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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 - 20 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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