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IOR 2017 - 19th European Symposium on Improved Oil Recovery
- Conference date: April 24-27, 2017
- Location: Stavanger, Norway
- Published: 24 April 2017
81 - 100 of 139 results
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Quantification of Mineralogical Changes in Flooded Carbonate under Reservoir Conditions
Authors N. Egeland, M.W. Minde, K. Kobayashi, T. Ota, E. Nakamura, U. Zimmermann, M.W. Madland and R.I. KorsnesSummaryInjection of seawater-like brines is one of the most successful EOR methods on the Norwegian Continental Shelf. Aqueous chemistry affects the mechanical strength of chalk. The injected seawater might trigger several mechanisms simultaneously and the importance of each mechanism is not fully understood. The aim of this study is to obtain an improved understanding of EOR mechanisms at pore scale by studying new mineral phases when flooding chalk with MgCl2 at reservoir conditions (130°C, 1 PV/day, 11.3 MPa effective stress). Two chalk cores were investigated, one artificial and one outcrop chalk. FE-SEM, STEM, and EDS-analyses show newly formed magnesite growing on calcite surfaces after 27 days. The Mg/Ca interphase is sharp, no diffusion of elements is observed on Ångström scale, and flooding experiments change the crystallography of phases. Whole-rock geochemistry of the Liége outcrop chalk flooded with MgCl2 for 3 years reveals a MgO content of c. 42 wt.%, but still c. 4 wt.% CaO. STEM mapping shows that CaO impurities are present in MgO dominated phases. These experiments confirm that magnesite grows as a new mineral phase even after short term flooding and that calcium is still present as impurities in the magnesite after long term flooding.
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SmartWater Flooding in a Carbonate Asphaltenic Fractured Oil Reservoir - Comprehensive Fluid-fluid-rock Mechanistic Study
Authors M. Fattahi Mehraban, S. Afzali, Z. Ahmadi, R. Mokhtari, S. Ayatollahi, M. Sharifi, A. Kazemi, M. Nasiri and S. FathollahiSummaryWaterflooding has been regarded as an efficient method for pressure maintenance of oil reservoirs. x Improved techniques such as Smart Water flooding as a new EOR/IOR process has gained more momentum based on the recent research activities in this field and the reduction of oil price. Despite many efforts on achieving the governing mechanisms of Smart Water flooding in many individual fields, most of data are sparse and more possible mechanisms which explains all the interactions yet to be introduced. This experimental study used a systematic laboratory framework which is based on seawater treatments at fixed ionic strength to eliminate the ionic strength effects, NaCl considered as the adjusting salt, as the injecting water. An oil-wet carbonate asphaltenic and fractured reservoir is the subject of this study. In order to investigate the impact of divalent ions in Smart Water and determining the governing mechanisms, both fluid-fluid and rock-fluid interactions are carefully studied through contact angle, IFT and pH measurements. The best Smart Water recipes from these experiments are chosen for Amott cell imbibition tests to combine all of the rock-fluid and fluid-fluid interactions of species during Smart Water injection in fractured rocks. According to the obtained results, sulfate ion has the most impact on IFT reduction for the crude oil and various Smart Water recipes and also causes the most reduction in contact angle tests. The imbibition experiments confirm these results, since the lowest recovery was obtained by removing sulfate in seawater while increasing this ion up to 4 times in seawater causes more than 8% of the ultimate recovery efficiency. The results indicated that sulfate is the most efficient divalent ion in seawater to improve the wettability alteration process for carbonate rocks during Smart Water flooding due to the expansion of electrical double layer mechanism. It is also believed that the acceleration of wettability alteration process would be mostly through rock dissolution mechanism. In addition, in the condition of high concentrations of sulfate ions, increased amount of Ca2+ and Mg 2+ concentrations and the absence of monovalent ions in the injecting water, result in significant enhancements in wettability alteration which lead to 17.5% increase in ultimate oil recovery efficiency.
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Interfacial Rheology at the Crude Oil/brine Interface - A Microscopic Insight of SmartWater Flood
Authors A. Gmira, S.M. Al Enezi and A.A. YousefSummarySmartWater flooding (SWF) has been proven as an effective and successful recovery method for carbonates, in which the injected water alters the carbonate rock wettability to produce incremental oil. Core-scale displacement experiments have demonstrated significant incremental recoveries of SmartWater in both secondary and tertiary modes and single-well chemical tracer tests have demonstrated this potential in the field at a larger scale. Still, the underlying mechanisms responsible for SmartWater wettability alteration of carbonates are not well understood. In this study, we are investigating the effect of salinity and ionic composition on a crude oil monolayer using Langmuir trough technique. Solely ions brines were used (CaCl2, MgCl2, Na2SO4, NaCl) in addition to seawater dilutions. Results confirmed the sensitivity of the interfacial monolayer to brine composition: a salinity decrease increases interfacial compressibility while sulfate and magnesium ions have shown interfaces with higher compressibility compared to sodium and calcium ions. The ultimate goal of this study is to enhance our understanding of carbonate wettability alteration by integrating interfacial rheological properties and its dependency on various parameters. These efforts will ultimately lead to additional oil recovery trough optimization of the fluid/fluid interactions involved in oil/brine/rock systems during SmartWater flooding.
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Introducing a Novel Enhanced Oil Recovery Technology
Authors C. Parsons, A. Chernetsky, D. Eikmans, P. te Riele, D. Boersma, I. Sersic and R. BroosSummaryIn this paper we present a novel Chemical EOR technique in which dimethyl ether (DME), a widely-used industrial compound is utilised as a miscible solvent in conjunction with conventional waterflooding. The end effect of the solvent’s application is an increase in oil recovery significantly greater than that typically achieved by waterflood alone.
The method of application is straightforward, taking advantage of DME’s solubility in both water and hydrocarbons: water is used as a carrier for DME during injection and upon contact with reservoir fluids, DME preferentially partitions into the hydrocarbon phase thereby swelling and mobilising the oil phase. This is followed by a DME-free water chase to recover the remaining mobile oil and DME. Residual oil saturation after sweep is reduced, significantly below that typically achieved by waterflood alone. Furthermore, the DME can be extracted from the produced wellstream fluids by distillation and/or absorption processes, and re-used for injection.
The DME Enhanced Waterflooding (DEW) technique takes advantage of the unique solubility properties of dimethyl ether to improve oil mobility and reduce residual oil saturations. Significant research into the pressure-volume-temperature (PVT) behaviour of DME and DME/crude oil mixtures has been carried out in recent years; in particular the partitioning behaviour of the solvent and mixing rules for the various mass transfer properties affecting mobility. The PVT-driven behaviour and the overall displacement efficiency of the DEW technique have been observed in core flood experiments using both carbonate and clastic core plugs.
The DEW technique can be deployed in reservoirs with different geologies, fluid properties and conditions (pressure, temperature and salinity), making its application envelope much larger than that of any of the currently available EOR technologies.
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Nanoparticle-stabilized Emulsions for Improved Mobility Control for Adverse-mobility Waterflooding
Authors I. Kim, A.J. Worthen, M. Lotfollahi, K.P. Johnston, D.A. DiCarlo and C. HuhSummaryThe immense nanotechnology advances in other industries provided opportunities to rapidly develop various applications of nanoparticles in the oil and gas industry. In particular, nanoparticle has shown its capability to improve the emulsion stability by generating so-called Pickering emulsion, which is expected to improve EOR processes with better conformance control. Recent studies showed a significant synergy between nanoparticles and very low concentration of surfactant, in generating highly stable emulsions. This study’s focus is to exploit the synergy’s benefit in employing such emulsions for improved mobility control, especially under high-salinity conditions.
Hydrophilic silica nanoparticles were employed to quantify the synergy of nanoparticle and surfactant in oil-in-brine emulsion formation. The nanoparticle and/or the selected surfactant in aqueous phase and decane were co-injected into a sandpack column to generate oil-in-brine emulsions. Four different surfactants (cationic, nonionic, zwitterionic, and anionic) were examined, and the emulsion stability was analyzed using microscope and rheometer.
Strong and stable emulsions were successfully generated in the combinations of either cationic or nonionic surfactant with nanoparticles, while the nanoparticles and the surfactant by themselves were unable to generate stable emulsions. The synergy was most significant with the cationic surfactant, while the anionic surfactant was least effective, indicating the electrostatic interactions with surfactant and liquid/liquid interface as a decisive factor. With the zwitterionic surfactant, the synergy effect was not as great as the cationic surfactant. The synergy was greater with the nonionic surfactant than the zwitterionic surfactant, implying that the surfactant adsorption at oil-brine interface can be increased by hydrogen bonding between surfactant and nanoparticle when the electrostatic repulsion is no longer effective.
In generating highly stable emulsions for improved control for adverse-mobility waterflooding in harsh-condition reservoirs, we show a procedure to find the optimum choice of surfactant and its concentration to effectively and efficiently generate the nanoparticle-stabilized emulsion exploiting their synergy. The findings in this study propose a way to maximize the beneficial use of nanoparticle-stabilized emulsions for EOR at minimum cost for nanoparticle and surfactant.
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Evaluation of Innovative Associative Polymers for Low Concentration Polymer Flooding
Authors D. Alexis, D. Varadarajan, D.H. Kim, G. Winslow and T. MalikSummaryPerformance of current synthetic EOR polymers is primarily constrained by salinity, temperature and shear which restrict their application to low to moderate salinity, low to moderate temperature and relatively high permeability reservoirs. The primary goal of the current work is to qualify recently developed associative polymers (AP) for EOR applications as well as to study their behavior in porous media. We also compare their performance with conventional non-associative polymers. In this work, we present the evaluation of several associative polymers. Two broad types of associative polymers were tested, one with a partially hydrolyzed poly acrylamide (HPAM) backbone and the other with a sulfonated HPAM backbone. The concentrations of the tested polymer vary between 75 ppm and 1000 ppm. We demonstrate the applicability of these innovative AP’s through the carefully controlled lab experiments: (1) Corefloods in sandpacks to compare the sweep behaviors with conventional HPAM’s. (2) Single phase flooding experiments are carried out in consolidated outcrop rocks to identify optimal polymer concentrations to achieve the desired in-situ resistance. (3) One dimensional displacement experiments with 8 cP and 90 cP oil are carried out in both unconsolidated and consolidated rocks at different temperatures to validate improved oil recovery. Results generally indicate that associative polymers require lower polymer concentration to generate high resistance factors in porous media and have stable long term injectivity behavior in high permeability rocks (>1D). Associative polymers with HPAM backbone have better filterability and injectivity in comparison to those with HPAM sulfonated backbone in low permeability (<300mD) rocks. Improved oil recovery in high permeability rocks compare well with conventional HPAM and sulfonated HPAM polymers. Based on the laboratory results, we are able to establish the selection baseline for associative polymers in different permeability rocks, salinities and temperatures. Such information can be used to select and screen the appropriate associative polymers, resulting in extending their applicability envelope in EOR.
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How Much Polymer Should Be Injected during a Polymer Flood? Review of Previous and Current Practices
By R.S. SerightSummaryThis paper provides an extensive review of the polymer concentrations, viscosities, and bank sizes used during existing and previous polymer floods. On average, these values have been substantially greater during the past 25 years than during the first 30 years of polymer flooding field activity. Reasons for the changes are discussed. Even with current floods, a broad range of polymer viscosities are injected—with substantial variations from a base-case design procedure. Extensive discussions with operators and designers of current polymer floods revealed substantial differences of opinion for the optimum design of polymer floods. This paper examines the validity of arguments that are commonly given to justify deviations from the base-case design. For applications involving viscous oils (e.g., 1000 cp), the designed polymer viscosities have sometimes been underestimated because of (1) insufficient water injection while determining relative permeabilities, (2) reliance on mobility ratios at a calculated shock front, and (3) over-estimation of polymer resistance factors and residual resistance factors. In homogeneous reservoirs, the ratio of produced oil value to injected fluid cost is fairly insensitive to injected polymer viscosity (up to the viscosity predicted by the base-case method), especially at low oil prices. However, reservoir heterogeneity and economics of scale associated with the polymer dissolution equipment favor high polymer viscosities over low polymer viscosities, if injectivity is not limiting.
Injection above the formation parting pressure and fracture extension are crucial to achieving acceptable injectivity for many polymer floods—especially those using vertical injectors. Under the proper circumstances, this process can increase fluid injectivity, oil productivity, and reservoir sweep efficiency, and also reduce the risk of mechanical degradation for polyacrylamide solutions. The key is to understand the degree of fracture extension for a given set of injection conditions so that fractures do not extend out of the target zone or cause severe channeling. Many field cases exist with no evidence that fractures caused severe polymer channeling or breaching the reservoir seals, in spite of injection above the formation parting pressure.
Although at least one case exists (Daqing) where injection of very viscous polymer solutions (i.e., more viscous than the base-case design) reduced Sor below that for waterflooding, our understanding of when and how this occurs is in its infancy. At this point, use of polymers to reduce Sor must be investigated experimentally on a case-by-case basis.
A “one-size-fits-all” formula cannot be expected for the optimum bank size. However, experience and technical considerations favor using the largest practical polymer bank. Although graded banks are commonly used or planned in field applications, more work is needed to demonstrate their utility and to identify the most appropriate design procedure.
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Application of New Tracer Technologies for Surveillance of EOR and IOR
Authors O.K. Huseby, S.K. Hartvig, K. Jevanord and Ø. DugstadSummaryRecent advances of tracer technology have induced a step-change in surveillance opportunities for EOR and IOR projects. Two particularly interesting methodologies, both targeting assessment of how remaining oil saturation can be minimized, are the partitioning inter-well tracer test (PITT) and the single-well chemical tracer test (SWCTT). Upon completion of a SWCTT or a PITT, the remaining oil saturation (ROS) can be estimated from this time-lag and the partitioning coefficient, through a simple relation. Regarding PITTs, new and stable, oil-water partitioning tracers were developed and has now matured into a well-established methodology applicable for a wide range of reservoir conditions. For SWCTTs, new and significantly improved tracers were recently applied in the field and pilot testing demonstrated that required tracer amounts are reduced from tonnes to grams. The reduction in required tracer amounts solves several operational and logistical issues. It also allow for injection of several tracers simultaneously, without compromising the chemical composition of the reservoir fluids. The tracers can be designed to span a wide range of partitioning coefficients. By analysis of interpretation of the production curves from the individual partitioning tracers, an in-situ assessment of fractional flow and how EOR chemicals can affect this fractional flow, can be made.
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Improved Method for Inter-well Partitioning Tracer Response Interpretation
Authors S.P. Busch, D.W. van Batenburg and C.P.J.W. van KruijsdijkSummaryThe partitioning inter-well tracer test (PITT) is a method to determine average oil saturation between an injector-producer pair. Tracer tests can be used to quantify incremental oil recovery in enhanced oil recovery (EOR) pilots and for reservoir surveillance purposes. Various interpretation methods can be applied: peak arrival time comparison, Residence Time Distribution Analysis (RTDA), extrapolation methods and projection methods. Various sensitivities influence the outcome, accuracy and consistency of these methods. First and foremost, reservoir geometry and heterogeneity have significant impact on the shape of the tracer response curve, and on the accuracy of the subsequent oil saturation estimation. The presence of multiple flow paths can be clearly identified from tracer responses and oil saturation of each flow path can be determined individually by use of extrapolation and projection methods. Thus, potential permeability baffles or barriers can be identified and static reservoir models can be improved by evaluating tracer response data. Further key sensitivities are sampling duration, sampling frequency and measurement errors. An incomplete tracer response can lead to significant loss of accuracy of oil saturation determination by RTDA. A low sampling frequency has severe impact on the accuracy of oil saturation estimation, especially if large measurement errors are present. For timely execution of an EOR project, an early estimation of oil saturation is desirable. In this study, a new and robust analytical projection method is proposed that enables early time estimation of oil saturation based on limited data. The projection method is based on a translation of the non-partitioning tracer response curve to the partitioning tracer curve using a time and amplitude scalar. Robustness of this method is achieved by performing a least squares optimization that takes into account all available data in order to find optimal fitting time and amplitude scalars for tracer data translation. This projection method provides accurate early time oil saturation estimations based on limited partitioning tracer data. Especially if responses are incomplete, contain multiple peaks caused by reservoir heterogeneities, have a low sampling frequency and contain large measurement errors, the least squares projection method provides a more accurate oil saturation estimate than the other methods.
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New Fluorescent Tracers for SWCTT
Authors T.B. Brichart, M.O.M. Ould Metidji, L.F. Ferrando-Climent and T.B. BjørnstadSummaryTracer technology is a tool mostly uses to monitor mass flow in various systems. In the context of reservoir monitoring, and when used during a Single Well Chemical Tracer Test (SWCTT), tracers can provide information on residual oil saturation (SOR) in the near-well zone.
Although effective, today’s single-well tracers suffer from important drawbacks. Current technology consists of simple esters such as ethyl acetate which need to be used in large quantities to be detected properly by highly qualified workers.
With its ease of use, luminescence seems to be a promising substitute to current technics. Although the oil intrinsic luminescence may be looked upon as a difficulty, time-resolved spectroscopy offers a way to circumvent it, without generating too much drawbacks.
Lanthanide chelates have gained a lot of traction over the last decade in several fields including tracers (e. g. in medicine). They are versatile and it is possible to adapt, modify and customize so that they conform to specified requirements in term of interactions and stability. In this manner, it is possible to produce potential replacement candidates for today’s SWCTT tracers.
This study explores luminescent tracers currently being designed for SWCTT, their possibilities, future developments and applications for SOR measurements.
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Integration of Analytical and Simulation Techniques to Estimate Uncertainty in Incremental Oil Recovery from SWCTTs
Authors D.J. Robbins and G.R. JerauldSummarySingle well chemical tracer tests (SWCTTs) are the first measure of potential enhanced oil recovery (EOR) response in a reservoir. This paper presents a workflow of integrating classical tracer analysis techniques with reservoir simulation modelling for understanding of the impact of pertinent non-ideal physical effects on the estimated incremental oil saturation. In particular, we introduce an extension of the direct shift method to quantitatively estimate co-injected product alcohol and the extent of gas stripping of the ester and a new type curve method for matching raw tracer data. As the reservoir simulation model of the SWCTT is under-constrained, a Monte Carlo iterator is employed to determine the distribution of oil saturation values that adequately describe the observed tracer data with unbiased sampling of the variable space. It is observed that the distribution of oil saturations derived from simulation models is not necessarily Gaussian. We show an example of a pair of SWCTTs performed in an onshore US field to determine the response of the field to a low salinity water treatment. The observed P50 estimate of incremental oil saturation is 5 saturation units, with a positively-skewed distribution biased towards larger values of incremental oil saturation.
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Robust Dynamic Modelling of the Impact of Chemical Flood Implementation Time on Ultimate Recovery and Net Present Value
Authors A.J. Alshehri, M. A. Algeer and A.M. AlkhatibSummaryChemical EOR (CEOR) methods such as polymer-surfactant flooding are used to reduce oil trapping and mobilize remaining oil. This trapping is mainly a resultant of capillary trapping associated with waterflooding. Hence, it is believed that earlier implementation of CEOR post water-flooding will result in higher oil recovery, as the impact of capillary trapping will be less prominent in this case.
One of the main challenges associated with CEOR flooding is the high implementation cost. Earlier implementation results in higher cost, hence defining the optimum implementation time necessities evaluating both ultimate recovery and Net Present Value (NPV). This study investigates the effect of post-waterflood implementation time of surfactant-polymer flooding on ultimate recovery and (NPV) - given this capillary trapping – in order to determine the optimal implementation time while maximizing the dual objectives of NPV and ultimate recovery.
CEOR has been identified as an effective EOR method which is usually implemented in tertiary mode, where field development has reached a mature level. At this stage, the efficiency of waterflooding in terms of mobilizing remaining oil declines due to capillary trapping. Although this EOR process have been implemented in tertiary mode, experimental results of earlier implementation have shown more desirable effect on recovery because capillary trapping is less prominent.
This study investigates impact of post-waterflood implementation time of surfactant-polymer flooding on ultimate recovery and (NPV) given this capillary trapping. A series of numerical experiments were conducted to test this effect while accounting for operating expenses associated with both flooding options. Capillary pressure curves for the waterflood case and the chemical flood case were added to incorporate capillary trapping effects. Then, the chemical-flood implementation time was varied to evaluate its impact on the ultimate oil recovery and NPV These experiments were performed on 2 stylized reservoir models: the PUNQ-S3 and SPE10 reservoir models.
In a previous work, we have only covered the static properties. A pronounced impact was seen on the NPV however no drastic changes were recorded on the ultimate recovery. In this study, we implement a robust model accounting for all dynamic properties associated with varying the implementation time of CEOR flooding including effects on the relative permeability.
In general, the sooner chemical EOR is implemented the higher the ultimate recovery of the process. Also, results show that the optimum implementation time – based on NPV values - is function of reservoir heterogeneity, as the more heterogeneous model has earlier optimum implementation time.
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Modeling Waterflood Sweep Improvement at Prudhoe Bay and Determining Key Controls on Incremental Oil Recovery
Authors P.K. Singh, G.R. Jerauld, D.R. Thrasher, J.S. Isby, D. Nottingham, D.H. Ohms, B. Stechauner, G. Stechauner and H. FramptonSummaryWe present a model of how a Thermally Activated Particle (TAP) system works and model the incremental response of a pattern in Prudhoe Bay, Alaska. The model has also been applied on a range of descriptions to determine the major controls on incremental oil recovery and the best circumstances to apply TAP.
Polymeric “kernel” particles expand as a result of breaking labile cross-links through a hydrolysis reaction under the influence of temperature and time. The expanded particles adsorb and provide Residual Resistance Factor to water. The model builds on conventional reservoir simulation of cold water injection and polymer flooding by including reaction kinetics of the particles and the dependence of reaction rate and other polymer properties on temperature as well as the extent of reaction. To address the uncertainty in the mechanisms, the model considers both mechanical entrapment and physical adsorption, linking the amount and impact of the entrapment to the ratio of the particle size to the estimated pore-throat size.
Previously reported slim tube data and recent coreflood studies on Prudhoe Bay core indicate physical adsorption to be the dominant mechanism. The application of the model to the treated pattern captures the timing and magnitude of the incremental response. The overall size and the resistance of the in-situ block are comparable to that interpreted from the Pressure Fall-Off analysis.
Realistic type pattern models and idealized descriptions have been used to model TAP performance for a range of slug sizes and waterflood maturities. The primary controls on incremental oil recovery are the slug size, pattern maturity, mobility ratio and heterogeneity. Traditional measures of heterogeneity do not correlate well with incremental recovery. Instead, the best correlations appear to be with the ratio of the swept volume, at breakthrough, to the total pore-volume and the slope of cumulative water-oil ratio to the instantaneous water-oil ratio, with larger slopes indicating better candidates.
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Capital Rationing by Metrics - Implications for IOR/EOR-projects
More LessSummary(1) Overview
The recent fall in the oil price has given rise to a renewed focus on other parameters for project selection that the net present value (NPV). A regime with capital constraints is introduced, implemented by key metrics like the Internal Rate of Return (IRR), the Net Present Value Index (NPVI) and the Break Even Price (BEP). The paper describes metrics used by the oil companies to ration capital, and analyse implications for IOR/EOR projects.
(2)Method
We examine the different investment metrics of a portfolio of oil projects and check how they affect ranking of projects. Particular attention is paid to IOR/EOR-projects. After the increased volatility of the oil price, more emphasis has been placed on the breakeven price. We analyse how IOR/EOR-projects are affected in their ranking - towards other types of projects - of this decision criteria. We also address how the current Norwegian petroleum tax system affects the possibility to sanction marginal IOR/EOR-projects.
(3)Results
The project metrics analysis shows that the overall grouping of the projects is the same with the three metrics for capital rationing. The highest ranked projects are the same for the l3 first projects with individual order ranking the same. This is also the same for the 6 worst projects. Projects 14 to 21 are the same for the three metric rankings but their individual ranking differ somewhat. The company focus on robustness related to oil price gives particular attention to break-even price and cost optimisation. Capital rationing may severely affect marginal IOR/EOR-project, but the choice of rationing metric is not significant. The Norwegian petroleum tax system is not well designed to secure implementation of marginal IOR/EOR-projects.
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Optimization of Alkaline-Surfactant-Polymer (ASP) Flooding Minimizing Risk of Scale Deposition
Authors O. Vazquez, I. Fursov, A. Beteta and E. MackaySummaryAlkaline-Surfactant-Polymer (ASP) flooding, which is classified as chemical EOR (Enhanced Oil Recovery) technique, has a great potential to recover an additional 10–25% of the oil in place, as demonstrated during various field pilot tests. A typical ASP flooding comprises of three stages: main ASP slug, polymer post slug and finally a water slug. The surfactant reduces the interfacial-tension between the displacing fluid and oil, the alkaline reduces the surfactant adsorption and creates in-situ natural surfactant, and the polymer decreases the water to oil mobility ratio. However, the deposition of inorganic scales directly attributed to geochemical processes during ASP flooding can significantly impact the viability of ASP floods.
ASP flooding has economic limitations due to the large volumes of chemicals injected. Therefore, technical and economical feasibility of ASP flooding depends on the effective use of the injected chemicals and slug formulation. The main purpose of this paper is to describe the automatic optimisation of ASP flooding designs using an optimization algorithm, in particular, PSO (Particle Swarm Optimization). The algorithm identifies the most efficient optimum ASP design for a given set of criteria, specifically minimizing the total chemical expense and the scaling risk, and maximizing the oil revenue and NPV (Net Present Value).
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Joint Optimization of Field Development and Water-alternating-gas Recovery Strategies
Authors T. Feng, O. Leeuwenburgh, C. Hewson and R.G. HaneaSummaryAlternating injection of water and gas (WAG) has been widely applied as an oil recovery strategy since the late 1950s. The expected benefits are improved macroscopic sweep, with the water and gas sweeping lower and upper zones of the reservoir respectively, and improved microscopic sweep due to various effects leading to lowering of the residual oil saturation. Benefits on the microscopic scale are expected especially if the injected gas is miscible with the oil. WAG has been applied to various North Sea assets such as Snorre, Statfjord and Gullfaks.
WAG strategies are typically designed using trial simulations of different scenarios. For fields with many wells it is not generally possible to design an optimal strategy without the use of approaches to systematically explore alternative strategies. Mathematical optimization theory provides such methods. Previously, we have applied such methods to determine optimal drilling sequences for new field developments for a number of Norwegian assets under uncertainty. Here we apply similar concepts to additionally optimize the optimal injection and production strategies for drilled wells.
The development period may take a number of years if many wells are to be drilled, leading to time-varying capacity to (re-)inject gas that is difficult to take into account when the order in which injectors become available is not a priori fixed. Therefore we investigate alternative approaches to characterize WAG strategies during the field development stage, namely switching time controls and injection type controls, also in combination with injection rate controls.
We present a number of examples of numerical experiments for a representative test model. Multiple geological realizations of the model are used to represent the uncertainty. Results indicate that significant improvements in economic returns can be obtained through optimization relative to reasonable base strategies, also if the WAG strategy is optimized for a fixed drilling sequence. We show that not only the expected value can be increased, but that also the value for the worst performing realizations can be improved, thereby reducing risk. Finally, we provide physical interpretations of the optimal strategies in support of decision maturation.
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Value of Information from History Matching - How Much Information is Enough?
Authors A.J. Hong and R.B. BratvoldSummaryWith the rapid increase in computing power over the past several decades, automatic or semi-automatic approaches to history matching (HM) have become viable replacements for the traditional manual HM approach. HM approaches now include robust and efficient numerical algorithms with the ability to account for geological and petrophysical uncertainties. Downhole rate and pressure data are commonly collected for the purpose of uncertainty reduction through the HM process. Although the cost required to collect such data, and conduct the HM, is significant, few companies conduct an a priori analysis of the information value from the data.
Although some studies have demonstrated the post-hoc value of HM data, few have demonstrated its a priori value; i.e., the assessment required to determine whether it is worthwhile investing in gathering the data and conducting the HM. In this paper, we illustrate and discuss an a priori analysis on information valuation, known as the Value-of-Information (VOI) analysis. The VOI from HM is assessed for future production data with the goal of informing the decision-maker of the potential value of investing in downhole measuring devices and HM procedures. We present the scientific basis for VOI analysis followed by an example of its implementation for an improved-oil-recovery (IOR) case. In the example, we use our proposed workflow of assessing VOI from HM to calculate the VOI from different types of production data and compare their values to distinguish between constructive and wasteful information gathering.
The contributions of this paper are three-fold. Firstly, we provide a consistent definition of VOI from production data and HM, and discuss the details of the calculations. Secondly, we propose a workflow of assessing VOI from HM. Thirdly, we present an IOR example using our proposed workflow involving the use of Ensemble Kalman Filter (EnKF) combined with Robust Optimization (RO) to calculate the VOI. Finally, we identify and discuss the possible causes for the limited use of VOI methods in HM contexts and suggest ways to increase the use of this powerful analysis tool.
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Polymer
Authors K. Sandengen, K. Melhuus and A. KristoffersenSummaryThere exist several mentions of HPAM polymers leading to reduced end point saturation; commonly referred to as “viscoelastic effect”. Huh and Pope(2008) proposed that polymers act as to maintain oil phase continuity, meaning that an impact can only be induced before oil breaks up into discontinuous ganglia. Hence, if their proposed mechanism is correct, common tertiary mode investigations would be misleading and cannot capture the full potential effect.
The present work was therefore initiated with the aim of testing the hypothesis of Huh and Pope. A reservoir rate core flood study was performed in a “micro-CT” imaging system enabling pore scale (≈ 7 μ m) resolution of fluids. Tertiary polymer injection, did not change oil saturation, which was in agreement with the hypothesis. Thereafter oil was injected into the porous medium, which already contained polymer, to increase oil saturation. Subsequent polymer injection led to higher SOR, which was in complete contradiction to the hypothesized lowering of SOR.
The results reported herein, did consequently not fit with the expectations from the hypothesis at question. On a general basis the results do therefore not support claims that polymer flooding, due to the viscoelastic nature of the fluid, should lead to a lower SOR.
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An Original SEC Method to Assess Simultaneously Concentration and Hydrolysis of HPAM for EOR
Authors M.L. Loriau, A.B. Boufar, T.K. Ky and N.P.B. Passade-BoupatSummaryAn original SEC method to assess simultaneously concentration and hydrolysis of HPAM for EOR.
In the current condition of hydrocarbon production, future developments of chemical EOR (cEOR) productions require a specific attention to the monitoring of chemical additives. Polymer flooding or Surfactant Polymer flooding are among the most promising cEOR technologies: the polymer is used to viscosify the injection water in order to get a better mobility control within the reservoir. For those technologies, it would be very beneficial to be able to monitor easily the polymer along the process, from the injection to the back-production. There are different water soluble classes of polymers which are able to increase the viscosity, but the most common polymer used in these technologies is partially hydrolyzed polyacrylamide (HPAM). The most specific and accurate analytical methods to quantify the HPAM polymer content are based on specific amide group dosage. As a consequence, knowing the hydrolysis degree of the polymer chains is an important parameter to determine before doing the quantification. It is also a very important parameter in itself to determine the history of the polymer chains along the process. The amide group hydrolysis can occur in the reservoir, in the wells, in the surface process, depending of physical parameters, as pressure or temperature, and also of the residence time of the polymer. In addition, the hydrolysis rate depends strongly on the water pH of the geological formation. We have developed a new methodology for polymer concentration measurements by size exclusion chromatography coupled to an Ultraviolet (UV) and a Refractive Index (RI) detector. The simultaneous use of these two detectors allows evaluating the hydrolysis rate of the HPAM. As a consequence, it is possible by only one short time analyze to obtain a real HPAM concentration, considering the real amide chemical function remaining in the polymer.
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