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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 - 50 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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