that encircles the reservoirs. Each satellite has 8 to 10 injectors (each well injects 100 m3/day in an average net thickness of 18 m). The total number of injectors is 59 in the Grimbeek-2 block, 40 in Grimbeek-North block and 20 injectors in the Grimbeek-North-2 block. Injection in the remaining well will start in the second 3-year cycle.
Here we report the use of reservoir simulation to design the entire architecture of the development which includes both the optimum injection period and the number of satellites under simultaneous injection. The strategy is based on the plug-in concept in which we minimise the footprint and we maximise the use of current surface facilties connecting the polymer skids to the waterflooding satellite.
We tracked the oil that is swept by the injectors in each satellite. The simulation methodology extracted the incremental oil of each satellite because of polymer injection. We found that between 2.5 to 3 years polymer injection cycle and eight simultaneous polymer injection skids minimise the utility factor (kg of polymer injected per bbl of incremental oil above waterflooding baseline). After the 3-year cycle, the eight polymer injection skids rotate from the initial eight satellites to eight new locations, and water injection follows on the initial satellites. This strategy minimises CAPEX, OPEX and the risk of polymer production compared to the scenario of injecting in all wells in the same manner as waterflooding was implemented.
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Synthesis and Characterization of a Reactive Fluorescent Tracer and its Possible Use for Reservoir Temperature's Data Collection
Authors M. Ould Metidji, M. Silva, A. Krivokapic and T. BjørnstadSummaryTracer technology for well experiments is one of very few applicable technologies for collection of unique dynamic data of reservoir flows. Two main tracer tests are commonly used for reservoir characterization: (i) the Single-Well Chemical Tracer Test (SWCTT) and (ii) the Inter-Well Tracer Test (IWTT) which includes Partioning Inter-Well Tracer Tests (PITT). SWCTT and PITT give access to the residual oil saturation (SOR) respectively in the near-well and interwell regions. Non-partitioning IWTT allows assessing qualitatively and quantitatively interwell flow connections, swept volumes, etc., resulting in an improved reservoir model.
We have previously introduced the concept for a new class of potential partitioning fluorescent tracers for SWCTT tests (IOR 2017 in Stavanger, Norway ; EAGE conference). The tracer is a complex compound by an organic chelate and a fluorescent metallic center. The results have shown that it was possible to functionalize the chelate with an ester function to theoretically increase the affinity of the final complex for the oil phase. However, the complexation of the new modified chelate with the metallic center was not solved.
In the present study, the complexation strategies and characterization tools for detecting and quantifying the tracer will be discussed. Especially, High-Performance Liquid Chromatography (HPLC) coupled with a Time-Resolved Fluorescence (TRF) detection allowed separating the different partitioning compounds and their passive form with a high specificity. A series of partitioning tests have been carried-out using synthetic production water and both synthetic oil and a crude oil from the Norwegian continental shelf.
Against the expectation, close to 100% of the ester tracer was found in the aqueous phase after contact with the oil. This result has been confirmed for two tracers with different ester chain length (ethylester and butylester). Liquid Chromatography coupled with Mass Spectroscopy (LC-MS) characterizations performed on the butylester form before and after contact with oil have confirmed the observations and results obtained by HPLC. Moreover, the LC-MS characterization provided a better understanding about the environment of the metallic ion, particularly on its degree of complexation which suggests that most of the final complex is negatively charge.
Given that the reaction of hydrolysis of the ester is dependent on temperature, pH and salinity the tracer could be relevant as a “probe” to obtain accurate data on those three parameters in-situ. The ester has in this case no partitionning behavior and any changes in the previously cited parameters will affect its kinetic of hydrolysis.
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Alkylpyrazines - from the “Dinner Table” to the Oilfield: A New Class of Partitioning Tracers
Authors M. Silva, M. Ould Metidji, H. Stray and T. BjørnstadSummaryA partitioning inter-well tracer test (PITT) is a dynamic tool to measure the residual oil saturation (SOR) in the swept volumes of oilfields. Knowledge about SOR is an important parameter in the design of many IOR projects. Such projects are increasingly important to satisfy the global demand for hydrocarbons, as the worldwide number of mature oilfields steadily grows and very few large hydrocarbon rich basins are left unexplored. By performing a PITT before and after an IOR project is implemented, the performance of such project can also be evaluated. PITTs were first used in hydrogeology and introduced in the oil industry in the early 1970s. PITTs never became a routine tool for the characterization of oil reservoirs, however have been receiving increasing attention in recent years. The first PITTs were performed with tracer compounds successfully used in hydrogeology or selected based on the easiness of their analysis. This led often to unsuccessful tests, as the behaviour of the tracers was not well understood in the conditions encountered on the oilfield. Furthermore, environmental regulations on oil&gas production were introduced in recent years (as for example, on the Norwegian continental shelf) which restrict the chemicals possible to use as tracers. The small number of compounds thoroughly investigated and qualified for use as PITT tracer is one of the major obstacles for the dissemination of this technology. It is therefore important to develop new, functional, and environmentally acceptable partitioning tracers.
Alkylpyrazines are heterocyclic aromatic compounds which are major natural constituents of flavour and aroma of many roasted and fermented foods and beverages. Their worldwide annual production is limited to a few tons primarily used by the food industry. Both scientific studies and legal guidelines consider the use of alkylpyrazines as flavour or odor agents in food products to be safe. Many alkylpyrazines exhibit physico-chemical properties which make them interesting oil/water partitioning tracer candidates.
In the present work, we present the studies and laboratory testing performed on selected alkylpyrazines. Experimental and physical-chemical data was analysed to assess the possibility of using compounds from this class of chemicals as inter-well oil/water partitioning tracers. Results suggest that these alkylpyrazines, used primarily as food additives, can be transferred from “the dinner table to the oilfield” as a new class of partitioning tracers to measure SOR in the inter-well region.
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A New Generation of Single Well Chemical Tracer Tests – Tracers and Methodologies
Authors O. Huseby, C. Galdiga, S. Hartvig, G. Zarruk and Ø. DugstadSummaryThe single well chemical tracer test (SWCTT) was introduced in the 1970ies by Deans and coworkers, and is commonly used to assess oil saturation in flooded reservoirs and to identify reduction in oil saturation after EOR. Reactive tracers are injected in a cylindrical volume in push-and-pull tests and the tracer hydrolyze in-situ to generate a secondary tracer. New SWCTT chemicals were piloted in a carbonate reservoir by Al Abbad et al. (2016), to overcome challenges such as flammability and the requirement for large amounts of chemicals associated with commonly used tracers, such as Ethyl Acetate. About 0.1 kg of the new tracers is sufficient, which should be compared to injected amounts up to several hundreds of kg for the traditional tracers.
The reduced tracer amount opens for injection of a cocktail of tracers with different affinity to oil and the individual tracers will explore cylindrical volumes of different radii. This can be exploited to assess gradients in the oil saturation or the fractional flow of oil and water. The new tracers also opens for new and improved operational methodologies (in addition to the obvious related to reducing injection amount). Such improvements include adding tracers in the well using a simple injection system. The chemicals are designed to enable off-site analysis, thus removing the requirement to mobilize a chemical lab to the field. The injection of a cocktail of tracers gives tracer curve pairs of injected and in-situ generated tracers. This abundance of data required implementation of effective interpretation schemes that are also presented.
In this paper, we summarize results findings from tests using the three new sets of tracer in sandstone and carbonate reservoirs. The paper summarizes design considerations and implementation of the tests, highlights operational improvements and demonstrate methods for interpretation of the results. The tracers are all shown to perform successfully at temperatures ranging from 50 – 100 C. They can all be injected simultaneously in a short pulse, and off-site analysis is shown to be a valid alternative to on-site analysis.
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Use of Tracers in the Alkaline-Surfactant-Polymer Pilot in West Salym
Authors A.J. De Reus, V. Karpan, D.W. Van Batenburg and E. MikhaylenkoSummaryAn Alkaline-Surfactant-Polymer (ASP) pilot was executed in the West Salym oil field in the Russian West-Siberian oil province. An extensive surveillance plan was essential to the successful interpretation of the ASP pilot. A tracer program formed a significant part of the surveillance plan. This tracer program was designed and executed to A) understand the connectivity and sweep between the pilot wells and B) to determine the change in saturations due to ASP flooding. This paper focusses on the results of the tracer program.
The West Salym reservoir is a sandstone formation with temperatures as high as 83 °C, low crude oil viscosities of about 2 cP and permeabilities ranging from 10 to 250 mD. The main oil bearing sand bodies are stacked deltaic sandstones interceded with shales. Individual sand bodies are relatively long, narrow and internally inhomogeneous with porosity ranging from 18 to 22%. The field is waterflooded, with oil production having peaked in 2011. To increase the recovery factor, a tertiary oil recovery technique (ASP) was selected.
A confined five spot pattern was selected for the ASP pilot. Four tracer stages were conducted during the ASP pilot, where different tracers were injected in the injectors at the corners of the pilot pattern. Tracer results were analyzed using Shook's method as well as reservoir modelling. The tracer stage during the pilot pre-flush showed a strong drift across the pilot area, resulting in a decision to shut in two producers near the pilot. During the subsequent (ASP) tracer stage, it was confirmed that the drift was reduced, and that conformance had increased due to the viscosity of injected fluids. Analytical tracer analysis was complicated by the production and injection upsets due to scaling, as well as the changes in injected viscosities: the requirement for steady state conditions were not met. Nonetheless, tracer data was important for history matching the ASP pilot dynamic model and determining the chemical sweep. The partitioning tracers in the water post-flush helped to confirm the low residual oil saturation after ASP.
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Towards an Economically Viable (A)SP Flooding Project in West Salym
Authors V. Karpan, J. De Reus, S. Milchakov, S. Volgina, I. Edelman, Y. Volokitin, D. Van Batenburg and A. GromanSummaryWest Salym (WS) is a typical mature West Siberian oil field that has been developed since 2004 and waterflooded since 2005. Oil production peaked in 2012 and despite evergreen waterflood optimization activities the production from WS is declining. Expected ultimate recovery due to the waterflooding is 38% leaving significant oil in place as a target for tertiary oil recovery. The technique, called Alkaline-Surfactant-Polymer (ASP) flooding, was selected as the most suitable for WS reservoir conditions. To assess the technology potential a series of laboratory studies, a Single Well Chemical Tracer field test, and finally a multi-well ASP flooding pilot were executed. With incremental oil recovery of 17% the pilot project has demonstrated the technical success of ASP flooding. Currently, the project team is working on the economic viability of large-scale chemical flooding in WS to ensure further development of the project.
This paper focuses on the workflow developed for scaling up the WS pilot results to a commercial-scale project and on the optimization of chemical flooding efficiency. Realistic representation of complex flow mechanisms and interaction of injected chemicals with the reservoir rock and fluids occurring during the (A)SP displacement is a technical challenge for the evaluation of the potential for a large scale commercial project. Dynamic reservoir modelling has been widely used for this task replacing the analytical techniques under the premise of delivering more reliable results. For accurate modelling of chemical flooding recovery mechanisms, the use of fine grid simulations, rather than coarse grids with upscaled physical properties, is recommended whenever feasible. Additionally, the chemical flooding optimization is an iterative process to find the most economic combination of chemical flood design (concentration of chemicals vs. slug sizes), surface/subsurface configuration and pace of project expansion. Such iterative forecasting combined with the need for fine grid dynamic models is usually associated with long run times.
One key attribute of our approach is the use of modern dynamic modelling software that allows time-efficient modelling of the chemical flooding. A commercial simulator optimized to provide the best parallel performance on multicore platforms was used. The general formulation of the ASP flooding mathematical model valid for both black-oil and compositional descriptions, captures the major chemical flooding effects i.e. modification of relative permeability, interfacial tension, water viscosity, interaction and retention of injected chemicals, etc.
The developed workflow has been successfully utilized to predict and optimize the performance of (A)SP flooding scenarios in tertiary mode for the West Salym oil field.
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In-depth Experimental Studies of Low-Tension Gas (LTG) in High Salinity and High Temperature Sandstone Reservoir
Authors G. Ren, K. Mateen, K. Ma, H. Luo, G. Bourdarot, D. Morel, N. Nguyen and Q.P. NguyenSummaryLow-Tension Gas (LTG) process has been studied for sandstone reservoirs. In the prior publication ( Nguyen et al. 2015 ), LTG was successfully used to achieve high oil recoveries with the proposed surfactant formulation and injection strategy. Sensitivity to change in optimum salinity was also investigated. However, some questions remained, particularly linked to the sudden drop of effluent salinity and the consequential oil recovery under Type I conditions. In this work, in-depth experimental investigations are carried out to understand the underlying mechanisms. Surfactant flooding without presence of gas is conducted to establish the incremental impact of the microemulsion on oil recovery and pressure drop. Constant salinity core flood experiments were carried out under Winsor Type I conditions at varying capillary numbers to examine the desaturation efficiency. Dynamic foamability tests were carried in the absence of oil to probe the foamability of the developed formula and the contribution of alkyl polyether sulfonate (APS). Effluent salinity when injecting brine only was compared with the case where both brine and gas are co-injected to better understand the role of gas. Further, the importance of foam in the drive was evaluated by conducting LTG without the foaming surfactant in the drive. The dynamic foam tests showed good foamability with the proposed formulation, presence of APS in the surfactant formulation further enhanced the foamability. Surfactant flooding without gas resulted in only 30% remaining oil recovery. Constant salinity coreflood confirmed that the oil recoveries observed under Type I conditions in LTG process indeed can be achieved at the prevailing capillary numbers. The effluent salinity comparison between brine only and brine/gas injections showed significant impact of gas on salinity distribution in the core. Much lower oil recovery was observed and the salinity propagation was delayed when no foaming agent was used in the drive. This implies that foam mobility control is critical for the success of LTG process. It is the first time that in-depth experimental studies were conducted for the LTG process. It improves the interpretation of the findings in prior work, and provides the guidance to the future experimental and theoretical studies.
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How to Select Polymer Molecular Weight and Concentration to Avoid Blocking? Field Practices Experience
By H. GuoSummaryIn current lasting low oil price era, polymer flooding is the most economical mature chemical EOR technique. Following our previous paper focused on theoretical aspect, lessons learned from onshore and offshore polymer flooding practice in China are summarized and reviewed to provide operational guidelines for engineers and insights for researchers. The previous paper ( Guo, 2017 ) focuses on theoretical aspect of polymer molecular cluster size and its blocking mechanisms with strata pore-throat, this paper gives practical aspect of polymer concentration and molecular weight (Mw) selection advice. Polymer flooding has been widely used commercially since 1996 and 1997 in Daqing and Shengli Oilfield, the largest two oilfields in China. Experiences and lessons from commercial polymer flooding practice in China are reviewed. Previous popular criteria in China may lead to blocking in low permeability strata. In addition, difficulty exists to select the proper core samples to represent the target strata. One common practice in Daqing selects the certain content permeability sublayer limit in accumulation curve from coring or logging. However, their blocking mechanisms may be improved. Interests in polymer viscoelasticity effect on displacement efficiency encourages to inject most viscous polymer. However, latest polymer flooding practice in Xinjiang Oilfield in China shows that serious blocking happens. When the concentration and polymer molecular was reduced, field test performance got better. If the injection pressure is high, the planned production volume will not be injected, and the liquid production will drop greatly. The damage of the oil wells and the damage of the injection equipment, as well as failure to inject polymer are signs of formation blockage.The practice of polymer flooding in Shengli Oilfield shows that for high permeability oil layers, the use of lower concentration and medium molecular weight polymers can achieve very good technical and economic effects.
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Dreaming Big “Surfactant Injection in a Giant Offshore Carbonate Field”, From Successful Injection Trials to Pilot Design and Implementation
Authors M. Pal, G. Tarsauliya, P. Patil, N. Rohilla, H. Mounzer, B. Bacaud, S.F. Gilani, A. Katiyar and P. RozwskiSummaryAl-Shaheen Field, offshore Qatar, is responsible for 45% of Qatar's crude oil production. Kharaib,the most prolific reservoir of Al-Shaheen Field, is an oil wet tight carbonate. Even after an extensive water-flooding for several years, there is substantial amounts of oil left behind owing to the highly oil-wet nature of the reservoir. Wettability altering surfactant offers a very promising EOR technique with ability of releasing the residual oil from tight oil wet pores. Three successful short surfactant injection trials have led to comprehensive planning for conducting a long term surfactant injection pilot to evaluate incremental oil gain.
The pilot planning consists of three-tier approach; additional laboratory experiments, reservoir modelling and field implementation. Laboratory experiments were performed to establish surfactant formulation's stability and adsorption in presence of reservoir fluids and rock. Core floods were performed to estimate incremental recovery with different surfactant slug sizes and concentration. Core flooding results were history matched to obtain necessary parameters for field scale modelling. The candidate location was selected considering reservoir properties, operational constraints and implementation feasibility.
The unique ability of this surfactant is to alter reservoir surface wettability with low adsorption on the rock surface and negligible change in interfacial tension. Core flood experiments showed significant oil recovery and field trials showed injectivity improvements which were indication of the wettability alteration to more water wet state. A long term pilot is planned to establish the surfactant EOR potential in Al-Shaheen reservoirs. Several evaluation options for the success of this pilot such as single well tracer test, inter-well tracer test, micro-pilot tests, time lapse saturation logging, and observation wells have been assessed. Reservoir modelling, logistical considerations, field applicability, drilling schedule and cost implications have been considered for determining the most optimum solution to help de-risk field scale implementation. This paper presents a phased approach to scale up an EOR project in a highly complex offshore carbonate field.
A novel EOR implementation approach called S3IP (Surfactant Induced Improvement in Injectivity and Productivity) is applied which results in incremental recovery and injectivity improvement with single EOR agent. The phased approach taken, from screening the surfactants to short term injectivity trials and then continuing to a long term pilot, is unique for the offshore field and the current oil price condition. This pilot will demonstrate the ability to deliver and inject large quantity of surfactant in challenging offshore environment and to exhibit incremental recovery potential of field scale implementation.
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Analyzing the Production Chemistry Data of the North Sea Chalk Reservoirs with a Multiphase Reactive Transport Model
Authors M. Taheri, M. Bonto, A.A. Eftekhari and H. NickSummaryThe production chemistry data contains a wealth of knowledge on the physicochemical interactions of the formation and injected water with the reservoir rock and the hydrocarbons. This is even more pronounced in the highly reactive chalk formations of the Danish North Sea. The interpretation of the data is, however, not trivial due to the short-circuiting of the injected fluid into the production well in the fractured reservoirs, the injection of an often unknown mixture of the formation and sea water, and the reactive flow of brine in the carbonate system that continuously alters the water composition. A reactive transport model that is coupled to the multiphase flow of fluids in a well-characterized geology is a tool that can facilitate the interpretation of the production chemistry data. Our objective is to analyze the production chemistry and water cut data by constructing a reactive transport model that takes into account all the chalk-oil-brine physicochemical interactions. To that end, we use a transport model that is coupled to a surface complexation model, with parameters that are optimized by fitting the model to the chromatographic and zeta-potential data. We also include the dissolution and precipitation rate of different minerals (calcite, magnesite, and anhydrite) in the model. Moreover, we link the chalk and oil altered surface composition in the presence of sea and formation water on the transport properties of the aqueous and oleic phases in the chalk reservoir. To validate the model, we apply it to the Halfdan field, where no short-circuiting occurs due to the near piston-like displacement of the injected seawater in several sectors of the reservoir; moreover, in the Halfdan field data, clear trends in the produced water composition and the water-cut are identified in several production wells.
Our results show that the observed trends in the field data, i.e., a jump in the water-cut followed by an increase in the concentration of certain ions in the produced water, can be explained by our reactive transport model. Considering the so-called smart water effect of the seawater observed previously in the chalk outcrops, we also suggest possible mechanisms for the –possible- improved recovery of oil due to the interactions of the seawater with the chalk-oil-formation water system.
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Analyzing the Smart Water Core-flooding Data in Carbonates by Modelling the Oil Breakthrough Time Using a Novel Reactive Transport Model
Authors M. Taheri, M. Bonto, A. Eftekhari, I.D. Piñerez Torrijos, T. Puntervold, S. Strand and H. Maghami NickSummaryNumerous forced and spontaneous imbibition experiments in carbonate cores have demonstrated that the injection of modified-salinity water with an ionic composition different from the formation water (also called Smart Water) accelerates oil recovery and reduces the remaining oil saturation. Different physical mechanisms are suggested based on the carbonate-oil-brine physicochemical interactions, e.g., wettability alteration due to the ion exchange and surface complexation, carbonate dissolution, and water-weakening (only in chalk). Each of these can be described by relatively accurate thermodynamic models (e.g., ion exchange and dissolution) or a combination of thermodynamics and semi-empirical models. Although there is still an ongoing discussion on the importance and/or relevance of these physical mechanisms, it is widely accepted that due to the change in ionic composition the mobilities of the oleic phase and to a lesser extent the aqueous phase are altered toward a more water-wet state, exhibiting increased capillary forces and improved sweep efficiency. This is reflected in the mathematical models as two sets of relative permeability curves, one for the formation water-oil and modified-salinity water-oil systems. The multiphase flow model switches between these relative permeabilities based on a chosen indicator in the carbonate-oil-brine system, e.g., the total salinity of the brine for simple transport models to the surface density of a complex on the carbonate surface for more complicated reactive transport models. A quick review of the literature shows that apart from the complexity of the reactive transport models and the chosen indicator for the mobility alteration, almost all the proposed models can reasonably fit the measured recovery factors in a selected set of smart water core floodings. This is due to the large number of adjustable parameters in the two sets of relative permeability curves, which makes the choice of physical mechanism for the development of a mechanistic model irrelevant. Here, we address this problem by performing a constrained history matching of the Smart Water core flooding in carbonate cores (limestone and chalk). Moreover, we give a higher priority to fitting the oil breakthrough time during the smart-water injection in tertiary mode. We use an optimized surface complexation model to accurately simulate the adsorption of ions on the carbonate surface at high temperature. We then couple it with an in-house finite volume solver and a state of the art optimization package to obtain the relative permeability parameters. Our results show that the oil breakthrough times can only be correctly obtained by accurately modeling the carbonate-brine interactions and choosing the adsorbed potential determining ions’ concentrations as a mobility-modifier indicator.
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A Modified Derjaguin-Landau-Verwey-Overbeek (DVLO) Model Accounting for Steric Effects at High Ionic Strength: Implications for Low Salinity Waterflooding
Authors H. Collini and M. JacksonSummaryTraditionally, the Poisson-Boltzmann equation is solved to describe the electrical potential in the diffuse layer of an electrolyte adjacent to a charged interface and the electrostatic contribution to the total interaction potential between the interface and the ionic species. A major assumption of the Poisson-Boltzmann equation is that ions act as point charges, which allows for an infinite ion and charge density near to the charged interface, and thus predicts that the zeta potential falls to zero at high ionic strength (typically >0.1M). However, experimental measurements have reported small but measurable zeta potential values at high ionic strength, showing the zeta potential does not tend to zero as predicted.
Electrostatic forces acting between electrically charged mineral-brine and oil-brine interfaces in the classical Derjaguin-Landau-Verwey-Overbeek (DLVO) theory have been used to explain observed increases in oil recovery during low salinity waterflooding. Injection of a low salinity brine is expected to create a more negative zeta potential at the mineral-brine interface. If the oil-brine interface is negatively charged, this increases the electrostatic repulsive force per unit area which, if larger than the disjoining pressure, should lead to improved oil recovery. However, the calculation of the electrostatic forces are normally based on the traditional Poisson-Boltzmann model which underestimates the electrostatic contribution at high salinity.
Here, a modified Poisson-Boltzmann equation ( Borukhov et al., (1997) , Physical Review Letters, 79(3), 435), which accounts for steric effects in the diffuse layer at high salinity but recovers the original Poisson-Boltzmann equation at low salinity, has been combined with a triple layer model which accounts for charge in the Stern layer ( Revil et al., (1999) , Journal of Geophysical Research, 104). This combined model has been used to match experimental zeta potential measurements made on natural, intact sandstones across the ionic strength range 10–5 – 5M, including small and constant zeta potentials observed at ionic strength >0.4M. The effect of this modified Poisson-Boltzmann model on the total interaction potential and DLVO theory has further been investigated. Our relatively simple modification shows that the electrostatic forces at high salinity are larger than previously thought and should not be neglected when calculating total interaction forces. Previous models using classic DLVO theory for understanding low salinity waterflooding may be inaccurate as they incorrectly estimate the changes in the electrostatic forces that occur during injection of low salinity brines.
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Permeability Evolution of Shear Failing Chalk Cores under Thermochemical Influence
Authors E. Kallesten, M. Madland, R.I. Korsnes, E. Omdal, U. Zimmermann and P. AndersenSummaryDevelopment of petroleum reservoirs, including primary depletion of the pore pressure and repressurization during water injection naturally leads to changes in effective stresses of the formations. These changes impose mechanical deformation of the rock mass with subsequent altering of its petrophysical properties. Besides mechanical compaction, chalk reservoirs on the Norwegian Continental Shelf also seem susceptible to mineralogical and textural changes as an effect of the injecting fluid's chemical composition and temperature. Understanding such chemical and thermal effects and how they interplay with the mechanical response to changes in effective stresses could contribute to an improved prediction of permeability development during field life. This article presents results from mechanical testing of chalk cores in triaxial cells allowing systematic combinations of pressure, temperature and injecting fluid, intended to replicate in-situ processes. The sample set consists of water-saturated cores of medium-porosity (32%) outcrop chalk (Niobrara Fm, Kansas). Preliminary results highlight the effect of three different injecting brines (equilibrium sodium chloride NaCl, equilibrium sodium sulphate Na2SO4 and synthetic seawater SSW) at 130°C temperature and low confining pressure (1.2MPa) on the cores’ permeability evolution.
Deviatoric loading above yield resulted in a shear failure with a steeply dipping fracture of the core and a simultaneous increase in permeability. This occurred regardless of the brine composition. However, yield and failure stresses were clearly lower in Na2SO4 and SSW test series in comparison to NaCl tests. In addition, the shear failure caused more axial deformation and a higher increase in permeability in these two test series ( Figure 1 ). During creep and unloading, the permeability changes were negligible, such that the end permeability remained higher than the initial values.
Further investigations regarding the combined effects of confining pressure, water chemistry, and temperature on the rock permeability are still ongoing. The results will, together with experimental data from actual reservoir rocks, not only enhance the understanding of the impact of typical water-related IOR techniques, but also improve the accuracy of reservoir predictions, and contribute to finding smarter solutions for future IOR.
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Multiscale Study of Chemically-tuned Waterflooding in Carbonate Rocks using Micro-Computed Tomography
Authors M.S. Tawfik, Z. Karpyn and R. JohnsSummaryCarbonate reservoirs host more than half of the remaining oil reserves worldwide. Due to their complex pore structure and intermediate to oil-wet nature, it is becoming more challenging to produce the remaining oil from these formations. Over the past two decades, chemically-tuned waterflooding (CTWF) has gained the attention of researchers worldwide. Experimental, numerical, and field studies in this area suggest that changes in injected water salinity and ion composition have the potential to increase oil recovery both in sandstone and carbonate reservoirs via wettability alteration. However, the physico-chemical mechanisms involved in improving oil recovery by CTWF remain poorly understood. This could be attributed to the interplay of several mechanisms at the pore-scale resulting in the incremental oil recovery observed at the macro-scale. It is also mainly due to the lack of consistent experimental data across different scales (i.e.: field scale, core-scale, and pore-scale), reducing the possibility of drawing accurate correlations across length-scales. This study proposes multiscale experimental measurements to investigate the effect of oil composition on the performance of CTWF, where continuum-scale floods are performed to investigate the effect of oil composition on oil recovery from oil-wet carbonate rocks by CTWF. In parallel, in-situ pore-scale measurements of wettability and interface curvature alteration are performed. X-ray microtomography is used to perform direct measurement of changes in interfacial curvatures and in-situ 3D contact angle distributions at the micro-scale at different stages of the CTWF. The study also aims at finding a correlation between the magnitude of improvement in oil recovery at the macro-scale and the corresponding magnitude of wettability alteration at the pore-scale at different conditions. This allows for a better understanding of the physico-chemical mechanisms controlling CTWF, which helps advance currently existing CTWF models, as well as result in more well-informed candidate reservoir selection and the development of a workflow to determine the optimum injection brine properties for a given crude oil-brine-rock system.
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Improving Oil Recovery from Carbonate Rocks Using Compositionally Modified Water Injection
Authors M.T. Al-Murayri, D.S. Kamal, M. Delshad, A. Alizadeh and C. BrittonSummaryThere is a potential to improve oil production from carbonate and sandstone reservoirs by modifying the salinity and ionic composition of the injection brine relative to resident brine. This process can increase oil production in both green and mature waterflooded reservoirs in secondary and tertiary modes. While initial studies focused mainly on sandstones, the fact that carbonate formations host a major portion of the world's known oil reserves has motivated researchers to examine the feasibility of low salinity water injection in carbonates.
Numerous experimental studies have focused on effect of low salinity on contact angle, zeta potential, oil recovery in imbibition tests and corefloods. There is very little experience in the field and limited to single well tests to measure the change in oil saturation with high salinity and low salinity brines.
We have conducted spontaneous imbibition and coreflood using reservoir core from oolitic-carbonate reservoir focused on the effects of injection brine salinity and reactive-ion composition on wettability alteration and oil recovery in calcite-rich carbonate reservoir rocks. Reservoir core plugs were first cleaned with solvent, oven-dried, vacuumed, and saturated with 250,000 ppm TDS synthetic formation brine. Initial water saturation was established by flooding the core with reservoir stock tank crude oil, and the aging with the crude oil was performed at reservoir temperature of 92 ºC and elevated pressure for about two weeks to somewhat restore the native reservoir wettability. Samples were then placed in imbibition cells filled with formation brine to monitor oil recovery by formation brine imbibition. The results indicated very little oil was produced from the plugs indicating mixed wettability.
Incremental oil recovery and rate of oil recovery compared to the formation brine imbibition were evaluated by replacing formation brine with various select-ion brines to gain insights into different recovery mechanisms using diluted injection seawater, and selective modification of the concentration of potential determining ions (PDI). Brine compositions tested were 50,000 ppm TDS seawater, 10 times diluted seawater, variable concentrations of PDI as well as brine containing wettability-altering agents such as surfactants. Fluid pH and IFT were also measured for the oil/brine compositions tested here.
Dynamic oil recovery of the most promising brines was also evaluated in corefloods using stacked reservoir core plugs at reservoir conditions. Effluent ion chromatography analysis was used to investigate the mechanisms and determining ions. Pressure drop at several lengths was monitored for a potential change in permeability due to calcite dissolution/fines migration.
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Zeta Potential in Intact Carbonate Samples: Impact of Brine Composition, Temperature and Wetting State with Application to Controlled Salinity Waterflooding
Authors M.D. Jackson, H. Collini, S. Li, B. Rashid, J. Couves, K. Webb, I. Collins and M. MaynardSummaryLaboratory experiments and field trials have shown that oil recovery from carbonate reservoirs can be increased by modifying the injected brine composition in a process termed controlled salinity water-flooding (CSW). However, the mineral- to pore-scale processes responsible for improved recovery during CSW remain ambiguous and there is no method to predict the optimum CSW composition for a given crude oil/brine/rock (COBR) system. The zeta potential is a measure of the electrical potential at mineral-brine and oil-brine interfaces and controls the electrostatic forces acting between these interfaces. Measured values of zeta potential at the mineral-brine interface in carbonate rocks remain scarce, particularly at reservoir conditions of temperature, salinity and wetting state. Moreover, there are no measured zeta potential data for the oil-brine interface at these conditions.
Here, we report zeta potential measured using the streaming potential method and intact samples of outcrop and reservoir carbonates. Measured values were obtained in clean, water-wet samples and in the same samples after aging in two different crude oils. Measurements were conducted at laboratory temperature, or at elevated temperatures >70°C. In some samples, CSW was then conducted to determine whether changing the injection brine composition increased recovery.
The measured zeta potential in clean samples saturated with synthetic formation brine was consistently positive across all the samples tested, while zeta potential in the same (clean) samples saturated with low salinity brine (dilute seawater) was consistently negative, irrespective of temperature. Consequently, changing the brine composition during CSW from formation brine to low salinity brine in these samples is expected to invert the polarity of the zeta potential.
After aging in crude oil and formation brine, the zeta potential consistently became more positive in samples aged in one crude oil, and less positive in samples aged in the other crude oil. This result can be interpreted in terms of the zeta potential at the oil-brine interface: the crude oil yielding a more positive sample zeta potential after aging has a positive zeta potential at its interface with the brine; the crude oil yielding a less positive sample zeta potential after aging has a negative zeta potential at its interface.
Injecting low salinity brine yielded improved recovery with the ‘negative’ oil, but no response with the ‘positive’ oil, consistent with the hypothesis that improved recovery follows from an increase in the repulsive electrostatic force acting between mineral-brine and oil-brine interfaces.
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A Mechanistic Model for the Fines-migration During the Modified-salinity Waterflooding in Carbonate Reservoirs
Authors M. Bonto, A.A. Eftekhari and H. NickSummaryThe fines migration is one of the most reported mechanisms for the improved oil recovery during low salinity waterflooding in sandstone reservoirs. However, the release of particles and its effect on the recovery of oil from carbonates has received less attention and in this work, we emphasize its role. When injecting a brine incompatible with the formation water, different phases can precipitate which can also lead to more calcite dissolution, releasing some particles from the surface. These particles, together with the detachment of organic layers from the rock surface or the migration of clay minerals present in the formation, can be retained blocking some pore throats and diverting the flow of water to different zones, increasing the sweep efficiency. In the present paper, we first study the mechanical equilibrium of a particle by considering DLVO, drag, lift and gravitational forces, validating the fines migration inferred experimentally from the pressure drop increase for a set of coreflooding experiments. We show that particle detachment occurs also in carbonates when the salinity drops below a certain value. Then, we model the fines migration based on the concept of the so-called critical retention function. Our approach is different from the previous reported models, since we calculate this function from the balance of forces, and not taking it as a constant deduced from pressure drop measurements. Using a constant critical retention function would imply that the electrostatic forces do not change along the core/reservoir, which is definitely not the case for chalk reservoirs, where the calcite minerals are highly reactive. To account for the changes in the electrostatic repulsive forces and therefore in the critical retention function, we couple a CD-MUSIC surface complexation model to our model for fines release. Therefore, at each core position we are able to calculate the critical retention function by considering variables like the ionic strength, pH, pCO2, all of them affecting the electrostatic forces. The main novelty of this work is the coupling of our optimized surface complexation model with the fluid flow, which allows us to better estimate the electrostatic forces, and consequently the critical retention function that will eventually govern the amount of particle released or reattached. With this model, we are able to predict the critical salinity at which fines migration occurs, the transport and capture of the particles, their impact on the effective permeability of water, and the pressure drop profile during low salinity waterflooding.
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Experimental Investigation of Three-Phase Relative Permeability under Simultaneous Water and Gas (SWAG) Injection
Authors L. Moghadasi, M. Bartosek, D. Renna, G. Maddinelli and S. ScagliottiSummaryVarieties of enhanced oil recovery (EOR) processes involve simultaneous flow of two or three immiscible fluids (i.e., water, oil, and gas) in reservoirs. Proper quantification of multi-phase flow processes has considerable economic and scientific importance in management and development of oil- and gas-bearing geologic formations. Relative permeabilities are key rock-fluid properties required for continuous-scale modeling of multiphase flow dynamics in porous and fractured media. A reliable characterization of these quantities, including uncertainty quantification, enables reservoir engineers to assess reservoir performance, forecast ultimate oil recovery, and investigate the efficiency of enhanced oil recovery techniques.
In this work, we report the results of a suite of laboratory-scale experimental investigations of multi-phase (water/oil/gas) relative permeabilities on reservoir core sample. Two (water/oil) - and three-phase (water/oil/gas) relative permeability data are obtained at high temperature of the reservoir by way of a Steady-State (SS) technique. Our laboratory methodology allows improved relative permeability acquisition through a joint use of traditional flow-through investigations and direct X-Ray measurement of the core local saturation distribution. The latter renders detailed distributions of (section-averaged) fluid phases along the core, which can then be employed for the characterization of relative permeabilities. The three-phase Steady-State relative permeability experiments have been conducted by resorting to a dual energy X-Ray methodology. The experimental setup also includes a closed loop system to validate and support saturation measurements/estimates. The SS three-phase experiments are performed by following diverse saturation paths including CDI, DDI, IID and some cycle injection of WAG, where, C, D and I denote as Constant, Increasing and Decreasing (i.e., CDI means Constant water, Decreasing oil and Increasing Gas). Several different flow rate ratios have been selected to cover the saturation ternary diagram extension as completely as possible.
The use of in-situ X-Ray scanning technology enables us to accurately measure depth-averaged fluid displacement during the core-flooding test. We observe in most of the tests, three-phase water relative permeabilities display an approximately linear dependence on its saturation when the latter is subject to a logarithmic transformation. The three-phase oil and gas relative permeabilities, when plotted versus their saturations are scattered by apparently quasi-linear trends, compared to the behavior of water relative permeabilities.
We provide the experimental data set to demonstrate the possible three-phase region and eventually investigate the hysteretic effects on three-phase relative permeabilities. As only a limited quantity of three-phase data are available, this study stands as a reliable reference for further model development and testing.
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Analysis of 3-phase Behavior in WAG Injections for Various Wettabilities
Authors M. Bourgeois, T. Joubert and V.E. DominguezSummaryWAG increments are known to be quite variable, both in the field and in the simulations, and are often analysed by splitting the WAG applications between miscible and immiscible cases.
The authors are quite convinced that the more complex theory combining wettability and interfacial tensions, predicting the wetting order at pore scale, is relevant at core scale, and field scale, and that it could explain some surprisingly good results of immiscible WAG in oil-wet reservoirs, and some disappointing results of miscible WAG in water-wet conditions.
In coherence with this existing theory, we have adapted our wetting model, and extended the Larsen-Skauge model to allow water trapping as well as gas trapping. It allows to reproduce quite well the serious water injectivity limitations for WAG in rather water-wet reservoirs, as well as the absence of this issue in oil-wet operations. We also believe that the 3-phase relative permeability corrections which are applied to the 2-phase inputs need to be consistent with that pore occupancy scheme, and have explained notionally how the parameters should vary with wettability.
Naturally, further work is needed to consolidate these findings, but some suggestions are already made to estimate the new parameters to use with extended 3-phase hysteresis model.
Various representations on ternary diagrams and injectivity plots are proposed, and the link to wettability is discussed.
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Modelling the Transition between Immiscible and Miscible WAG
Authors A. Skauge, K.S. Sorbie and M.I.J. Van DijkeSummaryCurrent WAG modelling is either handling three-phase relative permeabilities with hysteresis and phase trapping, but cannot simultaneously include compositional effects. Whereas, conventional, compositional, WAG models lack the correct multi-phase flow functions (3 phase relative permeabilities, 3PRP). Our objective in this paper is to lay out a programme of research which will close the gap between immiscible WAG and miscible WAG by construction a physics based WAG model that includes best choice of fluid flow functions, saturation dependencies, phase trapping, transition to miscibility, and compositional effects.
We first lay out a mechanistic phase diagram of the 2 major components of any WAG flood immiscible or miscible (more generally near-miscible) , i.e (i) relative permeability effects – flow functiosn and 3PRP and (ii) compositional effects as the gas and oil approach miscibility. At present there is no physically consistent theory which carries over ALL of the various physical effects from the purely immiscible WAG case (with no, or very weak compositional effects) to the near miscible case. As just one example of incorrect physics, the 3 phase wetting order can change as the 3 IFTs change on approach to miscibility; we might think of this change as IFT to gas/oil σgo change towards 0 , but in real systems, the IFT usually decreases and then increases again (as light oil components are stripped out). This wetting change should change the saturation dependencies of the 3PRP functions, but we invariably keep the original form of these functions (e.g.as Stone 1 or 2, which strictly only apply for strongly water-wet systems).
A full agenda laying out all of the required parts of the physics is laid out in this paper and, where the physics is already known, it is briefly explained, and where not some conjectures are made or the challenges are clarified. The authors hope this paper will stimulate both discussion of the physics of WAG processes and more technical research to address the challenges.
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Mesh Adaptivity and Parallel Computing for 3D Simulation of Immiscible Viscous Fingering
Authors A. Kampitsis, P. Salinas, C. Pain, A. Muggeridge and M. JacksonSummaryWe present the recently developed Double Control Volume Finite Element Method (DCVFEM) in combination with dynamic mesh adaptivity in parallel computing to simulate immiscible viscous fingering in two- and three-dimensions.
Immiscible viscous fingering may occur during the waterflooding of oil reservoirs, resulting in early breakthrough and poor areal sweep. Similarly to miscible fingering it is triggered by small-scale permeability heterogeneity while it is controlled by the mobility ratio of the fluid and the level of transverse dispersion / capillary pressure. Up to this day, most viscous fingering studies have focussed on the miscible problem since immiscible fingering is significantly more challenging. It requires numerical simulations capable to capture the interaction of the shock front with the capillary pressure, which is a saturation dependent dispersion term. That leads to models with very fine mesh in order to minimise numerical diffusion, resulting in computationally intensive simulations.
In this study, we apply the dynamic mesh adaptive DCVFEM in parallel computing to simulate immiscible viscous fingering with capillary pressure. Parallelisation is achieved by using the MPI libraries. Dynamic mesh adaptivity is achieved by mapping of data between meshes. The governing multiphase flow equations are discretised using double control volumes on tetrahedral finite elements. The discontinuous representation for pressure and velocity allows the use of small control volumes, yielding higher resolution of the saturation field.
We demonstrate convergence of fingers using our parallel numerical method in 2d and 3d, on fixed and adaptive meshes, quantifying the speed-up due to parallelisation and mesh adaptivity and the achieved accuracy. Dynamic mesh adaptivity allows resolution to be automatically employed where it is required to resolve the fingers with lower resolution elsewhere, enabling capture of complex non-linearity such as tip-splitting. We achieve convergence with less than 10k elements, approximately 5 times fewer elements than are needed for the converged fixed mesh solution, consequently the computational cost is also significantly reduced.
Initial growth rates as a function of wavenumber, viscosity ratio, relative permeability and capillary pressure are compared with the literature. We demonstrate that the structure of the mesh plays a key role in simulation of fingering as it can itself trigger the instability, control the dominant wavelength of the fingers and their growth rate. We show that it is important to characterise the amount of transverse to longitudinal numerical diffusion in a general unstructured mesh in order to ensure that the correct fingering pattern is simulated.
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Injection Test as Milestone for the Applicaton of Polymer Flooding in the German North Sea
Authors C. Burmester, F. Leicht, D. Bols and T. DoseSummaryWith respect to maximising recovery and optimising a field's value, Chemical Enhanced Oil Recovery (CEOR) especially with polymers is frequently an option. This method was identified as a promising method to enhance production from Germany's largest oil field Mittelplate. The field presents challenging operational conditions with respect to surface, subsurface, and environmental constraints. This paper describes the upscaling of lab results to field scale as well as results from a conducted injection field test.
A stepwise scale up from lab to field was performed. On the lab scale, the selection process for this field was presented (EAGE Annual 2018).
Because the subsurface injectivity for polymer solutions of the anticipated target reservoir was unknown, an injection test was planned. Due to the unknown injection parameters for the test, a mixing unit was constructed based on the results from the pilot plant tests. The main criteria for the design were operational safety considerations and high flexibility with respect to flow rates and mixing energy while maintaining a high quality of the mixed polymer solution with produced water.
At the pilot plant scale, continuous mixing tests with equipment from different suppliers and different setups were carried out for rates up to 600 l/h. A yard test of the mixing unit using field injection water generated valuable lessons, which completed the onshore evaluation for offshore field application.
In the 3rd quarter 2017, an injection test on Mittelplate Island was carried out. The test was conducted with produced water (190 g/1) without any special treatments sourced from the injection water system. The solution quality was very good and injectivity was above expectations. No plugging behaviour and no significant shear degradation of the injected solution was observed which confirms lab results regarding an excellent shear stability of the mixed polymer solutions. The injection index of the injector was well preserved.
Overall the test proved the applicability of the selected chemical system with high salinity injection water on Mittelplate.
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Development of Conformance Gel for Diadema Oil Field using Powder and Emulsion Polymers and their Impact on Equipment and Economics
Authors G. Dupuis, S. Bataille, J. Monzon, N. Gaillard, G. Fondevila Sancet, M. Villambrosa, M.D. Goldman and M. AlvarezSummaryDiadema Oil Field is located in the San Jorge Gulf Basin in Southern Argentina. The field is operated by CAPSA, an Argentinean oil producer company; it has around 500 producer and 300 injector wells (well spacing is around 250 m). The company has been developing water flooding during more than 25 years (today this technique represents +65% of oil production), polymer flooding during more than 10 years and (+15% of oil production); produces about 1,850 m3/d of oil and 45,000 m3/d of gross production (96% water cut) with 43,000 m3/d of water injection.
The main reservoir under secondary recovery is characterized by high permeability (500 md average), high heterogeneity (10 to 5000 md), high porosity (30%), very stratified sand-stone layers (4 to 12 m of net thickness) with poor lateral continuity (fluvial origin) and 20 °API oil (100 cp at reservoir conditions, 50 °C). Due to such reservoir conditions, injectors and producers are subject to channeling problems.
Polymer gels have been extensively used to tackle such conformance issues. The criteria of success do not only depend on the quality of the technical solution but also on economics. Generally, gels are formulated using polymers under powder form requiring the mobilization of a dissolution unit, a maturation tank and one to several dilution tanks. On the opposite the utilization of polymers under reverse emulsion form only requires the use of a single skid including a static mixer for the inversion of the emulsion and one or two static mixers for polymer dilution and homogenization with the crosslinker, reducing both the footprint of the equipment (important for offshore) and the cost of the treatment.
Two gel formulations using Chromium (III) acetate as crosslinker and partially hydrolyzed polyacrylamide either under its powder or its reverse emulsion version were developed to fit field conditions targeting a gel D category according to Sydansk classification and a gel time below 36 hours. A cost analysis comparison of both formulations was performed to select the more efficient solutions.
Gels C to D were achieved for both formulations, 15 hours gel time and good stability over 3 months. The economical evaluation showed that the cost saving associated to the use of a single skid did not compensate the extra price of the reverse emulsion compared to the powder. The formulation using HPAM as a powder was selected and 20+ injection wells were treated without facing any operational issue.
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First Use of Ultra-Deep Resistivity 2D Deep Azimuthal Images to Identify Reservoir Sweep in a Mature Waterflood of Al-Shaheen Field
Authors S. Finlay, D. Omeragic, M. Thiel, N. Farnoosh, J. Denichou and M. ViandanteSummaryThe Al Shaheen field has been on production for 25 years and is developed using waterflood and ERD wells, some of which are openhole. Production logging Tools are occasionally required to assess waterflood performance, and the implementation of appropriate mitigation steps. Wellbore architecture and offshore facility limitations make conventional production logging challenging. Therefore to identify swept zones or non-conformances an ERD producer and injector, a novel data acquisition plan based on Ultra-deep resistivity LWD measurements and more conventional open hole measurements was designed to overcome these challenges. Ultra-deep directional resistivity measurements recorded in the injector well were used to map the reservoir structure and fluid distribution up to 100 feet above and below from the injector well. In addition to time lapse resistivity logging, a novel 2D deep azimuthal imaging using extended set of ultra-deep directional resistivity measurements with 3D sensitivities were used to identify movement of fluid in horizontal direction towards the producer well. Full 3D modeling of deep directional resistivity responses was performed before the data acquisition to evaluate sensitivities and signatures of invaded fracture swarms of variable fracture density on measurements and real-time interpretation based on 1D inversions.
The 2D deep azimuthal imaging using the extended 3D set of ultra-deep directional resistivity measurements provided resistivity maps used to identify the fluid fronts and evaluate movement of fluids in lateral direction and heterogeneities not only above and below but also left and right up to 100ft away from the wellbore. The identified flooded zones were consistent with time-lapse resistivities. The 3D modeling and 1D inversion helped to understand patterns in real-time deep directional resistivity interpretation. Detailed analysis of resistivity responses and original while drilling images confirmed identified fracture swarm zones. Besides overcoming challenges with conventional production logs, the methodology provides a unique 3D view of the reservoir from LWD logs at the scale of inches to 100ft.
The case study demonstrates the potential of newly developed deep azimuthal 2D imaging using ultra-deep directional resistivity data to refine the 3D structural interpretation and evaluate the fluid distribution up to 100 feet away from the injector well. This information will be critical to build for the first time consistent 3D interpretation from the wellbore to reservoir scale, calibrating 4D seismic in challenging Middle East carbonates reservoir and bridging the gap between the time-lapse conventional resistivity logs and 4D seismic.
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A Systematic Investigation of Surfactant/polymer Flooding in Conglomerate Reservoir: From Laboratory to Field Test
More LessSummaryConglomerate reservoir is characterized by high water cut, poor sweep efficiency and inefficient oil recovery during the end-period of water flooding. Surfactant/polymer (SP) flooding has been proved as one of the most promising CEOR methods to improve remaining oil recovery after water flooding, due to the unique synergy of polymer/surfactant. The mechanism and performance of SP flooding in conglomerate reservoir need be studied thoroughly.
We took Karamay oilfield, the biggest conglomerate pilot for SP flooding in China, as an example. Three critical issues, surfactant formulation, relationship between oil displacement and lithology, and filed adjustment methods based on development data, for successful SP flooding in conglomerate were investigated in this paper. Firstly, Petroleum sulfonate surfactant was extracted from Karamay crude oil and three properties including molecular structure and phase behavior were tested to optimize surfactant formations. Then the pore structure difference between conglomerates and sandstones was compared through thin section photographs and mercury-injection capillary pressure tests. Meanwhile, these typical cores of different lithology were used to conduct core flooding experiments, and pore-scale displacement of different concentrations of polymer and surfactant was also evaluated using nuclear magnetic resonance (NMR). After these laboratory researches, a pilot test (18 injection 26 production) at Karamay oilfield was performed in November 2011. Finally, technical issues related to scale-up and unique phenomena of development in conglomerate reservoir were discussed.
The complex of two anionic surfactants made surfactant solution achieve longer range of carbon number distribution, lower CMC and ultra-low interfacial tension with low concentration. Compared with sandstone, the diagenesis of conglomerates normally takes place in a shallower depth and then possesses more tortuous pore structures. Unlike sandstone cores, increasing polymer concentration cannot increase oil efficiency. The result of NMR test showed polymer flooding was hard to mobilize residual oil in pores whose radius was below 5μm. However, residual oil in these pores obviously decreased in SP flooding. For the pilot test, heterogeneous reservoir pressure and very low liquid production were observed in first 2 years. We had to stop some well group tests whose permeability was below 30mD and decrease molecular weight and concentration of polymer to continue testing in those wells (8 injection 13 production) whose permeability is relatively high. It has some good performances including appropriate emulsification, low water cut and high oil recovery (15.5%) until December 2016.
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Field Experience of Inorganic Gels Application with Cyclic Steam Stimulation
Authors I. Kuvshinov, L. Altunina and V. KuvshinovSummaryIn this paper we present the experience of using inorganic thermotropic gel-forming compositions, combined with cycle-steam stimulation of wells, at the Permian-Carboniferous deposit of the Usinsk oilfield, Russia, the Komi Republic, over the last 5 years. The compositions are aqueous solutions of salts with a viscosity close to water and are injected immediately before or at the initial stage of steam injection. Then, under the temperature of the injected steam, the composition forms a gel that ensures the leveling of the injectivity profile, the increase in the formation sweep by the steam, and the reduction of the water cut of the product. Inorganic gel based on aluminum salts, in contrast to many polymer compositions, is able to withstand high temperatures, typical for steam treatments, about 300 C.
The object under consideration, the Permian-Carboniferous deposit of the Usinsk oilfield is a carbonate fractured reservoir, characterized by a high oil viscosity, 710 mPa∙s, and a heterogeneous geological structure. The initial reservoir temperature is 23 C, which together with the high viscosity of oil gives the prerequisites for the application of thermal methods of recovery.
Over the past 5 years, from 2014 to the present, several dozens, and more recently, more than a hundred, of steam cyclic treatments are being conducted at the field in question. Of these, about 15–20 wells are treated annually with the use of inorganic thermotropic composition GALKA, in its different variations. The average oil production rate in the wells before treatment is 2–3 t/day, in the first month after treatment 15 t/day or more. Water cut before treatment is 85–95 %, after treatment with application of the composition and injection of steam is reduced by an average of 20 %, up to 65–75 %, whereas for steam treatments without reagents, an increase in water cut is observed, as the vapor condenses and is extracted along with oil in the form of water.
Also, it has been assumed that there is some critical, or optimal, well capacity by the amount of injected steam during steam cycling treatment, about 4–6 thousand tons for processing for a particular field. Exceeding this value does not increase the efficiency, but, on the contrary, can cause additional watering at the initial stage of extraction after processing. The use of gel-forming compositions increases steam coverage and reduces water cut, which allows to increase this critical capacity.
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Low Salinity and Immiscible CO2 Combined Flooding For Sandstone Reservoirs: Low Salinity-Alternating- CO2 Flooding (LS-CO2 WAG)
Authors H. Al-Saedi, R. Flori and W. Al-BazzazSummaryLow salinity (LS) water flooding and CO2 flooding are two new combination floods coupled due to the vital role of both in methods for increasing oil recovery. LS water was examined by many laboratory and field works, and it showed an impressive result in enhancing oil recovery. CO2 was tested on increasing oil recovery, and the oil recovery increased by improved wettability alteration effect towards more water-wet and interfacial tension reduction. Although CO2 showed an improvement in oil recovery, the density difference between CO2 and oil resulted in gravity override and channeling problems. LS water alternating CO2 flood gathers the benefits of LS itself to improve sweep efficiency by CO2, prevent the CO2 problems mentioned earlier, and capture the CO2 from the atmosphere. Furthermore, miscible CO2 flooding can reduce oil viscosity and trigger oil swelling. The laboratory experiments of all scenarios showed an incremental oil recovery, but the optimum scenario was the huff and puff-LS water-CO2-LS water scenario with additional oil recovery of 20.65% of OOIP. The three-hours huffing mobilized a new bank of oil, while the shorter LS water-CO2 cycles were the second optimum with incremental oil recovery 17.95% of the OOIP. This combination technology can solve the CO2 flooding problems and support CO2 by LS water, which in itself can increase oil recovery by altering the wettability towards more water-wet.
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Microfluidics Technology for Visualizing Surfactant Performance in Enhanced Oil Recovery
Authors J. Kim, E. Willmott and L. QuinteroSummaryThis paper introduces a microfluidic technology for surfactant evaluation for Enhanced Oil Recovery (EOR). During EOR surfactant development process, each developed surfactant formulation for a targeted reservoir must undergo oil recovery performance testing using conventional methods such as sandpack and coreflood test. Although these are beneficial testing tools, testing protocols and labor requirements can be quite time-consuming and expensive. The microfluidic system developed in this study accelerates surfactant selection process in a rapid, more convenient, and cost effective manner. It can be utilized as a fast screening tool to select candidate surfactant formulations for the final validation with core flood testing. It also offers superior visualization of oil-surfactant interactions to provide better understanding of what is occurring inside a reservoir that was not previously possible with conventional testing methods.
The newly developed microfluidic system utilizes porous media that resembles reservoir sandstone in terms of reservoir pore structure, wettability, and polarity. Initially, the porous media is filled with crude oil to be aged in-situ overnight at reservoir temperature and moderate pressure. Injection water is then injected into the porous media to simulate secondary recovery water flooding. For the residual oil left behind, a surfactant flood is injected, followed by additional water injection. The progression of oil recovery throughout the whole process is video recorded for visual assessment of surfactant performance. The collected images are analyzed to quantify the amount of oil recovery.
The experimental results confirmed that the microfluidic system can differentiate oil recovery performance among good, average, and poor performing surfactants. A systematic study showed that the microfluidic technique gives higher data resolution to differentiate surfactant performance than sandpack method and reasonable repeatability when wettability is controlled.
Furthermore, the details of oil recovery process inside porous media through the interaction between oil and surfactant and the formation of microemulsion is vividly exhibited in a transparent microfluidic reservoir. Depending on the surfactant type and efficacy, the effectiveness on oil recovery varies. This variation in surfactant performance was noticeable by comparing the digital images of residual oil in microfluidic porous media after flooding with different surfactants, enabling another level of chemical evaluation, which was not possible with conventional testing methods. The quantified oil recovery data was similar to those of conventional sandpack and core flood tests, but obtained faster by a few days up to a few weeks with less operational difficulty.
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Simulation Interpretation of Capillary Pressure and Relative Permeability from Waterflooding Laboratory Experiments in Preferentially Oil-wet Porous Media
Authors P.Ø. Andersen, K. Walrond, C. Nainggolan, E. Pulido and R. AskarinezhadSummaryIn preferential oil-wet porous media, water flooding laboratory experiments are prone to capillary end effects. The wetting oil phase will tend to accumulate at the outlet where the capillary pressure is zero and leavea high remaining oil saturation at steady state (defined by stable pressure drop and zero oil production rate) compared to the residual oil saturation. Andersen et al. (2017a) derived analytical solutions describing how capillary pressure and relative permeabilityof water (the injected phase) could be determined based on pressure drop and average saturation at steady states obtained at different water injection rates. Plotting these values against inverse rate reveal linear trends at high rates, with slopes and interceptsthat directly quantify the saturation functions in the range of negative capillary pressures. The method is similar to Gupta and Maloney0027;s (2016) intercept theory, but quantifies entire functions rather than a single point and provides the trends also at lowrates, thus utilizing all the information.
Our aim is to demonstrate how pressure drop and oil production at steady state for different water injection rates can be used to derive relative permeability and capillary pressure from water flooding. This is done inthree ways. First, synthetic waterflooding tests are generated (using the commercial software Sendra) applying the same saturation function correlations as assumed in the analytical solution. Then, more general correlations are assumed when generating thesynthetical data with Sendra. This , to test the robustness of the analytical solution of producing similar functions as the ‘true’ ones. Finally, we perform a waterflooding experiment in the lab on a high permeability (3 Darcy) Bentheimer sandstone core, alteredoil-wet using Quilon solution. The core was saturated with ~90 % n-decane oil and ~10 % brine. Spontaneous imbibition yielded << 1 % recovery. Forced imbibition of brine followed, starting from 0.4 PV/d, then increased stepwise after approaching steady stateuntil 12 rates had been applied, varied overall by a factor ~ 1000 to yield states governed by capillary forces and states governed by advective forces. The results were interpreted using both Sendra and the analytical solution.
The experimental procedure and model demonstrate that only water relative permeability and capillary pressure determine the steady state during water flooding and hence can be estimated accurately. The analytical solutioncould match the trends and magnitude simultaneously of steady state pressure drop and production with injection rate to give an estimation of the saturation functions. The estimates were as good as full history matching.
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Selection of Optimal Polyacrylamide for Polymer Flooding –Impact of Brine Composition and Reservoir Temperature
More LessSummaryHPAM is a copolymer of acrylamide and acrylic acid, and it is the most common polymer utilized in polymer flooding. Sulfonated polyacrylamides, i.e. copolymers of acrylamide and acrylamide tertiary butyl sulfonic acid (ATBS), are a potential choice for high temperature and harsh salinity reservoirs. The aim of this study was to provide systematic information to aid in the selection of most optimal type of polyacrylamide for polymer flooding, depending on reservoir temperature and injection brine composition. Specifically, two different types of polyacrylamides – HPAM and sulfonated – were compared.
The viscosity yield and long-term stability of selected HPAM and sulfonated samples were studied over a wide range of conditions: TDS (700 – 170 000 ppm), relative hardness (0–20 mol% of all cations), and temperature (25–120°C). The selected samples represent typical products often considered for polymer flooding. We provide landscape graphs for different sample types to visualize the effect of TDS, relative hardness and temperature to sample viscosity yield and long-term stability. The long-term stability was studied in various brine conditions by accelerated aging experiments at 83–120°C. Viscosity loss at these temperatures is mainly related to the hydrolysis reaction that turns acrylamide and ATBS groups into acrylic acid. Viscosity retention and hydrolysis rate (by 13C NMR) were followed throughout the aging experiments.
From the results it can be observed that HPAM type sample provides highest viscosity over a wide range of brine conditions at 25°C. Sulfonated samples provided higher viscosity than HPAM if temperature and/or relative brine hardness was high. Divalent cations in the brine have clear detrimental effect on HPAM viscosity. Similar relative hardness (mol% of cations) provides similar relative drop in viscosity (% viscosity loss compared to soft brine) over a wide range of TDS – i.e. the relative hardness can be considered even more informative value than the absolute content of divalent cations in ppm. The long-term stability becomes important at temperatures above ca. 50 – 60°C. The stability is affected by the reservoir temperature and brine quality. As the polymer hydrolyses, competing beneficial (increasing charge) and adverse (increasing interaction with divalent cations) effects are present, and their effect will vary from brine to brine. Sulfonation significantly improves long term stability.
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Evaluating Reservoir Fluids Geochemistry for Planning of Surfactant-Polymer Flooding
Authors I. Koltsov, A. Groman, S. Milchakov, N. Tretyakov, L. Panicheva, S. Volkova, E. Turnaeva and D. LenevSummaryGeochemistry of oils and fluids is often explored for understanding of basin origin and oil migration. Variability of fluids properties is also important for IOR\EOR projects, because critical parameters of chemical flooding, such as interfacial tension (IFT) and surfactant adsorption depend upon crude oil properties and brine composition. Understanding of geochemical and geological heterogeneity became even more important for project upscaling when large blocks or an entire field are proposed for chemical flooding.
This paper presents results of lab experiments with crude oils collected from several West Siberian oilfields which are considered as potential objects for surfactant-polymer (SP) flooding.
At first, paper describes which parameters are important for SP flooding compare to ASP. It is shown that SP technology requires the different set of parameters to be taken into account. For example, optimal salinity depends upon oil EACN, salinity of formation fluids, their hardness and, sometimes, balance between Ca\ Mg as the main hardness ions. Majority of mentioned parameters is routinely measured during waterflooding, but quality of data is sometimes questionable. Therefore interpretation could be a challenging task. Approaches for prudent interpretation are discussed, need for special sampling program is justified.
Variation of oils0027; EACN was investigated inside several oilfields. Standard geochemical parameters for oil composition (SARA) are also analyzed. Significant variation of oil parameters within several fields was discovered, especially in case of coproduction from different layers. Variation of optimal salinity for SP mixture as a function of fluids hardness was investigated in a lab. Changes in IFT around optimum were measured, possible correlations are proposed.
Finally, authors discuss how to use estimated variations in EACN, salinity and hardness for high-level modeling of chemical flooding. Regional and infield variations of oil properties were converted to a range of IFT values for a specific SP cocktail. Results allow further optimization of surfactant blends and reveal most important factors influencing efficiency of SP flooding and current technical strategy.
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Carbonated Water Injection in the North Sea Chalk Reservoirs: Energy Analysis and Environmental Assessment
More LessSummaryCarbon dioxide is one of the most effective fluids for improving and enhancing oil recovery. It dissolves in oil and reduces its density (i.e., swells the oil) and viscosity, giving oil a higher mobility. However, when the reservoir condition is not suitable for the CO2 to become miscible in oil, the high mobility and low density of the CO₂ causes channeling and gravity override, and as a result a poor sweep and early breakthrough. These problems can be addressed by dissolving the CO₂ in water, a fluid with lower mobility, and injecting it into the reservoir, known as carbonated water injection. It is observed experimentally that the injection of a water-soluble solvents such as CO₂ or DME into a chalk core (in tertiary mode) mobilizes a large fraction of the remaining oil and vastly improves the recovery factor. Moreover, the injected CO₂, if trapped in the reservoir, can mitigate the harmful impact of the CO₂ that is otherwise released to the atmosphere. This work tries to quantify the effectiveness of the carbonated water injection into a North Sea chalk reservoir in terms of the extra oil recovery, the overall process energy balance, and the net amount of stored carbon dioxide.
The prerequisite to a successful implementation of the carbonated water flooding is the availability of the CO₂. Different options are considered in this work, viz., pipeline transport of the captured CO₂ from the nearby fossil-fuel power plants, liquefied CO₂ transported by a ship, and the wind-farm electricity-driven separation of CO₂ from the atmosphere. All the energy requirements for the separation, transport, and injection of CO₂ are included in the energy analysis. The carbonated water injection into the chalk reservoir is modeled using an in-house finite volume solver. The amount of the stored CO₂ in the reservoir is quantified from the simulation results. It is assumed that the produced CO₂ in the production wells is separated and re-injected into the reservoir. The final results is presented as the net amount of recovered hydrocarbon energy from the reservoir and the net amount of captured CO₂ per unit recovered energy. The effectiveness of this process is compared to other CO₂ capture and storage processes in terms of the energy requirement per unit mass of captured carbon dioxide. The energy analysis in this work, which is founded on the fundamental laws of thermodynamics, can be easily converted to economic analysis.
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Dilute Surfactants for Wettability Alteration and Enhanced Oil Recovery in Carbonates
Authors S. Ayirala, A. Boqmi, A. Alghamdi and A. AlSofiSummaryThis experimental study evaluates the capability of dilute nonionic surfactants for wettability alteration and enhanced oil recovery applications in carbonates.Firstly the compatibility of surfactant was determined by performing aqueous stability tests in both low salinity and high salinity brines followed by surface tension measurements to determine critical micelle concentrations (CMC). Phase behavior, and interfacialtension measurements were conducted using 0.1 wt% surfactant and crude oil at reservoir temperature. The contact angle measurements were performed using carbonate surfaces and the nonionic surfactant at dilute concentrations to evaluate wettability alterationin carbonates at reservoir conditions. Zeta potential measurements were also carried out across calcite-brine/surfactant, and crude oil-brine/surfactant interfaces to confirm the wettability alterations induced by the surfactant. Lastly microscopic dynamicliberation experiments were conducted using dilute concentrations of surfactant and polymer chemicals in both high salinity and low salinity brines to quantify the effects of wettability alteration on oil liberation efficiency in carbonates.
The compatibility of nonionic surfactant was demonstrated in high salinity brine at reservoir temperature. The critical micelle concentrations were found to bevery low in the range of 0.0020 to 0.0025 wt% in both low salinity and high salinity brines. The phase behavior results showed the formation of middle phase microemulsion and correspondingly low interfacial tensions in the range of about 0.05 mN/m with 0.1wt% surfactant in high salinity brine. The contact angle data indicated the ability of nonionic surfactant to significantly alter the wettability of carbonate from oil-wet to either intermediate wet or less oil-wet in high salinity brine whereas only marginalwettability alterations from oil-wet to less oil-wet were obtained in low salinity brine. The increasing negative zeta potentials and the alteration of charge polarity from positive to negative were observed at crude oil-brine and calcite/brine interfaces,respectively, by using 0.1 wt% surfactant in the high salinity water. Such results confirm the effectiveness of nonionic surfactant in high salinity water to alter the wettability of carbonates at dilute concentrations. The microscopic equilibrium degree ofcrude oil liberation from carbonate surface was found to be about 20% higher with high salinity surfactant-polymer solution when compared to the low salinity surfactant-polymer solution. These consistent findings obtained from different experimental techniquesclearly point out that dilute nonionic surfactant combined with dilute polymer in conventional high salinity injection water can become one potential cost-effective chemical EOR solution for oil recovery in carbonate reservoirs.
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Gravity Assisted Steam Flooding (GASF) as a Post-CHOP for Foamy Extra-Heavy Oil Reservoirs
More LessSummaryExtra-heavy oil reservoirs in the Carabobo Area, the eastern Orinoco Belt, have been exploited with Cold Heavy Oil Production (CHOP) with horizontal wells utilizing foamy oil drive mechanism nowadays, with a primary recovery less than 12% OOIP. Steam flooding (SF) can effectively improve oil recovery factor of heavy oil reservoirs, but for horizontal wells the steam breakthrough and steam overlying are serious problems hindering the application of SF. Therefore the Gravity Assisted Steam Flooding (GASF) technology is presented. For GASF technology, the injector (vertical well or horizontal well) is laterally above the producer, so that the direction of steam flooding is laterally downward. The technical feasibility and adaptability of GASF processes are investigated in this study.
A representative sub-model of Block M located in the Carabobo Area was extracted to evaluate the performance of GASF. And some key issues including transfer time from cold production to GASF, appropriate well pattern, well spacing, and operation parameters were further discussed using the ideal numerical models. The study indicates that the technology of GASF could drastically increase the oil recovery of foamy extra-heavy oil reservoirs after cold production. The oil displacement mechanism of GASF includes steam flooding and gravity drainage. The best transfer time from cold production to GASF is when reservoir pressure drops down to the lower pressure during the cold production phase. For the homogeneous reservoir, the GASF with injector of horizontal well presents better performance. But if the heterogeneity reaches a certain degree, the GASF with injector of horizontal well will be inefficient, and the injector of GASF should be vertical well. Moreover, for GASF horizontal distance between injector and producer reduces, the oil recovery and oil steam ratio increases obviously. In addition, for GASF the vertical distance between injector and producer, the vertical injectors numbers, steam injection rate, and steam quality are discussed in this work.
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Experimental Investigation of Non-thermal EOR Methods for Foamy Extra-Heavy Oil Reservoirs
More LessSummarySome foamy heavy oil reservoirs in the eastern Orinoco Heavy Oil Belt in Venezuela have been developed for decades by the foamy oil cold production method. The oil production rate declines obviously with reservoir pressure depletion. It should be carried out with consideration of a follow-up method to increase the ultimate oil recovery. Whereas the completion method of a great many production wells is not suitable for steam based recovery technology. Therefore a series of non-thermal EOR methods were investigated.
In this work, the viscosity of dead oil is 14500 mPa•s (53.7℃) and the produced gas is mainly comprised of methane and CO2 (87:13 in molar ratio). The flooding EOR methods of water flooding, produced gas flooding, surfactant flooding, and foam flooding; the huff and puff EOR methods of produced gas huff and puff , viscosity reducer assisted produced gas huff and puff, and foaming agent assisted produced gas huff and puff were conducted through microscopic visualization and sandpack displacement experiments.
Experimental results show that the for the flooding EOR methods, due to the tremendous mobility ratio, the water flooding and produced gas flooding get poor EOR performance. The surfactant flooding can improve the oil recovery factor by 15.09% because the surfactant reduces the interfacial tension and increases displacement efficiency. Furthermore the foam flooding can improve the oil recovery factor by 24.06% because the foam increases both the displacement efficiency and the sweep efficiency. For huff and puff EOR methods, produced gas huff and puff can improve the oil recovery factor by 7.4%, and microscopic visualization experiment shows the secondary foamy oil is generated after produced gas dissolved in oil phase. The viscosity reducer assisted produced gas huff and puff can improve the oil recovery factor by 12.5% owing to the reduced oil viscosity and improved oil mobility. The foaming agent assisted produced gas huff and puff can improve the oil recovery factor by 18.2%. That is because the foaming agent helps to form secondary foamy oil and keep the produced gas dispersed in the oil phase as long as possible.
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The Effects of Crossflow and Permeability Variation on Different Miscible CO2 injection Schemes Performance in Layered Sandstone Porous Media
Authors D. Al-Bayati, A. Saeedi, C. White, Q. Xie and M. MyersSummarySupercritical carbon dioxide (SCCO2) injection in hydrocarbon reservoirs is documented as important means to achieve hydrocarbon potential whilst mitigating the greenhouse gas effect. However, reservoir heterogeneity significantly affects subsurface multiphase flow behaviour thereby oil recovery factor, thus triggering intrinsic uncertainties to manage and predict reservoir performance. In this manuscript, we present the results of a systematic approach to investigate the influences of crossflow and permeability variations in layered core samples on the efficiency of miscible continuous SCCO2 and water alternating gas (WAG) flooding performance. Here, we manufactured heterogeneous porous media by stacking two hemi cylindrical sample (each sample has a different permeability) together. Placing either a lint free tissue paper or a Teflon sheet allowed us to investigate the impact of crossflow on displacement efficiency. The core flooding experiments were conducted under miscible conditions at a reservoir temperature of 343 K and pressure of 17.23 MPa using n C10, synthetic brine and SCCO2. Two different SCCO2 flooding schemes were used; namely, continuous injection of SCCO2 and water alternating SCCO2.
The results obtained from heterogeneous porous media indicate that permeability variations in layered porous media have significantly impact the ultimate recovery for both continuous and WAG flooding. It is also found that crossflow in the layered sample has an appreciable effect on the ultimate oil recovery (i.e. increasing oil recovery by 4.8% as a maximum) when injecting SCCO2 continuously. However, as the permeability variations between layers increases a considerable channelling of the injected SCCO2 through the high permeability layer is dominated which reduces the amount of additional oil mobilised by crossflow. In contrast to the findings of continuous injection of SCCO2, the effect of crossflow during WAG flooding is negatively impacts the recovery factor. Such an outcome by WAG flooding may be attributed to the achievement of conformance control under the non communication layers which otherwise cannot due to occurrence of preferential flow paths. Thus, the results of this study provide insight into the importance of crossflow in layered porous media to overcome the current challenges in capturing the importance of geological uncertainties in the current and future SCCO2 IOR/EOR projects.
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Successful Time Lapse Seismic Pilot on Al Shaheen field (Offshore Qatar): Analysis and Practical Applications in Reservoir Monitoring
Authors G. Berthereau, R. Sanchez and M. EmangSummaryThe Al Shaheen field, offshore Qatar, is one of the world's oil largest carbonate fields currently at a production plateau of 300 000bopd with more than 300 active wells. It comprises a stacked sequence of thin layered Lower Cretaceous reservoirs. The objective of the paper is to illustrate the applicability and demonstrate the economic impact of 4D information by revisiting data acquisition, work overs, appraisal wells around monitor acquisition time.
Time lapse seismic survey (4D seismic) is a geophysical technique consisting in acquiring 3D seismic over the same area at different times. Following a conclusive 4D feasibility study, a pilot monitor survey was shot in 2015 to be compared to a base survey shot in 2007 (first oil in 1994). Aside from seismic acquisition repeatability and processing, successful 4D analysis was highly dependent on extracting meaningful 4D attribute, integration and collaboration of different geoscience disciplines.
4D analysis led to the following conclusions:
- 4D seismic response is broadly consistent between Al Shaheen carbonate reservoirs
- 4D signal associated with gas saturation changes is easily observable in a very reduced time frame:
- Sg increase associated with gas exsolution (due to unsupported production) or gas injection (WAG)
- Sg decrease associated with gas production / re-dissolution due to unsupported production before base monitor and support between base and monitor.
- 4D signal associated with water saturation increase is mostly limited to non-uniform sweep such as early water breakthrough issue.
- 4D signal associated with pressure decrease is not directly observed as quickly associated with gas exsolution whereas 4D signal associated with pressure increase is limited to producers in depletion mode converted around base monitor time into water injectors.
Current applications in reservoir management include:
- Identification of undrained / poorly supported areas based on non-uniform 4D signal associated with gas saturation changes
- Identification of early water breakthrough issue location along water injector
- reservoir surveillance plan strategy
- influencing workover strategy
- optimizing appraisal well location in order to sample sweep efficiency or investigate inter reservoir communication.
Despite 4D has been proven a successful technique in clastic environment, its applicability to carbonates fields is more challenging and depends first on rock physics and also seismic quality. Nevertheless, the 2015 seismic pilot results proved the 4D value particularly in reservoir management and consequently validated a full field 4D OBN monitoring strategy with first survey to be executed in 2019.
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A New Mechanism for Enhanced Oil Recovery by CO2 in Shale Oil Reservoirs
Authors P. Mahzari, T. Mitchell, A. Jones and E. OelkersSummaryDuring the past decade, enhanced oil recovery (EOR) by CO2 in shale oils has received substantial attention. In shale oil reservoirs, CO2 diffusion into the resident oil has been considered to be the dominant interaction between the CO2 in fractures and the oil in the matrices. CO2 diffusion will lead to oil swelling and improvement in oil viscosity. However, despite two-way mass transfer during CO2 EOR in conventional oil reservoirs, one-way mass transfer into shale oils saturated with live oils is controlled by an additional transport mechanism, which is the liberation of light oil components in the form of a gaseous new-phase. This in-situ gas formation could generate considerable swelling, which could improve the oil recovery significantly. This mechanism has been largely overlooked in the past. This study is aimed to better understand the role of this evolving gas phase in improving hydrocarbon recovery.
Taking account of Bakken shale oil reservoir data, numerical simulations were performed to identify efficiencies of EOR by CO2 at the laboratory and field scales. Equation-of-state parameters between CO2 and oil components were adjusted to optimize the calculations and a sensitivity analysis was performed to identify the role of the parameters on gas formation and consequent EOR efficiencies. At the laboratory scale, in-situ gas formation can increase oil recovery by 20% depending on the amount of gas saturation. Also, the CO2 storage capacity of the shale matrix can be enhanced by 25%, due to CO2 trapping in the gas phase. At the field scale, an additional oil recovery of 9.3% could be attained, which is notably higher than previous studies where this gas evolution mechanism was ignored. The results suggest that a 6 weeks huff period would be sufficient to achieve substantial EOR if this new mechanism is incorporated. Furthermore, the produced fluid in the early period was primarily composed of CO2, which would make it available for subsequent cycles. The produced gas of the well under CO2 EOR was used in an adjacent well, which resulted in similar additional oil recovery and hence, 10% impurities in CO2 injection stream would not undermine efficiency of this EOR method. The results of this study, therefore, could potentially be used to substantially improve the evaluations of CO2 EOR in shale oil reservoirs.
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An Approach to Miscible Injection in the Oil Rim Reservoir
Authors N. Glavnov, A. Penigin, M. Vershinina, I. Mukhametzyanov and P.L. McGuireSummaryAcross PJSC «Gazprom Neft» portfolio of technological projects an especial place is reserved for gas technologies and miscible flooding is one of them. It allows to increase production and recovery factor but also helps utilize rich gas components which otherwise would be flamed/sold without extra value. This paper discusses development options of miscible injection in oil rim reservoir.
To evaluate gas processing options multiple models in Aspen HYSYS were designed in order to increase extraction of C2–C4 fraction that is mixed with lean gas to achieve miscible displacement in the reservoir, since otherwise the only option to get rid of C2–C4 is to mix in with lean gas and sell as pipeline gas. At the beginning PVT model was designed and MME was evaluated. Having results from actual lab experiments and compositional modeling software available optimal composition of injection fluids and pressure regimes were investigated. Current and planned patterns of oilfields were studied for best injector location using 3D compositional simulator. Integrated models were built to monitor and predict produced and injected gas compositions and volumes. In addition they allowed watching for bottle-necks in production network, cryogenic plant, gas facilities and calculation of recycling volume.
Main idea was to ensure maximum economically possible extraction of C2–C4 fraction from produced gas thus obtaining fluid for miscible injection. During iterative process decision was to be made between -55 and -80O C after turbo-expander and the last one was more prominent, since it increased extraction by 35%. According to MME test, average pressure, regimes of production and available volume of gas optimal composition of miscible gas is 65% methane and is achieved by mixing C2–C4 with lean gas for a pipeline and gas cap injection. Gas utilization achieves maximum for patterns with higher OIP, number of wells and their density. WAG is considered to perform better in terms of gas utilization that in its turn leads to increased incremental oil. By choosing most efficient patterns in terms it became possible to increase recovery in these regions by 10–15%.
The paper describes the approach used to design development strategy of miscible flooding option for the oil rim reservoir. Technical details shown describe cryogenic plant design considerations, selection process of optimal injected gas composition, evolution of development strategy for the reservoir. The approach shows a way to incorporate all available data into one decision-making space in order to achieve maximum value from available resources.
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Low Salinity Evaluation in Low Permeable Sandstone Reservoirs with Intermediate Clay Content
Authors E. Hoffmann, R.E. Hincapie and L. GanzerSummaryWithin this work, we evaluate the Low Salinity Waterflooding (LSWF) effects in the German Wealden Sandstone (intermediate clay-content). Therefore, we present a comprehensive workflow that combines different experimental approaches to determine LSWF effects in oil mobilization. Experiments included fluid optimization-characterization, spontaneous imbibition and coreflooding evaluations.
The workflow comprises the following steps: 1) Detailed fluid optimization/characterization based on typical German reservoir characteristics (including oil samples, brine composition and polymer solutions)-for mobility control-, 2) Routine core analysis (such as porosity, permeability, contact-angle and pore-size distribution), 3) Spontaneous imbibition evaluations for selected fluids -to assess wettability changes-, 4) Investigation of LSWF combined with polymer in coreflooding experiments (monitoring pressure response and mobilized oil vs PV injected), 5) Assessment of Streaming-Potential response for selected cores, to link with the LWSF effects and 6) Cross-checking the acquired data by performing a quantitative and qualitative analysis.
Results of this work allowed to validate three main mechanisms out of those reported in literature: 1) Wettability Alteration (contact angle and spontaneous imbibition), 2) Fine Migration (pressure responses along with fine production), and 3) Multi-ion exchange (Streaming-Potential decline). Half of the experiments in secondary-mode depicted a higher Recovery Factor. The less saline brine LSW2 (50-times diluted FW), injected after LSW1 (10-times diluted), did not recover any additional oil. This suggested that a higher reduction in salinity should be aimed for in future investigations. Tertiary-flooding with solely LSWF, showed a lower recovery than tertiary LSWF-PF flooding. This observation confirms the potential of polymer-combined LSWF in sandstones. Streaming-Potential measurements enabled the verification of the multi-ion exchange inside the rock pores during flooding. Results have shown a declining trend in voltage response, indicating the exchange of dissolved ions with the rock surface. Moreover, results of the Spontaneous Imbibition tests refuted the Low Salinity Effect (LSE) in aged cores. On one hand, the immersion in formation water has yielded 3.2% more oil compared to LSW1. On the other hand, in the case of non-aged cores the low saline brine released additional oil.
To the best knowledge of the authors, Low Salinity Water Flooding has yet not been investigated in the German Cretaceous Wealden Formation. This investigation provided excellent insights on recovery factor in secondary and tertiary-mode. Tertiary-mode flooding experiments provided clear evidence of the advantages of LSWF-PF. This could yield that the processes -when applied in tandem- become a leading EOR strategy. Moreover, fellow researchers can benefit with the presented data and workflows.
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Importance and Inclusion of Gas Diffusion in CO2 Emulsion Population-balance Model
Authors H. Luo, G. Ren, K. Ma, K. Mateen, V. Neillo, C. Blondeau, G. Bourdarot and D. MorelSummaryUnlike conventional foams made of nitrogen or methane, CO2 emulsion exhibits more complex behaviors in porous media. For instance, CO2 emulsions are relatively weak and do not exhibit sudden loss of apparent viscosity at very high foam quality. Compared to conventional foams in porous media that capillary suction is the main mechanism of bubble coalescence, gas diffusion is significantly enhanced in CO2 emulsion, but the relative contribution of the two emulsion destruction mechanisms and how to account for gas diffusion are rarely seen in the literature. To better understand the key underlying mechanisms, a comprehensive investigation of the CO2 emulsion stability is carried out and bubble coalescence due to gas diffusion is introduced in a population-balance model. First, analytical models are set-up to evaluate the characteristic times of capillary suction and gas diffusion under the same conditions. The analytical solutions suggest that the characteristic time of gas diffusion is comparable to that of capillary suction for CO2 emulsion, while it is one to two orders longer in case of N2 foam. Based on these analyses, a foam/emulsion model is developed through incorporating an additional gas diffusion term as a function of gas solubility, diffusivity, capillary pressure, temperature and several other variables. The new foam/emulsion model is used to fit a set of experiments of CO2 and N2 foams ranging among different foam qualities in the same core. The fittings were carried out using three different selections of the coalescence terms, i.e., the capillary suction term only, the gas diffusion term only, and both terms, for N2 foam and CO2 foam. The results reveal that using the original coalescence model (only capillary suction) can fit the N2 foam data but leads to mismatch with the CO2 data, while using the gas diffusion term only leads to mismatch with the N2 foam data but better match with the CO2 foam data. Using both terms was found optimum for the CO2 emulsion model. In addition, having the gas diffusion term enables to capture the gradual change of the foam strength with foam quality for CO2 foam instead of the abrupt change of foam strength for N2 foam near the limiting capillary pressure. Our research on this subject has unveiled the fact that gas diffusion is important for CO2 emulsion instability. This methodology is a key to evaluate the feasibility of improving CO2 EOR through foaming and to optimize such a process.
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Foam to Optimize Gas Injection Development Scheme: Labs Evidence and Simulation Forecast of Gas Control Efficiency
Authors C. Topini, M. De Simoni, L. Dovera, F. Rotelli, M. Bartosek, A. Abrar, D. Renna and E. BraccalentiSummaryThe present work aims to assess the potentialities of foam in mitigating the gas injection issues foreseen during water alternating gas injection (WAG) scheme, such as premature gas breakthrough at producers and gas cycling. Main objective is to demonstrate foam efficiency for an offshore oil field by integrating extensive dedicated laboratory testing, accurate reservoir modeling and preliminary facilities feasibility, key steps for field EOR application.
The adopted workflow focused on the close integration of different analyses allowing the characterization of the different phenomena and criticalities that may arise during foam injection application.
Lab tests started with an accurate in bulk surfactants screening to identify the best performer for the candidate reservoir.
Eleven foamers were tested and the best one was selected for the following core flood tests.
Core flood tests were performed at reservoir pressure and temperature conditions. Berea cores were first flooded under WAG scheme and then adding also a buffer of the optimized foamer solution (FAWAG scheme). Core flood results showed that injection of foam decreases gas and fluid mobility. The reduction of foamer performance in presence of oil was also evaluated.
Core floods results were matched and main foam parameters were obtained to perform field scale foam injection simulations. Two sets of parameters matching the available lab data were defined. Both of them were applied providing an optimistic and a pessimistic scenario. Field scale simulations highlighted that foam injection provided a positive effect on field oil production and GOR reduction; the best scenario highlights additional reserves of about 3% after 15 years of production associated with a 30% GOR reduction.
The pre-feasibility study identified the most suitable injection scheme and it assessed no major show stoppers from flow assurance. The preliminary cost estimate per incremental barrel associated to the implementation of the technology was also done.
Main conclusion of the study was that laboratory tests, numerical simulations and preliminary facilities assessment confirm the potentialities of foam injection for the candidate reservoir.
An integrated and comprehensive workflow was set-up to estimate the efficiency and benefits of foam injection. The presented workflow is currently being applied to assess foam injection potentiality for other fields within the company's portfolio.
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Parameter Estimation of a Population-balance Foam Model Using Two-step Multi-variable Search
Authors K. Ma, K. Mateen, G. Ren, H. Luo, V. Neillo, C. Blondeau, G. Bourdarot, D. Morel, O. M'barki and Q. NguyenSummaryEvaluation of modeling techniques for foam flow through porous media requires reliable laboratory measurements. Previously, a set of experimental data points have been collected in steady-state foam flood. Significant efforts have been made to mitigate foam hysteresis and to ensure experimental repeatability in each run by properly restoring the system.
In this work, we have investigated the steady-state behavior of the Chen et al population-balance foam model in porous media. The classic Nelder-Mead search algorithm is used to estimate the foam-model parameters from the abovementioned experimental data with a variety of total fluid velocities and foam qualities. Our results show that this foam model does not correctly model the high-quality foam regime as the limiting capillary pressure is not reached. Further analysis reveals that, depending on the initial guesses, two different steady-state saturations at the same foam quality can be obtained. We have identified that the quadratic formula in the foam coalescence equation is the source of the issue, with which the same foam coalescence rate results in two saturation values. Therefore, we have resolved the problem with significantly reduced bubble density when the capillary pressure exceeds the limiting value. The improvement in this model results in physically meaningful fit to the steady-state data with a unique solution. Additionally, sensitivity studies of the parameters indicate that the trapped gas function could be combined with other parameters in the model based on our steady-state data fit.
During this investigation we have discovered that the lack of proper initial guesses frequently causes convergence issues of the Nelder-Mead search algorithm. A new two-step approach is therefore developed with a combination of direct calculation and Nelder-Mead search to estimate the foam-model parameters. The new approach greatly reduces the parameter space explored in the algorithm, thus it significantly improves the computational efficiency and the convenience of probing a suitable set of initial guesses to mitigate convergence issues.
For the first time, we have provided methodology with improved multi-variable parameter search and evaluation of hysteresis-free steady-state foam data with a population-balance foam model. The improvement in the model makes it not only correctly simulate the effect of the limiting capillary pressure but also potentially more stable in reservoir simulation practices due to the elimination of non-physical solutions.
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Screening and Uncertainty Assessment of Foam-Assisted Water-Alternate Gas Injection
Authors H. Groot, J. Groenenboom, N.I. Kechut, N.M. Rahayu Razali, S. Vincent-Bonnieu and A. Mar-OrSummaryIn a Foam-Assisted Water-Alternate Gas injection (FAWAG) process, surfactant is used to reduce the mobility of the gas by creating foam in the reservoir. This process potentially improves the performance of a Water-Alternate Gas injection (WAG) process. The effective dynamic behaviour of FAWAG can be highly complex and often stands in contrast to the behaviour of WAG. This paper presents insights in the effective dynamic behaviour of FAWAG and a comparative study of its sensitivity to uncertainties, reservoir conditions, field design and modelling assumptions, which is important for risk mitigation, opportunity realisation and process optimisation. In this paper the FAWAG process is modelled from the assumption of local equilibrium of foam creation and coalescence using an Implicit Texture model. Sensitivities to uncertainties, pattern design and reservoir screening parameters are studied to identify and analyse the key parameters impacting the FAWAG process as opposed to a WAG process and quantify the reliability of production forecasts with FAWAG. A box reservoir model is used for the study that represents a line drive pattern and can mimic a wide range of different reservoir conditions, injection strategies and pattern designs. A ranking is made of the sensitivity parameters according to their ultimate impact on oil recovery. The results are compared with the literature.
From the sensitivity study it is concluded that FAWAG is mostly sensitive to permeability and well-spacing because of the relatively low throughput rate, while in contrast WAG is mostly sensitive to reservoir heterogeneity and oil viscosity as the process requires high displacement stability. In addition, FAWAG requires high throughput rate or project duration to overcome high heterogeneity and oil viscosity in the long run. It shows that the optimal conditions for a successful FAWAG are high permeability, small well-spacing, high layer connectivity and favourable conditions for injectivity. Furthermore, FAWAG can still be expected to perform well in a reservoir with high heterogeneity and reasonably high oil viscosity, which could turn out to be detrimental conditions for iWAG. Finally, a successful FAWAG project requires optimal conditions for foam generation in the reservoir, which means foam strong enough to improve mobility control, yet not too strong to impair injectivity. However, the optimal conditions for foam at field scale often prove to be highly uncertain in practice and should be determined from field pilots or injectivity tests.
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Injectivity of Multiple Gas and Liquid Slugs in SAG Foam EOR: A CT Scan Study
SummarySurfactant-alternating-gas (SAG) is often the injection method for foam enhanced oil recovery (EOR) in order to improve injectivity. However, liquid injectivity can be very poor once foam is created in the near-wellbore region. In a previous study, we reported core-flood experiments on liquid injectivity after foam flooding and liquid injectivity after a period of gas injection following foam. Results showed the importance of the gas slug to subsequent liquid injectivity. However, the effects of multiple gas and liquid slugs were not explored.
In this paper, we present a coreflood study of injectivities of multiple gas and liquid slugs in a SAG process. We inject nitrogen foam, gas and surfactant solution into a sandstone core sample. The experiments are conducted at a temperature of 90°C with 40-bar back pressure. Pressure differences are measured to quantify the injectivity and supplemented with CT scans to relate water saturation to mobility.
We find that during prolonged gas injection in the first gas slug following foam, a collapsed-foam region forms near the inlet due to the interplay of evaporation, capillary pressure and pressure-driven flow. This region slowly propagates downstream. During subsequent liquid injection, liquid mobility is much greater in the collapsed-foam region than downstream, and liquid sweeps the entire core cross section there rather than a single finger. In the region beyond the collapsed-foam region, liquid fingers through foam. Liquid flow converges from the entire cross section to the finger through the region of trapped gas.
During injection of the second gas slug, the liquid finger disappears quickly as gas flows in, and strong foam forms from the very beginning. A collapsed-foam region then forms near the inlet and slowly propagates downstream with a propagation velocity and mobility similar to that in the first gas slug. Behavior of the second liquid slug is likewise similar to that of the first liquid slug.
Our results suggest that, in radial flow, the small region of foam collapse very near the well is crucial to injectivity because of its high mobility. The subsequent gas and liquid slugs behave like the first slugs. The behavior of the first gas slug and subsequent liquid slug is thus representative of near-well behavior in a SAG process.
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Foam Propagation at Low Superficial Velocity: Implications for Long-Distance Foam Propagation
Authors G. Yu, S. Vincent-Bonnieu and W. RossenSummarySince the 1980s experimental and field studies have found anomalously slow propagation of foam that cannot be explained by surfactant adsorption. Friedmann et al. (1994) conducted foam-propagation experiments in a cone-shaped sandpack and concluded that foam, once formed in the narrow inlet, was unable to propagate at all at lower superficial velocities towards the wider outlet. They hence concluded that long-distance foam propagation in radial flow from an injection well is in doubt.
Ashoori et al. (2012) provide a theoretical explanation for slower or non-propagation of foam at decreasing superficial velocity. Their explanation connects foam propagation to the minimum velocity or pressure gradient required for foam generation in homogeneous porous media ( Gauglitz et al., 2002 ). The conditions for propagation of foam are less demanding than those for creation of new foam. However, there still can be a minimum superficial velocity necessary for propagation of foam, except that it could be significantly smaller than the minimum velocity for foam generation from an initial state of no-foam. At even lower superficial velocity, theory ( Kam and Rossen, 2003 ) predicts a collapse of foam.
In this study, we extend the experimental approach of Friedmann et al. in the context of the theory of Ashoori et al. We use a cylindrical core with stepwise increasing diameters such that the superficial velocity in the outlet section is 1/16 of that in the inlet. N2 foam is created and stabilized by an alpha olefin sulfonate surfactant. Previously ( Yu et al., 2019 ), we mapped the conditions for foam generation in a Bentheimer sandstone core as a function of total superficial velocity, surfactant concentration and injected gas fraction (foam quality). In this study, we extend the map to include the conditions for propagation of foam, after its creation in the narrow inlet section at greater superficial velocity. Thereafter, by reducing superficial velocity, we map the conditions for foam collapse.
Our results suggest that the minimum superficial velocities for foam generation, propagation and maintenance increase with increasing foam quality and decreasing surfactant concentration, in agreement with theory. The minimum velocity for propagation of foam is much less than that for foam generation, and that for foam maintenance is less than that for propagation. The implications of our lab results for field application of foam are discussed.
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Coreflood Study of Non-Monotonic Fractional-Flow Behavior with Foam: Implications for Surfactant-Alternating-Gas Foam EOR
Authors R.O. Salazar Castillo and W. RossenSummaryFoam is able to increase gas's sweep efficiency in Enhanced-Oil-Recovery applications. A surfactant-alternating-gas, or SAG, process is usually preferred for placing foam in the reservoir. During a SAG process, foam is generated away from the wellbore, offering both good injectivity and good mobility control at the leading edge of the foam bank.
Scale-up of laboratory data for SAG to field applications remains a challenge. Direct scale-up of dynamic SAG coreflood results is unreliable because of the dominance of core-scale artifacts. Steady-state coreflood data can be scaled up using fractional-flow theory ( Kibodeaux and Rossen, 1997 ; Rossen and Boeije, 2015). However, about half the published laboratory studies of foam fractional-flow curves report non-monotonic behavior, where at some point liquid saturation Sw increases with decreasing liquid fractional flow fw. Rossen and Bruining (2007) warn that such behavior would result in foam collapse during injection of the gas slug in a SAG process at the field scale. Here we report and analyse a series of steady-state and dynamic coreflood experiments to investigate the occurrence of non-monotonic fractional-flow behavior. These corefloods vary surfactant concentration, injected gas fraction (foam quality) and total superficial velocity and are supported by CT measurements. The CT data confirm that in these cases, as foam weakens with decreasing fw, liquid saturation increases, confirming the non-monotonic fw(Sw) behaviour.
In our results, every case of non-monotonic fractional-flow behavior begins with propagation of foam from the inlet, followed by eruption of a much-stronger foam at the outlet of the core and backwards propagation of the stronger foam state to the inlet, similar to behavior reported by Apaydin and Kovscek (2001) and Simjoo et al. (2013) . This suggests that there may be more than one stable local-equilibrium (LE) foam state. The initial creation of the stronger foam near the outlet is at least in part due to the capillary end effect. It is thus not clear which LE foam state controls behaviour in a SAG process in the field.
In our results, the subsequent transition from a stronger- to a weaker-foam state, leading to non-monotonic fw(Sw) behavior, coincides with conditions for weaker foam (lower surfactant concentration, lower fw) and less-vigorous foam generation (lower superficial velocity); this agrees with the theory of foam propagation of Ashoori et al. (2012) . We discuss the implications of these findings, if confirmed to apply generally, for design of SAG foam processes.
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Isolation and Characterization of Endogenous Crude Oil Surface Active Species and their Implication in the Formulation of Surfactants for EOR
Authors V. Molinier, A. Klimenko, M. Loriau, L. Ligiero, M. Bourrel and N. Passade-BoupatSummaryIn SP (Surfactant Polymer) and ASP (Alkali Surfactant Polymer) EOR processes, the surfactant role is to reduce the oil/water interfacial tension down to extreme values (10-3 mN/m and lower). The surfactant blend has to be adapted to the specific conditions of each reservoir, i.e. to the temperature, water in place salinity and crude oil nature, through rigorous phase behavior studies. If the effects of temperature and salinity on surfactants phase behavior are well established, the impact of crude oil, and particularly of its endogenous surface active species, is much less understood.
Naphthenic acids and asphaltenes are the two crude oil components families that are usually described as having interfacial activity. Their implication in physical-chemical problems linked to surface activities, as emulsion and foam formation in separators, is well documented. However, their role in the presence of surfactants for EOR applications has been much less studied, even if ASP processes take advantage of the global contribution of naphthenic acids salts to the reduction of oil/water interfacial tension. Gaining insights on the interfacial activity of these endogenous surfactants in the presence of synthetic detergents could help select and eventually design the most efficient EOR surfactants.
In this work, several techniques have been used to isolate the surface active species of a medium-density oil: naphthenic acids have been isolated by liquid-liquid extraction, asphaltenes have been precipitated with n-heptane and global interfacial materials have been extracted by emulsification and by using the wet-silica method. These natural surfactants have been characterized from a physical-chemical (tensiometry, phase behavior in model systems) and from an analytical (mass spectrometry) point of view. The phase behavior of EOR surfactants with the crude oil cleared from these components has also been studied, with and without alkali. All these experiments allowed confirming the surface activity of these crude oil extracts. Moreover, their contributions to the interfacial activity in the presence of EOR surfactants have been evaluated and compared, which gives some insights on the role of these species in surfactant formulation optimization.
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Modeling Alkali-Polymer Corefloods in Viscous Oil
Authors A. Perez-Perez, C. Romero, A. Klimenko, E. Santanach, G. Bourdarot and I. BogdanovSummaryThe injection of alkali in acidic viscous oils is known to promote the in-situ formation of emulsions during chemical oil recovery. Naphthenic acid components react with the alkali to form in-situ surfactants, which support oil emulsification at the water-oil interface. Experimental observations confirm that emulsification and transport of the dispersed oil in presence of polymer can improve oil recovery significantly.
In this work a new mechanistic non-equilibrium model is proposed to simulate Alkali-Polymer processes (AP) for viscous oil. The model takes into account emulsion generation kinetics, polymer and emulsion non Newtonian viscosity through a straightforward modelling strategy. In this model, the emulsified oil is treated as a dispersed component in water phase, while water mobility is represented by an apparent water viscosity containing dispersed oil and polymer. Shear rate effects were considered for both polymer and emulsion viscosities and viscous fingering was included using the effective fingering model developed recently at the University of Texas to retrieve the initial condition after secondary water flood/polymer flood process.
Seven Alkali-Polymer (AP) corefloods were successfully history-matched using this new approach to interpret AP corefloods mainly as a tertiary recovery process. Different alkali types were evaluated at different concentrations and slug sizes. In all cases, a high molecular weight partially hydrolyzed polyacrylamide (HPAM) was used as polymer. Oil viscosity was between 2000–3500 cP @ 50°C.
Numerical results show that the proposed model is capable of appropriately matching oil production, total pressure drop and oil cut, when the oil bank formed at emulsion breakthrough is composed by non-emulsified oil and dispersed oil. Kinetics obtained by history match indicate that emulsions can be generated at different rates depending on the choice of the alkali and that emulsion properties will also change depending on the alkali type. This development provides to our knowledge, one of the first alkali-polymer models to take into account the unstable displacement framework and modified water phase non Newtonian viscosity including emulsion and polymer.
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Evaluation and Prediction of Emulsion Formation in Produced Fluids during an ASP Flood Applied to a Carbonate Reservoir in Kuwait
Authors A. Qubian, S. Adkins, H. Al-Enezi and M. DelshadSummaryThis work is concerned with the nature of produced fluids resulting from ASP injection in a carbonate reservoir in Kuwait. The main objective is to examine and identify the nature of produced emulsions at conditions and chemical concentrations that are predicted by numerical simulation studies of the ASP pilot. The laboratory element of the work provides emulsion handling insight before the pilot begins, to reduce potential downtime and production costs.
Laboratory tests and numerical simulations were used to identify the nature of the produced fluids. The simulations used a pilot-scale model to determine realistic ranges of chemical concentrations. The laboratory study used these pre-determined concentration ranges to form, observe, and characterize the emulsions. Key variables that increase emulsion formation and stability are determined. Variables studied include total surfactant concentration, surfactant ratio, polymer, effects of crushed core, temperature, pH, salinity, and viscosity.
O/W and W/O emulsions were formed with a typical emulsion stability pattern of sedimentation followed by coalescence. The emulsion stability varied with conditions. The conditions leading to the most-stable and problematic emulsions included high surfactant, high polymer concentrations, low temperatures, and high salinity. Dense, creamy emulsions were the most stable. When surfactant concentration was increased, interfacial tension decreased, stability increased, and water and oil qualities decreased. A low interfacial tension allowed smaller (more stable) droplets to form, slowed sedimentation, and if low enough stabilized drops against coalescence. As polymer concentration increased, the aqueous viscosity increased and slowed sedimentation, water quality increased, and oil quality decreased. Shearing the polymer (reducing the viscosity) increased sedimentation. Emulsion stability decreased markedly when the temperature was increased. Sedimentation and coalescence were faster, giving an improved oil quality. Lower oil/water viscosities and densities, plus higher thermal energy destabilize the emulsions.
Pilot recommendations: At low surfactant concentration, adequate residence time in the separator is needed, where the phases exiting will be easier to break. For higher surfactant concentrations, in-field bottle-testing of stable, dense emulsions is needed to select a chemical demulsifier and neutralize the surfactant. The success of chemical EOR pilots can be jeopardized due to the formation and stability of produced emulsions. Increased downtime and unplanned mitigation costs may ruin a pilot. Limited ASP emulsion handling resources are available in industry due to the limited ASP pilots made public worldwide. This work provides additional produced emulsion resources and investigations before the pilot begins and also addresses new challenges in a carbonate reservoir ASP flood.
AbstractThis work is concerned with the nature of produced fluids resulting from ASP injection in a carbonate reservoir in Kuwait. The main objective is to examine and identify the nature of produced emulsions at conditions and chemical concentrations that are predicted by numerical simulation studies of the ASP pilot. The laboratory element of the work provides emulsion handling insight before the pilot begins, to reduce potential downtime and production costs.
Laboratory tests and numerical simulations were used to identify the nature of the produced fluids. The simulations used a pilot-scale model to determine realistic ranges of chemical concentrations. The laboratory study used these pre-determined concentration ranges to form, observe, and characterize the emulsions. Key variables that increase emulsion formation and stability are determined. Variables studied include total surfactant concentration, surfactant ratio, polymer, effects of crushed core, temperature, pH, salinity, and viscosity.
O/W and W/O emulsions were formed with a typical emulsion stability pattern of sedimentation followed by coalescence. The emulsion stability varied with conditions. The conditions leading to the most-stable and problematic emulsions included high surfactant, high polymer concentrations, low temperatures, and high salinity. Dense, creamy emulsions were the most stable. When surfactant concentration was increased, interfacial tension decreased, stability increased, and water and oil qualities decreased. A low interfacial tension allowed smaller (more stable) droplets to form, slowed sedimentation, and if low enough stabilized drops against coalescence. As polymer concentration increased, the aqueous viscosity increased and slowed sedimentation, water quality increased, and oil quality decreased. Shearing the polymer (reducing the viscosity) increased sedimentation. Emulsion stability decreased markedly when the temperature was increased. Sedimentation and coalescence were faster, giving an improved oil quality. Lower oil/water viscosities and densities, plus higher thermal energy destabilize the emulsions.
Pilot recommendations: At low surfactant concentration, adequate residence time in the separator is needed, where the phases exiting will be easier to break. For higher surfactant concentrations, in-field bottle-testing of stable, dense emulsions is needed to select a chemical demulsifier and neutralize the surfactant. The success of chemical EOR pilots can be jeopardized due to the formation and stability of produced emulsions. Increased downtime and unplanned mitigation costs may ruin a pilot. Limited ASP emulsion handling resources are available in industry due to the limited ASP pilots made public worldwide. This work provides additional produced emulsion resources and investigations before the pilot begins and also addresses new challenges in a carbonate reservoir ASP flood.
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Why is it so Difficult to Predict Polymer Injectivity in Chemical Oil Recovery Processes?
Authors A. Thomas, M.A. Giddins and R. WiltonSummaryPolymer injection to improve and/or accelerate oil recovery is a widespread technique with numerous ongoing and successful projects. In recent years, many field cases have been reported with injected polymer viscosity ranging from 5 to 160cP, producing large incremental oil volumes, without major injectivity issues. These field results often contradict pessimistic predictions of injectivity from prior studies. Despite abundant publications on the subject, there is no standard explanation of the reasons for discrepancies between forecast and actual behavior, and many questions are not yet fully answered. Will it be possible to inject the polymer solution at target viscosity? How much to inject? How fast? Will high pressures lead to fracturing or polymer degradation? Should the polymer solution be pre-treated, pre-sheared? What should be done if planned injection rates are not achievable? Will injectivity decline over time? These questions are very topical when it comes to building a business case for EOR, using 3D reservoir simulation models for forecasting production and calculating the economics of the project. In this paper, we present a critical review of selected field cases from the literature, analyzing reservoir characteristics and development history as well as properties of the injected solution. We discuss the mechanisms which can affect injectivity, including polymer solution rheology, near-well flow regimes, reservoir heterogeneity and geomechanical effects, and how these mechanisms can be represented in reservoir simulation models. Based on this investigation, we propose appropriate methodologies for dynamic modeling of polymer injection, considering the impact on predicted flow behavior of assumptions about polymer physics, selection of key parameters for sensitivity studies and the issues of upscaling from core experiments to the field. We suggest guidelines for using laboratory measurements and field observations, and for implementing forecasting workflows. Finally, we make recommendations on designing a practical field injection and monitoring program, to obtain data for calibrating models and improving future predictions.
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Analysis and Simulation of Polymer Injectivity
Authors J.G. Jacobsen, M. Alzaabi, S. Tormod, K. Sorbie and A. SkaugeSummaryPolymer flooding is one of the most successful and mature chemical EOR methods. Qualification programs, which often include injectivity and/or performance pilots, are a prerequisite to reduce risk in further implementation. The former being typically pressure fall-off tests and the latter single well tracer tests (SWTT). However, limited work has been conducted on assessing interpretability and uncertainty associated with these tests. This is something of a paradox since investments to perform these pilots are large and implications of successful versus failed pilots are enormous.
In field tests, only injection bottom-hole pressure (BHP) and volumetric injection rate are the available parameters to determine polymer in-situ rheology. In addition, analysis of pressure fall-off tests for polymer injections are far more complex compared to water and gas due to the non-Newtonian behavior of the polymer. The following question remains: what rheological information is actually obtainable based solely on BHP? Moreover, how sensitive is polymer rheology estimation to uncertainties in pressure measurements? Can high uncertainties in pressure data completely distort the rheological information obtained? Lastly, is pressure response from the near wellbore region sufficient to obtain accurate estimations of polymer injectivity in porous media?
The aforementioned issues are investigated herein by modelling pressure fall-off tests using the STARS simulation tool (CMG). Generic field data were used to design a near-well sector and a high molecular weight partially hydrolyzed polyacrylamide (HPAM) was used as polymer reference. Here, the influence of different polymer rheological behaviors on BHP and BHP-transient was analyzed and identified.
Influence of pressure measurement noise on polymer rheology was evaluated using the automated history-matching tool CMOST (CMG) for lab scale simulations. A recently developed history match method, based on pressure measurements from internal pressure taps distributed between injector and producer, was used. Even though results showed deviations from a generic (base case) rheology curve for individual rates, the arithmetic average of these curves displayed negligible deviation from its generic behavior below a threshold noise level. Moreover, simulations show that polymer injectivity is solely dependent on polymer behavior in the near wellbore region. Finally, two different flood experiments using the same HPAM polymer were history matched and results confirm the conclusions suggested in the simulation study.
This paper provides additional interpretational anchoring for pressure fall-off test for polymer injectivity assessments. Additional methods and insights developed in this paper should both improve experimental design and reduce implementation risk for polymer flood projects.
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A Scientific Approach for Generating a Rheology Model to Simulate Polymer Injectivity
Authors D.C. Raharja, D. Prasad and C. MittelbachSummaryModelling polymer injection at near-wellbore conditions is challenging, as it is strongly affected by Non-Newtonian polymer rheology among other parameters. During polymer injection, viscosities vary significantly near the wellbore where flow velocities and therefore shear rates are high. Current commercial reservoir simulators have limited capabilities in capturing this behaviour. Modification of properties on each grid around the injector including reducing fluid viscosity, increasing permeability along with building extremely fine grid is often performed in the simulation. However, this results in limited prediction capability and will be inefficient for full field simulation where multiple injectors with different properties and rates must be considered. This paper presents both; a workflow to generate an appropriate rheology model using viscometer and core flood data, and polymer injectivity simulation.
Viscosity vs. shear rate and viscosity vs. velocity data has been generated from rheometer and core floods at different velocities respectively. Data is then plotted together after converting core flood velocities into shear rate. A correction factor is established by matching viscosity at high shear rate regimes. Based on this, a rheology model for highly shear thinning biopolymer Schizophyllan was generated using Carreau-Yasuda correlation. The rheology model was then used to simulate and match the bottomhole pressure (BHP) response of a recently conducted single well test in 2017 using conceptual radial and actual Cartesian grid model. The matching was achieved with and without grid refinement for the Cartesian model while correcting the skin factor for the grid size (Behr et al.). Matching exercise required numerical tuning due to highly shear thinning behaviour. Additionally, the same rheology model was validated by matching the multi-well pilot injector BHP for a longer period without any near wellbore modification. In contrast, earlier matching attempts had required multiple modifications in either viscosity or permeability at different time periods with progressing flood.
The newly generated rheology model accounts for both viscometer and core flood data and represents the polymer behaviour much closer to reservoir performance. The results from the single- and multi-well polymer injection simulation showed a decent history match without any near wellbore grid property modification.
The workflow to generate a rheology model and deriving a shear correction factor is relatively novel for this biopolymer. The advantage of such a rheology model becomes more distinct for the simulation and history matching of a full field scale polymer injection with multiple injectors, as the overall process can be simplified.
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Modeling of Associative Polymer Flow in Porous Medium
Authors A. Lohne, A. Stavland and R. Reichenbach-KlinkeSummaryPrevious core flood investigation of acrylamide-based polymers with associative thickening properties indicated in-situ flow resistance factors (RF) significantly higher than experienced with non-associative polymers having similar bulk rheological properties. Here we propose a novel model for associative polymers which handles the formation of an in-situ polymer network and captures its properties in different flow regimes and at various polymer concentrations. The model is implemented in an in-house black-oil simulator and will allow more robust core-to-field scaling of laboratory results.
The modeling is validated by simulating a set of core experiments conducted with the same polymer but with different concentrations.
In the experimental study the polymer was injected at variable flow rates into dual serial mounted cores with 100 % water saturation. The results are compared with results obtained with a non-associative polymer with similar bulk rheological properties. The increased flow resistance due to injected polymer was observed to propagate as two fronts. The first front had flow resistance consistent with measured bulk viscosity and a velocity typical for non-associative polymer, while the second front had up to two order of magnitude higher RF and the velocity was lower and dependent on the injected polymer concentration. Another characteristic observed for these types of polymer is the moderate sensitivity of the steady-state pressure drop to changes in the flow rate.
In the proposed model, the associative polymer is treated as a mixed polymer system consisting of a smaller fraction rich in hydrophobic groups and a larger fraction with properties like a regular synthetic polymer. For both fractions, we include typical rheological behavior observed for regular synthetic polymers in flow regimes; shear thinning, shear thickening (elongational flow) and mechanical degradation when going from low to high shear rate. The formation of a pore filling network is modelled as a shear rate dependent retention of the smaller hydrophobic fraction and its additional flow resistance is obtained using a Carman-Kozeny approach.
Simulations of the experiments conducted with 100 % Sw demonstrate that the model can reproduce observed effects like pressure front velocities at different polymer concentrations and responses in RF to rate variations. The model was also applied to two-phase experiments. Effect of water saturation was included in appropriate terms and the RF in presence of oil is captured. Finally, we demonstrate how temperature dependent associative behavior can be utilized at the field scale in a simple large-scale model.
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Flexible Coiled Polymer Dynamics in a Single Pore Throat with Effects of Flow Resistance and Normal Stresses
Authors E. Eguagie, S. Berg, J. Crawshaw, S. De and P. LuckhamSummaryWe investigate the challenges involved in the use of polymer flooding as a chemical enhanced oil recovery (cEOR) technique for improving mobility ratio and enhancing macroscopic sweep efficiency. Flexible coiled polymers in porous media undergo stretching in a spatially heterogeneous structure. Due to the viscoelasticity of these polymers, they stretch continuously depending on their previous deformation until their elastic limit is reached and relaxation occurs. Previous research has proposed that at a certain critical flow rate, the relaxation of polymers cause an increase in viscosity and in turn a better mobility for enhancing microscopic sweep in porous media. However, others have reported that the increased viscosity in porous media is not so much related to the elasticity but more on the normal stresses that occur when polymers are sheared in porous media flow. One similar fact is that as increased viscosity is observed an enhanced pressured drop occurs and the flow becomes highly unstable even at laminar flow regime. This unstable flow is termed the elastic instability or turbulence but the details of this kind of turbulence, its consequences and applicability on the impact of oil recovery is not understood. In this work, we experimentally investigate the flow behaviors of flexible coiled polymers of hydrolyzed polyacrylamide (HPAM) based on a single pore throat geometry using a microfluidic device. The aim is to adequately parameterize the effects of the normal stress difference in shear and extension as a function of the geometry and intrinsic characteristics of the polymer solutions at different Deborah (De) numbers. Hence, we carry out pressure drop and particle image velocimetry experiments and results showed a critical De at which polymer viscosity increases as well as the normal stress difference. It was also observed that the flow resistance might be a function of both the elasticity and the normal stresses in shear flow, however, extensional stresses cannot be neglected.
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Novel Insights on the Transport of HPAM Solutions in Low Permeability Porous Media: Impacts of Brine and Reservoir Properties
Authors I. Guetni, C. Marlière, D. Rousseau, I. Bihannic, M. Pelletier and F. VilliérasSummaryChemical EOR is now considered as an attractive option for low permeability reservoirs, in particular where lack of gas supply does not allow gas injection processes. However, its application can be challenging for permeabilities below 100 mD as poor injectivity and high chemical retention are frequently observed. This work aimed at investigating the impact of both chemical and mineralogical parameters on the transport of polymer solutions in well-controlled low permeability porous media.
Selected polyacrylamide (HPAM) solubilized in brines of variable strengths and hardnesses were injected in granular sand and clays packs having similar petrophysical characteristics (permeability around 60–80 mD) but variable and well controlled mineralogical compositions. The granular packs were characterized in terms of structure (SEM) and specific surface area (BET) before and after polymer injections. The main observables of the coreflood tests were the resistance and residual resistance factors generated by the polymer, the polymer inaccessible pore volume and its irreversible retention.
Viscometric analysis showed that the HPAM solutions intrinsic viscosity decreased with increasing total salinity, as expected from charge screening, with a sharp decrease in presence of divalent cations, even at low ionic strength, which was less expected. Coreflood experiments revealed that polymer retention, resistance factor and irreversible resistance factor increased significantly: (a) with increasing ionic strength and hardness for porous media of a given mineralogical composition (this appeared consistent with the outcomes of the viscometric study and confirmed the major impact of hardness); (b) in presence of clays, even at low ionic strength and hardness. The polymer inaccessible pore volume was significantly impacted by the presence of clays, but not by the brine composition.
Assuming that polymer retention originated in polymer adsorption, irreversible resistance factors were translated into adsorbed layer thicknesses according to a simple capillary bundle model. This allowed discussing the results in terms of adsorbed layer density, which was showed to increase if brine hardness was increased and to be lower in presence of illite than kaolinite and pure quartz. These findings indicate that complex polymer adsorption/retention mechanisms occur depending on the clay type (layer charge and expandability).
This systematic study allowed dissociating the impacts of salinity, hardness and clay contents/types on the transport properties of polymer solutions in low permeability porous media. Its results should be of interest to the chemical EOR industry as they provide guides to help tuning the injection brine composition and polymer concentration to the reservoir properties.
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Numerical Study of Polymer Flow in Porous Media using Dynamic Pore Network Modelling
Authors N. Zamani, I. Cecilie Salmo, K. Sorbie and A. SkaugeSummaryPolymer flooding is a mature EOR technology, in which polymer is generally used to modify mobility ratio to improve volumetric sweep efficiency. Some experimental and numerical studies have revealed that beside volumetric sweep efficiency, polymer is also able to increase microscopic sweep efficiency by mobilizing trapped and diverting fluid towards by-passed oil. Polymer solution is a non-Newtonian fluid, meaning that its viscosity may change at different flow conditions; it may show both shear thinning as well as “flow thickening” behaviour when the extensional viscosity increases sharply at higher flow rates. Both experimental and numerical studies confirm that microstructure properties of rock samples such as pore aspect ratio and connectivity play important role on in-situ rheological properties of polymer solution, especially on the onset of extensional viscosity. Onset of extensional viscosity is an important factor for two reasons: (I) its impact on polymer solution injectivity and (II) its role in potential oil mobilization. Therefore, for an efficient polymer flooding design, several parameters of both rock and polymer properties should be considered, and if possible optimised.
Traditional pore network models use an invasion-percolation approach, which causes some limitations to include EOR methods, since this describes a purely drainage process. However, dynamic pore network modelling of imbibition is more relevant for including EOR processes. In this study, we have developed a new dynamic imbibition approach for pore network model (based on Li et al., 2017 ) for polymer flow, for both single and two-phase flow. Rheological properties such as shear-thinning, shear thickening and a complex rheological model, (includes both shear thinning and shear thickening behaviour) are included in the code. We have studied effect of porous media properties on the onset of extensional viscosity and the code has been validated by comparing with Chauveteau's experimental results and results from the Navier-Stokes approach ( Zamani et al., 2015 ). It is shown that by increasing the aspect ratio, onset of extensional viscosity happens at lower injection rate, which is consistent with experimental and numerical studies.
In addition, effect of polymer solution rheology on fluid distribution at different mobility ratios and initial water saturations are studied. The results show that, at adverse mobility ratio, the more viscous polymer makes thicker fingers and sweep more oil in domain and more injecting fluid is diverted into the bonds perpendicular to the main flow. Meanwhile, higher initial water saturation significantly reduces the sweep efficiency at different mobility ratios.
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The Effect of Total Dissolved Solids and Permeability on the EOR Low Salinity Water Flooding
Authors H. Al-Saedi, R. Flori and W. Al-BazzazSummaryLow salinity (LS) water flooding is an eminent enhanced oil recovery technique due to its performance, cost-effectiveness and the interesting results of oil recovery.
To investigate the benefits of LS water in a different range of low permeable sandstone reservoir, different cores were sampled from different depths of the Bartlesville Sandstone Reservoir located in Eastern Kansas. Three pairs of cores were categorized based on their permeabilities. Four different brine salinities (formation water [FW] salinity is 104,550 ppm and others are diluted from FW) were examined for each pair to probe the role of both dissolved solids and permeability on the LS water performance.
The core-flood results show that as the permeability decreases, the injection of LS water into cores not flooded with FW in the secondary stage is increased. The subsequent flooding of the four brines (including LS water) provided a higher oil recovery than injecting LS water alone regardless of the permeability. The oil recovery using only LS water flooding is higher than the combined FW-d2FW-d10FW flooding in all scenarios, and the highest was 8.93% of the OOIP. The oil recovery using only LS water flooding was higher than FW flooding in all scenarios, and the highest was 15.46% of the OOIP.
On the other hand, the contact angle measurements show that the contact angle of the cores flooded with only LS water is lower than the other cores. This study demonstrates the importance of LS water in low permeable sandstone reservoirs.
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Emulsification Mechanisms in Alkali-Surfactant-Polymer (ASP) Flooding Enhanced Oil Recovery
More LessSummaryAlkali-surfactant-polymer flooding (ASP) is one of most attractive chemical EOR techniques in view of incremental recovery upon waterflooding. Emulsification mechanism in ASP flooding is very important but not well understood. Effects of emulsification in ASP flooding is reviewed based on reported field tests as well as laboratory studies, especially on progress and understanding of ASP flooding in China, where the only commercial ASP flooding has been conducted. The main mechanism of ASP flooding can be summarized to the displacement efficiency improvement due to the ultra-low interfacial tension (IFT) between oil and water and the sweep efficiency increase due to mobility control technique by polymer viscosifying and emulsification effect. Emulsification is crucial in ASP flooding since all ASP flooding pilots were seen emulsification with different extent. Oil emulsifying and emulsion profile controlling was regarded as important in ASP flooding mechanisms. Laboratory tests showed that emulsification increase the oil recovery by 5%-6% when emulsified compared with not emulsified. Experience from Daqing oilfield in China reported that contribution of emulsifying ability of ASP system to oil displacement efficiency can be as high as 30%. Factors affecting emulsification included the properties of oil and water, type and concentration of chemical, water cut, external force applied and permeability. Effects of alkali to ASP system and oil emulsification was carefully studied. IFT was an important but not crucial factor to emulsification. Lower IFT at higher alkali concentration promoted easier emulsification, while too low IFT was detrimental to emulsion stability due to the competitive adsorption of in-situ surfactants and added surfactant in oil/water interface. Addition of polymer was beneficial to the stability of emulsion and the effect of associate polymer recent was obvious. ASP field tests in Daqing oilfield verified the emulsify ability of NaOH was almost the same as Na2CO3, which was quite different from laboratory studies. In all development stages of ASP flooding, emulsification was seen. Injection pattern and water cut affected emulsification. Separate injection of alkali and surfactant as one system, while polymer as the other make higher degree of O/W type emulsion. Emulsification in main slug and vice slug showed difference characteristics, which was attributed to the relative content of surfactants in different water cut stage.
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Polymer Flooding Optimization, Minimizing Fouling in Heat Exchangers
Authors O. Vazquez, M. Cooper, M. Al Kalbani, A. Beteta and E. MackaySummaryPolymer flooding is a well-known enhanced oil recovery (EOR) technique, commonly deployed after water flooding as tertiary recovery. Management of the water produced is an important aspect in production operations, particularly in terms of flow assurance. There has been a great deal of attention to impact of water cycle in production facilities, in terms of inorganic mineral scale deposition, hydrate formation and corrosion. However, the interaction of the water produced and the injected EOR chemicals has not been as thoroughly studied, despite the fact of the significant impact on surface production facilities. Fouling in heat-exchangers is not commonly considered in polymer flooding EOR strategies at the front end engineering and design (FEED) stage. The structure of EOR polymers makes them susceptible to multiple factors within a reservoir environment, such as thermal hydrolysis and the presence of divalent ions the produced water. Polymers in the presence of divalent cations precipitate, known as cloud point, where compatibility reduces with temperature. Therefore, fouling in heat exchangers is expected, when polymer breaks through, and as a consequence the rate of heat transfer decreases. Although, the exact mechanism is extremely complex, due to the numerous chemical and physical phenomena, it depends mainly on the nature of the crude oil and the composition of the produced brine, particularly the concentration of divalent ions. In this study, the impact of fouling in the production facilities is described by the Fouling Index (FI), which is the product of divalent ions concentration in the produced water and the produced polymer concentration.
The purpose of this manuscript is to identify optimum polymer flooding strategies in a five-spot pattern heterogeneous synthetic reservoir model, minimizing the level of fouling in the heat exchangers, by minimizing FI. Fouling in heat exchangers prevent the efficient production of hydrocarbons; with the corresponding halt in production and loss of revenue. The optimization results identified the optimum injection polymer concentration and optimum injection water salinity. The results highlighted that reducing the salinity around 50% of the original value, the project net present value (NPV) was optimized, minimizing FI and therefore achieving an optimum oil production. The reduction of salinity can be achieved economically using nano-filtration at the lowest level of rejection, 60%. In conclusion, the results identified optimum polymer flooding strategies, where oil recovery and NPV is maximized, fouling is minimized, aiming for the most efficient continuous oil production.
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Development of Effective Carbonate Steamflood Strategy Using Full-field Simulation Models and Machine Learning Algorithms
Authors S. Ursegov, A. Zakharian, E. Taraskin and A. RunenkovSummarySteamflooding is a widely used thermal method for recovering heavy oil from sandstone reservoirs. In carbonates, the implementation of steamflooding usually demonstrates higher steam-oil ratio and lower oil recovery. The key performance problem is a poor sweep efficiency of steam injection. It is fully confirmed by actual results of steamflooding in the Permian – Carboniferous carbonate reservoir of the Usinsk field located in Northwest European Russia.
The reservoir has the largest heavy oil remaining reserves in carbonates of Russia and Europe. Since the viscosity of its oil is more than 700 mPa*s, in some areas of the reservoir, there is a steam injection at ~300°C and ~10 MPa, which are being used for almost 40 years mostly via vertical wells. However, the current oil recovery numbers of the areas are estimated only between 12 and 15 %. It is assumed that these oil recovery efficiencies could be improved with optimized reservoir management with advanced numerical modeling to evaluate the additional oil production and steam-oil ratio and figure out the best further steamflooding strategy. For many years, an exclusively deterministic approach was used to simulate the reservoir, which significantly limited the possibilities for modifying the steam injection process. That is why, the search for alternative approaches of reservoir modeling, which ensure prompt obtaining realistic forecasting of its development, was relevant. In this work, a novel forecasting technology termed an adaptive approach that combines the full-field geological and hydrodynamic models with the unique machine-learning algorithm based on fuzzy-logic functions was implemented. The obtained results of the adaptive approach application demonstrated the improvement in understanding of the reservoir thermal performance and in making the practical recommendations of cost saving and oil production increase.
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Investigation of Anhydrite Dissolution as a Potential Low Salinity Waterflooding Mechanism in Carbonates
Authors T. Uetani, H. Kaido and H. YonebayashiSummaryMany mechanisms have been proposed for low salinity waterflooding enhanced oil recovery (EOR) in carbonate rocks over the last decade, and they are still in debate. One suggested mechanism is the dissolution of anhydrite (CaSO4) mineral from a rock material, which generates sulfate ions in-situ, and subsequently acts as a wettability modifier chemically. Another suggested mechanism is the increase in permeability due to mineral dissolution. Primary objective of this work was to verify whether dissolution of anhydrite could be the key low salinity waterflooding EOR mechanism.
Spontaneous imbibition tests were conducted using six rock samples from two carbonate oil reservoirs. The first reservoir rock contains anhydrite, while the second reservoir does not contain anhydrite. If anhydrite dissolution is the key mechanism, then the amount of increased oil recovery due to low salinity brine should correlate with the amount of anhydrite dissolved from the rock. Our experimental results, however, did not suggest such a relationship. Hence, anhydrite dissolution was considered unlikely as the key mechanism of low salinity EOR for the crude-oil, brine and rock (COBR) system used in this study.
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Applying the Calibrated Todd and Longstaff's Mixing Parameter Value for Miscible Slug Size WAG Injection on Field Scale
More LessSummaryThis paper presents the application of the calibrated values of the Todd and Longstaff's mixing parameter, ω, for miscible finite-sized slug WAG (FSS WAG) injection on a field scale. This work is an extension of the work of calibrating the mixing parameter value ( Al-Haboobi, 2019 ) where Al-Haboobi showed there is a relationship between the value of ω with specific slug size and WAG ratio. The application on a field scale was through the use of a black oil simulator, Eclipse E100, and was designed to show the reservoir performance obtained using the calibrated values of ω for 1:1 WAG ratio at different slug sizes. Also, to compare the reservoir performance at the calibrated value with a full mixing ω =1 and with Todd and Longstaff's value = ⅔. Todd and Longstaff recommended a value of ⅓ to be applied on a field scale to take into account the effect of heterogeneity. However, the value of ⅔ is used in this comparison, because this comparison was established in the original work of calibrating the mixing parameter value ( Al-Haboobi, 2019 ).
Two case studies were used to test the reservoir performance and the impact of the calibrated value of ω on the reservoir performance, a synthetic quarter five spot model and a semi-synthetic model (the Watt field model). The quarter five-spot model allowed the demonstration of some of the key features of FSS WAG injection in a 3D model without the additional complexity of multiple wells, horizontal producers, faults, and complex permeability and porosity distributions, such as those in the Watt field model.
The paper begins by presenting the models under study, their fluid properties and the grid-refinement study conducted on both models. Then, the paper provides the assumptions of applying the calibrated value of ω on a field scale. Finally, it shows the results and the impact of the calibrated value of ω on the WAG zone and the oil recovery factor.
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The Impact of Calibrating Todd and Longstaff's Mixing Parameter on Optimising Miscible Finite Sized Slug WAG Injection
More LessSummaryThis paper presents the work of optimising the WAG ratio and slug size in miscible finite sized slug WAG (FSSWAG) injection on a field scale, considering the impact of Todd and Longstaff's mixing parameter (ω, also known as TLMIXPAR) value. This work is an extension of Al-Haboobi's (2019 ) work where Al-Haboobi showed there is a relationship between the value of ω with specific slug size and WAG ratio. This relationship was used in the optimisation of slug size and WAG ratio by updating ω (TLMIXPAR) in the Eclipse 100 data deck using a Python code.
In order to identify the impact of the calibrated value of ω on the optimisation of miscible FSS WAG injection, the slug size, WAG ratio, type of fluid injected (so-called WAG pattern injection) and the flow rate were optimised. The optimisation scenario is performed with the assumption that there is an unlimited supply of gas to inject, what if the gas supply was finite (limited)? Therefore, the impact of the calibrated value of ω on the optimisation results has been investigated by adding the assumption that there is a limited amount of gas to inject for the optimisation of WAG ratio, slug size, WAG pattern injection and the amount of flow rate to inject. The results of the previous optimisation scenarios for the calibrated value of ω are compared with the results of the optimisation at a fixed value of ω=1 for both secondary and tertiary recovery. The full details of this work can be found in ( Al-Haboobi, 2019 ).
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Numerical Simulation of Low Salinity Waterflood on Fractured Chalk Outcrop-based Models
Authors N. Andrianov and H.M. NickSummaryWe focus on numerical simulation of low salinity waterflood on outcrop-based models, which are representative of North Sea fractured chalk reservoirs. To this end, we consider a 2D model of an outcrop at Lägerdorf quarry in northwest Germany, which reveals an extensive fracture network together with several major faults, see Koestler and Rekstein (1995). The model is populated with rock and fluid properties, representative for North Sea chalk reservoirs, see Graue and Bognø (1999 ).
We discretize the domain using a Discrete Fracture Matrix (DFM) approach so that the fractures are represented as low-dimensional finite volumes, see Gläser et al. 2017 . Low salinity waterflood is modelled as a two-phase oil-water immiscible displacement with oil being a single component incompressible liquid. The water phase is represented either with two components – high-salinity (HS) and low-salinity (LS) injection water, or with a variable number of chemical elements. In the latter case, the thermodynamic equilibrium for the water phase is achieved by coupling the transport solver to the reaction module PhreeqcRM of Parkhurst and Wissmeier (2015 ). This model was implemented in DuMuX, a free and open-source simulator for flow and transport processes in porous media, see Flemisch et al. 2011 .
We run a sensitivity study on the dependency of recovery rate on water injection rates for various fracture apertures and wettability distribution. The results demonstrate that for certain range of injection rates there is an optimal value in terms of recovery rate vs. number of pore volumes injected.
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Interpretation of Induction Time and Nonstandard Spontaneous Imbibition Trends Utilizing In-situ Measurements – Identification of No-Flow Regions and Wettability Alteration
Authors P.Ø. Andersen, T.L. Føyen, J.S. Chauhan and B. BrattekåsSummaryThis work aims to analyse and explain non-standard imbibition, observed here and frequently in the literature. Previously conducted spontaneous imbibition tests in fully oil-saturated and strongly water-wet Bentheimersandstone core plugs, using OEO (One End Open) and TEOFSI (Two Ends Open Free Spontaneous Imbibition) revealed a significant delay at start of imbibition (induction time) before standard theoretical recovery vs time behaviour was established. The radial corefaces had been sealed with epoxy glue to define no-flow boundaries and yield imbibition corresponding to one dimensional (1D) solutions. However; in-situ imaging revealed that flow occurred in a two-dimensional (2D) manner. Particularly, in-situ imaging showedthat the water saturation at the end of imbibition was much higher in the core center than close to the no-flow boundaries. The tests were simulated numerically to interpret possible causes for the non-standard behaviour. First, the core scale model was parameterizedby matching AFO (All Faces Open) experiments (same experimental conditions, but not applying epoxy) and some of the TEOFSI tests that seemed able to be corrected for induction time. The predicted behaviour of the remaining tests was in agreement in terms ofimbibition rate if an induction time correction was made, however much lower recovery was observed than predicted.
Introducing no-flow regions in the model near the epoxy layers and an initially weakly oil-wet state centrally in the core were both necessary mechanisms to fully interpret the tests.The no-flow regions explained the difference in end recovery, but also impacted the imbibition rate (it was reduced). The initial weakly oil-wet state explained the low, but not zero imbibition rate in the induction period. A wettability alteration towardsstrongly water-wet then explained the resulting behaviour. It was found that this event was more likely triggered than gradual. It was however challenging to determine the triggering event.
This work demonstrates that spontaneous imbibition tests are very sensitive to the flow properties near the no-flow boundaries and can potentially affect the interpretation of end pointsaturations and flow functions. In-situ imaging by PET-CT improved the interpretation of the results by direct implementation of no-flow regions in the model. Accurate spontaneous imbibition behaviour must be achieved in the laboratory before upscaling tothe field.
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Optimization of Gas-condensate Reservoir EOR Technology under Geological Uncertainties
Authors O. Burachok and O. KondratSummaryDevelopment of gas-condensate reservoirs is a complicated problem by itself. The classic way to enhance hydrocarbon recovery from fields with high condensate yield is to implement hydrocarbon or nonhydrocarbon gas injection to support reservoir pressure high enough to be close to dewpoint pressure. Application of chemical EOR methods was not really suggested in the industry for gas-condensate fields. Commonly, identifying the optimum technology for the field is based on a single geomodel realization concept that enables unbiased comparison of suggested technologies. Unfortunately, when we are considering selection of the technology for a pilot field application, we are still highly uncertain about property distribution and even fluid properties and their true interaction with injected chemicals.
The problem becomes even more complicated when we also have to optimize the implementation of the technologies based on technical or economic efficiency. The current paper proposes the workflow that addresses the problem described above.
The classic approach for enhancement of condensate recovery is implementation of gas recycling using hydrocarbon or nonhydrocarbon gases. This proves to be efficient method in cases when reservoir pressure is maintained close to dewpoint, preventing in-situ condensation of liquid fractions. The problem of current study is a synthetic deep gas-condensate reservoir that was developed under depletion, resulting in significant decrease of reservoir pressure way beyond dewpoint with formation of the liquid phase, which is only mobile in the vicinity of the wells, where critical saturations were achieved. Being uncertain about geological description of the reservoir, facies distribution, porosity, permeability, and SCAL data, we want to identify the most economically feasible chemical EOR technology and optimize its parameters under uncertainties. Using a numerical compositional simulator with a synthetic reservoir model, we performed optimization of a field development project's net present value (NPV) for different chemical EOR methods – surfactant (S), alkaline (A), polymer (P), AS, SP, and ASP for the duration of injection (slug volume) under geological uncertainties within different static reservoir property realizations, fault transmissibilities, aquifer strength, and relative permeability endpoints. Optimization was done using a simplex algorithm combined with risk assertion to account for geological uncertainties.
Results indicate repeatability and applicability of the proposed approach on real full-field gas-condensate models.
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Analytical and Numerical Solutions of Chemical Flooding in a Layered Reservoir with a Focus on Low Salinity Water Flooding
Authors H. Al-Ibadi, K. Stephen and E. MackaySummaryChemical flooding has been implemented and studied intensively as an EOR method. One such process, Low Salinity WaterFlooding (LSWF) has become increasingly applied. Simulations can be performed for these processes to predict behaviour and make field management decisions. These are costly and incur numerical errors. Analytical solutions to flow behaviour have been developed previously for waterflooding in reservoirs that consist of non-communicating layers. We extend that analysis here for chemical flooding, and in particular for LSWF. We also extend the analysis that we developed previously to include dispersion effects. We then compare the analytical predictions to the more realistic case of flow across communicating layers to assess crossflow effects. We derive a mathematical form of fractional flow theory for a set of non-communicating layers that can be used to predict fluid flow and solute transport including the location of waterfronts. This model corrects for the effects of numerical and physical dispersion. We examine the validity of this analytical model by comparing it to simulations of fluid flow behaviour in non-communicating layers first and then in communicating layers. We use dimensionless numbers that can be used to deduce the inter-layer relationships of the various fronts that form as a function of viscous crossflow. We examined models with different degrees of heterogeneity under various mobility ratios.
The analytical method worked very well compared to numerical simulations in the absence of cross-flow. Our results show that for virtually homogenous reservoirs, the crossflow has negligible effect on oil recovery. For moderately heterogeneous reservoirs, the crossflow has a negative effect reducing the recovery factor. Cross flow resulted in varying effects ranging from a reduced ultimate recovery of 2% or increased it by 9%, relative to the original oil in place. The former occurred for models with a mobility ratio at the leading formation waterfront that was less than one combined with low heterogeneity while the latter occurred for highly heterogeneous cases.
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A Modeling Study for Foam Generation for EOR Applications in Naturally Fractured Reservoirs Using Disperse Surfactant in the Gas Stream
Authors J.D. Valencia, J.M. Mejía, A. Ocampo and H. SolanoSummaryThe preferential flow channels in oil reservoirs affect the performance of oil recovery processes, reducing the sweep efficiency and affecting the expected recovery factor. Preferential flow channels are generated by viscous fingering, gravitational segregation or porous media heterogeneity like natural fractures. In the Colombian foothills fields where the gas injection is the main method of recovery, the gravitational segregation and the presence of natural fractures strongly reduce the sweep efficiency. For these fields, foam generation is an alternative with high potential to increase sweep efficiency in gas displacement processes. Different foaming methodologies have been evaluated at laboratory core scale and field pilots with good incremental production, but with high operational expenses associated with high surfactant retention and lack of water injection facilities. Dispersed surfactant injection in a gas stream is a new proven method for foam generation. Different core flooding results and field pilots have shown that disperse injection increase cumulative oil production. However, there is a high level of uncertainty due to a few experimental and field information. For compensating the high uncertainty of the method, a mechanistic model was previously developed and validated with information from homogeneous cores. Nevertheless, it is necessary to extend the scope of the model to evaluate the effect of blocking foams in naturally fractured reservoirs, in this work we scale the previously built foam models to evaluate the disperse surfactant injection in Naturally Fractured Reservoirs through thin, high permeability, and horizontal layers to represent fractured systems and reproduce laboratory and field pilot results.
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Single Well Modeling and Field Validation of Heavy-oil Well Stimulations Using Nanofluids
Authors J. Mejia, R. Zabala and J. ValenciaSummaryEngineered nanofluids were designed to reduce oil viscosity and to restore wettability in heavy oil formations ( Zabala et al. 2016 ). Incremental production rates, between 50% and 150%, were registered after injecting the nanofluids in 4 wells in two heavy oil fields of the Llanos Basin in Colombia ( Zabala et al. 2016 ). A rigorous mathematical model of the interaction of nanoparticles in heavy-oil systems was developed by Mozo et al. (2018 ). The model accounts for transport and retention of nanoparticles, wettability alteration and oil viscosity reduction. The model was developed for 1D-linear flow in order to calibrate the model parameters with core-flooding experiments. In this work, we extended the model to radial models in 3D in order to simulate the injection, soaking and production stages of a nanofluid injection in a well. The equations were discretized using the finite volume method. The non-linear equations were sorved using the Newton-Raphson method. Two wells of the pilot study were simulated, showing a good agreement with field measurements of oil production. Since the model accounts for the underlying physical and chemical processes, the deployment of a well stimulation can simulated and evaluated using the developed tool. We simulated different nanofluids injection scenarios at reservoir scale in order to assess the impact of unknown model parameters as well as main operating conditions on the incremental oil production. The sensitivity analysis results provides important information for designing experimental and field protocols for model tuning and validation, as well for designing effective surveillance activities related to the pilot / field applications. References
Mozo I., Mejía J. M., Cortés F., Zabala R. (2018). A robust mathematical model for heavy-oil well stimulations using nanofluids: modelling, simulation and validation at lab and reservoir scales. 16th European Conference on the Mathematics of Oil Recovery- EAGE. 3–6 September 2018 . Barcelona, Spain. Zabala R., Franco C. A., & Cortés F. B. (2016). Application of Nanofluids for Improving Oil Mobility in Heavy Oil and Extra-Heavy Oil: A Field Test. Society of Petroleum Engineers. SPE-179677-MS.
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A New Qualitative and Quantitative Analytics Approach on Waterflood Operations Data for Improving Oil Recovery
Authors A. Venkatraman, A. Malkov, A. Yadav, D. Davudov, K. Awemo, T. Hag and X. ChenSummaryWater flooding is an established method of secondary recovery to increase oil production. While previous research has focused on designing waterflood operations, there are no tools to evaluate the efficacy of those designs and optimize it frequently based on data available during the course of water flooding operations. In this research, we present a novel approach of using data mining techniques to increase oil recovery using operations data from a field undergoing water flooding. The results presented in this research can be adapted to any field to optimize recovery at frequent intervals, where injection and production data is continuously available.
Operations data from a current water flooding field is used to improve water injection strategy by using a combination of qualitative (cross correlation analysis) and quantitative analysis (capacitance resistance model). Field data obtained from each injector and the surrounding producers are used for cross correlation analysis that enable identifying thief zones. The qualitative insights obtained from the cross-correlation analysis are used to improve the capacitance resistance model for the field. The improved capacitance resistance model is used to obtain redistribution of water among injectors with the purpose of increasing oil recovery. Reservoir simulation prediction of oil recovery on the two cases (the previous benchmark case and the new optimized injection strategy obtained using data mining techniques) is presented. It can be seen that the redistribution of water obtained using this novel approach improves oil estimates in the range of 5–10%.
A field case of using data mining techniques of cross correlation analysis and capacitance resistance modeling is presented as a means to improve reservoir characterization using operations data. The insights obtained by using a combination of these two methods are used to redistribute water injection in a producing field. This new approach can be used to optimize water injection at frequent intervals based on the operations data obtained from the field. Operational challenges in implementing redistribution of water injection rates frequently are highlighted for the sake of other operators implementing such an approach.
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An Adaptive Newton's Method for Implicit Dynamic Local Grid Refinement for Simulation of IOR/EOR Processes
Authors H Groot, H Cui, J Rommelse and D VanBatenburgSummaryDynamic Local Grid Refinement (DLGR) is a well-known computational method to improve the performance of reservoir simulations by dynamically adapting the grid resolution to local physical phenomena at each location in time. This enables reservoir simulators to achieve similar accuracy with only a fraction of the number of grid cells that it would otherwise utilize. This is particularly useful for IOR/EOR processes due to the small scale and complexity of the physical and chemical processes involved.
A challenge in using DLGR is the adaptation of the local grid resolution in advance of dynamic changes in physical phenomena, such as moving thermal or oil displacement fronts. Failure to intercept such changes up front by a locally high resolution grid will lead to loss of numerical accuracy. A Repeat Time Step (RTS) method that iteratively repeats time steps to implicitly evaluate the grid adaptation criteria at the next time node was previously proposed. However, the results in this paper show that using the RTS method for DLGR leads on average to considerably higher computational time spent in the linear solver. As a result, it was found that it is more efficient in most cases to tighten the tolerances for the grid adaptation criteria in order to create a buffer zone of fine grid cells in regions that require high grid resolution instead of using the RTS method.
This report proposes an iDLGR-ANM method in which an Adaptive Newton's Method (ANM) is used to further reduce computational overhead spent in repeat time steps performed by DLGR. The ANM leads to reduced simulation times by only considering unconverged and adjacent grid cells in each NR iteration. Furthermore, the added benefit of ANM to the RTS method is that ANM can immediately be restricted to refined grid cells and adjacent cells from the first NR iteration in the repeat time steps rather than solving the full system of linearized equations. In order to compare the performance of the RTS method with and without the ANM, eight examples are considered involving various IOR/EOR applications and numerical schemes. Results show that iDLGR-ANM is nearly as fast in terms of CPU time spent in the linear solver as DLGR without using the RTS method. Moreover, if a post-Newton material balance smoothing technique is applied, iDLGR-ANM results in production forecasts with the same accuracy as DLGR when the RTS method is used without ANM, with differences within machine accuracy.
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Velocity Enhancement Models for Polymer Flooding in Reservoir Simulation
Authors J. Romate and E. GuarnerioSummaryPolymer flooding is a well-known technique used in EOR. In order to accurately predict oil recovery, a velocity enhancement effect for the polymer molecules, also known as hydrodynamic acceleration, has to be included in the governing equations. The traditional model of a constant velocity enhancement factor, widely used in commercial simulators, leads to an ill-posed problem. As a consequence, simulations may produce unphysical solutions, showing an unlimited accumulation of polymer at the propagation front. Therefore, alternative models have been derived in order to formulate a well-posed problem. In this paper, these models are re-examined. Using mathematical theory of hyperbolic laws, an analytical solution is computed for the velocity enhancement model proposed by Bartelds et al. (G.A. Bartelds, J. Bruining, and J. Molenaar. The modeling of velocity enhancement in polymer flooding. Transport in Porous Media, 26(1):75–88, 1997). A property of this solution is that the polymer concentration decreases as polymer flows through the porous medium and no accumulation effect occurs. The polymer front travels faster than the case where no enhancement model is used, but a constraint on a parameter, needed to ensure well-posedness of the problem, limits the magnitude of the polymer acceleration. Hence, Hilden et al. (S.T. Hilden, H.M. Nilsen, and X. Raynaud. Study of the well-posedness of models for the inaccessible pore volume in polymer flooding. Transport in Porous Media, 114(1):65–86, 2016) proposed an extended model in order to overcome this constraint. However, it is shown in this paper that the model of Hilden results in a loss of hyperbolicity of the system of equations and may lead again to an unphysical accumulation of polymer at the propagation front. As many simulators still employ the ill-posed traditional model because of the uncertainty of the outcomes of alternative approaches, this analysis will hopefully help to understand the consequences of velocity enhancement modeling on the analytical and numerical solutions of polymer flooding.
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EOR Back Produced Water Treatment: Media Selection to Improve Filtration Efficiency
Authors N. Lesage, H. Foraison, J. Lafourcade, M. Jouanolou, G. Munduru, C. Sagne, P. Pedenaud and P. CordelierSummaryPolymer flooding is one of the most advanced enhanced oil recovery techniques to improve production. It is a cost-effective method due to the properties of polymers, mainly its capacity to develop suitable viscosities when diluted, leading to an improved hydrocarbon's extraction. The technique consists in injecting Hydrolyzed Polyacrylamide polymer (HPAM), mixed with water, in the reservoir to reach a target viscosity, in order to guarantee oil extraction, while reducing a bit the water cut. However, back produced water viscosity is quite high and leads to poor water treatment efficiency. Several water treatment technologies for oil removal have been developed for this purpose using gravity separation, gas floatation, chemical treatment and filtration. The media filtration is one of the most attractive technology because it has low operating costs and can handle high flux rates; it can help switch from water flooding to polymer flooding by retrofitting existing water treatment facilities, and so minimize CAPEX. This technology is very efficient to treat the produced water (PW) and can reach a very low oil concentration (<5mg/L). Nevertheless the filtration efficiency is function of the PW quality as well as media selected for the filtration.
The aim of this study was to compare the efficiency of several media for the treatment of produced water and back produced viscosified water. The impact of the polymer concentration (500 mg/L) on the retention efficiency was demonstrated in batch and continuous modes on synthetic produced water (50 mgOil/L, 10 mg/L of calibrated particles, 100 mg/L corrosion inhibitor). Indeed, the high viscosity of the PW mostly increases the fouling velocities. First tests aimed at screening the oil retention in batch mode for 6 different kinds of media (3 nutshell, sand, and a polymeric media). The 3 best media were then tested in continuous mode (flow 15–25 m/h) with automatic cleaning phases. This phase allowed assessing the regeneration efficiency and the ageing of the media. Results of the tests concluded on the impact of the water quality on the retention efficiency and design parameter for the media filtration of back produced viscosified water. Thanks to this study, several selection criteria of media were highlighted to adapt this technology for each field case.
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Evaluation of Empirical Models for Viscous Fingering in Miscible Displacement
Authors I. Tai and A. MuggeridgeSummaryThe performance of miscible gas injection projects can be significantly affected by viscous fingering. This is further complicated by the presence of heterogeneities, as depending on the scale of the heterogeneity, there can be a diffusive, advective or channelling effect. To assess the economic feasibility of a miscible gas injection project, reservoir simulations are needed but very fine grids are required for the fingers to be modelled explicitly. This requires a large amount of computational power and time. To get around this issue, many empirical models have been proposed which model the average behaviour of the viscous fingers, allowing predictions of performance, thus reducing grid size and computational time.
Many previous studies have investigated the ability of empirical models to represent fingering in line drives but none have considered flow in a quarter five spot pattern. In this study, a two phase, three component higher-order simulator is used to simulate miscible injection in square line drive and quarter five spot models, with and without heterogeneities. The results of the detailed fingering simulations were compared to the Todd & Longstaff and Fayers empirical models. To account for the effect of heterogeneities, the mixing parameter, w, in the Todd & Longstaff was adjusted using Koval's heterogeneity factor, H_k. The growth rate of the fingers, α, and the final fraction of the cross section occupied by the fingers, a+b, were adjusted in the Fayers model to account for heterogeneities and bypassed oil. The empirical models were implemented in a commercial immiscible reservoir simulator, Eclipse-100 using pseudo relative permeabilities.
The detailed simulations indicate that the growth rate of the fingers varies non-linearly with mean concentration in radial flows and this is not captured by either of the empirical models. A modification of the Fayers model is proposed to capture this. For both heterogeneous line drive and quarter five spot models, the Todd & Longstaff model consistently overestimates recovery after solvent breakthrough as it cannot account for bypassed oil. The Fayers model underestimates recovery whereas the modified Fayers model tends to overestimate the breakthrough time, but after this point, it can accurately reproduce the effluent profile from simulations. However, this requires production data or detailed fingering simulation data to calibrate b, the constant which defines bypassed oil, as this depends on the heterogeneity, the mobility ratio and the time scale of interest
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The Development of a Low Shear Valve Suitable for Polymer Flooding
Authors T. Husveg, M. Stokka, S. Jouenne and R. HusvegSummaryHydrolyzed polyacrylamides are used as mobility control agents to improve the macroscopic sweep efficiency of oil reservoirs. In order to maximize their viscosifying power, very high molecular weight polymers are preferred, which in turn make them very sensitive to shear degradation.
Shear degradation originates from chain stretching and breaking when the solution is subjected to a sudden acceleration. Such extension dominated flow fields are encountered at different locations of surface facilities (mainly in pumps, pipes and valves) and at the wellbore interface. Although CAPEX intensive, the use of one injection pump and line per injector well is a way to control and to minimize polymer degradation. For mature field developments or large fields with long injection lines, it is generally necessary to install a control valve on the wellhead of each well to regulate the injection pressure and flow rate.
In classical chokes used for water flooding, the fluid accelerates strongly in order to create the turbulence required for pressure reduction, which in turn leads to a high degradation of polymer chains. Fundamental development work is presented, where polymer degradation is studied in flow through diffusers and expanders of various geometrical shapes, as well as through straight pipes and pipe coils of various diameters and lengths. Empirical correlations between geometries and polymer degradation are established. In particular, for a given flow capacity, it is found that the optimal geometry of a tube-based throttling device, is a compromise between length, diameter and number of tubes in parallel. Results demonstrate that the creation of pressure drop through viscous pipe friction is very ineffective with tubes of constant diameter, most likely due to the drag reducing effect of polymer flow. In addition, the arrangement of very long, straight or coiled tubes in parallel is impractical and bulky.
A novel valve technology solves these challenges: Firstly, through the unique use of carefully designed contractions evenly spaced in the flow channels, the drag reducing effect is overruled. Secondly, the arrangement of multiple flow channels of certain diameters and lengths, and with optimally designed reducer and expansion zones, resolves itself by using a stack of machined spiral discs. The latter also enables an easy and reliable technical solution for flow and pressure regulation. The efficiency of the new valve technology is demonstrated through small and large-scale prototype tests. Degradation is less than 10% at 40 bar pressure drop compared to 80% for a standard valve.
Hydrolyzed polyacrylamides are used as mobility control agents to improve the macroscopic sweep efficiency of oil reservoirs. In order to maximize their viscosifying power, very high molecular weight polymers are preferred, which in turn make them very sensitive to shear degradation. Shear degradation originates from chain stretching and breaking when the solution is subjected to a sudden acceleration. Such extension dominated flow fields are encountered at different locations of surface facilities (mainly in pumps, pipes and valves) and at the wellbore interface. Although CAPEX intensive, the use of one injection pump and line per injector well is a way to control and to minimize polymer degradation. For mature field developments or large fields with long injection lines, it is generally necessary to install a control valve on the wellhead of each well to regulate the injection pressure and flow rate.
In classical chokes used for water flooding, the fluid accelerates strongly in order to create the turbulence required for pressure reduction, which in turn leads to a high degradation of polymer chains. Fundamental development work is presented, where polymer degradation is studied in flow through reducers and expanders of various geometrical shapes, as well as through straight pipes and pipe coils of various diameters and lengths. Empirical correlations between geometries and polymer degradation are established. In particular, for a given flow capacity, it is found that the optimal geometry of a pipe-based throttling device, is a compromise between length, diameter and number of pipes in parallel. Generally, the work also demonstrates that the creation of pressure drop through viscous pipe friction is very ineffective with regular tubes, most likely due to the drag reducing effect of polymer flow. In addition, the arrangement of very long, straight or coiled pipes in parallel is impractical and bulky.
This paper presents the development of a novel valve technology that solves these challenges. Firstly, through the unique use of spiralling flow channels with optimally designed reducer and expansion zones, machined on the surface of discs, shear forces and thereby polymer degradation is controlled. Secondly, the arrangement of numerous such disc forming a disc-stack, any target capacity can be met efficiently. Thirdly, the disc-stack concept enables an easy and reliable plug-based solution for flow regulation and control. The performance of the new valve technology is demonstrated through small and large-scale prototype tests. At very shear sensitive test conditions, it is demonstrated that polymer degradation of the new valve is less than 10 % at 40–45 bar pressure drop, compared to 60–80 % for a standard valve.
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Universal Viscosifying Behavior of Acrylamide-based Polymers Used in EOR - Application for QA/QC, Viscosity Predictions and Field Characterization
Authors S. Jouenne, B. Levache, M. Joly, C. Hourcq, M. Questel and G. HeurteuxSummaryConventional EOR polymers are acrylamide-based copolymers. Their viscosity in aqueous solution depends on various physicochemical parameters such as: monomer composition, concentration, average molecular weight, polydispersity, salinity level and ionic composition, temperature… Moreover, solutions are non-Newtonian, they exhibit a Low shear Newtonian plateau viscosity at low shear rate followed by a shear thinning region at higher shear rate. In the absence of predictive model, for any new polymer grade or lot, any new or slightly varying field conditions, it is necessary to perform a whole set of viscosity measurements at varying concentrations which is tedious, time consuming and not valuable.
Flow curves (Viscosity vs. Shear rate) were measured on a great number of polymers solutions in various physicochemical conditions (variation of the polymer microstructure, monomer composition, molecular weight, brine salinity and temperature). The flow curves in both dilute, semidilute non-entangled and semidilute entangled regimes were modelled by only two adjustable parameters: the intrinsic viscosity [η] and the relaxation time in the diluted regime λd. The low shear plateau viscosity η0 (more specifically, the specific viscosity ηspe) and the shear thinning index n obey mastercurves which are solely function of the overlap parameter C[η]. The relaxation time λ depends on C[η] and the relaxation time in the diluted regime λd. All these results are consistent with predictions for a neutral polymer in good solvent.
By using these mastercurves, intrinsic viscosity of any polymer/brine system can be easily obtained at various temperatures from a single measurement in the semi-dilute regime in which viscosity is higher than water, and classic rheometers are very sensitive. The whole flow curve (η=f(γ)) can be predicted at any concentration, temperature and molecular weight. For any unknown polymer/brine system, the determination of λd enables to determine the viscosimetric average molecular weight M of the polymer. Finally, by using the additive property of the intrinsic viscosity of binary solutions, a method is proposed to evaluate molecular weight of field samples. Polymer physics is today considered as well described and well known. However, the beauty and the usefulness of this physics have been partly ignored by the EOR community up to now. This study gives a methodology to predict the viscosifying behavior and the molecular weight of any acrylamide based copolymer/brine system. By attributing molecular weight rather than a viscosity value, on-site and lab QA/QC will be greatly improved.
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SmartWater Synergy with Chemical EOR: Polymer Effects on SmartWater Spontaneous Imbibition
Authors A.M. AlSofi, A.B. Fuseni, Z.K. Kaidar and S.M. AlEneziSummarySynergy between EOR processes has the potential for achieving more effective application. Previously, we demonstrated Smart water's slight negative-impact on polymer and chase brine injectivity, positive impact on polymer retention, and negligible impact on polymer acceleration. We also demonstrated polymer's positive effects on Smart water's surface potentials, contact angles, and oil recoveries. Herein, we further investigate this synergy focusing on polymer's possible effects on SmartWater spontaneous imbibition. We also revisit singlephase displacement observations with regard to polymer injectivity and retention using bench-top experiments. The main experimental program consisted of spontaneous-imbibition and sorption measurements. A supplementary experimental program included polymer filterability and adsorption tests to provide additional insights on this synergistic SmartWater/Polymer process.
Results showed the superiority of SmartWater as an imbibition fluid compared to the higher-salinity injection water. With polymer addition, the lower-salinity SmartWater upheld its superiority. Accounting for viscosity variations, sorption rates into powdered rock packs were actually very comparable with and without the polymer. In core plugs, and with both brines, polymer addition yielded further water imbibition above that obtained with polymer-free solutions. Still imbibition was much more effective with SmartWater even in the presence of the polymer. At the same polymer concentrations, polymer adsorptions onto the rock were comparable with both SmartWater and the higher-salinity injection water. However, at equivalent viscosities, polymer adsorption onto the rock was lower with SmartWater than with the higher-salinity injection water. These static adsorption results could provide an additional explanation to the substantially lower retention observed with the lower-salinity SmartWater in dynamic retention tests. At the same polymer concentration, the solutions in both brines exhibited comparable filtration ratios. However, for solutions of equivalent viscosities, the solution in the higher-salinity conventional injection water exhibited higher filtration ratio. This discrepancy with single-phase displacement results can be explained based on differences of the main mechanism contributing to permeability reduction (adsorption layer versus mechanical plugging).
In conclusion, the favorable SmartWater/Polymer synergy extends to spontaneous imbibition. Polymer solutions, in both SmartWater and injection water yielded additional imbibition in tertiary mode. However, with injection water the additional imbibition after polymer addition is much smaller than with SmartWater.
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Performance of Associative Polymers in the Presence of Low Tension Surfactants at Different Temperatures and Variable Salinity Conditions
Authors D.A. Alexis, D. Varadarajan, D.H. Kim, T. Isbell, G. Winslow and T. MalikSummaryAssociative polymers (AP) have been shown to develop similar or greater resistance at very low concentrations during polymer transport in comparison to non-associative polymers. This makes AP an attractive option for improved oil recovery at a lower cost. However, their performance dependence on salinity, temperature, concentration, compatibility and interaction with low tension surfactants for improved oil recovery has not been thoroughly understood. The goal of the current work is to study the interaction of these polymers with different surfactant structures and compare their performance with traditional HPAM/AMPS polymers in mobilizing capillary trapped residual oil.
We evaluated both HPAM and sulfonated-HPAM based associative polymers with different associative contents in the presence of sulfate and sulfonate surfactants at both moderate and high temperatures with crude oils of different viscosities at high pH and neutral pH conditions. We first tested the effect of the polymers on surfactant - crude oil phase behavior to study the static compatibility and oil solubilization ratios as a function of salinity. Once satisfactory surfactant-crude oil phase behavior results were obtained in the presence of polymer, the next step was injection of single phase surfactant polymer solutions in the absence of oil to observe baseline resistance factors during the propagation of surfactant-polymer slug in the surrogate rock. Finally, we evaluated the performance of these associative polymers during the displacement of residual oil. We compared the recovery performance of the associative polymers with conventional polymers in terms of remaining oil saturation, oil bank propagation and pressure gradients during the surfactant-polymer flooding process.
Results indicate that associative polymers are generally compatible with traditional low tension surfactants as seen from the phase behavior experiments and corefloods. The associative polymers are aqueous stable at optimal salinity and show no plugging in single phase injectivity experiments in Bentheimer sandstone. The associative polymers show comparable oil recovery to conventional HPAM and sulfonated HPAMs at a lower polymer dosage and appear to be good alternatives for field application.
Based on the laboratory results, we demonstrate that associative polymers can be used with low-tension surfactants for EOR at lower concentrations.
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Radial Injectivity of an Associative Polymer for EOR
Authors T. Skauge, K. Djurhuus, T. Zimmermann, C. Bittner and R. Reichenbach-KlinkeSummaryHydrophobically modified polyacylamides (HMPAMs), also known as associative polymers, have high potential as EOR chemicals due to their specific chemical properties. However, the strength of hydrophobic interactions also leads to more complex flow behavior. Mostly, polymer injectivity is studied in linear coreflood experiments. However, in reality the polymer injection occurs in radial flow. The main difference is that linear flow has constant pressure gradient and thereby constant shear rate, while radial flow has a position dependent pressure gradient and therefore a shear gradient in the near-well region. For complex non-Newtonian polymers like HMPAMs this may have large implications for injectivity.
The influence of relatively weak hydrophobic interactions on flow properties was studied by radial injection of a semi-dilute solution of associative polymer under high injection rates. Radial flow was achieved by injection in a well placed in the center of a 30 cm diameter, 3 cm thick disc cut from Bentheimer outcrop sandstone. Bentheimer was chosen due to the high homogeneity of the rock. Pressure ports were positioned between the injection well and the rim to allow determination of the pressure decay curve during flow. Effluent was collected and analyzed for mechanical degradation.
The radial injection of the associative polymer showed shear thinning behavior at all rates, including at near-well equivalent rates. This means that this polymer can be injected with relatively low pressures and will gain viscosity as it propagates further from the well. Interestingly, this is different from the observations in linear core floods. Disruption and regeneration of weak hydrophobic interactions appears to be the main cause of the change in rheological behavior between linear and radial flow. The associative polymer showed excellent shear stability with only moderate viscosity reduction at extreme injection rates. The results confirm the need for in-situ measurements of polymer rheology not only in linear but also radial flow as input data for injectivity modeling. The experiments reveal that the associative polymer has different rheological behavior in bulk, linear and radial flow. The near-Newtonian behavior at near-well injection rates combined with building of viscosity at lower rates further from the well is beneficial for application in polymer flooding. This is to our knowledge the first systematic investigation of an associative polymer in radial flow. The results have major implications for polymer flood modeling and flood design, particularly for injections in vertical wells where injectivity is critical.
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Improve Kinetics of Oil Recovery in Naturally Fractured Carbonates: Optimization of an Advanced EOR Foam Process
Authors E. Chevallier, S. Bouquet, N. Gland, F. Douarche and G. BatôtSummaryIn naturally fractured carbonate reservoirs, Gas Oil Gravity Drainage processes (GOGD) are successfully implemented but oil recovery is limited by a slow kinetics. However a gas EOR process represents a promising alternative to boost this oil production rate. Nevertheless the design of this process should address several technical challenges: the typically unfavorable wettability of the matrix (intermediate to strongly oil-wet), the densely connected fracture network and the high contrast of fracture-to-matrix permeability.
We propose here the injection of an advanced EOR foam with reduced interfacial tensions. The foam flow in the fracture creates an important viscous drive by imposing a pressure gradient, thus enhancing the oil recovery dynamics compared to GOGD. Besides, the reduced interfacial tension (IFT) between crude oil and aqueous phase allows the aqueous phase to enter the matrix despite the unfavorable wettability.
In this paper, we demonstrate that a balance exist between IFT and foam strength performances to optimize the process. Three foam formulations are optimized with very different profiles in terms of IFT and foam performances. For their design, priority is given either to ultra-low IFT values (0.001mN/m) or to a strong foam with larger IFT (0.15mN/m) or to a balance between the two first formulations (0.03mN/m). These formulations are compared in vials, sandpack and coreflood experiments (fractured cores). Foams are evidenced as intrinsically less stable in ultra-low IFT conditions: foam stability (in vials) and apparent viscosity (in porous media) in contact with oil are respectively enhanced by a factor 30 and by two decades when IFT rises from 0.001 to 0.1mN/m. Based on sandpack and coreflood experiments, we recommend an IFT of 0.1 to 0.01mN/m as a balance between the viscous drive in fracture and an efficient aqueous phase imbibition in the oil-wet matrix. Simulation work supports this experimental conclusion: the common target of IFT of the order of 0.001 mN/m determined by capillary desaturation curves in SP flooding can be revised to a higher IFT, which is can be deduced from the wettability of the reservoir.
To ensure an accelerated oil recovery in naturally fractured carbonate reservoirs, we recommend the design of a low-IFT foam formulation with revised IFT performances compared to a classical Surfactant-Polymer process. This article gives the target formulation parameters which arise from the mechanisms at play (viscous drive and imbibition in oil-wet matrix), and are realistically achieved with industrial surfactants.
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Creating Insitu EOR Foams in Naturally Fractured Reservoirs by the Injection of Surfactant in Gas Dispersions – Lab Confirmation
Authors A. Ocampo, A. Restrepo, J.M. Mejia, J.D. Valencia and H. SanchezSummaryThe present work presents the conceptual basis and experimental evaluation for a new technique to create insitu blocking foams in naturally fractured reservoirs by the injection of the foaming agent dispersed in a non-condensable gas stream. This work represents a further development of a previous paper (SPE-190219-MS; Ocampo et al, 2018) which presents a similar development for matrix dominated systems. Equivalent to previous work, the main objective is simplifying the operation and reducing costs for the deployment of EOR foams in gas injection based projects, and overcoming the limited reservoir volume of influence achieved by the surfactant alternated gas (SAG) technique.
An extensive and systematic experimental work was performed using fluids and low porosity naturally fractured rock representative of the Piedemonte area (Colombia, South America). The experiments were devised to investigate the effect of the dispersed chemical (surfactant) concentration and the gas velocity on the ability to create blocking foams at high pressure and temperature through the naturally fractured rock at a stress state representing open fracture conditions. The main physical mechanism behind this new technique is again the transfer of foamer droplets dispersed in the gas stream into the water present in the hydrocarbon reservoir. This transfer occurs because of the contrast in foamer concentration between the dispersed phase and the in-situ water. Results herein show reductions in gas mobility between 50% and 66%, along with increases in oil recovery factor between 10% and 34%, when the foamer chemical is dispersed in the gas stream, compared with the base gas flooding process performed on the described rock at residual oil and water saturations. This condition is obtained as far as the gas velocity is closed to rates equivalent to the velocities experienced near wellbore in the target reservoir, and the concentration of the active chemical is above 800 ppm (five times the concentration required to create blocking foam in the matrix system; Ocampo et al, 2018). Successful experiments with this new foam technique showed similar incremental recovery factors and stability periods as foams created by the SAG technique at higher chemical concentrations on the same rock fluid system.
The experimental results encouraged the progression and approval of a field pilot application of this foams technique this year in a Colombian Piedemonte gas condensate field characterized by the presence and dominance of the natural fractures both in the production and hydrocarbon gas injection performance.
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Impact of Crude Oil on Pre-generated Foam in Porous Media
Authors A. Hussain, S. Vincent-Bonnieu, R. Kamarul Bahrim, R. Pilus and W. RossenSummaryAs foam is injected into an oil reservoir, the region near an injector can become oil-free due to the relatively high capillary number. Foam created in this region encounters oil further out in the reservoir. The impact of oil on foam in porous media is usually investigated by co-injecting surfactant, gas and oil, or by injecting pre-generated foam into an oil-saturated core. However, the former experiment does not give information on the impact of oil on pre-generated foam, and from the latter experiment one cannot easily obtain data at different oil fractional flows, necessary to model the impact of oil on pre-generated foam.
Here the impact of crude oil on pre-generated foam is studied by co-injecting surfactant solution and gas into a relative narrow core (0.01 m diameter), and injecting oil into the porous medium some distance downstream from the inlet, through ports in the side of the porous medium. By injecting the three phases into the core we investigate the flow behaviour of foam with oil at fixed fractional flows of all three phases. The relatively narrow core allows rapid contact between the injected crude oil and pre-generated foam.
We observe a progressive decrease in the apparent viscosity of the foam after encountering oil. Foams with a higher gas fraction experience a more significant weakening by oil over the length of the core than foams with a lower gas fraction. By the end of the core, the apparent viscosities of foam with a higher gas fraction approach values observed with three-phase co-injection. Foam made with surfactant pre-equilibrated with the crude oil propagated for a shorter distance in presence of oil than foam made with surfactant that hasn't contacted oil before.
We present a novel, but relatively simple method to investigate the change of foam mobility as it encounters oil in a porous medium, at controlled fractional flows of all phases. We show that in our case the apparent viscosity of foam with oil can decrease by more than a factor of four over a distance of 0.15 m, indicating that foam and oil reach steady-state (as observed with three-phase co-injection) almost instantaneously compared to the length of a reservoir-simulation grid-block.
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Foam Generation by Snap-off in Flow Across a Sharp Permeability Transition
Authors S. Shah, H. As Syukri, K. Wolf, R. Pilus and W. RossenSummaryFoam reduces gas mobility and can help improve sweep efficiency in an enhanced oil recovery process. For the latter, long-distance foam propagation is crucial. In steady gas-liquid flow, foam is generated in homogeneous porous media by exceeding a critical pressure gradient, which normally only happens near the wellbore. Away from wells, these requirements may not be met, and foam propagation is uncertain.
It has been shown theoretically that foam can be generated, independent of pressure gradient, during flow across an abrupt increase in permeability. This could dominate foam generation away from wells in layered or laminated geological formations and can improve the chances of success of a foam application. The objective of this study is to validate theoretical explanations through experimental evidence and to quantify the effect of permeability contrast, velocity and fractional flow on this process.
In this study, we validate theoretical predictions through a variety of experimental evidence. Coreflood experiments involving co-injection of gas and surfactant solution at field-like velocities were performed. Layered, consolidated and well-characterized sintered glass cores were used as the porous media. The permeability change in each core was analogous to sharp, small-scale heterogeneities such as laminations and cross-laminations. The experiments were carefully designed not to allow foam generation by mechanisms other than snap-off at the permeability boundary in the core. Local pressure gradient was measured at various locations and was used to identify foam generation and subsequent propagation through the porous medium. Additionally, X-ray computed tomography (CT) was employed to detect changes in phase saturation that accompany foam generation and subsequent propagation downstream. CT-based saturations measurements were also used to qualitatively chart the reduction in capillary pressure across the sharp permeability jump, supporting theoretical explanations behind this process. The effect of permeability contrast, superficial velocity and flowing gas fraction on this process was also investigated. For a given permeability contrast, foam generation was observed at higher gas fractions than predicted by previous theory ( Rossen, 1999 ). Conditions for propagation of foam were explored by successively performing experiments at lower velocities and higher gas fractional flows. Significant fluctuations in pressure gradient accompanied the process of foam generation, indicating a degree of intermittency in the generation rate - probably reflecting cycles of foam generation, dryout, imbibition, and then generation. The intermittency of foam generation was found to increase with decreasing injection velocities and greater permeability contrasts.
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Experimental Investigation of Multiple Pore Volumes Needed to Reach Steady-state Foam Flow in a Porous Media
Authors O. M'barki, K. Ma, K. Mateen, G. Ren, H. Luo, V. Neillo, G. Bourdarot, D. Morel and Q. NguyenSummaryIn most of transient foam core-flood studies, it is observed that multiple pore volumes of foam injection are needed before reaching the steady-state. The pore volumes needed appear to change with the degree of homogeneity of the porous media, orientation of the core, type of surfactant and the total injected flow rate. This is contrary to the foam-model results, which usually predict reaching the steady-state after approximately a single moveable pore volume of gas injection. It is important to understand whether this is a laboratory artifact due to core scale and/or gravity segregation, or could it also be present at reservoir scale, in order to have the reliable foam rheology predictive tools at reservoir scale.
We designed the experimental set-up to investigate the phenomenon. In order to mitigate the gravity segregation in typical sand-pack systems, as well as to study the scale effect, we used slim-tubes of 1-ft and 6-ft length to understand the pore volumes needed to reach steady-state. Silica-sand-packed cylindrical slim tubes with an inner diameter of 0.66 inch were used in the foam flood experiments. Foaming surfactant solution and gas were co-injected into the slim-tube apparatus until a steady state is reached. Transient and steady-state pressure gradient data were recorded to investigate foam flow in the slim tube at a variety of injection conditions.
Foam experiments with foot-long and 6-ft long slim tubes were compared in order to understand the effect of system length on foam generation and transport. One of the most important findings in this study is that the 6-ft long slim-tube requires significantly fewer pore volumes to reach a steady state than foot-long one under the same foam injection scheme. The analysis of our results revealed several key factors that played important roles in triggering foam generation in the slim tube. We found that the vertical configuration with gas and surfactant solution co-injected from the bottom significantly promoted foam generation in a relatively homogeneous system compared with the horizontal configuration. Foam generation in the slim tube was also facilitated by wider sand grain-size distribution in our tests possibly due to more favorable pore throat-to-body ratios for the snap-off mechanism. Additionally, higher injection velocity helped triggering foam generation in the slim tube.
The results obtained in this study can be therefore used not only for improving fundamental knowledge of foam transport but also for upscaling foam models.
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Numerical Assessment and Optimization of Foam-Based EOR Processes in Naturally Fractured Carbonate Oil-Wet Reservoirs
Authors S. Bouquet, F. Douarche, F. Roggero, B. Bourbiaux and The EOR AllianceSummaryIn the recent years, foam process has shown a growing potential in producing naturally fractured reservoirs. While much effort was devoted to fractured reservoir characterization and laboratory design of foaming chemicals, decision-making for field development goes through reservoir simulation. This work assesses foam flooding performance through dual-media reservoir simulations, to optimize injection strategy and foam key features such as stability, mobility reduction, adsorption and interfacial tension reduction.
Foam flooding may improve significantly oil recovery in fractured oil-wet reservoirs through a better fluid mobility control and an increase in viscous forces in fractures, improving the sweep efficiency. Additionally, foaming chemicals can yield ultra-low interfacial tension between oil and water, and thus enhance the oil mobilization. This study evaluates the sensitivity of foam flooding performances to foam model parameters and injection strategy at pilot-scale.
This sensitivity analysis is based on the variance decomposition (Sobol's index) of the response model (such as oil production), while a surrogate model is built to limit the number of simulations required to evaluate the objective function. Optimization are performed to constrain the process to be more efficient than gas and/or water injection.
Compared to other flooding processes such as gas and/or water injection, this work demonstrates how foam flooding can be optimized such that viscous gradients and gravity drainage act optimally to sweep oil in the matrix, but still maintain a sufficient injectivity to yield a maximum recovery. The foam process optimum is a trade-off between oil recovery maximization and costs minimization, which corresponds to a rise in viscous forces that force out the oil from the matrix while respecting the fracture pressure and limiting the amount of injected chemicals.
This sensitivity assessment brings new insights for pre-feasibility studies, in particular for the foaming formulation design. Specifically, as foam flooding recovery mechanisms interplay, impacts of chemicals adsorption, injection strategy and optimization parameters will strongly differ whether foaming chemicals achieve or not ultra-low interfacial tension. Hence, for a “low-IFT foam”, chemicals adsorption reduction will be crucial although negligible for a foam process without IFT reduction. Because of different mechanisms involved, the foam process efficiency mainly depends on viscous forces developed in the fracture network whereas the “low-IFT” effect mainly relies on the penetration of chemicals in the matrix, that facilitates oil recovery.
The optimization workflow demonstrated its ability to evaluate and to help the selection of the most appropriate process at pilot scale, according to the reservoir specificities.
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Enhancement of a Foaming Formulation with Zwitterionic Surfactants for GOR Control Application in Harsh Reservoir Conditions
SummaryThis work presents the development of an improved formulation based on an Alpha Olefin Sulfonate (AOS) as the main surfactant for in-situ foam generation. The need for this formulation enhancement is driven by the the harsh reservoir conditions of the presented case study, which push the surfactants to the limit and pose new challenges for foam EOR application. According to literature, anionic surfactants mixed with zwitterionic surfactants (such as betaines), possess strong interaction and profound synergistic effects for improving foam generation ability and foam stability. In this sense, betaines act as foam boosters and are able to expand the range of application of the main surfactants. Unfortunately, laboratory optimization procedures are not widely documented in the literature.
Therefore, the aim of this paper is to delimit the applicability range of the AOS surfactant and to investigate its synergistic effects in mixtures with betaines to enhance foam performance. These are important steps to successfully design a robust formulation for a field pilot. For this purpose, we followed a laboratory workflow with a de-risking approach to define the most appropriate formulation for the challenging reservoir conditions of the presented case (high salinity, high divalent concentration, light oil, hydrocarbon gas and high temperature). The experiment setup was the following:
Phase 1 defines the most appropriate base surfactant (AOS) among a series of commercial candidates. The negative impact of each variable (salinity, temperature and presence of light hydrocarbons) and differences between different AOS providers are addressed.
Phase 2 defines the most appropriate betaine booster to be combined with the previously selected AOS and narrows the surfactant- booster ratio for enhanced synergistic effects in static conditions.
Phase 3 optimizes the surfactant-booster ratio in a dynamic co-injection of the formulation, nitrogen gas and slugs of oil through a porous medium with similar characteristics to the reservoir rock.
Phase 4 characterizes foam behavior according to critical variables (interstitial velocity, salinity, gas-water ratio) in coreflooding experiments using a core sample with live oil residual saturation. History matching allows to retrieve input parameters for the dynamic simulation.
As a result of this study, a mixture of an AOS C14-C16 and cocamidopropyl hydroxysultaine (CAPHS) gave the best performance. The designed formulation has proved its robustness in a wide range of conditions, which will allow to generate strong foam at reservoir conditions and provide stable foam propagation, overcoming variations in salinity, concentration and gas-water ratio along the reservoir.
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Influence of Wettability and Oil Saturation on the Rheological Behavior of CO2-Foams
Authors V. Beunat, G. Batôt, N. Gland, N. Pannacci, E. Chevallier and A. CuencaSummaryFoam processes aim to improve the efficiency of gas-based injection methods through gases mobility control. They have been successfully applied in various EOR contexts: CCUS through CO2-EOR, steam injection for heavy oil reservoirs, and also in fractured reservoirs. The success of such processes depends on multiple factors, among which the interactions between the surfactants, the oil and the rock, play a key role. The purpose of this study is to provide initial answers by focusing on the influence of wettability and oil saturation on the behavior of CO2-foam flows.
A new coreflooding set-up is designed for ‘mesoscopic’ cores (2cm diameter) in order to conduct foam formulation screening and perform faster foam injection tests at reservoir conditions. This set-up was first validated by repeating experiments performed previously on classical corefloods with 4cm diameter cores. Similar results in terms of mobility reduction were obtained for the same operating conditions with a considerable reduction of test duration.
All experiments were performed with Clashach sandstones cores having approximatively 16% porosity and 600mD permeability. Two gas compositions have been studied: (1) a dense supercritical CO2 (density of 638kg/m3 at P=160bar, T=60°C) and (2) a non-dense gas mixture of CO2 and CH4. For each gas composition, four foam injection tests were carried out: two on water-wet rock samples, two others on crude-aged core samples, and for both in the absence and in presence of oil. Anionic surfactant formulations and gas were co-injected with a gas fraction of 0.7. Foam rheology was assessed by measuring foam apparent viscosity through a scan of interstitial velocities.
All the tests performed in dense conditions have highlighted the generation of strong foams, which present shear-thinning rheological behavior; the apparent viscosity decreases as a power law of the interstitial velocity. An influence of the wettability is observed on the foam apparent viscosity, which drops off by 30% in altered wettability rock samples. When samples were originally saturated with oil at Swi, the level of apparent viscosity remains globally unchanged but the kinetics of the initial formation of the foam is slower with oil than without. Foam flooding experiments are sometimes carried out simply in the presence of oil without taking into account the influence of wettability, which appears to be as important, if not more, than the oil saturation itself. These results will hopefully provide some guidance for future foam studies and raise awareness on the importance of these parameters.
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Polymer Flood Field Implementation - Pattern Configuration and Horizontal versus Vertical Wells
Authors M. Sieberer, T. Clemens, J. Peisker and S. OforiSummaryA polymer pilot in the 8 TH reservoir in Austria showed promising results. The Utility Factors were below 2 of kg polymer injected / incremental barrel of oil produced (polymer cost are 2 – 4 USD/kg). Furthermore, substantial incremental oil was produced which might result in economic field implementation. The results triggered the planning for field implementation of polymer flooding.
To optimize the economics of field implementation, a workflow was chosen ensuring that the uncertainty was covered. 1200 geological models were generated covering a variety of different geological concepts. These geological models were clustered based on the dynamic response into 100 representative geological realizations and then used for history matching.
For infill drilling, probabilistic quality maps can be used to find locations. However, injection and production well optimization is more challenging. Introducing probabilistic incremental Net Present Value (NPV) maps allows for selection of locations of injection and production well patterns.
The patterns need to be optimized for geometry and operating parameters under uncertainty. The geometry was optimized in a first step followed by operating parameter optimization. In addition, injectivity effects of vertical and horizontal wells due to the non-Newtonian polymer rheology were evaluated. The last step was full-field simulation using the probabilistic NPV map, optimized well distance and operating parameters.
The resulting Cumulative Distribution Function of incremental NPV showed a Probability of Economic Success (PES) of 91 % and an Expected Monetary Value of 73 mn EUR.
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Development of a Field Scale Polymer Project in Argentina
Authors M.A. Hryc, F. Hochenfellner, R. Ortíz Best, S. Maler, P. Freedman and D. TorchinskySummaryAfter 6 years of continous polymer injection in El Corcobo Norte field, pilot's preliminar evaluation showed promising results. Although the evaluation is still ongoing, polymer technology economics look good enough to sustain a project expansion. Located in the Neuquén Basin, El Corcobo Norte field is an unconsolidated, underpressurized, strongly water-wet sandstone reservoir, producing medium-heavy oil from the Centenario Formation. Reservoir drive is waterflood, which has been implemented since the beginning of the field's development. Up to date the field has more than 650 producers and 350 injectors, mostly developed under 20 acres, inverted 7-spot patterns. Main challenge for this field's operation is sand production and chanelling issues that leave bypassed or undrained oil zones. Since 2008 EOR technologies were evaluated in order to increase ultimate recovery factor. As a results of this screening, polymer injection was chosen as the first candidate to test in the field. Polymer pilot design and execution was described in SPE 160078 (“Desing and Execution of a Polymer Injection Pilot in Argentina”) and pilot preliminar evaluation was presented in SPE 181210 (“Evaluation of a Polymer Injection Pilot in Argentina”). Based on the pilot's learnings, an expansion project was designed to maximize the use of the available capacity and upscale polymer injection as efficiently as possible, considering field's current operational conditions. The present article will focus on describing the upscale of the polymer pilot and the strategy to optimize the project's operation.
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High Pressure Gas EOR PVT Experimental Programs: Challenges in Measurements and Data Interpretations
Authors H. Alboudwarej, J.M. Sheffield, M. Srivastava, S.S. Wu, L. Zuo, A. Inouye, D. Zhou and A. OghenaSummaryStandard gas Enhanced Oil Recovery (EOR) Pressure-Volume-Temperature (PVT) program includes experiments such as solubility/swelling, multi-contact, slim tube, vapor-liquid equilibria (VLE) tests, and fluid property measurements. These tests are designed to determine the extent of gas miscibility and mixture phase behavior during gas injection in hydrocarbon reservoirs. These experimental programs are known to be expensive and time consuming. The degree of complexity increases as the industry move into conducting gas EOR PVT for high/ultra-high-pressure reservoirs. The focus of this paper is to demonstrate the challenges associated with these measurements and evaluate the merit, applicability, and usage of such data for fluid model development for high pressure gas EOR studies.
Associated challenges include utilizing gas concentrations up to 90% mole during swelling tests to determine critical mixture composition. Determination of dew point pressures by visual inspection or liquid build-up method proved inefficient. An interpretation of pressure-volume data showed good promise for determining both saturation pressure and liquid build-up curve for opaque dew point systems. VLE tests were designed at gas concentrations close to critical mixture composition to generate phases with increased affinity for mass transfer. Measured Minimum Miscibility Pressure (MMP) for all studied oil and gas systems were less than 6000 psia, except for N2 gas. Such relatively low MMP values suggest that development of full miscibility is not a concern for these high-pressure fluid systems. Such relatively low MMP values suggest that generated miscibility is not a concern for these high-pressure fluid systems. Instead the focus shifted to determine and effectively model the first contact miscibility pressures for these fluid systems (if it existed at pressures less than initial reservoir pressure). Measured MMPs were assigned a low weight factor in EoS model optimization process. Swelling test data for gas concentrations lower than 50% mole was of little value for EoS model optimization. Presence of precipitated asphaltenes challenged accurate measurement of liquid phase density and viscosity, as capture and analysis of a representative sample was very difficult. A knowledge of asphaltenes phase envelope for mixtures of reservoir fluid and injection gas proved to be invaluable.
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Cyclic Steam Stimulation Enhanced with Nitrogen
Authors E. Trigos, M.E. Lozano and A.M. JimenezSummaryThe main objective of this paper is show the design, implementation and results of a nitrogen + steam pilot implemented in a Colombian heavy oil reservoir. Given that the answer to the cyclic steam injection has declined significantly in some wells of the interest field due to the high number of cycles, a pilot project to assess the feasibility of injecting nitrogen accompanied cyclic steam was raised. The determination of optimum volumes and injection scheme by numerical simulation was performed in a sector model. Eleven schemes of steam plus nitrogen injection were evaluated. In all schemes, it was tested remained constant volume of injected steam, while the volume of nitrogen varied according to the scheme (pre-injection, post -injection, co-injection or a combination of the above). In all cases, it assumed the injection of nitrogen according to real drive capacity 1200 m3/hour (1017072 ft3/day).
The best case corresponds to start injecting only one day with nitrogen, followed by five days of co-injection and ending with a single nitrogen day. Under this scheme an incremental production of 5642 barrels of oil a trial period of six months, with average oil production of 53 BOPD in the same period and maximum rate of 142 BOPD. According to the simulation results, it was decided to implement the pilot steam + nitrogen injection, following the best injection scheme given above; that is, a day of pre-injection (nitrogen only), five days of co-injection (steam + nitrogen) and one day post-injection (nitrogen only). The results of the pilot show that oil production has increased compared to previous cycles, reaching similar results to the numerical simulation forecast. A methodology to implement steam injection enhanced with nitrogen is proposal in this paper, which can be applied in any field of heavy crude scheme developed under cyclic steam stimulation.
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Surfactant Flooding in Offshore Environments
SummaryA low complexity chemical flooding formulation has been developed for application in offshore environments. The formulation uses seawater with no additional water treatment beyond that which is normally performed for water flooding (filtration, de-oxygenation, etc.). The formulation is a mixture of an alkyl propoxy sulfate (APS) and an alkyl ethoxy sulfate (AES) with no cosolvent. With seawater only (no salinity gradient) the blend of APS and AES gives substantially higher oil recovery than a blend of APS and internal olefin sulfonate (IOS) in outcrop sandstone.
It is shown that the highest oil recovery is obtained with surfactant blends that produce formulations that are underoptimum (Winsor Type 1 phase behavior) with reservoir crude oil. Also, these underoptimum formulations avoid high injection pressures seen with optimum formulations in low permeability outcrop rock. The formulation recovers a similar amount of oil in reservoir rock in the swept zone. Overall recovery in reservoir rock is lower than outcrop sandstone due to greater heterogeneity, which causes bypassing of crude oil.
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Modeling Wettability Change in Sandstones and Carbonates Using a Surface-Complexation-Based Method
Authors A. Kazemi and G.R. JerauldSummaryPreviously proposed models of wettability change have not been tied to the chemistry that controls wettability but instead were driven by simplistic criteria such as salinity level or concentration of an adsorbed species. Such models do not adequately predict the impact of brine compositional change and therefore cannot be used to optimize brine composition. In this work, after testing proposed models in the literature on sandstones and carbonates, we propose a mechanistic surface-complexation-based model that quantitatively describes observations for ionically treated waterfloods. To the best of our knowledge this is the first surface-complexation-based model that fully describes ionic compositional dependence observed in ionically treated waterfloods in both sandstones and carbonates.
We model wettability change by directly linking wettability to brine chemistry using detailed colloidal science. Brine has charged ions that interact with polar acidic/basic components at the oil-water interface and rock surface and therefore oil/brine and rock/brine interfaces are charged and exert both Van der Waals and electrostatic forces on each other. If the net result of the forces is repulsive, the thin water film between the two interfaces is stable (i.e., the rock is water-wet) otherwise, the thin water film is unstable and the rock becomes oil-wet. Based on Hirasaki (1991) , we describe a ratio of electrostatic force to Van der Waals force with a dimensionless group, called “stability number,” where rock wettability is water-wet for values greater than one and oil-wet for values less than one. For sandstones, the zeta potentials of oil/brine and rock/brine interfaces become more negative/less positive by diluting or softening the brine and/or increasing pH. Similarly, for carbonates, dilution and/or sulfate enrichment of brine makes surface potentials more negative. Such brine modification can therefore be used to improve oil recovery.
We implemented the improved wettability change model in a comprehensive coupled reservoir simulator, UTCOMP-IPhreeqc, in which oil/brine and rock/brine zeta potentials are modeled using the IPhreeqc surface complexation module. We take into the account total acid number (TAN) and total base number (TBN) for the oil/brine interface and we use rock surface reactions for brine/rock surface potential modeling. Surface potentials obtained from the geochemical model are used to calculate the dimensionless group controlling wettability change, which is dynamically modeled in the transport simulator. The model is validated in sandstones and carbonates by simulating an inter-well test, and several corefloods and imbibition tests reported in the literature. For sandstones, we model Kozaki (2012) and BP's Endicott trial. For simple dilution in carbonates we model experiments by Shehata et al. (2014) and Yousef et al. (2010) . For enrichment with sulfate we model Zhang and Austad (2006) and for increasing total ionic strength via sodium chloride enrichment, Fathi et al. (2010a) .
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Long-term Polymer Degradation in High pH Solutions and Polymer Effect on Alkali-oil Phases
Authors J.R.F. Sarquez Bernal, R.E. Hincapie R., T. Clemens and B. SchumiSummaryOMV's 16 Tortonian Horizon (TH) reservoir is considered a suitable candidate for EOR via Alkali-Surfactant-Polymer A(S)P flooding. Polymer stability in A(S)P applications is a major concern mainly due to effects of temperature and brine salinity composition. Within this work, we evaluate the effect of temperature, dissolved-oxygen and presence of alkali on polymer stability in a long-term. Moreover, we also describe the polymer effect in alkali-oil mixtures and emulsion development.
We performed experiments for a period ~100 days using real injection water. Data was gathered through steady-shear rheology, pH tracking, dissolved oxygen control, phase-behavior screening and selected single-phase flooding. The workflow included a fourfold approach: 1) Assess polymer baseline behaviour with different concentrations at reservoir temperature. 2) Define optimum polymer concentrations in presence of alkali (7500 ppm), aiming to reach viscosity values reported in previous micromodel/core flooding. 3) Long-term stability assessment to define effects of temperature (50–70°C), dissolved-oxygen and presence of alkali on viscosity and average molecular weight (MW). 4) Phase-behaviour experiments to draw micro/macro emulsion phase maps. Different polymers/vendors were assessed and three included in this work. During baseline assessment a Homopolymer post-hydrolysed (Acrylamide) of high-MW (P-A) depicted the highest viscosifying power, followed by a co-polymer (Acrylamide–Sodium acrylate) of medium-MW (P-B) and a Terpolymers (Acrylamide– Sodium, Acrylate–ATBS) of high-MW (P-C). As expected, presence of alkali reduced polymer viscosity in all polymers, with optimum polymer concentrations ~2000 ppm. Long-term stability tests showed that presence of alkali enhances polymer residual viscosity6 ( η/ηo, corrected by ηbrine ), with residual viscosity decreasing once temperature is increased. However, viscosities at a given time were higher for solutions in presence of alkali compared to those without, presumably owing to increasing hydrolysis. Solutions aged at 50°C depicted 20-30% higher residual viscosity when compared to the solutions aged at 70°C. Solutions degassed with argon/nitrogen enhances polymer long-term stability. Results also showed that degassed solutions had 25% higher residual viscosity than untreated solutions and matched with previous results performed under anaerobic environment (glove-box). Complementarily, phase-experiments depicted that presence of polymer reduces water solubility. Once alkali concentration was increased a 3-phase mainly described as macro-emulsion was observed, microemulsions where only described by eye-looking/light-through observations. Overall, this study provides a workflow to perform long-term polymer degradation screening in a partially degassed environment in the absence of a glovebox. With a major observation that the experiments need to be performed without oxygen, otherwise results are different and too pessimistic.
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Development and Application of a Composite Silicate Gel for Water Shutoff Treatment in Hungary
Authors I. Lakatos, G. Szentes, J. Lakatos-Szabo, A. Vago and Z. KaraffaSummaryExcess water production usually has negative influence on volumetric sweep efficiency, and as a result deteriorates the profitability of production operations. In the past half century, numerous techniques were extensively applied in frame of water shutoff technology including polymer-based macro- and microgels, emulsions, sols, crystalline compounds, etc. Surprisingly, the operators did not appreciated the use of silicates despite the fact that the silicates were proposed as chemical diverting agent and profile control already in 1922. In the past decades, the silicate technology has a revival because of their outstanding features, which is apparently superior to other gels. These facts are well proved by more than 100 well treatments carried out in Hungary, Serbia and Oman curing various problems including excess water production, water conning, leakoff, restriction of vertical gas migration in a collapsed well and profile control in water injection wells. Earlier, the pure silicate solutions were applied, however recognizing some weak points of the gel under HPHT conditions, substantial efforts were made to improve both the chemical systems and the injection protocol.
First, combining the silicates with polymers some fundamental deficiencies could be eliminated forming a double network in gel providing flexibility and much less sensitivity to fracture and syneresis at high-pressure gradient. Later, nanomaterials were added to silicate and silicate/polymer gels, which advanced nucleation providing faster, reliable and controllable gelation in case of sequential injection protocol. The detailed laboratory studies have shown that the gelation kinetics is also substantially modified because the polymer is a retardant, while the nanosilica is an accelerator influencing thus the setting time. In addition, inevitable advantages of the composite gel are that the technology is based on cheap, easily available, and environmentally friendly chemicals. The “green” method was first applied in an oil filed (Algyő 2, field, Hungary) already in 2014, and abundant information could be collected to summarize the results and lessons to learn. Application of silicate/polymer/nanosilica gel controlling the detrimental water production resulted in outstanding technical and economic results. In one-year basis, the water production decrease by 32,000 bbl, meanwhile the incremental oil production increased by 21,000 bbl. The net profit was 653,000 USD in contrast to the investment (OPEX) of 238,000 USD. Since the profitability of treatments was above the expectation, the operator plan to continue extending the advanced composite RCC method. The paper to be presented will give a detailed overview of the laboratory studies and pilot tests.
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