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74th EAGE Conference and Exhibition incorporating EUROPEC 2012
- Conference date: 04 Jun 2012 - 07 Jun 2012
- Location: Copenhagen, Denmark
- ISBN: 978-90-73834-27-9
- Published: 04 June 2012
1 - 100 of 948 results
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Condensate Recovery from a Fractured Carbonate Field (SPE 153349)
Authors C. Paraschiv, J. Abdev and T. ClemensFractured reservoirs are characterised by a large difference in permeability of the fracture and matrix system. Usually, the matrix contains the bulk of the oil while the fractures are the flow paths. These characteristics are challenging for projects aiming at increasing hydrocarbon liquid recovery from gas condensate fields by gas injection. While in fractured oil reservoirs, capillary forces (imbibition) or gravity forces can be utilised to improve oil recovery, for gas injection into gas condensate reservoirs, these forces are less important. The recovery mechanisms were investigated using the properties of a rich gas condensate field in the Middle East. A fine grid sector simulation model was created in which the fractures and matrix were introduced explicitly. Without taking diffusion into account, the injected gas breaks through at the producer very fast. The concentration in the produced gas is closely linked to the effective permeability of the fracture divided by the effective permeability of the matrix. However, taking diffusion into account, the increase in injected gas concentration is much slower. The speed of the increase (for the same pore volume injected) depends on matrix porosity, velocity of the front, fracture spacing and permeability contrast. The molecules of the injected gas are diffusing into the matrix while the components of the reservoir gas are diffusing towards the fracture. The various components have different diffusion coefficients. Dependent on the injection gas, the dew point pressure in the matrix can be reached (despite the reservoir pressure being constant) and condensate drops out. Hence, the condensate recovery depends on the injected gas. The results of the study show that neglecting diffusion in fractured reservoirs can result in errors in the condensate recovery of more than 50 %. In addition, the shape of the condensate recovery curve will be incorrect if diffusion is not accounted for.
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Gravity Segregated Flow in Surfactant Flooding (SPE 154495)
Authors A. Lohne, I. Fjelde and E.Y. PurwantoThe main recovery mechanism in surfactant flooding is improved microscopic displacement achieved by suppressing pore-scale capillary forces by approximately four orders of magnitude through reduced interfacial tension (IFT). Effects on macroscopic mechanisms like capillary trapping in presence of heterogeneities or gravity segregation are normally not considered. The influence of capillary forces on segregated flow behind the displacement front is investigated by numerical simulations in homogeneous and heterogeneous models and by steady-state upscaling. The positive effect of gravity segregation is that oil floats up, accumulates under low permeable cap rocks and thereby increases the effective horizontal oil mobility. Capillary forces act against this segregation. These mechanisms are not captured in normal coarse-gridded field models. Simulations in homogeneous layer models indicated up to 20% incremental oil production from a moderate IFT reduction (1 mN/m). More field relevant heterogeneous descriptions decreased incremental recovery down towards 5%. Gravity segregation is observed below a critical rate, depending on phase density difference, vertical permeability and layer thickness. All pertinent parameters are combined into a dimensionless viscous-gravity ratio, Rvg. The condition for gravity segregation is Rvg<1. At lower rate the oil recovery approached an upper limit obtained from upscaling under gravity-capillary equilibrium conditions. This limit was represented in terms of the dimensionless Bond number, NB. The oil production was found to be sensitive to IFT when 0.1
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Proper Design Criteria of Microemulsion Treatment Fluids for Enhancing Well Production (SPE 154451)
Authors L. Quintero, T.A. Jones and P.A. PietrangeliWhen newly drilled oil and gas wells fail to reach the expected production levels, near-wellbore damage may have resulted from fluid incompatibility, poor fluid/rock interaction and/or mechanical damage. These problems may also occur during remediation or stimulation operations if the treatment fluid is not properly designed. The main formation damage mechanisms that lead to these problems are in-situ emulsions, wettability changes, water blocks and scale formation. It is recognized that such reservoir damage can be removed or prevented using microemulsion technology which leads to more productive oil and gas wells. The challenge is to design and select an optimized microemulsion system based on the reservoir conditions, such as the bottom-hole temperature and the composition of the crude oil, formation water, and the drilling and completion fluids. A well designed treatment fluid should provide ultra-low interfacial tension, high oil solubilization and complete compatibility of all fluids it encounters. The selection of the optimum formulations for specific applications requires a systematic study of the phase behavior of brine-surfactant-oil systems as a function of temperature and its final composition, which includes the salt, surfactants, co-surfactants and an optional acid. This paper provides a comprehensive discussion of the phase behavior obtained with the brine/surfactant/oil systems used in microemulsion formulations for formation damage prevention and removal. Laboratory tests results and field applications in open-hole and cased-hole completed wells have proven that the microemulsion treatment fluids are successful in the field if there is a systematic analysis of phase behavior that identifies and defines the treatment fluid phase boundaries.
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Novel Insights into the Pore-scale Mechanisms of Enhanced Oil Recovery by CO2 Injection (SPE 154529)
Authors M. Sohrabl and A. EmadiCO2 injection is a proven EOR (enhanced oil recovery) method, which has been extensively applied in the field. CO2 promotes oil recovery through a number of mechanisms including; CO2 dissolution, viscosity reduction, oil swelling, and extraction of light hydrocarbon components of crude oil. One of the main advantages considered for CO2 injection is that it can develop miscibility with most of light crude oils at a pressure lower than what would be required for other gases. Miscibility development is a function of reservoir pressure, temperature and also oil composition. In water flooded oil reservoirs, water can adversely affect the performance of CO2 injection as it reduces the contact between oil and CO2. However, CO2 will be able to dissolve into water and diffuse from water into the oil. The dynamic interplay between these various mechanisms is complicated and cannot be captured by existing models and simulations.
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Multidisciplinary Approach for Novel Application of Formation-pressure-while-drilling Service in High-temperature(160C) Low-permeability Carbonate (SPE 154463)
Authors M. Turner, C. Bruni, I.B. Odumboni, M. Sanguinetti and B. SellamiThe Abiod formation is the principal target in the Miskar field, offshore Tunisia. Consisting of fractured geomechanically stressed carbonate with matrix permeability as low as 0.1 mD. The formation dates from Campanian to lower Maastrichtian and forms a horst structure. The formation has been under production since 1996. Obtaining formation pressure data was considered critical for determining the magnitude of depletion from production, well-to-well comparisons for vertical and lateral connectivity, forward modeling, completion decisions, and refinement of the field development plan. Historically, this has been a challenge with conventional wireline formation testers for the following reasons: - Severe depletion causing differential sticking - High temperatures (160CB0C) at the limit of tool electronics - Low permeability - Fractures and breakouts impacting seal success This was overcome with a systematic multidisciplinary approach. After review of historical formation testing data to determine seal success and probe and packer influence, it was decided to apply formation-pressure-while-drilling (FPWD) technology. The key questions with FPWD in this environment are: Can we achieve a good transient profile and what is potential impact of supercharging? These questions were addressed with advanced prejob modeling, which enabled determination of an optimized pretest configuration and testing procedure to minimize potential supercharging effects. While drilling, stage-in procedures were used, and mud logging total gas data were gathered to identify areas of liberated gas. Post-run wireline petrophysical data were gathered to calculate an intrinsic permeability profile. Ultrasonic borehole images and caliper data were used to determine the principal horizontal stress directions, fracture frequency, and orientation. Combined, this information allowed a focused orientation of the FPWD probe and optimal station selection avoiding fractures and breakouts. This novel approach resulted in 100% seal success, >60% improvement. Four days of rig time were saved, and the required data were obtained.
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Characterization of Direct Fractures Using Real Time Offshore Analysis of Deuterium Oxide Tracer (SPE 154878)
Authors A. Poulsen, K. Bousquet Lafond, T. Lundgaard and L.M. PedersenInduced or natural fractures in waterflooded reservoirs can have a negative impact on oil recovery. Direct connections between injectors and producers allows otherwise recoverable oil to be bypassed by the injected water, reducing the sweep efficiency and the pressure support to the reservoir. Knowledge about the number of connections, their location and size is essential to properly design a reliable conformance treatment. The Danish Technological Institute has together with Maersk Oil developed a deuterium based tracer technology which can provide information about high conductivity fractures in tight reservoirs. The method has been proven on several studies in the North Sea and allows quick and direct analysis offshore. Immediate actions based on real time results offshore can be taken and minimum response time is needed for planning further operations. The tracer used is deuterium oxide which is safe to handle and brings no environmental issues, as it is already naturally present in water. It is completely miscible with water and does not dissolve in the oil phase. The returns are analyzed directly from the produced water stream after separation using a mass spectrometer. This portable equipment allows a quick and reliable analysis with minimal sample preparation. The concentration of tracer is analyzed to give information such has breakthrough time, concentration profile and volume of tracer returned. This data is then used to determine the number of fractures, their conductivity and their relative position in the wellbore using an injector-fracture-producer model.
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Optimizing Reservoir Monitoring - Improving PNL Logs in Changing Borehole Environments (SPE 152761)
Authors M. Kanfar, I. Ariwodo, A. Qatari and P. SaldungarayThe growing demand for oil has emboldened producing companies to reenter old wells to drill laterals to further improve productivity and recovery. This requires reevaluating the water saturation. Successes in reservoir saturation monitoring petrophysical analysis have increased the confidence to drill sidetracks in watered wells that have bypassed oil potential. Several techniques can be used to perform the analysis. The Pulsed Neutron Log is one of the most popular. Slim logging tools allow running the surveys without having to pull out the production string. Under the right conditions, Pulsed-Neutron Capture logs can be run periodically in the time-lapse mode to monitor changes in water saturation, and movements in the oil-water contact and gas-oil contact. The wellbore environment might change between runs and this can complicate the analysis. For example, the borehole fluids can be different: gas, oil or brines of varying salinities. Also, changes in the downhole completion hardware would require running the logs in single or multiple strings. One has to be cognizant of all these environmental effects and appropriately correct for them to obtain the true formation properties, and to make comparisons between runs in the time-lapse analysis. Different vendors use different correction schemes. In this paper we will discuss case studies with a methodology from one service company that uses the forward modeling approach, which relies on first characterizing the tool response in a known environment. The paper will comment on the advantages and disadvantages of this technique, in particular, when the downhole conditions deviate from the characterized environment. Alternatives will be proposed to get the best possible results, based on a study conducted by Saudi Aramco. Finally, we will present some examples in Saudi Arabian wells where the computed capture cross section and neutron porosity were successfully corrected in challenging conditions.
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Ekofisk 4D Seismic - Seismic History Matching Workflow (SPE 154347)
Authors E. Tolstukhin, B. Lyngnes and H.H. SudanThis presentation outlines an integrated workflow that incorporates 4D LoFS data into the Ekofisk field reservoir model history matching process. Successful application and associated benefits of the workflow process are also presented. A permanent ocean-bottom cable array was installed in Ekofisk field in 2010 as a part of a Life of Field Seismic (LoFS) program. This program provides frequent 4D seismic data, and the first three surveys have been acquired in years 2010-2011. LoFS monitoring data is used to optimize the Ekofisk waterflood by providing water movement insights and subsequently improving infill well placement. Reservoir depletion and water injection in Ekofisk lead to reservoir rock compaction and fluid substitution. These changes are revealed in space and time through 4D seismic differences. Inconsistencies between predicted (calculated from reservoir model output) and actual 4D differences are therefore used to identify reservoir model shortcomings. This process is captured using the following workflow: prepare and upscale a geologic model; simulate fluid flow and associated rock-physics using a reservoir model; generate a synthetic 4D seismic response from fluid and rock-physics forecasts; and update the reservoir model to better match actual production/injection data and the 4D seismic response. The above-mentioned Seismic History Matching (SHM) workflow employs rock-physics modeling to quantitatively constrain the reservoir model and develop a simulated 4D seismic response. Then parameterization techniques are used to constrain and update the reservoir model. This workflow updates geological parameters in an optimization loop through minimization of a misfit function. It is an automated closed loop system, and optimization is performed using an in-house computer-assisted history matching tool with an evolutionary algorithm. In summary, the Ekofisk LoFS SHM workflow is a multi-disciplinary process that requires collaboration between geological, geomechanical, seismic and reservoir engineering disciplines to optimize reservoir management.
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Reservoir Description of the Subsurface Eagle Ford Formation, Maverick Basin Area, South Texas, USA (SPE 154528)
Authors B. Driskill, A. Garbowicz, A.M. Govert and N. SuurmeyerThe Eagle Ford Formation (EF) is a marl deposited during a highstand on a broad shelf along the paleo-Texas coast. It is thickest in the Maverick Basin, a small sag related to crustal thinning. Datasets were collected including core, cuttings, chemostrat, biostrat, and well logs. From the core and cuttings, core CT scans, thin sections, SEM images, FIB-SEM volumes, and XRD/XRF tables were acquired. The purpose of the data was to understand EF depositional processes and rock textures, and to create a predictive model for reservoir properties. The regional EF study began with correlation of 400+ logs. The correlation involved a sequence stratigraphic framework (SSF) based on log character and refined with ash correlations, biostrat and chemostrat. Texture seen in core, core CT scans, and the SEM/FIB-SEM work was compared to the SSF. These data gave insights into patterns of fluctuating oxygen and energy levels which were then included into the depositional model (DM). The DM shows regional patterns of composite parasequences in which properties such as TOC, porosity, carbonate content and rock texture are predictable. SEM/FIB-SEM images show that pores in the EF are mainly intergranular or within organic matter (OM), and that the structure of OM pores is related to maturity level. Using the SSF, reservoir properties can be predicted along the EF trend: cycles of EF with good reservoir properties can be mapped with respect to hydrocarbon fluid zones to yield risk maps. By understanding how and where different parts of a parasequence stack you can better predict sweet spots for well productivity, both geographically and stratigraphically. Each unconventional play is unique; what works for reservoir characterization and risk mapping in one is not always applicable to another. It is important, then, to document which strategies work in each play.
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Overdisplacing Propped Fracture Treatments - Good Practice or Asking for Trouble? (SPE 154397)
Authors K.A.W. van Gijtenbeek, H.J. De Pater and J.R. ShaoulOne of the major issues that comes with the development of unconventional ultra-tight shale gas reservoirs is related to under-displacing or over-displacing hydraulic proppant fracture treatments in multiple zone completions in horizontal wells. Multi-stage hydraulic proppant fracture treatments in horizontal well completions in tight gas reservoirs are, in general, under-displaced to ensure that a highly conductive path exists between the reservoir and the wellbore. In recent years, a large amount of multi-stage propped fracture treatments in horizontal wells in ultra-tight shale gas reservoirs are being over-displaced in order to get a clean wellbore and avoid problems with the hardware used for rapid multi-zone completions. Clean-out treatments are not required and therefore multiple treatments can be performed quickly, saving time and money. This practice may result in a poor connection between the ultra-tight reservoir and the wellbore. On the other hand, if the rock strength is sufficient, over-displacing a treatment could result in a very high conductivity region at the wellbore. This mechanism is similar to what has been seen in some wells with proppant flowback, where well productivity has increased following proppant flowback, which creates channels in the proppant pack near the perforations. This paper discusses these practices and, based on a combination of finite element modeling and fine gridded reservoir simulation, will try to answer if and when over-displacing fracs in shale or tight gas reservoirs should have a positive or a negative effect on production.
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Transient Gas Flow in Unconventional Gas Reservoirs (SPE 154448)
Authors Y. Wu, P. Fakcharoenphol, J. Li and C. WangUnconventional gas resources from low-permeability formation, i.e., tight and shale gas, are currently received great attention because of their potential to supply the entire world with sufficient energy for decades to come. In the past few years, as a result of industry-wide R&D effort, progresses are being made towards commercial development of gas and oil from such unconventional resources. However, studies, understandings, and effective technologies needed for development of unconventional reservoirs are far behind the industry needs, and gas recovery from those unconventional resources remains low (estimated at 10-30% of GIP). Gas flow in low-permeability unconventional reservoirs is highly nonlinear, coupled by many co-existing, processes, e.g., non-Darcy flow and rock-fluid interaction within tiny pores or micro-fractures. Quantitative characterization of unconventional reservoirs has been a significant scientific challenge currently. Because of complicated flow behavior, strong interaction between fluid and rock, the traditional Darcy law may not be applicable for describing flow phenomena in general. In this paper, we will discuss a general mathematical model and use both numerical and analytical approaches to analyze gas flow in unconventional reservoirs. In particular, we will present analytical solutions of incorporating Klinkenberg effect, non-Darcy flow with threshold pressure gradient, and flow behavior in pressure sensitive media. We will discuss the numerical implementation of the mathematical model and show applications of the mathematical model and solutions.
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Will Gas Hydrate Lying on Oceanic Floors in India Solve its Energy Problem? A Futuristic Approach (SPE 152471)
Authors A. Jha, S. Alimuddin, S. Kundu and A. SinghIndia with the largest gas hydrate deposits in the world have potential of being the biggest global producer of NGH (a solidified form of gas lying on oceanic floors). 1.08 trillion cubic metres of the proven conventional natural gas reserves in India is around 1700 times less than the prognosticated gas hydrate resources of 1894 trillion cubic metres lying in the deep water regions. Even the extraction of minor fraction of this resource can be the energy hunters for decades. This paper discusses the geological and geophysical aspects of marine gas hydrate distribution in India. Through a wide literature survey on successful gas hydrate field studies in the world authors have shown the technical and economic hurdles which are imposing constraints on the wide scale extraction of natural gas from NGH. The Indian exploration strategies to identify and quantify the gas hydrates by various seismic tools (e.g. seismic reflectors coincidence with the base of the gas hydrate stability zone (BGHSZ)) with its limitations are described in lucid manner. Also, the technical advancements with the help of various case studies are presented to eliminate the mentioned limitations. Well- based extraction technology (a drilling program) is discussed for safe and economically viable production of gas from gas hydrate reservoirs. Lastly at present researches going on to simulate the gas hydrate reservoirs incorporating mass and heat transfer along with intrinsic hydrate decomposition kinetics is described in context of Indian gas hydrate reservoirs. IndiaC"s 7500 km of coastline having a vast fuel reserve in the form of NGH can be a next generation energy source if mature extraction technology is developed to extract the gas from gas hydrate reservoirs.
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Gravity-enhanced Transfer between Fracture and Matrix in Solvent-based Enhanced Oil Recovery (SPE 154374)
Authors S. Kahrobaei, H. Bruining, R. Farajzadeh and V.S. SuicmezDescription Solvent injection has been recently considered as an efficient method for enhancing oil recovery from fractured reservoirs. If the mass transfer was solely based on diffusion, oil recovery would have been unacceptably slow. The success of this method therefore depends on the degree of enhancement of the mass exchange rate between the solvent residing in the fracture and the oil residing in the matrix. A series of soak experiments have been conducted to investigate the mass transfer rate between the fracture and the matrix. In a soak experiment, a porous medium containing oil is immersed in an open space containing the solvent to simulate the matrix and the fracture respectively. We use a CT scanner to visualize the process. The experimental data are compared with a simulation model that takes diffusive, gravitational and convective forces into account. Application For oil wet conditions, injection of a liquid (waste) solvent can be considered as a possible alternative for recovery from naturally fractured reservoirs. In the absence of interfacial tension no residual phase trapping occurs. Gravity enhanced transfer leads to practical recovery rates. Results, Observations and Conclusions The initial stage of all experiments can be described by a diffusion-based model with an enhanced C"effective diffusion coefficientsC". In the second stage enhancement of the transfer rate occurs due to the natural convection of solvent in the fracture and its effect on the flow in the matrix. The experiments can be quantitatively mimicked by numerical simulations. We find that transfer rates depend on the properties of the rock, solvent and oil. Technical and economic aspects are further discussed in the paper. Significance The interaction between matrix and fracture is visualized for solvent flooding by means of X-ray computed tomography, which can be used to validate theories of enhanced transfer in fractured media.
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Smart Waterflooding (High Sal/Low Sal) in Carbonate Reservoirs (SPE 154508)
Authors A. Zahid, A.A. Shapiro, A. Skauge and E.H. StenbyIn recent decade, low salinity waterflooding has been emerged as a prospective EOR method. Extensive laboratory research and successful field tests showed that low salinity waterflooding can improve the oil recovery from both outcrop samples (used in experiments) and reservoir sandstones. However, low salinity effect has not been thoroughly investigated for carbonates. Most recently, Saudi Aramco reported 16-18 % OOIP increase in oil recovery by low salinity waterflooding in composite rock samples from Saudi Arabian carbonate reservoirs. The objective of this work is to experimentally investigate the oil recovery potential of low salinity water flooding for carbonate rocks and to study the ion interaction with rock and wettability change using NMR. We used the Thamama formation carbonate (Abu Dhabi) and the Aalborg chalk core plugs for this study. The flooding experiments were carried out initially with the seawater, and afterwards the contribution to oil recovery was evaluated by sequential injection of various diluted versions of the seawater. The total oil recovery, interaction of the different ions with the rock, and the wettability change were studied both at room and high temperature. No low salinity effect was observed for the Thamama formation core plug at room temperature, but increase of the pressure drop over the core plug is detected. On the contrary, a significant increase in oil recovery was observed under low salinity flooding of the Thamama formation core plug at 90 CB0C. An increase in pressure drop was also observed in this case and that may be related to migration of fines or formation of emulsions. The Aalborg chalk core plugs did not show any low salinity effect, both at room and high temperature. NMR measurements showed that low salinity brine solutions affect the wettability of the Thamama formation core plugs.
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World's First Combination of Acid & Steam Provides a New Dimension to Heavy Oil Enhanced Recovery Process (SPE 154515)
Authors T. Shaheen, W. Hassan, S. Kamal and M.I. Ul Haq SiddiquiThe Issaran field located200 km east of Cairo-Egypt, is a heavy oil reservoir.The oil is of 8-12 degree API with viscosity of 4000 cps at standard conditions. Productivity of the wells has sharply declined due to increase in water cut and increase in the formation skin value. The problem is attributed to the heterogeneity of the reservoir together with presence of fractures which is causing poor sweep efficiency plus the accumulation of hydrocarbon deposits. The major challenge to remedy this situation was; Not only the creation of new extended flow channels, accurate placement of the treatment, diversion within the reservoir, and to provide sustain production increase but also the flow and the production of oil through the newly formed wormholes. A new innovative approach using a combination of acid based treating fluids and steam were used. Acid in combination with unique chemical diverting agent plus selective placement mechanism succeeded to open new production horizons and stimulate the existing one. The Addition of Steam has succeeded in reducing the viscosity and increasing the mobility of oil, and also in providing pressure support to the reservoir achieving further increase in the benefits of the acid stimulation. The results of the treatments carried out so far have provided a new dimension in the enhanced recovery process of the heavy oil. This paper explains the design, execution, evaluation and the recommended way forward of this world first acid & steam production enhancement initiative for the reservoir enhanced recovery process.
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Effect of Hot Water Injection on Sandstone Permeability - An Analysis of Experimental Literature (SPE 154489)
Authors G. Rosenbrand and I.L. FabriciusThe seasonal imbalance between supply and demand of renewable energy requires temporary storage, which can be achieved by hot water injection in warm aquifers. This requires that the permeability and porosity of the aquifer are not reduced significantly by heating. We present an overview of published results regarding the effect of temperature on sandstone permeability. These tests are performed with mineral oil, nitrogen gas, distilled water and solutions of NaCl, KCl, CaCl2 as well as brines that contain a mixture of salts. Thirteen sandstone formations, ranging from quartz arenites to formations with a significant fraction of fine particles including clay minerals are investigated. The porosities range from 0.10 to 0.30 and permeabilities span the range from 1 to 1000 md. To compare different rock types, specific surface is determined from permeability and porosity using Kozeny’s equation.
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Adjoint-based History-matching of Production and Time-lapse Seismic Data (SPE 154375)
Authors G.M. van Essen, A. Conn, G.D. Sippe, L. Horesh, E. Jimenez, J.K. Przybysz-jarnut and P.J. Van den HoekTime-lapse (4D) seismic attributes can provide valuable information on the fluid flow within subsurface reservoirs. This spatially-rich source of information complements the poor areal information obtainable from production well data. While fusion of information from the two sources holds great promise, in practice, this task is far from trivial. Joint Inversion is complex for many reasons, including different time and spatial scales the fact that the coupling mechanisms between the various parameters are often not well established, the nature of the required model updates is localized, and the necessity to integrate multiple data. These concerns limit the applicability of many data-assimilation techniques. Adjoint-based methods are free of these drawbacks but their implementation generally requires extensive programming effort. In this study we present a workflow that exploits the adjoint functionality that modern simulators offer for production data to consistently assimilate inverted 4D seismic attributes without the need of re-programming of the adjoint code. Here we discuss a novel workflow which we applied to assimilate production data and 4D seismic data from a synthetic reservoir model, which acts as the real - yet unknown - reservoir. Synthetic production data and 4D seismic data were created from this model to study the performance of the adjoint-based method. The seamless structure of the workflow allowed rapid setup of the data assimilation process, while execution of the process was reduced significantly. The resulting reservoir model updates displayed a considerable improvement in matching the saturation distribution in the field, as well as a vast improvement in predictive capacity. This work was carried out as part of a joint Shell-IBM research project.
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Assisted Seismic History Matching in Different Domains - What Seismic Data Should We Compare? (SPE 154503)
Authors I. Sagitov and K.D. StephenTime-lapse (4D) seismic data can be integrated into history matching by comparing predicted and observed data in various domains. These include time domain, seismic attributes, or petro-elastic properties such as acoustic impedance. Each domain requires different modelling methods and assumptions as well as data handling workflows. The aim of this work is to investigate the degree to which the choice of domain influences outcome of history matching on the choice of best model and associated uncertainties. Another aspect of history matching is that long simulations often pose an obstacle for an automatic approach. In this study we use appropriately upscaled models manageable in the automatic history matching loop. We apply manual and assisted seismic history matching to the Schiehallion field. In the assisted approach, the optimization loop is driven by a stochastic algorithm, while the manual workflow is based on qualitative comparison of seismic maps. By upscaling we obtained an order of magnitude gain in performance. Accurate upscaling was ensured by thorough volume and transmissibility calculation within regions. The parameterisation of the problem is based on a pattern of seismically derived geobodies with specified transmissibility multipliers between the regions. Seismic predictions are made through petro-elastic modelling, 1D convolution, coloured inversion and calculation of different attributes. We were able to achieve a reasonable match of production and 4D seismic data using coarse scale models in manual and assisted approaches. We observed that the misfit surfaces are different when working in the various seismic domains considered. Use of equivalent domains for observed and predicted data was found to give a more unique misfit response and better result. Accurate comparison of predicted and observed 4D seismic data in different domains is necessary for tackling non-uniqueness of the inverse problem and hence reducing the uncertainty of field development predictions.
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Assisted Seismic History Matching of the Nelson Field - Managing Large Numbers of Unknowns by Divide and Conquer (SPE 154892)
Authors K. Stephen, A. Kazemi and F. Sedighi-dehkordiAutomatic history matching may be used to condition reservoir simulation models by including time-lapse seismic data. Stochastic optimization algorithms are used to perform a good search of the parameter space and to ensure proper determination of the best models. These approaches can require many thousands of simulations for large dimensional problems. Divide and conquer is an assisted history matching approach that enables deconvolution of the parameters so that they can be searched more efficiently and also leads to better uncertainty analysis. We present an application of this approach to the Nelson field. Nine years of production history data were used along with seismic baseline and monitor surveys. Localised variations were made to permeability and net:gross. We were able to divide the reservoir model into separate parameter regions as a form of localization by combining experimental design and proxy model analysis. The former enabled insignificant parameters to be discarded. The latter showed that each region could be treated as a separate history matching sub-problem which was solved simultaneously using an adapted genetic algorithm. We found that a forty-two dimensional problem could be reduced to a combination of three 9D problems and a 3D problem due to the spatial deconvolution of parameters and misfits. An improved match was obtained for the production and seismic data. Compared to a full stochastic search of the parameter space, the number of models was several orders of magnitude smaller. Further, improved uncertainly analysis was made possible resulting in better forecasting. An improved match to reservoir models leads to better confidence in their prediction and thus they can be used more effectively in reservoir management. The method presented here improves the match and retains the benefits of stochastic searching without the penalty of requiring an impractical number of simulations.
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Reducing the Dimensionality of Geophysical Data in Conjunction with Seismic History Matching (SPE 153924)
Authors J. Rezaie, J. Sotrom and E. SmorgravSeismic history matching (HM) has attracted increasing attention the last few years. With the increasing amount 4D seismic available, it becomes imminent to find efficient and robust ways of conditioning these data jointly with the production data. A common conception seems to be that the amount of data represented by geophysical observations and the complexity of working with 3D fields make the updating procedure hard. We investigate the nature of geophysical observations from a conditioning point of view by testing several data reduction techniques such as Principal Component Analysis (PCA), regression techniques such as forward stagewise, as well as elastic nets. We argue that simulated geophysical fields from the prior models are prone with spatial correlations and that their information content and effective dimensionality is much smaller than the size/rank of the observed field. The techniques are tested on a reservoir model of a real North Sea oil field, using two conditioning algorithms: The ensemble Kalman filter and a response surface Bayesian approach. In addition to production data we condition the model to the seismic time shift, i.e. the difference in travel time integrated over the reservoir between two surveys. We find that PCA is particularly promising, resulting from the versatility and robustness of the method. In practice this means that high dimensional geophysical data, e.g. seismic images or seismic cubes, can often be described using only a handful of scalars. We show how to assess the information content in the data, compress the data, and use this compressed data consistently with other data types in a reservoir conditioning setting. Our results are of high significance. The methods we present are generic; they apply equally well to any geophysical attribute regardless of representation and they can be applied with any history matching algorithm.
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Integrated Reservoir Studies, Karachaganak Field, Republic of Kazakhstan (SPE 154390)
Authors A. Francesconi, C. Albertini, F. Bigoni, C. Catalani, A. Cominelli and V. TarantiniThe Karachaganak field is one of the largest accumulation of gas-condensate in the world, in production since 1985. Located in the northern Pricaspian Basin (Kazakhstan) the field is a Permo-Carboniferous isolated carbonate platform with a hydrocarbon column that resides within different environments of deposition. The distribution of reservoir properties has been largely debated because of both the depositional heterogeneity and the diagenetic overprint. These uncertainties were assessed by analyzing and integrating the vast amount of geological and production data to build a predictive history matched reservoir model. Seismic facies analysis, with support from outcrop analogues and integrated with field core and log data, reveals, within stratigraphic intervals, C"depositional regionsC" (DRs) that ranges from platform interior bedded deposits to aggrading/prograding mounds, clinoforms, slopes and basin sediments. These DRs were first seismically mapped and then petrophysically characterized using geologic and dynamic data. In a geologically meaningful manner that makes use of DRs, a sequence of better and better models was built and critical petrophysical issues (such as enhanced/matrix permeability, sealing barriers and dolomitization) were in parallel addressed. A reference model has been so defined and a history match of remarkable quality has been achieved for this complex heterogeneous reservoir. The uncertainty was investigated in a pragmatic manner using HM as benchmark. The reservoir uncertainty decreases closer and closer to the well, hence various models were built by updating DR properties up to a certain distance from the production wells. Using the distance and the magnitude of the perturbations as control parameter and the degree of history match as selection criterion, we could identify two cases. These scenarios represent possible alternative C"end membersC" consistent with the geological data, still endorsed by a high quality history match and capable to give a significant spread in the production forecast.
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Effect of Drilling Fluid (Water-based vs Oil-based) on Phase Trap Damage in Tight Sand Gas Reservoirs (SPE 154652)
Authors M. Tsar, H. Bahrami, R. Rezaee, G. Murickan, S. Mehmood, M. Ghasemi, A. Ameri and M. MehdizadehTight gas reservoirs normally have production problems due to very low matrix permeability and different damage mechanisms during drilling, completion and stimulation operations. Therefore they may not produce gas at commercial rates without production optimization and advanced completion techniques. Tight formations have small pore size with significant capillary pressure energy suction that imbibes and holds liquid in the capillary pores. Leak off of liquid into formation damages near wellbore permeability due to phase trap damage and clay swelling, and it can significantly reduce well productivity even in hydraulically fractured tight gas reservoirs. This study presents evaluation of damage mechanisms associated with water invasion and phase trapping in tight gas reservoirs. Single well reservoir simulation is performed based on typical West Australian tight gas formation data, in order to understand how water invasion into formation affects well production performance in both non-fractured and hydraulically fractured tight gas reservoirs. A field example of hydraulic fracturing in a West Australian tight gas reservoir is shown and the results are analysed in order to show importance of damage control in hydraulic fracturing stimulation of low permeability sand formations.
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New Flattening-based Methodology for More Accurate Geostatistical Reservoir Populating (SPE 154781)
Authors M. Poudret, C. Bennis, C. Dumont, O. Lerat and J.F. RainaudIn the domain of oil exploration, geostatistical methods aim at simulating petrophysical properties in a 3D grid model of reservoir. The main input comes from drilled wells data in the geographic space. Lithofacies and petrophysical properties as porosity and permeability are measured along these wells trajectories. These data are then assigned to every cell of the 3D grid model which intersects a well trajectory. At this step, only a small amount of cells are populated with petrophysical properties. Roughly speaking, the question is: which properties we should give to cell c, knowing the properties of n cells at a given distance from c? Obviously, the population of the whole reservoir must be computed while respecting the spatial correlation distances between petrophysical properties. Thus, the computing of these correlation distances is a key feature of the geostatistical simulations. In the classical geostatistical simulation workflow, the evaluation of the correlation distance is imprecise. Indeed, they are computed in a Cartesian simulation space which is not representative of the geometry of the reservoir. Thus, depending on the deformation degree of the lithostratigraphic units in the geographic space, significant errors may be introduced in the geostatistical simulation. This lack of accuracy has prompted us to work on and devise a new methodology in order to increase the reliability of the parameters required by the geostatistical simulators. We propose a new methodology in order to better estimate the correlation distances between wells. Our methodology is based on the isometric flattening of lithostratigraphic units. Thanks to this flattening process, we accurately reposition the initial populated cells in a flat simulation space, before computing the correlation distances. In this paper, we introduce our methodology threw study case representing different deposit modes of the sub-surface models. We finally present some preliminary results.
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Asphaltene Deposition Study and its Effects on Permeability Reduction - A Case Study (SPE 153512)
Authors S.M. Razavi, R. Kharrat and Z. ZargarAbstract Asphaltene deposition affects the porosity and permeability which in turn reduces the production and raises the processing costs. Therefore, it is necessary to determinine the amount of solid deposition causing the porosity and permeability reduction. In this paper, it has been tried to overcome this need by simulating the process in one of the South-West Iranian reservoirs in which asphaltene problem has been encountered frequently. The wells under production were facing severe asphaltene choking and coiled tubing acid wash were done every six month to remove the deposited asphaltene. Flow assurance results for the fluid are clearly indicating that oil is highly asphaltenic although it is a light oil with low asphaltene content. In the other hand, wells under production always are required to keep the rate as long as possible due to economic limits and it was critical for the management to know the effect of asphaltene deposition in the reservoir formation on the flow rate and vice versa. The best way to see the effect is reservoir simulation in which asphaltene deposition is modeled. First of all, the fluid model and asphaltene precipitation curve were prepared. Then, the reservoir static and dynamic models were generated based on the rock and fluid properties. The behavior of asphaltene during the production as precipitated, flocculated, and deposited asphaltene were modeled using commercial software. In addition, the variation of permeability due to asphaltene deposition was obtained. Asphaltene and permeability map were generated for the entire reservoir. Most of the deposition was found to form around and nearby the production wells. Minor permeability reduction was observed throughout the reservoir; however, major damage was around the wellbore. Both precipitation and deposition amounts were visible and can be reported and this ability increases the capability to decide better about the optimum production.
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Chalk Reservoir Management through Rock Physics Diagnostics - Field Examples from the Danish North Sea (SPE 154870)
Authors L. Gommesen and H.P. HansenWith improvements in 3D seismic products and an increasing number of 4D examples from North Sea chalk fields, the usages of rock physics is becoming more and more accepted as an enabler for detailed reservoir characterization and monitoring of the dynamic behavoiur of the reservoirs. In order to manage the fields optimally, it becomes increasingly relevant for the asset team to understand the effective elastic properties of the reservoir rock recorded from seismic, well logs and laboratory experiments and the related the changes that production and water injection may induce. Through a series of field examples this paper decomposes and quantifies the effect of lithology and porosity variations, fluid replacements, pressure changes in a reservoir management context using rock physics fundamentals. The examples includes both 3D and 4D seismic observations and the case examples are backed up by well log and laboratory data. The paper summarizes on how rock physics insights on North Sea chalk has increased the understanding of the chalk reservoirs and directly impacted reservoir management by integration of quantitative geophysical interpretation with solid reservoir engineering and proven geoscience processes. On basis of the examples the paper concludes that an intgrated approach to field development and reservoir management evidently includes quantitative geophysical interpretation in order to optimize hydrocarbon production from tight chalk fields.
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History-matching with Ensemble-based Methods - Application to an Underground Gas Storage Site (SPE 154475)
Authors V. Gervais, L. Heidari, M. Le Ravalec-Dupin and T. SchaafThis paper shows the application of two ensemble-based assimilation methods to constrain an underground gas storage site operated by GDF-Suez to well pressure data. The methods considered here are the Ensemble Kalman filter (EnKF) and the Ensemble Smoother (ES). The EnKF is a sequential data asssimilation method that provides an ensemble of models constrained to dynamic data. It entails a two-step process applied any time data are collected. First, the production response is computed for each model of the ensemble at the following acquisition time. Second, models are updated using the Kalman filter to reproduce the data measured at that time. The EnKF has been widely applied in petroleum industry. More recently, the ES was used successfully on real field cases. This method is also based on the Kalman filter, but the update is performed globally over the entire history-matching period: values simulated at each assimilation time are considered simultaneously in the update step. The multiple restarts necessary with EnKF are thus avoided. We present here an application of these methodologies for constraining an underground gas storage site to well pressure data. The uncertain parameters are the porosity and horizontal permeability values populating several layers of the geological model. Both methods yield a good match of pressure data in the history-matching and prediction periods. For ES, this can require two successive applications. Considering the same initial ensemble, the ES leads to a smoother mean with less extreme values and a higher variance. The EnKF and ES methodologies turn out to be powerful tools to constrain geological models to dynamic data, and were applied successfully to a real field. The ES gives here similar results in terms of match and predictions while preserving a higher spread within the model ensemble with less extreme petrophysical values.
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On Population Diversity Measures of the Evolutionary Algorithms Used in History Matching (SPE 154488)
Authors A. Abdollahzadeh, M.A. Christie, D. Corne, B.J. Davies, A. Reynolds and G. WilliamsIn history-matching the aim is to generate multiple good-enough history-matched models in limited number of simulations which will be used to efficiently predict reservoir performance. History-matching is the process of the conditioning reservoir model on the observation data which is mathematically ill-posed, inverse problem and has no unique solution and several good solutions may occur. Numerous evolutionary algorithms are applied to history-matching which operate differently in terms of population diversity in the search space throughout the evolution. Even different flavours of an algorithm behave differently and different values of an algorithmC"s control parameters result in different value of diversity measure. These behaviours vary from explorative to exploitative. The need to measure population diversity arises from two bases. On one hand maintaining population diversity in evolutionary algorithms is essential to detect and sample good history-matched ensemble models in parameter search space. On the other hand, since objective function evaluations in history matching are expensive, algorithms with fewer total number of reservoir simulations in result of a better convergence are much more favourable. Maintaining populationC"s diversity is crucial for sampling algorithm to avoid premature convergence toward local optima and achieve a better match quality. In this paper, we introduce and use two measures of the population diversity in both genotypic and phenotypic space to monitor and compare performance of the algorithms. These measures include an entropy-based diversity from the genotypic measures and a moment of inertia based diversity from the phenotypic measures. The approach has been illustrated on a synthetic model, PUNQ-S3, as well as on a real North Sea model. We demonstrate that introduced diversity measures provide efficient criteria for tuning the control parameters of the algorithms as well as performance comparison of the different algorithms used in history matching.
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Assisted History-matching for the Characterization and Recovery Optimization of Fractured Reservoirs Using Connectivity Analysis (SPE 154392)
Authors A. Lange, A. De Lima and D.J. SchiozerAn integrated optimization workflow was developed to characterize seismic and sub-seismic fault networks from history-matching. A fractal model of fault networks is optimized via the gradual deformation of stochastic realizations of fault density maps, fault spatial and length distributions. In order to facilitate the history-matching, connectivity analysis tools were developed for characterizing wells-reservoir and well-to-well connectivity. Indeed these connectivity properties usually depend on the fault network realization and may be strongly correlated with the reservoir flow dynamics. Connectivity analyses were performed on a fractured reservoir model involving a five-spot well configuration with four injectors and one producer. The connectivity was estimated from shortest path algorithms applied on a graph representation of the reservoir model. Several reservoir simulations were performed for different fault network realizations to seek correlations between injector-producer connectivity and water breakthrough time. The impact of the fracture properties uncertainties on the wells-reservoir connectivity was estimated via the cumulated connected volume computed for each well. This connectivity measure provides a mean to characterize and classify fault network realizations. Correlations were found between the water breakthrough time and the injector-producer connectivity, thus allowing one to identify the most probable fault network realizations to match the observed water breakthrough time. Finally, for a given fault network realization, it is shown how the oil recovery can be optimized by correlating injectors rates with the injector-producer connectivity. A gain of 3e6m3 in produced oil was obtained, while retarding the water breakthrough time by 16 years, compared with a case where all injectors have the same rate. The proposed methodology and tools facilitate the history-matching of fractured reservoir, providing consistent reservoir models that can be used for production forecast and optimization.
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Assisted History Matching Using Three Derivative-free Optimization Algorithms (SPE 154112)
More LessDescription: Gradient-based optimization algorithms can be very efficient in history matching problems. Since many commercial reservoir simulators do not have an adjoint formulation built in, exploring capability and applicability of derivative-free optimization (DFO) algorithms is crucial. DFO algorithms treat the simulator as a black box and generate new searching points using objective function values only. DFO algorithms usually require more function evaluations, but this obstacle can be overcome by exploiting parallel computing. Application: This paper tests three DFO algorithms, Very Fast Simulated Annealing (VFSA), Simultaneous Perturbation and Multivariate Interpolation (SPMI) and Quadratic Interpolation Model-based (QIM). Both SPMI and QIM are model-based methods. The objective function is approximated by a quadratic model interpolating perturbation points evaluated in previous iterations, and new search points are obtained by minimizing the quadratic model within a trust region. VFSA is a stochastic search method. These algorithms were tested data with two synthetic cases (IC fault model and Brugge model) and one deepwater field case. Principal Component Analysis is applied to the Brugge case to parameterize the reservoir model vector to less than 40 parameters. Conclusions: We obtained good matches with all three derivative-free methods. In terms of number of iterations used for converging and the final converged value of the objective function, SPMI outperforms the others. Since SPMI generates a large number of perturbation and search points simultaneously in one iteration, it requires more computer resources. QIM does not generate as many interpolation points as SPMI, and it converges more slowly. VFSA is a sequential method and usually requires hundreds of iterations to converge. With enough computer resources available, applying the SPMI method is the best choice. When the number of computer cluster nodes is limited, QIM is the best choice. We recommend applying VFSA when using a single computer.
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A Comprehensive Workflow for Assisted History Matching Applied to a Complex Mature Reservoir (SPE 154383)
Authors J.F.M. Van Doren, G. Van Essen, O. Wilson and E.B. ZijlstraCurrently a multitude of techniques exist for (computer-) assisted history matching (AHM) of simulation models, each with their merits and limitations. In this paper, it is demonstrated how different AHM techniques can be combined to quickly reveal diagnostics of a subsurface model and to obtain a better model in less time, optimally using the strengths of each method. A completed field application of AHM will be presented, in which several AHM techniques are sequentially used to arrive at a history match on pressures and fluid rates and, equally important, an improved understanding of both the static and dynamic model. The water flooded field, located in the Middle East, has decades of historical production data from about 30 wells and is notoriously difficult to match. The first technique that has been applied involves Design of Experiments to generate proxies followed by Monte Carlo Markov Chain to find the ensemble of global parameters that give an improved match. Subsequently, adjoint-based history matching has been used to find the areas in the model that were under-modelled and needed additional attention of the subsurface team members. Based on the results in this step of the workflow the static model has been improved such that it is consistent with the information in the production measurements. For this field, the AHM workflow has achieved a considerable reduction of history matching time and improved quality of both the match and the model. For general simulation studies this workflow is estimated to result in a time saving of 40% with respect to manual history matching. In addition, it results in a better understanding of the static and dynamic subsurface uncertainties.
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An Improved Inversion Workflow Jointly Assimilating 4D Seismic and Production Data (SPE 154157)
More LessDescription: Quantitative integration of 4D seismic data with production data into reservoir models is a challenging task. This paper tackles two key issues of the complex joint inversion workflow to improve its efficiency and accuracy. We applied two derivative free optimization (DFO) methods, namely particle swarm optimization (PSO) and Simultaneous Perturbation and Multivariate Interpolation (SPMI), and compared their performances. We tested different strategies of effectively mining information in both 4D seismic and production data. We proposed a method of choosing the different weights in data domain by utilizing sensitivity of inversion parameters to different types of data. We also tested the strategy of combining the inversion results from separate inversion runs using 4D seismic data or production data only. Application: We tested the workflow in a 3D synthetic model. Uncertain parameters for this model include relationship between porosity and permeability, and the ratios of kv to kh for different reservoir zones. The performance of PSO and SPMI are compared in terms of the evolution of objective function and estimation of uncertain parameters. We also provide recommendations about when to use which method. Different strategies of optimal use of 4D seismic and production data are also applied and compared using this model. The learning is also applied to a deepwater turbidite field. Results, Observations, Conclusions: Both PSO and SPMI are effective DFO methods and deliver good results for 4D seismic history matching problems. The complementary features of these two methods can ensure both applicability and efficiency of this joint inversion workflow. Choosing proper weights in either data or model domain can improve the accuracy of this workflow. Significance of Subject Matter: By solving the two key issues of jointly assimilating 4D seismic and production data, we deliver reliable workflow for reservoir model characterization and management.
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Refined Adaptive Gaussian Mixture Filter - Application on a Real Field Case (SPE 154479)
Authors R. Valestrand, G. Nævdal, A. Shafieirad, A.S. Stordal and E. DoveraOver the last decade the ensemble Kalman filter (EnKF) has attracted attention as a promising method for solving the reservoir history matching problem: Updating model parameters so that the model output matches the measured production data. The method possesses unique qualities such as; it provides real time update and uncertainty quantification of the estimate, it can estimate any physical property at hand, and it is easy to implement. The method does, however, have its limitations; in particular it is derived based on an assumption of a Gaussian distribution of variables and measurement errors. A recent method proposed to improve upon the original EnKF method is the Adaptive Gaussian mixture filter (AGM). The AGM loosens up the requirements of a linear and Gaussian model by making a smaller linear update than the EnKF and by including importance weights associated with each ensemble member at computational costs as low as EnKF. In this paper we present a refined AGM algorithm where the importance weights are included in the calculation of the apriori and the aposteriori covariance matrix and we also present results where this algorithm is combined with distance based localization. Moreover, in this paper the AGM algorithm is for the first time applied to a real field study. To validate the performance of AGM the result is compared with the EnKF, with and without distance based localization. Several statistical measures are used to validate the performance of the filters, and we are able to distinguish the performance of the different filters. In particular all the methods provide good history match, but we see that the AGM stands out by better honoring the original geostatistics.
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Removal Efficiency of Water-based Drill-in Fluid Filter Cake Using Polylactic Acid (SPE 154192)
Authors S. Elkatatny and H.A. Nasr-El-DinWater-based drilling fluids consist of xanthan gum, starch, sized calcium carbonate and salt particles to increase mud density was used to drill horizontal wells. Available chemical methods of removing filter cake like mineral acids, esters, oxidizers, and chelating agents are limited at certain conditions. A drilling fluid was designed based on calcium carbonate particles and an ester of lactic acid. The objective of the latter is to remove calcium carbonate once the drilling operation is complete and there is a need to remove the filter cake. Extensive lab work was done to; 1) determine thermal stability of the drilling fluid (70-72 pcf) for 24 hrs, 2) characterize the filter cake using a computer tomography, 3) assess potential formation damage for different rock types (limestone and sandstone) using a modified HPHT filter press, and 4) determine the removal efficiency of the filter cake and the return permeability. The results obtained showed that the drilling fluid has stable rheological properties up to 300oF over 24 hrs. CT scan showed that the filter cake contained two layers, one layer closed to the rock surface, which contained a mixture of calcium carbonate and acid-precursor and one layer closed to the drilling fluid that contained a mixture of XC-polymer and starch. The polymer layer was removed by using 10% solution of alpha amylase. The rest of the filter cake was removed by lactic acid that was produced from the hydrolysis of the ester. The removal efficiency of the filter cake was nearly 80% and the return permeability was about 100%. The decrease in CT number of the core after the removal process indicated that the filter cake was completely removed. This paper will discuss the development of this new drilling fluid and will give recommendations for field applications.
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Wellbore Section Contribution in Fractured Horizontal Openhole Wells (SPE 153326)
More LessMore and more horizontal wells are completed as openhole and fractured with multistage fractures. The question is what is the contribution of the openhole section to total production in a fractured horizontal openhole well? Based on actual production data of a horizontal well before and after multistage fracturing, combining the data from a cemented casing horizontal well nearby, the paper analyzes popular horizontal and fractured horizontal well correlations first, and then presents a new inflow performance model accounting both the horizontal openhole section and the fractures of horizontal wells. Data from 13 fractured horizontal openhole wells were used to check the presented model. The paper can be used to study the inflow performance of a horizontal gas well, and to check how much the horizontal openhole section contributes in a fractured well. The presented analyses can also be used to determine fracture numbers and weather to use openhole or cemented casing completion. For a fractured horizontal openhole well, both wellbore and fractures contribute to the total production of the well. Openhole length, fracture number and the ratio of horizontal to vertical permeability are the major control factors. The producing part from the wellbore section is less than that from widely used horizontal models (like JoshiC"s). The more the fractures are, the less the openhole section contribution is. The model can be used for horizontal wells with or without fractures. The presented new model gives better results for authors 13 wells. Previous fractured horizontal well models overestimate the production from the wellbore, and underestimate the production from the fractures. The paper presents the change of fluid flow direction due to hydraulic fractures into the wellbore.
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Real Time Advanced Surface Flow Analysis for Detection of Open Fractures (SPE 154927)
Authors T. Al-Adwani, J.M. Dashti, J. Estarabadi, G. Ferroni, B. Khan, A. Martocchia and K. SinghDescription A Coriolis-type mud flowmeter was run on an exploratory well to obtain Real-Time identification of open formation fractures in an otherwise tight carbonate reservoir. The well was drilled with oil base mud which does not enable accurate flow measurement with other sensor types. This was the first time that accurate fracture detection via advanced flowmeters was performed in oil base mud. Application Tight, fractured carbonate reservoirs are the prime targets for hydrocarbon exploration in Kuwait. Sustained economic production from carbonate reservoirs depends entirely on the connectivity of open fracture networks. Hence, proper evaluation of fractures is key to exploration of these reservoirs. Cores and image logs are used for fracture characterization, but they do not provide Real-Time response. The patterns in the variations of mud flow, instead, enable to identify open fractures. Results, Observations, Conclusions The system has proven to be the only source of Real-Time information on the presence of open fractures while drilling. It has also been utilized as an early kick detection tool. The paper presents a series of events in which these results are substantiated. These results have enabled to confirm and further develop interpretation models for flow behaviour in relation to fluid exchange between the borehole and the formation. Furthermore, in order to maximize the quality of the flow data, a correct sensor installation design and execution has proved critical. Significance of Subject Matter No open hole logging was possible in the zone of interest in the pilot well due to high pressure and associated drilling complications. In this situation, information from mud flow anomalies was the only source for identification of open fractures. This information was utilized to identify the well test interval.
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Evaluation of Multistage Fracturing by Hydrajet, Swellable Packer and Comprehensive Packer Techniques in Horizontal Openhole Wells (SPE 153328)
More LessHorizontal openhole wells are commonly fractured by one of the three hydraulic fracturing techniques of hydrajet, swellable parker and compressive packer techniques. The paper reviews the application of 23 wells fractured by hydrajet (12 wells), swellable parker (4 wells) and compressive packer (7 wells) in tight gas sands in China. None method is overwhelming in the view of increasing production rate from the paper. The paper presented that different treatment pressures among stages may not a signal of perfect isolation. Created traverse fracture by hydraulic stimulation may not be at the middle of two packers or at the place of opened sleeve port for swellable packer and mechanical packer stimulation. Hydrajetting is a good choice to stimulate a specific place along the entire wellbore. Unlike in vertical wells, hydrajetting may not reduce the breakdown pressure in horizontal well treatment. The presented comprehensive comparison and discussion of the three fracturing methods will help operators understand the three methods better and accomplish production goals.
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A Novel Optimisation Algorithm for Inflow Control Valve Management (SPE 154472)
Authors I. Grebenkin and D.R. DaviesIntelligent Wells are equipped with downhole sensors to monitor the downhole flow and Inflow Control Valves (ICVs) to control the zonal flow rate. These ICVs are operated to increase the hydrocarbon recovery and prevent unwanted fluid production. This objective is simply stated, but optimisation of ICV operation is a complex, non-linear problem. Several commercial software providers have made optimisation algorithms available to the industry. Nevertheless, experience shows that challenges still arise with these algorithms when they are applied to real-field cases. Not only does the calculation time increase dramatically (up to 50 times when compared with non optimal run), but also stability and convergence problem give additional increases in running time as well as providing unrealistic results at random intervals. These problems are particularly acute if the software is applied to production uncertainty analysis where the running of multiple realisations is required. This paper will present a novel method for implementing an ICV control strategy. We chose the direct search algorithm to form the basis for our method since it is not affected by convergence problems. Our control strategy will use the current, zonal inflow rate and water cut data to identify the optimal ICV choke positions. The availability of this data reduces the number of possible choke positions that have to be evaluated at each time step by the simulator. Run times only 2-5 times greater than the base case can then be achieved while, equally importantly, the optimal value identified is similar to the value from other, widely accepted methods. We will show how this method can be used for reactive control of oil production from intelligent wells completed with discrete ICVs and, since this control algorithm is always convergent, fast and sufficiently stable will indicate how it may be used for production uncertainty analysis.
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A Modified Version of the Aziz et al - Multiphase Flow Correlation Improves Pressure Drop Calculations in High-rate Oil Wells (SPE 154125)
Authors H. Al-Attar, M. Amin and M. MohamedThe prediction of multiphase pressure drop during the simultaneous flow of oil, gas and water in vertical tubing strings is crucial in the development and optimum exploitation of an oil field. In this paper a method is proposed to improve pressure drop calculations of the Aziz et al. multiphase vertical-flow correlation which has been theoretically justified. The present method suggests combining several flow pattern maps with the Aziz et al. correlation in an attempt to achieve the improvement sought. Two field data sets gathered from 38 production tests conducted in the Middle East and North Africa are used to examine the performance of the various combinations. The results of this work indicate that the performance of Aziz et al. multiphase correlation can be best improved by replacing its original flow-pattern map with the traditional Duns-Ros flow-regime map and for both data sets used. A significant improvement has been observed giving an overall absolute average percent deviation of 2.17% compared with 9.54% for the original correlation. Surprisingly, the Taitel et al. and Barnea et al. flow pattern map does not seem to give accuracies comparable to those of the Duns-Ros correlation. Also it has been found that an improvement in the performance of the Taitel et al. and Barnea et al. flow pattern map would be possible by assigning a value of 0.33 to its void fraction parameter instead of the original value of 0.25. This work represents an addition to the technology of multiphase behavior in vertical pipes and its results will help in a more accurate design of oil well tubing strings in high-rate producing wells.
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Vertical Lift Models Substantiated by Statfjord Field Data (SPE 154803)
Authors O. Fevang, M.G. Fossmark, K.N. Kulkarni, H.T. Lauritsen and S.M. SkjaevelandThe Statfjord field entered into the blowdown phase after 30 years of production. Production of injection gas and gas liberated from residual oil is the main production target in this phase. In some areas, the gas cap has been produced and the wells are producing mainly water until the solution gas is mobilized. These wells have gone through large changes in GLR and WCT. Production tests from wells located in such areas have been used when analysing the ability of multiphase-flow correlations to model vertical lift performance (VLP). Accurate modelling of the VLP is critical to predict a realistic production rate during the blowdown phase. Measured wellhead (THP) and downhole pressures from 203 production tests, from six wells, were used to analyse the accuracy of VLP correlations at widely varying flow conditions (GLR, WCT, and THP). Altogether 17 partly well-known, multiphase pressure drop correlations incorporated in the program Prosper were tested by comparing observed and calculated downhole pressures. Based on the production tests the ability of the different correlations to predict the VLP varies with the following top 3: Petroleum Experts, Petroleum Experts 2, and Petroleum Experts 3. These correlations are recommended if no measured data is available. In general too low pressure drops were predicted at low gas-liquid ratio (GLR), and too high pressure drops at high GLR. After tuning, accurate predictability was observed for the different correlations for limited ranges in GLR e.g. 50-300 Sm3/Sm3. However, for larger ranges in GLR it was not possible to achieve an accurate VLP correlation even after tuning. The error in the predicted production performance when a single VLP correlation is used can be substantial for highly productive wells with large variations in producing GLR. It is recommended to shift the tuning following the GLR development.
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The Volund Field - Developing a Unique Sand Injection Complex in Offshore Norway (SPE 154912)
Authors A. Townsley, E.W. Jameson and A. SchwabThe Volund Field, in offshore Norway, is unique in being composed entirely of a large-scale sandstone injection complex. It consists of stacked sandstone sills, surrounded by shallower, steeper dipping injected sandstone dykes (>20CB0). The sands are excellent reservoir with consistently high porosity and permeability. Based on seismic, good connectivity was expected within the injectites from the water leg through the oil and into the gas cap. However, pre-production the extent of aquifer support and efficiency of water sweep were unclear. The Early Eocene complex was identified from seismic, which exhibits a Class 3 negative amplitude AVO anomaly. Development drilling began in 2009. The team strove to build a simulation model that allowed rapid generation of multiple realisations to investigate the effects of geological uncertainty on recovery, whilst honouring the AVO data. Geobodies extracted from seismic captured the geometry of the injectite. By populating these core bodies and surrounding C"halosC" with sands of varying properties within a geomodel, a series of realisations were built. Simulation modelling was employed to complete a dynamic uncertainty study and understand the potential effects of connectivity on aquifer and injection support. Drilling of four horizontal production branches and one injector was successfully completed in 2010 giving ~5500m of well control. Production began in April 2010 and 18 months of plateau production have demonstrated good communication. The reservoir benefits from aquifer support, but requires injection to maintain pressures. To date, no water has been produced, suggesting sweeps efficiencies in the upper half of our uncertainty range. This case study presents a modelling method based on seismic attributes which allows very quick generation of realisations that focus variation where there is the most uncertainty. This was key to the successful development of the Volund Field, a unique example of an economically producing sandstone injection complex.
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Considerations on of Drillpipe Dynamics with Actual Drilling Data (SPE 154481)
More LessThe scientific drilling vessel CHIKYU was designed to have the capability to drill down to 10000m total vertical depth and to obtain core samples. To reach such deep drilling and to recover core samples, it is important to know drill pipe dynamics using the actual drilling data. The core recovery rate is affected by the variation of the weight on bit caused by the propagation of the vessel heave motions. Therefore, a heave-compensating system will be used and it is very important to evaluate the performance. Furthermore, the drill bit behavior will also influence on the core recovery. In the extreme case, stick-slip, which will cause cracks or fractures in the core samples, occurs. In addition, to reach such deep drilling, a fine strength evaluation is mandatory because there is little margin. So, the estimation of dynamic tension due to vessel heave motions is necessary. Thus, the authors have acquired the drilling data including the vessel motions, the hook load variations and drilling torque variations. It is observed that the heave compensating system have the capability to mitigate the propagation of the vessel heave to the drill string within 30% if the condition is good. On the other hand, it was also observed that the heave compensator operated at a low level of mitigation if the condition is bad. Also we conduct the drill pipe dynamics analysis such as the vertical dynamic motions and the drill bit rotation, and make considerations on the hook load variations and the drill bit behaviors. Actual drilling data provided the worthy information on the drill pipe dynamics. The considerations will be utilized for future operations such as Tohoku Earthquake Drilling Program and NANKAI Trough drilling programs and also for future technical development.
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In-depth Evaluation of Deep-rock Hydrajet Results Shows Unique Jetted Rock Surface Characteristics (SPE 153333)
Authors H. Stockhausen, D.G.G. Sanchez, R.A. Loghry and J. Basuki SurjaatmadjaThe use of hydrajetting for perforating of wells has been commonplace since the sixties. During those early years, wells were relatively shallow; and jetting success was consistently demonstrated. However, as wells became deeper, and rock formations tend to be harder at those depths, performance of hydrajetting was less dependable; as subsequent stimulation failures more often occur from the lack of fracture initiation. In order to remedy this situation, a series of tests were performed to define new best practices for hydrajet perforating of rock under high ambient pressure. Various rocks were subjected to these tests; which were done using different jetting pressures and different abrasives. The perforation surfaces were then dissected, and then evaluated using photographic and chemical means. Further assessments are then made to determine as to what actually happened during the hydrajetting process. This paper discusses various tests results; and new constraints for jetting are defined and presented.
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Risk Evaluation Technique for Tubing-conveyed Perforating (SPE 152419)
Authors C. Baumann, K.E. Barnard, J.R. Cromb, D.R. McDaniel, R. Suffridge and H.A.R. WilliamsHigh-pressure wells are susceptible to gunshock damage when they are perforated with inappropriate gun systems. This paper presents a simulation tool that predicts Tubing Conveyed Perforating gunshock loads reliably. This tool enables completion engineers to evaluate the sensitivity of gunshock loads to changes in gun type, charge type, shot density, tubing size and length, use of shock absorbers, rathole length, and placement of packers, among others. When planning perforating jobs in high-pressure wells, engineers strive to minimize the risk of equipment damage due to gunshock loads. The software described here helps engineers to identify perforating jobs that have a risk of gunshock related damaged, such as bent tubing and unset packers. When predicted gunshock loads are large, changes to the perforating equipment or job execution parameters are sought to reduce gunshock loads and the associated damage risk. We compare software predictions with high-speed pressure gauge data for each perforation job. Gauge pressure data shows that predicted wellbore pressure transients are accurate both in magnitude and time. Peak sustained pressure amplitudes at the gauges are on average within 10% of software simulated values, both for gun underbalanced and gun overbalanced conditions. For cases where shock absorbers were used, residual deformations of crushable elements correlate well with the peak axial loads predicted by the software. The software is able to simulate perforating job designs in a short time, which allows engineers to optimize perforation jobs by reducing gunshock loads and equipment costs. The ability to predict and reduce gunshock induced damage in perforating operations is very important because of the high cost associated with high-pressure deepwater operations. With the software tool described in this paper engineers can optimize high-pressure well perforation designs by minimizing the risk of gunshock related damage and the associated rig time losses.
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An Engineering Approach to Utilize Fiber Optics Telemetry Enabled Coiled Tubing (ACTive Technology) in Well Testing and Sand Stone Matrix Stimulation - First Time in the World (SPE 154513)
Authors T. Shaheen, S. Abd El Rahman, E. Anwar and V. NoyaThis paper explains the first ever application of using Fiber Optics Telemetry Enabled Coiled Tubing (ACTive Technology) in well testing and the capability of calculating the skin value, live, during Matrix Stimulation. It also explains the efficiency in determining the faults in the reservoir and the time saving in making Build Up test for low pressure reservoirs which are not naturally flowing. For the last years viscous pills and some polymers were used to kill the wells during the workover operation in the tronian formation existing in the eastern desert of Egypt. The polymer being pumped has negatively affected the wells productivity by blocking the pore throats and reducing the permeability. As an example, the well (A) was producing 500 bopd which declined dramatically after a work over operation to produce only 40 bopd. An Engineering Study was done to identify the main reason for the decline in the production. Several experiments were done in the lab in order to simulate the filter cake using formation sample and simulate the effect of the polymer being injected on the permeability. An engineered solution was designed to break the polymer being pumped in the formation and stimulate the Matrix in order to recover and enhance the oil production. Operation was done utilizing Fiber Optics Telemetry Enabled Coiled Tubing (ACTive Technology) in order to achieve the following: 1) Measure and record bottom hole pressure. 2) Measure and record bottom hole temp. 3) CCL depth correlation to achieve max accuracy while placing the fluid. 4) Monitor the change in temp during treatment execution. 5) Monitor how the diversion effect and the reactions in the sand stone formation during stimulations and the timing required for efficient reactions. All the data gathered were very representative and became a reference for the field.
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Simulation of Drilling Fluid Filtrate Invasion Near an Observation Well (SPE 154014)
Authors R. Chassagne and P.S. HammondDescription: We use a commercial reservoir simulator to study first the dissipation of aqueous drilling fluid filtrate invasion around a cased observation well in an oil-saturated formation under the action of capillary pressure, and then the interaction of a waterflood front with the cased well and remaining invaded zone. Hysteretic behaviour of the capillary pressure and relative permeabilities is critically important to these processes and is taken into account using the Killough model, with the various bounding drainage and imbibition curves computed from a pore network model. Application: Filtrate invasion into a hydrocarbon formation influences the readings of well logging tools. Although this phenomenon has been known, and corrected for, for many years, uncertainty remains with regard to the long-time behaviour of invasion around observation wells where no flow in or out of the formation occurs after completion and to the influence of formation wettability. Results: After sufficient time the invaded zone dissipates completely in a water-wet formation, but some invasion always remains in the oil-wet case. Non-wetting-phase trapping, manifested through relative permeability hysteresis, is the cause. Because trapping affects the values and the end points of the relative permeability curves, a waterflood front passing across an observation well is more distorted in the oil-wet case. Significance: The simulation results allow us to understand how logging tool measurements made in cased observation wells are influenced by drilling fluid invasion and will therefore lead to improved interpretation. This study shows strong links between the wettability of the formation and persistence of invaded zone saturation, and between invaded zone saturation and the distortion of subsequent flood fronts.
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Geology and Geohistory Contribute to Flow Assurance (SPE 154585)
Authors H. Yonebayashi, D.R. O‘Brien and S. TosicKashagan is a super giant offshore carbonate field which was discovered in 2000 by a consortium of oil companies (currently, affiliates of): ExxonMobil, ENI, Shell, TOTAL, Conoco-Phillips, INPEX and KazMunaiGaz. The field is a deep, large structural relief, over pressured, isolated, carbonate build-up with a high-permeability, karstified and fractured rim and relatively low-permeability platform interior. The field contains a sour, undersaturated light oil with a large gas content. High pressure miscible gas injection is planned for oil recovery enhancement, as well as sulfur management. No-one doubts the importance of flow assurance in offshore projects. The consortium has undertaken extensive evaluations to ascertain the likelihood of any flow assurance risks from subsurface to surface. During the asphaltene risk evaluation, many bottomhole samples have been collected and analyzed for asphaltene content, asphaltene onset pressure (AOP), and SARA (saturates, aromatics, resins and asphaltenes). These analysis efforts sometimes revealed anomalous results such as AOP being detected from some fluid samples while not being detected from others. The apparently inconsistent AOP results are critical to understand to guide flow assurance measures. Therefore, all available asphaltene data were re-assessed in all their aspects to attempt to clarify asphaltene risk. This paper presents a multidisciplinary approach where a synergy between reservoir engineering and geoscience has been developed to explain AOP results for this difficult fluid. The results should help flow assurance specialists to better define the asphaltene operating envelope, which will be used for reservoir and production operations optimization. In addition, these results should be useful for optimizing data-surveillance and for defining new sample acquisition plans. The paper will show examples of the related flow assurance analyses, and the geological information which were incorporated in the study, resulting in a detailed asphaltene matrix risk profile for this reservoir.
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Optimization of Proactive Control Valves of Producer and Injector Smart Wells under Economic Uncertainty (SPE 154511)
Authors M.A. Pinto, C.E. Barreto and D.J. SchiozerSmart wells can improve oil recovery, mitigate risks and avoid unnecessary well intervention in petroleum fields. However, there is no consolidated methodology to evaluate the applicability of smart wells and to represent smart wells in commercial simulators, which complicates the comparison with conventional well. Moreover, there are two main modes of operation of smart well valves, reactive and proactive; each one can provide different benefits. In general, proactive control seeks maximum oil recovery, but it requires larger computational effort and greater knowledge of the reservoir than the reactive control. This paper presents a comparison between different configurations of smart wells with proactive control and mode operation on/off: (1) five-spot configuration with conventional wells (producer and injectors), (2) one smart producer and four conventional injectors, (3) one conventional producer and four smart injectors and (4) one smart producer and four smart injectors, in order to compare the different behaviors. The objective of this study is evaluate the potential of each type of configuration and the benefits of the smart injectors and producer acting separately or together, considering the effects on production and costs of smart completion. For this, a genetic algorithm was coupled to a commercial simulator to optimize the proactive control and to search the maximum net present value (NPV), determining the optimum operation control for each valve. The case study consists in one heterogeneous reservoir model, light oil and three economic scenarios (pessimistic, probable and optimistic). Results show that the use of smart injector wells, in this case study, can improve control over water production, although it may not be sufficient to justify the investment on a more expensive completion. On the other hand, the configuration using a smart producer well is capable of increasing oil recovery, therefore making the investment in a smart completion feasible.
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New State of the Art Asset-optimization Data Applications for Intelligent Completions in Digital Oilfields (SPE 153702)
More LessInformation provided using intelligent completions in digital oil fields is increasing in importance, because it has the capability to minimize the needs for custom data-gathering solutions as well as simplify industry data interfacing standards for multiple devices and systems. For assets using intelligent completions, solutions offered are attained by a combination of subsurface and surface or subsea sensors provided by several vendors. Challenges arise when attempting to manage the interfaces required for providing real time data from all points of interest; i.e., subsurface choke positions, flow, pressures and temperatures, wellhead positions, subsea facility readings etc. This paper describes the design and implementation of an integrated data-applications system that can integrate data from multiple workflow sources for the purpose of maximizing field performance. The asset optimization applications acquire operating parameters from all points of interest and make them available to software modules designed to estimate key well-performance indicators. The asset-optimization application discussed here is an integrated system that performs the following five services. A data-interfacing methodology acquires data from multiple sources or directly from downhole devices. The integration service converts the subsurface and surface data to engineering units of measured well parameters. The well performance service uses well PVT and device-integration service values to execute complex calculations like virtual flow metering, water-cut estimates, etc. The human/machine/interface service provides visualization, trending and querying. The connectivity service facilitates structured data transfer to field historians. The paper will explain how the system works and its implementation into fields of different scales and types to reduce information technology (IT) customization, simplify interfacing of multiple devices or systems, and accommodate evolutions in IT. Additional system benefits that included more efficient management of real-time data security, quality, redundancy, and mirroring will also be provided.
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A New Approach to Fracturing and Completion Operations in the Eagle Ford Shale (SPE 152874)
More LessDescription: This paper describes a new approach to fracturing and completing shale wells - getting them on production more quickly. Many operators in south Texas use a traditional approach to completions and pipeline hookup. A new process has been introduced which integrates LWD, wireline, coiled tubing, fracturing, micro-seismic, and flow back/testing to bring wells online more safely, efficiently, and repeatably. Application: Wells in the Eagle Ford shale require large high pressure hydraulic fracturing fleets and multiple service providers. Traditionally this entails fifteen - twenty service companies to coordinate the stage fracturing process. 4500 foot laterals in the Eagle Ford shale required ten days to stimulate 14-20 stages using plug and perforating techniques. The new approach described in the paper reduces this time and improves KPIC"s. Results and Observations: The paper documents three south Texas case studies. Eagle Ford well completions are complex. When fifteen or more service companies are contracted this complexity results in inefficiency and safety incidents. The new integrated approach improves process flow, planning, safety and efficiency and has gained favor with south Texas operators. Planning and communicating are key to reducing non-productive time during 24 hour per day operations. New logistics software is described. Other improvements include hybrid and cross-linked fracturing fluids, open-hole completion assemblies, micro-seismic, chemical tracers and geo-chemical use along with azimuthal LWD measurements to ensure laterals remain in-zone. Significance of Subject Matter: This paper documents the efficiencies being experienced by Eagle Ford operators using a holistic approach to completing and fracturing shale wells. Experienced on-site service coordinators are key to effectively bringing wells on line quicker and more safely with fewer lost time problems. Because of the success described in the paper the new approach will become common in shale plays outside of North America.
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Depth of Investigation and Depletion Behavior in Unconventional Reservoirs Using Fast Marching Methods (SPE 154532)
Authors A. Datta-gupta, M.J. King and J. XieThe concept of depth of investigation is fundamental to well test analysis. Much of current well test analysis relies on solutions based on homogeneous or layered reservoirs. Well test analysis in spatially heterogeneous reservoirs is complicated by the fact that GreenC"s function for heterogeneous reservoirs is difficult to obtain analytically. In this paper, we introduce a novel approach for computing the depth of investigation and pressure response in spatially heterogeneous and fractured reservoirs based on a semi-analytic construction of the GreenC"s function. In our approach, we first present an asymptotic solution of the diffusion equation in heterogeneous reservoirs. Considering terms of highest frequencies in the solution, we obtain two equations: the Eikonal equation that governs the propagation of a pressure C"frontC" and the transport equation that describes the pressure amplitude as a function of space and time. The Eikonal equation generalizes the depth of investigation for heterogeneous reservoirs and provides a convenient mechanism to construct the GreenC"s function. A major advantage of our approach is that the Eikonal equation can be solved very efficiently using a class of front tracking method called the Fast Marching Method. Thus, transient pressure response can be obtained in multimillion cell geologic models in seconds without resorting to reservoir simulators. We validate our approach by comparison with analytic solutions for homogeneous and composite reservoirs. We apply the technique using a high resolution full field geologic model of a tight gas reservoir from the Rocky Mountain region to predict the depth of investigation and pressure depletion. The computation is orders of magnitude faster than conventional simulation and provides a foundation for future work in reservoir characterization and field development optimization.
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Analysis of Surface and Downhole Microseismic Monitoring Coupled with Hydraulic Fracture Modeling in the Woodford Shale (SPE 154804)
Authors C. Neuhaus and J.L. MiskiminsThe work presented in this paper analyzes surface and downhole microseismic data for a horizontal well in the Woodford Shale in Oklahoma, comparing those results with calibrated hydraulic fracture modeling. Hydraulic fracture models were created for each of five stages with a three-dimensional modeling software, incorporating available petrophysical data in order to match the recorded treatment pressure and the fracture geometry obtained from the microseismic data. Further analysis investigated the congruency of the downhole and the surface microseismic data, what difference they produced in a match if used exclusively, the influence of the number of events on the fracture geometry obtained from the microseismic data, the error of event location, the degree of complexity of the created fracture network, and the relationship between the magnitude of events and the time and location of their occurrence. The fracture models produced good matches for both pressure and fracture geometry but showed problems matching the fracture height due to cross-stage fracturing into parts of the reservoir that were already stimulated in a previous stage. Surface and downhole microseismic data overlapped in certain regions and picked up on different things in others, giving a more complete picture of microseismic activity and fracture growth if used together. However, they deviated in terms of vertical event location with surface data showing more upward growth and downhole data showing more downward growth. In general, the downhole microseismic data showed that the stimulation treatment was successful in creating a fairly complex hydraulic fracture network for all stages, with microseismic recordings making flow paths visible governed by both paleo and present day stress. Plots showing the speed of event generation, the cumulative seismic moment, and the event magnitude versus the event-to-receiver-distance identified interaction with pre-existing fault structures during Stages III and V.
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Application of New Techniques for Characterization of an Eocene Carbonate Reservoir in the Gulf of Suez, Egypt (SPE 154461)
Authors M. Van Steene, E. Abdul Elaziz Bassim, S. Ghadiry, E. Haddad, S. Shaaban and V. VallegaA variety of recently developed techniques are available to improve carbonate rock characterization. This paper reviews the application of these techniques on an Eocene carbonate reservoir from the Gulf of Suez. Dolomite content was computed from spectroscopy data for direct extraction of the magnesium yield. This allowed computation of the dolomite volume while the photoelectric factor could not be used. Small amounts of dolomite were computed overall, with minimum impact of the dolomitization process over the porosity and permeability. Since rock texture has a strong impact on porosity and permeability in carbonates, it is necessary to include texture-sensitive tools in the evaluation. Based on NMR data, porosity partitioning analysis showed that the porosity is dominated by micro and meso pore sizes. While the default correlations used for NMR in carbonates considerably overestimate permeability, a modified SDR equation was applied to predict permeability more accurately, providing a good match to core data. Hydrocarbon properties have been found to vary vertically. NMR fluid identification stations were used to characterize the variation. Tar was identified based on the comparison of total porosity and NMR porosity. This is an important parameter as tar can affect the reservoir producibility. Fracture analysis was performed on a data set of micro-resistivity image and Stoneley data. The analysis performed on the Oil Based Mud micro-Imager identified the orientation of the fracture system and the sonic Stoneley wave processing determined that the majority of the fractures encountered in the reservoir were healed. This conclusion was supported by the core analysis results. The work presented in this paper demonstrates how it is necessary to integrate the measurements from various tools and sources to gain a good understanding of reservoir producibility in carbonates. The integrated evaluation was validated with core and well test results.
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Improving Well Cementing Quality with an Environmentally Preferred Multifunctional Polymer (SPE 154498)
Authors A. Brandl, W.S. Bray and C. MagelkyIn designing an optimum cementing system for zonal isolation of wellbores, an engineer generally has to combine several different cement additives to adjust the required and complex slurry properties, such as rheology, thickening time, stability, free fluid-, fluid loss-, and gas control. To minimize environmental impacts and incompatibility issues among various chemical admixtures as well as to simplify logistics and operations, it would be ideal to reduce the loadings and number of different additives required to optimize a cement slurry design. One way to accomplish this is to use multifunctional additives that can improve several slurry properties at the same time without significant detrimental effects on other required properties. Towards this end, a modified cellulose-based polymer has been tested according to API recommended practices in various cement slurries and was identified to have multiple benefits in addition to be environmentally friendly: The test results demonstrate that this single additive controls fluid loss better than commonly used fluid loss additives at temperatures up to 80(degree)C while also controlling free fluid and performing as an extender. In addition, it was found to work as a foam stabilizer and gas control agent in cement slurries, which was not observed for any other cellulose-based polymers. Furthermore, the new polymers retarding effect on thickening time is lower than for other cellulose-based polymers. Some forms of this modified cellulose-based polymer also exhibit delayed hydration, which facilitates surface mixing and pumping of the corresponding cement slurries. This paper will describe test procedures and demonstrate that a single modified cellulose-based polymer can replace several additives in a cement system to adjust the required cement slurry performances for optimum placement and properties in the wellbore. The presented multifunctional biopolymer simplifies cement slurry design and operations contributing to higher quality cement jobs.
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Reducing Surfacel Tension to Improve Clean Up Efficiency of Hydraulically Fractured Wells - Does it Really Work? (SPE 154894)
Authors P. Ghahri, M. Jamiolahmady and M.S. RamliThe main purpose of applying surfactants for hydraulically fractured wells is to reduce interfacial tension (IFT) during the leak off process. Much of the research up to now has been concentrated in developing different types of such chemicals. However, in a recent numerical study (SPE-14414), we have shown that for many practical ranges of fracture permeability reducing IFT tends to decrease the cleanup efficiency process. Following our previous study, we have conducted a comprehensive sensitivity study to identify the effect of IFT over a wide range of variation of pertinent parameters, which controls the cleanup efficiency process. We have looked at the impact of matrix permeability (km), fracture permeability (kf) and fracture fluid injection volume. Over 200 runs were performed to evaluate the impact of these pertinent parameters for a single fractured well model. The results indicate that at the early stage of production the cleanup efficiency is almost independent of IFT, km and kf and relatively poor. At late stages of production and when kf is low, reducing IFT decreases the efficiency of cleanup. For high kf values, on the other hand, cleanup efficiency improves with such a reduction. For the cases with km values more than 0.001, the cleanup is more effective if IFT increases. Furthermore as km decreases the damage due to fracture fluid blockage becomes more sever. It is interesting to note that when km is less than 0.0001, cleanup efficiency always decreases with IFT for all different kf values indicating the severity of fracture fluid damage for very tight gas reservoirs. Increasing the fracture fluid injection volume did not significantly change the above trend. The results presented here help the industry in properly evaluating the added value of using surfactant for the hydraulically fractured wells during cleanup process.
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Oilfield Scale Management in the Siri Asset - Paradigm Shift Due to the Use of Mixed PWRI / Seawater Injection (SPE 154534)
Authors E. Mackay, W.R. Ginty and T.J. JonesThere may be various drivers to implement Produced Water Re-Injection (PWRI). However, re-injecting produced water from the same field cannot replace the voidage created by production, especially early in the life of the field, since most of that voidage is created by hydrocarbon extraction. Thus seawater may have to be considered to C"top upC" PWRI. This raises the question of what are the implications for scale control of mixing potentially incompatible brines before injection, compared to the conventional injection scenario where the mixing takes place in the reservoir. A study was set up to consider scale management during the life cycle of four fields offshore Denmark. The available data included analysis of formation and produced water and seawater compositions, and the time evolution of the produced water C"" seawater split in the injection system. The tools used included thermodynamic scale prediction and reservoir simulation calculations. Thus the evolution of the scale risk over the entire water cycle C"" from injection, through the reservoir, to production could be evaluated. The produced water compositions and the results of the calculations show that the scale risk at the producers is much lower than if only seawater had been injected. Calculations were also performed to identify whether bullhead application of scale inhibitor would provide adequate protection for the wells. This was important, as some of the wells are subsea completions. The clear conclusion was that any residual scale risk at the producer wells could be managed by bullhead squeezing. However, the corollary is that the scale risk at the injectors is much higher. The trigger for scale precipitation in this scenario is brine mixing, but instead of that happening in the reservoir, here it occurs before injection. Thus the location of greatest scale risk is moved much further upstream in the flow process.
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Application of Integrated Production and Asset Modeling for Sour Field Development Planning (SPE 154073)
Authors A. Alkindi and S.J. LinthorstA challenging issue in the EP industry is Integrated Asset Management, which encompasses efforts from various disciplines to build a single integrated model that describes the whole system. This paper presents an integrated production model (IPM), forecasting workflow and decision making philosophy to develop two complex sour fields comprising three reservoirs in South of Oman. The study involves two sour oil reservoirs of different PVT properties, H2S concentrations and drive mechanisms and one sour gas condensate reservoir used to complement associated gas to give a constant gas rate for export. Water injection and water handling are parts of the model. The modeling couples subsurface dynamic 3D models (built using Shell's MoReS reservoir simulator), well models and surface network (built in GAP) and the interactions occuring in the production system. The configuration involves three reservoirs, 19 oil and 3 gas producers, 12 water injectors, one production station, two separators (low and high pressure) and several flow lines of different sizes. The main objective of the study is to optimize the developments of these reservoirs by assessing the best design of surface network (plant capacity). The integration allows to assess the impact of various station capacities; either liquid or/and gas, on the project profitability under different operational scenarios such as injection rate, off-take, artificial lift and well phasing and their impact on CAPEX and OPEX. The model also helps in identifying system bottle-necks, back pressure effects, mixing of fluids and flow assurance. The use of jet pumps as artificial lift mechanism was successfully imbedded and optimized. The paper describes the structure of modeling, surface components, optimization strategy, benefits and challenges of IPM deployment to choose the optimum field design. The results demonstrate the importance and merit of field management in addition to accuracy and rapidness of production forecast.
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Determination of the In-situ Polymer Viscosity from Fall-off Tests (SPE 154832)
Authors T. Clemens, A. Gringarten, A. Laoroongroj and M. ZechnerLaboratory experiments and simulations showed that for an Austrian oil reservoir, oil recovery can be significantly increased using polymers. One of the key design parameters for optimizing displacement efficiency while minimizing costs is the in-situ viscosity of the polymer solutions. Whereas the viscosity of polymer solutions can be measured at surface, the viscosity in the reservoir is difficult to estimate owing to the degradation of the polymers during the injection process. In addition, polymers exhibit Non-Newtonian behaviour resulting in different viscosities of the polymer solutions dependent on the shear rate in the reservoir. For the Austrian reservoir, water injection fall-off tests have been performed. With these tests, a simulation model was calibrated. The calibrated model was used to simulate injection of polymer solutions for some time followed by fall-off tests. The results show that conducting a base-line fall-off test prior to polymer injection and a set of fall-off tests during polymer injection can be used to determine the in-situ viscosity of polymer solutions and the distance of the polymer front from the injection well. Even for Non-Newtonian shear-thinning behaviour, the results show that the average polymer solution viscosity prior to shut-in of the well and location of the front can be determined with reasonable accuracy. Due to the costs of polymers, knowing the in-situ viscosity of polymer solutions is of paramount importance. The injection process can be modified (e.g. changing pumps, modifying perforations) if the degradation of the polymer viscosity is significant. Also, knowing the in-situ viscosity rather than estimating can be applied to tailor the polymer concentration to achieve stability of the displacement process and improve the displacement efficiency.
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Developing a Toolbox for Evaluating of Water Injection Performance on the Norne Field (SPE 154046)
Authors S. Atabay, O.M. Dronen, A.R. Fawke and J.M.F. HvidstenThe Norne Field is a mature oil field located on the Norwegian continental shelf in 380 meters water depth and it has been on production since November 1997. The reservoir drainage strategy in the oil zone has been WAG injection, followed by only water injection from 2007, and the pressure support is successfully achieved; however, the major challenge in this field is to optimize the vertical and areal sweep efficiency. Different methods and techniques have been applied to understand the current water injection strategy in order to optimize the macroscopic (vertical and areal) sweep efficiency: 1) Reviewing the historical well injection data. 2) Hall plot technique for evaluating the vertical sweep efficiency. 3) Tracer data to evaluate the areal sweep efficiency. 4) Spearman's rank correlation to investigate injection-production well relationships. 5) Full field and conceptual fine gridded simulation models. The major conclusions of these evaluations are: 1) The Hall plots can be used to better understand the water injection history and to make recommendations regarding which wells that should be logged (ILT/RST). 2) Spearman's rank correlation has been unsuccessful in finding injection-production well relationships. 3) The coarse full field model gives a reasonable prediction of drainage performance. 4) Conceptual simulation model indicates the vertical injection inflow profiles are of limited importance. Improving the field water injection strategy is important for maximizing the field recovery factor. In order to achieve this goal, several recommendations have been made for improving the current field water injection strategy.
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Optimization of Fluorinated Wettability Modifiers for Gas-condensate Carbonate Reservoirs (SPE 154522)
Authors J. Fahimpour, M. Jamiolahmady and M. SohrabiA significant reduction in well productivity of gas-condensate reservoirs occurs owing to reduced gas mobility due to the presence of liquid condensate/water phases around the wellbore. Fluorinated chemicals as wettability modifiers are capable of delivering a good level of oil and water repellency to the rock surface, make it intermediate gas-wet and alleviate such liquid impairments. The main objective of this experimental work has been to propose an effective chemical treatment process for carbonate rocks, which in comparison to sandstone rocks, suffer from lack of information in this area. Screening tests including contact angle measurements, spontaneous imbibition tests and compatibility tests with brine were performed mainly using anionic and nonionic fluorosurfactants. The anionic chemicals were sufficiently effective on positively charged carbonate surfaces to repel the liquid phase, whilst the nonionic chemicals showed an excellent stability in brine media. A new approach of combining anionic and nonionic chemical agents is proposed to benefit from these two positive features of an integrated chemical solution. A number of low and high permeable carbonate cores have successfully been treated by chemicals selected through thorough screening tests. Optimization of solvent composition and filtration of solution before injecting chemicals into the core proved very effective to reduce/eliminate the risk of possible permeability damage due to deposition of large chemical aggregates on the rock surface. The chemical solution optimized in this study can be applied as an efficient wettability modifier for mitigating the negative impact of condensate/water banking in carbonate gas-condensate reservoirs.
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Experimental and Numerical Investigation on the Performance of Gas-oil Gravity Drainage at Different Miscibility Conditions (SPE 154368)
Authors A. Ghasrodashti, R. Farajzadeh and V.S. SuicmezDescription Fractured reservoirs have been traditionally considered poor candidates for gas injection processes as highly conductive fractures rapidly transport the gas to the wellbore and consequently majority of oil in the matrix is bypassed. In fractured reservoirs, matrix recovery is achieved by interactions between matrix blocks and fractures. A comprehensive study of the controlling mechanisms (e.g. capillarity, gravity, phase behavior) can lead to optimized recovery. We describe a set of gas injection experiments conducted at different enrichment conditions(immiscible, near-miscible, and miscible) using CO2, nitrogen and flue gas. Moreover, we study the effect of block boundary conditions that are aligned with geological artifacts, e.g., horizontally-oriented impermeable shale layers on the recovery efficiency. A compositional numerical model is developed to simulate gas injection processes at different miscibility conditions. Application When the capillary-driven counter-current imbibition is hampered due to non-water-wetting nature of the reservoir, the injection of gas can be considered as an alternative for recovery from fractured reservoirs. Injection of a miscible gas improves the ultimate recovery, because the miscibility adds the advantage of single-phase flow and interfacial tension elimination. Moreover, injection of an immiscible gas before injecting the miscible gas can be considered to optimize the economics of the project. Results Results reveal that although ultimate oil recovery increases considerably once miscibility is reached, increasing the pressure postpones the oil recovery. This can be attributed to the lower density difference between gas in the fracture and oil in the matrix. The impermeable layer impairs the performance of the gas-oil gravity drainage process for immiscible gas injection, however, it improves the recoveries for miscible gas injection. Significance This study addresses important fluid exchange processes (gravity, mass diffusion and capillary diffusion) which occur between fracture and matrix block at various miscibility conditions.
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A Comprehensive EOR Study of a Highly Fractured Matured Field - Case Study (SPE 153311)
Authors D. Ghorbani and R. KharratMost of the Middle East fields are approaching their final stage of primary production. Most of these fields are highly fractured and carbonate in nature. One major problem is the creation of gas and water invaded zones during the history of production form such fields. Hence, the implementation of proper EOR process requires an extensive laboratory work. A mature field with more than six decays of production has been considered in this study to explore all possible EOR methods. Several EOR processes such as continuous gas injection (GI), WAG (water alternative gas flooding), SWAG (simultaneous WAG), FAWAG (surfactant WAG), and GAGD (Gas Assisted Gravity Drainage) process were studied in laboratory scale and simulation work. The Gas injection and GAGD were found to be unfeasible due the high fracture frequency and early gas breakthrough even with low rate of injection. However, the WAG, SWAG and FWAG were found to be more feasible. This is possibly due to mobility modification by water phase. During SWAG method all pores displaced at the same time, so that a higher ultimate recovery factor achieved sooner in comparison with WAG process. In order to have better exploration for the residual oil, FAWAG method was applied to control the injectivity of injected gas and reduce the interfacial tension (IFT) between residual oil and rock. Surfactant was chosen in different concentration of 5000, 2000, 1000, 500ppm of surfactant. All experiments were carried out under reservoir condition. The FAWAG process was found to be more suitable process for such reservoirs due to its high recovery. Finally the simulation study was conducted with different patterns of injection and production for all the mentioned EOR scenarios. It was found that the fractures density had an important role in the selection of the optimum pattern.
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Foam-Oil Interaction in Porous Media - Implications for Foam-assisted Enhanced Oil Recovery (SPE 154197)
Authors R. Farajzadeh, A. Andrianov, R. Krastev, W.R. Rossen and G.J. HirasakiA problem associated with many gas injection projects is the inefficient gas utilization, poor sweep efficiency, oil recovery due to viscous instabilities (channelling or fingering), and gravity segregation. The above mentioned effects are caused by rock heterogeneity and the low density and viscosity of the injected gas. Foam, which is created by co-injection of surfactant solution and gas, or by SAG (Surfactant-Alternating-Gas), can be injected into oil reservoir to mitigate these drawbacks. When foam films are created in-situ, the flow of gas is hindered and gas can sweep portions of the reservoir that would not been reached in the absence of foam. Potentially foam injection can lead to better pore, aerial, and vertical sweep efficiencies. The efficiency of the displacement process in a foam assisted gas flood depends largely on the longevity of the created foam films, ratio of films destabilization and re-generation rates. Experimental results have demonstrated that oil can have a detrimental impact on foam stability. This paper summarizes experimental and theoretical results on the effect of oil on foam stability both in bulk and porous media. The relevant mechanisms of foam (in)stability in the presence of oil and destruction by oil such as disjoining pressure, coalescence and drainage, entering and spreading of oil, oil emulsification, snap-off, etc. are critically reviewed. Moreover, we describe the existing approaches to foam modeling in porous media and the ways these models represent the effect of oil on foam propagation in porous media. Finally, ways to improve foam stability in the presence of oil are discussed.
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Capillary Pressure - Is it Critical for Investment Decisions? Case study of Gas Condensate Reservoir Underlain with Water (SPE 154469)
Authors M. Fayzullin, A. Nasibullin, A. Yazkov and S. KolbikovThe paper highlights the importance of adequate characterization of capillary pressure effects when preparing a development plan for a greenfield gas condensate reservoir with a large transition zone (TZ). Capillary pressure data from centrifuge or porous plate (semi-permeable membrane) are used to characterise the transition zone. It is essential that a representative set of sample measurements is obtained. Core laboratories are not capable to keep initial pressure-temperature conditions during capillary pressure measurements. Hence, the conversion from surface to reservoir becomes uncertain. Conversion utilizes interfacial tension and wettability angle which are quite unknown and can be predicted using different P-T charts. Finally saturation model depends on the way of: characterization - discrete Rock Types (RT) or tuned-up Continuous Functions (Leverett, Amaefule etc.); matching log saturation profile with the one observed in the model; welltest playback in terms of mobile water and drained volumes.
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New Insight Into CO2 Injection and Storage in Saline Aquifers (SPE 154527)
Authors M. Sohrabi, C. Bernstone, M. Jamiolahmady, M. Riazi and S. IrelandWorldwide, significant efforts and resources are being directed at evaluating potentials of CCS (carbon capture and storage) for the long term storage of large quantities of CO2 that would otherwise be released in the atmosphere. Despite many years of experience with CO2 injection in oil reservoirs, our current understanding of brine/CO2 interdictions that occur during CO2 injection in aquifers (brine-bearing rocks) remains very limited. This is a source of uncertainty and concern not just for the governments and companies interested in investment in CCS (carbon capture and storage) but also for the public in relation to the safety of the long term injection and storage of CO2 in these formations. In this paper we report new insights into the pore-scale interactions between CO2 and brine obtained from the results of a series of CO2 injection visualisation experiments carried out in novel high-pressure transparent porous media. In these experiments we have physically simulated and visually investigated the behaviour of CO2 in brine-bearing porous media. We demonstrate key mechanisms affecting CO2 transport, trapping and its dissolution in the resident brine. In particular, through vivid images of fluids distribution taken during the experiments, we highlight a new mechanism in which CO2 evolution follows CO2 dissolution. In parts of the porous medium in which CO2 injection was taking place, it was observed that a free phase of CO2 nucleated and came out of solution and gradually expanded. The phenomenon accelerated when the brine salinity increased or when the CO2 injection rate increased. The observed mechanism is expected to affect many important aspects of CO2 flow and retention in porous media. It may increase CO2 storage capacity by displacing more brine. On the other hand, it can seriously and adversely affect the ability of rock to contain the stored CO2.
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Sorption of CO2 in Shales Using the Manometric Set-up (SPE 154725)
Authors R. Khosrokhavar, W.R. Rossen, S.E.J. Rudolph-Floter and C. BerentsenDescription The storage capacity of gas reservoirs for CO2 depends not only on its dissolution in brine but also on the sorption in the omnipresent minerals and shales. It can be expected that the sorption characteristics depend on the composition of the shales. This implies that measurements on shales of various compositions are required to estimate the sorption in practice. The sample of our choice is a Black Shale from Belgium. The procedure is as follows: the sample has been sieved and granulized to a size of 40-220 (lower case mu) m. we determined the mineral composition and elemental composition using XRD and XRF. We use the manometric set-up to obtain the sorption data. The equilibration time is about 40 hours for our granulized sample. The excess sorption isotherms was measured at a constant temperature of 318 K, up to a pressure of 1.8 MPa. These conditions are representative of typical European reservoirs. Our measurements are compared with existing data in the literature on sorption of CO2 on minerals. Applications To determine the effective storage capacity of CO2 in geological formations, e.g. abandoned gas reservoirs Results, Observations, Conclusions: -Preliminary experiments show that it is indeed possible to use the manometric set-up to determine the adsorption rate of CO2 on clays. -Accurate determination of the sorption rate requires an accurate equation of state, e.g., the Span-Wagner EOS. -The measured equilibrium time of CO2 on shale is of the order of tens of hours -The first two sorption points are 0.132648 and 0.169854 mmol CO2/ gsample for Black shale. Significance We propose the manometric set-up as a simple and straightforward measurement procedure for obtaining kinetic data of CO2 sorption in shale. The data are essential to quantify CO2 sequestration in gas fields .
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Wettability Determination by Equilibrium Contact Angle Measurements Reservoir Rock - Connate Water System with Injection of CO2 (SPE 154382)
Authors N. Shojai Kaveh, W.R. Rossen, S.E.J. Rudolph-Floter and C. BerentsenCarbon dioxide (CO2) injection into depleted gas reservoirs serves dual purposes: to enhance gas recovery and to store CO2. This process is largely controlled by the interactions among CO2, the reservoir fluid and rock. In particular, the wettability of the rock matrix has a strong effect on the distribution of CO2 injected in geological formation for sequestration. The rock wettability is determined by the three equilibrium interfacial tensions between the CO2, the connate water and the rock surface, which is one of the controlling parameters of the remaining fluid saturations, capillary pressure and relative permeability; hence conditioning the performance of any CO2 operation. In this study, the wetting behavior of CO2 on a Bentheimer sandstone surface in presence of synthetic connate water was investigated by means of visual contact-angle measurements. The experiments were conducted in a modified pendant drop cell at constant temperature of 318 K and pressures varying between 0.1- 16 MPa, typical in-situ conditions. This study shows that at a given temperature and pressure the dynamic contact angle increases over time to an equilibrium value. This equilibrium contact angle between the CO2/ water interface and the rock surface increases with pressure at constant temperature, indicating the rock surface becomes intermediate wet. In the range of pressure and salinity examined in this work, the system changes from strongly water-wet to intermediate wet. The system, however, does not become completely gas wet. Wetting behavior is very important for the design of an efficient CO2 storage process. Specifically, the alteration of the wettability of the rock in depleted gas reservoirs from strongly water-wet to intermediate or gas-wet changes the efficiency of the CO2 storage, because CO2 can imbibe into the rock matrix but also water banking might occur.
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Affecting Parameters on Density Driven Convection Mixing in CO2 Storage in Brine (SPE 154901)
Authors M. Soroush, J. Kleppe, A. Taheri, O. Torsaeter and D. Wessel-BergAfter injecting CO2 into the brine for storage, it will be trapped into the reservoir through various mechanisms. In the beginning, geological trapping mechanism dominates and CO2 plume moving upward below a cap rock. Then brine will imbibe the formation and some parts of the gas will be trapped in the pore paces. Later on injected CO2 will dissolve in the brine and increases its density. As a result, the heavy brine will move into deeper parts of the reservoir and density driven convection mixing will occur. This called solubility trapping mechanism. Here in this study, density driven phenomena in CO2 storage in brine and influencing parameters is the prime target. We find particularly interesting results for this through some helle-shaw cell experiments and numerical simulations. Hele-shaw flow is defined as stokes flow between two parallel flat plates separated by an infinitesimally small gap. In each experiment cell filled with fresh water and a shim prevents it to leak. Then liquid with higher density placed on top. Camera set for time sequences between automatic picturing to visualize the process. Couple of tests including different salinity of top fluid and different dip angles carried and the results interpreted separately and compared with the base experiment too. A numerical simulation model constructed based on the laboratory test with the same geometry and conditions. The results from the simulation matched to the experiment to be sure that the model is re-presenting the experiment. Then more extensive studies and sensitivity analysis carried on simulation model with wide range of effecting parameters, including density differences, ranges of pressures and temperatures, dip angles, permeability variations and effect of diffusion. Based on the result, we planned some modification and improvement to our experiment setup to target more findings.
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Evaluation of the CO2 Storage Capacity of the Captain Sandstone Formation (SPE 154539)
Authors E. Mackay, M. Akhurst, K. Hitchen, M. Jin and M. QuinnThe volume of CO2 that can be stored in the Captain Sandstone formation in the North Sea was investigated by building a geological model and performing numerical simulations. These simulations were also used to calculate the best position for the injection wells, and the migration and ultimate fate of the CO2. The overall migration of CO2 and the pressure response over the entire formation was studied by the calculated injection of 15 million tonnes CO2 per year. The injection rate was restricted to a maximum of 2.5 million tonnes CO2 per year for each of a possible 15 wells considered. An important objective was to predict how to avoid flow of the injected CO2 toward potential leakage points, such as the sandstone boundaries and faults. The migration of injected CO2 towards existing oil and gas fields was also a determining factor. The summary conclusions are: - The Captain Sandstone formation has significant potential CO2 storage capacity. Even with all boundaries closed to flow, the probable storage capacity is calculated to be about 358 million tonnes, giving a storage efficiency of 0.6% of pore volume, with an expected operating life-span of 15-25 years. - The possible storage capacity of the formation may be at least four times greater if the aquifer boundaries are open. This increase would be a result of displacement of salt water, and not CO2. - The storage capacity if the sandstone is closed to flow may be increase from 358 to 1668 million tonnes of CO2 by significant additional investment in 15 to 20 water production wells. - Injection of up to 2.5 million tonnes CO2 per year in one well has an impact on the pressure throughout the entire formation, and thus interference between different injection locations must be considered.
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A Proposed Workflow for Disposal of CO2 using CO2 Hydrate (SPE 154445)
By J. RajnauthCarbon dioxide is an important greenhouse gas because it transmits visible light but absorbs strongly in the infrared. Carbon dioxide is mainly generated from the combustion of fossil fuels or vegetable matter, among other industrial processes such as cement production and ammonia plants. CO2 emitted from burning fossil fuels is believed to be a major contributor to the amount of CO2 levels in the atmosphere contributing to global warming. Hydrate technology can be used to capture CO2 gas in the form of hydrates. In this technology CO2 and water are combined at certain conditions of temperatures and pressures to form of a hydrate, and then transported and released at great depths into the ocean. Disposal of CO2 in the form of hydrates in the sea is a great potential as the ocean is vast and occupies 70% of the earthC"s surface. Numerous power plants and petrochemical plants are located near the coastline and hence there is easy access to the ocean. The CO2 hydrate formation as a CO2 disposal method may potentially offer significant savings in CO2 disposal because of minimal cost of CO2 capture. This paper proposes a work flow for disposing of CO2. The model describes the sequence of operations for CO2 capture and disposal using CO2 hydrate. A typical example would be used to describe the workflow from CO2 emitted to CO2 hydrate disposal. CO2 hydrate is denser than seawater and therefore CO2 hydrate deposited in the ocean will sink to the seabed as long as the disposal site is within the hydrate formation envelope.
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Influence of Capillary Pressure on Phase Equilibrium of Mixed CO2-water Injection into Geothermal Reservoirs Incl. Phase Appearance & Disappearance (SPE 153886)
Authors H. Salimi, J. Bruining and K.H. WolfIn this article, the capillary pressure effect on the phase equilibrium of the CO2-water system is quantified. Our interest is in the capillary-pressure range between 0 and 100 bars for temperatures between 293 K and 358 K and pressures between 185 and 255 bars. For this purpose, we have implemented the capillary pressure effect in the PRSV equation of state. This makes it possible to determine the capillary-pressure effect on the CO2 storage capacity and energy recovery for CO2-water injection into geothermal reservoirs. We illustrate the process using a 2D model of the geothermal reservoir in the Delft Sandstone Member below the city of Delft (The Netherlands). Improved screening of injection conditions for optimal geothermal recovery and/or maximal CO2 storage. C"B" Capillary pressure reduces the CO2 solubility in water by less than 20%, whereas it increases the water solubility in the CO2-rich phase by less than 50%; C"B" Inclusion of the capillary pressure effect on the phase behavior does not significantly alter the capillary CO2-trapping mechanism (i.e., CO2 banks are mainly formed in highly permeable zones that are surrounded by less permeable zones), also heterogeneity still considerably weakens gravity effects; C"B" The frequent occurrence of evaporation and condensation, which is particularly effective close to the bubble point, substantially delays CO2 breakthrough and leads to a larger amount of useful-energy production and CO2 storage. C"B" However, for injected CO2 concentrations close to the bubble point, the effect of capillary pressure on the phase equilibrium can reduce both heat extraction and CO2 storage by 37%; for concentrations between 4% and 13%, the reduction is 10%. C"B" Based on simulations, we construct a plot of the recuperated useful energy versus the maximally stored CO2 for a variety of conditions including the capillary-pressure effect on phase behavior.
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Comparison of Upscaling Methods in a Heterogeneous Carbonate Model (SPE 154499)
Authors G.E. Pickup, P.W.M. Corbett, A. Kazemi and D.S. ShaikhinaCarbonate reservoirs are of great importance, due to their large hydrocarbon reserves. However, their complex structure makes them challenging targets to develop. In order to predict reservoir performance, we need to be able to model the effects of heterogeneity at a variety of scales. In this study, we have constructed a detailed geological model using published data for an outcrop of the San Andres Formation. The resolution of the model is 1.2 m x 0.6 m, much finer than a conventional reservoir simulation model. The aim of this work was to determine if we could develop a feasible approach to upscale the model. A number of single-phase upscaling methods were tested, including averaging (arithmetic/harmonic), and flow-based upscaling with local and extended boundary conditions. In addition the Well Drive Upscaling (WDU) method, a relatively new method, was applied. In this method a single-phase global simulation is performed with appropriate boundary conditions: high pressure at injection wells, low pressure at producers. The flows are then summed and the pressures averaged in order to calculate the effective transmissibilities between the coarse cells. The upscaling methods were tested by simulating a waterflood. Cases with single and multiple relative permeabilities were examined. The upscaling factor in each case was 65 by 5. In general, the coarse-scale models gave late breakthrough, and overestimated the recovery. The WDU method was consistently better than the other methods, because it was able to preserve the correct flow between coarse cells. On the contrary, the conventional flow-based methods with local boundary conditions gave poor results, sometimes worse than averaging. These results show that upscaling in a complex carbonate reservoir is feasible, providing a suitable method, such as the WDU method, is applied.
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Static and Dynamic Assessment of DFN Permeability Upscaling (SPE 154369)
Authors M.A. Elfeel and S. GeigerNearly half of the remaining petroleum reserves are contained in naturally fractured reservoirs (NFR). An accurate estimate of the effective fracture permeability tensor is a key to the successful prediction of oil recovery from NFR. Standard workflows nowadays employ discrete fracture network (DFN) modelling and analytical or flow-based methods to upscale fracture permeabilities. However, DFN modelling imposes some important challenges, which can cause great uncertainty in the effective permeability tensor and subsequent recovery prediction: Analytical upscaling methods, which are commonly used due to computational efficiency, are inaccurate for poorly connected fracture networks. Flow-based upscaling methods depend on boundary conditions and are computationally expensive. Defining the optimum grid size for either method is also very difficult. In addition, DFN upscaling is often driven by practical issues such as time constrains and computational limitations, leaving little room to investigate the effects of upscaling methods and grid size. In this paper we compare the performance of three different DFN simulators used in standard industry workflows for computing effective permeability tensors with flow-based and analytical methods. We use a dataset from a fractured formation of an on-shore reservoir in our assessment. Not surprisingly, there is up to three orders of magnitude variation in the effective permeability based on the chosen upscaling method and perceived optimum grid cell size. Quality control with streamline calculations provides no robust assessment of the best upscaling method. We hence introduce a new simulation technique, Discrete Fracture and Matrix (DFM) modelling, which accounts accurately for flow in the fractures and rock matrix as a robust. It is an efficient alternative for computing effective permeability tensors or assessing the accuracy of classical DFN upscaling approaches, which all help reducing uncertainty in recovery prediction.
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A Versatile Representation of Upscaled Relative Permeability for Field Applications (SPE 154487)
Authors F. Lomeland, E. Ebeltoft and B. HasanovA suitable approach to achieve a fit-for-purpose model for field application is upscaling of reservoir properties. However, upscaling of saturation functions like relative permeability is still a source of debate and is frequently omitted due to its inconvenient complexity. Upscaling of these functions, whether by steady-state methods or other techniques, typically generates a complex myriad of relative permeability curves that is challenging to handle pragmatically. This study investigates whether a three-parameter correlation of relative permeability is able to represent the saturation function for fine grid simulation models with the most common heterogeneities, coarse grid simulation models with upscaled properties in addition to verify two-phase core-flow experiments. To demonstrate the applicability of two flexible three-parameter correlations at the field simulation scale, we have utilized three synthetic fine-scale models with the most common heterogeneities: a severe thief zone, upward coarsening and downward coarsening. All simulation cases use a down-dip water injector and an up-dip oil producer. Excellent matches are obtained by history matching on the parameters of the coarse grid correlations in all cases. The flexibility of the correlations will, opposed to the restricted single-parameter Corey representation, enable a versatile, pragmatic and satisfactory upscaling for coarse grid blocks when used in combination with any well-known upscaling method. The benefit is a limited number of parameter arrays as opposed to numerous rather inconvenient tables. The proposed parametric representation of upscaled relative permeability is applicable to immiscible recovery methods in general. Implementation of the proposed three-parameter correlations of the relative permeability in the algorithm of full field simulators will overcome the representation challenges of present published upscaling methods. Upscaling of each coarse grid block individually can then be handled pragmatically, and hence provide fit-for-purpose models for field application.
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Dynamic Capillary Pressure Curves from Pore-scale Modelling in Mixed-wet Rock Images (SPE 154474)
Authors Y. Zhou and J.O. HellandIn several reservoir multiphase flow processes, such as fracture and near well-bore flow, both viscous and capillary forces determine the pore-scale fluid configurations due to high flow rates. This gives rise to significant dynamic effects in the capillary pressure relation because the fluids are redistributed faster than the relaxation time required for transitions between capillary-equilibrium states. We simulate quasi-static and dynamic capillary pressure curves for drainage and imbibition directly in SEM images of Bentheim sandstone at mixed-wet conditions by treating the identified pore spaces as tube cross-sections. Stepwise pressure differences are imposed between inlet and outlet. The phase pressures vary with length positions but remain unique in each cross-section, which leads to a nonlinear system of equations that are solved for interface positions as a function of time. The cross-sectional fluid configurations are computed accurately at any capillary pressure and wetting condition by combining free energy minimisation with a menisci-determining procedure that identifies the intersections of two circles moving in opposite directions along the pore boundary. Circle rotation at pinned contact lines accounts for mixed-wet conditions. Dynamic capillary pressure is calculated using volume-averaged phase pressures, and dynamic capillary coefficients are obtained from the rates of saturation change. The results could be applied in reservoir simulation models to assess dynamic pore-scale effects on the Darcy scale. Consistent with measurements, our results demonstrates that dynamic capillary pressure is higher than the static capillary pressure during drainage, but lower during imbibition. The dynamic capillary coefficients and rates of saturation change during imbibition depend strongly on wettability and initial water saturation. The proposed model provides insights into the extent of dynamic effects in capillary pressure curves for realistic mixed-wet pore spaces, which contributes to improved interpretation of core-scale experiments.
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Data-driven Monte Carlo Simulations in Estimating the Stimulated Reservoir Volume (SRV) by Hydraulic Fracturing Treatments (SPE 154537)
More LessHydraulic fracturing treatment has been proven to be the key factor for shale gas to flow at economic rate. Micro-seismic mapping has shown the extreme complexity of the hydraulic fracture network after the stimulation due to the geological complexity of shale formations. It becomes vitally important to understand the impact of the hydraulic fracture treatment, especially the massive multistage, multi-cluster hydraulic fracturing stimulations, to optimize stimulation and development plans of shale gas reservoirs. Recent advances in micro-seismic mapping enable realistic modeling of hydraulic fracture network, though with significant uncertainty. Consequently, it is possible, to certain extent, to represent actual large-scale fracture distribution in reservoir modeling and simulation of shale gas development. In this paper, we propose a simulation method that is able to generate highly likely realizations of fracture network based on micro-seismic data, taking into account of data and shale formation uncertainty. The simulated realizations are then used to construct highly constrained unstructured gridding and a connection list of all neighboring cells (SPE 143590), using the Discrete Fracture Modeling (DFM) approach. DFM enables the prediction of production yield curve. With real production data, statistical analysis is done to calibrate and refine the simulation attributes. Based on a well calibrated simulation system, and linking initial hydraulic stimulation, induced fracture network and production data, we predict future stimulated reservoir volume and production yield curve, hence enabling the optimization of stimulation and development. The proposed approach is extremely computational intensive. Approximations, efficient implementation and parallelization are used to make the approach practical. The approach was tested with success on real field experiments and data and the numerical results have shown great potential of the proposed approach to better understand the impact of hydraulic fracturing treatment.
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A Comparative Studies and a Sensitivity Analysis for a Heavy-oil Reservoir in GCC Region (SPE 152692)
More LessIn this study we are continuing our previous work to investigate the best development options for a major heavy oil reservoir in GCC region. In the early stage of this work the most applicable EOR methods were selected, and then several simulation runs were conducted to investigate different injection scenarios and ranked them based on their recovery factor (RF). In this stage of the study, using a compositional & thermal simulation, a comparative studies and a sensitivity analysis of various operational conditions and reservoir parameters were conducted in order to find the optimum conditions for a high RF and to predict the effect of reservoir heterogeneity on the reservoir performance. The factors concerned (operational conditions) were the injected fluid type, injection rate, injection location, injection swapping time, oil production rates and pressures. On the other hand, the reservoir parameters such as oil viscosity, initial water saturation, porosity and permeability were considered. In addition to this, the oil price sensitivity was considered to evaluate the financial feasibility of the selected recovery methods within a historical and forecasted oil price range. The preliminary results show that the RF is very sensitive to the oil viscosity value and the relation between them is nonlinear relation. The Simulation results also indicate that the increase in the porosity and permeability accelerates performance however the opposite is extremely true for the initial water saturation value. From an economic viewpoint, production acceleration would improve overall project economics by mitigating the negative impact of discounting on the revenue stream due to the low oil price. From the economic side, all successive scenarios approve a successful investment at the lowest (expected) oil price, in contrast, the continuous steam and hot-water flooding development options are showing a high economic risk after the second year.
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The Adaptive Well Log Data Interpretation in Geological Modeling (SPE 152463)
Authors I.S. Deshenenkov, K. Kovalenko and D. KozhevnikovWide spread application of 3D geological modeling, oil and gas field development practices resulted in substantiation of the necessity for transition from the traditional concept of "absolute pore volume" to the concept of "effective pore volume". This could be achieved with the geophysical and logging data algorithms interpretation and procedures system directed to the determination of reservoirs dynamic characteristics with high vertical resolution united with principles of adaptability and petrophysical invariance of reservoirs. The adaptive log data interpretation technology provides analytical relations between log interpretative parameters and reservoir rocks properties in the generalized form. Proposed interpretative algorithms are implemented in the geological modeling software package and combined with standard geological modeling procedures to develop the three-dimensional distribution of reservoir properties. Adaptive petrophysical models make possible the quantitative estimation of effective porosity and effective/phase/relative permeability. Formation parameters, which characterize the content of bound water in the matrix and cement, maximum possible total porosity and effective porosity, relations between effective porosity and effective permeability are estimated according to outcomes of petrophysical modeling. Effective porosity is calculated with the standard logs data interpretation. The distribution of reservoir properties in three-dimensional space is carried out with geostatistical simulation techniques. Application of effective porosity to prediction of relative permeability and capillary pressures with log data was realized as an important task for field development design. The test of the proposed technology is conducted on a large number of wells worldwide (Western & Eastern Siberia, Caspian region, Middle East, Alaska, etc.). Formations consist of clastic fine-grained sandstones with cement and matrix complex mineral composition. Application of proposed technology in geological modeling software packages represents an innovative direction of geological information technologies. It does not require any special capital expenditure with a significant economy of forces and operational time.
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Development of an Integrated Evaluation Methodology on Scale Management Pre- and Post-production - An Engineer's Perspective (SPE 154844)
Authors O. Akuanyionwu and F. WahidScale formation can have a detrimental impact on production if left unchecked. Similarly, scale management can be costly without proper evaluation and planning. Developing a cost- effective scale management strategy during field development planning phase is imperative to assist decision making. Furthermore the strategy must address the procedures to explicitly assess the well and field performance during production, to optimize the production over the field life. In the past, the assessment of potential for scale formation was performed based on static scaling risk assessment method, which relied solely on the output from static thermodynamic scale prediction models. In this document, we introduce a systematic methodology to assess the scale formation risk as time dependent by coupling dynamic modeling with static scaling risk assessments; where streamline simulation technique has been used to predict scale precipitation in the reservoir and the consequent in-situ stripping of scaling ions. Extending the use of the dynamic simulation tools to assess the scaling risks in reservoir and near wellbore will assist in field development planning, development, as well as production operation, monitoring and optimization. Workflows developed on a North Sea field development (pre- and post-production) are described, including results from analog/synthetic datasets as examples. Our work indicates that both in-situ ion stripping and drainage patterns significantly influence chemical requirements and treatment frequencies for squeeze treatments following in-situ scale deposition. It also shows from a historical perspective how scale has impacted production in analogue wells and more importantly to characterize the location of the precipating scale. Finally, we highlight limitations in current industry tools and workflows, and what can be done to reduce uncertainties during the development of a scale management strategy.
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Predicting Water in the Crest of a Giant Gas Field - Ormen Lange Hydrodynamic Aquifer Model (SPE 153507)
Authors M. Boya Ferrero, J. Hognestad and S.P. PriceThe hydrodynamic aquifer in the Norwegian Ormen Lange gas field has been assessed using isopotential mapping and dynamic simulation of the fluid-fill over geological time. These models correctly predicted the results of a 2011 appraisal well. The Ormen Lange gas field (8*40 km) is located in 700-1100m water depth with the main reservoir unit formed by a Paleocene submarine fan. The field, producing since 2007, was initially assumed to be a combined stratigraphic-structural trap with the gas-water contact delineated by a seismic DHI. A crestal 2008 appraisal well in the northern part of the field encountered only residual gas saturations in the middle of the DHI, leading to a re-appraisal of the charge history. Three subsequent appraisal wells have confirmed elevated contacts, residual gas, and pressure communication across the field. Three alternative models (breached, perched water and hydrodynamic aquifer) have been investigated to explain these observations. A phased hydrodynamic aquifer model is consistent with both field data and the basin history, where hydrodynamic flux is created by compaction of basinal shales. The aquifer has displaced the gas from the crest of the structure into the south giving a northward-thickening prism of residual gas, the base of which is imaged by a seismic DHI. Hydrodynamic aquifer conditions can result in a stepping FWL in a field, where structure does not justify perched water and without invoking the presence of sealing faults. Phased hydrodynamic conditions can lead to the presence of residual hydrocarbons beneath tilted contacts, even within stratigraphic traps with restricted aquifers. An understanding of basin hydrodynamics is critical for the correct exploration, appraisal and field development strategy and may challenge assumptions on contacts, volumes, fault-seal analysis and interpretations of DHIs and residual gas. Isopotential mapping and hydrodynamic simulation have considerable predictive power.
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Coupled Static / Dynamic Modeling for Improved Uncertainty Handling (SPE 154400)
Authors M.P. Kaleta, R. Bennett, J. Brint, P. Van Den Hoek, J. Van Doren, G. Van Essen, T.J. Woodhead and B.W.H. Van BeestIn the petroleum industry history-matched reservoir models are used to aid the field development decision-making process. Traditionally, models have been history-matched by reservoir engineers in the dynamic domain only. Ideally, if any changes are required to static parameters as result of history matching the dynamic model, then these should be reflected directly in the static reservoir model. This permits consistency between the static and dynamic domain. In addition, static model uncertainties are often not evaluated in the dynamic domain, which could result in the detailed modeling of geological features that have no impact on the dynamic behavior and the resulting development decision. This paper demonstrates a workflow where the reservoir simulator and static modeling package are closely linked to promote a more integrated approach and to enhance the interaction between the subsurface disciplines. Using either the simulator or the static modeling package as the platform, the output of the workflow is a sensitivity analysis of the uncertainties related to structure, rock properties, fluids and rock-fluid interactions. Next, computer-assisted history matching methods (i.e. adjoint-based and Design of Experiments) are used to find the parameter values that result in a successful history match. The workflow will be demonstrated both on a synthetic model and on a reservoir model from a real field case. This methodology results in history-matched models and a better understanding of the static and dynamic subsurface uncertainties, leading to more informed decision-making. The method presented here can significantly enhance the awareness of the impact of both static and dynamic subsurface uncertainties on development decisions. In addition, it offers a platform where all subsurface professionals can more optimally combine their efforts to improve the integrated understanding of reservoirs.
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Multi-phase Well Testing to Calibrate Relative Permeability Measurements for Reservoir Simulation (SPE 154851)
Authors A. Green, A.C. Gringarten and T.M. WhittleSpecial core analysis (SCAL) is the standard method for estimating relative permeabilities. These, however, must be upscaled for reservoir simulation and the upscaling process creates uncertainties that are propagated to field performance forecasts. This paper describes a six-stage well testing procedure to calibrate relative permeabilities for reservoir simulation and to reduce uncertainties in relative permeability end points and curvature. The well test includes: (1) single phase oil production; (2) build up; (3) single phase water injection; (4) falloff; (5) two-phase oil and water production; and (6) a final build up. The final build up is initiated at minimum well productivity. Transient pressure analyses of the first build up (2) and the fall off (4) provide the single phase mobility for each fluid at respective saturation end points. These yield an estimate for endpoint water relative permeability using a Corey type relative permeability correlation. Analysis of the second build up (6), on the other hand, yields an estimate of the minimum mobility. Uncertainty in oil and water relative permeability curvature (which depends on Corey exponents) is reduced using all three mobility estimates, while uncertainty in end point saturations can be reduced by running wireline logs at the onset of the test and of the following injection. The procedure is demonstrated by simulating a newly drilled well in an oil-water homogeneous reservoir above the bubble point pressure. The impact of relative permeabilities on water breakthrough and and oil production is shown to be significant in such an oil field developed by water flood. Sensitivities to reservoir heterogeneity, water cut during the flow back period, numerical dispersion, and capillary pressure have also been explored. Information provided by the proposed test and interpretation procedure allows improved field development decisions early in field life.
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Use of Water Chemistry Data in History Matching of a Reservoir Model (SPE 154471)
Authors D. Arnold, M.A. Christie, V. Demyanov and O. VazquezProduced Water Chemistry has been included in the history matching of reservoir simulations. Generally, in conventional history matching, the water chemistry is not considered as an extra constraint. The chemistry of the different types of water in a reservoir, such as aquifer, connate and seawater is very different, and can be traceable. Produced Water Chemistry is the main source of information to monitor scale precipitation in oil field operations. The objective of this paper is to evaluate the effect of adding produced water chemistry information as an extra constraint history matching a modified version of the PUNQ-S3 reservoir model. The PUNQ-S3 model is a synthetic benchmark case that has been used previously for history matching uncertainty quantification. Conventional historical production data (gas, oil rate and pressure) from six production wells are supported by the water chemistry tracer data from the wells that produce water in the history period. The different types of water are traced through their distinctive chemistries, namely aquifer, connate (formation) and sea (injection) water. Geological model is matched by varying porosity and permeability, both horizontal (kh) and vertical (kv) according to the prior beliefs about the reservoir geology (layering, spatial correlation and anisotropy). Two history matching scenarios are considered: including and not-including the Produced Water Chemistry (PWC) as extra matching constraints. Stochastic Particle Swarm Optimization (PSO) algorithm is used to generate ensembles of history matched models, which characterise the uncertainty of the reservoir prediction. The confidence intervals for the forecast are computed using NA-Bayes (Neighborhood Algorithm) technique, which evaluates the posterior probability of the generated models. Finally, to evaluate the effect of adding PWC in the history matching, the Bayesian confidence intervals (P10-P50-P90) generated by each method were compared.
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Integrated Interpretation for Pressure Transient Tests in Discretely Fractured Reservoirs (SPE 154531)
Authors K. Morton, R. Booth, F.J. Kuchuk and P. De Brito NogueiraIn 2005, Petrobras discovered a fractured Albian carbonate reservoir in Campos Basin. During the evaluation of an appraisal well, a full sequence of well tests (DSTs) and a 4-month extended well test (EWT) were performed to monitor reservoir behavior and to define the most probable geological reservoir model before the final development decision was made. While the results of the well test sequence were sufficiently favorable for development, the well test analysis raised concerns about the quantitative use of these tests for reservoir characterization. The seismic sections of the field indicated faulting, and open fractures were interpreted from image logs in the appraisal wells. However, the response of the DSTs and EWT did not indicate classical dual porosity type behavior that is consistent with an extensive connected fracture network system. The fractures in this reservoir are considered to be predominantly open in one direction only. Few methods exist for the interpretation of the pressure transient response of discretely fractured reservoirs where fractures provide conduits for fluid flow and displacement, but where the fracture network is poorly connected compared to dual porosity models. In this paper, we first outline the gaps in the existing pressure transient well test interpretation methodology for these reservoirs, then we introduce two new techniques developed to address these gaps: 1) A reservoir model-based inversion technique for parameter estimation from pressure transient data, and 2) A boundary element method for determining the pressure transient behavior of the reservoir with arbitrarily distributed finite and/or infinite conductivity vertical fractures. We define a new integrated interpretation methodology for reservoirs with discrete natural fractures making use of these techniques and incorporating openhole log data, seismic and the preliminary geological reservoir model. Finally, we illustrate the use of the methodology using the tested well.
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Reducing Reservoir Uncertainties Using Advanced Wireline Formation Testing (SPE 154426)
Authors S. Cantini, C. Baio, D. Baldini, M. Borghi, M. Gigliotti, F. Italiano, D. Loi and S. MazzoniSeveral offshore gas fields are present in Adriatic Sea (Italy), producing since the 60s. In these assets the gas is mainly produced from multilayer metric sand reservoirs. The declining production in these mature fields is normally offset by drilling new deviated wells. Recent technology evolution shifted the focus from metric reservoirs to thinly laminated intervals (thin beds), until now not produced due to difficulties in indentifying gas bearing zones. While gas identification in metric reservoirs can be achieved with standard petrophysical measurements, thin beds are challenging since lamination thickness is half inch or less and even advanced petrophysical logs struggle in discriminating gas from water in this environment. Conventional pressure gradient approach also does not work, since thin beds are often overpressurized and pressures are supercharged due to low mobility. A new wireline formation testing approach for thin beds to discriminate gas from water zones was introduced, using a dual packer string with downhole fluid analysis capabilities, including fluid density measurement. This provided the possibility of testing very low permeability zones with high uncertainties in saturations. The possibility to verify gas presence in zones with high uncertainties saved the cost of multiple well testings, optimized the completion strategy of the different reservoirs and allowed to increase the field production and reserves. Dual packer tests were also successfully carried out in the basinal and slope facies of foreland basin, a shale formation underlying the multilayer reservoir sequence never considered before a real reservoir, revealing potential for gas production. Several gas fields today producing from metric reservoirs will be revisited in the very near future in order to start production from thin beds, until now untouched. The advanced wireline formation testing approach described in this paper will certainly play a key role in optimal exploitation of thin beds gas reserves.
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Decision Making under Uncertainty in EOR - Applying the Least Squares MonteCarlo Method in Chemical EOR Implementation (SPE 154467)
Authors A. Alkhatib, M. Babaei and P.R. KingThis study builds on the previous work of the author in adapting the LSM (Least Squares MonteCarlo) method to an EOR context in order to value flexibility in the implementation of a surfactant flood and to produce the optimal policy. The LSM algorithm was developed in MATLAB and SchlumbergerC"s Eclipse was used as the reservoir simulator. The main focus of the algorithm was to consider the uncertainty in parameters that vary in time. The technical uncertainties considered were the residual oil saturation to the surfactant flood and surfactant adsorption while the main economic uncertain parameters considered were oil price, surfactant cost and water injection and production costs. The study is divided into two main sections: the first section considered the uncertainty in technical and economic parameters using a homogenous synthetic model, the second section considered the effects of the uncertainty of these parameters on a heterogeneous model based on permeability data from SPE Comparative Solution Project, Model 2. In this case, heterogeneity is considered as another uncertain parameter by having the heterogeneous permeability field realizations vary with time. This is achieved by using upscaled models and progressively replacing them with finer models. This procedure represents the increasing state of knowledge in terms of our understanding of the reservoir with time. The results show that the LSM method provides a decision making tool that was able to capture the value of flexibility in surfactant flooding implementation. It also demonstrated that it is economical to implement surfactant flooding under uncertainty compared with the evaluations of traditional methods which produce uneconomical outlooks under the same conditions. Another advantage of this method is that it considers the value of information during the life of an EOR project which might undergo an alteration of the implementation strategies at different decision times.
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Regularization in History Matching Using Multi-objective Genetic Algorithm and Bayesian Framework (SPE 154544)
Authors M. Sayyafzadeh and M. HaghighiHistory matching is an inseparable part of reservoir characterisation which is a highly nonlinear inverse problem and suffers from ill-posedness. Different regularisation methods such as Tikhonov regularisation and Bayesian framework have been used to overcome the ill-posedness using prior knowledge. In this study, the application of a multi-objective genetic algorithm (GA) in the history matching as a regularisation and an optimisation is introduced. In this approach, two separate objective functions likelihood and prior are defined. In Tikhonov and Bayesian approach, the mentioned objectives are defined with one weighted function. In the Bayesian framework, covariance matrixes are utilised as weighting factors for each parameter, but there is no constant to join likelihood and prior objectives. However Tikhonov relates the objectives with a weighting factor, it is a challenging task to find the optimum value for the constant in the history matching. Consequently, in these two regularisation methods, it is potential that one objective dominates the other one. To validate the approach, ECLIPSE is coupled with MATLAB. A synthetic 3 dimensional 3 phase reservoir is constructed. Gaussian noise is added to the history. After that, different approaches are used to match the history and reconstruct the reference case. Bayesian and Tikhonov regularisation with different optimisation methods, real-valued genetic algorithm and nonlinear least square Levenberg-Marquardt algorithm optimisation are used. Then, their results are compared with a multi-objective GA. The outcomes demonstrate that the proposed method converges quicker than other methods and more importantly the results are realistic. In multi-objective systems, each objective has effect on the other one. Hence, optimising a system without considering all the objectives together leads to unrealistic outcomes. Using a multi-objective GA, it would be feasible to consider all objectives togather and provide the Pareto front.
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Challenges in High Performance Computing for Reservoir Simulation (SPE 152414)
Authors E. Hayder and M.A. BaddourahHigh resolution reservoir modeling is necessary to analyze complex flow phenomena in the reservoir. As more powerful computing platforms are becoming available, simulation engineers are building larger high resolution reservoir models to study giant fields. Complexities in simulation algorithms and memory contentions are challenges to efficient use of emerging computing platforms. As new tools are available and performance of hardware and software improves, it is important to reevaluate and revise implementation details of the simulator to maintain a high level of scalability on the large number of processors. There is enormous potential in emerging technologies, such as graphic processing units (GPUs), but currently, the lack of development tools restricts their adaptation in high performance computing. Researchers in many areas of computational fluid dynamics have been able to achieve a very high level of computational performance. Such a high level is yet to be achieved in reservoir simulation. In this study, we review computational difficulties in high performance computing related to reservoir simulation and examine how improvements can be made by use of emerging technologies in this class of problems. We discuss our efforts towards improving communication and input/output (I/O) algorithms in our reservoir simulator. We also evaluate high speed interconnections, various communication libraries, etc., for parallel computations and examine how simulation performance can be improved on the latest multi-core processors. Benchmark results of various computational and I/O kernels and a summary of actual simulation results will be reviewed to illustrate current challenges and the near term outlook of high performance reservoir simulation studies.
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Improved Mobility Calculation for Finite Element Simulation (SPE 154480)
Authors A. Abushaikha, M.J. Blunt, O.R. Gosselin and T.C. LaForceWe implement a novel up-winding scheme for the mobility calculation using the computed velocities in a finite element (FE) unstructured-mesh simulator for fractured reservoirs. In the finite-element finite-volume (FEFV) numerical discretisation method, the pressure and transport equations are decoupled. The pressure is calculated using finite elements, and the saturation is calculated using finite volumes. Each element is shared between several control volumes -- three for triangles (2D-fractures) and four for tetrahedral (3D-matrix). Consequently, the saturations used in calculating the mobilities -- hence updating pressure -- are unclear. Some researchers use the average value between the elemental control volumes, or the integration points of the finite elements. For two-dimensional radial flow, this does not produce accurate saturations profiles when compared to the Buckley-Leverett reference solution. In this paper, we present a new formulation to calculate the FE mobility. We use the velocity vector, which is piece-wise constant in first order elements, to find the upstream saturation -- where the tail of velocity vector intersects an element. We compare the results of this new mobility calculation against other FEFV fractured reservoir simulators. We test the new method on a fracture network outcrop meshed using discrete fractures and matrix elements. This novel approach produces more accurate saturation profiles than previous methods even with higher order methods and better models multi-phase displacements in complex reservoir. It can be easily implemented in current FEFV based simulators.
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A Parallel Streamline Simulator for Integrated Reservoir Modelling on a Desktop (SPE 154484)
Authors M. Gaupaas, F. Bratvedt, S.K. Khataniar, A. Primera and F.P. RuanDesktop computing is undergoing a revolution with parallel processing on multi-core workstations. Parallel streamline simulators have been developed for shared memory architecture systems, using off-the-shelf compilers with an application programming interface for parallel programming. Here, we discuss the implementation and the performance analysis of a parallel streamline simulator based on native threading technology for both WindowsCB. and LinuxCB. operating systems. Although parts of the general streamline simulation algorithm are relatively straightforward to parallelize, there are several challenges that require special attention to avoid computing bottlenecks and inconsistent results across different computing environments. An efficient load balancing algorithm to avoid idle processors has been implemented, combined with a data-accumulation scheduling algorithm to ensure consistent results independent of the platform and the number of processing units. The combined performance of a multicore computer and a parallel streamline simulator offers significant opportunities for reservoir management applications. It can also increase the use of 64-bit desktop workstations that are commonly used for 3D geological modelling and the creation of applications that integrate the geosciences. Parallel scalability analysis for various model characteristics and simulator options is also analyzed. For a variety of models, we have observed an almost linear scalability for as many cores as available on a typical shared memory high-performance computer.
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A Comparative Study of Reduced Variables Based Flash and Conventional Flash (SPE 154477)
More LessSpeeding up flash calculation is a central issue in compositional reservoir simulations since phase equilibrium calculation is the most time-consuming part in those simulations. The reduced variables methods, or the reduction methods, reformulate the original phase equilibrium problem with a smaller set of independent variables. Various versions of the reduced variables methods have been proposed since the mid 80's. The methods were first proposed for cubic equations of state (EoS) with zero binary interaction parameters (BIPs) and later generalized to situations with non-zero BIP matrices. Most of the studies in the last decade suggest that the reduced variables methods are much more efficient than the conventional flash method. However, Haugen and Beckner questioned the advantages of the reduced variables methods in their recent paper (SPE 141399). A fair comparison between the reduced variables based flash and the conventional flash is not straightforward since the former is difficult to be formulated as unconstrained minimization and involves more complicated composition derivatives. With the recent formulations by Nichita and Garcia (2010), it is possible to code the reduced variables methods without extensive modifications of MichelsenC"s conventional flash algorithm. A minimization based reduced variables algorithm was coded and compared with the conventional minimization based flash. A test using the SPE 3 example showed that the best reduction in time was less than 20% for the extreme situation of 25 components and just one row/column with non-zero BIPs. A better performance can actually be achieved by a simpler implementation directly using the sparsity of the BIP matrix.
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Non-darcy Flow Numerical Simulation for Low-permeability Reservoirs (SPE 154890)
More LessWith further progress of oilfields' development all over the world, more and more low permeability reservoirs are being put in production. However, fluid flow in low permeability porous media deviates from the classic Darcy's law and instead conforms to the one of non-Darcy seepage. Most mature commercial numerical simulation softwares may cause error in simulating development performance of low permeability reservoirs. So a non-Darcy seepage numerical simulation software has been developed. In this paper, non-Darcy seepage mathematical model was proposed. In addition, on the basis of practical field and laboratory experiment data, an ideal model of five-spot well pattern was also established. Under the same reservoir condition, the non-Darcy simulation, conventional Darcy simulation and the simulation of threshold pressure gradient were conducted. The comprehensive comparison and analysis of the simulation results of Darcy flow, threshold pressure gradient flow and non-Darcy flow were provided. Research shows that compared to the results of Darcy flow, when considering non-Darcy flow, the oil production is low, and production decline is rapid; the fluid flow in reservoir consumes more driving energy which reduces the water flooding efficiency. Darcy flow model overstates the reservoir flow capability, and threshold pressure gradient flow model overstates the reservoir flow resistance. In the low permeability reservoirs, non-Darcy seepage dominates in a large scale of formation and the non-Darcy simulation result shows excellent agreement with the production data. Therefore taking the non-Darcy seepage into account is more suitable to reflect the percolation mechanism and development performance of low permeability reservoirs. This numerical simulation method has been applied successfully in Shengli oilfields.
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Machine Learning Methods to Speed up Compositional Reservoir Simulation (SPE 154505)
Authors V. Gaganis and N. VarotsisCompositional reservoir simulation is one of the most powerful techniques currently available to the reservoir engineer upon which most reservoir development decisions rely on. According to the number of components used to describe the fluids there is an increasing demand for computational power due to the complexity and the iterative nature of the solution process. Phase stability and phase split computations often consume more than 50% of the simulation total CPU time as both problems need to be solved repeatedly and iteratively for each discretization block at each iteration of the non-linear solver. Therefore, speeding up these calculations is a research challenge of great interest. In this work, machine learning methods are proposed for the solving of the phase behavior problem. It is shown that under proper transformations, the unknown closed-form solution of the Equation-of-State based phase behavior formulation can be emulated by proxy models. The phase stability problem is treated by classifiers which label the fluid state in each block as either stable or unstable. For the phase split problem, regression models provide the prevailing equilibrium coefficients values given the feed composition, pressure and temperature. The development of these models is rapidly performed offline in an automated way, by utilizing the fluid tuned-EoS model prior to running the reservoir simulator. During the simulation run, rather than solving iteratively the phase behavior problem, the proxy models are called to provide non-iteratively direct answers at a constant, very small CPU charge regardless of the proximity to critical conditions. The proposed approach is presented in two-phase equilibria formulation but it can be extended to multi-phase equilibria applications. Examples demonstrate the advantages of this approach, the accuracy obtained in the calculations and the very significant CPU time reduction achieved with respect to conventional methods.
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Comparison and Validation of Theoretical and Empirical Correlations for Black Oil Reservoir Fluid Properties (SPE 152222)
Authors S. Godefroy, S.H. Khor and D. EmmsComparison and Validation of Theoretical and Empirical Correlations for Black Oil Reservoir Fluid Properties (SPE 152222)
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Application of Injection Fall-off Analysis in Polymer Flooding (SPE 154376)
Authors P. Van den Hoek, D. Brooks, H. Mahani, F. Saadi, S. Sen, K. Shuaili, T. Sorop and M. ZwaanDESCRIPTION Polymers exhibit non-Newtonian rheological behavior, such as in-situ shear-thinning and shear-thickening effects. This has a significant impact on pressure decline signature as exhibited during Pressure Fall-Off (PFO) tests. Therefore, applying a different PFO interpretation method, compared to conventional approaches for Newtonian fluids is required. RESULTS, OBSERVATIONS, CONCLUSIONS This paper presents a novel, simple and practical methodology to infer the in-situ polymer rheology from PFO tests performed during polymer injection. This is based on a combination of numerical flow simulations and analytical pressure transient calculations, resulting in generic type curves that are used to compute consistency index and flow behavior index, in addition to the usual reservoir parameters (kh, faulting, etc.) and parameters relating to (possible) induced fracturing during injection (fracture length and height). The tools and workflows are illustrated by a number of field examples of polymer PFO, which will also demonstrate how the polymer bank can be located from the data. APPLICATION This methodology can be used for interpretation of PFO tests on EOR polymer flooding projects, where monitoring of injection performance and of in-situ effective polymer rheology are key in the success of a project. SIGNIFICANCE OF SUBJECT MATTER The novelty of this study is that it presents a simple, straightforward methodology for analysis of polymer properties and polymer bank location from PFO tests which can be easily implemented into any software package. The methodology has a general applicability in that it also covers cases in which radial flow symmetry has been lost owing to induced fracturing during injection.
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Pressure Transient Analysis in Multiphase Multi Layer Reservoirs with Inter Layer Communication (SPE 152838)
Authors M. Mokhtari, A. Hashemi and E. NikjooThe focus of this study is on the investigation of multiphase flow effects on the pressure transient analysis in layered reservoirs with cross flow. Virtually all studies on the subject of multiphase well test analysis have been carried out in a single layer reservoirs. However, many reservoirs are found to be composed of number of layers whose characteristics are different from each other and the wells in such reservoirs may be completed and produced from more than one layer. A novel technique is presented by replacing multi-phase multi-layer reservoirs with cross flow with an equivalent single phase single layer reservoir. In order to investigate the applicability of the presented method several reservoirs in which the contrast in phase saturations in each layer is the parameter of interest is considered. The reservoir parameters such as phase mobilities, skin factor and average reservoir pressure are compared with actual values. According to the results of this work, it has been concluded that the reservoir parameters can be estimated by high accuracy with equivalent single phase single layer reservoir however, the data should be interpreted with care if horizontal saturation gradient is significant in the layers.
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Applications of Harmonic Pulse Testing to Field Cases (SPE 154048)
Authors P.A. Fokker and F. VergaHarmonic pulse testing is a well testing technique in which the injection or production rate is varied in a periodic way. The pressure response to the imposed rates, both in the pulser well and in the observer wells, can be analyzed in the frequency domain to evaluate the reservoir properties. The advantages of this type of test is that dedicated well testing surface equipment is not required and that the test can be performed during ongoing field operations. In an earlier study we demonstrated that the harmonic pulse testing methodology can be used to evaluate the development of effective permeability and total compressibility even for such a heterogeneous case as resulting from a water injection scenario. The analysis can be performed using a numerical simulator in the Fourier domain, by which heterogeneities can be explicitly taken into account. As time-stepping is not required in such a simulation, the calculation can be performed much faster. In the present paper we report on the application of the methodology to two field cases. In the first case a gas storage reservoir was operated with a day-night injection-shutin scenario. Data analysis could prove that the reservoir was homogeneous and that a minor fault identified by the seismic was not hindering hydraulic communication between the pulser and the observer wells. The second case was a harmonic test experiment in three groundwater wells which was reported earlier, but where the analysis was inadequate. The theory used was insufficient to consistently explain all the measurements, likely to be affected by strong reservoir heterogeneity. Only with our novel methodology it was possible to investigate the effects of heterogeneity. We demonstrate that a heterogeneity in the form of high-permeability streaks adequately describes the test results.
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Optimizing Well Placement with Quality Maps Derived From Multi-fidelity Meta-models (SPE 154416)
More LessThis paper presents a new methodology for locating infill wells so as to improve reservoir performance and value. The methodology centers on the determination of both qualitative and quantitative quality maps, quality being a measure of how good an area is expected to be for production. The determination of the best infill well locations is a highly nonlinear optimization problem. Solutions can be found using optimization algorithms. However, they usually correspond to local optima and require a few thousands of fluid flow simulations. This strongly penalizes the use of optimization algorithms for designing field production schemes. In this paper, we proposed a practical solution to handle infill well placement. First, various physical attributes are computed without any flow simulator to approximate the production capability of the reservoir. They are classified and used to delineate regions with poor or favorable potentials for well placement. Second, a few well locations are sampled on the basis of the defined regions and a flow simulation is performed for each of them to estimate how oil production evolves when an infill well is drilled at these locations. The resulting oil production responses are used to approximate oil production at unsampled locations. The specific feature of this method is to consider that grid blocks are characterized by their spatial coordinates plus the distance to the closest existing well. This third coordinate accounts for the wells already drilled and can be easily updated when a new one is implemented. This approach makes it possible to account for well interferences while calling for a reduced number of flow simulations. The proposed method is expedient. It does not yield the optimal locations of the wells to be added. Yet, it provides a useful first-pass set of well locations. An application case is presented to illustrate its potential.
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Complexity of Wettability Analysis in Heterogeneous Carbonate Rocks - A Case Study (SPE 154402)
Authors M. Mohammadlou and M.B. MorkEstimation of reservoir wettability and its effect on reservoir fluid flow, hydrocarbon recovery and fluid distribution has been the subject of many researches in recent years and remains one of the major challenges in reservoir characterization. This study examines the reservoir wettability in heterogeneous karstified carbonate rocks from comparison of special core analysis (SCAL) and resistivity index measurements on the core plugs, together with study of nuclear magnetic resonance (NMR) log, and formation pressure obtained by modular dynamic tool (MDT) measurements in the reservoir. The SCAL test results present moderately water-wet reservoir conditions at the cored intervals of the reservoir. Surveys from resistivity index measurements are in general agreement with the SCAL results. Due to lack of core data in the lower/main part of the reservoir, analysis of the NMR T2 distribution are combined with MDT data to describe the reservoir wettability. The pressure data suggests a water gradient through the reservoir column except for anomalous high pressure values in which corresponds to zones with high resistivity and oil saturations. High oil saturation is not expected in zones where the reservoir has been water flooded (water level rise in the reservoir) after hydrocarbon accumulation. The study of the T2 distribution of these intervals helps to identify the oil wet nature of the larger pores in the reservoir. The surface relaxivity of oil when it wets the pore surface cause a shift in the T2 distribution towards shorter T2sC". The water volume, then, in oil wet pores relaxes as bulk relaxation with longer T2 compared to the water wet case. This study suggest that a combination of the NMR log with MDT data and resistivity logs provides a method to identify wettability characteristics of complex rocks when core plugs are missing.
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