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IOR 2013 - 17th European Symposium on Improved Oil Recovery
- Conference date: 16 Apr 2013 - 18 Apr 2013
- Location: Saint Petersburg, Russia
- ISBN: 978-90-73834-45-3
- Published: 16 April 2013
41 - 60 of 73 results
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Recent Progress in Surfactant Flooding in Carbonate Reservoirs
Authors E. Chevallier, P. Moreau, S. Renard, R. Tabary, B. Bazin, F. Douarche and F. OukhemanouSurfactant Polymer (SP) flooding in carbonate reservoirs is still considered as a considerable challenge today. Indeed, adsorption of anionic surfactants onto carbonate rocks is known to be much higher than onto sandstone rocks. This limits drastically the efficiency of the process. We develop here new methods on reducing surfactant adsorption in carbonate reservoirs using new additives: adsorption inhibitors. First we illustrate the impact of lithology (dolomite, limestone) on surfactant adsorption. We demonstrate how high adsorption clearly limits chemicals flooding performances in carbonate rocks under realistic conditions, i.e. moderate amount of injected chemicals at reservoir flowrates. Then, static adsorption tests show that careful selection of additives can significantly decrease surfactant adsorption onto carbonate rocks. This is further confirmed by dynamic adsorption tests. These laboratory results clearly demonstrate that surfactant flooding can be successfully applied in matrix carbonate reservoirs but it is crucial to consider lithology as it plays a significant role on final process performances, showing high variabilities in porous medium. The use of adsorption inhibitors appear as a significant advance for surfactant flooding in carbonate reservoirs, opening new opportunities for surfactant flooding in these challenging conditions.
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Microemulsion Rheology and Alkaline-surfactant-polymer Flooding
Authors K. J. Humphry and M. van der LeeWorkflows to assess the technical and economic suitability of an enhanced oil recovery (EOR) technique for a particular field generally involve laboratory testing, such as core flooding experiments, and field-scale reservoir modelling. When building these field scale models and interpreting laboratory experiments it is important to understand the flow properties of all phases present in the particular EOR process. In alkaline-surfactant-polymer flooding (ASP) flooding, surface-active molecules decrease the interfacial tension between water and crude oil, increasing the capillary number, and recovering oil trapped in the reservoir pores. The ultra-low interfacial tensions needed for ASP flooding occur when the surface active molecules are equally soluble in the brine and oil phases. Under these conditions, in addition to the brine and oil phases, a third thermodynamically stable phase is formed. This third phase is known as a microemulsion. While the flow properties of crude oil and polymer-enriched brine are well understood, little has been done to characterize the microemulsion phase, particularly with respect to rheology in porous media. In this study, larger volumes of microemulsion, with and without polymer, are generated using a model ASP system. These microemulsions are studied using conventional shear rheology. Additionally, an in situ, or apparent, viscosity is recovered from core flooding experiments in Berea sandstone, where pressure drop across the core is recorded as a function of the flow rate of the microemulsion through the core. The implication of these results for ASP flooding is discussed.
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Methodology of Selecting Pilot Development Areas for Application of BrightWater™ Technology
Authors D.V. Akinin, A. Timchuk, Y.V. Zemtcov and O.Y. BochkarevAt present, development of unique and reserves-rich fields is characterized by declining oil production rates and increasing portion of residual recoverable reserves in reservoirs with high current watercut. Conventional tools to recover such reserves are rather inefficient. Therefore, application of flow-diverging techniques of enhancing oil recovery is becoming more and more important. In the recent time, there has been a growing interest to a new EOR technology BrightWaterТМ. Since 2004, the commercial use of this method has expanded from single pilot applications to several dozens of wells, and has been implemented at oil fields in Alaska, Argentina, Azerbaijan, Brazil etc. The key feature of this technology, which makes it different from its analogs, is the formation of a barrier diverging the flow of water within the formation rather than in the bottomhole area. To select the most appropriate areas at the Company’s oilfields and test BrightWaterТМ technology, a number of fields have been assessed and analyzed for feasibility of such application. This paper describes the main criteria of applying BrightWaterТМ technology and the algorithm of selecting pilot development areas for this purpose.
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Laboratory and Field Tests of Component-wise Gel Injection Technology for EOR
Authors I.V. Kuvshinov and V.V. KuvshinovThis work presents the results of computer modeling, laboratory research and field tests of component-wise gel injection technology for EOR. Now standard methods of gel injection imply using of homogeneous gel-forming composition, with component mixing on a surface just before injection, or even earlier, at a stage of chemicals production. It is not always acceptable, because the gelation process can start inside or near the wellbore, e.g. in a hot steam injection well, but the technology requires the formation of a gel shield at a certain distance from the well. Component-wise injection technology is based on fluid dispersion during filtration through a porous media, when the solutions of each reagent are sequentially injected into the well, and their mixing occurs due to dispersion at a certain distance from wellbore. The computer model of the component-wise injection process, which enables to estimate the required volumes of reagent and their mixing conditions in situ, is presented. Modeling results for different laboratory experiments and injection schemes for field tests are shown. The specially constructed laboratory setup for studying fluid dispersion, with test column length up to two meters, is described. Experimental data obtained were used for computer model verification. In special series of the experiments, test column configuration was varied, with “dead zones” modeled, to estimate its effect on fluid dispersion process. The results of the first successful field test of the technology, performed on injection well in one of the Western Europe oilfields, are also presented. These results prove the adequacy of the model, and the technology effectiveness.
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From Lab to Pilot Design of ASP Flooding in High Temperature Reservoir of Limau Field Indonesia
Authors I.P. Suarsana, A. Badril and I. WijayaHigh temperature is considered the most handicaps in the process of chemical selection, Laboratory analysis, core flooding process, and lab verification of government authority. When we get the best fluid selection then the price will control the pilot project. This paper will present the chemical selection, lab analysis and pilot design of Limau Field, section P&Q, located in South Sumatera Indonesia. Limau Field is one of the oil field located in the working area of PT. Pertamina EP Sumatera Region, Limau is a mature field began produced since 1930. Tertiary Recovery stage (EOR) target implementation in block P, Q-22 and Q-51. This three block has been selected since they have highest potential of remaining oil in place, and have been implemented secondary recovery phase with water injection and got a positive response from this activity. Primary peak oil production was achieved at 46,000 BOPD with 5 % of Water Cut in 1960, Activities of secondary recovery (water injection) stage conducted in 1991 with water injection using a staggered line drive and peripheral pattern with the main d in Soutin 1994 from the previous condition of 1,222 BOPD in 1989. From the results of successful secondary recovery stage, Pertamina EP and partner plan to implementation tertiary recovery stage with chemical injection (ASP Flooding),. To propose a chemical flooding project, there several regulation has to be follow before the pilot implementation. There are some activities to convincing EOR stage include : screening chemical flooding, chemical flooding laboratory study (fluid-fluid analysis & rock fluid analysis) in accordance with the conditions of the reservoir at temperature of 1050 C, GGRPF (geophysical & Geology, Reservoir, Production and facilities) study for the determination of the pilot area until full scale development. The challenges facing the stage screening chemical use is high reservoir temperatures in the range 1050 C, the results core flooding conducted and chemical flooding (ASP floding) who has been getting incremental recovery of 13,84% conducted in SURTEK lab USA and Lemigas Lab for verification is 9.94% of the OOIP. From the laboratory stage and studies that have been successfully carried out, will continue with ASP flooding pilot with 6 spot inverted pattern, where the results of reservoir simulation production response to injection will be felt in the 4 month with an annual increase of 2400 bopd from the previous condition of 225 bopd in production wells.
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Impact of Difficult Environments on Chemical Flooding Performance
Authors B. Bazin, R. Tabary, F. Douarche, P. Moreau and F. OukhemanouSurfactant flooding processes become challenging when one of the following criteria is met: hard brines, high temperature, low permeability rock and high clay content. This paper illustrates how we overcome those difficulties combining appropriate formulations with the right injection strategy (slugs design). A particular emphasis is set on solutions that can be applied in the field. High performances solutions first rely on selecting appropriate surfactants from an extended portfolio representative of industrial products. We describe how ultra-low interfacial tension formulations are designed while maintaining a good solubility at high temperature (>100°C) and in hard brines (high divalent ion concentration). Various reservoir cases will then be reviewed: In hard brines chemical adsorption is known to be significantly higher than in soft brines. Surfactant adsorption is drastically reduced (<0.2 mg/g) when using appropriate adsorption inhibitors. This results in a very high oil recovery (>90 %) with performances comparable to the one obtained in soft brine conditions. High temperature (> 70-80°C) raises thermal stability issues with losses of effectiveness and possible plugging. New surfactants and polymers are available to address this situation. Successful oil recovery experiments done up to 120°C will be discussed. Low permeability sandstone, usually associated with high clay levels has an impact on both injectivity and chemical adsorption. In most challenging conditions alkaline cannot be used and an optimized salinity gradient combined with adsorption inhibitors is requested. The paper will demonstrate how surfactant flooding can be successfully applied in challenging reservoir conditions to open new opportunities for chemical EOR.
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Injectivity Errors in Simulation of Foam EOR
Authors W. Rossen, T.N. Leeftink and C.A. LatooijInjectivity is a key factor in the economics of foam EOR processes. Poor injectivity of low-mobility foam slows the production of oil and allows more time for gravity segregation of injected gas. The conventional Peaceman equation, when applied in a large grid block, makes two substantial errors in estimating injectivity: it ignores the rapidly changing saturations around the wellbore and the effect of non-Newtonian mobility of foam. When foam is injected in alternating slugs of gas and liquid ("SAG" injection), the rapid increase in injectivity from changing saturation near the well is an important and unique advantage of foam injection. Foam is also shear-thinning in many cases. We use the method-of-characteristics approach of Rossen et al. (2011), which for the first time resolves both changing saturations and non-Newtonian rheology with great precision near the wellbore, and compare to conventionally computed injectivity using the Peaceman equation in a grid block. By itself, the strongly non-Newtonian rheology of the "low-quality" foam regime makes a significant difference to injectivity of foam. Thus for continuous injection of foam in this regime, the Peaceman equation underestimates injectivity by a factor of two even for grid blocks as small as 10 m wide, and by a larger factor for realistic grid-block sizes. However, one could estimate this effect using the equation for injectivity of power-law fluids, i.e. without accounting for changing water saturation near the well, without much error. In SAG processes, however, non-Newtonian rheology is less important than accounting for foam collapse in the immediate near-wellbore region. Averaging water saturation in a large grid block misses this dryout very near the well and the Peaceman equation grossly underestimates the injectivity of gas. We illustrate with examples using foam parameters fit to laboratory data.
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CO2 Injections for Enhanced Oil Recovery Visualized with an Industrial CT-scanner
Authors Ø. Eide, M.A. Fernø, Z. Karpyn, Å. Haugen and A. GraueThe effect of micro-scale heterogeneities on front instabilities during secondary, liquid CO2 injections for enhanced oil recovery in standard-sized chalk core plugs was investigated. The rock structure and displacement process was imaged in an industrial CT-scanner to probe the effect of micro-scale heterogeneities on the flow patterns and development of plume and CO2 fingers during injections. Heterogeneities in the chalk samples include fractures, healed shear bands and remnants of burrows. A one-component mineral oil was placed in contact with CO2 at the experimental conditions to promote reproducibility between repeated tests. The chalk is considered homogeneous on a standard-sized plug level, and varies only slightly in porosity and permeability within a large number of cores. The high spatial resolution CT scanning revealed sub-mm healed shear bands running through the length of the core which potentially can cause a permeability decrease or diversion of the injected fluid. Total oil recovery from CO2 injection was around 90% regardless of heterogeneities, and there was no visible difference in CO2 arrival at the outlet. With no permeability contrast through the length of the core, the production of oil took place with less than one pore volume (PV) of CO2 injected. With a permeability contrast through the length of the core, more than one PV of CO2 was required to reach end-point oil saturation. Imaging the dynamic properties of a CO2 flood in the industrial CT showed how micro scale heterogeneities impact the flooding characteristics of a small core sample, as the healed shear bands diverted flow to a certain degree. It is also demonstrated how a larger permeability contrast will make the recovery more dependent on diffusion, which is a slower process than viscous displacement. The results demonstrate the need for characterization of micro-scale heterogeneity, because high permeability streaks and fractures will dominate flow during CO2 injection for EOR.
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History Match and Polymer Injection Optimization in a Mature Field Using the Ensemble Kalman Filter
Authors S. Raniolo, L. Dovera, A. Cominelli, C. Callegaro and F. MasseranoThe paper focuses on a Chemical EOR study for a mature field. The field was selected due to its volume in place and good petrophysical properties. Indeed, the preliminary screening gave indication that polymer injection could be a promising EOR technique. New core data, SCAL and PLT were acquired and a high resolution model of the pilot area was built to integrate such new data and to properly capture the behaviour of the chemicals. The sector modelling was challenging due to the complexity of the history match and polymer injection optimization. The field has been producing for 60 years. Moreover, due to the complex structural settings, the sector model is not completely isolated from the full field model and dummy wells were introduced to mimic the flow interaction with the rest of the reservoir. A Computer Assisted History Matching (CAHM) was carried out by the means of the Ensemble Kalman Filter (EnKF). The EnKF is a Monte-Carlo method that automatically updates an ensemble of reservoir models by production data integration. The EnKF is capable of providing a set of matched models that preserve the geological coherence which can be used to quantify uncertainty in forecast production. In this paper, we present the application of the EnKF to history match the sector model and the consequent optimization for polymer injection. EnKF was used to calibrate petrophysical properties, relative permeability and faults transmissibility integrating measurements, shut-in pressures and rates, of 14 wells including the dummy wells. The final output is a set of 100 alternative models that properly match production data which were used to set up and optimize the forecast development strategy through polymer injection. This application provides evidence that the EnKF is effective and efficient for history matching. Moreover, dealing with multiple models put the basis for a conscious estimation of future production and a more realiable risk evaluation on EOR strategy.
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Results and Lessons Learned from an Extended Single-well Tracer Campaign Performed in the Handil Field, Indonesia.
Authors A. Mechergui, C. Romero, N. Agenet, J. Batias, M. Nguyen and L. HeidariHandil is a mature oil and gas field in the Mahakam Delta, Indonesia. It was discovered in 1974 and developed since 1975. It was firstly produced by natural depletion and then by waterflooding. From 1995 gas injection was implemented as tertiary recovery mechanism. In 2007 a first Single-well tracer test (SWTT) campaign was carried out in the field showing a low Remaining Oil Saturation (ROS) that was confirmed by coring technique in the selected reservoir. Uncertainty existed on the origin of such low ROS (12-14%), thus in 2011 an ambitious SWTT campaign was launched to assess the ROS distribution in different reservoirs under waterflood and simultaneous water and gas flood strategies. The objective was to better understand EOR mechanisms prevailing in the field and help assess ROS under different flooding strategies. The challenging campaign consisted of a program of consecutive SWTT trials performed in a mature and offshore field environment. This paper focuses on the operations and results of the SWTT campaign obtained from three tests out of five that were performed in different reservoirs. The interpretation of these tests was challenging and numerical simulation was compulsory for a reliable ROS estimation. In reservoir A, we suspected that the tested zone have been invaded by the gas cap. Therefore, in order to get an uncertainty range of ROS in presence of gas, the partitioning coefficient of primary tracer (Ethyl Acetate) between gas and water was measured at reservoir conditions. Results indicate that even with high trapped gas saturation, the ROS is in the order of 22%. For the second test in Reservoir B, the mass balance was excellent but profiles showed non ideal behavior due either to drift or a wellbore effect. The two hypotheses were investigated and numerical simulations helped identify that wellbore effect was the main non-ideality. This was included and a reliable ROS value of ~30% was determined. The third SWTT was performed in Reservoir C and showed an excellent tracer recovery with low scattering data. However production phase was characterized by an unstable flow regime which required the use of instantaneous production rate during numerical simulation. Matching of tracer profiles indicates an average ROS in this reservoir of 20%. These ROS values that range between 20-30% allow us today to move forward in the identification of potential EOR candidates and they will help us advance in the location of future pilot zones for different EOR processes.
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Injection Fall-off Interpretation from Fractured Injectors
More LessWe performed numerical simulations of injection fall-off (IFO) testing for both water and (non-Newtonian) polymer in which the gradual closure of the induced fracture is explicitly included. A large variety of induced fracture sizes and shapes was included in this study. Results show that half-slope and quarter-slope ranges will only occur very exceptionally in the early-time pressure derivative curves. On the other hand, the unit slope (storage flow dominated) occurs very often at early time. In principle, both half-slope / quarter-slope and unit slope can be used for IFO test analysis to estimate the dimensions (length, height) of the induced fractures. However, based on the above, we conclude that fracture dimensions in IFO tests can only be reliably interpreted from the unit slope part. This point is further illustrated by a two IFO test examples from the field, where it is shown that interpretation of half-slope or quarter-slope can often result in unrealistically large fractures.
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Continuous Land Seismic Reservoir Monitoring of Thermal EOR in the Netherlands
Authors J. Cotton, L. Michou and E. ForguesA continuous reservoir monitoring system has been installed for Shell, on a heavy-oil onshore field situated in the Netherlands, to re-develop oil production by Gravity-Assisted Steam Drive. The challenge was to continuously monitor using seismic reflection the expansion of the steam chest injected in the reservoir during production. The main problems for onshore time-lapse seismic are caused by near-surface variations between base and monitor surveys which affect the seismic signal coming from the reservoir. In our system, a set of permanent shallow buried sources and sensors has been installed below the weathering layer to both mitigate the near-surface variations and minimize the environmental footprint. The very high sensitivity of our buried acquisition system allows us to track very small variations of the reservoir physical properties in both the spatial and calendar domains. The 4D reservoir attributes obtained from seismic monitoring fit the measurements made at observation, production, and injector wells. A daily 4D movie of the reservoir property changes allows us to propose a scenario that explains the unexpected behavior of the production and confirms that the steam does not follow the expected path to the producer wells but rather a more complicated 3D path within the reservoir.
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Experiments and Analysis of Imbibition in Carbonates
Authors R.A. Anderson, N.A. Al-Ansi and M.J.B. BluntWith around half the world's remaining conventional oil contained in fractured carbonate reservoirs, it is important that the fundamentals of the transfer of fluids from fracture to matrix are understood. We present the results of an extensive series of spontaneous imbibition ambient-condition experiments on three carbonate cores of different length, designed to test recent theoretical models of imbibition. We study the displacement dynamics, from an initial square-root-of-time recovery to an exponential relaxation to residual saturation as the wetting from reaches the end of the core. We also quantify the effect of pore structure in highly heterogeneous systems. The scaling models presented by Ma et al. (1995), Li and Horne (2004), and Schmid and Geiger (2012) were tested on the experimental data. Schmid and Geiger’s correlation was found to be the most reliable. The recovery, as a function of dimensionless time, could be fitted with the mass transfer function proposed by Aronofsky et al. (1958) and the analytical oil recovery solution presented by Tavassoli et al. (2005). The work suggests that recent correlations for transfer rates in the literature, combined with benchmark experimental results, can be used as a reliable technique to help predict field-scale recovery rates in fractured reservoirs.
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Integrated Laboratory and Numerical Investigations Towards a MEOR Pilot
Authors H.K. Alkan, E. Biegel, A. Herold and F. VisserA project on the application of MEOR in one of the Wintershall candidate fields has been initiated. The project aims mainly at developing nutrient formulations for stimulating microbial activity in terms of oil recovery and defining reservoir and process parameters for the selected field leading to a field trial. The project is structured with a workflow consisted of 5 work packages. The sampling activities were extended with a sub-surface sampling in one of the candidate fields to investigate the effect of pressure on bacterial activity. The works on the determination of growth rates and metabolite activities of microbial consortia derived from one field is continuing with batch tests and micromodels. Dynamic screening experiments are going on in sandpacks and cores under sterile and anaerobic conditions. Numerical works are performed in two parallel ways. On one hand, an analytical model is being applied to evaluate relevant process parameters. On the other hand, a numerical simulator is being tested and validated to implement it into a reservoir simulator. The recent results both in experimental and numerical parts are presented and discussed in the paper.
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An Integrated Laboratory Workflow for the Design of a Foam Pilot in Malaysia
An integrated laboratory workflow for the design of a foam pilot in Malaysia. Max Chabert (Rhodia), Lahcen Nabzar (IFPEN), Siti Rohaida, Pauziyah Hamid (Petronas PRSB). We present the laboratory feasibility study dedicated to the design of an enhanced water alternating gas (EWAG) process for a Malaysian oilfield. The field is currently submitted to produced gas injection, mainly consisting of CO2. We focus here on the design of a water soluble foaming surfactant formulation using advanced characterization methods and the evaluation of this formulation in corefloods experiments. On-field conditions make the design of a surfactant formulation particularly challenging, with a reservoir temperature of 100°C and only sea water available for foaming formulation injection. The ultimate goal of this design study is thus to obtain an industrially realistic formulation yielding stable foams in reservoir conditions (including in presence of oil) at an affordable price. We set-up a specific laboratory workflow to design a foaming surfactant formulation adapted to reservoir settings. An automated screening routine based on robotics was used at ambient and reservoir temperature to pre-select the most performing formulations for foam stabilization among more than 400 binary and ternary mixes. Formulations solubility maps were obtained using automated image analysis. Only formulations perfectly soluble in the window defined by injection and production waters salinities were retained for further testing. Selected formulations were then characterized for foam stabilization in reservoir pressure and temperature conditions using a high pressure variable volume view cell. Adsorption of the selected formulations on reservoir crushed rock was optimized by exploiting synergistic effects between surfactant families. A formulation yielding over 2 hours foam half-life in reservoir conditions with a static adsorption below 1 mg/g was obtained. This formulation was further characterized in petrophysics application tests using analog Berea sandstones and reservoir rocks. These tests were designed to mimic potential pilot conditions in terms of injection strategy, injection rate and gas composition. High values of mobility reduction factors were obtained, including in presence of residual oil. This set of results is a first step toward application of an enhanced WAG foam process.
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Dynamic Interactions between Matrix and Fracture in Miscible Solvent Flooding of Fractured Reservoirs
Authors A. Ameri Ghasrodashti, R. Farajzadeh, M. Verlaan, V.S. Suicmez and H. BruiningMiscible solvent injection has received increasing attention in recent years as an efficient method to improve oil recovery from fractured reservoirs. Due to the large permeability difference between fracture and matrix, the success of this method depends to large extent on the degree of enhancement of the mass exchange rate between the solvent flowing through the fracture and the oil residing in the matrix. A series of experiments have been conducted to investigate the mass transfer rate between the fracture and the matrix. Different scenarios have been considered to examine the effect of flow rate, matrix permeability, fracture aperture, and oil properties. To this end a porous medium (fully saturated with oil) is placed in a vertical core holder that can be used in a CT scanner, to simulate the matrix. A small slit between the porous medium and the core holder simulates the fracture. The interaction between the matrix and fracture is visualized for solvent flooding by means of CT-Scanning, which can be used to validate theories of enhanced transfer in fractured media. The experimental data are compared with a simulation model that takes diffusive, gravitational and convective forces into account.
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Enhancing Recovery from the Oil-Rim Using Energy from the Gas Cap
Authors N.N. Ivantsov and A.S. TimchukIn the environment of constant deterioration of resource base, stability of oil production in the nearest decades will depend on the prospects of development of geologically complicated fields. In Western Siberia significant part of undeveloped reserves is represented by highly viscous oil fields with gas cap. Such are Russkoye, Messoyakhskoye, Van-Yoganskoye, Severo-Komsomolskoye and other, having reserves over 4 bln. tons. Development of such assets is hindered by adverse geological and physical conditions. Presence of a gas cap and a fine oil rim leads to early gas breakthroughs. Viscous oil and poorly consolidated reservoir contribute to the risk of premature water breakthroughs (matrix breakthrough events), reducing the efficiency of injection. Permafrost and reservoir clay swelling limit the deployment of thermal techniques. The fields were discovered over 40 years ago and massive pilot work is being carried out only in Russkoye field, however, an efficient development technique has not yet been found. In such an environment it seems relevant to look into unconventional solutions. The authors propose an oil rim development technique using the energy of the gas cap. In this technique the design and the trajectory of horizontal wells allow for simultaneous controllable oil production from the oil saturated zone and gas production from the gas cap. This allows for enhancement of oil flow rate, reduction of gas coning and extends the period of stable well operation. The earlier achieved results of calculations made for Russkoye field have shown that while depletion recovery factor equals 6%, enhancement could provide up to extra 3%. In this work the authors, using modeling results, have determined optimal geo-technical conditions for deployment of this technique. Efficiency evaluation has been performed for operations at injection scheme. Particular features of this technique enable it to be viewed not only as an EOR technique, but also as a tool to prevent the main risks for similar fields, i.e. gas breakthroughs and reservoir damage. Based on the results of the study proposals were elaborated for pilot work in Russkoye field.
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Pelican Lake Polymer Flood - First Successful Application in a High Viscosity Reservoir
Authors E. Delamaide Inc., A. Zaitoun, G. Renard and R. TabaryThe Pelican Lake heavy oil field located in northern Alberta (Canada) has had a remarkable history since its discovery in the early 1970s. The reservoir formation is thin (less than 5m) and as the oil is viscous (from 600 to over 40,000cp), initial production using vertical wells was poor. Several methods were used in order to improve production and recovery, including an air injection scheme in the 1990’s. However it is only with the introduction of horizontal drilling that the field began to reach its full potential; indeed Pelican Lake was one of the first fields worldwide to be developed with horizontal then multi-lateral wells. With primary recovery around 5-7% and several billion barrels OOIP, the prize for EOR is large; polymer flood had never been considered in such high viscosity oil until 1995, when the idea of combining polymer flood and horizontal wells gave way to a polymer flood pilot in 1997. This was the first step on the way, and today the field is in the process of being fully converted to polymer flood, with several hundred injection wells already in action. Polymer flooding has the potential to increase recovery to over 20%OOIP at relatively low cost. Pelican Lake is the first successful application of polymer flood in a high viscosity oil reservoir (1,000-2,500cp). This paper presents the history of the field then focuses on the polymer flooding aspects. It describes the preparation and results of the first polymer flood pilots as well as the extension to the field.
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ASP Pilot in West Salym Field - Project Front-end Engineering
Authors Y.E. Volokitin, J. Nieuwerf, V. Karpan, M. Shuster, W. Tigchelaar, D. van Batenburg, M. Shaymardanov, I. Chmuzh, I. Koltsov and R. FaberSalym Petroleum Development N.V. (SPD) is a 50/50 Joint Venture of Shell and Gazpromneft. SPD is the License holder and operator of the Salym Group of fields in Western Siberia (Upper Salym, West Salym and Vadelyp Work on maturation of Enhanced Oil Recovery option for Salym Petroleum Development (SPD) has began in 2007 and after initial screening, the ASP (Alkaline-Surfactant-Polymer) technology has been chosen for further work. Follow-up work involved laboratory and field tests, subsurface modelling and surface high-level concept design. High-level assessment demonstrated production potential of 30+ mln tones additional oil and a significant potential value to be shared between SPD and Russian Government. At that stage work began on Production Pilot as a Separate Project with Pilot Concept selected and Front-End Engineering work completed in 2012.Construction and opperation is expected in 2013-2014. The chosen concept for the Pilot involves a single 100x100m square pattern with 4 injectors and one producer. Since the primary objective of the Pilot is to demonstrate technology and to collect data for further optimization, 2 additional observation wells will be drilled within the pattern to provide information about the effectiveness of the process. Wells will be drilled from a dedicated well pad in the Northern area of West Salym field. The same location will host standalone mixing and production facilities. Produced fluids will be collected in the tank farm at the well pad and analysed. Logistics and planning for assurance of quality control of chemical mix has provided a separate challenge, also exacerbated by remoteness of location, but also by rheology properties of viscous surfactnat concentrates. In addition all storage and mixing facilities have to survive harsh Siberian conditions with temperatures ranging from -50 to +40 deg C. The paper describes some subsurface, chemical and engineering solutions for Salym pilot that might be of value for other groups contemplating cEOR pilots and small-scale production in a similar area
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Effect of Nonionic Surface-active Substances on Paraffin Crystallization in the System
Authors L.K. Altunina, L.A. Stasyeva and V.A. KuvshinovPresented are physicochemical and rheological properties of viscous paraffinic oils recovered from the south of West Siberia, Russia, Germany and Mongolia in the temperature range of 20-90 °C at different shear rates and interactions with oil-displacing systems based on surfactants and alkaline buffer solutions. The systems were determined to have demulsifying effect on the viscous paraffinic oils under study, regardless of surfactants composition and structure. Temperature dependence of paraffin crystallization point on a preheating temperature is extreme. At the same time maximum paraffin crystallization points correspond to preheating temperatures of 50-60 °C. We studied the ability of non-ionic surfactants – oxyethylated alkylphenols with different degrees of oxyethylation, from 12 to 90, to exhibit depressant properties with respect to paraffinic oils, reduce the viscosity of crude oils and the paraffin crystallization point. Optimal degree of oxyethylation of non-ionic surfactants was determined equal to 50, at which the decreases in oil viscosity and paraffin crystallization point were maximal. One can use the proposed compositions to develop EOR technologies for high-viscosity paraffinic oils.
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